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As filed with the Securities and Exchange Commission on August 28, 2007

Registration No. 333-142847

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 4

Form S-1

REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

ENCORE ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)


Delaware	1311	20-8456807
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

777 Main Street, Suite 1400

Fort Worth, Texas 76102

(817) 877-9955

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Jon S. Brumley

President and Chief Executive Officer

Encore Energy Partners GP LLC

777 Main Street, Suite 1400

Fort Worth, Texas 76102

(817) 877-9955

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:


Sean T. Wheeler Joshua Davidson Baker Botts L.L.P. 910 Louisiana Street Houston, Texas 77002 (713) 229-1234		David C. Buck Andrews Kurth LLP 600 Travis Street, Suite 4200 Houston, Texas 77002 (713) 220-4200

Approximate date of commencement of proposed sale to the public: As soon as practicable after this registration statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION DATED AUGUST 28, 2007

PROSPECTUS

Encore Energy Partners LP

9,000,000 Common Units
Representing Limited Partner Interests

We are a growth-oriented Delaware limited partnership formed on February 13, 2007 by Encore Acquisition Company to acquire, exploit and develop oil and natural gas properties and to acquire, own and operate related assets. This is the initial public offering of our common units. No public market currently exists for our common units. We expect the initial public offering price to be between $20.00 and $22.00 per common unit. Our common units have been approved for listing on the New York Stock Exchange under the symbol “ENP.”

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 20.

These risks include the following:


	•	We may not have sufficient cash flow from operations to pay the initial quarterly distribution 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, L.P.

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

	•	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.

	•	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.

	•	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 your detriment.


	•	You will experience immediate and substantial dilution of $8.83 per common unit.


	•	You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

In order to comply with certain U.S. laws relating to the ownership of interests in oil and natural gas leases on federal lands, we require an owner of our units to be an “Eligible Holder.” If you are not an Eligible Holder, you will not be entitled to receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption. Please read “The Partnership Agreement — Non-Eligible Holders; Redemption.”

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.


	Per Common Unit	Total

Public Offering Price	$	$
Underwriting Discount(1)	$	$
Net Proceeds, before expenses, to Encore Energy Partners LP	$	$


(1)		Excludes an aggregate fee payable to UBS Securities LLC and Lehman Brothers Inc. equal to 0.375% of the gross proceeds of this offering, or approximately $ , for the evaluation, analysis and structuring of our partnership.

To the extent that the underwriters sell more than 9,000,000 common units, the underwriters have the option to purchase up to an additional 1,350,000 common units on the same terms and conditions as set forth in this prospectus.

The underwriters expect to deliver the common units on or about , 2007.


UBS Investment Bank	Lehman Brothers


A.G. Edwards	Credit Suisse	Raymond James	RBC Capital Markets

, 2007

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the notes to those financial statements. The information presented in this prospectus assumes an initial public offering price of $21.00 per common unit and, unless otherwise noted, that the underwriters’ option to purchase additional common units is not exercised. You should read “Risk Factors” beginning on page 20 for information about important factors that you should consider carefully before buying our common units. We include a glossary of some of the terms used in this prospectus in Appendix B.

Encore Energy Partners LP

We are a growth-oriented Delaware limited partnership formed on February 13, 2007 by Encore Acquisition Company (NYSE: EAC) to acquire, exploit and develop oil and natural gas properties and to acquire, own and operate related assets. Our assets consist primarily of producing and non-producing oil and natural gas properties in the Elk Basin of Wyoming and Montana and the Permian Basin of West Texas. As of December 31, 2006, on a pro forma basis after giving effect to the acquisition of the Elk Basin assets from subsidiaries of Anadarko Petroleum Corporation, our total estimated proved reserves were 21.4 MMBOE, 68% of which were oil and 86% of which were proved developed.

Our primary business objective is to make quarterly cash distributions to our unitholders at our initial distribution rate and, over time, increase our quarterly cash distributions. We believe our properties are well suited for our partnership because they have predictable production profiles based on a long history of production, a 5.5% average decline rate, an average reserve-to-production ratio of 13.1 years and forecasted maintenance capital requirements of only $8.7 million for the twelve months ending September 30, 2008. The following table summarizes information about our oil and natural gas reserves as of December 31, 2006 and our net production for 2006 on a pro forma basis to reflect the Elk Basin acquisition:


													Average		Estimated
	Estimated Net Proved Reserves												Reserve-to-		Production
	at December 31, 2006(1)						2006 Net Production						Production		Decline
	Developed		Undeveloped		Total		Oil		Natural Gas		Total		Ratio(2)		Rate(3)
			(MBOE)				(MBbls)		(MMcf)		(MBOE)		(Years)

Elk Basin		13,285		1,806		15,091		1,266		362		1,326		11.4		4.4	%
Permian Basin		5,125		1,163		6,288		7		1,796		306		20.5		10.0	%

Total		18,410		2,969		21,379		1,273		2,158		1,632		13.1		5.5	%


(1)		Our proved oil and natural gas reserves were estimated by Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents, Ltd. performed their evaluations using unescalated prices, operating expenses, and capital expenditures provided by us. Their evaluation was a full determination, which included reviewing and forecasting 100% of the properties. Proved reserves and future net revenues were estimated in accordance with SEC rules.


(2)		The average reserve-to-production ratio is calculated by dividing estimated net proved reserves as of December 31, 2006 by pro forma net production for 2006.


(3)		Represents percentage decrease in production from our proved developed producing properties from 2007 to 2008 as estimated by Miller and Lents, Ltd.

Our Properties

Elk Basin Properties

of which approximately 97% was oil and 3% was natural gas. On a pro forma basis for the six months ended June 30 2007, production from our Elk Basin properties was approximately 3,519 BOE/D. Our Elk Basin properties had estimated proved reserves at December 31, 2006 of 15,091 MBOE, of which 13,285 MBOE was proved developed and 1,806 MBOE was proved undeveloped. Approximately 99% of proved reserves in the Elk Basin are located in the Embar-Tensleep, Madison and Frontier formations. Our oil and natural gas properties in the Elk Basin include 21,925 gross acres and 13,699 net acres located in Park County, Wyoming and Carbon County, Montana. All of our production in the Elk Basin is operated, and over 77% of our oil and natural gas properties in the Elk Basin are leased from the Federal Bureau of Land Management.

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 higher sulfur natural gas from the Elk Basin field to our Elk Basin natural gas processing facility.

Permian Basin Properties

Our properties in the Permian Basin were acquired by EAC in March 2000 and are located in Crockett County, Texas. For the year ended December 31, 2006, production from our Permian Basin properties was approximately 838 BOE/D, substantially all of which was natural gas. For the six months ended June 30, 2007, production from our Permian Basin properties was approximately 719 BOE/D, substantially all of which was natural gas. Our Permian Basin properties had estimated proved reserves at December 31, 2006 of 6,288 MBOE, of which 3,702 MBOE was proved developed producing, 1,423 MBOE was proved developed non-producing and 1,163 MBOE was proved undeveloped. Our Permian Basin properties consist of 25,115 gross acres and 10,384 net acres located in Crockett County, Texas.

Business Strategy


	•	purchase assets from EAC through negotiated transactions;

	•	purchase assets through joint efforts with EAC;

	•	purchase assets independently of EAC;

	•	use the benefits of our relationship with EAC and the leadership of I. Jon Brumley and Jon S. Brumley;

	•	use EAC’s technical expertise to identify and implement successful exploitation techniques to achieve optimum production and reserve recovery;

	•	mitigate negative effects of falling commodity prices through entering into commodity derivative contracts; and

	•	maintain relatively low levels of indebtedness to permit us to be opportunistic with future acquisitions.

Competitive Strengths

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


	•	our relationship with EAC, which we believe will provide us with certain advantages;

	•	our relatively high-quality asset base is characterized by low declining, stable and long-lived production;


	•	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 technical expertise, particularly in enhanced recovery methods, should enable us to efficiently produce and maximize the profitability of our assets;

	•	our operational control of approximately 73% of our properties permits us to manage our operating costs and better control capital expenditures as well as the timing of development activities; and

	•	our cost of capital, ability to issue additional common units and low level of indebtedness upon completion of this offering should enable us to be competitive in pursuing acquisitions.

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. As of December 31, 2006, on a pro forma basis after giving effect to acquisitions of certain oil and natural gas properties and related assets in the Big Horn and Williston Basins (including the Elk Basin assets) and the disposition of certain oil and natural gas properties and related assets in the Mid-Continent, EAC’s total estimated proved reserves were 226 MMBOE, 83% of which were oil and 69% of which were proved developed.

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.

The following table summarizes information about EAC’s oil and natural gas reserves as of December 31, 2006 and EAC’s net production for 2006 on a pro forma basis:


																			Average
	Estimated Net Proved Reserves at																		Reserve-to-
	December 31, 2006(1)									2006 Net Production									Production
	Oil			Natural Gas			Total			Oil			Natural Gas			Total			Ratio
	(MBbls)			(MMcf)			(MBOE)			(MBbls)			(MMcf)			(MBOE)			(Years)(2)

Cedar Creek Anticline		117,868			15,750			120,493			4,851			1,330			5,073			23.8
Permian Basin		23,105			106,693			40,887			1,277			5,841			2,250			18.2
Rockies		8,716			2,895			9,198			732			360			792			11.6
Mid-Continent		3,745			181,426			33,983			475			15,925			3,129			10.9

Total		153,434			306,764			204,561			7,335			23,456			11,244			18.2
Acquisitions(3)		35,685			19,496			38,934			3,349			1,558			3,608			10.8
Disposition(4)		(1,465	)		(95,703	)		(17,416	)		(164	)		(7,308	)		(1,382	)		12.6

Total pro forma		187,654			230,557			226,079			10,520			17,706			13,470			16.8


(1)		EAC’s proved oil and natural gas reserves were estimated by Miller and Lents, Ltd., independent petroleum engineers, except for oil and natural gas reserves related to the Gooseberry acquisition and the Williston Basin acquisition, which were estimated by EAC’s engineers.

(2)		The average reserve-to-production ratio is calculated by dividing EAC’s estimated net proved reserves as of December 31, 2006 by its net production for 2006.

(3)		Includes oil and natural gas reserves from the acquisition of properties in the Elk Basin field and the Gooseberry field in the Big Horn Basin of Wyoming and Montana on March 7, 2007 and the acquisition of properties in the Williston Basin in Montana and North Dakota on April 11, 2007.

(4)		The disposition relates to the sale of oil and natural gas properties and related assets in the Mid-Continent on June 29, 2007.

EAC had a staff of approximately 338 persons, including 35 engineers, 13 geologists and 12 landmen as of August 3, 2007. Through our relationship with EAC, we will have access to EAC’s personnel and senior management team, strong commercial relationships throughout the oil and natural gas industry and access to EAC’s broad operational, commercial, technical, risk management and administrative infrastructure. For more information about the management of our partnership and our use of EAC personnel, please read “Management” beginning on page 119.

Summary of Risk Factors

An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. The following list of risk factors is not exhaustive. Please read carefully these and the other risks under the caption “Risk Factors” beginning on page 20.

Risks Related to Our Business


	•	We may not have sufficient cash flow from operations to pay the initial quarterly distribution 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, L.P.

	•	Our estimate of the minimum Adjusted EBITDA necessary for us to make a distribution on all units at the initial distribution rate for each of the four quarters ending September 30, 2008 is based on assumptions that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated.


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

	•	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.

	•	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.

	•	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.

	•	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.

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

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 your detriment.

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

	•	We do not have any employees and rely solely on officers of our general partner and employees of Encore Operating, L.P., a wholly owned subsidiary 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.

	•	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.

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

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


	•	We may issue additional units, including units that are senior to the common units, without your approval, which would dilute your ownership interests.


	•	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.


	•	You will experience immediate and substantial dilution of $8.83 per common unit.

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 Internal Revenue Service, or 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 you would be substantially reduced.


	•	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.

	•	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 you.

	•	You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

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

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

	•	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.

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

	•	The sale or exchange of 50% 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 may adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the holders of management incentive units and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Other Information

Our principal executive offices are located at 777 Main Street, Suite 1400, Fort Worth, Texas 76102, and our telephone number is (817) 877-9955. Our Internet address will be www.encoreenp.com. We expect to make our periodic reports and other information filed or furnished to the Securities and Exchange Commission, or SEC, available, free of charge, through our web site, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our web site or any other web site is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Formation and Closing Transactions

Formation Transactions

We were formed on February 13, 2007. In March 2007, the following transactions occurred:


	•	EAC assigned its rights to acquire the Elk Basin assets to us;

	•	we entered into a five-year revolving credit facility with Bank of America, N.A. providing for an initial borrowing base of $115 million and a $10 million overadvance feature;

	•	an affiliate of EAC loaned us $120 million under the terms of a subordinated term loan agreement;

	•	EAC (through its subsidiaries) made a capital contribution to us of approximately $93.7 million;

	•	we used borrowings of $115 million under our revolving credit facility (excluding $1.6 million of debt issuance costs), $120 million of borrowings under the subordinated term loan agreement and $93.4 million of the capital contribution from EAC to acquire the Elk Basin assets; and


	•	EAC (through its subsidiaries) assigned certain commodity derivative contracts to us covering certain future production from the Elk Basin assets.

Closing Transactions

At the closing of this offering, the following transactions will occur:


	•	we will enter into a contribution, conveyance and assumption agreement with EAC and Encore Operating, L.P., a wholly owned subsidiary of EAC, pursuant to which:


	•	Encore Operating, L.P. will transfer the Permian Basin assets to us in exchange for 4,043,478 common units; and

	•	EAC will agree 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;


	•	we will sell 9,000,000 common units to the public representing an approximate 37.4% limited partner interest in us, and will use the net proceeds from this offering as described under “Use of Proceeds”;

	•	we will issue additional general partner units to our general partner in exchange for common units to enable our general partner to maintain its 2% general partner interest; and

	•	we will enter into an amended and restated administrative services agreement with Encore Operating, L.P. pursuant to which Encore Operating, L.P. will perform administrative services for us such as accounting, corporate development, finance, land, legal and engineering.

We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units to repay additional indebtedness under our revolving credit facility. If the underwriters’ option is exercised in full, EAC and its affiliates will own common units and management incentive units representing an aggregate 57.3% limited partner interest in us, and the public unitholders will own common units representing an aggregate 40.7% limited partner interest in us.

Management of Encore Energy Partners LP

Encore Energy Partners GP, our general partner, will manage our operations and activities, and its board of directors and officers will make decisions on our behalf. Jon S. Brumley, EAC’s President and Chief Executive Officer, will be our general partner’s President and Chief Executive Officer and will be actively involved in our business. In addition, all of the other executive officers and some of the directors of our general partner also serve as executive officers or directors of EAC. We, our subsidiaries and our general partner do not have employees. The board of directors and executive officers of our general partner will make all strategic decisions on our behalf, and we will enter into an amended and restated services agreement with Encore Operating, L.P., a wholly owned subsidiary of EAC, for all of our administrative services, such as accounting, corporate development, finance, land, legal and engineering. Under the amended and restated administrative services agreement, Encore Operating, L.P. will receive an administrative fee of $1.75 per BOE of our production, estimated to be approximately $2.8 million based on forecasted production for the twelve months ending September 30, 2008, for such services and reimbursement of actual third-party expenses incurred on our behalf. Encore Operating, L.P. will have substantial discretion in determining which third-party expenses to incur on our behalf. We will also pay our share of expenses that are directly chargeable to wells under joint operating agreements. In determining the amount of the administrative fee, EAC considered its historical cash expenses on a per BOE basis associated with administrative functions, together with an analysis of such expenses by other exploration and production companies that are organized as publicly traded partnerships. The $1.75 per BOE administrative fee was not intended to result in a subsidy to our partnership or a premium to EAC. This fee represents an approximation of the expenses that would have been allocable to our oil and natural gas properties had they remained in EAC.

In addition, Encore Operating, L.P. will be entitled to retain any Council of Petroleum Accountants Societies, or 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.

In May 2007, the board of directors of our general partner granted 550,000 management incentive units, subject to vesting, to certain of our general partner’s executive officers. A management incentive unit entitles the holder to an initial quarterly distribution of $0.35 (or $1.40 on an annualized basis) to the extent paid to our common unitholders, and to increasing distributions upon the achievement of 10% compounded increases in our distribution rate to common unitholders, provided that distributions payable to the holders of management incentive units will be subject to a maximum limit equal to 5.1% of all distributions to our unitholders at the time of any such distribution. If the 5.1% 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 public unitholders. Additionally, management incentive units are convertible into common units in increasing amounts as our distribution rate to common unitholders increases, provided that the holders of management incentive units will not be entitled to receive, in the aggregate, common units upon conversion of the management incentive units equal to more than 5.1% of all our then-outstanding units. 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. 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, as long as such units are outstanding. Please read “Management — Management Incentive Units.”

Our general partner will also be entitled to distributions on its general partner units. EAC holds all of the membership interests in our general partner and consequently is indirectly entitled to all of the distributions that we make to our general partner, subject to the terms of the limited liability company agreement of our general partner and relevant legal restrictions. Please read “Our Cash Distribution Policy and Restrictions on Distributions,” “Management — Executive Compensation” and “Certain Relationships and Related Party Transactions.”

Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or its directors. EAC will elect all members to the board of directors of our general partner and we will have at least three directors who are independent as defined under the independence standards established by The New York Stock Exchange, or the NYSE. For more information about these individuals, please read “Management — Directors and Executive Officers of Our General Partner.”

Summary of Conflicts of Interest and Fiduciary Duties

Our general partner has a legal duty to manage us in a manner beneficial to the holders of our common units. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, because our general partner is owned by EAC, the officers and directors of our general partner have fiduciary duties to manage our general partner in a manner beneficial to EAC. As a result of this relationship, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, on the other hand. For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Risk Factors — Risks Inherent in an Investment in Us” and “Conflicts of Interest and Fiduciary Duties.”

Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner owed to the holders of our common units. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duties owed to unitholders. Our partnership agreement also provides that EAC is not restricted from competing with us. By purchasing a common unit, you are treated as having consented to various actions contemplated in our partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable law. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties” for a description of the fiduciary duties imposed on our general partner by Delaware law, the material modifications of these duties contained in our partnership agreement and certain legal rights and remedies available to unitholders.

For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

Restrictions on Ownership of Common Units

In order to comply with certain U.S. laws relating to the ownership of interests in oil and natural gas leases on federal lands, we have adopted requirements regarding our owners. Our partnership agreement requires that a transferee of common units or a unitholder, including the underwriters and those who purchase common units from the underwriters, properly complete and deliver to us a transfer application containing a certification as to a number of matters, including the status of the transferee, or all its owners, as being an “Eligible Holder.” 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. If a transferee or a unitholder, as the case may be, does not properly complete the transfer application or recertification for any reason, the transferee or unitholder will have no right to receive any distributions or allocations of income or loss on its common units or to vote its common units on any matter and we have the right to redeem such common units at a price which is equal to the lower of the transferee’s or unitholder’s purchase price or the then-current market price of such common units. The redemption price will be paid in cash or by delivery of a promissory note as determined by our general partner. Please read “Description of the Common Units — Transfer of Common Units” and “The Partnership Agreement — Non-Eligible Holders; Redemption.”

The Offering


Common units offered by us		9,000,000 common units.

		10,350,000 common units if the underwriters exercise their option to purchase additional common units in full.

Units outstanding after this offering		23,062,247 common units, or 24,385,247 common units if the underwriters exercise their option to purchase additional common units in full. The general partner will own 481,883 general partner units, or 508,883 general partner units if the underwriters exercise their option to purchase additional common units in full, in each case representing a 2% general partner interest in us. Certain of our general partner’s executive management will also own 550,000 management incentive units.


Use of proceeds		We intend to use the estimated net proceeds of approximately $172.0 million from this offering, after deducting underwriting discounts and a structuring fee of approximately $13.2 million in the aggregate and estimated offering expenses of approximately $3.8 million, to:


		• repay all $120 million of indebtedness, together with accrued interest of approximately $6.9 million, under a subordinated term loan agreement with one of EAC’s subsidiaries; and


		• repay $45.1 million of indebtedness under our revolving credit facility.


		We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units to repay additional indebtedness under our revolving credit facility. Please read “Use of Proceeds.” An affiliate of RBC Capital Markets Corporation, one of the underwriters in this offering, is a lender under our revolving credit facility and, accordingly, will receive a portion of the proceeds from this offering through the repayment of indebtedness under that facility.

Cash distributions		We expect to make an initial quarterly distribution of $0.35 per unit ($1.40 per unit on an annualized basis) on all common units, management incentive units and general partner units to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. Our ability to pay distributions at this initial distribution rate is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.”

		Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending September 30, 2007, we distribute all of our available cash to unitholders of record on the applicable record date. The term “available cash,” for any quarter, means all cash and cash equivalents on hand at the end of that quarter, less the amount of cash reserves established by our general partner to:

		• provide for the proper conduct of our business;

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


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

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

		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% of all distributions to our unitholders at the time of any such distribution. If the 5.1% 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 public unitholders. We do not have any subordinated units, and our general partner is not entitled to any incentive distributions. Please read “Description of the Common Units,” “Management — Management Incentive Units” and “The Partnership Agreement.”

		We expect to pay unitholders a prorated distribution for the first quarter during which we are a publicly traded partnership. Assuming that we become a publicly traded partnership before September 30, 2007, we will pay unitholders a prorated distribution for the period from the closing of the offering through September 30, 2007. We expect to pay this cash distribution on or before November 14, 2007.

		We believe that we will have sufficient cash available from operations to make cash distributions for each quarter for the twelve months ending September 30, 2008 at the initial quarterly distribution rate of $0.35 per unit per quarter on all common units, management incentive units and general partner units. Please read “Our Cash Distribution Policy and Restrictions on Distributions — Assumptions and Considerations.”

Issuance of additional common units		We can issue an unlimited number of additional units, including units that are senior to the common units in rights of distribution, liquidation and voting, on the terms and conditions determined by our general partner without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Securities.”

Voting rights		Our general partner will manage and operate us. Unlike stockholders of a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, affiliates of EAC will own an aggregate of 61.0% of our common units. This will give EAC the ability to prevent removal


		of our general partner. Please read “The Partnership Agreement — Voting Rights.”

Eligible Holders and redemption		Only Eligible Holders will be entitled to receive distributions or be allocated income or loss from us. 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. If a transferee or a unitholder, as the case may be, does not properly complete the transfer application or recertification, for any reason, the transferee or unitholder will have no right to receive any distributions or allocations of income or loss on its common units or to vote its units on any matter and we have the right to redeem such units at a price which is equal to the lower of the transferee’s or unitholder’s purchase price or the then-current market price of such units. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “Description of the Common Units — Transfer of Common Units” and “The Partnership Agreement — Non-Eligible Holders; Redemption.”

Limited call right		If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a purchase price not less than the then-current market price of the common units. Please read “The Partnership Agreement — Limited Call Right.”

Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2009, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.40 per common unit, we estimate that your average allocated federal taxable income per year will be no more than $0.28 per unit. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions” for the basis of this estimate.

Material tax consequences		For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”

Agreement to be bound by the Partnership Agreement		By purchasing a common unit, you will be admitted as a unitholder of our partnership and will be deemed to have agreed to be bound by all of the terms of our partnership agreement.

Listing and trading symbol		Our common units have been approved for listing on the New York Stock Exchange under the symbol “ENP.”

Summary Historical and Pro Forma Financial Data

Set forth below is summary historical financial data for Encore Energy Partners LP Predecessor, the predecessor to Encore Energy Partners LP, summary historical financial data for Encore Energy Partners LP and pro forma financial data of Encore Energy Partners LP, as of the dates and for the periods indicated.

The summary historical financial data presented as of December 31, 2005 and 2006 and for the years ended December 31, 2004, 2005 and 2006 is derived from the audited carve out financial statements of Encore Energy Partners LP Predecessor included elsewhere in this prospectus. The summary historical financial data presented as of June 30, 2007 and for the six months ended June 30, 2006 and 2007 is derived from the unaudited combined historical and predecessor carve out financial statements of Encore Energy Partners LP included elsewhere in this prospectus. The carve out financial statements of Encore Energy Partners LP Predecessor are comprised of certain of EAC’s oil and natural gas assets, liabilities and operations located in the Permian Basin of West Texas, which we refer to as the Permian Basin assets and which EAC will contribute to us on or prior to the completion of this offering. Due to the factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors Affecting Comparability of Future Results,” our future results of operations will not be comparable to Encore Energy Partners LP Predecessor’s historical results.

The summary pro forma financial data for the year ended December 31, 2006 and as of and for the six months ended June 30, 2007 is derived from the unaudited pro forma financial statements of Encore Energy Partners LP included elsewhere in this prospectus. The unaudited pro forma financial statements of Encore Energy Partners LP give pro forma effect to the following transactions:

March 2007 Transactions


	•	the borrowing by us of $120 million under a subordinated term loan agreement with a wholly owned subsidiary of EAC and $116.6 million under our revolving credit facility (including $1.6 million of debt issuance costs);

	•	a $93.7 million capital contribution by EAC to us, substantially all of which was used to fund a portion of the purchase price for the Elk Basin assets;

	•	the assignment of certain commodity derivative contracts to us by EAC (through its subsidiaries) covering certain future production from the Elk Basin assets;

	•	the acquisition of the Elk Basin assets for $329.4 million (including estimated transaction costs of approximately $1.0 million);

Closing Transactions


	•	the contribution of the Permian Basin assets to us in exchange for the issuance of 4,043,478 common units;

	•	the sale by us of 9,000,000 common units to the public in this offering;

	•	the issuance by us of additional general partner units to our general partner in exchange for common units to enable our general partner to maintain its 2% general partner interest;


	•	the execution by us of an amended and restated administrative services agreement with Encore Operating, L.P., as described in “Certain Relationships and Related Party Transactions — Amended and Restated Administrative Services Agreement”;


	•	the completion of this offering and the use of proceeds from this offering as described in “Use of Proceeds”; and

Subsequent Event


	•	the August 22, 2007 amendment to our revolving credit facility, which resulted in our ability to classify outstanding balances as long-term.

offering, the management incentive units granted to executive officers of our general partner will partially vest, at which point we will recognize an expense for the estimated fair value of the vested portion of the units. We will recognize additional expenses over at least the following two-year period as the management incentive units continue to vest. Because this expense is a non-recurring charge resulting directly from the completion of this offering, this expense is not reflected in our unaudited pro forma financial statements.

You should read the following table in conjunction with “— Formation and Closing Transactions,” “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical carve out financial statements of Encore Energy Partners LP Predecessor, the combined historical and predecessor financial statements of Encore Energy Partners LP and the unaudited pro forma financial statements of Encore Energy Partners LP included elsewhere in this prospectus. Among other things, those historical and pro forma financial statements include more detailed information regarding the basis of presentation for the following information.

The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in our business. This measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain this measure below and reconcile it to the most directly comparable financial measures calculated and presented in accordance with GAAP.


								Encore Energy					Encore Energy Partners LP
	Encore Energy Partners LP							Partners LP(1)					(Pro Forma)
	Predecessor							Six Months					Year Ended			Six Months
	Year Ended December 31,							Ended June 30,					December 31,			Ended June 30,
	2004		2005		2006			2006		2007			2006			2007
								(unaudited)					(unaudited)
	(In thousands, except per unit data)

Statements of Operations Data:
Revenues:
Oil	$	442	$	535	$	409		$	174	$	20,469		$	64,104		$	30,928
Natural gas		12,791		16,366		12,337			6,719		5,904			14,732			6,031
Marketing and other		—		—		—			—		4,852			3,649			8,427

Total revenues		13,233		16,901		12,746			6,893		31,225			82,485			45,386

Expenses:
Production:
Lease operations		1,604		1,751		1,673			793		4,951			9,108			6,916
Production, ad valorem, and severance taxes		1,195		1,473		1,226			638		3,286			9,065			4,548
Depletion, depreciation, and amortization		1,394		1,286		1,200			580		10,412			30,867			14,867
General and administrative		477		572		631			326		1,092			2,856			1,342
Derivative fair value loss		—		—		—			—		6,497			—			6,497
Marketing and other operating		202		263		246			122		4,646			6,105			8,060

Total expenses		4,872		5,345		4,976			2,459		30,884			58,001			42,230

Operating income		8,361		11,556		7,770			4,434		341			24,484			3,156

Other income (expenses):
Interest		—		—		—			—		(6,444	)		(4,264	)		(2,205	)
Other		—		—		—			—		27			—			27

Total other income (expenses)		—		—		—			—		(6,417	)		(4,264	)		(2,178	)

Income (loss) before income taxes		8,361		11,556		7,770			4,434		(6,076	)		20,220			978
Income tax provision		—		—		(122	)		—		(39	)		(122	)		(39	)

Net income (loss)	$	8,361	$	11,556	$	7,648		$	4,434	$	(6,115	)	$	20,098		$	939

Pro forma net income per limited partner unit													$	0.85		$	0.04
Adjusted EBITDA	$	9,755	$	12,842	$	8,970		$	5,014	$	17,277		$	55,351		$	24,547


(1)		Represents the combined historical and predecessor carve out financial statements of Encore Energy Partners LP.


										Encore Energy						Encore Energy Partners LP
	Encore Energy Partners LP									Partners LP(1)						(Pro Forma)
	Predecessor									Six Months Ended						Year Ended	Six Months
	Year Ended December 31,									June 30,						December 31,	Ended June 30,
	2004			2005			2006			2006			2007			2006	2007
										(unaudited)						(unaudited)
										(In thousands)

Balance Sheet Data (at period end):
Working capital(2)	$	2,257		$	3,505		$	1,633					$	(107,455	)		$	7,545
Total assets		26,794			29,133			26,923						379,884				379,884
Long-term debt		—			—			—						123,641				66,671
Partners’/Owner’s equity		25,822			27,954			25,719						119,293				291,263
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	9,394		$	11,604		$	10,919		$	6,611		$	5,203
Investing activities		(1,810	)		(2,180	)		(1,036	)		(73	)		(327,524	)
Financing activities		(7,584	)		(9,424	)		(9,883	)		(6,538	)		323,669


(1)		Represents the combined historical and predecessor carve out financial statements of Encore Energy Partners LP.


(2)		Working capital at June 30, 2007 includes $115 million of borrowings under our revolving credit facility on a historical basis. On a pro forma basis, the revolving credit facility is classified as long-term debt.

Non-GAAP Financial Measures

We include in this prospectus the non-GAAP financial measure Adjusted EBITDA and provide reconciliations of Adjusted EBITDA to net income (loss) and net cash provided by (used in) operating activities, our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income (loss) plus:


	•	Interest expense;

	•	Income tax provision;

	•	Depletion, depreciation and amortization (“DD&A”); and

	•	Unrealized (gain) loss on commodity derivative contracts.

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess:


	•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;

	•	our operating performance and return on capital as compared to those of other companies and partnerships in our industry, without regard to financing or capital structure; and

	•	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

We believe eliminating unrealized (gain) loss on commodity derivative contracts in calculating Adjusted EBITDA is useful and appropriate for the following reasons:


	•	The executive officers of our general partner use Adjusted EBITDA (which excludes unrealized (gain) loss on commodity derivative contracts) as a measure of our operating performance and return on

capital and, therefore, public disclosure of Adjusted EBITDA calculated in the same manner is important in explaining how management evaluates our partnership.


	•	Our revolving credit agreement requires us to maintain a minimum ratio of consolidated EBITDA to consolidated interest expense plus letter of credit fees. In computing consolidated EBITDA, we are required to exclude any unrealized non-cash gains, losses or charges in respect of any commodity derivatives transactions resulting from the requirements of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” We believe it is important to maintain consistency between the way we report Adjusted EBITDA and the way we are required to calculate EBITDA for purposes of our revolving credit agreement.

	•	Adjusted EBITDA is a frequently used financial measure by publicly traded partnerships and the exclusion of unrealized (gain) loss on commodity derivative contracts is common.

	•	The concepts of pro forma cash available for distribution and estimated cash available for distribution are critical to evaluating our historical and future business. In arriving at cash available for distribution, we exclude the effects of unrealized (gain) loss on commodity derivative contracts in arriving at Adjusted EBITDA, which we believe is important in enabling investors to evaluate our ability to sustain or increase distributions.

Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents a reconciliation of Adjusted EBITDA to net income (loss) and net cash provided by (used in) operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.


										Encore Energy						Encore Energy Partners LP
	Encore Energy Partners LP									Partners LP(1)						(Pro Forma)
	Predecessor									Six Months						Year Ended		Six Months
	Year Ended December 31,									Ended June 30,						December 31,		Ended June 30,
	2004			2005			2006			2006			2007			2006		2007
										(unaudited)						(unaudited)
(In thousands)

Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss)	$	8,361		$	11,556		$	7,648		$	4,434		$	(6,115	)	$	20,098	$	939
Income tax provision		—			—			122			—			39			122		39
Depletion, depreciation, and amortization		1,394			1,286			1,200			580			10,412			30,867		14,867
Unrealized loss on commodity derivative contracts		—			—			—			—			6,497			—		6,497
Interest expense		—			—			—			—			6,444			4,264		2,205

Adjusted EBITDA	$	9,755		$	12,842		$	8,970		$	5,014		$	17,277		$	55,351	$	24,547

Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	9,394		$	11,604		$	10,919		$	6,611		$	5,203
Add:
Cash income taxes		—			—			—			—			39
Cash interest expense		—			—			—			—			2,695
Realized gain on commodity derivative contracts		—			—			—			—			(185	)
Change in operating assets and liabilities		367			1,248			(1,933	)		(1,590	)		9,654
Other non-cash expense		(6	)		(10	)		(16	)		(7	)		(129	)

Adjusted EBITDA	$	9,755		$	12,842		$	8,970		$	5,014		$	17,277


(1)		Represents the combined historical and predecessor carve out financial statements of Encore Energy Partners LP.

Summary Historical and Pro Forma Reserve and Operating Data

The following tables show estimated net proved oil and natural gas reserves for Encore Energy Partners LP Predecessor and pro forma estimated net proved oil and natural gas reserves for Encore Energy Partners LP based on a reserve report prepared by our independent petroleum engineers and certain summary unaudited information regarding production and sales of oil and natural gas with respect to such properties. You should refer to “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business — Our Pro Forma Oil and Natural Gas Data — Estimated Pro Forma Proved Reserves” in evaluating the material presented below.


										Encore Energy
										Partners LP
	Encore Energy Partners LP									(Pro Forma)
	Predecessor									As of
	As of December 31,									December 31,
	2004			2005			2006			2006(4)

Reserve Data:
Estimated net proved reserves:
Oil (MBbls)		43			45			50			14,520
Natural gas (MMcf)		40,966			44,190			37,426			41,152
Total (MBOE)		6,871			7,410			6,288			21,379
Proved developed (MBOE)		4,881			5,372			5,125			18,410
Proved undeveloped (MBOE)		1,990			2,038			1,163			2,969
Proved developed reserves as % of total proved reserves		71	%		72	%		82	%		86	%
Standardized Measure (in thousands)(1)	$	82,722		$	126,605		$	50,672		$	297,376
Realized Oil and Natural Gas Prices(2):
Oil per Bbl	$	40.67		$	57.03		$	57.46		$	46.46
Natural gas per MMBtu	$	5.88		$	8.49		$	5.23		$	5.29
Spot Oil and Natural Gas Prices(3):
Oil — spot per Bbl	$	43.46		$	61.04		$	61.06		$	61.06
Natural gas — spot per MMBtu	$	6.19		$	9.44		$	5.48		$	5.48


(1)		Standardized measure is 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, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Our standardized measure does not reflect any future income tax expenses because we are not subject to federal income taxes, although we have provided for the payment of Texas franchise taxes. Standardized measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk.”

(2)		The realized prices above that were used in the determination of standardized measure represent a cash market price on December 31 less all expected quality, transportation and demand adjustments. Realized prices are presented before the effects of hedging.

(3)		The spot oil and natural gas prices represent the cash market prices at December 31, 2004, 2005 and 2006 without reduction for expected quality, transportation and demand adjustments.

(4)		Includes reserves attributable to our Elk Basin acquisition in March 2007.

RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business

We may not have sufficient cash flow from operations to pay the initial quarterly distribution 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, L.P.

We may not have sufficient available cash each quarter to pay the initial quarterly distribution of $0.35 per unit or any other amount. Under the terms of our partnership agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserve 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 will depend 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 will have available for distribution will depend 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, including expenses we will incur as a result of being a public company;

	•	cash settlement of commodity derivative contracts;

	•	timing and collectibility of receivables; and

	•	the amount of cash reserves, which we expect to be substantial, established by our general partner for the proper conduct of our business.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

Our estimate of the minimum Adjusted EBITDA necessary for us to make a distribution on all units at the initial distribution rate for each of the four quarters ending September 30, 2008 is based on assumptions that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated.

Our estimate of the minimum Adjusted EBITDA necessary for us to make a distribution on all units at the initial distribution rate for each of the four quarters ending September 30, 2008, as set forth in “Our Cash Distribution Policy and Restrictions on Distributions,” is based on our management’s calculations, and we have not received an opinion or report on it from any independent accountants. This estimate is based on assumptions about development, production, oil and natural gas prices, settlements under commodity

derivative contracts, capital expenditures, expenses, borrowings and other matters that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. If any of these assumptions prove to have been inaccurate, our actual results may differ materially from those set forth in our estimates, and we may be unable to pay all or part of the initial quarterly distribution on our units.

None of the proceeds of this offering will be used to maintain or grow our asset base or be reserved for future distributions.

None of the proceeds of this offering will be used to maintain or grow our asset base, which may be necessary to cover future distributions, and none of the proceeds will be reserved for future distributions. The proceeds of the offering will be used to repay debt, including debt owed to one of EAC’s affiliates.

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

If our reserves decrease and we do not reduce our distribution, then a portion of the distribution may be considered a return of part of your investment in us as opposed to a return on your 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 be required to 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 will reduce 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 will be 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, or OPEC, 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;

	•	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.

In the past, prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2006, the NYMEX oil price ranged from a high of $77.03 per Bbl to a low of $55.81 per Bbl, while the NYMEX Henry Hub natural gas price ranged from a high of $9.87 per MMBtu to a low of $3.63 per MMBtu. For the five years ended December 31, 2006, the NYMEX oil price ranged from a high of $77.03 per Bbl to a low of $17.97 per Bbl, while the NYMEX Henry Hub natural gas price ranged from a high of $19.38 per MMBtu to a low of $1.98 per MMBtu.

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 positions. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and natural gas differentials. In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have gradually widened this differential. 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 the twelve months ending September 30, 2008, please read “Our Cash Distribution Policy and Restrictions on Distributions — Assumptions and Considerations — Operations and Revenue.”

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 for impairments. If we incur 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.

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 both realized and unrealized 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. Furthermore, our revolving credit facility requires that we limit derivative transactions that cap the price we will receive from expected production volumes and, as a result, we will continue to have direct commodity price exposure on a portion of our production volumes. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk.”

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative 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 nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase 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% 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.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with the Financial Accounting Standards Board’s, or FASB, Statement of Financial Accounting Standards 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.

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 66% of our production and 50% of our reserves 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.

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

Even if we do make 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 will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.

Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition given time constraints imposed by sellers. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to 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 and Texas. Due to our lack of diversification in asset type and location, an adverse development in the oil and natural gas business of these geographic areas would have a significantly greater impact on our results of operations and cash available for distribution to our unitholders than if we maintained more diverse assets and locations.

We depend on 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 revenue and cash available for distribution will decline to the extent we are not able to find new customers for our production.

On a pro forma basis for the year ended December 31, 2006, Marathon Oil Corporation and ConocoPhillips accounted for approximately 35% and 25% of our total sales volumes, respectively. On a pro forma basis for the six months ended June 30, 2007, Marathon Oil Corporation and ConocoPhillips accounted for approximately 58% and 18% of our total sales volumes, 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, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel 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 financial or human 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 initial distribution rate or the then-current 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.

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

After giving effect to this offering and the related transactions, we estimate that we will have $69.9 million of debt. Following this offering, we will have the ability to incur additional debt, including

under our revolving credit facility, subject to borrowing base limitations in our revolving credit facility. 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 existing and future debt arrangements will 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 than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be 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. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Revolving Credit Facility.”

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.

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 27% of our properties (measured by total reserves) and approximately 36% of our wells on a pro forma basis as of December 31, 2006. 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, 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 you. Please read “Business — Environmental Matters and Regulation” and “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 exploration and 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 ability to make distributions to you could be adversely affected. Please read “Business — Environmental Matters and Regulation” for more information.

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 and 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 your detriment.

Following the offering, affiliates of EAC will own 61.0% of our common units and control our general partner, which controls us. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to EAC. Furthermore, certain directors and officers of our general partner may be directors or 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. Please read “— 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.” 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 assets to us. Please read “— EAC is not limited in its ability to compete with us, which could limit our ability to acquire additional assets or businesses”;

	•	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 will 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. By purchasing common units, unitholders will be 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 reserves, each of which can affect the amount of cash that is distributed to unitholders;

	•	we intend to enter into an amended and restated administrative services agreement with Encore Operating, L.P. pursuant to which Encore Operating, L.P. will perform administrative services for us. Under the amended and restated administrative services agreement, Encore Operating, L.P. will receive 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, L.P. will have substantial discretion in determining which third-party expenses to incur on our behalf. We will also pay our share of expenses that are directly chargeable to wells under joint operating agreements. In addition, Encore Operating, L.P. will be 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 intends to limit 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% of the common units;

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

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

Please read “Certain Relationships and Related Party Transactions” and “Conflicts of Interest and Fiduciary Duties.”

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. Please read “Conflicts of Interest and Fiduciary Duties.”

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

Since an affiliate of EAC owns our general partner, it will have the ability to elect all the members of the board of directors of our general partner. Our general partner will have control over all decisions related to our operations. Since affiliates of EAC also will own 61.0% of our outstanding common units following the closing of this offering, the public unitholders will not have an ability to influence any operating decisions and will not be 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 Encore Operating, L.P., a wholly owned subsidiary 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 intend to enter into an amended and restated administrative services agreement with Encore Operating, L.P. pursuant to which Encore Operating, L.P. will perform administrative services for us, such as accounting, corporate development, finance, land, legal and engineering. Under the amended and restated administrative services agreement, Encore Operating, L.P. will receive 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, L.P. will have substantial discretion in determining which third-party expenses to incur on our behalf. We will also pay our share of expenses that are directly chargeable to wells under joint operating agreements. In addition, Encore Operating, L.P. will be 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. Affiliates of our general partner and Encore Operating, L.P. 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, Encore Operating, L.P. and their affiliates. If the officers of our general partner and the employees of Encore Operating, L.P. and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

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

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


	•	permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;

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

	•	generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not


		involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may 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 non-appealable 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.

By purchasing a common unit, a unitholder will become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”

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 will 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 will be chosen by EAC. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will 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 will be unable initially to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon completion of this offering to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove the general partner. Following the closing of this offering, our general partner and its affiliates will own 61.0% of our aggregate outstanding common units.

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

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

We may issue additional units, including units that are senior to the common units, without your approval, which would dilute your ownership interests.

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% 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% 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.

After this offering, EAC will hold an aggregate of 14,062,247 common units. The sale of these units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

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

If at any time our general partner and its affiliates own more than 80% 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, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You also may incur a tax liability upon a sale of your common units. At the completion of this offering, our general partner and its affiliates will own 61.0% of our outstanding common units. For additional information about this call right, please read “The Partnership Agreement — Limited Call Right.”

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

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

	•	your right 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.

Please read “The Partnership Agreement — Limited Liability” for a discussion of the implications of the limitations of liability on a unitholder.

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 you 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. Please read “Description of the Common Units — Transfer of Common Units” and “The Partnership Agreement — Non-Eligible Holders; Redemption.”

Unitholders may have limited liquidity for their common units, a trading market may not develop for the common units and you may not be able to resell your common units at or above the initial public offering price.

Prior to the offering, there has been no public market for the common units. After the offering, there will be 9,000,000 publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

If our common unit price declines after the initial public offering, you could lose a significant part of your investment.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control.

In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

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

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited 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.

You will experience immediate and substantial dilution of $8.83 per common unit.

At an assumed initial public offering price of $21.00 per common unit, our common unit price would exceed our pro forma net tangible book value of $12.17 per common unit. Based on the assumed initial public offering price, you would incur immediate and substantial dilution of $8.83 per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded at their historical cost, and not their fair value, in accordance with GAAP. Please read “Dilution.”

Tax Risks to Common Unitholders

In addition to reading the following risk factors, you should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of our common units.

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 you 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% and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you 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 will be subject to a new entity-level tax, the Texas margin tax, at an effective rate of up to 0.7% on the portion of our income that is generated in 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 you.

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. Please read “Material Tax Consequences — Disposition of Common Units — Allocations Between Transferors and Transferees.”

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 you.

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 expressed in this prospectus 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.

You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

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

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

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

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 you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material Tax

Consequences — Uniformity of Units” for a further discussion of the effect of the depletion, depreciation and amortization positions we will adopt.

You 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, you 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. You 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, you may be subject to penalties for failure to comply with those requirements. We initially will own property and conduct business in Wyoming, Montana and Texas. 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 your 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% 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% 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. Please read “Material Tax Consequences — Disposition of Common Units — Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

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.

USE OF PROCEEDS

We intend to use the estimated net proceeds of approximately $172.0 million from this offering, after deducting underwriting discounts and a structuring fee of $13.2 million in the aggregate and estimated offering expenses of approximately $3.8 million, to:


	•	repay all $120.0 million of indebtedness, together with accrued interest of approximately $6.9 million, under a subordinated term loan agreement with one of EAC’s subsidiaries; and


	•	repay $45.1 million of indebtedness under our revolving credit facility.

An affiliate of RBC Capital Markets Corporation, one of the underwriters in this offering, is a lender under our revolving credit facility and, accordingly, will receive a portion of the proceeds from this offering through the repayment of indebtedness under that facility. See “Underwriting — Affiliations.”

A $1.00 increase or decrease in the assumed initial public offering price of $21.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, the structuring fee and estimated offering expenses, to increase or decrease by approximately $8.4 million.

On March 7, 2007, we acquired oil and natural gas properties and related assets in the Elk Basin for approximately $329.4 million, including estimated transaction costs of approximately $1.0 million. We partially financed the acquisition and related costs with borrowings of $115.0 million under our revolving credit facility (excluding $1.6 million of debt issuance costs) and proceeds from a $120.0 million subordinated term loan from EAP Operating, Inc., a wholly owned subsidiary of EAC. As of June 30, 2007, the interest rate was 7.1% under the revolving credit facility and 10.3% under the subordinated term loan. The revolving credit facility matures on March 7, 2012, and the subordinated term loan matures on March 7, 2013. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Revolving Credit Facility” and “— Subordinated Term Loan.”

We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units to repay additional indebtedness under our revolving credit facility.

CAPITALIZATION

The following table shows:


	•	the historical capitalization of Encore Energy Partners LP and Encore Energy Partners LP Predecessor as of June 30, 2007; and


	•	our pro forma capitalization as of June 30, 2007, adjusted to reflect this offering, the application of the net proceeds we expect to receive as described under “Use of Proceeds” and the subsequent amendment to our revolving credit facility.

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” For a description of the pro forma adjustments, please read our Unaudited Pro Forma Balance Sheet included elsewhere in this prospectus.


	As of June 30, 2007
	Historical		Pro Forma(1)
	(In thousands)

Debt:
Current:
Revolving credit facility(2)	$	115,000	$	—
Long-term:
Revolving credit facility(2)		—		66,671	(3)
Subordinated term loan		123,641		—

Total debt		238,641		66,671	(3)

Partners’ equity:
Predecessor business		119,293		—
Common units-public		—		111,392
Common units-EAC		—		174,046
General partner’s interest		—		5,825
Management incentive units		—		—

Total partners’ equity		119,293		291,263

Total capitalization	$	357,934	$	357,934


(1)		Assumes an initial public offering price of our common units of $21.00 per unit and reflects partner capital of common unitholders from the net proceeds of this offering of approximately $172.0 million, including underwriting discounts and a structuring fee of $13.2 million in the aggregate and estimated offering expenses of approximately $3.8 million. A $1.00 increase or decrease in the assumed initial public offering price per common unit would increase or decrease, respectively, the net proceeds by approximately $8.4 million. The pro forma information discussed above is illustrative only and following completion of this offering will be adjusted based on the actual initial public offering price and other terms of this offering determined at pricing.


(2)		On a pro forma basis, outstanding borrowings under the revolving credit facility have been reclassified from current to long-term due to an amendment to the facility.


(3)		Excludes approximately $3.2 million of additional debt to be outstanding under the revolving credit facility as of the closing of the offering, which would result in total debt of $69.9 million. This amount approximates the additional accrued interest to be incurred under the subordinated term loan during the third quarter of 2007.

This table does not reflect the issuance of up to an additional 1,350,000 common units that may be sold to the underwriters upon exercise of their option to purchase additional common units.

DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the net tangible book value per common unit after the offering. Net tangible book value is our total tangible assets less total liabilities. Assuming an initial public offering price of $21.00 per common unit, on a pro forma basis as of June 30, 2007, after giving effect to the offering of common units and the application of the related net proceeds and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value was $286.5 million, or $12.17 per common unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for accounting purposes, as illustrated in the following table:


Assumed initial public offering price per common unit			$	21.00
Pro forma net tangible book value per common unit before the offering(1)	$	7.88
Increase in net tangible book value per common unit attributable to purchasers in the offering		4.29

Less: Pro forma net tangible book value per common unit after the offering(2)				12.17

Immediate dilution in net tangible book value per common unit to new investors(3)			$	8.83


(1)		Determined by dividing the net tangible book value of our properties by the number of units (14,062,247 common units and 481,883 general partner units) to be issued to our general partner and its affiliates for their contribution of our properties to us. Does not include 550,000 management incentive units, which will not have any liquidation value immediately following the completion of this offering.

(2)		Determined by dividing the total number of units to be outstanding after this offering (23,062,247 common units and 481,883 general partner units) into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of this offering. Does not include 550,000 management incentive units, which will not have any liquidation value immediately following the completion of this offering.


(3)		If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $9.47 or $8.19, respectively.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates in respect of their units and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:


	Units Acquired					Total Consideration
	Number		Percent			$		Percent
			(In millions)

General partner and its affiliates(1)(2)		14,544,130		61.8	%	$	119.6		38.8	%
New investors		9,000,000		38.2	%		189.0		61.2	%

Total		23,544,130		100.0	%	$	308.6		100.0	%


(1)		Upon the consummation of the transactions contemplated by this prospectus, our general partner and its affiliates will own 14,062,247 common units and 481,883 general partner units. Does not include 550,000 management incentive units, which will not have any liquidation value immediately following the completion of this offering. We did not receive any cash consideration in exchange for the issuance of management incentive units.

(2)		The assets contributed by affiliates of the general partner were recorded at their book value in accordance with GAAP.

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “— Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma operating results, you should refer to our audited carve out financial statements for the years ended December 31, 2004, 2005 and 2006, our unaudited combined historical and carve out financial statements for the six months ended June 30, 2006 and 2007 and our unaudited pro forma financial statements for the year ended December 31, 2006 and for the six months ended June 30, 2007, included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy. Our partnership agreement requires us to distribute all of our available cash quarterly. 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. We intend to fund a portion of our capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. Our partnership agreement will not restrict our ability to borrow to pay distributions. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it. Also, because we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case if we were subject to federal income tax.

Restrictions and Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy. There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy is subject to certain restrictions and may be changed at any time, including:


	•	Our cash distribution policy is subject to restrictions on distributions under our revolving credit facility. Specifically, our revolving credit facility contains material financial tests and covenants that we must satisfy. These financial tests and covenants include a requirement that our ratio of (1) consolidated funded debt to consolidated adjusted EBITDA be not more than 3.5 to 1.0, (2) consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees be not less than 1.5 to 1.0, (3) consolidated EBITDA to consolidated senior interest expense of not less than 2.5 to 1.0, and (4) current assets to current liabilities be equal to or greater than 1.0 to 1.0. These financial ratios and covenants are described, and consolidated EBITDA and consolidated adjusted EBITDA for this purpose are defined, under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Revolving Credit Facility.” Should we be unable to satisfy these restrictions under our revolving credit facility or if we are otherwise in default under our revolving credit facility, we would be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy. Any future indebtedness may contain similar or more stringent restrictions.


	•	Our general partner will have the authority to establish reserves for the conduct of our business and for future cash distributions to our unitholders, and the establishment of those reserves could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish reserves made by our general partner in good faith will be binding on the unitholders. We intend to reserve a substantial portion of our cash generated from operations to fund our exploitation and development capital expenditures and to acquire additional oil and natural gas properties and related assets. Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient cash expenditures to maintain or grow 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. We will be unable to sustain distributions at the level of


		our estimated initial quarterly distribution without making accretive acquisitions or substantial capital expenditures that maintain or grow our asset base. Decreases in commodity prices from current levels will also adversely affect our ability to pay distributions. If our asset base decreases and we do not reduce our distributions, a portion of the distributions may be considered a return of part of your investment in us as opposed to a return on your investment.


	•	While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended by a vote of the holders of a majority of our common units. At the closing of this offering, affiliates of EAC will own our general partner and approximately 61.0% of our outstanding common units and will have the ability to amend our partnership agreement without the approval of any other unitholders.

	•	Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

	•	Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.

	•	We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including reduced demand for oil and natural gas, increases in our operating or general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.

Our Ability to Grow Depends on Our Ability to Access External Growth Capital. We expect that we will distribute all of our available cash to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, rather than cash reserves established by our general partner, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may impact the available cash that we have to distribute on each unit. There are no limitations in our partnership agreement and our revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

Our Initial Distribution Rate

Upon completion of this offering, the board of directors of our general partner will adopt a cash distribution policy that will require us to pay distributions at an initial distribution rate of $0.35 per unit per complete quarter, or $1.40 per unit per year, on all common units, management incentive units and general partner units no later than 45 days after the end of each fiscal quarter to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. This equates to an aggregate cash distribution of $8.4 million per quarter or $33.7 million per year, in each case based on the number of common units, management incentive units and general partner units outstanding immediately after completion of this offering. If the underwriters exercise their option to purchase additional common units in full, 24,385,247 common units, 550,000 management incentive units and 508,883 general partner units will be outstanding. This equates to an aggregate cash distribution of $8.9 million per quarter or $35.6 million per year in the event the underwriters exercise their option to purchase additional common units in full. Accordingly, the exercise of the underwriters’ option will increase the total amount of units outstanding and the amount of cash needed to pay the initial distribution rate on all units.

The table below sets forth the assumed number of outstanding common units (assuming no exercise and full exercise of the underwriters’ option to purchase additional common units), management incentive units and general partner units upon the closing of this offering and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our initial distribution rate of $0.35 per common unit per quarter ($1.40 per common unit on an annualized basis).


	No Exercise of the Underwriters’						Full Exercise of the Underwriters’
	Option to Purchase Additional Common Units						Option to Purchase Additional Common Units
	Number of		Distributions				Number of		Distributions
	Units		One Quarter		Four Quarters		Units		One Quarter		Four Quarters

Common units held by the public		9,000,000	$	3,150,000	$	12,600,000		10,350,000	$	3,622,500	$	14,490,000
Common units held by EAC subsidiaries		14,062,247		4,921,787		19,687,146		14,035,247		4,912,337		19,649,346
General partner units		481,883		168,659		674,636		508,883		178,109		712,436
Management incentive units		550,000		192,500		770,000		550,000		192,500		770,000

Total		24,094,130	$	8,432,946	$	33,731,782		25,444,130	$	8,905,446	$	35,621,782

We do not have a legal obligation to pay distributions at our initial distribution rate or at any other rate except as provided in our partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of expenses and the amount of reserves our general partner determines is necessary or appropriate to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the upcoming four quarters.

Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or imposed at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above; however, our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard other than the requirement to act in good faith. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interests.

Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. Our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended by a vote of the holders of a majority of our common units. At the closing of this offering, EAC will own our general partner and approximately 61.0% of our outstanding common units and will have the ability to amend our partnership agreement without the approval of any other unitholders.

Distributions will not be cumulative. If distributions on our units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders, including our general partner, will not be entitled to receive such payments in the future. We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the 1st of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. Assuming that we become a publicly traded partnership before September 30, 2007, we will pay unitholders a prorated distribution for the period from the closing of the offering through September 30, 2007.

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our initial distribution rate of $0.35 per unit each quarter through the quarter ending September 30, 2008. In those sections, we present two tables, consisting of:


	•	Our “Unaudited Pro Forma Available Cash,” in which we present the amount of cash we would have had available for the year ended December 31, 2006 and for the twelve months ended June 30, 2007 based on our unaudited pro forma financial statements. Our calculation of pro forma available cash in this table should only be viewed as a general indication of the amount of available cash that we might have generated had we been formed in an earlier period.

	•	Our “Estimated Cash Available for Distribution,” in which we present how we calculate the estimated minimum Adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay the full initial quarterly distribution on all the outstanding units for each quarter through September 30, 2008. In “— Assumptions and Considerations” below, we also present our assumptions underlying our belief that we will generate sufficient Adjusted EBITDA to pay the initial quarterly distribution on all units for each quarter through September 30, 2008.

Unaudited Pro Forma Available Cash for the Year Ended December 31, 2006 and for the Twelve Months Ended June 30, 2007

If we had completed the transactions contemplated in this prospectus on January 1, 2006, our pro forma available cash for the year ended December 31, 2006 and for the twelve months ended June 30, 2007 would have been approximately $46.8 million and $46.2 million, respectively. Assuming the underwriters do not exercise their option to purchase additional common units, pro forma available cash would have exceeded the amount necessary to make a cash distribution at the initial distribution rate of $0.35 per unit per quarter (or $1.40 per unit on an annualized basis) on all of the common units, management incentive units and general partner units outstanding after the closing of this offering for the year ended December 31, 2006 and for the twelve months ended June 30, 2007 by approximately $13.0 million and $12.5 million, respectively. Assuming the underwriters exercise in full their option to purchase additional common units, pro forma available cash would increase to $48.4 million and $47.8 million for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, respectively, due to lower interest expense resulting from additional indebtedness repaid with the proceeds. These amounts would have exceeded the amount necessary to make a cash distribution at the initial distribution rate of $0.35 per unit per quarter (or $1.40 per unit on an annualized basis) on all of the common units, management incentive units and general partner units outstanding after the closing of this offering for the year ended December 31, 2006 and for the twelve months ended June 30, 2007 by approximately $12.8 million and $12.2 million, respectively.

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma available cash only as a general indication of the amount of cash available to pay distributions that we might have generated had we been formed in an earlier period.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, the amount of available cash that would have been available for distributions to our unitholders, assuming that the formation transactions and this offering occurred on January 1, 2006, and that the underwriters did not exercise their option to purchase additional common units. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.

Encore Energy Partners LP
Unaudited Pro Forma Available Cash


	Pro Forma		Pro Forma
	Year Ended		Twelve Months Ended
	December 31, 2006		June 30, 2007
	(In thousands, except per unit data)

Net income	$	20,098	$	12,964
Plus:
Interest expense		4,264		4,414
Depletion, depreciation and amortization expense		30,867		30,250
Unrealized loss on commodity derivative contracts		—		6,497
Income taxes		122		161

Adjusted EBITDA(1)		55,351		54,286
Less:
Cash taxes		—		39
Cash interest expense(2)		3,941		4,091
Capital expenditures(3)		2,646		1,962
Estimated incremental general and administrative expenses(4)		2,000		2,000

Pro forma available cash	$	46,764	$	46,194

Distributions per unit	$	1.40	$	1.40

Pro forma cash distributions:(5)
Distribution to our general partner	$	675	$	675
Distribution to public common unitholders		12,600		12,600
Distribution to common units held by our general partner and its affiliates		19,687		19,687
Distribution to management incentive units		770		770

Total distributions	$	33,732	$	33,732

Excess	$	13,032	$	12,462


(1)		Please read “Prospectus Summary — Non-GAAP Financial Measures.”


(2)		Reflects the interest expense related to $64.6 million in borrowings under our revolving credit facility at an assumed annual interest rate of 6.1% and 6.3% for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, respectively. If the interest rate used to calculate this interest were 1.0% higher or lower, our annual cash interest cost would increase or decrease, respectively, by approximately $0.6 million.


(3)		Represents pro forma capital expenditures for the Elk Basin properties and the Permian Basin properties for the year ended December 31, 2006 and for the twelve months ended June 30, 2007.

(4)		Reflects estimated incremental general and administrative expenses as a result of being a publicly traded limited partnership.

(5)		The table below sets forth pro forma available cash, distributions per unit, pro forma cash distributions and the excess of our pro forma available cash for the periods indicated assuming full exercise of the underwriters’ option to purchase additional common units:


	Pro Forma		Pro Forma
	Year Ended		Twelve Months Ended
	December 31, 2006		June 30, 2007
	(In thousands)

Pro forma available cash	$	48,371	$	47,772

Distributions per unit	$	1.40	$	1.40

Pro forma cash distributions:
Distributions to our general partner	$	712	$	712
Distributions to public common unitholders		14,490		14,490
Distributions to common units held by our general partner and its affiliates		19,649		19,649
Distributions to management incentive units		770		770

Total distributions	$	35,621	$	35,621

Excess	$	12,750	$	12,151

Our cash interest expense for the year ended December 31, 2006 and the twelve months ended June 30, 2007 would decrease by $1.6 million for both periods due to the repayment of additional indebtedness under our revolving credit facility with the proceeds from the full exercise of the underwriters’ option to purchase additional common units.

Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2008

In order to pay the initial quarterly distribution on all our common units, management incentive units and general partner units of $0.35 per unit per complete quarter for four quarters, we estimate that our Adjusted EBITDA for the twelve months ending September 30, 2008 must be at least $46.6 million. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure our operating performance, liquidity or ability to service debt obligations. Please read “Prospectus Summary — Summary Historical and Pro Forma Financial Data” and “— Non-GAAP Financial Measures” for an explanation of Adjusted EBITDA and reconciliations of Adjusted EBITDA to net income and net cash from operating activities, its most directly comparable financial performance and liquidity measures calculated in and presented in accordance with GAAP.

We also anticipate that if our Adjusted EBITDA for such period is at or above our estimate, we would be permitted to make the quarterly distributions on all the common units, management incentive units and general partner units at the initial distribution rate under the applicable covenants under our revolving credit facility.

We believe that we will be able to generate the estimated minimum Adjusted EBITDA of $46.6 million for the twelve months ending September 30, 2008. You should read “— Assumptions and Considerations” below for a discussion of the material assumptions underlying this belief, which reflect our judgment of conditions we expect to exist and the course of action we expect to take. If our estimate is not achieved, we may not be able to pay the initial quarterly distribution on all of our units. We can give you no assurance that our assumptions will be realized or that we will generate the $46.6 million in estimated minimum Adjusted EBITDA required to pay the initial quarterly distribution on all our common units, management incentive units and general partner units. There will likely be differences between our estimates and the actual results we will achieve and those differences could be material. If we do not generate the estimated minimum Adjusted EBITDA or if our capital expenditures or interest expense are higher than estimated, we may not be able to pay the initial quarterly distribution on all units. Assuming the underwriters do not exercise their option to purchase additional common units, in order to fund distributions on all our common units, management incentive units and general partner units at the initial distribution rate of $1.40 per unit for the twelve months ending September 30, 2008, we estimate that our minimum Adjusted EBITDA for the twelve months ending September 30, 2008 must be at least $46.6 million. Assuming the underwriters exercise in full their option to purchase additional common units, in order to fund distributions on all our common units,

management incentive units and general partner units at the initial distribution rate of $1.40 per unit for the twelve months ending September 30, 2008, we estimate that our minimum Adjusted EBITDA for the twelve months ending September 30, 2008 must be at least $46.8 million.

When considering our ability to generate the estimated minimum Adjusted EBITDA of $46.6 million, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” and elsewhere in this prospectus. Any of these factors or the other risks discussed in this prospectus could cause our results of operations and cash available for distribution to our unitholders to vary significantly from those set forth below.

We do not as a matter of course make public projections as to future sales, earnings or other results. However, our management has prepared the prospective financial information set forth below to present the estimated cash available for distribution for the twelve months ending September 30, 2008. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments and presents, to the best of our management’s knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

Neither our independent registered public accounting firm, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and they assume no responsibility for, and disclaim any association with, the prospective financial information.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast or the assumptions used to prepare the forecast to reflect events or circumstances after the date in this prospectus. In light of the above, the statement that we believe that we will have sufficient cash available for distribution to allow us to make the full initial quarterly distribution on all of our outstanding common units, management incentive units and general partner units for each quarter through September 30, 2008 should not be regarded as a representation by us or the underwriters or any other person that we will make such distributions. Therefore, you are cautioned not to place undue reliance on this information.

The following table shows how we calculate the estimated minimum Adjusted EBITDA necessary to pay the initial quarterly distribution on all our common units, management incentive units and general partner units for each quarter in the twelve months ending September 30, 2008. Our estimated Adjusted EBITDA is based on the projected results of operations from all of our operating subsidiaries for the twelve months ending September 30, 2008 and assumes that the underwriters do not exercise their option to purchase additional common units. The assumptions that we have made that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes set forth in “— Assumptions and Considerations.”

Encore Energy Partners LP
Estimated Cash Available for Distribution


									Twelve Months
	Three Months Ending								Ending
	December 31,		March 31,		June 30,		September 30,		September 30,
	2007		2008		2008		2008		2008
	(In thousands, except per unit data)

Oil and natural gas revenues	$	20,369	$	20,181	$	19,046	$	18,880	$	78,476
Marketing and other		1,334		1,320		1,320		1,334		5,308

Total operating revenues		21,703		21,501		20,366		20,214		83,784
Production taxes		2,579		2,556		2,413		2,391		9,939
Lease operations expenses		3,843		3,537		3,614		3,809		14,803
Marketing and other operating expenses		1,388		1,374		1,370		1,382		5,514
General and administrative expenses		1,227		1,214		1,193		1,186		4,820
Depletion, depreciation and amortization expense		8,201		8,040		7,892		7,834		31,967
Derivative fair value loss		314		465		669		800		2,248
Interest expense		1,114		1,084		1,077		1,085		4,360
Income taxes		24		24		22		22		92

Net income		3,013		3,207		2,116		1,705		10,041
Adjustments to reconcile net income to estimated Adjusted EBITDA:
Add:
Depletion, depreciation and amortization expense		8,201		8,040		7,892		7,834		31,967
Unrealized loss on commodity derivative contracts		682		829		1,033		1,168		3,712
Interest expense		1,114		1,084		1,077		1,085		4,360
Income taxes		24		24		22		22		92
Other		98		99		100		101		398

Estimated Adjusted EBITDA(1)		13,132		13,283		12,240		11,915		50,570
Adjustments to reconcile estimated Adjusted EBITDA to estimated cash available for distribution:
Less:
Cash interest expense		1,033		1,003		996		1,004		4,036
Cash income taxes		24		24		22		22		92
Capital expenditures(2)		2,175		2,175		2,175		2,175		8,700

Estimated cash available for distribution	$	9,900	$	10,081	$	9,047	$	8,714	$	37,742

Per unit cash distribution for the period	$	0.35	$	0.35	$	0.35	$	0.35	$	1.40

Distributions to our general partner	$	169	$	169	$	169	$	169	$	675
Distributions to public common unitholders		3,150		3,150		3,150		3,150		12,600
Distributions to common units held by our general partner and its affiliates		4,922		4,922		4,922		4,922		19,687
Distributions to management incentive units		193		193		193		193		770

Total distributions for the period	$	8,434	$	8,434	$	8,434	$	8,434	$	33,732

Excess of cash available for distribution over cash distributions for the period	$	1,466	$	1,647	$	613	$	280	$	4,010

Estimated Adjusted EBITDA	$	13,132	$	13,283	$	12,240	$	11,915	$	50,570
Less:
Excess of cash available for distribution over cash distributions for the period		1,466		1,647		613		280		4,010

Minimum estimated Adjusted EBITDA necessary to pay cash distributions for the period	$	11,666	$	11,636	$	11,627	$	11,635	$	46,560


(1)		Please read “Prospectus Summary — Non-GAAP Financial Measures.”


(2)		We expect to incur approximately $7.3 million of actual capital expenditures for the twelve months ending September 30, 2008. Over the three-year period ending September 30, 2010, we expect that our capital expenditures will average approximately $8.7 million.

(3)		The table below sets for the estimated cash available for distribution, estimated Adjusted EBITDA and the minimum estimated Adjusted EBITDA necessary to pay cash distributions for the periods indicated assuming full exercise of the underwriters’ option to purchase additional common units:


									Twelve Months
	Three Months Ending								Ending
	December 31,		March 31,		June 30,		September 30,		September 30,
	2007		2008		2008		2008		2008
	(In thousands, except per unit data)

Estimated cash available for distribution	$	10,341	$	10,492	$	9,451	$	9,126	$	39,410

Per unit cash distribution for the period	$	0.35	$	0.35	$	0.35	$	0.35	$	1.40

Distributions to our general partner	$	178	$	178	$	178	$	178	$	712
Distributions to public common unitholders		3,623		3,623		3,623		3,623		14,490
Distributions to common units held by our general partner and its affiliates		4,912		4,912		4,912		4,912		19,649
Distributions to management incentive units		193		193		193		193		770

Total distributions for the period	$	8,906	$	8,906	$	8,906	$	8,906	$	35,621

Excess of cash available for distribution over cash distributions for the period	$	1,435	$	1,586	$	545	$	220	$	3,789

Estimated Adjusted EBITDA	$	13,132	$	13,283	$	12,240	$	11,915	$	50,570
Less:
Excess of cash available for distribution over cash distributions for the period		1,435		1,586		545		220		3,789

Minimum estimated Adjusted EBITDA necessary to pay cash distributions for the period	$	11,697	$	11,697	$	11,695	$	11,695	$	46,781

Assuming full exercise of the underwriters’ option to purchase additional common units, our cash interest expense would decrease by approximately $0.4 million for each of the three months ending December 31, 2007, March 31, 2008, June 30, 2008 and September 30, 2008 and would decrease by $1.7 million for the twelve months ending September 30, 2008, due to the repayment of additional indebtedness under our revolving credit facility with the proceeds from the full exercise of the underwriters’ option to purchase additional common units.

Assumptions and Considerations

Based upon the specific assumptions outlined below with respect to the twelve months ending September 30, 2008, we expect to generate cash flow from operations in an amount sufficient to fund our budgeted capital expenditures, establish cash reserves and pay the initial quarterly distribution on all units through September 30, 2008.

While we believe that these assumptions are reasonable in light of management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions do not materialize, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay the full initial quarterly distribution (absent borrowings under our revolving credit facility), or any amount, on all units, in which event the market price of our common units may decline substantially. We will be unable to sustain our current level of distributions without making accretive acquisitions or substantial capital expenditures that maintain or grow our asset base.

Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient cash expenditures to maintain or grow 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. Decreases in commodity prices from current levels will adversely affect our ability to pay distributions. If our asset base decreases and we do not reduce our distributions, a portion of the distribution may be considered a return of part of your investment in us as opposed to a return on your investment. When reading this section, you should keep in mind the risk factors and other cautionary statements under the headings “Risk Factors,” and “Forward-Looking Statements.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

Operations and Revenue

Production. The following table sets forth information regarding net production of oil and natural gas on a pro forma basis for the year ended December 31, 2006 and on a forecasted basis for the twelve months ending September 30, 2008:


							Forecasted for
	Pro Forma for Year						Twelve Months Ending
	Ended December 31, 2006						September 30, 2008
	Elk Basin		Permian Basin		Total			Total

Oil (MBbl)		1,266		7		1,273			1,255
Natural gas (MMcf)		362		1,796		2,158			2,132
Combined (MBOE)		1,326		306		1,632			1,611

Oil (Bbl/D)		3,470		18		3,488			3,440
Natural gas (Mcf/D)		992		4,920		5,912			5,840
Combined (BOE/D)		3,633		838		4,471			4,413

We estimate that our oil and natural gas production for the twelve months ending September 30, 2008 will be 1,611 MBOE as compared to 1,632 MBOE on a pro forma basis for the year ended December 31, 2006. The one percent decline in forecasted production for the twelve months ending September 30, 2008 from our pro forma production for the year ended December 31, 2006 is due in part to limited capital expenditures in the Elk Basin field during the year ended December 31, 2006 and subsequent periods prior to our ownership. The forecast reflects an estimated 4.4% natural proved developed producing production decline rate of the Elk Basin field and a 10.0% natural proved developed producing production decline rate of our Permian Basin properties, which is offset by increased production resulting from our 2007 and 2008 drilling program. Our weighted average proved developed producing production decline rate is approximately 5.5% per year.

During the first half of 2007, an additional 9 gross (0.9 net) wells commenced production in the Permian Basin, and we expect that 12 gross (4.7 net) wells will commence production by September 30, 2008. We expect to drill 6 gross (5.9 net) additional wells in the Elk Basin during the twelve months ending September 30, 2008. All of the wells drilled and completed to date in 2007 are producing in paying quantities. We have assumed that we will be successful in producing crude oil and natural gas in commercial quantities for all additional wells based on past drilling performance in our fields.

Prices. The table below illustrates the relationship between oil and natural gas wellhead prices as a percentage of average NYMEX prices on a pro forma basis for the year ended December 31, 2006 as compared to our forecast for the twelve months ending September 30, 2008:


										Forecasted for
	Pro Forma for Year									Twelve Months Ending
	Ended December 31, 2006									September 30, 2008
	Elk Basin			Permian Basin			Total				Total

Oil:
Average NYMEX oil ($/Bbl)	$	66.22		$	66.22		$	66.22			$	67.00
Differential to NYMEX		(15.91	)		(4.04	)		(15.86	)			(15.09	)

Wellhead price	$	50.31		$	62.18		$	50.36			$	51.91

Differential percentage to NYMEX		(24	)%		(6	)%		(24	)%			(23	)%

Natural Gas:
Average NYMEX natural gas ($/Mcf)	$	6.99		$	6.99		$	6.99			$	7.00
Differential to NYMEX		(0.37	)		(0.12	)		(0.16	)			(0.75	)

Wellhead price	$	6.62		$	6.87		$	6.83			$	6.25

Differential percentage to NYMEX		(5	)%		(2	)%		(2	)%			(11	)%

Total combined wellhead price ($/BOE)	$	49.83		$	41.67		$	48.31			$	48.72

Our oil differential as a percentage of the average NYMEX price is expected to average 23% for the twelve months ending September 30, 2008 as compared to 24% on a pro forma basis for the year ended December 31, 2006. Our natural gas wellhead price as a percentage of the average NYMEX price is expected to average 11% for the twelve months ending September 30, 2008 as compared to 2% on a pro forma basis for the year ended December 31, 2006. The increase in our forecasted natural gas differential is due primarily to recent market conditions in the Rockies and Elk Basin resulting from limited take-away capacity.

Derivative Fair Value. The following table summarizes our oil derivative contracts covering forecasted production through the end of December 2010:


	Swaps				Floors				Ceiling
			Weighted				Weighted				Weighted
			Average				Average				Average
	Bbl/D		Price		Bbl/D		Price		Bbl/D		Price

Oil derivative contracts at July 31, 2007:
July 2007 — December 2008		—	$	—		2,500	$	65.00		—	$	—
January 2009 — December 2009		1,000	$	68.70		1,000	$	63.00		—	$	—
January 2010 — December 2010		—	$	—		1,000	$	65.00		500	$	79.05

The 2,500 Bbl/D oil derivative floor contracts described in the table above cover 73% of our forecasted oil production for the twelve months ending September 30, 2008.

The following table summarizes our natural gas derivative contracts covering forecasted production through December 2009:

Floor

Ceiling

Weighted

Average

Mcf/D

Price

Mcf/D

Price

Natural gas derivative contracts at July 31, 2007:

July 2007 — December 2009

4,000

7.70

2,000

9.85

The 4,000 Mcf/D natural gas derivative floor and ceiling contracts described in the table above cover 69% and 34%, respectively, of our natural gas forecasted production for the twelve months ending September 30, 2008.

We will not designate any of our commodity derivatives as hedges. We estimate that our derivative fair value loss for the twelve months ending September 30, 2008 will be approximately $2.2 million. We did not have any derivative contracts on a pro forma basis for the year ended December 31, 2006.

Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk.”

Oil and Natural Gas Revenues. The following table illustrates the primary components of oil and natural gas revenues on a pro forma basis for the year ended December 31, 2006 and on a forecasted basis for the twelve months ending September 30, 2008 (in thousands):


							Forecasted for
	Pro Forma for						Twelve Months Ending
	Year Ended December 31, 2006						September 30, 2008
	Elk Basin		Permian Basin		Total		Total

Oil wellhead revenues	$	63,695	$	409	$	64,104	$	65,156
Natural gas wellhead revenues		2,395		12,337		14,732		13,320

Total oil and natural gas revenues	$	66,090	$	12,746	$	78,836	$	78,476

Marketing and Other Revenues. We estimate that our marketing and other revenues for the twelve months ending September 30, 2008 will be approximately $5.3 million as compared to $3.6 million on a pro forma basis for the year ended December 31, 2006. The increase is primarily attributable to increased purchases of third-party production from a counterparty other than to whom the production is sold for aggregation and sale with our own equity production in various markets. These purchases are for strategic purposes to assist us in marketing our production by decreasing our dependence on individual markets. These activities allow us to aggregate larger volumes, facilitate our efforts to maximize the prices we receive for production, provide for a greater allocation of future pipeline capacity in the event of curtailments and enable us to reach other markets.

The following table shows estimated Adjusted EBITDA sensitivities under various assumed NYMEX oil and natural gas prices for the twelve months ending September 30, 2008. In addition, the estimated Adjusted EBITDA amounts shown below are based on realized oil prices that take into account our average NYMEX oil price differential assumptions of 23% and 11% of NYMEX for our Elk Basin and Permian Basin production. We have assumed no changes in our production based on changes in prices and that our commodity derivative counterparties will perform as expected (in thousands, except per unit, per day amounts and percentages).


Oil NYMEX price ($/Bbl)	$	30.00		$	40.00		$	50.00		$	60.00		$	67.00		$	70.00		$	80.00
Natural gas NYMEX price ($/Mcf)	$	4.00		$	5.00		$	6.00		$	7.00		$	7.00		$	8.00		$	9.00
Combined daily production (BOE/D)		4,413			4,413			4,413			4,413			4,413			4,413			4,413
Percentage oil		78	%		78	%		78	%		78	%		78	%		78	%		78	%
Total revenues	$	39,907		$	52,262		$	64,617		$	76,973		$	83,784		$	89,328		$	101,683
Plus:
Derivative fair value gain		37,913			27,290			16,667			6,043			1,464			365			—
Less:
Marketing and other operating costs		17,922			18,588			19,253			19,918			19,919			20,583			21,248
Production taxes		4,674			6,142			7,610			9,079			9,939			10,547			12,015
General and administrative expenses		4,820			4,820			4,820			4,820			4,820			4,820			4,820

Estimated Adjusted EBITDA	$	50,404		$	50,002		$	49,601		$	49,199		$	50,570		$	53,743		$	63,600

As NYMEX prices decline below $60.00 and $7.00 for oil and natural gas, respectively, our estimated Adjusted EBITDA for the twelve months ending September 30, 2008 is projected to increase due to gains on commodity derivatives and lower production taxes and price differentials, which are calculated based on a

percentage of wellhead prices as opposed to contract prices. As our commodity derivative contracts expire, we may not be able to realize increases in estimated Adjusted EBITDA in a period of declining commodity prices.

Capital Expenditures and Expenses

Capital Expenditures. We estimate that our capital expenditures for the twelve months ending September 30, 2008 will be approximately $7.3 million as compared to $2.6 million on a pro forma basis for the year ended December 31, 2006. We expect that our capital expenditures will average approximately $8.7 million over the three-year period ending June 30, 2010. The increased capital expenditures for the twelve months ending September 30, 2008 are expected to consist of the following:


	•	approximately $5.6 million for the drilling of 6 gross (6 net) wells in the Elk Basin and 8 gross (3 net) wells in the Permian Basin;

	•	approximately $0.9 million for workovers;

	•	approximately $0.6 million for equipment and facilities; and

	•	approximately $0.2 million for potential costs that we may incur for acquiring leases and similar expenditures that will enable us to maintain our capital asset base.

We expect to finance these capital expenditures with cash flow from operations.

Lease Operations Expense and Marketing and Other Operating Expenses. The following table summarizes lease operations expenses and marketing and other operating expenses on an aggregate basis and on a per BOE basis for the pro forma year ended December 31, 2006 and on a forecasted basis for the twelve months ending September 30, 2008 (in thousands, except per BOE amounts):


							Forecasted for the
							Twelve Months
	Pro Forma for Year Ended						Ending
	December 31, 2006						September 30, 2008
	Elk Basin		Permian Basin		Total		Total

Lease operations expenses	$	7,435	$	1,673	$	9,108	$	14,803
Marketing and other operating expenses		5,859		246		6,105		5,514

Total	$	13,294	$	1,919	$	15,213	$	20,317

Lease operations expenses ($/BOE)	$	5.61	$	5.47	$	5.58	$	9.19
Marketing and other operating expenses ($/BOE)		4.42		0.80		3.74		3.42

Total operating expenses ($/BOE)	$	10.03	$	6.27	$	9.32	$	12.61

We estimate that our lease operations expenses for the twelve months ending September 30, 2008 will be approximately $14.8 million as compared to $9.1 million on a pro forma basis for the year ended December 31, 2006. The $5.7 million increase in forecasted lease operations expenses is primarily attributable to the following:


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

	•	increased operational activity to maximize production and revenues.

Our marketing and other operating expenses consist primarily of purchases of natural gas for resale and third-party transportation expenses related to our oil and natural gas production. We estimate that our marketing and other operating expenses for the twelve months ending September 30, 2008 will be approximately $5.5 million as compared to $6.1 million of marketing and other operating expenses on a pro forma basis for the year ended December 31, 2006.

Production Taxes. The following table summarizes production taxes in the aggregate and as a percentage of wellhead revenues on a pro forma basis for the year ended December 31, 2006 and on a forecasted basis for the twelve months ending September 30, 2008 (in thousands, except percentages):


							Forecasted for the
							Twelve Months
	Pro Forma for Year Ended						Ending
	December 31, 2006						September 30, 2008
	Elk Basin		Permian Basin		Total		Total

Wellhead revenues	$	66,090	$	12,746	$	78,836	$	78,476
Production taxes	$	7,839	$	1,226	$	9,065	$	9,939
Production taxes as a percentage of wellhead		11.9%		9.6%		11.5%		12.7%

Our production taxes are calculated as a percentage of our oil and natural gas wellhead revenues. In general, as prices and volumes increase, our production taxes increase and as prices and volumes decrease, our production taxes decrease. Additionally, production tax percentages vary by state and as revenues by state vary, it can cause increases or decreases in our overall rate.

General and Administrative Expenses. We estimate that our general and administrative expenses for the twelve months ending September 30, 2008 will be approximately $4.8 million as compared to approximately $2.9 million on a pro forma basis for the twelve months ended December 31, 2006. Our forecasted general and administrative expenses include $2.0 million of incremental general and administrative expenses that we expect to incur as a result of being a public company, which are not included in our pro forma financial statements. These expenses will include costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. At the closing of this offering, we expect to enter into an amended and restated administrative services agreement with Encore Operating, L.P. whereby Encore Operating, L.P. will perform administrative services for us in exchange for an administrative fee of $1.75 per BOE of our production and reimbursement of actual third-party expenses incurred on our behalf. Encore Operating, L.P. will have substantial discretion in determining which third-party expenses to incur on our behalf. We will also pay our share of expenses that are directly chargeable to wells under joint operating agreements. In addition, Encore Operating, L.P. will be 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 have not included any non-cash expense related to the management incentive units in our forecast of general and administrative expenses.

Interest Expense. We estimate that our interest expense for the twelve months ending September 30, 2008 will be approximately $4.4 million, compared to interest expense of $4.3 million on a pro forma basis for the year ended December 31, 2006. During the twelve months ending September 30, 2008, we expect to have average debt outstanding under our revolving credit facility of approximately $63.9 million.

Regulatory, Industry and Economic Factors. Our forecast for the twelve months ending September 30, 2008 is based on the following significant assumptions related to regulatory, industry and economic factors:


	•	there will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or an interpretation of existing regulation, that will be materially adverse to our business;

	•	there will not be any major adverse change in the portions of the energy industry or in general economic conditions; and

	•	market, insurance and overall economic conditions will not change substantially.

Distributions


	•	Forecasted Distributions. Distributions on the common units, management incentive units and general partner units for the twelve months ending September 30, 2008 are forecasted to be $33.7 million in the aggregate. Quarterly distributions will be paid within 45 days after the close of each quarter.

HOW WE MAKE CASH DISTRIBUTIONS


	Distributions of Available Cash

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending September 30, 2007, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the initial quarterly distribution for the period from the closing of the offering through September 30, 2007 based on the actual length of the period.

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


	•	provide for the proper conduct of our business;

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

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

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

We will distribute 98% of our available cash to our unitholders, pro rata, and 2% of our available cash to our general partner. 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% of all distributions to our unitholders at the time of any such distribution. If the 5.1% 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 public unitholders.


	Management Incentive Units

General

In May 2007, the board of directors of our general partner granted management incentive units to the executive officers of our general partner. A management incentive unit is a limited partner interest in our partnership that entitles the holder to an initial quarterly distribution of $0.35 (or $1.40 on an annualized basis) to the extent paid to our common unitholders and to increasing distributions upon the achievement of 10% compounding increases in our distribution rate to common unitholders.

At the time of our initial public offering and assuming no exercise of the underwriters’ option to purchase additional common units, we expect that the management incentive units will be entitled to approximately 2.28% of our aggregate annual distributions (or $770,000 in the aggregate) (or 2.16% of aggregate annual distributions if the underwriters exercise their option to purchase additional common units in full). The holders of management incentive units will not be entitled to receive, in the aggregate, distributions of our available cash in an amount that exceeds a maximum limit of 5.1% of all such distributions to all unitholders at the time of any such distribution. If the 5.1% 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 public 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 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% 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% 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% 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% debt and 50% 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% of our distributions on a rolling four quarter basis.

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 public unitholders must increase by 10% on a compounded basis;

	•	*Annualized Distribution per Management Incentive Unit*: After distributions payable to our public unitholders have increased by 10% 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% of all distributions to our unitholders.

Annualized Management Incentive Distributions
Distribution Summary


		Annualized		Aggregate
Annualized		Distribution		Annualized
Distribution		per Management		Distributions to
per Common Unit		Incentive Unit		Management

$	1.40	$	1.40	$	770,000
$	1.54	$	1.93	$	1,058,750
$	1.69	$	2.65	$	1,455,781
$	1.86	$	3.64	$	2,001,674
$	2.05	$	5.00	$	2,752,329
$	2.25	$	6.88	$	3,784,515
$	2.48	$	9.46	$	5,203,640
$	2.73	$	13.01	$	7,155,042

For more information on our management incentive units, including conversion rights, please read “Management — Management Incentive Units” beginning on page 126.


	Distributions of Cash Upon Liquidation

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to our unitholders, our general partner and the holders of management incentive units in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.


	Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders, our general partner and the holders of management incentive units in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in our partners’ capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

The following table shows selected historical financial data of Encore Energy Partners LP Predecessor, our predecessor, summary historical financial data for Encore Energy Partners LP and pro forma financial data of Encore Energy Partners LP for the periods and as of the dates presented. The carve out financial statements of Encore Energy Partners LP Predecessor are comprised of certain of EAC’s oil and natural gas assets, liabilities and operations located in the Permian Basin of West Texas, which we refer to as the Permian Basin assets and which EAC will contribute to us on or prior to the completion of this offering. Due to the factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors Affecting Comparability of Future Results,” our future results of operations will not be comparable to Encore Energy Partners LP Predecessor historical results.

The selected historical financial data as of December 31, 2005 and 2006 and for the years ended December 31, 2004, 2005 and 2006 is derived from the audited carve out financial statements of Encore Energy Partners LP Predecessor included elsewhere in this prospectus. The selected historical financial data as of December 31, 2002, 2003 and 2004 and for the years ended December 31, 2002 and 2003 is derived from the unaudited carve out financial statements of Encore Energy Partners LP Predecessor. The selected historical financial data as of June 30, 2007 and for the six months ended June 30, 2006 and 2007 is derived from the unaudited combined historical and predecessor carve out financial statements of Encore Energy Partners LP included elsewhere in this prospectus.

March 2007 Transactions


	•	the borrowing by us of $120 million under a subordinated term loan agreement with a wholly owned subsidiary of EAC and $116.6 million under our revolving credit facility (including $1.6 million of debt issuance costs);

	•	a $93.7 million capital contribution by EAC to us, substantially all of which was used by us to fund a portion of the purchase price for the Elk Basin assets;

	•	the assignment of certain commodity derivative contracts to us by EAC (through its subsidiaries) covering certain future production from the Elk Basin assets;

	•	the acquisition of the Elk Basin assets for $329.4 million (including estimated transaction costs of approximately $1.0 million);

Closing Transactions


	•	the contribution of the Permian Basin assets to us in exchange for the issuance of 4,043,478 common units;

	•	the sale by us of 9,000,000 common units to the public in this offering;

	•	the issuance by us of additional general partner units to our general partner in exchange for common units to enable our general partner to maintain its 2% general partner interest;


	•	the execution by us of an amended and restated administrative services agreement with Encore Operating, L.P., as described in “Certain Relationships and Related Party Transactions — Amended and Restated Administrative Services Agreement”;


	•	the completion of this offering and the use of proceeds from this offering as described in “Use of Proceeds”; and

Subsequent Event


	•	the August 22, 2007 amendment to our revolving credit facility, which resulted in our ability to classify balances outstanding as long-term.

The unaudited pro forma balance sheet assumes the transactions listed above occurred on June 30, 2007. The unaudited pro forma statement of operations data assumes the transactions listed above occurred on January 1, 2006. We expect to incur incremental general and administrative expenses of $2.0 million per year as a result of being a publicly traded limited partnership. These expenses are not reflected in our historical financial statements or in our unaudited pro forma financial statements. Upon completion of this offering, the management incentive units granted to executive officers of our general partner will partially vest, at which point we will recognize an expense for the estimated fair value of the vested portion of the units. We will recognize additional expenses over at least the following two-year period as the management incentive units continue to vest. Because this expense is a non-recurring charge resulting directly from the completion of this offering, this expense is not reflected in our unaudited pro forma financial statements.

We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. The table should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The following table includes the non-GAAP financial measure of Adjusted EBITDA. For a definition of Adjusted EBITDA and reconciliations to our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP, please read “Prospectus Summary — Non-GAAP Financial Measures.”


																Encore Energy						Encore Energy Partners LP
																Partners LP(1)						(Pro Forma)
	Encore Energy Partners LP Predecessor															Six Months						Year Ended			Six Months
	Year Ended December 31,															Ended June 30,						December 31,			Ended June 30,
	2002			2003			2004			2005			2006			2006			2007			2006			2007
(In thousands, except per unit data)	(unaudited)															(unaudited)						(unaudited)

Statements of Operations Data:
Revenues:
Oil	$	383		$	366		$	442		$	535		$	409		$	174		$	20,469		$	64,104		$	30,928
Natural gas		8,368			12,708			12,791			16,366			12,337			6,719			5,904			14,732			6,031
Marketing and other		—			—			—			—			—			—			4,852			3,649			8,427

Total revenues		8,751			13,074			13,233			16,901			12,746			6,893			31,225			82,485			45,386

Expenses:
Production:
Lease operations		1,465			1,431			1,604			1,751			1,673			793			4,951			9,108			6,916
Production, ad valorem, and severance taxes		902			1,174			1,195			1,473			1,226			638			3,286			9,065			4,548
Depletion, depreciation, and amortization		1,741			1,544			1,394			1,286			1,200			580			10,412			30,867			14,867
General and administrative		371			441			477			572			631			326			1,092			2,856			1,342
Derivative fair value loss		—			—			—			—			—			—			6,497			—			6,497
Marketing and other operating		83			120			202			263			246			122			4,646			6,105			8,060

Total expenses		4,562			4,710			4,872			5,345			4,976			2,459			30,884			58,001			42,230

Operating income		4,189			8,364			8,361			11,556			7,770			4,434			341			24,484			3,156

Other income (expenses):
Interest		—			—			—			—			—			—			(6,444	)		(4,264	)		(2,205	)
Other		—			—			—			—			—			—			27			—			27

Other income (expenses)		—			—			—			—			—			—			(6,417	)		(4,264	)		(2,178	)

Income (loss) before income taxes		4,189			8,364			8,361			11,556			7,770			4,434			(6,076	)		20,220			978
Income tax provision		—			—			—			—			(122	)		—			(39	)		(122	)		(39	)

Net income (loss)	$	4,189		$	8,364		$	8,361		$	11,556		$	7,648		$	4,434		$	(6,115	)	$	20,098		$	939

Pro forma net income per limited partner unit																						$	0.85		$	0.04
Adjusted EBITDA							$	9,755		$	12,842		$	8,970		$	5,014		$	17,277		$	55,351		$	24,547
Balance Sheet Data (at period end):
Working capital(2)	$	1,749		$	1,890		$	2,257		$	3,505		$	1,633					$	(107,455	)				$	7,545
Total assets		25,188			25,641			26,794			29,133			26,923						379,884						379,884
Long-term debt		—			—			—			—			—						123,641						66,671
Partners’/Owner’s equity		24,659			25,045			25,822			27,954			25,719						119,293						291,263

Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	5,558		$	9,715		$	9,394		$	11,604		$	10,919		$	6,611		$	5,203
Investing activities		(401	)		(1,737	)		(1,810	)		(2,180	)		(1,036	)		(73	)		(327,524	)
Financing activities		(5,157	)		(7,978	)		(7,584	)		(9,424	)		(9,883	)		(6,538	)		323,669


(1)		Represents the combined historical and predecessor carve out financial statements of Encore Energy Partners LP.


(2)		Working capital at June 30, 2007 includes $115 million of borrowings under our revolving credit facility on a historical basis. On a pro forma basis, the revolving credit facility is classified as long-term debt.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Selected Historical and Pro Forma Financial Data” and the accompanying financial statements and related notes included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We are a growth-oriented Delaware limited partnership formed on February 13, 2007 by Encore Acquisition Company (NYSE: 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 initial 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 Elk Basin of Wyoming and Montana and the Permian Basin of West Texas.

Our assets in the Elk Basin were acquired from subsidiaries of Anadarko Petroleum Corporation in March 2007 for approximately $329.4 million, including estimated transaction costs of approximately $1.0 million. For the year ended December 31, 2006, production from our Elk Basin properties was approximately 3,633 BOE/D, of which approximately 95% was oil and 5% was natural gas. From the date of acquisition through June 30, 2007, production from our Elk Basin properties was approximately 3,591 BOE/D, of which approximately 97% was oil and 3% was natural gas. On a pro forma basis for the six months ended June 30, 2007, production from our Elk Basin properties was approximately 3,519 BOE/D. Our Elk Basin properties had estimated proved reserves at December 31, 2006 of 15,091 MBOE, of which 13,285 MBOE was proved developed and 1,806 MBOE was proved undeveloped.

The historical financial statements of Encore Energy Partners LP Predecessor, our predecessor, as of December 31, 2005 and 2006 and for the years ended December 31, 2004, 2005 and 2006 and the historical financial statements of Encore Energy Partners LP for the six months ended June 30, 2007 and 2006 do not include the results of operations of our Elk Basin assets prior to the purchase of our Elk Basin assets on March 7, 2007.

How We Evaluate Our Operations

We use a variety of financial and operational measures to assess our performance. Among these measures are the following:


	•	Volumes of oil and natural gas produced;

	•	Realized prices;


	•	Production expenses;

	•	G&A expenses; and

	•	Adjusted EBITDA.

Volumes of Oil and Natural Gas Produced

The following table presents historical production volumes for our properties for the years ended December 31, 2004, 2005 and 2006 and for the six months ended June 30, 2006 and 2007 and on a pro forma basis for the year ended December 31, 2006 and for the six months ended June 30, 2007:


	Historical(a)										Pro Forma(b)
							Six Months						Six Months
	Year Ended						Ended				Year Ended		Ended
	December 31,						June 30,				December 31,		June 30,
	2004		2005		2006		2006		2007		2006		2007

Total combined production (MBOE)		357		344		306		155		568		1,632		767
Average daily combined production (BOE/D)		976		942		838		858		3,139		4,471		4,238


(a)		Represents results of Encore Energy Partners LP Predecessor for the years ended December 31, 2004, 2005 and 2006 and the results of Encore Energy Partners LP Predecessor, together with the results of the Elk Basin assets from March 7, 2007, for the six months ended June 30, 2006 and 2007.

(b)		Pro forma results as if the Elk Basin properties had been acquired on January 1, 2006.

Realized Prices

Factors Affecting the Price of Crude Oil and Natural Gas at the Wellhead. We market our oil and natural gas production to a variety of purchasers based on regional pricing. The relative value of crude oil and natural gas at the wellhead is determined by two main factors: quality and location relative to consuming and refining markets.


	•	Crude Oil Prices. The NYMEX futures price of crude oil is a widely used benchmark in the pricing of domestic and imported oil in the United States. Crude oils differ from one another due to their different molecular makeup, which plays an important part in their refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly impact crude oil quality differentials: (1) the API gravity and (2) the percentage of sulfur content by weight. In general, lighter crudes (with higher API) produce a larger number of lighter products, such as gasoline, which have higher resale value and, therefore, lighter crudes are expected to sell at a premium over heavier crude oil. Crude oil produced in close proximity to major consuming and refining markets will require less transportation and therefore will be more attractive and command a premium over oil produced farther from the market, which requires greater transportation costs to get to the market. Crudes with lower sulfur content are more desirable and less expensive to refine and, as a result, receive a higher price than high-sulfur crudes. The crude oil in the Elk Basin is considered a high sulfur crude.

	•	Natural Gas Prices. The NYMEX futures price of natural gas is a widely used benchmark in the pricing of natural gas in the United States. Among other things, there are three characteristics that commonly impact natural gas prices: (1) the Btu content of natural gas, which measures its heating value, (2) the percentage of sulfur content by volume, and (3) the proximity of the natural gas to major consuming markets. Our Permian Basin properties produce natural gas with a high Btu content.

Differentials. The prices that we receive for our crude oil and natural gas production sometimes trade at a discount to the relevant benchmark prices, such as NYMEX. The difference between the NYMEX price and the price we receive is called a differential.


	•	Elk Basin. In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have gradually widened the differential for crude oil produced in Wyoming. For example, for the year ended December 31, 2006, the average discount to NYMEX for our Elk Basin crude oil was approximately $15.91 per Bbl as compared to $13.91 per Bbl for the year ended December 31, 2005.

	•	Permian Basin. Natural gas production in the Permian Basin is also often sold at a slight discount to benchmark prices due primarily to its remote location from consuming areas. For the year ended December 31, 2006, the average discount to NYMEX for our Permian Basin natural gas was approximately $0.12 per Mcf as compared to $0.79 per Mcf for the year ended December 31, 2005.

Derivative Transactions. We enter into derivative transactions to reduce the impact of crude oil and natural gas price volatility on our cash flow from operations. For the remainder of 2007, we have crude oil and natural gas put contracts and ceiling contracts covering 72% and 8%, respectively, of our estimated future production. For 2008 and 2009, we have crude oil and natural gas put contracts covering 72% and 37%, respectively, of our estimated future production, swap contracts covering 0% and 22%, respectively, of our estimated future production, and ceiling contracts covering 8% and 7%, respectively, of our estimated future production. For 2010, we have crude oil and natural gas put contracts and ceiling contracts covering 24% and 12%, respectively, of our estimated future production.

We currently intend to enter into put contracts for approximately one-third of our estimated future production and fixed-price commodity derivative contracts (such as swaps or collars) for an additional one-third of our estimated future production. Using this approach, we will have a fixed floor price for two-thirds of our estimated future production, but a fixed ceiling price for only one-third of our estimated future production, which will enable us to participate in price increases for our crude oil and natural gas. We will maintain the flexibility to mitigate the price risk on the remaining one-third of our estimated future production by using commodity derivative contracts. When we enter into new commodity derivative contracts, we expect that they will be for approximately 24 months.

By removing the price volatility from a significant portion of our crude oil production, we have mitigated, but not eliminated, the potential effects of changing crude oil prices on our cash flow from operations for those periods. Please read “— Quantitative and Qualitative Disclosures About Market Risk.”

Production and General and Administrative Expenses

In evaluating our production operations, we frequently monitor and assess our production expenses and G&A expenses per BOE produced. This measure allows us to better evaluate our operating efficiency and is used by us in reviewing the economic feasibility of a potential acquisition or development project.

Production Expenses. Production expenses are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water injection and disposal, production taxes and materials and supplies comprise the most significant portion of our operating expenses. Production expenses do not include G&A costs. A majority of our operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we incur power costs in connection with various production related activities such as pumping to recover oil and natural gas, separation and treatment of water produced in connection with our oil and natural gas production, and re-injection of water produced into the oil producing formation to maintain reservoir pressure. As these costs are driven not only by volumes of oil produced but also volumes of water produced, fields that have a high percentage of water production relative to oil production, also known as a high water cut, will experience higher levels of power costs for each Bbl of oil produced. A majority of our oil is produced from fields undergoing a secondary recovery technique known as a waterflood in which water is reinjected into the formation. Over the life of these fields, the amount of water produced increases for a given volume of oil production. Thus production of a given Bbl of oil gets more expensive each year as the cumulative oil produced from a field increases until at some point additional production becomes uneconomic. Certain items, however, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can

fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased expenses in periods during which they are performed.

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. Wyoming currently imposes a severance tax on oil and natural gas producers at the rate of 6% of the value of the gross product extracted. Texas currently imposes an oil production tax at the greater of 4.6% of the market value of the oil produced or 4.6¢ per Bbl. In addition, producers of crude petroleum in Texas pay a tax of 3/16 of one cent per Bbl produced. Texas currently imposes a natural gas production tax of 7.5% of the market value of the gas, with a minimum rate of 121/1,500¢ per Mcf. Montana currently imposes a severance tax on oil and natural gas producers. The owners of nonworking interests in Montana are taxed at a rate of 15.06% of the gross value of all oil and natural gas production. The owners of working interests in Montana are taxed at a maximum rate of 12.76% of the gross value of oil production and 15.06% of the gross value of natural gas production. Reduced rates or credits may apply to certain types of wells and production methods.

In addition to production taxes, Montana and Texas 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 gas properties. Wyoming also imposes an ad valorem tax on production equipment.

G&A Expenses. We expect to incur $2.0 million of incremental G&A expenses as a result of being a publicly traded limited partnership. We also intend to enter into an amended and restated administrative services agreement with Encore Operating, L.P., a wholly owned subsidiary of EAC, pursuant to which Encore Operating, L.P. will perform administrative services for us. Under the amended and restated administrative services agreement, Encore Operating, L.P. will receive 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, L.P. will have substantial discretion in determining which third-party expenses to incur on our behalf. We will also pay our share of expenses that are directly chargeable to wells under joint operating agreements. In addition, Encore Operating, L.P. will be 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.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) plus:


	•	Interest expense;

	•	Income tax provision;

	•	DD&A; and

	•	Unrealized (gain) loss on commodity derivative contracts.

We use Adjusted EBITDA to assess:


	•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;

	•	our operating performance and return on capital as compared to those of other companies and partnerships in our industry, without regard to financing or capital structure; and

	•	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

Outlook

Oil and natural gas prices have increased significantly since the beginning of 2004. Rising prices contributed to an increase in our oil and natural gas sales in both 2006 compared to 2005 and 2005 compared to 2004. We anticipate a continued favorable commodity price environment in 2007 and 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.

The price risk on a substantial portion of our estimated future production is currently mitigated using commodity derivative contracts through December 2010, and we intend to continue to enter into commodity derivative transactions to mitigate the impact of price volatility on our oil and natural gas revenues.

The increase in commodity prices has resulted in increased drilling activity and demand for drilling and operating services and equipment in North America. Due to the expected continued high commodity price environment and related demand pressures, we anticipate drilling service and labor costs, as well as costs of equipment and raw materials, to remain at or exceed the levels experienced in 2006.

In 2006, we did not develop new oil wells on our properties. Accordingly, we experienced normal production declines and production volumes decreases for oil. We plan to invest approximately $2.4 million between October 2007 and September 2008 in drilling new oil producing wells to offset the normal production declines in our fields.

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. We plan to invest approximately $3.2 million between October 2007 and September 2008 in drilling new natural gas producing wells to offset the normal production declines in our fields.

We expect to fund our 2007 and 2008 capital expenditures with cash flow from operations. We also estimate that we will have sufficient cash flow from operations after funding capital expenditures to enable us to make our initial quarterly distribution to unitholders for each quarter for the twelve months ending September 30, 2008. Please read “— Liquidity and Capital Resources” below and “Our Cash Distribution Policy and Restrictions on Distributions.”

We expect to continue to pursue asset acquisition opportunities in 2007 and 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. We believe that our structure as a pass-through vehicle for tax purposes will allow us to have a lower cost of capital for acquisition opportunities than many of our taxable competitors.

Factors Affecting Comparability of Future Results

You should read the discussion of our financial condition and results of operations in conjunction with our historical and pro forma financial statements included elsewhere in this prospectus. 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 Three Years Ended December 31, 2006 or for the Six Months Ended June 30, 2006 and 2007. The discussion of our historical results that follows reflects the operations related to our Elk Basin assets, which we acquired in March 2007 from subsidiaries of Anadarko Petroleum Corporation for approximately $329.4 million (including estimated transaction costs of approximately $1.0 million) only from the date of acquisition forward. The following table sets forth historical revenues and direct operating expenses attributable to the Elk Basin assets for the periods indicated:


							Six Months
	Year Ended December 31,						Ended June 30,
	2004		2005		2006		2006		2007
							(unaudited)

Revenues:
Oil	$	44,839	$	54,592	$	63,695	$	29,644	$	30,790
Natural gas		2,026		1,828		2,395		1,498		457
Marketing and other		1,197		1,745		3,649		517		8,427

Total revenues		48,062		58,165		69,739		31,659		39,674

Direct operating expenses:
Lease operating expenses		5,757		6,263		7,435		3,671		6,283
Marketing and other		2,134		3,909		5,598		2,167		7,907
Production and other taxes		5,619		6,769		7,839		3,981		3,992

Total direct operating expenses		13,510		16,941		20,872		9,819		18,182

Excess of revenues over direct operating expenses	$	34,552	$	41,224	$	48,867	$	21,840	$	21,492

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

The following table displays pro forma revenues, direct operating expenses and operating data attributable to the oil and natural gas production activities of the Permian Basin assets and the Elk Basin assets for the year ended December 31, 2006 and for the six months ended June 30, 2007.


	Pro Forma		Pro Forma
	Year Ended		Six Months
	December 31,		Ended June 30,
	2006		2007

Revenues (in thousands):
Oil	$	64,104	$	30,928
Natural gas		14,732		6,031

Total combined oil and natural gas revenues		78,836		36,959

Direct operating expenses (in thousands):
Lease operations		9,108		6,916
Production, ad valorem, and severance taxes		9,065		4,548

Total direct operating expenses		18,173		11,464

Revenues in excess of direct operating expenses	$	60,663	$	25,495

Total production volumes (in thousands):
Oil (Bbls)		1,273		617
Natural gas (Mcf)		2,158		901
Combined (BOE)		1,632		767
Average daily production volumes:
Oil (Bbl/D)		3,488		3,409
Natural gas (Mcf/D)		5,912		4,978
Combined (BOE/D)		4,471		4,238
Average realized prices:
Oil ($/Bbl)	$	50.36	$	50.13
Natural gas ($/Mcf)	$	6.83	$	6.69
Combined ($/BOE)	$	48.31	$	48.19
Direct operating expenses ($/BOE):
Lease operations	$	5.58	$	9.02
Production, ad valorem, and severance taxes		5.55		5.93

Total direct operating expenses		11.13		14.95

Revenues in excess of direct operating expenses ($/BOE)	$	37.18	$	33.24

The pro forma revenues and direct operating expenses attributable to the oil and natural gas production activities of the Permian Basin assets and the Elk Basin assets are not indicative of future results. These statements should be read in conjunction with our unaudited pro forma financial statements and related notes included elsewhere in this prospectus.

Increase in Outstanding Indebtedness. For the three 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 subsidiary of EAC pursuant to a subordinated term loan and $115 million under our revolving credit facility (excluding $1.6 million of debt issuance costs). As of June 30, 2007, our subordinated term loan bore interest at a rate of 10.3% per annum, and our revolving credit facility bore interest at a rate of 7.1% per annum. We plan to use the net proceeds from this offering to repay all $120 million of outstanding borrowings under the subordinated term loan, together with accrued interest of approximately $6.9 million, and approximately $45.1 million of outstanding borrowings under our revolving credit facility. We expect to have approximately $69.9 million

outstanding under our revolving credit facility immediately after completion of this offering. In addition, any additional borrowings will increase interest expense during the period they are outstanding.

Purchase of Derivatives. Neither the historical financial statements of Encore Energy Partners LP Predecessor nor the statements of revenues and direct operating expenses of the Anadarko Elk Basin Operations contain any costs related to derivative transactions. In connection with the Elk Basin acquisition, EAC contributed floor contracts for 2,500 Bbl/D of production at $65.00 per Bbl for April through December of 2007 and all of 2008. Additionally, in the first quarter of 2007, we purchased floor contracts for 1,000 Bbl/D at $63.00 per Bbl for 2009, entered into swap contracts for 1,000 Bbl/D at $68.70 per Bbl for 2009 and purchased floor contracts for 2,000 Mcf/D at $8.20 per Mcf for July 2007 through the end of 2009. In the second quarter of 2007, we entered into a costless collar transaction whereby we purchased floor contracts for 2,000 Mcf/D of production at $7.20 per Mcf and sold ceiling contracts for 2,000 Mcf/D of production at $9.85 per Mcf for July 2007 through the end of 2009. In the third quarter of 2007, we purchased a floor contract for 500 Bbl/D of production at $65.00 per Bbl for all of 2010 and entered into a costless collar transaction whereby we purchased a floor contract for 500 Bbl/D of production at $65.00 per Bbl and sold a ceiling contract for 500 Bbl/D of production at $79.05 per Bbl for 2010.

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 the executive officers of the general partner. A management incentive unit is a limited partner interest in our partnership that entitles the holder to an initial quarterly distribution of $0.35 (or $1.40 on an annualized basis) and to increasing distributions upon the achievement of 10% 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. Upon completion of this offering, the management incentive units granted to executive officers of our general partner will partially vest at which point we will recognize an expense for the estimated fair value of the vested portion of the units. We will recognize additional expenses over at least the following two-year period as the management incentive units continue to vest. This expense is not reflected in our unaudited pro forma financial statements.

Additional General and Administrative Expenses. We expect to incur approximately $2.0 million per year in incremental general and administrative expenses as a result of becoming a publicly traded entity. These costs include fees 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 are not reflected in the historical financial statements of Encore Energy Partners LP Predecessor or our unaudited pro forma financial statements.

Results of Operations for Encore Energy Partners LP

The discussion of the results of operations and period-to-period comparisons presented below covers the historical results of Encore Energy Partners LP Predecessor for the six months ended June 30, 2007 and 2006, together with the historical results of the Elk Basin assets from the date of acquisition on March 7, 2007 through June 30, 2007.

Comparison of Six Months Ended June 30, 2007 to Six Months Ended June 30, 2006

Revenues and production. The following table illustrates the primary components of revenues for the six months ended June 30, 2007 and 2006, as well as each period’s respective oil and natural gas production volumes:


	Six Months Ended June 30,
	2007		2006		Increase/(Decrease)

Revenues (in thousands):
Oil	$	20,469	$	174	$	20,295
Natural gas		5,904		6,719		(815	)
Marketing and other		4,852		—		4,852

Total revenues	$	31,225	$	6,893	$	24,332

Average realized prices:
Oil ($/Bbl)	$	48.04	$	63.41	$	(15.37	)
Natural gas ($/Mcf)	$	6.92	$	7.34	$	(0.42	)
Combined ($/BOE)	$	46.41	$	44.41	$	2.00
Total production volumes:
Oil (Bbls)		426,043		2,744		423,299
Natural gas (Mcf)		853,053		914,811		(61,758	)
Combined (BOE)		568,219		155,213		413,006
Average daily production volumes:
Oil (Bbl/D)		2,354		15		2,339
Natural gas (Mcf/D)		4,713		5,054		(341	)
Combined (BOE/D)		3,139		858		2,281
Average NYMEX prices:
Oil ($/Bbl)	$	61.65	$	67.09	$	(5.44	)
Natural gas ($/Mcf)	$	7.42	$	7.28	$	0.14

Oil revenues increased $20.3 million from $0.2 million in the first six months of 2006 to $20.5 million in the first six months of 2007. The increase is due primarily to higher oil production volumes of 423,299 Bbls, which increased revenues by approximately $26.8 million, partially offset by lower realized oil prices, which reduced revenues by approximately $6.5 million. The increase in production volumes is due to our acquisition of the Elk Basin assets in March 2007. The decrease in revenues from lower realized average oil prices is the result of lower average wellhead oil price of $15.37 per Bbl in the first six months of 2007 from the first six months of 2006, which resulted as the average NYMEX price declined from $67.09 per Bbl in the first six months of 2006 to $61.65 per Bbl in the first six months of 2007 and as our oil differential increased $9.93 per Bbl between the periods.

Natural gas revenues decreased $0.8 million from $6.7 million in the first six months of 2006 to $5.9 million in the first six months of 2007. The decrease is primarily due to lower realized average natural gas prices, which reduced revenues by approximately $0.4 million, and a decrease in natural gas production volumes of 61,758 Mcf, which reduced revenues by approximately $0.5 million. The decrease in production volumes is the result of normal production declines as development projects were not sufficient to offset the natural decline curve. The decrease in revenues from lower realized average natural gas prices is the result of

a $0.56 per Mcf increase in our natural gas differential from $0.06 per Mcf in the first six months of 2006 to $(0.50) per Mcf in the first six months of 2007.

Marketing and other revenues of $4.9 million are entirely attributable to our acquisition of the Elk Basin assets in March of 2007. Our Permian Basin assets do not have marketing or other revenue.

The table below illustrates the relationship between oil and natural gas realized prices as a percentage of average NYMEX prices for the first six months of 2007 and the first six months of 2006. Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.


	Six Months Ended June 30,
	2007			2006

Average realized oil price ($/Bbl)	$	48.04		$	63.41
Average NYMEX ($/Bbl)	$	61.65		$	67.09
Differential to NYMEX	$	(13.61	)	$	(3.68	)
Average realized oil price to NYMEX percentage		78	%		95	%
Average realized natural gas price ($/Mcf)	$	6.92		$	7.34
Average NYMEX ($/Mcf)	$	7.42		$	7.28
Differential to NYMEX	$	(0.50	)	$	0.06
Average realized natural gas price to NYMEX percentage		93	%		101	%

Expenses. The following table summarizes our expenses for the first six months of 2007 and the first six months of 2006:


	Six Months Ended
	June 30,				Increase/
	2007		2006		(Decrease)

Expenses (in thousands):
Production:
Lease operations	$	4,951	$	793	$	4,158
Production, ad valorem, and severance taxes		3,286		638		2,648

Total production expenses		8,237		1,431		6,806
Other:
Depletion, depreciation, and amortization		10,412		580		9,832
General and administrative		1,092		326		766
Derivative fair value loss		6,497		—		6,497
Marketing and other operating		4,646		122		4,524

Total operating		30,884		2,459		28,425
Interest expense		6,444		—		6,444
Income tax provision		39		—		39

Total expenses	$	37,367	$	2,459	$	34,908

Expenses (per BOE):
Production:
Lease operations	$	8.71	$	5.11	$	3.60
Production, ad valorem, and severance taxes		5.78		4.11		1.67

Total production expenses		14.49		9.22		5.27
Other:
Depletion, depreciation, and amortization		18.32		3.74		14.58
General and administrative		1.92		2.10		(0.18	)
Derivative fair value loss		11.43		—		11.43
Marketing and other operating		8.18		0.79		7.39

Total operating		54.34		15.85		38.49
Interest expense		11.34		—		11.34
Income tax provision		0.07		—		0.07

Total expenses	$	65.75	$	15.85	$	49.90

Production expenses. Total production expenses increased $6.8 million from $1.4 million in the first six months of 2006 to $8.2 million in the first six months of 2007. This increase is primarily due to higher production volumes associated with the Elk Basin assets acquired in March 2007 along with a $5.27 increase in production expense per BOE. As a result, our production margin (defined as oil and natural gas revenues less production expenses) for the first six months of 2007 decreased nine percent to $31.92 per BOE for the first six months of 2007 as compared to $35.19 per BOE for the first six months of 2006.

The production expense attributable to lease operations expense (“LOE”) for the first six months of 2007 increased $4.2 million from $0.8 million in the first six months of 2006 to $5.0 million in the first six months of 2007. The increase is due to an increase in production volumes associated with the Elk Basin assets, which contributed approximately $2.1 million of additional LOE and an increase in the per BOE rate, which contributed approximately $2.0 million of additional LOE. The increase in the average LOE per BOE rate was attributable to higher rates per BOE for the Elk Basin assets as compared to the Permian Basin assets.

The production expense attributable to production, ad valorem and severance taxes (“production taxes”) increased $2.6 million from $0.6 million in the first six months of 2006 to $3.3 million in the first six months of 2007. The increase is due to higher revenues resulting from the acquisition of the Elk Basin assets and higher tax rates in the Elk Basin region. As a percentage of oil and natural gas revenues, production taxes increased to 12.5 percent in the first six months of 2007 as compared to 9.3 percent in the first six months of 2006.

DD&A expense. DD&A expense increased $9.8 million from $0.6 million in the first six months of 2006 to $10.4 million in the first six months of 2007 due to higher production volumes primarily resulting from our acquisition of the Elk Basin assets. The increase in DD&A per BOE from $3.74 in the first six months of 2006 to $18.32 in the first six months of 2007 is due to the higher price of purchased reserves at Elk Basin as compared to the Permian Basin assets, which were acquired when oil and natural gas prices were significantly lower.

G&A expense. G&A expense increased $0.8 million from $0.3 million in the first six months of 2006 to $1.1 million in the first six months of 2007 primarily due to the acquisition of the Elk Basin assets in March 2007. The $0.18 decrease in the per BOE rate is primarily the result of Elk Basin’s G&A expenses of $1.75 per BOE as billed per the amended and restated administrative services agreement with Encore Operating, L.P.

Derivative fair value loss. We entered into several oil and natural gas derivative contracts during the six months ended June 30, 2007 in connection with the acquisition of the Elk Basin assets at a cost of $2.3 million and received a non-cash contribution of derivative contracts from EAC with a value of $9.4 million. We recognized losses of $6.5 million for the six months ended June 30, 2007 due to changes in the fair value of these derivatives. There were no such derivative instruments in place during the six months ended June 30, 2006.

Marketing and other operating. Marketing and other operating expenses increased $4.5 million from $0.1 million in the first six months of 2006 to $4.6 million in the first six months of 2007. This increase is due entirely to expenses associated with marketing activities on our newly acquired Elk Basin assets in March 2007.

Interest expense. Interest expense was $6.4 million during the first six months of 2007. We did not have any interest expense during the first six months of 2006. In the first six months of 2007, we borrowed $115 million under our revolving credit facility (not including debt issuance cost of $1.6 million) and $120 million under a subordinated term loan with EAP Operating, Inc., a wholly owned subsidiary of EAC. The funds from these borrowings were used to purchase the Elk Basin assets in March 2007.

Comparison of 2006 to 2005

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


	Year Ended
	December 31,				Increase/
	2006		2005		(Decrease)

Revenues (in thousands):
Oil	$	409	$	535	$	(126	)
Natural gas		12,337		16,366		(4,029	)

Total combined oil and natural gas revenues	$	12,746	$	16,901	$	(4,155	)

Average realized prices:
Oil ($/Bbl)	$	62.18	$	53.29	$	8.89
Natural gas ($/Mcf)	$	6.87	$	8.17	$	(1.30	)
Combined ($/BOE)	$	41.67	$	49.13	$	(7.46	)
Total production volumes:
Oil (Bbls)		6,578		10,040		(3,462	)
Natural gas (Mcf)		1,795,954		2,003,800		(207,846	)
Combined (BOE)		305,904		344,007		(38,103	)
Average daily production volumes:
Oil (Bbl/D)		18		28		(10	)
Natural gas (Mcf/D)		4,920		5,490		(570	)
Combined (BOE/D)		838		942		(104	)
Average NYMEX prices:
Oil ($/Bbl)	$	66.22	$	56.56	$	9.66
Natural gas ($/Mcf)	$	6.99	$	8.96	$	(1.97	)

Oil revenues decreased $0.1 million from $0.5 million in 2005 to $0.4 million in 2006. The decrease is 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. We plan to invest approximately $2.4 million between September 2007 and October 2008 in drilling new oil producing wells to offset the normal production declines in our fields. The higher realized average oil price is 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 $12.4 million in 2006. The decrease is primarily due to lower realized average 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. We plan to invest approximately $3.2 million between September 2007 and October 2008 in drilling new natural gas producing wells to offset the normal production declines in our fields. The lower realized average 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 $8.96 per Mcf in 2005 to $6.99 per Mcf in 2006.

The table below illustrates the relationship between realized oil and natural gas prices and average NYMEX prices for 2006 and 2005 by showing our realized prices as a percentage of NYMEX. 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)	$	6.99		$	8.96
Differential to NYMEX	$	(0.12	)	$	(0.79	)
Average realized natural gas price to NYMEX percentage		98	%		91	%

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


	Year Ended
	December 31,				Increase/
	2006		2005		(Decrease)

Expenses (in thousands):
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	%

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 total oil and natural gas revenues per BOE decreased approximately 15 percent. As a result of these changes, Encore Energy Partners LP Predecessor’s production margin (defined as oil and natural gas revenues less production expenses) 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 is 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 Encore Energy Partners LP Predecessor’s average LOE per BOE rate of $0.38 was attributable to:


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

	•	increased operational activity to enhance production;

	•	the operation of higher operating cost wells (which have offered acceptable rates of return due to increases in 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 $0.3 million from $1.5 million in 2005 to $1.2 million in 2006. The decrease is 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 is primarily the result of expensing of stock options granted to employees of EAC beginning January 1, 2006.

Income taxes. Income tax expense for 2006 increased $0.1 million over 2005. This is due to changes to the Texas franchise tax, which caused us to adjust our net deferred tax balances using the new higher marginal tax rate we expect to be effective when those deferred taxes become current. This resulted in a charge of $0.1 million during 2006.

Comparison of 2005 to 2004

Revenues and production. The following table illustrates the primary components of oil and natural gas revenues for 2005 and 2004, as well as each year’s respective oil and natural gas volumes:


	Year Ended December 31,				Increase/
	2005		2004		(Decrease)

Revenues (in thousands):
Oil	$	535	$	442	$	93		21	%
Natural gas		16,366		12,791		3,575		28	%

Total combined oil and natural gas revenues	$	16,901	$	13,233	$	3,668		28	%

Average realized prices:
Oil ($/Bbl)	$	53.29	$	38.26	$	15.03		39	%
Natural gas ($/Mcf)	$	8.17	$	6.17	$	2.00		32	%
Combined ($/BOE)	$	49.13	$	37.05	$	12.08		33	%
Total production volumes:
Oil (Bbls)		10,040		11,552		(1,512	)	(13	)%
Natural gas (Mcf)		2,003,800		2,073,578		(69,778	)	(3	)%
Combined (BOE)		344,007		357,148		(13,141	)	(4	)%
Average daily production volumes:
Oil (Bbl/D)		28		32		(4	)	(13	)%
Natural gas (Mcf/D)		5,490		5,666		(176	)	(3	)%
Combined (BOE/D)		942		976		(34	)	(3	)%
Average NYMEX prices:
Oil ($/Bbl)	$	56.56	$	41.26	$	15.30		37	%
Natural gas ($/Mcf)	$	8.96	$	6.11	$	2.85		47	%

Oil revenues increased $0.1 million from $0.4 million in 2004 to $0.5 million in 2005. The increase is due primarily to higher realized average oil prices. The increase in oil revenues from higher realized average oil prices, which contributed approximately $0.2 million in additional oil revenues, was partially offset by lower oil production volumes of 2 MBbls, which reduced oil revenues by approximately $0.1 million. The decrease in production volumes is the result of normal production declines. Encore Energy Partners LP Predecessor’s average realized oil price increased $15.03 per Bbl in 2005 over 2004 as a result of increases in the overall market price for oil, which is reflected in the increase in the average NYMEX price from $41.26 per Bbl in 2004 to $56.56 per Bbl in 2005.

Natural gas revenues increased $3.6 million from $12.8 million in 2004 to $16.4 million in 2005. The increase is due primarily to higher realized average natural gas prices, which contributed approximately $4.0 million in additional natural gas revenues, offset by lower natural gas production volumes of 70 MMcf, which reduced revenues by approximately $0.4 million. The increase in realized average natural gas prices was due to an increase in the overall market price of natural gas, which is reflected in the increase in the average NYMEX price from $6.11 per Mcf in 2004 to $8.96 per Mcf in 2005. The decrease in the production volumes is the result of normal production declines.

The table below illustrates the relationship between oil and natural gas wellhead prices as a percentage of average NYMEX prices for 2005 and 2004. Management uses the wellhead to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.


	Year Ended December 31,
	2005			2004

Average realized oil price ($/Bbl)	$	53.29		$	38.26
Average NYMEX ($/Bbl)	$	56.56		$	41.26
Differential to NYMEX	$	(3.27	)	$	(3.00	)
Average realized oil price to NYMEX percentage		94	%		93	%
Average realized natural gas price ($/Mcf)	$	8.17		$	6.17
Average NYMEX ($/Mcf)	$	8.96		$	6.11
Differential to NYMEX	$	(0.79	)	$	0.06
Average realized natural gas price to NYMEX percentage		91	%		101	%

Expenses. The following table summarizes Encore Energy Partners LP Predecessor’s expenses for 2005 and 2004:


	Year Ended
	December 31,				Increase/
	2005		2004		(Decrease)

Expenses (in thousands):
Production:
Lease operations	$	1,751	$	1,604	$	147
Production, ad valorem, and severance taxes		1,473		1,195		278

Total production expenses		3,224		2,799		425		15	%
Other:
Depletion, depreciation, and amortization		1,286		1,394		(108	)
General and administrative		572		477		95
Other operating		263		202		61

Total expenses	$	5,345	$	4,872	$	473		10	%

Expenses (per BOE):
Production:
Lease operations	$	5.09	$	4.49	$	0.60
Production, ad valorem, and severance taxes		4.28		3.35		0.93

Total production expenses		9.37		7.84		1.53		20	%
Other:
Depletion, depreciation, and amortization		3.74		3.90		(0.16	)
General and administrative		1.66		1.34		0.32
Other operating		0.76		0.57		0.19

Total expenses	$	15.53	$	13.65	$	1.88		14	%

Production expenses. Total production expenses increased $0.4 million from $2.8 million in 2004 to $3.2 million in 2005 primarily due to a $1.53 increase in production expenses per BOE. The 20 percent increase in total production expenses per BOE compares to a 33 percent increase in revenues per BOE due to a higher production margin (defined as revenues less production expenses) in 2005 as compared to 2004.

The production expense attributable to LOE for 2005 increased by $0.1 million as compared to 2004 due to an increase in the average per BOE rate. The increase in Encore Energy Partners LP Predecessor’s average

expense per BOE was attributable to increases in prices paid to oilfield service companies and suppliers due to a higher price environment, increased operational activity to maximize production, and the operation of higher operating cost wells, which became more attractive due to increases in oil and natural gas prices. This increased average per BOE rate resulted in approximately $0.2 million of additional LOE for price escalation for services, offset by lower production volumes, which reduced LOE by approximately $0.1 million.

The production expense attributable to production taxes for 2005 increased $0.3 million from $1.2 million in 2004 to $1.5 million in 2005. This increase is due to an increase in the average wellhead price Encore Energy Partners LP Predecessor received for oil and natural gas production. The average wellhead price Encore Energy Partners LP Predecessor received for oil and natural gas revenues increased $12.08 per BOE, resulting in additional production taxes of approximately $0.3 million in 2005. As a percentage of oil and natural gas revenues, production taxes remained constant at approximately nine percent in 2005 and 2004.

DD&A expense. DD&A expense decreased $0.1 million from $1.4 million in 2004 to $1.3 million in 2005 due to the decrease in production volumes of 13 MBOE over 2004.

G&A expense. G&A expense increased $0.1 million from $0.5 million in 2004 to $0.6 million in 2005. The overall increase, as well as the $0.32 increase in the per BOE rate, is a result of increased staffing to manage Encore Energy Partners LP Predecessor’s larger asset base, higher activity levels and increased personnel costs due to intense competition for human resources within the industry.

Liquidity and Capital Resources

Our primary sources of liquidity are expected to be cash generated from our operations, amounts available under our revolving credit facility described below and funds from future private and public equity and debt offerings.

Our partnership agreement requires that we distribute our available cash. In making cash distributions, our general partner will attempt 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 using commodity derivative contracts. We are generally required to settle our commodity derivatives within 5 days of the end of the month. As is typical in the oil and 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 will be required to pay the counterparty the difference between the fixed price and the market price before we receive the proceeds from the sale of the production under the commodity derivative. If this were to occur, we may make working capital borrowings to fund our distributions. Because we will distribute our available cash, we will not have those amounts available to reinvest in our business to increase our reserves and production. Because we will distribute a substantial portion of our cash flows rather than reinvest those cash flows in our business, we may not grow as quickly as other companies or at all.

We plan to make substantial capital expenditures in the future for the acquisition, exploitation and development of oil and natural gas properties. In estimating the minimum amount of Adjusted EBITDA that we must generate to pay our initial quarterly distribution to unitholders for each quarter for the twelve months ending September 30, 2008, we have assumed that our capital expenditure budget for the twelve months ending September 30, 2008 will be approximately $8.7 million. We intend to finance these capital expenditures with cash flow 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 you 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.

Cash Flows

Cash Flows Provided by Operating Activities. Cash provided by operating activities decreased $1.4 million from $6.6 million in the first six months of 2006 to $5.2 million in the first six months of 2007. The decrease is primarily attributable to $2.1 million in purchases of derivative instruments.

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 decrease in oil and natural gas revenues was primarily the result of a 10% decrease in natural gas volumes and a 16% lower average natural gas price per Mcf, which together accounted for $4.0 million of the decrease from 2005 to 2006.

For 2005 as compared to 2004, cash provided by operating activities increased $2.2 million from $9.4 million in 2004 to $11.6 million in 2005. This increase resulted mainly from an increase in revenues of $3.7 million, which outpaced the increase in total operating expenses of $0.5 million. Revenues increased in 2005 as commodity prices were higher than in 2004. Our average realized oil price increased $15.03 per Bbl from $38.26 per Bbl in 2004 to $53.29 per Bbl in 2005. Our average realized natural gas price increased $2.00 per Mcf from $6.17 per Mcf in 2004 to $8.17 per Mcf in 2005.

Cash Flows Used in Investing Activities. Cash used in investing activities increased $327.4 million from $0.1 million in the first six months of 2006 to $327.5 million in the first six months of 2007, which is wholly attributed to our acquisition of the Elk Basin assets.

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

For 2005 as compared to 2004, cash used in investing activities increased $0.4 million from $1.8 million in 2004 to $2.2 million in 2005, which is due to an increase in costs incurred for the development of oil and natural gas properties.

Cash Flows Provided by (Used in) Financing Activities. Cash used in financing activities was $6.5 million in the first six months of 2006. In the first six months of 2007, cash flows provided by financing activities was $323.7 million, which is attributable to additional amounts we borrowed and capital contributions we received from EAC (through it subsidiaries) which were used to acquire the Elk Basin assets.

Cash used in financing activities increased $0.5 million from $9.4 million in 2005 to $9.9 million in 2006, which is wholly attributed to an increase in distributions of earnings to EAC.

For 2005 as compared to 2004, cash used in financing activities increased $1.8 million from $7.6 million in 2004 to $9.4 million in 2005, which is wholly due to an increase in distributions of earnings to EAC.

Revolving Credit Facility

On March 7, 2007, our operating company entered into a five-year credit agreement with Bank of America, N.A. 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 currently equal to $115 million, provided that our operating company has the option of borrowing up to $10 million in excess of the borrowing base for a certain period of time following the closing date. The borrowing base is redetermined semi-annually and upon requested special redeterminations. We have requested that the borrowing base be redetermined to account for the Permian Basin assets that will be transferred by Encore Operating, L.P. to us at the closing of this offering. We expect that the redetermined borrowing base will be increased to $145 million and will become effective upon the transfer of the Permian Basin assets to us at the closing of this offering.

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.

Loans under the credit agreement are subject to varying rates of interest based on (1) the total amount outstanding under the credit agreement in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans bear interest at the base rate plus the applicable margin indicated in the following table:


	Applicable Margin for			Applicable Margin for
Ratio of Total Outstandings 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 operating company) is the rate per annum equal to the British Bankers Association London Interbank Offered Rate, or the LIBOR rate, 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 (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (2) the federal funds effective rate plus 0.5%.

As of July 31, 2007, the aggregate principal amount of loans outstanding under the credit agreement was $115 million, and there were no outstanding letters of credit. 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 paying dividends or making distributions, 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, change of principal business;

	•	a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75% 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 below) 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 below) 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 to consolidated adjusted EBITDA (as defined in the credit agreement) of not more than 3.5 to 1.0.

The credit agreement contains customary events of default. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the credit agreement to be immediately due and payable. At June 30, 2007, our operating company was in violation of a covenant that required it to maintain a ratio of consolidated EBITDA (as defined below) to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0. Accordingly, amounts outstanding under the credit agreement were classified as a current liability in the June 30, 2007 financial statements since the credit agreement was not amended at the time such financial statements were originally filed. Our operating company requested and obtained a waiver from the bank syndicate for the June 30, 2007 violation, and on August 22, 2007, the credit agreement was amended to revise the financial covenants as described above. Accordingly, we expect any amounts outstanding under the credit agreement to be classified as long-term in subsequent periods. We were in compliance with all other debt covenants under the credit agreement as of June 30, 2007.

Our revolving credit facility defines consolidated EBITDA as an amount equal to our consolidated net income for a period, plus (1) any provision for (or less any benefit from) income or franchise taxes included in determining consolidated net income, (2) consolidated net interest expense deducted in determining consolidated net income, (3) depreciation, depletion, amortization and exploration expense deducted in determining consolidated net income, (4) other non-cash charges deducted in determining consolidated net income to the extent not already included in such determination, and (5) any unrealized non-cash gains or losses or charges in respect of certain hedge transactions. For purposes of calculating the ratio of consolidated funded debt to consolidated adjusted EBITDA, consolidated EBITDA is adjusted to give pro forma effect to certain acquisitions, dispositions and other events occurring during the relevant measurement period.

Subordinated Term Loan

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 the operating company in the aggregate amount of $120 million.

The subordinated term loan matures on March 7, 2013. The operating company’s obligations under the subordinated credit agreement are subordinated in right of payment to the payment in full of its obligations under the revolving credit facility and other related obligations on the terms and conditions set forth in an intercreditor agreement dated as of March 7, 2007.

The operating company’s obligations under the subordinated credit agreement are secured by a second-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 subordinated credit agreement are guaranteed by us and the operating company’s restricted subsidiaries. Obligations under the subordinated credit agreement are non-recourse to EAC and its restricted subsidiaries.

The subordinated term loan is subject to varying rates of interest based on whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus 5.00%, and base rate loans bear interest at the base rate plus 3.75%. The operating company has the option to defer payment of any accrued interest that is due and payable by adding the interest to the principal amount of the subordinated term loan.

The “Eurodollar rate” for any interest period (either one, two, three or six months, as selected by the operating company) is the rate per annum equal to the LIBOR Rate, as published by Reuters or another source designated by EAP Operating, Inc., for deposits in dollars for a similar interest period. The “base rate” is calculated as the higher of (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (2) the federal funds effective rate plus 0.5%.

The subordinated term loan may be prepaid from time to time in whole or in part without penalty. However, under the terms of the revolving credit facility, the operating company is prohibited from prepaying the subordinated term loan until the closing of this offering, at which time it can prepay all or a portion of the subordinated term loan so long as the amounts outstanding under the revolving credit facility at the time of prepayment are less than or equal to $100 million or 90% of the borrowing base, whichever is lower.

As of July 31, 2007, the aggregate principal amount of loans outstanding under the subordinated credit agreement was $124.7 million.

The subordinated credit agreement contains covenants that are customary for secured financings provided by lenders that are not affiliated with the borrower, including, among others:


	•	a prohibition against incurring debt, subject to permitted exceptions;

	•	a prohibition against paying dividends or making distributions, 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, change of principal business;

	•	a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75% 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 subordinated credit agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.25 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 subordinated credit agreement) of not more than 3.85 to 1.0.

The subordinated credit agreement contains customary events of default. EAP Operating, Inc.’s rights to accelerate amounts due under the subordinated credit agreement and institute enforcement actions with respect to the collateral upon the occurrence and during the continuance of an event of default are governed by the terms of the intercreditor agreement, which provides for, among other things, a standstill period of 180 days.

At June 30, 2007, we were in violation of our covenant that requires us to maintain a ratio of consolidated EBITDA (as defined in the subordinated credit agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.25 to 1.0. We obtained a waiver from EAP Operating, Inc. for the June 30, 2007 violation. We have also amended the subordinated credit agreement to change the calculation of the debt covenant. Amounts outstanding under the subordinated credit agreement have continued to be classified as long-term debt. We were in compliance with all other debt covenants under the subordinated credit agreement as of June 30, 2007.

Intercreditor Agreement

Pursuant to an intercreditor agreement dated as of March 7, 2007, the operating company’s obligations under the subordinated credit agreement are subordinated in right of payment to the payment in full of its obligations under the revolving credit facility and other related obligations (the “senior obligations”). However, when the closing of this offering occurs, the operating company may prepay all or a portion of the subordinated term loan so long as the amounts outstanding under the revolving credit facility at the time of prepayment are less than or equal to $100 million or 90% of the borrowing base, whichever is lower, and no default under the revolving credit facility then exists. In addition, so long as no blockage period (as defined in the intercreditor agreement) exists and no default under the revolving credit facility resulting from non-payment of any senior obligations exists, the operating company may pay regularly scheduled interest payments accruing on the outstanding principal of the subordinated term loan.

The intercreditor agreement provides that all liens securing the operating company’s obligations relating to the subordinated term loan (the “subordinated obligations”) are junior in priority to any liens that secure the senior obligations. In addition, until the senior obligations are paid in full, no lien may be granted on assets to secure the subordinated obligations without also subjecting the same assets to first-priority liens in favor of the holders of the senior obligations (the “senior creditors”).

Subject to the following sentence, until the senior obligations are paid in full, the senior creditors have the exclusive right to take any enforcement action with respect to the senior obligations or the subordinated obligations, including acceleration of the maturity of the obligations, prosecution of actions for the payment of the obligations and exercise of remedies with respect to the collateral. However, the subordinated term lender may exercise its rights and remedies with respect to the collateral after the passage of 180 days from the date the subordinated term lender notifies the senior creditors of its intention to exercise such rights and remedies due to the existence of an event of default under the subordinated credit agreement. Notwithstanding the expiration of the standstill period, the subordinated term lender may not exercise or continue to exercise such rights and remedies if (1) any senior creditor commences and diligently pursues the exercise of its rights and remedies with respect to the collateral or (2) an insolvency proceeding with respect to us, the operating company or any of its restricted subsidiaries is commenced.

Contractual Obligations

The following table illustrates our contractual obligations outstanding at June 30, 2007:


	Payments Due by Period
Contractual obligations and commitments	Total		2007		2008-2009		2010-2011		Thereafter
	(In thousands)

Revolving credit facility(a)	$	115,000	$	115,000	$	—	$	—	$	—
Subordinated credit agreement(a)		221,780		—		—		—		221,780
Derivative obligations(b)		1,090		—		1,090		—		—
Asset retirement obligations(c)		25,257		236		945		945		23,131

Total	$	363,127	$	115,236	$	2,035	$	945	$	244,911


(a)		Amounts included in the table above include both principal and projected interest payments.

(b)		Derivative obligations represent derivative liabilities that were valued as of June 30, 2007, the ultimate settlement of which are unknown because they are subject to continuing market risk.

(c)		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.

determining which third-party expenses to incur on our behalf. We will also pay our share of expenses that are directly chargeable to wells under joint operating agreements. In addition, Encore Operating, L.P. will be 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 in 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, L.P. 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, L.P. and our general partner, with the approval of the conflicts committee of our general partner.

For more information on the amended and restated administrative services agreement, please read “Certain Relationships and Related Party Transactions — Amended and Restated Administrative Services Agreement.”

Critical Accounting Policies and Estimates

The discussion and analysis of our historical financial condition and results of operations are based upon the consolidated financial statements of Encore Energy Partners LP, which have been prepared in accordance with GAAP. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the financial statements of Encore Energy Partners LP. We provide an expanded discussion of the more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect the more significant estimates and assumptions used in preparation of the financial statements of Encore Energy Partners LP and those that will be used in the preparation of our financial statements in the foreseeable future.

Oil and Natural Gas Properties

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

If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs would be expensed in the Statement of Operations and shown as a non-cash adjustment to net income in the “Operating activities” section of the Statement of Cash Flows in the period in which the determination was made. If a determination cannot be made within one year of the exploration well being drilled and no other drilling or exploration activities to evaluate the discovery are firmly planned, all previously capitalized costs associated with the exploratory well would be expensed and shown as a non-cash adjustment to net income in the “Operating activities” section of

the Statement of Cash Flows in the period in which the determination was made. Re-drilling or directional drilling in a previously abandoned well would be classified as development or exploratory based on whether it is in a proved or unproved reservoir for determination of capital or expense. 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 would be charged to expense.

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 are 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. Additionally, Miller and Lents, Ltd., our independent petroleum engineers, estimate our reserves once a year at December 31.

Significant tangible equipment added or replaced is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reserves 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 Statement of Financial Accounting Standards 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 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 reasonable. Any impairment charge incurred is expensed and reduces our recorded basis in the asset pool. Management currently aggregates proved property for impairment testing for Encore Energy Partners LP Predecessor using only one pool of assets due to the geologic similarity and proximity of the properties. 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, Ltd., our independent reserve engineer, prepares a reserve and economic evaluation of all of our properties on a well-by-well basis. Assumptions used by the independent reserve engineers 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 will not remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. As these estimates change, the amount of calculated reserves changes. 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. We are required to 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 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 underproduced imbalance position (i.e., we have cumulatively been under-allocated production) is greater than our share of remaining reserves, we record a liability for the excess at year-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.

New Accounting Pronouncements

Statement of Financial Accounting Standards No. 157, “Fair Value Measurement” (“SFAS 157”)

In September 2006, the FASB issued SFAS 157. SFAS 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under SFAS 157, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim

periods within those fiscal years. We do not expect the implementation of SFAS 157 to have a material impact on our results of operations or financial condition.

Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”)

In February 2007, the FASB issued SFAS 159. SFAS 159 permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We do not expect the implementation of SFAS 159 to have a material impact on our results of operations or financial condition.

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.

Due to the historical volatility of crude oil and natural gas prices, we have entered into various derivative instruments to manage our exposure to volatility in the market price of crude oil and natural gas. We intend to 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.

Derivative Transactions

Oil. As of July 31, 2007, we had outstanding swap, floor and collar contracts as summarized below. Location and quality differentials attributable to our properties are not reflected in the prices. The agreements provide for monthly settlement based on the differential between the fixed price per the contract and the actual average closing NYMEX price for a given month for West Texas Intermediate for near month delivery.


	Swaps				Floors				Ceiling
			Weighted				Weighted				Weighted
			Average				Average				Average
	Bbl/D		Price		Bbl/D		Price		Bbl/D		Price

Oil derivative contracts at July 31, 2007:
July 2007 — December 2008		—	$	—		2,500	$	65.00		—	$	—
January 2009 — December 2009		1,000	$	68.70		1,000	$	63.00		—	$	—
January 2010 — December 2010		—	$	—		1,000	$	65.00		500	$	79.05

Natural Gas. As of July 31, 2007, we had entered into floors and collars with respect to our properties based on the average NYMEX Houston Ship Channel near month prices as summarized below. Location and quality differentials attributable to our properties are not reflected in the prices. The agreements provide for monthly settlement based on the differential between the fixed price per the contract and the actual average closing NYMEX price for a given month for Houston Ship Channel near month delivery.

Floor

Ceiling

Weighted

Average

Mcf/D

Price

Mcf/D

Price

Natural gas contracts at July 31, 2007:

July 2007 — December 2009

4,000

7.70

2,000

9.85

We enter into derivative contracts, primarily collars, swaps and floor contracts in order to mitigate the impact of downward swings in prices on our cash available for distribution. While the use of swaps and collars limits the downside risk of adverse price movements, it also limits increases to future revenues from favorable price movements. The use of derivatives also involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.

All derivative instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying forward price at the determination date. Due to high cost of compliance and reduced financial statement clarity that we feel results from the use of hedge accounting, we do not intend to use hedge accounting for these instruments. As a result, net income will be subject to increased volatility as all the outstanding contracts will be marked to market though earnings each quarter.

Changes in Fair Value

The fair value of our outstanding oil commodity derivative instruments and the change in fair value that would be expected from a $5.00 per Bbl increase in the price of oil and a $1.00 per Mcf increase in the price of natural gas is shown in the table below (in thousands):


	July 31, 2007
			Effect of
			$5.00/Bbl
	Fair		$1.00/Mcf
	Value		Increase

Derivatives not designated as hedging instruments	$	7,811	$	(5,472	)

The fair value of the swaps and option contracts are estimated based on quoted 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 above table. Price risk sensitivities were calculated by assuming across-the-board increases in price of $5.00 per Bbl for oil and $1.00 per Mcf for natural gas regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of actual changes in prompt month prices equal to the assumptions, the fair value of our derivative portfolio would typically change by less than the amount shown in the table due to lower volatility in out-month prices.

BUSINESS

Overview

We are a growth-oriented Delaware limited partnership formed on February 13, 2007 by Encore Acquisition Company to acquire, exploit and develop oil and natural gas properties and to acquire, own and operate related assets. Our assets consist primarily of producing and non-producing oil and natural gas properties in the Elk Basin of Wyoming and Montana and the Permian Basin of West Texas. As of December 31, 2006, on a pro forma basis after giving effect to the acquisition of the Elk Basin assets from subsidiaries of Anadarko Petroleum Corporation, our total estimated proved reserves were 21.4 MMBOE, 68% of which were oil and 86% of which were proved developed.


													Average		Estimated
	Estimated Net Proved Reserves at												Reserve-to-		Production
	December 31, 2006(1)						2006 Net Production						Production		Decline
	Developed		Undeveloped		Total		Oil		Natural Gas		Total		Ratio(2)		Rate(3)
			(MBOE)				(MBbls)		(MMcf)		(MBOE)		(Years)

Elk Basin		13,285		1,806		15,091		1,266		362		1,326		11.4		4.4	%
Permian Basin		5,125		1,163		6,288		7		1,796		306		20.5		10.0	%

Total		18,410		2,969		21,379		1,273		2,158		1,632		13.1		5.5	%


(1)		Our proved oil and natural gas reserves were estimated by Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents, Ltd. performed their evaluations using unescalated prices, operating expenses, and capital expenditures provided by us. Their evaluation was a full determination, which included reviewing and forecasting 100% of the properties. Proved reserves and future net revenues were estimated in accordance with SEC rules.

(2)		The average reserve-to-production ratio is calculated by dividing estimated net proved reserves as of December 31, 2006 by pro forma net production for 2006.

(3)		Represents percentage decrease in production from our proved developed producing properties from 2007 to 2008 as estimated by Miller and Lents, Ltd.

Formation and Closing Transactions

Formation Transactions

We were formed on February 13, 2007. In March 2007, the following transactions occurred:


	•	EAC assigned its rights to acquire the Elk Basin assets to us;

	•	we entered into a five-year revolving credit facility with Bank of America, N.A. providing for an initial borrowing base of $115 million and a $10 million overadvance feature;

	•	an affiliate of EAC loaned us $120 million under the terms of a subordinated term loan agreement;

	•	EAC (through its subsidiaries) made a capital contribution to us of approximately $93.7 million;

	•	we used borrowings of $115 million under our revolving credit facility (excluding $1.6 million in debt issuance costs), $120 million of borrowings under the subordinated term loan agreement and $93.4 million of the capital contribution from EAC to acquire the Elk Basin assets; and


	•	EAC (through its subsidiaries) assigned certain commodity derivative contracts to us covering certain future production from the Elk Basin assets.

Closing Transactions

At the closing of this offering, the following transactions will occur:


	•	we will enter into a contribution, conveyance and assumption agreement with EAC and Encore Operating, L.P., a wholly owned subsidiary of EAC, pursuant to which:


	•	Encore Operating, L.P. will transfer the Permian Basin assets to us in exchange for 4,043,478 common units; and

	•	EAC will agree 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;


	•	we will sell 9,000,000 common units to the public representing an approximate 37.4% limited partner interest in us, and we will use the net proceeds from this offering to reduce our indebtedness;

	•	we will issue additional general partner units to our general partner in exchange for common units to enable our general partner to maintain its 2% general partner interest; and

	•	we will enter into an amended and restated administrative services agreement with Encore Operating, L.P. pursuant to which Encore Operating, L.P. will perform administrative services for us such as accounting, corporate development, finance, land, legal and engineering.

Business Strategy


	•	Purchase assets from EAC through negotiated transactions. We expect to have the opportunity to make acquisitions of 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 will have a lower cost of capital than EAC and our corporate competitors that will enhance our ability to acquire oil and natural gas properties and midstream assets. If we purchase 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 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 will enhance our ability to acquire oil and natural gas properties.

	•	Purchase assets independently of EAC. We plan to implement a growth strategy of pursuing accretive acquisitions of oil and natural gas assets and midstream businesses, 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 also 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 will have a cost of capital advantage relative to our corporate competitors that will enhance 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 will have access to a significant pool of management talent and strong industry relationships that we intend to use in implementing our strategies. I. Jon Brumley, EAC’s founder and current Chairman of the Board, and Jon S. Brumley, EAC’s current Chief Executive Officer and President, will be 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 making quarterly cash distributions to our unitholders at our initial distribution rate, 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 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 will enter into commodity derivatives transactions with unaffiliated third parties in order to mitigate the effects of falling commodity prices. We currently intend 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 will have a fixed floor price for two-thirds of our forecasted production, but a fixed ceiling price for only one-third of our forecasted production, which will enable 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 24 months, depending on various factors including commodity prices, budget requirements and cash reserves.

	•	Maintain relatively low levels of indebtedness in relation to our cash flows from operations to permit us to be opportunistic with future acquisitions of oil and natural gas properties. In the future, we expect to fund approximately 50% of the purchase price of acquisitions with the proceeds from equity issuances and cash flows from operations and to maintain relatively low levels of indebtedness.

Competitive Strengths

We believe the following competitive strengths will 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 will provide 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 relatively high-quality 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 focus for managing and enhancing our operations, for accessing strategic acquisition opportunities and for developing our assets.

	•	Our technical expertise, particularly in enhanced recovery methods, should enable us to efficiently produce and maximize the profitability of our assets. We believe our 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 73% 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 73% of our proved reserves, which allows us to control capital allocation and expenses. For the year ended December 31, 2006, our pro forma direct operating expenses consisted of LOE of $5.58 per BOE and production, ad valorem and severance taxes of $5.55 per BOE. For the six months ended June 30, 2007, our pro forma direct operating expenses consisted of LOE of $9.02 per BOE and production, ad valorem and severance taxes of $5.93 per BOE. Our pro forma general and administrative costs averaged $1.75 per BOE for the year ended December 31, 2006 and for the six months ended June 30, 2007.


	•	Our cost of capital, ability to issue additional common units and low level of indebtedness upon completion of this offering should enable 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 should provide 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. In addition, on a pro forma basis after giving effect to this offering, we will have approximately $69.9 million of debt under our revolving credit facility (or $43.5 million if the underwriters exercise their option to purchase additional common units in full). We believe these attributes will enable us to be competitive in seeking to acquire oil and natural gas properties.

Hydrocarbon Recovery

Through our relationship with EAC, we will have access to significant technical expertise in all methods of hydrocarbon recovery, which differentiates us from many of our competitors. We intend to use this expertise to maximize our production and reserve recovery.

In general, there are three stages of hydrocarbon production. In the first stage, called primary recovery, a well is drilled and completed in a hydrocarbon-bearing zone and the natural pressure of the reservoir forces hydrocarbons into the wellbore and up to the surface. As hydrocarbons are produced, the reservoir pressure declines. Eventually, primary recovery reaches its limit either because the reservoir pressure is so low that further production is not economical or the proportion of gas or water in the production stream is too high. During primary recovery, only a small percentage of the original oil in place is produced.

In the second stage of hydrocarbon production, an external volume such as water or gas is injected into the reservoir through injection wells in order to increase the pressure in the reservoir. The most common secondary recovery technique is waterflooding, which uses injector wells to introduce large volumes of water into the reservoir. As the water flows through the formation toward the producing wellbore, it sweeps additional oil it encounters along with it. Upon reaching the surface, the oil is separated out and the water is reinjected. EAC has been using waterfloods in numerous fields, particularly in the CCA and Permian Basin, for many years. EAC’s engineers, which will be available to us, have significant experience in optimizing waterflood patterns and maximizing production through waterfloods. Through our relationship with EAC, we believe that we will have an opportunity to improve the waterfloods in the Madison formation in the Elk Basin field. While somewhat more expensive than primary production, the successive use of primary recovery and secondary recovery in an oil reservoir typically recovers about 15% to 40% of the original oil in place.

The third stage of hydrocarbon production is called tertiary recovery, or enhanced oil recovery. Tertiary recovery can begin after a secondary recovery process or at any time during the productive life of an oil reservoir. The purpose of tertiary recovery is not only to maintain or restore formation pressure, but also to improve oil displacement or fluid flow in the reservoir. The three major types of tertiary recovery operations are chemical flooding (including alkaline flooding or micellar-polymer flooding), gas flooding (including carbon dioxide, natural gas or nitrogen injection) and thermal recovery (including steamflood or high-pressure air injection). We are currently using a gas-based tertiary recovery technique in the Embar-Tensleep formation in the Elk Basin field where we inject flue gas from our Elk Basin natural gas processing plant into the reservoir. This technique has resulted in relatively flat production from the Embar-Tensleep formation for several years, and we expect only a modest decline rate in the near future. In recent years, EAC has employed high-pressure air injection, or HPAI, as a tertiary recovery process in the CCA. HPAI involves using compressors to inject air into previously produced oil and natural gas formations in order to displace remaining resident hydrocarbons and force them under pressure to a common lifting point for production. The optimal application of each type of recovery process depends on reservoir characteristics.

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 in 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 (collectively, the “Elk Basin”) were acquired from subsidiaries of Anadarko Petroleum Corporation in March 2007 for approximately $329.4 million, including estimated transaction costs of approximately $1.0 million. For the year ended December 31, 2006, production from the Elk Basin was approximately 3,633 BOE/D, of

which approximately 95% was oil and 5% was natural gas. From the date of acquisition through June 30, 2007, production from the Elk Basin was approximately 3,591 BOE/D, of which approximately 97% was oil and 3% was natural gas. On a pro forma basis for the six months ended June 30, 2007, production from our Elk Basin properties was approximately 3,519 BOE/D. The Elk Basin had estimated proved reserves at December 31, 2006 of 15,091 MBOE, of which 13,285 MBOE was proved developed and 1,806 MBOE was proved undeveloped. Approximately 99% of proved reserves in the Elk Basin are located in the Embar-Tensleep, Madison and Frontier formations. Our oil and natural gas properties in the Elk Basin include 21,925 gross acres and 13,699 net acres located in Park County, Wyoming and Carbon County, Montana. All of our production in the Elk Basin is operated, and over 77% of our oil and natural gas properties in the Elk Basin are federal leases. Our Elk Basin properties have a proved developed producing production decline rate of approximately 4.4% per year and a reserve-to-production ratio of approximately 11 years. The reserve report prepared by Miller and Lents, Ltd. includes 29 projects in the Elk Basin field that are categorized as proved reserves.

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 higher 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. We operate 118 gross wells that produce from the Embar-Tensleep formation in the Elk Basin field. These wells are drilled to a depth of 4,200 to 5,400 feet. We hold a 62% working interest and a 56% net revenue interest in our wells in the Embar-Tensleep formation.

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.

The Embar-Tensleep formation had estimated total proved reserves at December 31, 2006 of 6,201 MBOE, all of which were oil and 96% of which were proved developed, and is expected to produce 592 MBOE in 2007.

Madison Formation in the Elk Basin Field. We operate 187 wells that produce from the Madison formation in the Elk Basin field. These wells are drilled to a depth of 4,800 to 5,800 feet. We hold a 67% working interest and a 61% net revenue interest in our wells in the Madison formation.

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

The Madison formation had estimated total proved reserves at December 31, 2006 of 5,880 MBOE, all of which were oil and 85% of which were proved developed, and is expected to produce 353 MBOE in 2007.

Frontier Formation in the Elk Basin Field. We operate 4 wells that produce from the Frontier formation in the Elk Basin field. These wells are typically drilled to a depth of 1,600 to 2,900 feet. We hold a 93% working interest and a 83% net revenue interest in our wells in the Frontier formation. The Frontier formation is being produced through primary recovery techniques.

The Frontier formation had estimated total proved reserves at December 31, 2006 of 1,701 MBOE, 76% of which were oil and 60% of which were proved developed, and is expected to produce 126 MBOE in 2007.

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 significant working interests and net revenue interests in these wells.

Natural Gas Processing Plant

We operate and own a 62% interest in the Elk Basin natural gas processing plant near Powell, Wyoming, which was first placed into operation in the 1940s. ExxonMobil Corporation, or ExxonMobil, owns a 34% interest in the Elk Basin natural gas processing plant and other parties own the remaining 4% 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 the South Elk Basin fields. The Elk Basin natural gas processing plant currently produces approximately 380 net Bbls of NGLs per day, primarily propane, normal butane and natural gasoline.

A by-product of our natural gas processing is flue gas. 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 to increase the pressure in this formation.

Pipelines

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

The Clearfork pipeline is regulated by the Federal Energy Regulatory Commission, or FERC, and transports approximately 4,000 Bbl/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 10.6 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 11.4 MMcfe/D of higher sulfur natural gas from the Elk Basin field to our Elk Basin natural gas processing plant.

Permian Basin Crockett 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.

Our properties in the Permian Basin were acquired by EAC in March 2000 and are located in Crockett County, Texas. For the year ended December 31, 2006, production from our Permian Basin properties was approximately 838 BOE/D, substantially all of which was natural gas. For the six months ended June 30, 2007, production from our Permian Basin properties was approximately 719 BOE/D, substantially all of which was natural gas. Our Permian Basin properties had estimated proved reserves at December 31, 2006 of 6,288 MBOE, of which 3,702 MBOE was proved developed producing, 1,423 MBOE was proved developed non-producing and 1,163 MBOE was proved undeveloped. The reserve report prepared by Miller and Lents, Ltd. includes 45 projects in the Permian Basin that are categorized as proved reserves. Our Permian Basin properties consist of 25,115 gross acres and 10,384 net acres located in Crockett County, Texas.

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

Operated Properties

We operate 50 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 55% and net revenue interests of 48% 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 29% and an average net revenue interest of 21% 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. The Canyon Sand produces from several sands over a gross interval of 400 to 500 feet. Many of the wells were not completed in all of the known producing intervals. We have identified 1,423 MBOE of proved non-producing reserves in these wells.

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 1,163 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 2000. In addition, there remain many quality infill locations to be developed on this company’s leases. Historically, we have participated with this company in drilling 2 to 4 wells per year and hold an average working interest of approximately 46%.

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 ranged from 2.4% to 6.8%.

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 the 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. As of December 31, 2006, on a pro forma basis after giving effect to acquisitions of certain oil and natural gas properties and related assets in the Big Horn and Williston Basins (including the Elk Basin assets) and the disposition of certain oil and natural gas properties and related assets in the Mid-Continent, EAC’s total estimated proved reserves were 226 MMBOE, 83% of which were oil and 69% of which were proved developed.

The following table summarizes information about EAC’s oil and natural gas reserves as of December 31, 2006 and EAC’s net production for 2006 on a pro forma basis:


																			Average
	Estimated Net Proved Reserves at																		Reserve-to-
	December 31, 2006(1)									2006 Net Production									Production
	Oil			Natural Gas			Total			Oil			Natural Gas			Total			Ratio
	(MBbls)			(MMcf)			(MBOE)			(MBbls)			(MMcf)			(MBOE)			(Years)(2)

Cedar Creek Anticline		117,868			15,750			120,493			4,851			1,330			5,073			23.8
Permian Basin		23,105			106,693			40,887			1,277			5,841			2,250			18.2
Rockies		8,716			2,895			9,198			732			360			792			11.6
Mid-Continent		3,745			181,426			33,983			475			15,925			3,129			10.9

Total		153,434			306,764			204,561			7,335			23,456			11,244			18.2
Acquisitions(3)		35,685			19,496			38,934			3,349			1,558			3,608			10.8
Disposition(4)		(1,465	)		(95,703	)		(17,416	)		(164	)		(7,308	)		(1,382	)		12.6

Total pro forma		187,654			230,557			226,079			10,520			17,706			13,470			16.8


(1)		EAC’s proved oil and natural gas reserves were estimated by Miller and Lents, Ltd., independent petroleum engineers, except for oil and natural gas reserves related to the Gooseberry acquisition and the Williston Basin acquisition, which were estimated by EAC’s engineers.


(2)		The average reserve-to-production ratio is calculated by dividing EAC’s estimated net proved reserves as of December 31, 2006 by its net production for 2006.

(3)		Includes oil and natural gas reserves from the acquisition of properties in the Elk Basin field and the Gooseberry field in the Big Horn Basin of Wyoming and Montana on March 7, 2007 and the acquisition of properties in the Williston Basin in Montana and North Dakota on April 11, 2007.

(4)		The disposition relates to the sale of oil and natural gas properties and related assets in the Mid-Continent on June 29, 2007.

EAC had a staff of approximately 338 persons, including 35 engineers, 13 geologists and 12 landmen as of August 3, 2007. Through our relationship with EAC, we will have access to EAC’s personnel and senior management team, strong commercial relationships throughout the oil and natural gas industry and access to EAC’s broad operational, commercial, technical, risk management and administrative infrastructure. We expect that numerous EAC personnel will devote time to the conduct our business and affairs, including the following:


	•	EAC has dedicated one full time engineer to the position of Manager of MLP Assets;

	•	EAC’s and our general partner’s Vice President of Mid-Continent will devote at least 50% of his time to our business and affairs;

	•	approximately 47 field personnel related to our Elk Basin assets in Wyoming will devote all of their time to our business and affairs;

	•	approximately three field personnel related to our Permian Basin assets in Crockett County, Texas will devote an estimated 15% of their time to our business and affairs;

	•	four financial reporting and tax accountants will devote substantially all of their time to our business and affairs; and

	•	several other accountants will devote their time to our business and affairs in an aggregate amount equivalent to six full-time people.

We will also have access to such other employees of EAC as may be necessary for the conduct of our business and affairs.

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. EAC has indicated that it intends to use us as a growth vehicle to pursue the acquisition of producing oil and natural gas properties. After giving effect to the Big Horn Basin acquisition, the Williston Basin acquisition and the Mid-Continent disposition, EAC’s properties currently are located in the following core areas:


	•	Cedar Creek Anticline: The CCA is a major structural feature of the Williston Basin in southeastern Montana and northwestern North Dakota. EAC’s acreage is concentrated on the two- to six-mile-wide “crest” of the CCA, giving it access to the greatest accumulation of oil in the structure. EAC’s holdings extend for approximately 120 continuous miles along the crest of the CCA across five counties in two states. Primary producing reservoirs are the Red River, Stony Mountain, Interlake and Lodgepole formations at depths of between 7,000 and 9,000 feet. EAC’s fields in the CCA include the North Pine, South Pine, Cabin Creek, Coral Creek, Little Beaver, Monarch, Glendive North, Glendive, Gas City and Pennel fields. EAC is producing the CCA through a combination of waterfloods and high-pressure air injection. Since taking over operations, EAC’s net production from the CCA has increased by approximately 64% from 7,807 BOE/D (average for June 1999) to 12,805 BOE/D (average for the second quarter of 2007). As of December 31, 2006, EAC’s total estimated proved reserves in the CCA were 120.5 MMBOE, 98% of which were oil and 58% of which were proved developed.


	•	Permian Basin: EAC’s Permian Basin properties include fields in West Texas and New Mexico:


	•	West Texas: EAC’s West Texas properties include seventeen operated fields, including the East Cowden Grayburg Unit, Fuhrman-Mascho, Crockett County, Sand Hills, Howard Glasscock, Nolley, Deep Rock and others; and seven non-operated fields. Production from the central portion of the Permian Basin comes from multiple reservoirs, including the Grayburg, San Andres, Glorietta, Clearfork, Wolfcamp and Pennsylvanian zones. Production from the southern portion of the Permian Basin comes mainly from the Canyon and Strawn formations with multiple pay intervals.

In March 2006, EAC entered into a joint development agreement with ExxonMobil to develop legacy natural gas fields in West Texas. The ExxonMobil agreement covers certain formations in the Parks, Pegasus and Wilshire Fields in Midland and Upton Counties, the Brown Bassett Field in Terrell County, and Block 16, Coyanosa and Waha Fields in Ward, Pecos and Reeves Counties. Targeted formations include the Barnett, Devonian, Ellenberger, Mississippian, Montoya, Silurian, Strawn and Wolfcamp horizons.


	•	New Mexico: EAC established the New Mexico region in May 2006 with the strategy of deploying capital to develop low- to medium-risk drilling projects in southeastern New Mexico where multiple reservoir targets are available. Since May 2006, EAC has acquired or farmed-in approximately 10,500 gross acres and identified and secured approximately 30 low-risk infill locations.

Average daily production for EAC’s Permian Basin properties in the second quarter of 2007 was 7,146 BOE/D. As of December 31, 2006, EAC’s total estimated proved reserves in the Permian Basin were 40.9 MMBOE, 57% of which were oil and 73% of which were proved developed. For a discussion of EAC’s Permian Basin properties that will be contributed to us in connection with this offering, please read “— Our Areas of Operation — Permian Basin Crockett Properties.”


	•	Rockies: The Rockies area includes non-CCA assets in the Big Horn Basin of Montana and Wyoming, the Williston and Powder River Basins of Montana and North Dakota, and the Paradox Basin of southeastern Utah.


	•	Big Horn Basin — Wyoming and Montana: In March 2007, EAC acquired oil properties and related assets in the Gooseberry field in Park County, Wyoming at the same time that we acquired the Elk Basin properties. Average daily production for EAC’s Big Horn Basin properties was 4,440 BOE/D during the second quarter of 2007. For a discussion of our Elk Basin properties, please read “— Our Areas of Operation — Elk Basin Properties” beginning on page 94.

	•	Williston Basin — North Dakota and Montana: EAC’s Big Horn, Williston Basin properties have historically consisted of working and overriding royalty interests in several geographically concentrated fields. The properties are located in the Williston Basin of western North Dakota and eastern Montana, which is the same basin as the CCA properties. In April 2007, EAC acquired additional properties in the Williston Basin. The properties are comprised of 50 different fields across Montana and North Dakota. EAC’s internal engineers have estimated that total proved reserves from these properties are approximately 21 MMBOE, which are 90% oil and 81% proved developed producing and are 85% operated by EAC. As part of this acquisition, EAC also acquired approximately 70,000 net acres in the Bakken play of Montana and North Dakota. The average daily production from the Williston Basin properties was 5,961 BOE/D for the second quarter of 2007.

	•	Powder River Basin — Montana: The Bell Creek properties are located in the Powder River Basin of southeastern Montana. EAC operates seven production units that comprise the Bell Creek properties, each with a 100% working interest. The shallow (less than 5,000 feet) Cretaceous-aged Muddy Sandstone reservoir produces oil. EAC has initiated a pilot polymer injection program on its Bell Creek properties whereby a polymer is injected into a well to reduce the amount of water injection needed to recover oil. The polymer injection process also redirects the injected water into new pathways to produce oil previously bypassed by the original waterflood. This process, coupled with polymer treatments to oil producers, makes for a more efficient recovery of oil than standard

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		waterflooding. Average daily production from the Bell Creek properties was 716 BOE/D during the second quarter of 2007.


	•	Paradox Basin — Utah: The Paradox Basin properties, located in southeast Utah’s Paradox Basin, are divided between two prolific oil producing units: the Ratherford Unit and the Aneth Unit both operated by Resolute Natural Resources Company. EAC believes these properties have potential horizontal redevelopment, secondary development and tertiary recovery potential. Average net production from the Paradox Basin properties for the second quarter of 2007 was approximately 717 BOE/D.

Average daily production for the Rockies area was 11,833 BOE/D for the second quarter of 2007. As of December 31, 2006, EAC’s total estimated proved reserves in the Rockies were 9.2 MMBOE, 95% of which were oil and 78% of which were proved developed.


	•	Mid-Continent: The Mid-Continent area includes the Arkoma and Anadarko Basins of Oklahoma, the North Louisiana Salt Basin, the East Texas Basin and the Barnett Shale of North Texas:


	•	Oklahoma, Arkansas, North Texas and Kansas: EAC’s assets in Oklahoma and Arkansas consist of operated interests in 5 mature waterfloods in Oklahoma, nonoperated interests in the Cleveland formation in northwest Oklahoma, nonoperated interests in the Chismville gas field in northwest Arkansas and royalty interests in Arkansas and Oklahoma. Average daily production from these properties during the second quarter of 2007 was approximately 37,110 Mcfe/D.

	•	North Louisiana Salt Basin and East Texas Basin: The North Louisiana Salt Basin and East Texas Basin properties consist of operated working interests, non-operated working interests and undeveloped leases acquired primarily in EAC’s Elm Grove and Overton acquisitions in 2004. EAC’s interests acquired in the Elm Grove acquisition are located in the Elm Grove Field in Bossier Parish, Louisiana, and include non-operated working interests ranging from 1% to 47% across 1,800 net acres in 15 sections. The Overton Field assets are in the same core area as EAC’s interests in Elm Grove field and have similar geology. The properties are producing primarily from multiple tight sandstone reservoirs in the Travis Peak and Lower Cotton Valley formations at depths ranging between 8,000 and 11,500 feet. Estimated proved reserves are approximately 94% natural gas, and the properties are 100% operated by EAC. Average daily production for this region was 20,485 Mcfe/D for the second quarter of 2007.

Average daily production for the Mid-Continent area was 57,595 Mcfe/D for the second quarter of 2007. As of December 31, 2006, EAC’s total estimated proved reserves in the Mid-Continent were 34.0 MMBOE, 89% of which were natural gas and 79% of which were proved developed.

The Lifecycle of an Acquisition

When we acquire oil and natural gas properties, we attempt to maximize our investment by taking the following steps:


	•	Re-engineering. We look for opportunities to re-engineer mature oil and natural gas fields to more efficiently and economically produce the remaining hydrocarbons. Many oil and natural gas properties are sold because they are not of strategic importance to the seller. This scenario, more than any other, presents opportunities for increased reserve recovery because non-strategic assets are often undermanned, and these assets can be enhanced by a new and more attentive owner.

	•	Identifying Opportunities for Immediate Improvement. As we re-engineer our acquired properties, we identify opportunities to raise production without spending significant capital, such as returning producers back to production.

	•	Workovers. After thoroughly evaluating a new acquisition and taking advantage of opportunities for immediate improvement, we identify existing wells that need a workover, which is a process of performing major maintenance or remedial treatments on an oil or natural gas well.

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	•	Drilling and Waterfloods. After working over existing wells, we evaluate our inventory of potential drilling locations. For fields on waterflood, we also evaluate the feasibility of optimizing waterflood patterns in order to maximize production. We believe that waterflooded fields are well suited for our partnership because of their potential for increased reserve recovery with modest capital requirements.

	•	Tertiary Recovery. After waterflooding techniques have been applied, we also evaluate the feasibility of applying tertiary recovery techniques to our existing properties to increase production and proved reserves. We are currently using tertiary recovery techniques in the Embar-Tensleep formation in the Elk Basin field and EAC has employed the HPAI tertiary recovery process in the CCA. We believe that such enhanced recovery projects are well suited for our partnership because we believe they will enable us to maintain our current production levels from these assets for several years with relatively modest capital requirements.

Crude Oil and Natural Gas Prices

Factors Affecting the Price of Crude Oil and Natural Gas at the Wellhead

The relative value of crude oil and natural gas at the wellhead is determined by two main factors: quality and location relative to consuming and refining markets.


	•	Crude Oil Prices. The NYMEX futures price of crude oil is a widely used benchmark in the pricing of domestic and imported oil in the United States. Crude oils differ from one another due to their different molecular makeup, which plays an important part in their refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly impact crude oil quality differentials: (1) the API gravity and (2) the percentage of sulfur content by weight. In general, lighter crudes (with higher API) produce a larger number of lighter products, such as gasoline, which have higher resale value and, therefore, lighter crudes are expected to sell at a premium over heavier crude oil. Crude oil produced in close proximity to major consuming and refining markets will require less transportation and therefore will be more attractive and command a premium over oil produced farther from the market, which requires greater transportation costs to get to the market. Crudes with lower sulfur content are more desirable and less expensive to refine and, as a result, receive a higher price than high-sulfur crudes. The crude oil in the Elk Basin is considered a high sulfur crude.

	•	Natural Gas Prices. The NYMEX futures price of natural gas is a widely used benchmark in the pricing of natural gas in the United States. Among other things, there are three characteristics that commonly impact natural gas prices: (1) the Btu content of natural gas, which measures its heating value, (2) the percentage of sulfur content by volume, and (3) the proximity of the natural gas to major consuming markets. Our Permian Basin properties produce natural gas with a high Btu content.

Differentials

The prices that we receive for our crude oil and natural gas production sometimes trade at a discount to the relevant benchmark prices, such as NYMEX. The difference between the NYMEX price and the price we receive is called a differential.


	•	Elk Basin. In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have gradually widened the differential for crude oil produced in Wyoming. For example, for the year ended December 31, 2006, the average discount to NYMEX for our Elk Basin crude oil and NGL production was approximately $15.91 per Bbl.

	•	Permian Basin. Natural gas production in the Permian Basin is also often sold at a discount to benchmark prices due primarily to its remote location from consuming areas. For the year ended December 31, 2006, the average discount to NYMEX for our Permian Basin natural gas was approximately $0.12 per Mcf.

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Derivative Transactions

We enter into derivative transactions to reduce the impact of crude oil and natural gas price volatility on our cash flow from operations. For the remainder of 2007, we have crude oil and natural gas put contracts and ceiling contracts covering 72% and 8%, respectively, of our estimated future production. For 2008 and 2009, we have crude oil and natural gas put contracts covering 72% and 37%, respectively, of our estimated future production, swap contracts covering 0% and 22%, respectively, of our estimated future production, and ceiling contracts covering 8% and 7%, respectively, of our estimated future production. For 2010, we have crude oil and natural gas put contracts and ceiling contracts covering 24% and 12%, respectively, of our estimated future production.

We currently intend to enter into put contracts for approximately one-third of our future production and fixed-price commodity derivative contracts (such as swaps or collars) for an additional one-third of our estimated future production. Using this approach, we will have a fixed floor price for two-thirds of our future production, but a fixed ceiling price for only one-third of our estimated future production, which will enable us to participate in price increases for our oil and natural gas. We will maintain the flexibility to mitigate the price risk on the remaining one-third of our estimated future production by using commodity derivative contracts. When we enter into new commodity derivative contracts, we expect that they will be for approximately 24 months.

By removing the price volatility from a significant portion of our crude oil production, we have mitigated, but not eliminated, the potential effects of changing crude oil prices on our cash flow from operations for those periods. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk.”

Our Pro Forma Oil and Natural Gas Data

This section reflects Encore Energy Partners LP’s oil and natural gas data on a pro forma basis after giving effect to the Elk Basin acquisition in March 2007.

Estimated Pro Forma Proved Reserves

The following table presents the estimated net proved oil and natural gas reserves and the present value of estimated proved reserves relating to our properties at December 31, 2006, based on a reserve report prepared by our independent petroleum engineers, Miller and Lents, Ltd.


	As of
	December 31,
	2006

Reserve Data:
Estimated net proved reserves:
Oil (MBbls)		14,520
Natural gas (MMcf)		41,152
Total (MBOE)		21,379
Proved developed (MBOE)		18,410
Proved undeveloped (MBOE)		2,969
Proved developed reserves as % of total proved reserves		86	%
Standardized Measure (in millions)(1)	$	297.4
Realized Oil and Natural Gas Prices(2):
Oil per Bbl	$	46.46
Natural gas per MMBtu	$	5.29
Spot Oil and Natural Gas Prices(3):
Oil — spot per Bbl	$	61.06
Natural gas — spot per MMBtu	$	5.48

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(1)		Standardized measure is 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, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Our standardized measure does not reflect any future income tax expenses because we are not subject to federal income taxes, although we have provided for the payment of Texas franchise taxes. Standardized measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk.”

(2)		The realized prices above that were used in the determination of standardized measure represent a cash market price on December 31 less all expected quality, transportation and demand adjustments. Realized prices are presented before the effects of hedging.

(3)		The spot oil and natural gas prices represent the cash market prices at December 31, 2006 without reduction for expected quality, transportation and demand adjustments.

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

The data in the above table represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. Please read “Risk Factors.”

Future prices received for production and paid for costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. Standardized measure is the present value of estimated future net revenues 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) without giving effect to non-property related expenses such as general and administrative expenses, debt service or depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. Because we are a limited partnership which passes through our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of standardized measure, although we have provided for the payment of Texas franchise taxes. Standardized measure does not give effect to derivative transactions. The standardized measure shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by FASB pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

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Our Pro Forma Production and Price History

The following table sets forth information for our oil and natural gas properties regarding net production of oil and natural gas and certain price and cost information for the periods indicated:


			Six Months
	Year Ended		Ended
	December 31,		June 30,
	2006		2007

Net Production:
Total production (MBOE)		1,632		767
Average daily production (BOE/D)		4,471		4,238
Average Sales Prices per BOE	$	48.31	$	48.19
Production Expense per BOE	$	11.13	$	14.95

Our Pro Forma Productive Wells

The following table sets forth pro forma information relating to the productive wells in which we owned a working interest as of December 31, 2006. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have 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 hold in all wells. We compute the number of net wells we own by totaling the percentage interests we hold in all our gross wells.

Our wells may produce both oil and natural gas. We classify a well as an oil well if the net equivalent production of oil was greater than natural gas for the well.


	Gross Wells						Net Wells
			Natural						Natural
	Oil		Gas		Total		Oil		Gas		Total

Elk Basin
Operated		308		35		343		267		23		290
Non-Operated		—		—		—		—		—		—
Permian Basin
Operated		—		50		50		—		27		27
Non-Operated		—		217		217		—		64		64

Total		308		302		610		267		114		381

Our Pro Forma Developed and Undeveloped Acreage

The following table sets forth pro forma information as of December 31, 2006 relating to our leasehold acreage.


	Developed Acreage(2)				Undeveloped Acreage(3)
	Gross(4)		Net(5)		Gross(4)		Net(5)

Elk Basin
Operated(1)		9,658		6,113		12,267		7,586
Non-Operated		—		—		—		—
Permian Basin
Operated		4,475		2,865		—		—
Non-Operated		19,972		6,851		668		668

Total		34,105		15,829		12,935		8,254

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(1)		We also own royalty or overriding royalty interests in 3 wells in the Elk Basin that are operated by Merit Energy Company.

(2)		Developed acres are acres spaced or assigned to productive wells.

(3)		Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.

(4)		A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(5)		A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Substantially all of our developed and undeveloped acreage is held by production, which means that, as long as our wells on the acreage continue to produce, we will continue to own the leases.

Our Pro Forma Development Activity

We intend to 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 will vary depending on the amount of funds we have available, the cost of those activities, the size of the fractional working interests we acquire in each well and the estimated recoverable reserves attributable to each well.

The following table sets forth information for our properties with respect to wells completed during the year ended December 31, 2006 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. Productive wells are those that produce commercial quantities of oil and natural gas, regardless of whether they produce a reasonable rate of return. No exploratory wells were drilled during the periods presented.


	Year Ended
	December 31,
	2006

Gross Development Wells:
Productive		3.0
Dry		—

Total		3.0

Net Development Wells:
Productive		1.4
Dry		—

Total		1.4

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Encore Energy Partners LP Predecessor’s Oil and Natural Gas Data

Encore Energy Partners LP Predecessor Reserves

The following table presents Encore Energy Partners LP Predecessor’s estimated net proved oil and natural gas reserves and the present value of Encore Energy Partners LP Predecessor’s estimated proved reserves at December 31, 2006, prepared in accordance with the rules and regulations of the SEC.


	As of December 31,
	2004			2005			2006

Reserve Data:
Estimated net proved reserves:
Oil (MBbls)		43			45			50
Natural gas (MMcf)		40,966			44,190			37,426
Total (MBOE)		6,871			7,410			6,288
Proved developed (MBOE)		4,881			5,372			5,125
Proved undeveloped (MBOE)		1,990			2,038			1,163
Proved developed reserves as % of total proved reserves		71	%		72	%		82	%
Standardized Measure (in thousands)(1)	$	82,722		$	126,605		$	50,672
Realized Oil and Natural Gas Prices(2):
Oil per Bbl	$	40.67		$	57.03		$	57.46
Natural gas per MMBtu	$	5.88		$	8.49		$	5.23
Spot Oil and Natural Gas Prices(3):
Oil — spot per Bbl	$	43.46		$	61.04		$	61.06
Natural gas — spot per MMBtu	$	6.19		$	9.44		$	5.48


(1)		Standardized measure is 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, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Our standardized measure does not reflect any future income tax expenses because we are not subject to federal income taxes, although we have provided for the payment of Texas franchise taxes. Standardized measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk.”

(2)		The realized prices above that were used in the determination of standardized measure represent a cash market price on December 31 less all expected quality, transportation and demand adjustments. Realized prices are presented before the effects of hedging.

(3)		The spot oil and natural gas prices represent the cash market prices at December 31, 2004, 2005 and 2006 without reduction for expected quality, transportation and demand adjustments.

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Encore Energy Partners LP Predecessor Production and Price History

The following table sets forth information regarding net production of oil and natural gas prices and certain price and cost information of Encore Energy Partners LP Predecessor for each of the periods indicated.


	Year Ended December 31,						Six Months Ended June 30,
	2004		2005		2006		2006		2007

Net Production:
Total production (MBOE)		357		344		306		155		568
Average daily production (BOE/D)		976		942		838		858		3,139
Average Sales Prices per BOE	$	37.05	$	49.13	$	41.67	$	44.41	$	46.41
Production Expense per BOE	$	7.84	$	9.37	$	9.48	$	9.22	$	14.49

Encore Energy Partners LP Predecessor Productive Wells

The following table sets forth information relating to the productive wells in which Encore Energy Partners LP Predecessor owned a working interest as of December 31, 2006. 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 Encore Energy Partners LP Predecessor had a working interest, regardless of its percentage interest. A net well is not a physical well, but is a concept that reflects the actual total working interest Encore Energy Partners LP Predecessor held in all wells. The number of net wells Encore Energy Partners LP Predecessor owned is calculated by totaling the percentage interests it held in all our gross wells.

Encore Energy Partners LP Predecessor’s wells may produce both oil and natural gas. A well is classified as an oil well if the net equivalent production of oil was greater than natural gas for the well.


	Gross Wells						Net Wells
			Natural						Natural
	Oil		Gas		Total		Oil		Gas		Total

Permian Basin
Operated		—		50		50		—		27		27
Non-Operated		—		217		217		—		64		64

Total		—		267		267		—		91		91

Encore Energy Partners LP Predecessor Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2006 relating to Encore Energy Partners LP Predecessor’s leasehold acreage.


	Developed				Undeveloped
	Acreage(1)				Acreage(2)
	Gross(3)		Net(4)		Gross(3)		Net(4)

Permian Basin
Operated		4,475		2,865		—		—
Non-Operated		19,972		6,851		668		668

Total		24,447		9,716		668		668


(1)		Developed acres are acres spaced or assigned to productive wells.

(2)		Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.

(3)		A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

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(4)		A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Encore Energy Partners LP Predecessor Development Activity

The following table summarizes Encore Energy Partners LP Predecessor’s approximate gross and net interest in wells completed during the year ended December 31, 2006 on its properties 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.


	Year Ended
	December 31,
	2006

Gross Development Wells:
Productive		3.0
Dry		—

Total		3.0

Net Development Wells:
Productive		1.4
Dry		—

Total		1.4

Delivery Commitments

We have no delivery commitments at prices other than market prices or for terms greater than one year.

Operations

Well Operations

In general, we seek to be the operator of wells in which we have an 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. Pursuant to the amended and restated administrative services agreement, Encore Operating, L.P. will provide administrative services to us. Encore Operating, L.P. employs production and reservoir engineers, geologists and other specialists, as well as field personnel. For more information, please read “Certain Relationships and Related Party Transactions — Amended and Restated Administrative Services Agreement.”

During 2006 and the first six months of 2007, pro forma lease operations expenses for our wells was $9.1 million and $6.9 million, respectively.

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;

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	•	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

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

Please read “— Our Areas of Operation — Elk Basin Properties.”

Our gas gathering systems will be operated for us by Encore Operating, L.P. pursuant to the amended and restated administrative services agreement. For a description of this agreement and the fees to be charged thereunder, please read “Certain Relationships and Related Party Transactions — Amended and Restated Administrative Services Agreement.”

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any well(s) drilled on the lease premises. In the Elk Basin, this amount is typically 12.5% for oil and natural gas, resulting in a 76.5% net oil revenue interest and a 75.5% net natural gas revenue interest to us for most leases directly acquired by us. In the Permian Basin, this amount is typically 12.5% for oil and natural gas, resulting in a 44.9% net oil revenue interest and a 23.4% net natural gas revenue interest to us for most leases directly acquired by us.

Because the acquisition of oil and natural gas leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are often held by other oil and natural gas operators. In order to gain the right to drill these leases, we may elect to farm-in leases and/or purchase leases from other oil and natural gas operators. Typically the assignor of such leases will reserve an overriding royalty interest, ranging from 1/32nd to 1/16th (3.125% to 6.25%), which further reduces the net revenue interest available to us to between 87.5% and 81.25%.

Sometimes these third-party owners of oil and natural gas leases retain the option to participate in the development of wells on leases farmed out or assigned to us. The retained interest normally ranges between a 10% and 50% working interest. In this event, our working interest ownership will be reduced by the amount retained by the third-party operator.

Substantially 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 gas, we will continue to own the lease.

Principal Customers and Marketing Arrangements

For the first six months of 2007, we sold 58% and 18% of our Elk Basin production to Marathon Oil Corporation and ConocoPhillips, respectively. For 2006, we sold 42% and 30% of our Elk Basin production to Marathon Oil Corporation and ConocoPhillips, respectively.

We currently sell all our operated Permian Basin production to Chevron Corporation. We do not market our own natural gas on our non-operated Permian Basin properties, but receive our net share of revenues from the operator.

Our production sales agreements contain customary terms and conditions for the oil and natural gas industry, provide for sales based on prevailing market prices and have terms ranging from 30 days to six months.

Derivative Activity

We enter into derivative transactions with unaffiliated third parties with respect to oil and natural gas in order to mitigate the negative effects of declining commodity prices. In the future, we may enter into interest rate derivative transactions in order to reduce our exposure to short-term fluctuations in interest rates. For a more detailed discussion of our derivative activities, please read “Management’s Discussion and Analysis of

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Financial Condition and Results of Operations — Overview” and “— Quantitative and Qualitative Disclosures About Market Risk.”

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for development equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs 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 financial or personnel 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 development 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 cannot assure you that we will be able to compete satisfactorily when attempting to make further acquisitions.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of development operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence development operations on a property until we have cured any material title defects on the property. Prior to completing an acquisition of producing oil leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Our oil properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Some of our oil and natural gas leases, easements, rights-of-way, permits, licenses and franchise ordinances require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. We believe that we have obtained or will obtain sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects as described in this prospectus. Record title to some of our assets will continue to be held by our affiliates until we have made the appropriate filings in the jurisdictions in which such assets are located and obtained any consents and approvals that are not obtained prior to transfer. With respect to any consents, permits or authorizations that have not been obtained, we believe that these consents, permits or authorizations generally will be obtained after the closing of this offering, or that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.

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.

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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 all relevant environmental and safety laws and regulations that relate to our operations.

Waste Handling

The Resource Conservation and Recovery Act, or 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, or 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 condition. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils, that may be regulated as hazardous wastes.

Site Remediation

The Comprehensive Environmental Response, Compensation and Liability Act, or 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

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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, 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 that are part of this acquisition, and some of these sites are undergoing active remediation. The risks associated with these environmental conditions, and the cost of remediation, are being 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 are assuming 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 the Elk Basin 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. Due to the significant level of uncertainty associated with the known and unknown environmental liabilities at the gas plant, our estimates include a large contingency. 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 even while the gas plant remains in operation. We have reserved $5.4 million as future abandonment cost on a pro forma basis for the decommissioning of the Elk Basin natural gas processing plant, and we expect to continue reserving additional amounts based on our estimated timing to cease operations of the natural gas processing plant.

Water Discharges

The Clean Water Act, or 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 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

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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, or OPA, which addresses three principal areas of oil pollution — prevention, containment and cleanup. OPA applies to vessels, offshore facilities and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be 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, or 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.

Congress is currently considering other proposed legislation directed at reducing “greenhouse gas emissions,” and certain states have adopted legislation, regulations and/or initiatives addressing greenhouse gas emissions from various sources, primarily power plants. Additionally, on April 2, 2007, the U.S. Supreme Court ruled in Massachusetts v. EPA that the EPA has authority under the CAA to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks). The Court also held that greenhouse gases fall within the CAA’s definition of “air pollutant,” which could result in future regulation of greenhouse gas emissions from stationary sources, 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 the 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, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct,

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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 and Other Laws and Regulation

We are subject to the requirements of the federal Occupational Safety and Health Act, or 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 the 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. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2006. Additionally, as of the date of this prospectus, we are not aware of any environmental issues or claims that will require material capital expenditures during 2007. However, accidental spills or releases may occur in the course of our operations, and we cannot assure you that we will not 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, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our business, financial condition, results of operations or ability to make distributions to you.

Other Regulation of the Oil and Natural Gas Industry

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

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

Development and Production

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


	•	the location of wells;

	•	the method of developing and casing wells;

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

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	•	the plugging and abandoning of wells; and

	•	notice to 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 natural gas and oil 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 natural gas and oil 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 natural gas and oil 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 FERC under the October 1, 1977 version of the Interstate Commerce Act, or ICA, and the Energy Policy Act of 1992, or 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, or 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.

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.

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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, or 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, or 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

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 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.

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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.

Employees

The officers of our general partner will manage our operations and activities. However, neither we, our subsidiaries, nor our general partner have employees. We intend to enter into an amended and restated administrative services agreement with Encore Operating, L.P. pursuant to which Encore Operating, L.P. will perform administrative services for us. For more information about the management of our partnership and our use of EAC personnel, please read “Management” on page 119. For more information on the amended and restated administrative services agreement, please read “Certain Relationships and Related Party Transactions — Amended and Restated Administrative Services Agreement.”

EAC had a staff of approximately 338 persons, including 35 engineers, 13 geologists and 12 landmen as of August 3, 2007. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that Encore Operating, L.P.’s relations with its employees are satisfactory.

Offices

EAC’s principal executive offices are located at 777 Main Street, Suite 1400, Fort Worth, Texas 76102, which is also where our principal executive offices are located.

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

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MANAGEMENT

Management of Encore Energy Partners

Encore Energy Partners GP, our general partner, will manage our operations and activities on our behalf. Encore Energy Partners GP is indirectly wholly owned by EAC. All of the executive management personnel of our general partner are employees of EAC and will devote their time as needed to conduct our business and affairs.

The board of directors and executive officers of our general partner will make all strategic decisions on our behalf, and we will enter into an amended and restated services agreement with Encore Operating, L.P., a wholly owned subsidiary of EAC, for all of our administrative services, such as accounting, corporate development, finance, land, legal and engineering. Under the amended and restated administrative services agreement, Encore Operating, L.P. will receive 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, L.P. will have substantial discretion in determining which third-party expenses to incur on our behalf. We will also pay our share of expenses that are directly chargeable to wells under joint operating agreements. In addition, Encore Operating, L.P. will be 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 amended and restated administrative services agreement will provide that employees of Encore Operating, L.P. (including the persons who are executive officers of our general partner) will devote such portion of their time as may be reasonable and necessary for the operation of our business. The amended and restated administrative services agreement does not have any effect on our general partner’s duties to us under the partnership agreement. For more information on the duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”

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 will also not be 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 will have 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 duties. 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. Whenever possible, our general partner intends to cause us to incur indebtedness or other obligations that are nonrecourse to it. Except as described in “The Partnership Agreement — Voting Rights” and subject to its fiduciary duty to act in good faith, our general partner will have exclusive management power over our business and affairs.

Encore Energy Partners GP has a board of directors that oversees its management, operations and activities. We refer to the board of directors of Encore Energy Partners GP as the “board of directors of our general partner.” The board of directors of our general partner will have at least three members who are not officers or employees, and are otherwise independent, of EAC and its affiliates, including our general partner. These directors, to whom we refer as independent directors, must meet the independence standards established by the NYSE and SEC rules. The board of directors of our general partner has appointed J. Luther King, Jr., Clayton E. Melton and George W. Passela as independent directors.

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.

At least two independent members of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board of directors believes may involve conflicts of interest. At the request of the board of directors, the conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including EAC, and must

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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.

In addition, our general partner will have an audit committee of at least three directors who meet the independence and experience standards established by the NYSE Listed Company Manual and the Securities Exchange Act of 1934. Messrs. King, Melton and Passela will serve on the audit committee. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee.

All of the executive officers of our general partner listed below will allocate their time between managing our business and affairs and the business and affairs of EAC. The executive officers of our general partner may face a conflict regarding the allocation of their time between our business and the other business interests of EAC. The executive officers of our general partner will devote their time as needed to conduct our business and affairs although it is anticipated that the executive officers of our general partner will devote less than a majority of their time to our business for the foreseeable future. We also expect that other EAC personnel will devote their time to conduct our business and affairs, including the following:


	•	EAC has dedicated one full time engineer to the position of Manager of MLP Assets;

	•	EAC’s and our general partner’s Vice President of Mid-Continent will devote at least 50% of his time to our business and affairs;

	•	approximately 47 field personnel related to our Elk Basin assets in Wyoming will devote all of their time to our business and affairs;

	•	approximately three field personnel related to our Permian Basin assets in Crockett County, Texas will devote an estimated 15% of their time to our business and affairs;

	•	four financial reporting and tax accountants will devote substantially all of their time to our business and affairs; and

	•	several other accountants will devote their time to our business and affairs in an aggregate amount equivalent to six full-time people.

We will also have access to such other employees of EAC as may be necessary for the conduct of our business and affairs.

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Directors and Executive Officers of Our General Partner

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


			Position with Encore Energy
Name	Age		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		46	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
J. Luther King, Jr.		67	Director
Clayton E. Melton		63	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. 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 was Assistant Controller for Bristol Resources Corporation from 1998 until 1999. Prior to 1998, 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.

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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 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.

J. Luther King, Jr. has been a director of our general partner since August 2007. Mr. King is the Chief Executive Officer, Chief Financial Officer and a director of Luther King Capital Management Corporation, a registered investment advisory firm that he founded in 1979, and is President and Trustee of LKCM Funds, a registered investment company. 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

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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.

Reimbursement of Expenses of Our General Partner

Our general partner will not receive any management fee or other compensation for its management of our partnership, but it will be entitled to reimbursement of direct or indirect third-party expenses incurred on our behalf. Our general partner intends to enter into an amended and restated administrative services agreement pursuant to which Encore Operating, L.P. will provide all necessary administrative services to us. Under the agreement, we will pay Encore Operating, L.P. an administrative fee of $1.75 per BOE of our production for providing administrative services to us, and we will reimburse Encore Operating, L.P. for actual third-party expenses incurred on our behalf. Encore Operating, L.P. will have substantial discretion in determining which third-party expenses to incur on our behalf. We will also pay our share of expenses that are directly chargeable to wells under joint operating agreements. In addition, Encore Operating, L.P. will be 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 more information on the amended and restated administrative services agreement, including an explanation of COPAS overhead charges, please read “Certain Relationships and Related Party Transactions — Amended and Restated Administrative Services Agreement.”

Executive Compensation

We and our general partner were formed on February 13, 2007. As such, our general partner did not accrue any obligations with respect to executive compensation for its directors and executive officers for the fiscal year ended December 31, 2006, or for any prior periods. Accordingly, we are not presenting any compensation for historical periods. Except for the issuance of management incentive units as described below under the caption “— Management Incentive Units,” we have not paid or accrued any amounts for executive compensation for the 2007 fiscal year. In addition, we do not expect to pay any salaries or bonuses, or to make any awards under our long-term incentive plan, to the current executives of the general partner for so long as the management incentive units remain outstanding.

Under the amended and restated administrative services agreement, we will pay Encore Operating, L.P. an administrative fee of $1.75 per BOE of our production for administrative services and reimburse Encore Operating, L.P. for actual third-party expenses incurred on our behalf. Encore Operating, L.P. will have substantial discretion in determining which third-party expenses to incur on our behalf. We will also pay our share of expenses that are allocable to wells under joint operating agreements. In addition, Encore Operating, L.P. will be 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 will not reimburse the general partner or Encore Operating, L.P. for any compensation or benefits paid to the executive officers of the general partner. Furthermore, our general partner will not receive any management fee or other compensation for its management of our partnership.

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. Encore Energy Partners GP, our general partner, will manage our operations and activities, and its board of directors and officers will 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) will be set by the compensation committee of and paid for by EAC. We do not expect to pay any salaries or bonuses,

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or to make any awards under our long-term incentive plan, to the current executives of the general partner for so long as the management incentive units remain outstanding.

Awards of Management Incentive Units

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 the executive officers of the general partner. A management incentive unit is a limited partner interest in our partnership that entitles the holder to an initial quarterly distribution of $0.35 (or $1.40 on an annualized basis) and to increasing distributions upon the achievement of 10% compounding increases in our annualized distribution rate to common unitholders, subject to a 5.1% maximum limit on the aggregate distributions payable to holders of management incentive units at the time of any such distribution. These grants are intended to align the economic interests of our general partner’s executives with the interests of our unitholders. For more information on our management incentive units, please read “— Management Incentive Units.”

Awards Under Our Long-Term Incentive Plan

Our general partner intends to adopt a long-term incentive plan for employees, consultants and directors of our general partner and its affiliates, including EAC, who perform services for us. The long-term incentive plan provides for the grant of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. Our general partner does not intend to make awards under the long-term incentive with respect to the 2007 fiscal year to recipients of management incentive units. For a more detailed description of the long-term incentive plan, please read “— Long-Term Incentive Plan.”

Compensation of Directors

Officers or employees of our general partner or its affiliates who also serve as directors will not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not officers or employees of our general partner will 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 will receive an additional annual fee of $10,000. In addition, directors of our general partner who are not officers or employees of our general partner will receive an annual grant of 5,000 phantom units under the Encore Energy Partners GP LLC Long-Term Incentive Plan described below under “— Long-Term Incentive Plan.”

In addition, each non-employee director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

Long-Term Incentive Plan

Our general partner intends to adopt the Encore Energy Partners GP LLC Long-Term Incentive Plan for employees, consultants and directors of Encore Operating, L.P., our general partner and any of their affiliates who perform services for us. The long-term incentive plan will consist 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 will limit 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 will be available for delivery pursuant to other awards. The plan will be 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

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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 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 its date of adoption.

Restricted Units. A restricted unit is a common unit that vests over a six-month period of time and during that time is subject to forfeiture. The plan administrator may make grants of restricted units containing such terms as it shall determine, including the period over which restricted units will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial or other performance objectives. Restricted units will be entitled to receive quarterly distributions during the vesting period.

Phantom Units. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the plan administrator, cash equivalent to the value of a common unit. The plan administrator may make grants of phantom units under the plan containing such terms as the plan administrator shall determine, including the period over which phantom units granted will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial objectives.

Unit Options. The long-term incentive plan will permit 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 will permit 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, or DERs, as a stand-alone award or with respect to phantom unit awards or other award 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 will permit 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 will permit 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 in 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% or more of us or our general partner;

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	•	approval by our limited partners of the complete liquidation of us;

	•	the sale or other disposition of all or substantially all of our assets, other than to our general partner or its affiliates;

	•	a transaction resulting in someone other than our general partner or one of its affiliates becoming our general partner; or

	•	a transaction resulting in our general partner ceasing to be an affiliate of EAC.

A “Change in Control” is defined in EAC’s 2000 Incentive Stock Plan as the occurrence of one or more of the following events:


	•	any person or group acquires beneficial ownership of 40% 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% 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 such transaction, (1) all or substantially all of EAC’s beneficial owners immediately prior to such transaction beneficially own more than 60% 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% or more of the corporation resulting from such transaction except to the extent that such person or group beneficially owned 40% 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 were 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% 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% of such corporation is then beneficially owned by any person or group, except to the extent that such person or group owned 40% 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.

Management Incentive Units

General

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At the time of our initial public offering and assuming no exercise of the underwriters’ option to purchase additional common units, we expect that the management incentive units will represent approximately 2.28% of our outstanding units on a fully diluted basis and will be entitled to approximately 2.28% of our aggregate annual distributions (or $770,000 in the aggregate) (or 2.16% of fully diluted outstanding units and 2.16% of aggregate annual distributions if the underwriters exercise their option to purchase additional common units). 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 will not be entitled to receive, in the aggregate, common units upon conversion of the management incentive units that exceed a maximum limit of 5.1% of all our then-outstanding units; and

	•	the holders of management incentive units will not be entitled to receive, in the aggregate, distributions of our available cash in an amount that exceed a maximum limit of 5.1% of all such distributions to all unitholders at the time of any such distribution.

If the 5.1% 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 public 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 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.


	•	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% 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% debt and 50% 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% of our distributions on a rolling four quarter basis.

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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 beginning on the closing of an initial public offering of our common units and on the first and second anniversary of such closing date. The holder of a management incentive unit will 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.

Distributions

The holder of a management incentive unit will initially be entitled to an annual distribution equal to $1.40 per unit, which is equal to the annual distribution we initially intend to pay on each common unit.

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 public unitholders must increase by 10% on a compounded basis;

	•	Annualized Distribution per Management Incentive Unit: After distributions payable to our public unitholders have increased by 10% on a compounded basis, the holders of management incentive units will be entitled to increased distributions per unit of approximately 38% 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% of all distributions to our unitholders.

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Annualized Management Incentive Distributions
Distribution Summary


Common Units					Management Incentive Units
Annualized					Annualized					Aggregate
Distribution per		Percentage			Distribution per		Percentage			Annualized
Unit(1)		Increase			Unit(1)		Increase			Distributions


$	1.40		—		$	1.40		—		$	770,000
$	1.54		10.0	%	$	1.93		37.5	%	$	1,058,750
$	1.69		10.0	%	$	2.65		37.2	%	$	1,455,781
$	1.86		10.0	%	$	3.64		37.6	%	$	2,001,674
$	2.05		10.0	%	$	5.00		37.8	%	$	2,752,329
$	2.25		10.0	%	$	6.88		37.8	%	$	3,784,515
$	2.48		10.0	%	$	9.46		37.7	%	$	5,203,640
$	2.73		10.0	%	$	13.01		37.6	%	$	7,155,042


(1)		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 will initially be 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.

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 public unitholders must increase by 10% on a compounded basis;

	•	Conversion Rate per Management Incentive Unit: After distributions payable to our public unitholders have increased by 10% 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.

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Annualized Management Incentive Units
Conversion Summary


Common Units
Annualized					Management Incentive Units
Distribution per		Percentage			Conversion Rate		Percentage			Common Unit
Unit		Increase(1)			per Unit		Increase(1)			Equivalents

$	1.40		—			1.0000		—			550,000
$	1.54		10.0	%		1.2500		25.0	%		687,500
$	1.69		10.0	%		1.5625		25.0	%		859,375
$	1.86		10.0	%		1.9531		25.0	%		1,074,205
$	2.05		10.0	%		2.4414		25.0	%		1,342,770
$	2.25		10.0	%		3.0518		25.0	%		1,678,490
$	2.48		10.0	%		3.8147		25.0	%		2,098,085
$	2.73		10.0	%		4.7684		25.0	%		2,622,620


(1)		Percentages 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% 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% of all the 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.

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% 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.

For the definition of a “Change in Control” under EAC’s 2000 Incentive Stock Plan, please read “Management — Long-Term Incentive Plan — Change in Control; Termination of Service.”

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our common units that will be outstanding upon the consummation of this offering and the related transactions and held by:


	•	each person who then will beneficially own 5% or more of the then outstanding units;

	•	all of the directors of Encore Energy Partners GP;

	•	each named executive officer of Encore Energy Partners GP; and

	•	all directors and officers of Encore Energy Partners GP as a group.


								Percentage of
	Common Units		Percentage of			Management		Management			Percentage of
	to be		Common Units			Incentive		Incentive			Total Units
	Beneficially		to be			Units Beneficially		Units Beneficially			Beneficially
Name of Beneficial Owner(1)	Owned(2)		Beneficially Owned			Owned		Owned			Owned

Encore Acquisition Company(3)		14,062,247		61.0	%		—		—			59.6	%
Encore Partners LP Holdings LLC(3)		10,018,769		43.4	%		—		—			42.4	%
Encore Operating, L.P.(3)		4,043,478		17.5	%		—		—			17.1	%
I. Jon Brumley		—		—			143,000		26	%			*
Jon S. Brumley		—		—			143,000		26	%			*
Robert C. Reeves		—		—			110,000		20	%			*
L. Ben Nivens		—		—			77,000		14	%			*
John W. Arms		—		—			77,000		14	%			*
Philip D. Devlin		—		—			—		—			—
J. Luther King, Jr.		—		—			—		—			—
Clayton E. Melton		—		—			—		—			—
George W. Passela		—		—			—		—			—
All executive officers and directors as a group (9 persons)		—		—			550,000		100	%		2.3	%


*		Less than 1%.

(1)		The address for all beneficial owners in this table is 777 Main Street, Suite 1400, Fort Worth, Texas 76102.

(2)		Does not include common units that may be purchased in the directed unit program.

(3)		EAC is the ultimate parent company of Encore 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.

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The following table sets forth, as of June 1, 2007, 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		Percent of
Name of Beneficial Owner	Indirectly(1)		Class

I. Jon Brumley(2)		3,218,533		6.1	%
Jon S. Brumley		872,241		1.6	%
Robert C. Reeves		134,575			*
L. Ben Nivens		31,906			*
John W. Arms		87,203			*
Philip D. Devlin		—		—
J. Luther King, Jr.(3)		340,545			*
Clayton E. Melton		—		—
George W. Passela		—		—
All executive officers and directors as a group (9 persons)		4,685,003		8.8	%


*		Less than 1%

(1)		Includes options that are or become exercisable within 60 days of June 1, 2007 as follows: Mr. I. Jon Brumley (328,362), Mr. Jon S. Brumley (293,192), Mr. Reeves (89,253), Mr. Nivens (3,435) and Mr. Arms (39,297) and all executive officers and directors as a group (753,539) upon the exercise of stock options granted pursuant to EAC’s 2000 Incentive Stock Plan. Includes unvested restricted stock as of June 1, 2007 as follows: Mr. I. Jon Brumley (219,476), Mr. Jon S. Brumley (111,870), Mr. Reeves (31,664), Mr. Nivens (21,834) and Mr. Arms (22,884) and all directors and executive officers as a group (407,728). With respect to Mr. Jon S. Brumley, includes 447,952 shares pledged as collateral pursuant to customary brokerage arrangements.

(2)		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.


(3)		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.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, EAC will indirectly own 14,062,247 common units representing an aggregate 59.6% limited partner interest in us. In addition, our general partner will own a 2% 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 prior to and in connection with the offering, after the closing of the offering and upon liquidation of Encore Energy Partners LP. These distributions and payments were determined by and among affiliated entities.

PRIOR TO AND IN CONNECTION WITH THE OFFERING


The consideration received by EAC and its subsidiaries in connection with our formation		• 10,279,639 common units; and

		• 221,013 general partner units.

The consideration received by EAC and its subsidiaries for the contribution of the Permian Basin assets and liabilities to us		• 4,043,478 common units.


The payments received by EAC and its subsidiaries from the net proceeds of the offering		• approximately $126.9 million, including accrued interest of approximately $6.9 million, to retire all of the indebtedness outstanding under our subordinated term loan agreement.


Estimated additional general partner units to be received in exchange for an equal number of common units to enable our general partner to maintain its 2% interest		• 260,870 general partner units (or 287,870 general partner units if the underwriters exercise their option to purchase additional common units in full).

AFTER THE CLOSING OF THE OFFERING


Distributions of available cash to our general partner and its affiliates		We will generally make cash distributions 98% to our unitholders pro rata, including our general partner and its affiliates, as the holders of 14,062,247 common units, 550,000 management incentive units and 2% to our general partner. 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% of all such distributions to all unitholders at the time of any such distribution. If the 5.1% 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 public unitholders.

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		Assuming we have sufficient available cash to pay the full initial quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $674,636 on their general partner units and $20.5 million on their common units and management incentive units.

Payments to our general partner and its affiliates		Our partnership agreement requires us to reimburse our general partner for all actual direct and indirect expenses it incurs or actual payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. We do not expect to incur any additional fees or to make other payments to our general partner in connection with operating our business. Our amended and restated administrative services agreement will require 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. will have substantial discretion in determining which third-party expenses to incur on our behalf. We will also pay our share of expenses that are directly chargeable to wells under joint operating agreements. In addition, Encore Operating, L.P. will be 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. Please read “— 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. Please read “The Partnership Agreement — Withdrawal or Removal of the General Partner.”

UPON LIQUIDATION OF ENCORE ENERGY PARTNERS LP


Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements Governing the Transactions

We and other parties have entered into or will enter into the various documents and agreements that will effect the offering transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid from the proceeds of this offering.

We do not have any policies or procedures for the review, approval or ratification of any transactions required to be reported under Item 404(a) of Regulation S-K. The board of directors of our general partner may adopt such policies and procedures after the completion of this offering. For information regarding potential conflicts of interest and the resolution of such conflicts under our partnership agreement, please read “Conflicts of Interest and Fiduciary Duties.”

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Amended and Restated Administrative Services Agreement

We intend to enter into an amended and restated administrative services agreement with Encore Operating, L.P. pursuant to which Encore Operating, L.P. will perform administrative services for us, such as accounting, corporate development, finance, land, legal and engineering. Encore Operating, L.P. will provide all personnel and any facilities, goods and equipment necessary to perform these services and not otherwise provided by us. Encore Operating, L.P. will receive an administrative fee of $1.75 per BOE of our production, estimated to be approximately $2.8 million based on forecasted production for the twelve months ending September 30, 2008, for such services and reimbursement of actual third-party expenses incurred on our behalf. Encore Operating, L.P. will have substantial discretion in determining which third-party expenses to incur on our behalf. We will also pay our share of expenses that are directly chargeable to wells under joint operating agreements. In determining the amount of the administrative fee, EAC considered its historical cash expenses on a per BOE basis associated with administrative functions, together with an analysis of such expenses by other exploration and production companies that are organized as publicly traded partnerships. The $1.75 per BOE administrative fee was not intended to result in a subsidy to our partnership or a premium to EAC. This fee represents an approximation of the expenses that would have been allocable to our oil and natural gas properties had they remained in EAC.

In addition, Encore Operating, L.P. will be 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 in 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, L.P. 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; or

	•	otherwise as agreed upon by Encore Operating, L.P. and our general partner, with the approval of the conflicts committee of our general partner.

Encore Operating, L.P. will not be liable to us for its performance of, or failure to perform, services under the amended and restated 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, L.P.;

	•	at the discretion of Encore Operating, L.P. upon 90-days notice to us;

	•	upon a change in control of our general partner or Encore Operating, L.P. by EAC or upon Encore Operating, L.P.’s failure to pay an employee within 30 days of the date such employee’s payment is due, subject to certain limitations; or

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	•	upon the bankruptcy, dissolution, liquidation or winding up of Encore Operating, L.P.

For information on the management of our partnership and our use of EAC’s personnel, please read “Management” beginning on page 119.

Contribution, Conveyance and Assumption Agreement

We intend to enter into a contribution, conveyance and assumption agreement to effect, among other things, the transfer of the Permian Basin properties from Encore Operating, L.P. to us at the closing of this offering in exchange for 4,043,478 common units. Pending the receipt of certain governmental and third-party consents to the transfer of certain leases, Encore Operating, L.P. will continue to hold title to these leases and will enter into an operations and proceeds agreement with our wholly owned operating subsidiary related to these leases. Under the operations and proceeds agreement, Encore Operating, L.P. will conduct the operations related to these leases. Any net profit relating to these leases will be payable by Encore Operating, L.P. to our operating subsidiary, and any net loss relating to these leases will be payable by our operating subsidiary to Encore Operating, L.P. In connection with the issuance of the common units by us in exchange for the Permian Basin properties, the initial public offering and the exercise of the underwriters’ option to purchase additional units, our general partner will exchange such number of common units for general partner units as is necessary to enable it to maintain its 2% general partner interest. Our general partner will receive the common units to be contributed through capital contributions from EAC and its subsidiaries of units they currently own.

Under the contribution, conveyance and assumption agreement, EAC will indemnify us for one year after the closing of this offering against certain potential environmental claims, losses and expenses associated with the operation of the assets and occurring before the closing date of this offering. EAC’s maximum liability for this indemnification obligation will not exceed $10 million. EAC will 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 will have no indemnification obligations with respect to environmental matters for claims made as a result of changes in environmental laws promulgated after the closing date of this offering.

Additionally, EAC will indemnify us for losses attributable to title defects related to the Permian Basin assets for three years after the closing of this offering, indefinitely for losses attributable to 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.

Subordinated Term Loan

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including EAC) on the one hand, and us and our limited partners, on the other hand. The directors and officers of Encore Energy Partners GP LLC have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders. The board of directors or the conflicts committee of the board of directors of our general partner will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

Our general partner is responsible for identifying any such conflict of interest and our general partner may choose to resolve the conflict of interest by any one of the methods described in the following sentence. Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:


	•	approved by the conflicts committee, although our general partner is not obligated to seek such approval;

	•	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

	•	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

	•	fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

As required by our partnership agreement, the board of directors of our general partner will maintain a conflicts committee, comprised of at least two independent directors. Our general partner may, but is not required to, seek approval from the conflicts committee of a resolution of a conflict of interest with our general partner or affiliates. If our general partner seeks approval from the conflicts committee, the conflicts committee will determine if the resolution of a conflict of interest with our general partner or its affiliates is fair and reasonable to us. 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. If a matter is submitted to the conflicts committee and the conflicts committee does not approve the matter, we will not proceed with the matter unless and until the matter has been modified in such a manner that the conflicts committee determines is fair and reasonable to us. If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third or fourth bullet points above, then it will be presumed that, in making its decision, the board of directors 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. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he or she is acting in the best interests of the partnership.

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Conflicts of interest could arise in the situations described below, among others:

EAC is not limited in its ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses which, in turn, could adversely affect our results of operations and cash available for distribution to our unitholders.

Our partnership agreement does not prohibit EAC from owning assets or engaging in businesses that compete directly or indirectly with us. For example, EAC owns other oil and natural gas properties in Wyoming, Montana, Texas and other states that will not be conveyed to us. In addition, EAC may acquire, develop or dispose of 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 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.

In addition, under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to the 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. Furthermore, neither the general partner nor any of its affiliates (including EAC) will be liable to us, to any of our limited partners or to any other person for breach of any fiduciary or other duty by reason of the fact that such person pursues or acquires for itself, directs such opportunity to another person or does not communicate such opportunity or information to us; provided such person does not engage in such business or activity as a result of or using confidential or proprietary information provided by us or on our behalf to such person.

Neither our partnership agreement nor any other agreement requires EAC to pursue a business strategy that favors us or uses our assets or dictates what markets to pursue or grow. EAC’s directors have a fiduciary duty to make these decisions in the best interests of the owners of EAC, which may be contrary to our interests.

Because the officers and certain of the directors of our general partner are also officers and/or directors of EAC, such officers and directors have fiduciary duties to EAC that may cause them to pursue business strategies that disproportionately benefit EAC or which otherwise are not in our best interests.

Our general partner is allowed to take into account the interests of parties other than us, such as EAC, in resolving conflicts of interest.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.

We will not have any employees and will rely on the employees of our general partner and its affiliates.

All of the executive management personnel of our general partner will be employees of EAC and will devote a portion of their time to our business and affairs. We will also use a significant number of employees of EAC to operate our business and provide us with general and administrative services. Affiliates of our general partner and EAC will also conduct businesses and activities of their own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to EAC.

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Employees of EAC (including the persons who are executive officers of our general partner) will devote such portion of their time as may be reasonable and necessary for the operation of our business. It is anticipated that the executive officers of our general partner will devote significantly less than a majority of their time to our business for the foreseeable future.

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

Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owner, EAC. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:


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


	•	its limited call right;

	•	its rights to vote and transfer the units it owns;

	•	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, meaning it believed the decision was in the best interests of our partnership;

	•	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 and that, 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 non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons 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 the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

If you purchase any common units, you will agree to become bound by the provisions in the partnership agreement, including the provisions discussed above.

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Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:


	•	the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

	•	the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and unit appreciation rights relating to our securities;

	•	the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

	•	the negotiation, execution and performance of any contracts, conveyances or other instruments;

	•	the distribution of our cash;

	•	the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

	•	the maintenance of insurance for our benefit and the benefit of our partners;

	•	the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships;

	•	the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

	•	the indemnification of any person against liabilities and contingencies to the extent permitted by law;

	•	the making of tax, regulatory and other filings or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

	•	the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement further provides that in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interests. Please read “The Partnership Agreement — Voting Rights” for information regarding matters that require unitholder approval.

Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:


	•	the manner in which our business is operated;

	•	amount, nature and timing of asset purchases and sales;

	•	cash expenditures;

	•	the amount of borrowings;

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	•	the issuance of additional units; and

	•	the creation, reduction or increase of reserves in any quarter.

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, our operating company or its operating subsidiaries.

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 partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the conflicts committee of our general partner may make a determination on our behalf with respect to one or more of these types of situations.

Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner or its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

We intend to enter into an amended and restated administrative services agreement with Encore Operating, L.P. pursuant to which Encore Operating, L.P. will perform administrative services for us. Under the amended and restated administrative services agreement, Encore Operating, L.P. will receive 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, L.P. will have substantial discretion in determining which third-party expenses to incur on our behalf. For more information on the amended and restated administrative services agreement, please read “Certain Relationships and Related Party Transactions — Amended and Restated Administrative Services Agreement.”

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The Partnership Agreement — Limited Call Right.”

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Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s-length negotiations.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither the partnership agreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are or will be the result of arm’s-length negotiations.

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

The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner’s board of directors has fiduciary duties to manage our general partner in a manner beneficial to its owners, as well as to you. Without these modifications, the general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable the general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to our common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest.

The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:


State-law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement

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		providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

		The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.

		In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further 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 errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment 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 the knowledge that such conduct was unlawful.

		Special provisions regarding affiliated transactions. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be:

		• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

		• “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

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		If our general partner does not seek approval from the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

We must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement — Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units in and to partnership distributions, please read this section and “Our Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Duties. American Stock Transfer & Trust Company will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units, except the following that must be paid by unitholders:


	•	surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

	•	special charges for services requested by a common unitholder; and

	•	other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal. The transfer agent may resign, by notice to us or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Each transferee:


	•	represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

	•	automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement;

	•	gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering; and

	•	certifies that the transferee is an Eligible Holder.

As of the date hereof, an 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

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	•	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.

A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfers of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:


	•	with regard to distributions of available cash, please read “Our Cash Distribution Policy and Restrictions on Distributions” and “How We Make Cash Distributions”;

	•	with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties”;

	•	with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units”; and

	•	with regard to allocations of taxable income, taxable loss and other matters, please read “Material Tax Consequences.”

Organization and Duration

Our partnership was organized on February 13, 2007 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose under the partnership agreement is to engage in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law. Our general partner, however, may not cause us to engage in any business activity that the general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the acquisition, exploitation and development of oil and natural gas properties and the acquisition, ownership and operation of related assets, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Power of Attorney

Each limited partner, and each person who acquires a unit from a unitholder, by accepting the common unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to grant consents and waivers on behalf of the limited partners under, our partnership agreement.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”

Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2% general partner interest if we issue additional units after the offering. Our general partner’s 2% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Our general partner will be

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entitled to make a capital contribution in order to maintain its 2% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below.

In voting their common units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.


Issuance of additional units		No approval right. Please read “— Issuance of Additional Securities.”

Amendment of the partnership agreement		Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a majority of our outstanding units. Please read “— Amendment of the Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets		A majority of our outstanding units in certain circumstances. Please read “— Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

Dissolution of our partnership		A majority of our outstanding units. Please read “— Termination and Dissolution.”

Continuation of our business upon dissolution		A majority of our outstanding units. Please read “— Termination and Dissolution.”

Withdrawal of the general partner		Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to June 30, 2017 in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of the General Partner.”

Removal of the general partner		Not less than 662/3% of the outstanding units, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of the General Partner.”

Transfer of the general partner interest		Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person (other than an individual) in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets, to such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to June 30, 2017. Please read “— Transfer of General Partner Units.”

Transfer of ownership interests in our general partner		No approval required at any time. Please read “— Transfer of Ownership Interests in the General Partner.”

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Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right or exercise of the right, by the limited partners as a group:


	•	to remove or replace our general partner;

	•	to approve some amendments to the partnership agreement; or

	•	to take other action under the partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then our limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us and reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Our subsidiaries conduct business in Texas, Wyoming and Montana, although we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of the operating company may require compliance with legal requirements in the jurisdictions in which the operating company conducts business, including qualifying our subsidiaries to do business there.

Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. If, by virtue of our ownership in the operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of our unitholders.

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It is possible that we will fund acquisitions through the issuance of additional common units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to our common units.

If we issue additional units in the future, our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. Our general partner’s 2% interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendment of the Partnership Agreement

General. Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below under “— No Unitholder Approval,” our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments. No amendment may be made that would:


	•	have the effect of reducing the voting percentage of outstanding units required to take any action under the provisions of our partnership agreement;

	•	enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

	•	enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, our general partner and its affiliates will own approximately 61.0% of the outstanding common units.

No Unitholder Approval. Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner or assignee to reflect:


	•	a change in our name, the location of our principal place of our business, our registered agent or our registered office;

	•	the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

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	•	a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we, nor the operating company, nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

	•	a change in our fiscal year or taxable year and related changes;

	•	an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or the directors, officers, agents or trustees of our general partner from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

	•	an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities;

	•	any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

	•	an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of the partnership agreement;

	•	any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

	•	any amendment that our general partner determines to be necessary or advisable to effect the reissuance of the management incentive units;

	•	conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

	•	any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:


	•	do not adversely affect our limited partners (or any particular class of limited partners) in any material respect;

	•	are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

	•	are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

	•	are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

	•	are required to effect the intent expressed in this prospectus or the intent of the provisions of the partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval. For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of

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holders of at least 90% of the outstanding units unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.

In addition, the partnership agreement generally prohibits our general partner, without the prior approval of the holders of a majority of our outstanding units, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement, each of our units will be an identical unit of our partnership following the transaction, and the partnership securities to be issued do not exceed 20% of our outstanding partnership securities immediately prior to the transaction.

If the conditions specified in the partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide the limited partners and the general partner with the same rights and obligations as contained in the partnership agreement. The unitholders are not entitled to dissenters’ rights of appraisal under the partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:


	•	the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority of our outstanding units;

	•	there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

	•	the entry of a decree of judicial dissolution of our partnership; or

	•	the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

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Upon a dissolution under the last clause above, the holders of a majority of our outstanding units may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a majority of our outstanding units, subject to our receipt of an opinion of counsel to the effect that:


	•	the action would not result in the loss of limited liability of any limited partner; and

	•	neither our partnership, our operating company nor any of our other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “How We Make Cash Distributions — Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of the General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to June 30, 2017 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after June 30, 2017, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to our limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “— Transfer of General Partner Units.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a majority of our outstanding units may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a majority of our outstanding common units, excluding the common units held by the withdrawing general partner and its affiliates agree in writing to continue our business and to appoint a successor general partner. Please read “— Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 662/3% of our outstanding units including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of our outstanding common units, including those held by our general partner and its affiliates. The ownership of more than 331/3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, our general partner and its affiliates will own 61.0% of the outstanding common units.

Our partnership agreement also provides that if our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase its general partner interest for fair market value. This fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general

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partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Units

Except for the transfer by our general partner of all, but not less than all, of its general partner units to:


	•	an affiliate of our general partner (other than an individual); or

	•	another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity;

our general partner may not transfer all or any part of its general partner units to another person prior to June 30, 2017 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time transfer units to one or more persons without unitholder approval.

Transfer of Ownership Interests in the General Partner

At any time, Encore Partners GP Holdings LLC, as the sole member of our general partner, may sell or transfer all or part of its membership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change the management of our general partner. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the

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class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:


	•	the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

	•	the current market price as of the date three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The federal income tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Tax Consequences — Disposition of Common Units.”

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Units that are owned by Non-Eligible Holders will be voted by our general partner and our general partner will distribute the votes on those units in the same ratios as the votes of limited partners on other units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of any common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Except as described above under “— Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

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Non-Eligible Holders; Redemption

To comply with certain U.S. laws relating to the ownership of interests in oil and natural gas leases on federal lands, transferees are required to fill out a properly completed transfer application certifying, and our general partner, acting on our behalf, may at any time require each unitholder to re-certify, that the unitholder is an Eligible Holder. As used in our partnership agreement, 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.

If a transferee or a unitholder, as the case may be, fails to furnish:


	•	a transfer application containing the required certification,

	•	a re-certification containing the required certification within 30 days after request, or

	•	provides a false certification,

then, as the case may be, such transfer will be void or we will have the right, which we may assign to any of our affiliates, to acquire all but not less than all of the units held by such unitholder. Further, the units held by such unitholder will not be entitled to any allocations of income or loss, distributions or voting rights.

The purchase price will be paid in cash or delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:


	•	our general partner;

	•	any departing general partner;

	•	any person who is or was an affiliate of a general partner or any departing general partner;

	•	any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;

	•	any person who is or was serving as a director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and

	•	any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against

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and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation, and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates. The general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and financial reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent registered public accounting firm. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:


	•	a current list of the name and last known address of each partner;

	•	a copy of our tax returns;

	•	information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;

	•	copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

	•	information regarding the status of our business and financial condition; and

	•	any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts. Please read “Units Eligible for Future Sale.”

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered hereby, our general partner and its affiliates will hold an aggregate of 14,062,247 common units and affiliates of EAC will own 550,000 management incentive units that may be convertible into our common units, as described in “Management — Management Incentive Units.” The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:


	•	1% of the total number of the securities outstanding; or

	•	the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least two years, would be entitled to sell common units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our partnership agreement does not restrict our ability to issue any partnership securities at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement — Issuance of Additional Securities.”

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units or other partnership securities that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units or other partnership securities to require registration of any of these units or other partnership securities and to include them in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts. Except as described below, our general partner and its affiliates may sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.

EAC, our partnership, our general partner, our operating company and the executive officers and directors of our general partner have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read “Underwriting.”

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MATERIAL TAX CONSEQUENCES

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Baker Botts L.L.P., counsel to our general partner and us, insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based upon current provisions of the Internal Revenue Code (the “Code”), existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Encore Energy Partners LP and our operating subsidiaries.

The following discussion does not comment on all federal income tax matters affecting us or the unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, IRAs, real estate investment trusts, employee benefit plans or mutual funds. Accordingly, we urge each prospective unitholder to consult his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Baker Botts L.L.P. and are based on the accuracy of the representations made by us.

No ruling has been requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Baker Botts L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made here may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Baker Botts L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”) and (2) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (Please read “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Uniformity of Units”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.

Section 7704 of the Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, transportation and marketing of natural resources, including crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial

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business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 1% of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Baker Botts L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income can change from time to time.

Baker Botts L.L.P. is of the opinion that, based upon the Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and the operating company will be disregarded as an entity separate from us for federal income tax purposes. No ruling has been or will be sought from the IRS and the IRS has made no determination as to our classification as a partnership for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Code. Instead, we will rely on the opinion of Baker Botts L.L.P.

In rendering its opinion, Baker Botts L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Baker Botts L.L.P. has relied are:


	•	Neither we nor the operating company has elected or will elect to be treated as a corporation; and

	•	For each taxable year, more than 90% of our gross income will be income that Baker Botts L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net earnings would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Baker Botts L.L.P.’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Encore Energy Partners LP will be treated as partners of Encore Energy Partners LP for federal income tax purposes. Also:


	•	assignees who are awaiting admission as limited partners, and

	•	unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units

will be treated as partners of Encore Energy Partners LP for federal income tax purposes.

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A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their status as partners in Encore Energy Partners LP for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-through of Taxable Income. We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year or years ending with or within his taxable year. Please read “— Tax Treatment of Operations — Taxable Year and Accounting Method.”

Treatment of Distributions. Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis in his common units generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including our general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including recapture of intangible development costs and depletion and depreciation deductions, and/or substantially appreciated “inventory items,” both as defined in Section 751 of the Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions. We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the year ended December 31, 2009, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed with respect to that period. We anticipate that after the taxable year ending December 31, 2009 the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the initial quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The

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actual percentage of distributions that will constitute taxable income could be higher or lower than our estimate, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:


	•	gross income from operations exceeds the amount required to make quarterly distributions on all units at the initial distribution rate, yet we only distribute the initial quarterly distribution on all units; or

	•	we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depletion, depreciation or amortization for federal income tax purposes or that is depletable, depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units. A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the underlying producing properties, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses generally will be limited to the tax basis in his units. However, percentage depletion deductions in excess of basis are not subject to the tax basis limitation.

In addition, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, the unitholder’s deduction for his share of our losses is limited to the amount for which the unitholder is considered to be “at-risk” with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that his tax basis or at-risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at-risk or basis limitations is no longer utilizable.

In general, a unitholder will be at-risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities. Moreover, a unitholder’s at-risk amount will decrease by the amount of the unitholder’s depletion deductions and will increase to the extent of the amount by which the unitholder’s percentage depletion deductions with respect to our property exceed the unitholder’s share of the tax basis of that property.

The at-risk limitation applies on an activity-by-activity basis, and in the case of natural gas and oil properties, each property is treated as a separate activity. Thus, a taxpayer’s interest in each oil or natural gas

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property is generally required to be treated separately so that a loss from any one property would be limited to the at-risk amount for that property and not the at-risk amount for all the taxpayer’s natural gas and oil properties. It is uncertain how this rule is implemented in the case of multiple natural gas and oil properties owned by a single entity treated as a partnership for federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or natural gas properties we own in computing a unitholder’s at-risk limitation with respect to us. If a unitholder must compute his at-risk amount separately with respect to each oil or natural gas property we own, he may not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at-risk amount with respect to his units as a whole.

The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded partnerships, or a unitholder’s salary or active business income. If we dispose of all or only a part of our interest in an oil or natural gas property, unitholders will be able to offset their suspended passive activity losses from our activities against the gain, if any, on the disposition. Any previously suspended losses in excess of the amount of gain recognized will remain suspended. Notwithstanding whether a natural gas and oil property is a separate activity, passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder’s share of our net earnings may be offset by any suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:


	•	interest on indebtedness properly allocable to property held for investment;

	•	our interest expense attributed to portfolio income; and

	•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections. If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us

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as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. If we have a net loss for the entire year, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

For tax purposes, we are required to adjust the “book” basis of all assets contributed to us by our general partner and its affiliates, referred to below as “Contributed Property,” to their fair market values at the time this offering closes. We are further required to adjust this book basis for each asset in proportion to tax depletion, depreciation or amortization we or our unitholders later claim with respect to the asset. Section 704(c) principles set forth in Treasury Regulations require that subsequent allocations of depletion, depreciation, amortization, gain, loss and similar items with respect to the asset take into account, among other things, the difference between the “book” and tax basis of the asset. In this context, we use the term “book” as that term is used in Treasury Regulations relating to partnership allocations for tax purposes. The “book” value of our property for this purpose may not be the same as the book value of our property for financial reporting purposes.

For example, a substantial portion of our Contributed Property will be depletable property with a “book” basis in excess of its tax basis. Section 704(c) principles generally will require that depletion with respect to each such property be allocated disproportionately to purchasers of common units in this offering and away from our general partner and its affiliates. To the extent these disproportionate allocations do not produce a result to holders of common units similar to that which would be the case if all of our initial assets had a tax basis equal to their “book” basis on the date this offering closes, purchasers of common units in this offering will be allocated the additional tax deductions needed to produce that result as to any asset with respect to which we elect the “remedial method” of taking into account the difference between the “book” and tax basis of the asset.

In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) allocations,” similar to the Section 704(c) allocations described above, will be made to all holders of partnership interests, including purchasers of common units in this offering, to account for the difference between the “book” basis and the fair market value of all property held by us at the time of the future transaction.

In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by unitholders that did not receive the benefit of such deduction. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required under Section 704(c) principles, will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:


	•	his relative contributions to us;

	•	the interests of all the partners in profits and losses;

	•	the interest of all the partners in cash flow; and

	•	the rights of all the partners to distributions of capital upon liquidation.

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Baker Botts L.L.P. is of the opinion that, with the exception of the issues described in “— Section 754 Election,” “— Uniformity of Units” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales. 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 for those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:


	•	any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

	•	any cash distributions received by the unitholder as to those units would be fully taxable; and all of these distributions would appear to be ordinary income.

Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates. In general, the highest United States federal income tax rate for individuals is currently 35% and the maximum United States federal income tax rate for net capital gains of an individual is currently 15% if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 Election. We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

The timing of deductions attributable to Section 743(b) adjustments to our common basis will depend upon a number of factors, including the nature of the assets to which the adjustment is allocable, the extent to which the adjustment offsets any Section 704(c) type gain or loss with respect to an asset and certain elections we make as to the manner in which we apply Section 704(c) principles with respect to an asset to which the adjustment is applicable. Please read “— Allocation of Income, Gain, Loss and Deduction.” The timing of these deductions may affect the uniformity of our units. Please read “— Uniformity of Units.”

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss

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immediately after the transfer or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally either nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Taxable Year and Accounting Method. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year different from our taxable year and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

Depletion Deductions. Subject to the limitations on deductibility of taxable losses discussed above, unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our natural gas and oil interests. Although the Code requires each unitholder to compute his own depletion allowance and maintain records of his share of the tax basis of the underlying property for depletion and other-purposes, we intend to furnish each of our unitholders with information relating to this computation for federal income tax purposes.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder’s average daily production of domestic crude oil or the natural gas equivalent, does not exceed 1,000 Bbls. This depletable amount may be allocated between natural gas and oil production, with six Mcf of domestic natural gas production regarded as equivalent to one Bbl of crude oil. The 1,000-Bbl limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is indefinite.

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Unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (1) dividing the unitholder’s share of the tax basis in the underlying mineral property by the number of mineral units (Bbls of oil and Mcfs of natural gas) remaining as of the beginning of the taxable year and (2) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder’s share of the total tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our natural gas and oil interests or the disposition by the unitholder of some or all of his units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

Because depletion is required to be computed separately by each unitholder and not by our partnership and because the availability of the depletion deduction depends upon the unitholder’s own factual circumstances, no assurance can be given to a particular unitholder with respect to the availability or extent of percentage depletion deductions to such unitholder for any taxable year. We encourage each prospective unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Deductions for Intangible Drilling and Development Costs. We will elect to currently deduct intangible drilling and development costs (“IDCs”). IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies and other items that are incidental to, and necessary for, the development and preparation of wells for the production of oil, natural gas or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

Although we will elect to currently deduct IDCs, each unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount will result for alternative minimum tax purposes.

Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to natural gas and oil wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An “integrated oil company” is a taxpayer that has economic interests in crude oil deposits and also carries on substantial retailing or refining operations. An oil or natural gas producer is deemed to be a substantial retailer or refiner if it is subject to the rules disqualifying retailers and refiners from taking percentage depletion. In order to qualify as an “independent producer” that is not subject to these IDC deduction limits, a unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 Bbls of oil (or the equivalent amount of natural gas) on average for any day during the taxable year or in the retail marketing of natural gas and oil products exceeding $5 million per year in the aggregate.

IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the tax basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a unitholder of interests in us. Recapture is generally determined at the unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Deduction for U.S. Production Activities. Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred

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to as the “Section 199 deduction”, equal to a specified percentage of our qualified production activities income that is allocated to such unitholder. The percentages are 6% for qualified production activities income generated in the years 2007, 2008 and 2009; and 9% thereafter.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each unitholder will aggregate his share of the qualified production activities income allocated to him from us with the unitholder’s qualified production activities income from other sources. Each unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are taken into account only if and to the extent the unitholder’s share of losses and deductions from all of our activities is not disallowed by the tax basis rules, the at-risk rules or the passive activity loss rules. Please read “— Tax Consequences of Unit Ownership — Limitations on Deductibility of Losses.”

The amount of a unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages that are deducted in arriving at our qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders.

Because the Section 199 deduction is required to be computed separately by each unitholder and its availability is dependent upon each unitholder’s own factual circumstances, no assurance can be given to a particular unitholder as to the availability or extent of the Section 199 deduction to such unitholder. Each prospective unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.

Lease Acquisition Costs. The cost of acquiring natural gas and oil leaseholder or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read “— Tax Treatment of Operations — Depletion Deductions.”

Geophysical Costs. The cost of geophysical exploration incurred in connection with the exploration and development of oil and natural gas properties in the United States are deducted ratably over a 24-month period beginning on the date that such expense is paid or incurred.

Operating and Administrative Costs. Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses that are reasonable in amount.

Initial Tax Basis, Depletion, Depreciation and Amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of those assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to this offering will be borne by our general partner and its affiliates. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. Part or all of the goodwill, going concern value and other intangible assets we acquire in connection with this offering may not

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produce any amortization deductions because of the application of the “anti-churning” restrictions of Section 197. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may be able to amortize, and as syndication expenses, which we may not able to amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss. Gain or loss will be recognized on a sale of units equal to the difference between the unitholder’s amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, a gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as a capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at a maximum rate of 15%. However, a portion of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to assets giving rise to “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depletion, depreciation, and IDC recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

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The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method. Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:


	•	a short sale;

	•	an offsetting notional principal contract; or

	•	a futures or forward contract

with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

The use of this method may not be permitted under existing Treasury Regulations as there is no controlling authority on this issue. Accordingly, Baker Botts L.L.P. is unable to opine on the validity of this method of allocating income and deductions between unitholders. We use this method because it is not administratively feasible to make these allocations on a daily basis. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Transfer Notification Requirements. A unitholder who sells any of his units, other than through a broker, generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15

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of the year following the sale). A unitholder who acquires units generally is required to notify us in writing of that acquisition within 30 days after the purchase, unless a broker or nominee will satisfy such requirement. We are required to notify the IRS of any such transfers of units and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties.

Constructive Termination. We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year different from our taxable year, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. Please read “— Tax Treatment of Operations — Taxable Year and Accounting Method.” We would be required to make new tax elections after a termination, including a new election under Section 754 of the Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. Any non-uniformity could have a negative impact on the value of the units. The timing of deductions attributable to Section 743(b) adjustments to the common basis of our assets with respect to persons purchasing units after this offering may affect the uniformity of our units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” For example, it is possible that we own, or will acquire, certain depreciable assets that are not subject to the typical rules governing depreciation (under Section 168 of the Code) or amortization (under Section 197 of the Code) of assets. Any or all of these factors could cause the timing of a purchaser’s deductions to differ, depending on when the unit he purchased was issued.

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our units even under circumstances like those described above. These positions may include reducing for some unitholders the depletion, depreciation, amortization or loss deductions to which they would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Our counsel, Baker Botts L.L.P., is unable to opine as to validity of such filing positions. A unitholder’s basis in units is reduced by his or her share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in his or her common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of Common Units — Recognition of Gain or Loss.” The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions. We do not believe these allocations will affect any material items of our income, gain, loss or deduction.

Tax-Exempt Organizations and Non-U.S. Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, nonresident aliens, foreign corporations, and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated

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business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

Nonresident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net earnings or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine his share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Code, Treasury Regulations, or administrative interpretations of the IRS. Neither we nor Baker Botts L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The partnership agreement names our general partner, Encore Energy Partners GP LLC, a Delaware limited liability company, as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with

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the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file Form 8082 with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:


	•	the name, address and taxpayer identification number of the beneficial owner and the nominee;

	•	whether the beneficial owner is:


	•	a person that is not a United States person;

	•	a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

	•	a tax-exempt entity;


	•	the amount and description of units held, acquired or transferred for the beneficial owner; and

	•	specific information including the dates of acquisitions and transfers, means of acquisitions and transfers and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-related Penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:


	•	for which there is, or was, “substantial authority”; or

	•	as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

More stringent rules apply to “tax shelters,” but we believe we are not a tax shelter. If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the

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valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

Reportable Transactions. If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses in excess of $2 million in any single year, or $4 million in any combination of tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures” above.

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:


	•	accuracy-related penalties with a broader scope, significantly narrower exceptions and potentially greater amounts than described above in “— Accuracy-related Penalties,”

	•	for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability, and

	•	in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We initially will own property or do business in Texas, Montana and Wyoming. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions if your income from those jurisdictions falls below the filing and payment requirements, you will be required to file income tax returns and to pay income taxes in many of the jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Baker Botts L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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INVESTMENT IN ENCORE ENERGY PARTNERS LP BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA, and restrictions imposed by Section 4975 of the Code. For these purposes, the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:


	•	whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

	•	whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

	•	whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Tax Consequences — Tax-Exempt Organizations and Non-U.S. Investors.”

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified prohibited transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by employee benefit plans are publicly offered securities (i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable, and registered under some provisions of the federal securities laws); or

(b) the entity is an “operating company,” (i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries).

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) above.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

We are offering our common units described in this prospectus through the underwriters named below. UBS Securities LLC and Lehman Brothers Inc. are the representatives and joint book-running managers of the underwriters. Subject to the terms and conditions of an underwriting agreement, which has been filed as an exhibit to the registration statement, each of the underwriters has severally agreed to purchase the number of common units listed next to its name in the following table:


	Number of
Underwriters	Common Units

UBS Securities LLC
Lehman Brothers Inc.
A.G. Edwards & Sons, Inc.
Credit Suisse Securities (USA) LLC
Raymond James & Associates, Inc.
RBC Capital Markets Corporation


Total		9,000,000

The underwriting agreement provides that the underwriters must buy all of the common units if they buy any of them. However, the underwriters are not required to take or pay for the common units covered by the underwriters’ option to purchase additional common units described below.

Our common units and the common units to be sold upon the exercise of the underwriters’ option to purchase additional common units, if any, are offered subject to a number of conditions, including:


	•	receipt and acceptance of our common units by the underwriters;

	•	the validity of the representations and warranties made to the underwriters;

	•	the absence of any material change in the financial markets;

	•	our delivery of customary closing documents to the underwriters; and

	•	the underwriters’ right to reject orders in whole or in part.

We have been advised by the representatives that the underwriters intend to make a market in our common units, but that they are not obligated to do so and may discontinue making a market at any time without notice.

Option to Purchase Additional Common Units

We have granted the underwriters an option to buy up to an aggregate 1,350,000 additional common units. This option may be exercised if the underwriters sell more than 9,000,000 common units in connection with this offering. The underwriters have 30 days from the date of this prospectus to exercise this option. If the underwriters exercise this option, they will each purchase additional common units approximately in proportion to the amounts specified in the table above.

Commissions and Discounts

Common units sold by the underwriters to the public will initially be offered at the initial offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount of up to $ per common unit from the initial public offering price. Any of these securities dealers may resell any common units purchased from the underwriters to other brokers or dealers at a discount of up to $ per common unit from the initial public offering price. If all the common units are not sold at the initial public offering price, the representatives may change the offering price and the other selling terms. Sales of common units made outside of the United States may be made by affiliates of the underwriters. Upon execution of the underwriting agreement, the underwriters will be obligated to purchase

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the common units at the prices and upon the terms stated therein, and, as a result, will thereafter bear any risk associated with changing the offering price to the public or other selling terms.

The following table shows the per unit and total underwriting discounts and commissions we will pay to the underwriters assuming both no exercise and full exercise of the underwriters’ option to purchase up to an additional 1,350,000 units.


	No Exercise	Full Exercise

Per Unit
Total

We estimate that the total expenses of this offering payable by us, not including the underwriting discounts and commissions, will be approximately $3.8 million.

In addition, we will pay UBS Securities LLC and Lehman Brothers Inc. an aggregate fee equal to 0.375% of the gross proceeds of this offering, or approximately $ million, for the evaluation, analysis and structuring of our partnership.

No Sales of Similar Securities

We, our subsidiaries, our general partner and its affiliates, including the executive officers and directors of our general partner will enter into lock-up agreements with the underwriters. Under these agreements, we and each of these persons may not, without the prior written approval of the representatives, offer, sell, contract to sell or otherwise dispose of or hedge our common units or securities convertible into or exchangeable for our common units, enter into any swap or other agreement that transfers, in whole or in part, any of the economic consequences of ownership of the common units, make any demand for or exercise any right, or file or cause to be filed a registration statement with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities or publicly disclose the intention to do any of the foregoing, except with respect to issuances of (1) common units upon the exercise of options or warrants outstanding on the date of this prospectus, (2) employee unit options or phantom units to directors of our general partner not exercisable during the lock-up period pursuant to the Encore Energy Partners GP LLC Long-Term Incentive Plan, (3) common units upon the conversion of any management incentive units and (4) common units in connection with, or to finance, future acquisitions. These restrictions will be in effect for a period of 180 days after the date of this prospectus. The lock-up period will be extended under certain circumstances where we release, or pre-announce a release of our earnings or announce material news or a material event during the 17 days before or 16 days after the termination of the 180-day period in which case the restrictions described above will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or material event.

At any time and without public notice, the representatives may in their discretion, release all or some of the securities from these lock-up agreements. When determining whether or not to release common units from these restrictions, the primary factors that the representatives will consider include the requesting unitholder’s reasons for requesting the release, the number of common units for which the release is being requested and the prevailing economic and equity market conditions at the time of the request. The representatives have no present intent to release any of the securities from these lock-up agreements.

Indemnification

We and EAC have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act and liabilities incurred in connection with the directed unit program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities. If we are unable to provide this indemnification, we will contribute to payments the underwriters may be required to make in respect of those liabilities.

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Directed Unit Program

At our request, certain of the underwriters have reserved up to 900,000 common units for sale at the initial public offering price to the officers, directors and employees of our general partner and its sole member and certain other persons associated with us. We do not know if these persons will choose to purchase all or any portion of these reserved units, but any purchases they do make will reduce the number of units available to the general public. Any reserved units not so purchased will be offered by the underwriters to the general public on the same basis as the other units offered by this prospectus. These persons must commit to purchase no later than before the open of business on the day following the date of this prospectus, but in any event these persons are not obligated to purchase common units and may not commit to purchase common units prior to the effectiveness of the registration statement relating to this offering.

New York Stock Exchange

The common units have been approved for listing on the NYSE under the symbol “ENP.” In connection with that listing, the underwriters have undertaken to cause the common units to be distributed in such a manner that as of the original listing date of the common units


	•	there will be at least 400 U.S. unitholders of 100 units or more, and

	•	at least 1,100,000 publicly held common units will be outstanding in the United States, and

	•	the aggregate market value of publicly held common units in the United States will be at least $60 million.

Eligible Holders

Our partnership agreement requires that all common unitholders be Eligible Holders. As used herein, an Eligible Holder is 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.

Price Stabilization; Short Positions

In connection with this offering, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of our common units including:


	•	stabilizing transactions;

	•	short sales;

	•	purchases to cover positions created by short sales;

	•	imposition of penalty bids; and

	•	syndicate covering transactions.

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Stabilizing transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of our common units while this offering is in progress. These transactions may also include making short sales of our common units, which involves the sale by the underwriters of a greater number of common units than they are required to purchase in this offering, and purchasing common units on the open market to cover positions created by short sales. Short sales may be “covered” shorts, which are short positions in an amount not greater than the underwriters’ option to purchase additional common units referred to above, or may be “naked” shorts, which are short positions in excess of that amount.

The underwriters may close out any covered short position by either exercising their option to purchase additional common units, in whole or in part, or by purchasing common units in the open market. In making this determination, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units.

Naked short sales are in excess of the underwriters’ option to purchase additional common units. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market that could adversely affect investors who purchased in this offering.

The underwriters also may impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased common units sold by or for the account of that underwriter in stabilizing or short covering transactions.

As a result of these activities, the price of our common units may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued by the underwriters at any time. The underwriters may carry out these transactions on the NYSE, in the over-the-counter market or otherwise.

Determination of Offering Price

Prior to this offering, there has been no public market for our common units. The initial public offering price was determined by negotiation by us and the representatives of the underwriters. The principal factors considered in determining the initial public offering price include:


	•	the information set forth in this prospectus;

	•	our history and prospects, and the history and prospects of the industry in which we compete;

	•	our past and present financial performance and an assessment of the directors and officers of our general partner;

	•	our prospects for future earnings and cash flow and the present state of our development;

	•	the general condition of the securities markets at the time of this offering;

	•	the recent market prices of, and demand for, publicly traded common units of generally comparable master limited partnerships; and

	•	other information made available to the representatives, including oil and natural gas reserve data.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of units for sale to

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online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

Discretionary Sales

The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of units offered by them.

Stamp Taxes

If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

NASD Conduct Rules

Because the Financial Industry Regulatory Authority views the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules. In no event will the maximum amount of compensation to be paid to FINRA members in connection with this offering exceed ten percent. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Affiliations

The underwriters and their affiliates may from time to time in the future engage in transactions with us and perform services for us in the ordinary course of their business. In addition, some of the underwriters have engaged in, and may in the future engage in, transactions with EAC and perform services for EAC in the ordinary course of their business. In particular, an affiliate of UBS Securities LLC is a lender under EAC’s credit facility and Royal Bank of Canada, an affiliate of RBC Capital Markets Corporation, is a lender under our revolving credit facility and a lender under EAC’s credit facility and, accordingly, will receive a portion of the proceeds from this offering through our repayment of indebtedness under our revolving credit facility.

181

VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Baker Botts L.L.P., Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas.

EXPERTS

The carve out financial statements of Encore Energy Partners LP Predecessor as of December 31, 2006 and 2005, and for each of the years in the three-year period ended December 31, 2006, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The consolidated balance sheet of Encore Energy Partners LP as of February 13, 2007, appearing in this Prospectus and Registration Statement has been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The consolidated balance sheet of Encore Energy Partners GP LLC as of February 13, 2007, appearing in this Prospectus and Registration Statement has been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The combined statements of revenues and direct operating expenses of the Anadarko Elk Basin Operations for each of the years in the three-year period ended December 31, 2006, have been included herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing. These statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in note 1 and are not intended to be a complete presentation of Anadarko Elk Basin Operations’ revenues and expenses.

The information appearing in this prospectus concerning estimates of our and EAC’s oil and natural gas reserves as of December 31, 2006 was prepared by Miller and Lents, Ltd., an independent engineering firm, with respect to the partnership properties and has been included herein upon the authority of this firm as an expert.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.

We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

182

FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about:


	•	the volatility of oil and natural gas prices;

	•	discovery, estimation, development and replacement of oil and natural gas reserves;

	•	cash flow, liquidity and financial condition;

	•	business and financial strategy;

	•	amount, nature and timing of capital expenditures, including future development costs;

	•	availability and terms of capital;

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

	•	availability of development and production equipment;

	•	operating costs and other expenses;

	•	prospect development and property acquisitions;

	•	marketing of oil and natural gas;

	•	competition in the oil and natural gas industry;

	•	the impact of weather and the occurrence of natural disasters such as fires, floods, earthquakes and other catastrophic events and natural disasters;

	•	governmental regulation of the oil and natural gas industry;

	•	developments in oil-producing and natural gas-producing countries; and

	•	strategic plans, expectations and objectives for future operations.

All of these types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in the “Prospectus Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business” and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors listed in the “Risk Factors” section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

183

ENCORE ENERGY PARTNERS LP

UNAUDITED PRO FORMA FINANCIAL STATEMENTS

INTRODUCTION

Encore Energy Partners LP (the “Partnership”) was formed in February 2007 as a Delaware limited partnership to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. Currently, Encore Acquisition Company, a publicly traded Delaware corporation (“EAC”), owns all general and limited partner interests in the Partnership. The Partnership plans to pursue an initial public offering (the “Offering”) of common units representing limited partner interests. Effective upon the closing of the Offering, Encore Operating, L.P., a wholly owned subsidiary of EAC, will exchange certain oil and natural gas properties and related assets located in the Permian Basin of West Texas (the “Permian Basin Assets”), which is the predecessor to the Partnership, for additional limited partner interests in the Partnership. In addition, in March 2007, certain oil and natural gas properties and related assets in the Elk Basin of Wyoming and Montana (“Elk Basin”) were acquired from certain subsidiaries of Anadarko Petroleum Corporation (“Anadarko”), an unaffiliated company.

The accompanying unaudited pro forma financial statements of the Partnership should be read together with the audited carve out financial statements of Encore Energy Partners LP Predecessor as of December 31, 2006 and 2005 and for the three years ended December 31, 2006 and the unaudited combined historical and predecessor carve out financial statements of Encore Energy Partners LP as of and for the six months ended June 30, 2007 included elsewhere in this prospectus. The unaudited pro forma financial statements have been prepared on the basis that the Partnership will be treated as a partnership for federal income tax purposes. The accompanying unaudited pro forma financial statements of the Partnership were derived by making certain adjustments to the financial statements of Encore Energy Partners LP Predecessor and the unaudited combined historical and predecessor financial statements of Encore Energy Partners LP. The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma financial statements.

The accompanying unaudited pro forma financial statements give effect to (i) the contribution of the Permian Basin Assets to the Partnership, (ii) the acquisition of Elk Basin by the Partnership, including new borrowings and equity contribution to fund the acquisition (collectively the “Elk Basin acquisition”), (iii) the transactions contemplated in connection with the closing of this Offering and (iv) a subsequent amendment to the Partnership’s revolving credit facility. The unaudited pro forma balance sheet assumes that the contribution of the Permian Basin Assets, the Offering and related transactions and the subsequent amendment to the Partnership’s revolving credit facility occurred on June 30, 2007. The unaudited pro forma statements of operations assume that the contribution of the Permian Basin Assets, the Elk Basin acquisition, the Offering and related transactions and the subsequent amendment to the Partnership’s revolving credit facility occurred on January 1, 2006.

The Permian Basin Assets contributed to the Partnership are recorded at historical cost in a manner similar to a reorganization of entities under common control. The Elk Basin acquisition was completed on March 7, 2007 and accordingly, the actual operating results related to the acquired properties are included in the Partnership’s operating results from that date forward.

F-2

ENCORE ENERGY PARTNERS LP

UNAUDITED PRO FORMA BALANCE SHEET

June 30, 2007


				Offering
	Combined			Pro Forma and
	Historical and			Subsequent			Partnership
	Predecessor			Event			Pro Forma
	Carve Out			Adjustments			as Adjusted
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,348		$	171,970	(a)	$	1,348
					(171,970	)(b)
Accounts receivable		15,250			—			15,250
Derivatives		3,736			—			3,736
Other		102			—			102

Total current assets		20,436			—			20,436

Properties and equipment, at cost
Proved properties, including wells and related equipment		364,064			—			364,064
Accumulated depletion, depreciation, and amortization		(22,331	)		—			(22,331	)

		341,733			—			341,733

Other assets:
Intangibles		7,656			—			7,656
Derivatives		5,706			—			5,706
Debt issuance costs, net		1,509			—			1,509
Other		2,844			—			2,844

Total other assets		17,715			—			17,715

Total assets	$	379,884		$	—		$	379,884


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	7,293		$	—		$	7,293
Accrued liabilities:
Lease operations expense		1,201			—			1,201
Production, ad valorem, and severance taxes		2,740			—			2,740
Interest		564			—			564
Derivatives		282			—			282
Revolving credit facility		115,000			(115,000	)(d)		—
Other		811			—			811

Total current liabilities		127,891			(115,000	)		12,891
Long-term debt, related party		123,641			(123,641	)(b)		—
Revolving credit facility		—			115,000	(d)		66,671
					(48,329	)(b)
Deferred taxes		122			—			122
Derivatives		2,074			—			2,074
Future abandonment cost		6,863			—			6,863

Total liabilities		260,591			(171,970	)		88,621

Partners’ Equity
Owner’s net equity		119,293			(119,293	)(c)		—
General partner’s interest		—			5,825	(c)		5,825
Limited partners’ interest		—			171,970	(a)		285,438
					113,468	(c)

Total partners’ equity		119,293			171,970			291,263

Total liabilities and partners’ equity	$	379,884		$	—		$	379,884

The accompanying notes are an integral part of these unaudited pro forma financial statements.

F-3

ENCORE ENERGY PARTNERS LP

UNAUDITED PRO FORMA STATEMENT OF OPERATIONS

For the Six Months Ended June 30, 2007


	Combined			Elk Basin
	Historical and			Acquisition			Offering			Partnership
	Predecessor			Pro Forma			Pro Forma			Pro Forma
	Carve Out			Adjustments			Adjustments			as Adjusted
	(In thousands, except per unit amounts)

Revenues:
Oil	$	20,469		$	10,459		$	—		$	30,928
Natural gas		5,904			127			—			6,031
Marketing and other		4,852			3,575			—			8,427

Total revenues		31,225			14,161			—			45,386

Expenses:
Production:
Lease operations		4,951			1,965			—			6,916
Production, ad valorem, and severance taxes		3,286			1,262			—			4,548
Depletion, depreciation, and amortization		10,412			4,455	(e)		—			14,867
General and administrative		1,092			250	(f)		—			1,342
Derivative fair value loss		6,497			—			—			6,497
Marketing and other operating		4,646			3,370			—			8,060
					44	(g)


Total expenses		30,884			11,346			—			42,230

Operating income		341			2,815			—			3,156

Other income (expenses):
Interest		(6,444	)		(3,979	)(h)		8,272	(i)		(2,205	)
					(54	)(j)
Other		27			—			—			27

Total other income (expenses)		(6,417	)		(4,033	)		8,272			(2,178	)

Income (loss) before income taxes		(6,076	)		(1,218	)		8,272			978
Current income tax provision		(39	)		—			—			(39	)

Net income (loss)	$	(6,115	)	$	(1,218	)	$	8,272		$	939

General partner’s interest in net income										$	19

Limited partners’ interest in net income										$	920

Net income per limited partner unit										$	0.04
Weighted average number of limited partner units outstanding											23,062

The accompanying notes are an integral part of these unaudited pro forma financial statements.

F-4

ENCORE ENERGY PARTNERS LP

UNAUDITED PRO FORMA STATEMENT OF OPERATIONS

For the Year Ended December 31, 2006


	Encore Energy			Elk Basin
	Partners LP			Acquisition			Offering			Partnership
	Predecessor			Pro Forma			Pro Forma			Pro Forma
	Carve Out			Adjustments			Adjustments			as Adjusted
	(In thousands, except per unit amounts)

Revenues:
Oil	$	409		$	63,695		$	—		$	64,104
Natural gas		12,337			2,395			—			14,732
Marketing and other		—			3,649			—			3,649

Total revenues		12,746			69,739			—			82,485

Expenses:
Production:
Lease operations		1,673			7,435			—			9,108
Production, ad valorem, and severance taxes		1,226			7,839			—			9,065
Depletion, depreciation, and amortization		1,200			29,667	(e)		—			30,867
General and administrative		631			2,225	(f)		—			2,856
Marketing and other		246			5,598			—			6,105
					261	(g)

Total expenses		4,976			53,025			—			58,001

Operating income		7,770			16,714			—			24,484

Interest expense		—			(20,100	)(h)		16,159	(i)		(4,264	)
					(323	)(j)

Income (loss) before income taxes		7,770			(3,709	)		16,159			20,220
Deferred income tax provision		(122	)		—			—			(122	)

Net income (loss)	$	7,648		$	(3,709	)	$	16,159		$	20,098

General partner’s interest in net income										$	402

Limited partners’ interest in net income										$	19,696

Net income per limited partner unit										$	0.85
Weighted average number of limited partner units outstanding											23,062

The accompanying notes are an integral part of these unaudited pro forma financial statements.

F-5

ENCORE ENERGY PARTNERS LP

NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS

Note 1. Basis of Presentation, the Offering, and Other Transactions

The combined historical and predecessor carve out financial information is derived from the unaudited combined historical and predecessor carve out financial statements of Encore Energy Partners LP. The predecessor carve out financial information is derived from the audited historical financial statements of Encore Energy Partners LP Predecessor. The pro forma adjustments have been prepared given that certain transactions that occurred in March 2007 and others are to be effected prior to the closing of this Offering. For purposes of the pro forma balance sheet, we assumed that the transactions to be effected prior to the close of the Offering had taken place on June 30, 2007. For purposes of the pro forma statements of operations, we assumed all transactions had taken place on January 1, 2006. These transactions include:

March 2007 Transactions


	•	the borrowing by us of $120 million under a subordinated term loan agreement with a wholly owned subsidiary of EAC and $116.6 million under our revolving credit facility (including $1.6 million of debt issuance costs);

	•	a $93.7 million capital contribution by EAC to us, substantially all of which was used by us to fund a portion of the purchase price for the Elk Basin assets;

	•	the assignment of certain commodity derivative contracts to us by EAC (through its subsidiaries) covering certain future production from the Elk Basin assets; and


	•	the acquisition of the Elk Basin assets for $329.4 million (including estimated transaction costs of approximately $1.0 million);

Closing Transactions


	•	the contribution of the Permian Basin assets to us in exchange for the issuance of 4,043,478 common units;

	•	the sale by us of 9,000,000 common units to the public in this Offering;

	•	the issuance by us of additional general partner units to our general partner in exchange for common units to enable our general partner to maintain its 2% general partner interest;


	•	the entrance by us into an amended and restated administrative services agreement with Encore Operating, L.P., as described in “Certain Relationships and Related Party Transactions — Amended and Restated Administrative Services Agreement”;


	•	the completion of this Offering and the use of proceeds from this Offering as described in “Use of Proceeds”; and

Subsequent Event


	•	the August 22, 2007 amendment to our revolving credit facility, which resulted in our ability to classify balances outstanding as long-term.

Upon completion of the Offering, we expect to incur incremental general and administrative expenses as a result of being a publicly traded limited partnership, costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs, and independent director compensation. We estimate these incremental general and administrative expenses initially to total approximately $2.0 million per year. These direct, incremental general and administrative expenditures are not reflected in our historical financial statements or in our unaudited pro forma financial statements.

Upon completion of this Offering, the management incentive units granted to executive officers of our general partner will partially vest at which point we will recognize expense for the estimated fair value of the

F-6

ENCORE ENERGY PARTNERS LP

NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS — (Continued)

vested portion of the units. We will recognize additional expense over at least the following two-year period as the management incentive units continue to vest. Because this expense is a non-recurring charge resulting from the completion of this Offering, this expense is not reflected in our unaudited pro forma financial statements.

In addition, we intend to enter into an amended and restated administrative services agreement with Encore Operating, L.P. pursuant to which Encore Operating, L.P. will perform administrative services for us. Under the amended and restated administrative services agreement, Encore Operating, L.P. will receive 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, L.P. will have substantial discretion in determining which third-party expenses to incur on our behalf. We will also pay our share of expenses that are directly chargeable to wells under joint operating agreements. In addition, Encore Operating, L.P. will be 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, L.P. will not be liable to us for its performance of, or failure to perform, services under the amended and restated administrative services agreement unless its acts or omissions constitute gross negligence or willful misconduct.


Note 2.	Pro Forma Adjustments and Assumptions

a) Reflects estimated gross proceeds to the Partnership of approximately $189.0 million from the issuance and sale of 9,000,000 common units at an assumed initial public offering price of $21.00 per unit, net of the estimated underwriting discounts and a structuring fee of approximately $13.2 million in the aggregate and estimated offering expenses of approximately $3.8 million.

b) Reflects the use of net proceeds from the Offering to repay the $123.6 million subordinated term loan from EAP Operating, Inc. (including $3.6 million of in-kind interest) and $48.3 million of outstanding borrowings under the Partnership’s revolving credit facility.

c) Represents the conversion of the equity of Encore Energy Partners LP Predecessor of $119.3 million from owner’s net equity to the general partner’s interest in the Partnership and common units in the Partnership. The conversion is as follows: $5.8 million for the general partner’s interest; and $113.5 million for additional common units.

d) Represents the reclassification of outstanding borrowings under the Partnership’s revolving credit facility from current to long-term as a result of an August 22, 2007 amendment to the facility.

e) Reflects the adjustment of additional depletion, depreciation, and amortization of oil and natural gas properties associated with the Elk Basin purchase price allocation on a unit-of-production basis over the remaining life of total proved developed reserves or proved reserves, as applicable.

f) Represents incremental general and administrative expenses associated with the amended and restated administrative services agreement with Encore Operating, L.P. at $1.75 per BOE of production for the combined operations.

g) Reflects the accretion of discount on amounts allocated to future abandonment cost of Elk Basin.

h) Reflects estimated incremental interest expense associated with borrowings of $116.6 million under the Partnership’s revolving credit facility and a $120 million subordinated term loan from EAP Operating, Inc. The one-month LIBOR rate in effect on January 2, 2007 and January 3, 2006 was 5.3% and 4.4%, respectively. If the LIBOR rate increased 1/8%, we would incur an additional $60 thousand per year of interest expense, and if the rate decreased 1/8%, we would incur $60 thousand per year less.

i) Adjusts the interest expense to reflect the debt paid off with the net proceeds from the Offering.

F-7

ENCORE ENERGY PARTNERS LP

NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS — (Continued)

j) Represents the amortization of debt issuance costs over the term of the Partnership’s revolving credit facility.


Note 3.	Pro Forma Net Income Per Limited Partner Unit

Pro forma net income per limited partner unit is determined by dividing the pro forma net income available to the common unitholders, after deducting the general partner’s 2% interest in pro forma net income, by the number of common units expected to be outstanding at the closing of the Offering. For purposes of this calculation, we assumed the aggregate number of common units was 23,062,247. All units were assumed to have been outstanding since January 1, 2006. Basic and diluted pro forma net income per unit are equivalent as there will be no dilutive units at the date of the closing of the Offering of the common units of the Partnership.


Note 4.	Purchase of Elk Basin Assets

On January 16, 2007, EAC entered into a Purchase and Sale Agreement with certain subsidiaries of Anadarko to acquire certain oil and natural gas properties and related assets in the Big Horn Basin of Wyoming and Montana, which included the Elk Basin assets. On March 6, 2007, EAC assigned its interest in the Elk Basin assets to Encore Energy Partners Operating LLC, a Delaware limited liability company and wholly owned subsidiary of the Partnership (“OLLC”).

The closing of the acquisition occurred on March 7, 2007. At closing, OLLC paid the sellers approximately $328.4 million for Elk Basin.

In connection with the acquisition, EAC purchased floor contracts for 2,500 Bbl/D of production at $65.00 per Bbl for April through December of 2007 and all of 2008, which were also assigned to OLLC. Also, the Partnership purchased floor contracts for 1,000 Bbl/D at $63.00 per Bbl for 2009, swap contracts for 1,000 Bbl/D at $68.70 per Bbl for 2009, and floor contracts for 2,000 Mcf/D of production at $8.20 per Mcf for July 2007 through the end of 2009. In the second quarter of 2007, the Partnership purchased collar contracts for 2,000 Mcf/D with a floor of $7.20 per Mcf and a ceiling of $9.85 per Mcf for July 2007 through the end of 2009. As of June 30, 2007, the fair market value of the Partnership’s oil derivative contracts was a net $4.7 million asset and the fair market value of the Partnership’s natural gas derivative contracts was a net $2.4 million asset. In the third quarter of 2007, the Partnership purchased a floor contract for 500 Bbl/D of production at $65.00 per Bbl for all of 2010 and entered into a costless collar transaction whereby the Partnership purchased a floor contract for 500 Bbl/D of production at $65.00 per Bbl and sold a ceiling contract for 500 Bbl/D of production at $79.05 per Bbl for 2010.


Note 5.	Oil & Natural Gas Producing Activities

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 in this prospectus. The accuracy of any reserve estimate is a function of the quality of available data and engineering, and estimates may justify revisions. 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 depletion, depreciation, and amortization on these properties.

F-8

ENCORE ENERGY PARTNERS LP

NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS — (Continued)

Estimated pro forma net quantities of proved oil and natural gas reserves of the Partnership were as follows as of December 31, 2006:


	Encore Energy
	Partners LP		Elk Basin		Partnership
	Predecessor		Acquisition		Pro Forma

Proved reserves:
Oil (MBbl)		50		14,470		14,520
Natural gas (MMcf)		37,426		3,726		41,152
Combined (MBOE)		6,288		15,091		21,379
Proved developed reserves:
Oil (MBbl)		50		12,789		12,839
Natural gas (MMcf)		30,450		2,975		33,425
Combined (MBOE)		5,125		13,285		18,410

The changes in pro forma proved reserves were as follows for 2006:


	Encore Energy Partners
	LP Predecessor									Elk Basin Acquisition									Partnership Pro Forma
				Natural			Oil						Natural			Oil						Natural			Oil
	Oil			Gas			Equivalent			Oil			Gas			Equivalent			Oil			Gas			Equivalent
	(MBbl)			(MMcf)			(MBOE)			(MBbl)			(MMcf)			(MBOE)			(MBbl)			(MMcf)			(MBOE)

Balance, December 31, 2005		45			44,190			7,410			18,155			7,663			19,433			18,200			51,853			26,843
Extensions and discoveries		—			402			67			—			—			—			—			402			67
Revisions of estimates		12			(5,370	)		(883	)		(2,419	)		(3,575	)		(3,016	)		(2,407	)		(8,945	)		(3,899	)
Production		(7	)		(1,796	)		(306	)		(1,266	)		(362	)		(1,326	)		(1,273	)		(2,158	)		(1,632	)

Balance, December 31, 2006		50			37,426			6,288			14,470			3,726			15,091			14,520			41,152			21,379

Reserves for the Elk Basin acquisition as of December 31, 2005 as shown in the table above are derived from an unaudited footnote to the Statements of Revenues and Direct Operating Expenses of the Anadarko Elk Basin Operations. Reserves as of December 31, 2006 as shown in the table above for the Elk Basin acquisition were estimated by Miller and Lents, Ltd., our independent petroleum engineers. These amounts differ from the reserves at December 31, 2006 included in an unaudited footnote to the Statements of Revenues and Direct Operating Expenses of the Anadarko Elk Basin Operations. Proved reserves and future net revenues as of December 31, 2005 and as of December 31, 2006 were estimated in accordance with the standards of the Securities and Exchange Commission Regulation S-X, Rule 4-10 (a). Differences in the two reserves estimates are based on the following reasons. Future forecasts of production volumes and future net revenues as of December 31, 2005 were based on the prevailing direct operating expenses, field performance and market pricing conditions combined to calculate an economic life for the properties. As of December 31, 2006, the prevailing economic environment changed, including direct operating expenses, field performance and market pricing conditions, leading to a different forecast of the economic life for the properties. The combination of these changes has resulted in a reduction to reserves. The 2.2 MMBbls of oil and 3.1 Bcf of natural gas (2.7 MMBOE) by which these reserve estimates differ at December 31, 2006 has been included as a revision of quantity estimates in the above table. The decrease in reserves attributable to revisions can be attributed to (1) different expectations as to future decline rates and the resultant property lives, (2) available time to perform engineering analysis required before undeveloped reserves can meet the criteria for being considered proved, (3) availability of geographical and/or geophysical information for the properties, (4) overall

F-9

ENCORE ENERGY PARTNERS LP

NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS — (Continued)

familiarity with the properties and availability of reliable data needed to calculate expected future yield of natural gas liquids, (5) differing expectations regarding the number of years over which liquids extraction is expected to be profitable and therefore the total volume of liquids included in reserves, and (6) noticeably lower natural gas prices at December 31, 2006 than 2005.

The pro forma standardized measure of discounted estimated future net cash flows was as follows as of December 31, 2006:


	Encore Energy
	Partners LP			Elk Basin			Partnership
	Predecessor			Acquisition			Pro Forma
	(In thousands)

Net future cash inflows	$	198,577		$	720,499		$	919,076
Future production costs		(57,998	)		(266,473	)		(324,471	)
Future development costs		(10,402	)		(18,107	)		(28,509	)
Future abandonment costs, net of salvage		(476	)		(2,614	)		(3,090	)
Future income tax expense		(1,288	)		—			(1,288	)

Future net cash flows		128,413			433,305			561,718
10% annual discount		(77,741	)		(186,601	)		(264,342	)

Standardized measure of discounted estimated future net cash flows	$	50,672		$	246,704		$	297,376

The primary changes in the pro forma standardized measure of discounted estimated future net cash flows were as follows for 2006:


	Encore Energy
	Partners LP			Elk Basin			Partnership
	Predecessor			Acquisition			Pro Forma
				(In thousands)

Standardized measure, beginning of year	$	126,605		$	190,559		$	317,164
Net change in sales price and production costs		(53,815	)		194,524			140,709
Extensions, discoveries, and improved recovery		1,040			—			1,040
Revisions of quantity estimates		(9,417	)		(90,751	)		(100,168	)
Sales, net of production costs		(7,608	)		(47,530	)		(55,138	)
Development costs incurred during the year		1,036			1,610			2,646
Accretion of discount		12,661			19,056			31,717
Change in estimated future development costs		4,846			(2,758	)		2,088
Change in timing and other		(24,676	)		(18,006	)		(42,682	)

Standardized measure, end of year	$	50,672		$	246,704		$	297,376

The changes in standardized measure in the above table for the Elk Basin acquisition differ from the amounts disclosed in an unaudited footnote to the Statements of Revenues and Direct Operating Expenses of the Anadarko Elk Basin Operations due to differences in estimated proved reserves at December 31, 2006 as described above and due to the inclusion of future income taxes in the disclosures included in the Statements of Revenues and Direct Operating Expenses of the Anadarko Elk Basin Operations. As the Partnership is not subject to federal income taxes, no amount has been deducted in the pro forma calculation of standardized measure for federal income taxes.

F-10

ENCORE ENERGY PARTNERS LP

NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS — (Continued)

Note 6. Subsequent Event

On August 22, 2007, the Partnership’s revolving credit facility was amended to revise the financial covenant requiring the Partnership to maintain a ratio of consolidated EBITDA (as defined in the revolving credit facility) to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0. The amendment to the Partnership’s revolving credit facility now requires the Partnership to maintain a ratio of consolidated EBITDA (as defined in the revolving credit facility) to the sum of consolidated net interest expense plus letter of credit fees of not less than 1.5 to 1.0 commencing at the last day of the quarter ended June 30, 2007. Additionally, the amendment requires the Partnership to maintain a ratio of consolidated EBITDA (as defined in the revolving credit facility) to consolidated senior interest expense of not less than 2.5 to 1.0. As a result of this amendment, the Partnership has concluded that it is probable that it will meet its financial covenants under its revolving credit facility in subsequent periods and has reflected balances outstanding under the revolving credit facility as long-term in the accompanying Unaudited Pro Forma Balance Sheet.

F-11

ENCORE ENERGY PARTNERS LP

UNAUDITED COMBINED HISTORICAL AND PREDECESSOR CARVE OUT BALANCE SHEET

June 30, 2007

(In thousands)


ASSETS
Current assets:
Cash and cash equivalents	$	1,348
Accounts receivable		15,250
Derivatives		3,736
Other		102

Total current assets		20,436

Properties and equipment, at cost:
Proved properties, including wells and related equipment		364,064
Accumulated depletion, depreciation, and amortization		(22,331	)

		341,733

Other assets:
Intangibles		7,656
Derivatives		5,706
Debt issuance costs, net		1,509
Other		2,844

Total other assets		17,715

Total assets	$	379,884


LIABILITIES AND OWNER’S NET EQUITY
Current liabilities:
Accounts payable	$	7,293
Accrued liabilities:
Lease operations expense		1,201
Production, ad valorem, and severance taxes		2,740
Interest		564
Derivatives		282
Revolving credit facility		115,000
Other		811

Total current liabilities		127,891
Long-term debt, related party		123,641
Deferred taxes		122
Derivatives		2,074
Future abandonment cost		6,863

Total liabilities		260,591
Owner’s net equity		119,293

Total liabilities and owner’s net equity	$	379,884

The accompanying notes are an integral part of these unaudited combined historical and

predecessor carve out financial statements.

F-12

ENCORE ENERGY PARTNERS LP

UNAUDITED COMBINED HISTORICAL AND PREDECESSOR CARVE OUT

STATEMENTS OF OPERATIONS

For the Six Months Ended June 30, 2007 and 2006

(In thousands)


	Six Months Ended June 30,
	2007			2006

Revenues:
Oil	$	20,469		$	174
Natural gas		5,904			6,719
Marketing and other		4,852			—

Total revenues		31,225			6,893

Expenses:
Production:
Lease operations		4,951			793
Production, ad valorem, and severance taxes		3,286			638
Depletion, depreciation, and amortization		10,412			580
General and administrative		1,092			326
Derivative fair value loss		6,497			—
Marketing and other		4,646			122

Total expenses		30,884			2,459

Operating income		341			4,434

Other income (expenses):
Interest		(6,444	)		—
Other		27			—

Total other income (expenses)		(6,417	)		—

Income (loss) before income taxes		(6,076	)		4,434
Current income tax provision		(39	)		—

Net income (loss)	$	(6,115	)	$	4,434

The accompanying notes are an integral part of these unaudited combined historical and

predecessor carve out financial statements.

F-13

ENCORE ENERGY PARTNERS LP

UNAUDITED COMBINED HISTORICAL AND PREDECESSOR CARVE OUT

STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2007 and 2006

(In thousands)


	Six Months Ended June 30,
	2007			2006

Cash flows from operating activities:
Net income (loss)	$	(6,115	)	$	4,434
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization		10,412			580
Non-cash derivative fair value		6,682			—
Non-cash interest expense		3,749			—
Other		129			7
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		(11,966	)		1,827
Other current assets		(102	)		—
Long-term derivatives		(2,051	)		—
Other assets		(2,779	)		—
Accounts payable		4,979			—
Other current liabilities		2,265			(237	)

Net cash provided by operating activities		5,203			6,611

Cash flows from investing activities:
Development of oil and natural gas properties		(193	)		(73	)
Acquisition of oil and natural gas properties		(327,331	)		—

Net cash used in investing activities		(327,524	)		(73	)

Cash flows from financing activities:
Proceeds from debt (net of debt issuance costs)		248,883			—
Payments on debt		(15,500	)		—
Contributions		93,658			—
Distributions		(3,372	)		(6,538	)

Net cash provided by (used in) financing activities		323,669			(6,538	)

Increase in cash and cash equivalents		1,348			—
Cash and cash equivalents, beginning of period		—			—

Cash and cash equivalents, end of period	$	1,348		$	—

The accompanying notes are an integral part of these unaudited combined historical and

predecessor carve out financial statements.

F-14

ENCORE ENERGY PARTNERS LP

NOTES TO UNAUDITED COMBINED HISTORICAL AND PREDECESSOR CARVE OUT

FINANCIAL STATEMENTS


Note 1.	Formation of the Partnership and Description of Business

Encore Energy Partners LP, a Delaware limited partnership (the “Partnership”), was formed in February 2007 by Encore Acquisition Company (together with its subsidiaries, “EAC”) to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. EAC currently owns all the general and limited partner interests in the Partnership. The Partnership plans to pursue an initial public offering of its common units representing limited partner interests (the “Offering”). At the closing of the Offering, the Partnership will hold (1) oil and natural gas properties and related assets in the Big Horn Basin of Wyoming and Montana (the “Elk Basin”) that the Partnership acquired in March 2007 from certain subsidiaries of Anadarko Petroleum Corporation (“Anadarko”) (See “Note 2. Basis of Presentation”) and (2) oil and natural gas properties and related assets in the Permian Basin (the “Permian Basin Assets”) currently owned by Encore Operating, L.P., a wholly-owned subsidiary of EAC (See “Note 2. Basis of Presentation”). At the closing of the Offering, Encore Operating, L.P. will contribute the Permian Basin Assets to the Partnership in exchange for common units representing limited partner interests in the Partnership.


Note 2.	Basis of Presentation

The accompanying unaudited combined financial statements and related notes thereto include the results of operations, cash flows, and changes in owner’s net equity of the Partnership from the date of its formation on February 13, 2007 through June 30, 2007 and the financial position of the Partnership as of June 30, 2007, and the carve out results of operations, cash flows, and changes in owner’s net equity of Encore Energy Partners LP Predecessor for the six months ended June 30, 2007 and 2006 and the carve out financial position of Encore Energy Partners LP Predecessor as of June 30, 2007. The Partnership and the Permian Basin Assets were wholly owned by EAC for all periods presented. The carve out amounts included in the accompanying financial statements were calculated in accordance with Regulation S-X, Article 3 “General instructions as to financial statements” and Staff Accounting Bulletin (“SAB”) Topic 1-B “Allocations of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity.” Certain expenses incurred by EAC are only indirectly attributable to its ownership of the Permian Basin Assets as EAC owns interests in numerous other oil and natural gas properties. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to Encore Energy Partners LP Predecessor, so that the amounts included in the accompanying combined financial statements attributable to Encore Energy Partners LP Predecessor reflect substantially all the costs of doing business. The allocations and related estimates and assumptions are described more fully in the audited carve out financial statements of Encore Energy Partners LP Predecessor included elsewhere in this report.

In the opinion of management, the accompanying unaudited combined financial statements include all adjustments necessary to present fairly, in all material respects, the combined financial position as of June 30, 2007, and the combined results of operations and cash flows for the six months ended June 30, 2007 and 2006. All adjustments are of a normal recurring nature. These interim results are not necessarily indicative of results for an entire year.

Certain amounts and disclosures have been condensed and omitted from the unaudited combined financial statements pursuant to the rules and regulations of the Securities and Exchange Commission. Therefore, these unaudited combined financial statements should be read in conjunction with the audited predecessor financial statements and related notes thereto and the audited Partnership financial statements and related notes thereto.

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 financial statements and the reported amounts of revenues and expenses. Also, certain amounts in the accompanying financial statements

F-16

ENCORE ENERGY PARTNERS LP

NOTES TO UNAUDITED COMBINED HISTORICAL AND PREDECESSOR CARVE OUT
FINANCIAL STATEMENTS — (Continued)

have been allocated in a way that management believes is reasonable and consistent in order to depict the historical financial position, results of operations and cash flows of Encore Energy Partners LP as if the Predecessor were a stand alone entity. Actual results could differ materially from those estimates.

Estimates made in preparing these 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 and oil and natural gas revenues; the estimated future cash flows and fair value of properties used in determining the need for any impairment; operating costs accrued; prices for revenues accrued; and the timing and amount of future abandonment costs used in calculating asset retirement obligations (“AROs”). Future changes in the assumptions used could have a significant impact on reported results in future periods.

Allocation of Costs

The accompanying unaudited combined financial statements have been prepared in accordance with SAB Topic 1-B. These rules require allocations of costs for salaries and benefits, depreciation, rent, accounting, legal services, and other general and administrative expenses. EAC has allocated general and administrative expenses to Encore Energy Partners LP Predecessor based on the Permian Basin Assets’ share of EAC’s total production as measured on a BOE basis. In management’s estimation, the allocation methodologies used are reasonable and result in an allocation of the cost of doing business borne by EAC on behalf of Encore Energy Partners LP Predecessor; however, these allocations may not be indicative of the cost of future operations or the amount of future allocations.

Earnings per Share

During the periods presented, the Partnership and the Permian Basin Assets were wholly owned by EAC. Accordingly, earnings per share has not been calculated.

Derivatives

All derivative financial instruments are recorded at fair value. We have elected to not designate our current portfolio of derivatives as hedges and will record mark-to-market gains or losses each quarter to operating income in the Unaudited Combined Historical and Predecessor Carve Out Statements of Operations.

New Accounting Standards

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

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS 157. SFAS 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under SFAS 157, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The implementation of SFAS 157 is not expected to have a material effect on the financial condition or results of operations of the Partnership.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”)

F-17

ENCORE ENERGY PARTNERS LP

NOTES TO UNAUDITED COMBINED HISTORICAL AND PREDECESSOR CARVE OUT
FINANCIAL STATEMENTS — (Continued)

interim periods within those fiscal years. The implementation of SFAS 159 is not expected to have a material effect on the financial condition or results of operations of the Partnership.


Note 3.	Asset Retirement Obligations

The primary AROs related to the Partnership are future plugging and abandonment expenses on the properties. The liability amount shown in the accompanying combined financial statements does not include a market risk premium in the risk estimates as the effect would not be material. The following table summarizes the changes in the future abandonment liability, the long-term portion of which is recorded in “Future abandonment cost” on the Unaudited Combined Historical and Predecessor Carve Out Balance Sheet, for the six months ended June 30, 2007 (in thousands):


Future abandonment liability at January 1, 2007	$	296
Liability assumed in Elk Basin acquisition		6,783
Accretion expense		124

Future abandonment liability at June 30, 2007	$	7,203


Note 4.	Related Party Transactions

The Partnership does not have its own employees. The employees supporting the operation of the Partnership are employees of Encore Operating, L.P. Accordingly, EAC recognizes all employee-related liabilities in its consolidated financial statements. In addition to employee payroll-related expenses, EAC incurred general and administrative expenses related to leasing of office space and other corporate overhead type expenses during the period covered by these combined financial statements. For purposes of deriving the accompanying financial statements, a portion of the consolidated general and administrative expenses reported for EAC has been allocated to the Partnership and included in the accompanying Unaudited Combined Historical and Predecessor Carve Out Statements of Operations for the six months ended June 30, 2007 and 2006. The portion of EAC’s consolidated general and administrative expenses to be included in the accompanying combined financial statements related to the Predecessor for each period presented was determined based on the respective percentage of BOE produced by the Predecessor in relation to the total BOE produced by EAC on a consolidated basis.

We intend to enter into an amended and restated administrative services agreement with Encore Operating, L.P. pursuant to which Encore Operating, L.P. will perform administrative services for us. Under the amended and restated administrative services agreement, Encore Operating, L.P. will receive an administrative fee of $1.75 per BOE of our production for such services and reimbursement for actual third-party expenses incurred on our behalf. Encore Operating, L.P. will have substantial discretion in determining which third-party expenses to incur on our behalf. We will also pay our share of expenses that are directly chargeable to wells under joint operating agreements. In addition, Encore Operating, L.P. will be 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, L.P. will not be liable to the Partnership for its performance of, or failure to perform, services under the amended and restated administrative services agreement unless its acts or omissions constitute gross negligence or willful misconduct.

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 discussed in Note 7 of these combined financial statements, to purchase the Elk Basin assets. Additionally, in the first quarter of 2007, our owners made a non-cash contribution of derivative oil put contracts representing 2,500 Bbls per day at

F-18

ENCORE ENERGY PARTNERS LP

NOTES TO UNAUDITED COMBINED HISTORICAL AND PREDECESSOR CARVE OUT
FINANCIAL STATEMENTS — (Continued)

$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.

In May 2007, the board of directors of our general partner issued 550,000 management incentive units to the executive officers of our general partner. A management incentive unit is a limited partner interest in the Partnership that entitles the holder to an initial quarterly distribution of $0.35 (or $1.40 on an annualized basis) to the extent paid to our common unitholders and to increasing distributions upon the achievement of 10% compounding increases in our distribution rate to common unitholders subject to a maximum limit of 5.1% on the aggregate distributions payable to holders of management incentive units. A management incentive unit is also convertible into common units upon the occurrence of certain events subject to a maximum limit of 5.1% on the aggregate number of common units issuable to holders of management incentive units.

See “Note 7. Debt” of these combined financial statements for a description of the subordinated term loan held by a related party of the Partnership.


Note 5.	Acquisition

On January 16, 2007, EAC entered into a Purchase and Sale Agreement (the “PSA”) with certain subsidiaries of Anadarko to acquire certain oil and natural gas properties and related assets in the Big Horn Basin of Wyoming and Montana, which included Elk Basin.

The closing of the acquisition occurred on March 7, 2007. Prior to closing, EAC assigned the rights and duties under the PSA relating to Elk Basin to Encore Energy Partners Operating LLC, a Delaware limited liability company and indirect wholly-owned subsidiary of the Partnership (“OLLC”). At closing, OLLC paid the sellers approximately $328.4 million for Elk Basin.

Based on currently available information, the calculation of the total purchase price and the estimated allocation to the fair value of the Elk Basin assets acquired and liabilities assumed from Anadarko are as follows as of June 30, 2007 (in thousands):


Calculation of total purchase price:
Cash paid to Anadarko	$	328,359
Estimated transaction costs		1,007

Total purchase price	$	329,366

Allocation of purchase price to the fair value of net assets acquired:
Proved properties, including wells and related equipment	$	328,200
Intangibles		7,656
Other		2,227

Total assets acquired		338,083

Accrued liabilities		(1,934	)
Future abandonment cost		(6,783	)

Total liabilities assumed		(8,717	)

Fair value of net assets acquired	$	329,366

At June 30, 2007, the Company was awaiting final post close on the Elk Basin acquisition, which will contain certain customary purchase price adjustments.

F-19

ENCORE ENERGY PARTNERS LP

NOTES TO UNAUDITED COMBINED HISTORICAL AND PREDECESSOR CARVE OUT
FINANCIAL STATEMENTS — (Continued)

The properties and equipment amount in the purchase price allocation above includes the fair value of proved leasehold costs, lease and well equipment, including flue gas reinjection facilities used to maintain NGL extraction facilities and oil and natural gas gathering and transportation assets. Hydrocarbon 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 Unaudited Combined Historical and Predecessor Carve Out Statements of Operations. Third party revenues and expenses derived from an acquired pipeline are included in “Marketing and other revenues” and “Marketing and other costs” in the accompanying Unaudited Combined Historical and Predecessor Carve Out Statements of Operations.

The operating results related to the Elk Basin assets are included in the Partnership’s operating results from the date of closing forward.

The Partnership financed the Elk Basin acquisition through a $93.7 million contribution from EAC (through its subsidiaries) and borrowings under its credit facilities. See “Note 7. Debt” for additional discussion of the Partnership’s borrowings.

The following unaudited pro forma combined condensed financial data for the six months ended June 30, 2007 and 2006 was derived from the historical financial statements of the Partnership and from the accounting records of Anadarko for the Elk Basin assets, giving effect to the acquisition as if it had occurred on January 1, 2006. The unaudited pro forma combined 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 taken place as of the dates indicated and are not intended to be a projection of future results.


	Six Months Ended June 30,
	2007		2006
	(in thousands)

Pro forma total revenues	$	45,386	$	38,552
Pro forma net income	$	1,468	$	8,563


Note 6.	Derivatives

In connection with the acquisition, EAC purchased floor contracts for 2,500 Bbl/D of production at $65.00 per Bbl for April through December of 2007 and all of 2008, that were all later contributed to the Partnership at their fair market value on the date of transfer of $9.4 million. Additionally, in the first quarter of 2007, the Partnership purchased floor contracts for 1,000 Bbl/D at $63.00 per Bbl for 2009, swap contracts for 1,000 Bbl/D at $68.70 per Bbl for 2009, and floor contracts for 2,000 Mcf/D of production at $8.20 per Mcf for July 2007 through the end of 2009. In the second quarter of 2007, the Partnership purchased collar contracts for 2,000 Mcf/D of production with a floor of $7.20 per Mcf and a ceiling of $9.85 per Mcf for July 2007 through the end of 2009.

As a result of derivative transactions for oil and natural gas, the Partnership recognized derivative fair value losses of $6.5 million related to changes in the market value of its derivative contracts for the six months ended June 30, 2007.

In the third quarter of 2007, the Partnership purchased a floor contract for 500 Bbl/D of production at $65.00 per Bbl for all of 2010 and entered into a costless collar transaction whereby the Partnership purchased a floor contract for 500 Bbl/D of production at $65.00 per Bbl and sold a ceiling contract for 500 Bbl/D of production at $79.05 per Bbl for 2010.

F-20

ENCORE ENERGY PARTNERS LP

NOTES TO UNAUDITED COMBINED HISTORICAL AND PREDECESSOR CARVE OUT
FINANCIAL STATEMENTS — (Continued)


Note 7.	Debt

Revolving Credit Facility

In conjunction with the closing of the acquisition on March 7, 2007, OLLC entered into two credit agreements, one with EAP Operating Inc, a Delaware corporation and wholly owned subsidiary of EAC and a five-year credit agreement (the “OLLC Credit Agreement”), with Bank of America, N.A. as administrative agent and letter of credit issuer, and Banc of America Securities LLC, as sole lead arranger and sole book manager, and certain 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, provided that OLLC has the option of borrowing up to $10 million in excess of the borrowing base for a certain period of time following the closing date. The initial borrowing base is $115 million. The borrowing base is redetermined semi-annually and upon requested special redeterminations. OLLC has requested that the borrowing base be redetermined to account for the Permian Basin assets that will be transferred by Encore Operating, L.P. to OLLC at the closing of the Offering. OLLC expects that the redetermined borrowing base will be $145 million and will become effective upon the transfer of the Permian Basin assets to OLLC at the closing of the Offering.

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 this credit facility are non-recourse to EAC and its restricted subsidiaries.

Loans under the OLLC Credit Agreement are subject to varying rates of interest based on (1) the total amount outstanding under the credit agreement in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans bear interest at the base rate plus the applicable margin indicated in the following table:


	Applicable Margin for			Applicable Margin for
Ratio of Total Outstandings 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 annum equal to the British Bankers Association London Interbank Offered Rate, or the LIBOR Rate, 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 (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (2) the federal funds effective rate plus 0.5%.

As of June 30, 2007, the aggregate principal amount of loans outstanding under the new credit facility was $115 million and there were no outstanding letters of credit. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.

F-21

ENCORE ENERGY PARTNERS LP

NOTES TO UNAUDITED COMBINED HISTORICAL AND PREDECESSOR CARVE OUT
FINANCIAL STATEMENTS — (Continued)

The OLLC Credit Agreement contains covenants that include, among others:


	•	a prohibition against incurring debt, subject to permitted exceptions;

	•	a prohibition against paying dividends or making distributions, 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, change of principal business;

	•	a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75% 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 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 June 30, 2007, the Partnership was in violation of a covenant that required it to 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 2.5 to 1.0 and, accordingly, amounts outstanding under the OLLC Credit Agreement have been classified as a current liability in the accompanying Unaudited Combined Historical and Predecessor Carve Out Balance Sheet as of June 30, 2007. The Partnership requested and obtained a waiver from the bank syndicate for the June 30, 2007 violation. On August 22, 2007, the OLLC Credit Agreement was amended to revise the financial covenants as described in Note 9. The Partnership was in compliance with all other debt covenants under the OLLC Credit Agreement as of June 30, 2007.

Subordinated Term Loan

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 subordinated term loan matures on March 7, 2013. The Partnership’s obligations under the subordinated credit agreement are subordinated in right of payment to the payment in full of its obligations under the revolving credit facility and other related obligations on the terms and conditions set forth in an intercreditor agreement dated as of March 7, 2007.

F-22

ENCORE ENERGY PARTNERS LP

NOTES TO UNAUDITED COMBINED HISTORICAL AND PREDECESSOR CARVE OUT
FINANCIAL STATEMENTS — (Continued)

subordinated credit agreement are guaranteed by the Partnership and OLLC’s restricted subsidiaries. Obligations under the subordinated credit agreement are non-recourse to EAC and its restricted subsidiaries.

The subordinated term loan is subject to varying rates of interest based on whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus 5.00%, and base rate loans bear interest at the base rate plus 3.75%. OLLC has the option to defer payment of any accrued interest that is due and payable by adding the interest to the principal amount of the subordinated term loan.

The “Eurodollar rate” for any interest period (either one, two, three or six months, as selected by OLLC) is the rate per annum equal to the LIBOR Rate, as published by Reuters or another source designated by EAP Operating, Inc., for deposits in dollars for a similar interest period. The “base rate” is calculated as the higher of (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (2) the federal funds effective rate plus 0.5%.

As of June 30, 2007, the aggregate principal amount of loans outstanding under the subordinated credit agreement was $123.6 million. The subordinated term loan may be prepaid from time to time in whole or in part without penalty. However, under the terms of the revolving credit facility, OLLC is prohibited from prepaying the subordinated term loan until the closing of this Offering, at which time it can prepay all or a portion of the subordinated term loan so long as the amounts outstanding under the revolving credit facility at the time of prepayment are less than or equal to $100 million or 90% of the borrowing base, whichever is lower.

The subordinated credit agreement contains covenants that are customary for secured financings provided by lenders that are not affiliated with the borrower, including, among others:


	•	a prohibition against incurring debt, subject to permitted exceptions;

	•	a prohibition against paying dividends or making distributions, 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, change of principal business;

	•	a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75% 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 subordinated credit agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.25 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 subordinated credit agreement) of not more than 3.85 to 1.0.

At June 30, 2007, the Partnership was in violation of its covenant that requires it to maintain a ratio of consolidated EBITDA (as defined in the subordinated credit agreement) to the sum of consolidated net interest

F-23

ENCORE ENERGY PARTNERS LP

NOTES TO UNAUDITED COMBINED HISTORICAL AND PREDECESSOR CARVE OUT
FINANCIAL STATEMENTS — (Continued)

expense plus letter of credit fees of not less than 2.25 to 1.0. The Partnership obtained a waiver from EAP Operating, Inc. for the June 30, 2007 violation. The Partnership also amended the subordinated credit agreement to change the calculation of the debt covenant. Amounts outstanding under the subordinated credit agreement have continued to be classified as long-term debt in the accompanying Unaudited Combined Historical and Predecessor Carve Out Balance Sheet as of June 30, 2007. The Partnership was in compliance with all other debt covenants under the subordinated credit agreement as of June 30, 2007.


Note 8.	Equity

During the first quarter of 2007, our owners contributed cash in the amount of $93.7 million and made a non-cash contribution of derivative oil put contracts representing 2,500 Bbl/D 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 9.	Subsequent Event

On August 22, 2007, the Partnership entered into the First Amendment to the OLLC Credit Agreement, which revised the financial covenant requiring the Partnership to 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 2.5 to 1.0. The amendment to the OLLC Credit Agreement now requires the Partnership to 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 commencing at the last day of the quarter ended June 30, 2007. Additionally, the amendment requires the Partnership to 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. The Partnership is currently in compliance with the amended financial covenants calculated as of June 30, 2007.

F-24

ENCORE ENERGY PARTNERS LP PREDECESSOR

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Encore Acquisition Company:

We have audited the accompanying carve out balance sheets of Encore Energy Partners LP Predecessor as of December 31, 2006 and 2005, and the related carve out statements of operations, owner’s net equity, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of Encore Acquisition Company’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 Encore Energy Partners LP Predecessor’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 Encore Energy Partners LP Predecessor’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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 financial statements referred to above present fairly, in all material respects, the carve out financial position of Encore Energy Partners LP Predecessor at December 31, 2006 and 2005, and the carve out results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Fort Worth, Texas

May 3, 2007

F-25

ENCORE ENERGY PARTNERS LP PREDECESSOR

CARVE OUT STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2006			2005			2004
	(In thousands)

Cash flows from operating activities:
Net income	$	7,648		$	11,556		$	8,361
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, and amortization		1,200			1,286			1,394
Deferred income taxes		122			—			—
Other non-cash expense		16			10			6
Changes in operating assets and liabilities:
Accounts receivable		1,991			(1,373	)		(683	)
Accrued liabilities		(58	)		125			316

Net cash provided by operating activities		10,919			11,604			9,394

Cash flows from investing activities:
Development of oil and natural gas properties		(1,036	)		(2,180	)		(1,810	)

Net cash used in investing activities		(1,036	)		(2,180	)		(1,810	)

Cash flows from financing activities:
Distributions to owner		(9,883	)		(9,424	)		(7,584	)

Net cash used in financing activities		(9,883	)		(9,424	)		(7,584	)

Increase (decrease) in cash and cash equivalents		—			—			—
Cash and cash equivalents, beginning of period		—			—			—

Cash and cash equivalents, end of period	$	—		$	—		$	—

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

F-28

ENCORE ENERGY PARTNERS LP PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS


Note 1.	Formation of the Partnership and Description of Business

Encore Energy Partners LP, a Delaware limited partnership (the “Partnership”), was formed in February 2007 by Encore Acquisition Company (together with its subsidiaries, “EAC”) to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. EAC currently owns all the general and limited partner interests in the Partnership. The Partnership plans to pursue an initial public offering of its common units representing limited partner interests (the “Offering”). At the closing of the Offering, the Partnership will hold (1) oil and natural gas properties and related assets in the Elk Basin of Wyoming and Montana that the Partnership acquired in March 2007 from certain subsidiaries of Anadarko Petroleum Corporation and (2) oil and natural gas properties and related assets in the Permian Basin (the “Permian Basin Assets”) currently owned by Encore Operating, L.P., a wholly owned subsidiary of EAC. At the closing of the Offering, Encore Operating, L.P. will contribute the Permian Basin Assets to the Partnership in exchange for common units representing limited partner interests in the Partnership.


Note 2.	Basis of Presentation

The accompanying carve out financial statements and related notes thereto represent the carve out financial position, results of operations, cash flows, and changes in owner’s net equity of the Permian Basin Assets, referred to as Encore Energy Partners LP Predecessor. The carve out financial statements have been prepared in accordance with Regulation S-X, Article 3 “General instructions as to financial statements” and Staff Accounting Bulletin (“SAB”) Topic 1-B “Allocations of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity.” Certain expenses incurred by EAC are only indirectly attributable to its ownership of the Permian Basin Assets as EAC owns interests in numerous other oil and natural gas properties. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to Encore Energy Partners LP Predecessor, so that the accompanying carve out financial statements reflect substantially all the costs of doing business. The allocations and related estimates and assumptions are described more fully in “Note 3. Summary of Significant Accounting Policies” and “Note 6. Related Party Transactions.”


Note 3.	Summary of Significant Accounting Policies

Cash and Cash Equivalents

EAC provides cash as needed to support the operations of the Permian Basin Assets and collects cash from sales of production from the Permian Basin Assets. Consequently, the accompanying Carve Out Balance Sheets of Encore Energy Partners LP Predecessor do not include any cash balances. Cash received or paid by EAC on behalf of the Encore Energy Partners LP Predecessor is reflected as net distribution to parent on the accompanying Carve Out Statements of Owner’s Net Equity.

Properties and Equipment

Oil and Natural Gas Properties. The accompanying carve out financial statements have been prepared using the successful efforts method of accounting for oil and natural gas properties under Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (“SFAS 19”). 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.

F-30

ENCORE ENERGY PARTNERS LP PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

section of the accompanying Carve Out Statement of Cash Flows in the period in which the determination was made. If a determination cannot be made within one year of the exploratory well being drilled and no other drilling or exploration activities to evaluate the discovery are firmly planned, all previously capitalized costs associated with the exploratory well would be expensed and shown as a non-cash adjustment to net income at that time. Re-drilling or directional drilling in a previously abandoned well would be classified as development or exploratory based on whether it is in a proved or unproved reservoir for determination of capital or expense. 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 would be charged to expense.

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 depletion, depreciation, and amortization (“DD&A”) reserve.

Additionally, independent reserve engineers estimate reserves once a year on December 31. This results in a new DD&A rate that is used to calculate DD&A expense.

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 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 reasonable.

Asset Retirement Obligations

SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”) 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 property is acquired or a new well is drilled. An amount equal to and offsetting the liability is capitalized as part of the carrying amount of 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. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining lives of those wells based on reserve estimates. The accompanying financial statements do not provide for a market risk premium associated with ARO because a reliable estimate cannot be determined. Please read “Note 4. Asset Retirement Obligations” for additional information.

Owner’s Net Equity

Since Encore Energy Partners LP Predecessor was not a separate legal entity during the period covered by these carve out financial statements, none of EAC’s debt is directly attributable to its ownership of the Permian Basin Assets, and no formal intercompany financing arrangement exists related to the Permian Basin Assets. Therefore, the change in net assets in each year that is not attributable to current period earnings, is reflected as an increase or decrease to owner’s net equity for that year. Additionally, as debt cannot be

F-31

ENCORE ENERGY PARTNERS LP PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

specifically ascribed to the purchase of the Permian Basin Assets, the accompanying Carve Out Statements of Operations do not include any allocation of interest expense incurred by EAC to Encore Energy Partners LP Predecessor.

Employee Benefit Plans

Stock-Based Compensation. The Partnership does not have its own employees. However, during the periods presented a portion of the general and administrative (“G&A”) expenses and lease operating expenses allocated to Encore Energy Partners LP Predecessor was non-cash stock-based compensation recorded on the books of EAC. On January 1, 2006, EAC adopted the provisions of SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”) using the “modified prospective” method. SFAS 123R is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”) and supersedes 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 under the provisions of APB 25, which resulted in no compensation expense being recorded by EAC for stock options, since all options that were granted to EAC employees or non-employee directors had an exercise price equal to or above the common stock price on the grant date. However, expense was recorded by EAC and allocated to Encore Energy Partners LP 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 Encore Energy Partners LP Predecessor would have increased by $33 thousand and $13 thousand in 2005 and 2004, respectively.

During 2005 and 2004, if compensation expense for the stock-based awards had been determined using the provisions of SFAS 123R, Encore Energy Partners LP Predecessor’s net income would have been adjusted to the pro forma amounts indicated below:


	Year Ended December 31,
	2005		2004
	(In thousands)

As Reported:
Non-cash stock-based compensation	$	120	$	64
Net income		11,556		8,361
Pro Forma:
Non-cash stock-based compensation		167		120
Net income		11,509		8,305

401(k) Plan. EAC made contributions to the Encore Acquisition Company 401(k) Plan, which is a voluntary and contributory plan for eligible employees based on a percentage of employee contributions. The amounts allocated to Encore Energy Partners LP Predecessor totaled $30 thousand, $27 thousand, and $24 thousand in 2006, 2005, and 2004, respectively. EAC’s 401(k) plan does not currently allow employees to invest in securities of EAC. Effective February 1, 2007, EAC increased the percentage of employee contributions that will be matched.

Segment Reporting

Encore Energy Partners LP Predecessor has only one operating segment during the years presented — the development and exploitation of oil and natural gas reserves. Additionally, all of the Permian Basin Assets are located in the United States and all of the related oil and natural gas revenues are derived from customers located in the United States.

F-32

ENCORE ENERGY PARTNERS LP PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

Major Customers/Concentration of Credit Risk

In 2006, ChevronTexaco accounted for 24 percent of total sales of production. In 2005, ChevronTexaco accounted for 19 percent of total sales of production. In 2004, Houston Pipeline Company accounted for 22 percent of total sales of production.

All of Encore Energy Partners LP Predecessor’s properties are located in the State of Texas.

Income Taxes

The operations of Encore Energy Partners LP Predecessor are currently included in the federal income tax return of Encore Operating, L.P., which is a limited partnership that is not subject to federal income taxes. Following the initial public offering of the Partnership, our operations will be treated as a partnership with each partner being separately taxed on its share of our taxable income. Therefore, no provision for current or deferred federal income taxes has been provided for in the accompanying carve out financial statements. However, a Texas franchise tax reform measure was signed into law on May 18, 2006, which caused the Texas franchise tax to be applicable to numerous types of entities that previously were not subject to the tax, including Encore Energy Partners LP Predecessor. A deferred tax liability and related income tax expense was recognized in 2006 for the expected future tax effect of the Texas Margin tax.

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 in “Transportation and other” in the accompanying Carve Out Statements of Operations. 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 values for those properties are estimated and recorded as accounts receivable in the accompanying Carve Out Balance Sheets. Encore Energy Partners LP Predecessor had no gas imbalances as we do not market our own natural gas production from wells of which we are not the operator. EAC markets all the natural gas production from the wells that it operates and remits the non-operating interest owners’ share upon collection. This results in our having no producer gas imbalances at the end of any of the years presented. No revenue is recognized for production in tanks, oil marketed on behalf of joint owners in the Permian Basin Assets, or oil in pipelines that has not been delivered to the purchaser. The Encore Energy Partners LP Predecessor had no net oil inventories in pipelines at December 31, 2006 or 2005.

Shipping Costs

Shipping costs in the form of pipeline fees and trucking costs paid to third parties are incurred to transport natural gas production from certain properties to a different market location for ultimate sale. These costs are included in “Transportation and other” expense in the accompanying Carve Out Statements of Operations.

Use of Estimates

Preparing carve out 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 financial statements and the reported amounts of revenues and expenses. Also, certain amounts in the accompanying carve out

F-33

ENCORE ENERGY PARTNERS LP PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

financial statements have been allocated in a way that management believes is reasonable and consistent in order to depict the historical financial position, results of operations and cash flows of Encore Energy Partners LP Predecessor on a stand-alone basis. Actual results could differ materially from those estimates.

Estimates made in preparing these financial statements include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating DD&A expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; and the timing and amount of future abandonment costs used in calculating AROs. Future changes in the assumptions used could have a significant impact on reported results in future periods.

Allocation of Costs

The accompanying carve out financial statements have been prepared in accordance with SAB Topic 1-B. These rules require allocations of costs for salaries and benefits, depreciation, rent, accounting, and legal services, and other general and administrative expenses. EAC has allocated general and administrative expenses to Encore Energy Partners LP Predecessor based on the Permian Basin Assets’ share of EAC’s total production as measured on a BOE basis. In management’s estimation, the allocation methodologies used are reasonable and result in an allocation of the cost of doing business borne by EAC on behalf of Encore Energy Partners LP Predecessor; however, these allocations may not be indicative of the cost of future operations or the amount of future allocations.

Earnings per Share

During the periods presented, the Permian Basin Assets were wholly owned by EAC. Accordingly, earnings per share has not been presented.

New Accounting Standards

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

F-34

ENCORE ENERGY PARTNERS LP PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)


Note 4.	Asset Retirement Obligations

The primary AROs related to Encore Energy Partners LP Predecessor are future plugging and abandonment expenses on the properties. The liability amount shown in the accompanying carve out financial statements does not include a market risk premium in the risk estimates as the effect would not be material. The following table summarizes the changes in the future abandonment liability, the long-term portion of which is recorded in “Future abandonment cost” on the Carve Out Balance Sheets of Encore Energy Partners LP Predecessor for 2006 and 2005:


	Year Ended December 31,
	2006		2005
	(In thousands)

Future abandonment liability at January 1	$	276	$	192
Wells drilled		4		6
Accretion expense		14		10
Revision of estimates		2		68

Future abandonment liability at December 31	$	296	$	276


Note 5.	Financial Instruments

The following table sets forth the book value and estimated fair value of the financial instruments of Encore Energy Partners LP Predecessor as of the dates indicated:

December 31,

2006

2005

Book

Fair

Book

Fair

Value

(In thousands)

Accounts receivable

2,428

4,419

The estimated fair value of accounts receivable approximates the carrying value of such financial instruments due to the short term nature of Encore Energy Partners LP Predecessor’s accounts receivable.


Note 6.	Related Party Transactions

Encore Energy Partners LP Predecessor does not have its own employees. The employees supporting the operation of Encore Energy Partners LP Predecessor are employees of Encore Operating, L.P. Accordingly, EAC recognizes all employee-related liabilities in its consolidated financial statements. In addition to employee payroll-related expenses, EAC incurred general and administrative expenses related to leasing of office space and other corporate overhead type expenses during the period covered by these carve out financial statements. For purposes of deriving the accompanying carve out financial statements, a portion of the consolidated general and administrative and indirect lease operating overhead expenses reported for EAC has been allocated to Encore Energy Partners LP Predecessor and included in the accompanying Carve Out Statements of Operations for each of the three years presented. The portion of EAC’s consolidated general and administrative and indirect lease operating overhead expenses to be included in the accompanying carve out financial statements for each period presented was determined based on the respective percentage of BOE produced by Encore Energy Partners LP Predecessor in relation to the total BOE produced by EAC on a consolidated basis.

F-35

ENCORE ENERGY PARTNERS LP PREDECESSOR

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,
	2006			2005
	(In thousands)

Properties and equipment, at cost — successful efforts method:
Proved properties	$	36,414		$	35,433
Unproved properties		—			—
Accumulated depletion, depreciation, and amortization		(11,919	)		(10,719	)

	$	24,495		$	24,714

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


	Year Ended December 31,
	2006		2005		2004
	(In thousands)

Total acquisitions	$	—	$	—	$	—

Development:
Drilling and exploitation		1,036		2,180		1,810
Asset retirement obligations		6		74		56

Total development		1,042		2,254		1,866

Total exploration		—		—		—

Total costs incurred	$	1,042	$	2,254	$	1,866

Oil & Natural Gas Producing Activities — Unaudited

The estimates of Encore Energy Partners LP Predecessor’s proved oil and natural gas reserves, which are located entirely within the United States, were prepared in accordance with guidelines established by the SEC 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 Encore Energy Partners LP Predecessor 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,
	2006		2005		2004

Oil (per Bbl)	$	61.06	$	61.04	$	43.46
Natural gas (per Mcf)		5.48		9.44		6.19

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

F-36

ENCORE ENERGY PARTNERS LP PREDECESSOR

SUPPLEMENTARY INFORMATION — (Continued)

effect of future Texas Margin tax, which was passed into law during 2006. Consistent with the presentation on the Carve Out Statement of Operations, future federal income taxes have not been deducted from future net revenues in the calculation of the Partnership’s standardized measure, as the operations of Encore Energy Partners LP Predecessor are currently included in the federal income tax return of Encore Operating, L.P., which is a limited partnership that is not subject to federal income taxes. Following the initial public offering of the Partnership, our operations will be treated as a partnership with each partner being separately taxed on its share of our 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. 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 Encore Energy Partners LP Predecessor were as follows as of the dates indicated:


	December 31,
	2006		2005		2004

Proved reserves:
Oil (MBbl)		50		45		43
Natural gas (MMcf)		37,426		44,190		40,966
Combined (MBOE)		6,288		7,410		6,871
Proved developed reserves:
Oil (MBbl)		50		45		43
Natural gas (MMcf)		30,450		31,960		29,025
Combined (MBOE)		5,125		5,372		4,881

F-37

ENCORE ENERGY PARTNERS LP PREDECESSOR

SUPPLEMENTARY INFORMATION — (Continued)

The changes in proved reserves were as follows for 2006, 2005, and 2004:


				Natural			Oil
	Oil			Gas			Equivalent
	(MBbl)			(MMcf)			(MBOE)

Balance, December 31, 2003		46			43,875			7,359
Extensions and discoveries		—			283			47
Revisions of estimates		8			(1,118	)		(178	)
Production		(11	)		(2,074	)		(357	)

Balance, December 31, 2004		43			40,966			6,871
Extensions and discoveries		—			1,945			324
Revisions of 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 estimates		12			(5,370	)		(883	)
Production		(7	)		(1,796	)		(306	)

Balance, December 31, 2006		50			37,426			6,288

The standardized measure of discounted estimated future net cash flows was as follows as of the dates indicated:


	December 31,
	2006			2005			2004
	(In thousands)

Net future cash inflows	$	198,577		$	377,543		$	242,848
Future production costs		(57,998	)		(102,129	)		(70,590	)
Future development costs		(10,402	)		(16,284	)		(10,990	)
Future abandonment costs net of salvage		(476	)		(470	)		(270	)
Future income tax expense		(1,288	)		—			—

Future net cash flows		128,413			258,660			160,998
10% annual discount		(77,741	)		(132,055	)		(78,276	)

Standardized measure of discounted estimated future net cash flows	$	50,672		$	126,605		$	82,722

F-38

ENCORE ENERGY PARTNERS LP

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Encore Acquisition Company

We have audited the accompanying consolidated balance sheet of Encore Energy Partners LP as of February 13, 2007. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement 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 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 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 Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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 audit provides a reasonable basis for our opinion.

In our opinion, the financial statement referred to above presents fairly, in all material respects, the consolidated financial position of Encore Energy Partners LP at February 13, 2007, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Fort Worth, Texas

May 3, 2007

F-40

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED BALANCE SHEET


Note 1.	Formation of Partnership and Basis of Presentation

Encore Energy Partners LP, a Delaware partnership (the “Partnership”), was formed on February 13, 2007, to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. Encore Energy Partners GP LLC, a Delaware limited liability company (the “General Partner”), currently holds a 2% general partner interest in the Partnership, and Encore Partners LP Holdings LLC, a Delaware limited liability company (the “Limited Partner”), currently holds a 98% limited partner interest in the Partnership. Both the General Partner and the Limited Partner are wholly owned subsidiaries of Encore Acquisition Company, a publicly traded Delaware corporation (“EAC”).

On February 13, 2007, the General Partner agreed to contribute $12 to the Partnership in exchange for its 2% general partner interest and the Limited Partner agreed to contribute $588 to the Partnership in exchange for its 98% limited partner interest in the Partnership. The accompanying balance sheet reflects the financial position of the Partnership immediately subsequent to its initial capitalization on February 13, 2007.

There were no other transactions involving the Partnership as of February 13, 2007.

On May 2, 2007, the Partnership collected in cash the $12 and $588 contributions receivable from the General Partner and the Limited Partner, respectively, that existed as of February 13, 2007.


Note 2.	Principles of Consolidation

The Partnership’s consolidated balance sheet includes the accounts of wholly owned subsidiaries. All of the Partnership’s subsidiaries are wholly owned. All material intercompany balances and transactions are eliminated.


Note 3.	Subsequent Events (Unaudited)

Initial Public Offering

The Partnership intends to offer common units, representing limited partner interests to the public in an offering registered under the Securities Act of 1933, as amended. Concurrently, Encore Operating, L.P., a wholly owned subsidiary of EAC, will transfer certain oil and natural gas properties in the Permian Basin to the Partnership in exchange for common units; the Limited Partner’s existing limited partner interest in the Partnership will be converted into common units; and the Partnership will issue to the General Partner, general partner units representing its initial 2% general partner interest in the Partnership.

Purchase of Elk Basin Assets

On January 16, 2007, EAC entered into a Purchase and Sale Agreement with certain subsidiaries of Anadarko Petroleum Corporation to acquire certain oil and natural gas properties and related assets in the Big Horn Basin of Wyoming and Montana, which included certain Elk Basin assets. On March 6, 2007, EAC assigned its interest in the Elk Basin assets to Encore Energy Partners Operating LLC, a Delaware limited liability company and wholly owned subsidiary of the Partnership (“OLLC”).

The closing of the acquisition occurred on March 7, 2007. At closing, OLLC paid the sellers approximately $328.4 million for Elk Basin.

Purchase of Derivative Contracts

In connection with the Elk Basin acquisition, EAC purchased floor contracts for 2,500 Bbl/D at $65.00 per Bbl for the remainder of 2007 and all of 2008, that were all later contributed to the Partnership at their fair market value on the date of transfer of $9.4 million. OLLC purchased floor contracts for 1,000 Bbl/D at $63.00 for 2009, and swap contracts for 1,000 Bbl/D at $68.70 for 2009.

F-42

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

Revolving Credit Facility

In conjunction with the closing on March 7, 2007, OLLC entered into two credit agreements, one with EAP Operating, Inc., a Delaware corporation and wholly owned subsidiary of EAC and a five-year credit agreement (the “OLLC Credit Agreement”) with Bank of America, N.A. as administrative agent and letter of credit issuer, and Banc of America Securities LLC, as sole lead arranger and sole book manager, and certain lenders. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.

The OLLC Credit Agreement matures on March 7, 2012. 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 this credit facility are non-recourse to EAC and its restricted subsidiaries.


Ratio of Total
Outstandings to	Applicable Margin for			Applicable Margin for
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	%

As of March 7, 2007, the aggregate principal amount of loans outstanding under the new credit facility was $125 million and there were no outstanding letters of credit. Borrowings under the Partnership Credit Agreement may be repaid from time to time without penalty.

The OLLC Credit Agreement contains covenants that include, among others:


	•	a prohibition against incurring debt, subject to permitted exceptions;

	•	a prohibition against paying dividends or making distributions, purchasing or redeeming capital stock or prepaying indebtedness, subject to permitted exceptions;

F-43

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)


	•	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, change of principal business;

	•	a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75% 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 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.

Subordinated Term Loan

OLLC’s obligations under the subordinated credit agreement are secured by a second-priority security interest in the operating company’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 subordinated credit agreement are guaranteed by us and OLLC’s restricted subsidiaries. Obligations under the subordinated credit agreement are non-recourse to EAC and its restricted subsidiaries.

The subordinated term loan is subject to varying rates of interest based on whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus 5.00%, and base rate loans bear interest at the base rate plus 3.75%. OLLC has the option to defer payment of any accrued interest that is due and payable by adding the interest to the principal amount of the subordinated term loan.

F-44

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

The subordinated term loan may be prepaid from time to time in whole or in part without penalty. However, under the terms of the revolving credit facility, OLLC is prohibited from prepaying the subordinated term loan until the closing of this offering, at which time it can prepay all or a portion of the subordinated term loan so long as the amounts outstanding under the revolving credit facility at the time of prepayment are less than or equal to $100 million or 90% of the borrowing base, whichever is lower.

The subordinated credit agreement contains covenants that are customary for secured financings provided by lenders that are not affiliated with the borrower, including, among others:


	•	a prohibition against incurring debt, subject to permitted exceptions;

	•	a prohibition against paying dividends or making distributions, 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, change of principal business;

	•	a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75% 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 subordinated credit agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.25 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 subordinated credit agreement) of not more than 3.85 to 1.0.

Amended and Restated Administrative Services Agreement

We intend to enter into an amended and restated administrative services agreement with Encore Operating, L.P. pursuant to which Encore Operating, L.P. will perform administrative services for us. Under the amended and restated administrative services agreement, Encore Operating, L.P. will receive an administrative fee of $1.75 per BOE of our production for such services and reimbursement for actual third party expenses incurred on our behalf. Encore Operating, L.P. will have substantial discretion in determining which third-party expenses to incur on our behalf. We will also pay our share of expenses that are directly chargeable to wells under joint operating agreements. In addition, Encore Operating, L.P. will be 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, L.P. will not be liable to the Partnership for its performance of, or failure to perform, services under the amended and restated administrative services agreement unless its acts or omissions constitute gross negligence or willful misconduct.

F-45

ENCORE ENERGY PARTNERS GP LLC

UNAUDITED CONSOLIDATED BALANCE SHEET
June 30, 2007
(in thousands)


ASSETS
Current assets:
Cash and cash equivalents	$	1,348
Accounts receivable		12,610
Derivatives		3,736
Other		102

Total current assets		17,796

Properties and equipment, at cost:
Proved properties, including wells and related equipment		327,492
Accumulated depletion, depreciation, and amortization		(9,901	)

		317,591

Other assets:
Intangibles		7,656
Derivatives		5,706
Debt issuance costs, net		1,509
Other		2,844

Total current assets		17,715

Total assets	$	353,102


LIABILITIES AND OWNER’S NET EQUITY
Current liabilities:
Accounts payable	$	7,293
Accrued liabilities:
Lease operations expense		1,122
Production, ad valorem, and severance taxes		2,433
Interest		564
Derivatives		282
Revolving credit facility		115,000
Other		761

Total current liabilities		127,455
Long-term debt, related party		123,641
Derivatives		2,074
Future abandonment cost		6,569

Total liabilities		259,739

Commitments and contingencies
Owner’s net equity:
Non-controlling owner’s equity		91,496
Owner’s equity		1,867

Total owner’s net equity		93,363

Total liabilities and owner’s net equity	$	353,102

The accompanying notes are an integral part of this unaudited consolidated balance sheet.

F-46

ENCORE ENERGY PARTNERS GP LLC

NOTES TO UNAUDITED CONSOLIDATED BALANCE SHEET


Note 1.	Formation of Company and Basis of Presentation

Encore Energy Partners GP LLC, a Delaware limited liability company (the “General Partner”), was formed on February 13, 2007, to own a 2% general partner interest in Encore Energy Partners LP, a Delaware limited partnership (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”).

On February 13, 2007, GP Holdings agreed to contribute $512 to the General Partner. Subsequently on February 13, 2007, the General Partner agreed to contribute $12 to the Partnership in exchange for its 2% general partner interest in the Partnership which owns 100% of Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly-owned subsidiary of the Partnership. The Partnership was formed on February 13, 2007 to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. 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, therefore, the consolidated balance sheets include all assets and liabilities of the Partnership and its subsidiaries.

The General Partner’s unaudited consolidated balance sheet includes the accounts of the Partnership, its only wholly owned subsidiary. The General Partner does not own an interest in any other companies. All material intercompany balances and transactions are eliminated.

In the opinion of management, the accompanying unaudited consolidated balanced sheet as of June 30, 2007 includes all normal and recurring adjustments necessary to present fairly the General Partner’s financial position as of June 30, 2007.

Certain amounts and disclosures have been condensed and omitted from the unaudited consolidated financial statements pursuant to the rules and regulations of the Securities and Exchange Commission. Therefore, these unaudited consolidated financial statements should be read in conjunction with the audited predecessor financial statements and related notes thereto and the audited General Partner financial statements and related notes thereto.

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 financial statements. Also, certain amounts in the accompanying financial statements have been allocated in a way that management believes is reasonable and consistent in order to depict the historical financial position. Actual results could differ materially from those estimates.

Estimates made in preparing these financial statements include, among other things, 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.

New Accounting Standards

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

F-47

ENCORE ENERGY PARTNERS GP LLC

NOTES TO UNAUDITED CONSOLIDATED BALANCE SHEET — (Continued)

within the fair value hierarchy. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The implementation of SFAS 157 is not expected to have a material effect on the financial condition or results of operations of the General Partner.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”)

In February 2007, the FASB issued SFAS 159. SFAS 159 permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The implementation of SFAS 159 is not expected to have a material effect on the financial condition or results of operations of the General Partner.


Note 2.	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 oil and natural gas properties and related assets in or near the Elk Basin field in Park County, Wyoming and Carbon County, Montana and oil and natural gas properties. The closing of the Big Horn Basin acquisition occurred on March 7, 2007. Prior to closing, EAC assigned the rights and duties under the purchase and sale agreement relating to the Elk Basin assets to OLLC, a Delaware limited liability company and indirect wholly-owned non-guarantor subsidiary of EAC. At closing, OLLC paid the sellers approximately $328.4 million for the Elk Basin assets.

The total purchase price for the Elk Basin assets was approximately $329.4 million, including estimated transaction costs of approximately $1.0 million. Based on currently available information, the calculation of the total purchase price and the estimated allocation to the fair value of the Elk Basin assets acquired and liabilities assumed from Anadarko are as follows as of June 30, 2007 (in thousands):


Calculation of total purchase price:
Cash paid to Anadarko	$	328,359
Estimated transaction costs		1,007

Total purchase price	$	329,366

Allocation of purchase price to the fair value of net assets acquired:
Proved properties, including wells and related equipment	$	328,200
Intangibles		7,656
Other		2,227

Total assets acquired		338,083

Current liabilities		(1,934	)
Future abandonment cost		(6,783	)

Total liabilities assumed		(8,717	)

Fair value of net assets acquired	$	329,366

At June 30, 2007, OLLC was awaiting final post close on the Elk Basin acquisition, which will contain certain customary purchase price adjustments. The properties and equipment amount in the Elk Basin 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 natural gas produced), and an oil pipeline and natural gas pipeline used primarily to transport production from the acquired fields.

F-48

ENCORE ENERGY PARTNERS GP LLC

NOTES TO UNAUDITED CONSOLIDATED BALANCE SHEET — (Continued)

OLLC financed the Elk Basin acquisition through borrowings under its revolving credit facility and its subordinated term loan. See “Note 5. Debt” for additional discussion of OLLC’s debt.


Note 3.	Derivative Financial Instruments

The following tables summarize OLLC’s open commodity derivative contracts as of June 30, 2007;

Oil Derivative Contracts


	Daily		Average		Daily		Average		Daily		Average
Period	Floor Volume		Floor Price		Ceiling Volume		Ceiling Price		Swap Volume		Swap Price
	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)

July 2007 - Dec 2008		2,500	$	65.00		—	$	—		—	$	—
Jan 2009 - Dec 2009		1,000		63.00		—		—		1,000		68.70

Natural Gas Derivative Contracts

Daily

Average

Daily

Average

Daily

Average

Period

Floor Volume

Floor Price

Ceiling Volume

Ceiling Price

Swap Volume

Swap Price

(Mcf)

(per Mcf)

(Mcf)

(per Mcf)

(Mcf)

(per Mcf)

July 2007 - Dec 2009

4,000

7.70

2,000

9.85

—


Note 4.	Asset Retirement Obligations

The Partnership’s primary asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The Partnership does not include a market risk premium in its risk estimates because a reliable estimate cannot be determined. The following table summarizes the changes in the future abandonment liability, the long-term portion of which is recorded in “Future abandonment cost” on the accompanying Unaudited Consolidated Balance Sheet, for the six months ended June 30, 2007 (in thousands):


Future abandonment liability at January 1, 2007	$	—
Acquisition of properties		6,783
Accretion of discount		117

Future abandonment liability at June 30, 2007	$	6,900


Note 5.	Debt

OLLC Credit Agreement

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.

F-49

ENCORE ENERGY PARTNERS GP LLC

NOTES TO UNAUDITED CONSOLIDATED BALANCE SHEET — (Continued)

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 Encore and its restricted subsidiaries.


	Applicable Margin for			Applicable Margin for
Ratio of Total Outstandings 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	%

As of June 30, 2007, the aggregate principal amount of loans outstanding under the OLLC Credit Agreement was $115 million and there were no outstanding letters of credit. Any outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.

The OLLC Credit Agreement contains covenants that include, among others:


	•	a prohibition against incurring debt, subject to permitted exceptions;

	•	a prohibition against paying dividends or making distributions prior to the IPO Effective Date (as defined in the OLLC Credit Agreement), 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 2.5 to 1.0; and

F-50

ENCORE ENERGY PARTNERS GP LLC

NOTES TO UNAUDITED CONSOLIDATED BALANCE SHEET — (Continued)


	•	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 credit fees 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 June 30, 2007, the Partnership was in violation of a covenant that required it to 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 2.5 to 1.0 and, accordingly, amounts outstanding under the OLLC Credit Agreement have been classified as a current liability in the accompanying Unaudited Consolidated Balance Sheet as of June 30, 2007. The Partnership requested and obtained a waiver from the bank syndicate for the June 30, 2007 violation. On August 22, 2007, the OLLC Credit Agreement was amended to revise the financial covenants as described in Note 7. The Partnership was in compliance with all other debt covenants under the OLLC Credit Agreement as of June 30, 2007.

Description of Subordinated Loan

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 operating company in the aggregate amount of $120 million.

The subordinated term loan matures on March 7, 2013. The operating company’s obligations under the subordinated credit agreement are subordinated in right of payment to the payment in full of its obligations under the revolving credit facility, and other related obligations on the terms and conditions set forth in an intercreditor agreement dated as of March 7, 2007.

The operating company’s obligations under the subordinated credit agreement are secured by a second-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, and all assets of the operating company and its restricted subsidiaries related thereto. In addition, the operating company’s obligations under the subordinated credit agreement are guaranteed by its direct parent, us, and the operating company’s restricted subsidiaries. Obligations under the subordinated credit agreement are non-recourse to EAC and its restricted subsidiaries.

The subordinated credit agreement contains representations and warranties, covenants and events of default that are customary for secured financings provided by lenders that are not affiliated with the borrower. EAP Operating, Inc.’s rights to accelerate amounts due under the subordinated credit agreement and institute enforcement actions with respect to the collateral upon the occurrence and during the continuance of an event of default are governed by the terms of the intercreditor agreement, which provides for, among other things, a standstill period of 180 days. At June 30, 2007, the Partnership was in violation of its covenant that requires it to maintain a ratio of consolidated EBITDA (as defined in the subordinated credit agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.25 to 1.0. The Partnership obtained a waiver from EAP Operating, Inc. for the June 30, 2007 violation. The Partnership also amended the subordinated credit agreement to change the calculation of the debt covenant. Amounts outstanding under the subordinated credit agreement have continued to be classified as long-term debt in the accompanying Unaudited Consolidated Balance Sheet as of June 30, 2007. The Partnership was in compliance with all other debt covenants under the subordinated credit agreement as of June 30, 2007.

F-51

ENCORE ENERGY PARTNERS GP LLC

NOTES TO UNAUDITED CONSOLIDATED BALANCE SHEET — (Continued)

Contractual Obligations

In addition to the revolving credit facility and subordinated loan described above, we intend to enter into an administrative services agreement with Encore Operating, L.P. pursuant to which Encore Operating, L.P. will operate our assets and performs other administrative services for us such as accounting, corporate development, finance, land, legal and engineering. Under the administrative services agreement, Encore Operating, L.P. will receive an administrative fee of $1.75 per BOE of our production for such services and reimbursement for actual third party expenses incurred on our behalf.


Note 6.	Commitments and Contingencies

Litigation

OLLC is a party to ongoing legal proceedings in the ordinary course of business. Management does not believe the result of these proceedings will have a material adverse effect on the Company.


Note 7.	Subsequent Events

Subsequent to June 30, 2007, OLLC entered into a costless collar with a $65.00 per Bbl floor and a $79.05 per Bbl ceiling for 500 Bbls/D in 2010 and a floor with a $65.00 per Bbl strike price for 500 Bbls/D in 2010. OLLC paid a premium of $1.0 million in connection with the floor contract.

F-52

ENCORE ENERGY PARTNERS GP LLC

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Encore Acquisition Company

We have audited the accompanying balance sheet of Encore Energy Partners GP LLC as of February 13, 2007. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement 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 financial statements are 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 also 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 audit provides a reasonable basis for our opinion.

In our opinion, the financial statement referred to above presents fairly, in all material respects, the financial position of Encore Energy Partners GP LLC at February 13, 2007, in conformity with U.S. generally accepted accounting principles.


		/s/ Ernst & Young LLP

Fort Worth, Texas

May 3, 2007

F-53

ENCORE ENERGY PARTNERS GP LLC

NOTES TO THE CONSOLIDATED BALANCE SHEET


Note 1.	Formation of Company and Basis of Presentation

Encore Energy Partners GP LLC, a Delaware limited liability company (the “General Partner”), was formed on February 13, 2007, to own a 2% general partner interest in Encore Energy Partners LP, a Delaware limited partnership (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.

On February 13, 2007, GP Holdings agreed to contribute $512 to the General Partner. Subsequently on February 13, 2007, the General Partner agreed to contribute $12 to the Partnership in exchange for its 2% general partner interest in the Partnership, which will acquire, exploit, and develop oil and natural gas properties and acquire, own, and operate related assets. The General Partner does not have any business other than holding its 2% general partner interest in the Partnership.

There were no other transactions involving the General Partner through February 13, 2007.

On May 2, 2007, the General Partner collected in cash the $512 contributions receivable from GP Holdings.


Note 2.	Principles of Consolidation

The General Partner’s consolidated balance sheet includes the accounts of the Partnership, its only wholly owned subsidiary. The General Partner does not own an interest in any other companies. All material intercompany balances and transactions are eliminated.

F-55

Independent Auditors’ Report

The Board of Directors
Anadarko Petroleum Corporation:

We have audited the accompanying combined statements of revenues and direct operating expenses of the Anadarko Elk Basin Operations (Elk Basin Operations), acquired on March 7, 2007 by a subsidiary of Encore Energy Partners LP for each of the years in the three-year period ended December 31, 2006. These statements are the responsibility of Anadarko Petroleum Corporation’s management. Our responsibility is to express an opinion on these statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements of revenues and direct operating expenses are free of material misstatement. An audit includes 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 Elk Basin Operations’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

The accompanying statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in note 1. The statements are not intended to be a complete presentation of Elk Basin Operations’ revenues and expenses.

In our opinion, the combined statements of revenues and direct operating expenses referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Elk Basin Operations for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.


		/s/ KPMG LLP

Houston, Texas

April 27, 2007

F-56

ANADARKO ELK BASIN OPERATIONS

Notes to Combined Statements of Revenues and Direct Operating Expenses

Years Ended December 31, 2006, 2005, and 2004

(1) Basis of presentation

On January 16, 2007, Encore Acquisition Company (Encore) entered into a Purchase and Sale Agreement (Agreement) with Clear Fork Pipeline Company, Howell Petroleum Corporation, and Kerr-McGee Oil & Gas Onshore LP, all of which are wholly owned subsidiaries of Anadarko Petroleum Corporation (collectively referred to as Anadarko), whereby Encore agreed to acquire from Anadarko certain oil and natural gas properties and related assets and liabilities in or near the Elk Basin field in Park County, Wyoming and Carbon County, Montana (Elk Basin Operations). On March 6, 2007, Encore assigned all of its interest in the Agreement to a wholly owned subsidiary of Encore Energy Partners LP (the Partnership). The acquisition closed on March 7, 2007 for a cash purchase price of approximately $328.4 million, subject to contractual post-closing adjustments as set forth in the Agreement.

Anadarko did not prepare separate stand alone historical financial statements for the Elk Basin Operations in accordance with accounting principles generally accepted in the United States of America. Accordingly, it is not practicable to identify all assets and liabilities or other indirect operating costs applicable to the Elk Basin Operations. The accompanying statements of revenues and direct operating expenses were prepared from the historical accounting records of Anadarko.

Certain indirect expenses as further described in note 4 were not allocated to the Elk Basin Operations’ historical financial records. Any attempt to allocate these expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by the Partnership.

These combined financial statements were prepared under Rule S-X 3-05 of the Securities and Exchange Commission and do not represent a complete set of financial statements reflecting the financial position, results of operations, shareholders’ equity, and cash flows of the Elk Basin Operations and are not indicative of the results of operations for the Elk Basin Operations going forward.

Gas and natural gas liquids production are primarily sold to a wholly owned Anadarko affiliate at prevailing market prices. These products are sold by the Anadarko affiliate to unrelated third parties. Any margins earned by the affiliate are excluded from the accompanying combined financial statements.

(2) Significant accounting policies


*(a)*	*Principles of Combination and Use of Estimates*

The combined statements of revenues and direct operating expenses are derived from the accounts of Anadarko. All significant intercompany transactions and balances have been eliminated in combination of the financial statements. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the statements of revenues and direct operating expenses. Actual results could be different from those estimates.


*(b)*	*Revenue Recognition*

Total revenues in the accompanying statements of revenues and direct operating expenses include oil, natural gas, natural gas liquids (NGLs), and other revenue. Anadarko recognizes revenues based on the amount of oil, natural gas, and NGLs sold to purchasers when delivery to the purchaser has occurred and title has transferred. Other revenue is comprised of third-party sulfur sales as well as processing revenues earned by the plant attributable to third-party owned production. Anadarko follows the sales method of accounting for gas imbalances, whereby, as sales volumes exceed Anadarko’s entitled share, an overproduced imbalance occurs. To the extent the overproduced imbalance exceeds Anadarko’s share of the remaining estimated proved natural

F-58

ANADARKO ELK BASIN OPERATIONS

Notes to Combined Statements of Revenues and Direct Operating Expenses

Years Ended December 31, 2006, 2005, and 2004

gas reserves for a given property, a liability is recorded. There were no significant imbalances with other revenue interest owners during any of the periods presented in these statements.


*(c)*	*Direct Operating Expenses*

Direct operating expenses are recognized when incurred and consist of direct expenses of operating the Elk Basin Operations. The direct operating expenses include lease operating, gathering, processing, and production and other tax expense. Lease operating expenses include lifting costs, well repair expenses, surface repair expenses, well workover costs, and other field expenses. Gathering and processing expenses include cost of product, maintenance and repair, and other operating costs. Lease operating and gathering and processing expenses also include expenses directly associated with support personnel, support services, equipment, and facilities directly related to oil and the production activities. Production and other taxes consist of severance and ad valorem taxes.

(3) Contingencies

The activities of the Elk Basin Operations are subject to potential claims and litigation in the normal course of operations. Anadarko’s management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the Elk Basin Operations.

(4) Excluded Expenses (Unaudited)

The Elk Basin Operations were part of a much larger enterprise prior to the date of the acquisition by the Partnership. Indirect general and administrative expenses, recovery of COPAS overhead charges to joint venture partners, interest, income taxes, and other indirect expenses were not allocated to the Elk Basin Operations and have been excluded from the accompanying statements. The COPAS overhead recoveries were approximately $750,000 per year. In addition, management of Anadarko believes such indirect expenses are not indicative of future costs or recoveries, which would be incurred by the Partnership.

Also, depreciation, depletion and amortization have been excluded from the accompanying statements of revenues and direct operating expenses as such amounts would not be indicative of those expenses, which would be incurred based on the amounts expected to be allocated to the oil properties in connection with the purchase price allocation by the Partnership.

(5) Cash Flow Information (Unaudited)

Capital expenditures relating to the Elk Basin Operations were approximately $1,610,000, $524,000, and $1,667,000 for the years ended December 31, 2006, 2005 and 2004, respectively. Other cash flow information is not available on a stand-alone basis for the Elk Basin Operations.

(6) Supplemental Information for Oil Producing Activities (Unaudited)

Supplemental oil reserve information related to the Elk Basin Operations is presented in accordance with the requirements of statement of financial accounting standards SFAS No. 69, Disclosures about Oil and Gas Producing Activities. (SFAS No. 69).

Because oil and natural gas reserves are based on many assumptions, all of which may substantially differ from actual results, estimates of reserves and timing of development and production may be significantly different from the actual quantities of oil and natural gas that are ultimately recovered and the timing of such production. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimates.

F-59

ANADARKO ELK BASIN OPERATIONS

Notes to Combined Statements of Revenues and Direct Operating Expenses

Years Ended December 31, 2006, 2005, and 2004

Estimated Proved Reserves

Proved oil and natural gas reserves are estimated and prepared in accordance with Securities and Exchange Commission (SEC) guidelines and are a function of; (i) the quality and quantity of available data, (ii) the interpretation of that data, (iii) the accuracy of various economic assumptions used, and (iv) the judgment of the persons preparing the estimate.

The volumes of proved oil and natural gas reserves shown are estimates, which, by their nature, are subject to later revision. These proved oil and natural gas reserves were estimated utilizing all available geological and reservoir data as well as production performance data. These estimates are prepared annually by reserve engineers, and revised either upward or downward, as warranted by additional performance data.

The following table sets forth estimates of the proved oil and natural gas reserves (net of royalty interests) and changes therein, for the periods indicated.


	Natural
	Gas			Liquids			Total
	(MMcf)			(MBbl)			(MBOE)(1)

January 1, 2004		13,409			20,781			23,016
Revisions of previous estimates		(4,904	)		155			(662	)
Production		(491	)		(1,378	)		(1,460	)

December 31, 2004		8,014			19,558			20,894
Revisions of previous estimates		76			(123	)		(110	)
Production		(427	)		(1,280	)		(1,351	)

December 31, 2005		7,663			18,155			19,433
Revisions of previous estimates		(455	)		(193	)		(269	)
Production		(362	)		(1,266	)		(1,326	)

December 31, 2006		6,846			16,696			17,838

Proved developed reserves as of:
December 31, 2004		7,723			17,094			18,381
December 31, 2005		7,387			15,697			16,928
December 31, 2006		6,366			14,361			15,422
Proved undeveloped reserves as of:
December 31, 2004		291			2,464			2,513
December 31, 2005		276			2,458			2,505
December 31, 2006		480			2,335			2,416


(1)		Total volumes are in thousands of barrels of oil equivalent (MBOE). For this computation, one barrel is the equivalent of six thousand cubic feet of gas. NGLs are included with oil and condensate reserves and the associated shrinkage has been deducted from gas reserves.

Estimates of future net cash flows from proved reserves of natural gas, oil, and condensate were made in accordance with SFAS No. 69. The amounts were prepared by Anadarko’s engineers and are shown in the following table. The estimates used for the development of future cash inflows were $57.75, $60.32 and $40.25 per barrel of oil and $5.64, $10.08, and $6.18 per MMBtu of natural gas for 2006, 2005 and 2004, respectively. Estimated future cash flows are reduced by estimated future development, production, abandonment and dismantlement costs based on year-end cost levels, assuming continuation of existing economic conditions, and by estimated future income tax expense. Income tax expense is calculated by

F-60

ANADARKO ELK BASIN OPERATIONS

Notes to Combined Statements of Revenues and Direct Operating Expenses

Years Ended December 31, 2006, 2005, and 2004

applying the statutory income tax rates to the pretax net cash flows giving effect to any permanent differences and reduced by the applicable tax basis.

Standardized Measure of Discounted Future Net Cash Flows

The present value of future net cash flows does not purport to be an estimate of the fair market value of the Elk Basin Operations’ proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves, and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas.

The following table sets forth estimates of the standardized measure of discounted future net cash flows from proved reserves of oil and natural gas for the periods indicated.


	Year Ended December 31
	2006			2005			2004
	(In thousands)

Future cash inflows	$	797,554			733,342			611,163
Future production costs		(359,103	)		(343,135	)		(292,772	)
Future development costs		(16,226	)		(17,034	)		(11,651	)
Future income tax expense		(140,122	)		(121,127	)		(96,408	)

Future net cash flows		282,103			252,046			210,332
10% discount for estimating timing of cash flows		(140,386	)		(123,652	)		(98,255	)

Standardized measure of discounted future net cash flows relating to oil and natural gas reserves	$	141,717			128,394			112,077

The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the periods indicated.


	Year Ended December 31
	2006			2005			2004
	(In thousands)

Beginning of year	$	128,394			112,077			121,211
Sales of oil and natural gas produced, net of production costs		(47,530	)		(41,169	)		(33,797	)
Net changes in prices and production costs		53,218			46,355			9,381
Development costs incurred during the period		1,610			524			1,667
Change in estimated future development costs		(877	)		(5,335	)		782
Revisions of previous quantity estimates		(1,936	)		(634	)		(3,840	)
Accretion of discount		17,990			15,567			17,626
Net change in income taxes		(6,106	)		(10,770	)		3,653
Timing and other		(3,046	)		11,779			(4,606	)

Net change		13,323			16,317			(9,134	)

End of year	$	141,717			128,394			112,077

F-61

ANADARKO ELK BASIN OPERATIONS

Notes to Unaudited Statements of Revenues and Direct Operating Expenses


(1)	Basis of presentation

On January 16, 2007, Encore Acquisition Company (“Encore”) entered into a Purchase and Sale Agreement (“Agreement”) with Clear Fork Pipeline Company, Howell Petroleum Corporation, and Kerr-McGee Oil & Gas Onshore LP, all of which are wholly owned subsidiaries of Anadarko Petroleum Corporation (collectively referred to as “Anadarko”), whereby Encore agreed to acquire from Anadarko certain oil and natural gas properties and related assets and liabilities in or near the Elk Basin field in Park County, Wyoming and Carbon County, Montana (“Elk Basin Operations”). On March 6, 2007, Encore assigned all of its interest in the Agreement to a wholly owned subsidiary of Encore Energy Partners LP (the “Partnership”). The acquisition closed on March 7, 2007 for a cash purchase price of approximately $328.4 million, subject to contractual post-closing adjustments as set forth in the Agreement.

Anadarko did not prepare separate stand alone historical financial statements for the Elk Basin Operations in accordance with accounting principles generally accepted in the United States of America. Accordingly, it is not practicable to identify all assets and liabilities or other indirect operating costs applicable to the Elk Basin Operations. The accompanying unaudited statements of revenues and direct operating expenses were prepared from the historical accounting records of Anadarko and Encore.

Certain indirect expenses as further described in Note 3 were not allocated to the Elk Basin Operations’ historical financial records. Any attempt to allocate these expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by the Partnership.

These unaudited statements of revenues and direct operating expenses do not represent a complete set of financial statements reflecting the financial position, results of operations, shareholders’ equity, and cash flows of the Elk Basin Operations and are not indicative of the results of operations for the Elk Basin Operations going forward.


(2)	Contingencies

The activities of the Elk Basin Operations are subject to potential claims and litigation in the normal course of operations. Encore’s management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the Elk Basin Operations.


(3)	Excluded expenses

Also, depreciation, depletion and amortization have been excluded from the accompanying unaudited statements of revenues and direct operating expenses as such amounts would not be indicative of those expenses, which would be incurred based on the amounts expected to be allocated to the oil properties in connection with the purchase price allocation by the Partnership.

F-63

SECOND AMENDED AND RESTATED AGREEMENT OF LIMITED
PARTNERSHIP OF ENCORE ENERGY PARTNERS LP

THIS SECOND AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF ENCORE ENERGY PARTNERS LP dated as of , 2007, is entered into by and among Encore Energy Partners GP LLC, a Delaware limited liability company, as the General Partner, and the other parties hereto, as limited partners, together with any other Persons who become Partners in the Partnership or parties hereto as provided herein, and amends and restates in its entirety the Agreement of Limited Partnership of Encore Energy Partners LP dated as of February 13, 2007, as amended and restated by the First Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP dated as of May 10, 2007. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I

DEFINITIONS

Section 1.1 Definitions.

The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

“Additional Book Basis” means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

(a) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

(b) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided, that the amount treated as Additional Book Basis pursuant hereto as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the Partnership’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (b) to such Book-Down Event).

“Additional Book Basis Derivative Items” means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Partnership’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “Excess Additional Book Basis”), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period.

“Additional Limited Partner” means a Person admitted to the Partnership as a Limited Partner pursuant to Section 10.4 and who is shown as such on the books and records of the Partnership.

“Adjusted Capital Account” means the Capital Account maintained for each Partner as of the end of each fiscal year of the Partnership, (a) increased by any amounts that such Partner is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all deductions in respect of depletion that, as of the end of such fiscal year, are reasonably expected to be made to such Partner’s Capital Account in respect of the oil and gas properties of the Partnership, (ii) the amount of

A-1

all losses and deductions that, as of the end of such fiscal year, are reasonably expected to be allocated to such Partner in subsequent years under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (iii) the amount of all distributions that, as of the end of such fiscal year, are reasonably expected to be made to such Partner in subsequent years in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner’s Capital Account that are reasonably expected to occur during (or prior to) the year in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or 6.1(d)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of the General Partner Interest, a Common Unit, a Management Incentive Unit or any other Partnership Interest shall be the amount that such Adjusted Capital Account would be if such General Partner Interest, Common Unit, Management Incentive Unit or other Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such General Partner Interest, Common Unit, Management Incentive Unit or other Partnership Interest was first issued.

“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section 5.5(d)(i) or 5.5(d)(ii).

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“Aggregate Remaining Net Positive Adjustments” means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all the Partners.

“Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

“Agreed Value” of any Contributed Property means the fair market value of such property or other consideration at the time of contribution as determined by the General Partner. The General Partner shall use such method as it determines to be appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Partnership in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.

“Agreement” means this Second Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP, as it may be amended, supplemented or restated from time to time.

“Amended and Restated Administrative Services Agreement” means the Amended and Restated Administrative Services Agreement, dated as of , 2007, among the General Partner, the Partnership, the Operating Company and Encore Operating, L.P., as it may be amended, supplemented or restated from time to time.

“Anniversary Date” means the first anniversary of the Conversion Date of a Management Incentive Unit.

“Assignee” means a Person to whom one or more Limited Partner Interests have been transferred in a manner permitted under this Agreement and who has executed and delivered a Transfer Application, including a Eligible Holder Certification, as required by this Agreement, but who has not been admitted as a Substituted Limited Partner.

“Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer or partner or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar

A-2

fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

“Available Cash” means, with respect to any Quarter ending prior to the Liquidation Date:

(a) all cash and cash equivalents of the Partnership Group on hand on the date of determination of Available Cash with respect to such Quarter, less

(b) the amount of any cash reserves established by the General Partner to (i) provide for the proper conduct of the business of the Partnership Group (including reserves for future capital expenditures and for anticipated future credit needs of the Partnership Group) subsequent to such Quarter, (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject or (iii) provide funds for distributions under Section 6.3 in respect of any one or more of the next four Quarters; provided, however, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines.

Notwithstanding the foregoing, “Available Cash” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

“Board of Directors” means the board of directors or managers, as applicable, of a corporation or limited liability company or the board of directors or board of managers, as applicable, of the general partner of a limited partnership.

“Book Basis Derivative Items” means any item of income, deduction, gain, loss, Simulated Depletion, Simulated Gain or Simulated Loss included in the determination of Net Income or Net Loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, Simulated Depletion, or gain, loss, Simulated Gain or Simulated Loss, with respect to an Adjusted Property).

“Book-Down Event” means an event that triggers a negative adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

“Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.5 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

“Book-Up Event” means an event that triggers a positive adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

“Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the States of New York or Texas shall not be regarded as a Business Day.

“Capital Account” means the capital account maintained for a Partner pursuant to Section 5.5. The “Capital Account” of a Partner in respect of a General Partner Interest, a Common Unit, a Management Incentive Unit or any other Partnership Interest shall be the amount that such Capital Account would be if such General Partner Interest, Common Unit, Management Incentive Unit or other Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such General Partner Interest, Common Unit, Management Incentive Unit or other Partnership Interest was first issued.

“Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of Contributed Property (which, in the case of a Capital Contribution by the General Partner pursuant to Section 5.2(b) may

A-3

include Units (other than General Partner Units) owned by the General Partner) that a Partner contributes to the Partnership pursuant to this Agreement.

“Carrying Value” means (a) with respect to a Contributed Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, depletion (including Simulated Depletion), amortization and cost recovery deductions charged to the Partners’ and Assignees’ Capital Accounts in respect of such Contributed Property, and (b) with respect to any other Partnership property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Sections 5.5(d)(i) and 5.5(d)(ii) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

“Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

“Certificate” means (a) a certificate (i) substantially in the form of Exhibit A to this Agreement, (ii) issued in global form in accordance with the rules and regulations of the Depositary or (iii) in such other form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more Common Units or (b) a certificate, in such form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more other Partnership Securities.

“Certificate of Limited Partnership” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

“Change-in-Control” means (a) a “Change in Control” as defined in Parent’s 2000 Incentive Stock Plan, as such plan may be amended, supplemented or restated from time to time, (b) any Person or group, other than Parent or its Affiliates, becomes the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in the General Partner or the Partnership, (c) the Limited Partners approve, in one or a series of transactions, a plan of complete liquidation of the Partnership, (d) the sale or other 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, (e) a transaction resulting in a Person other than Encore Energy Partners GP LLC or one of its Affiliates being the general partner of the Partnership, or (f) a transaction resulting in the general partner of the Partnership ceasing to be an Affiliate of Parent.

“claim” (as used in Section 7.12(c)) has the meaning assigned to such term in Section 7.12(c).

“Closing Date” means the first date on which Common Units are sold by the Partnership to the Underwriters pursuant to the provisions of the Underwriting Agreement.

“Closing Price” means, in respect of any class of Limited Partner Interests, as of the date of determination, the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, as reported in the principal consolidated transaction reporting system with respect to securities listed on the principal National Securities Exchange (other than the NASDAQ Global Select Market) on which the respective Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests are not listed or admitted to trading on any National Securities Exchange (other than the NASDAQ Global Select Market), the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the NASDAQ Global Select Market or such other system then in use, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined by the General Partner.

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“Code” means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

“Combined Interest” has the meaning assigned to such term in Section 11.3(a).

“Commission” means the United States Securities and Exchange Commission.

“Common Unit” means a Partnership Interest representing a fractional part of the Partnership Interests of all Limited Partners and Assignees, and having the rights and obligations specified with respect to Common Units in this Agreement.

“Common Unit Equivalents” means the number of Common Units which a Management Incentive Unit is considered to represent under Section 5.10(d) or, if applicable, under Section 6.3(d).

“Conflicts Committee” means a committee of the Board of Directors of the General Partner composed entirely of two or more directors who are not (a) security holders, officers or employees of the General Partner, (b) officers, directors or employees of any Affiliate of the General Partner or (c) holders of any ownership interest in the Partnership Group other than Common Units and who also meet the independence standards required of directors who serve on an audit committee of a board of directors established by the Securities Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which the Common Units are listed or admitted to trading.

“Continuous Employment” means continued employment by Parent (or any successor), any subsidiary of Parent (or any successor), the Partnership, the General Partner or any Affiliate of the Partnership or the General Partner.

“Contributed Property” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.5(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

“Contribution Agreement” means that certain Contribution, Conveyance and Assumption Agreement, dated as of the Closing Date, among the General Partner, the Partnership, the Operating Company and certain other parties, together with the additional conveyance documents and instruments contemplated or referenced thereunder, as such may be amended, supplemented or restated from time to time.

“Conversion Date” means the date that a Management Incentive Unit is converted into Common Units pursuant to Section 5.10(e).

“Conversion Notice” has the meaning assigned to such term in Section 5.10.

“Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(xi).

“Current Market Price” means, in respect of any class of Limited Partner Interests, as of the date of determination, the average of the daily Closing Prices per Limited Partner Interest of such class for the 20 consecutive Trading Days immediately prior to such date.

“Delaware Act” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

“Departing General Partner” means a former General Partner from and after the effective date of any withdrawal or removal of such former General Partner pursuant to Section 11.1 or 11.2.

“Depositary” means, with respect to any Units issued in global form, The Depository Trust Company and its successors and permitted assigns.

“Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

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“Eligible Holder” means a person or entity qualified to hold an interest in oil and gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; (3) a public body, including a municipality; or (4) 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.

“Eligible Holder Certification” means a properly completed certificate in such form as may be specified by the General Partner by which an Assignee or a Limited Partner certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Holder.

“Excess Allocations” has the meaning assigned to such term in Section 6.1(c)(i)(B).

“Excess Available Cash” has the meaning assigned to such term in Section 6.3(d).

“Executive” means any of I. Jon Brumley, Jon S. Brumley, Robert C. Reeves, L. Ben Nivens or John W. Arms or their Permitted Transferees.

“Event of Withdrawal” has the meaning assigned to such term in Section 11.1(a).

“Fifth Target Distribution” has the meaning assigned to such term in Section 5.10(d)(v).

“First Conversion Milestone” has the meaning assigned to such term in Section 5.10(e)(i).

“First Target Distribution” has the meaning assigned to such term in Section 5.10(d)(i).

“Fourth Conversion Milestone” has the meaning assigned to such term in Section 5.10(e)(i).

“Fourth Target Distribution” has the meaning assigned to such term in Section 5.10(d)(iv).

“General Partner” means Encore Energy Partners GP LLC, a Delaware limited liability company, and its successors and permitted assigns that are admitted to the Partnership as general partner of the Partnership, in its capacity as general partner of the Partnership (except as the context otherwise requires).

“General Partner Interest” means the ownership interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest held by it), which is evidenced by General Partner Units, and includes any and all benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement.

“General Partner Unit” means a fractional part of the General Partner Interest having the rights and obligations specified with respect to the General Partner Interest. A General Partner Unit is not a Unit. The initial number of General Partner Units held by the General Partner is 209,789.

“Grantee” has the meaning assigned to such term in Section 5.10(f)(i).

“Group” means a Person that with or through any of its Affiliates or Associates has any agreement, contract, arrangement, understanding or relationship for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

“Group Member” means a member of the Partnership Group.

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“Group Member Agreement” means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

“Holder” as used in Section 7.12, has the meaning assigned to such term in Section 7.12(a).

“Indemnified Persons” has the meaning assigned to such term in Section 7.12(c).

“Indemnitee” means (a) the General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was a member, partner, director, officer, fiduciary or trustee of any Group Member, the General Partner or any Departing General Partner or any Affiliate of any Group Member, the General Partner or any Departing General Partner, (e) any Person who is or was serving at the request of the General Partner or any Departing General Partner or any Affiliate of the General Partner or any Departing General Partner as an officer, director, member, partner, fiduciary or trustee of another Person; provided that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, and (f) any Person the General Partner designates as an “Indemnitee” for purposes of this Agreement.

“Initial Common Units” means the Common Units sold in the Initial Offering.

“Initial Limited Partners” means the Organizational Limited Partner, I. Jon Brumley, Jon S. Brumley, Robert C. Reeves, L. Ben Nivens, John W. Arms, Encore Operating, L.P., a Texas limited partnership, and the Underwriters, in each case upon being admitted to the Partnership in accordance with Section 10.1.

“Initial Offering” means the initial offering and sale of Common Units to the public, as described in the Registration Statement.

“Interim Closing Date” means May 10, 2007.

“Issuance Date” means any date following the Conversion Date and prior to the Anniversary Date on which the Partnership issues additional Partnership Securities.

“Issue Price” means the price at which a Unit is purchased from the Partnership, net of any sales commission or underwriting discount charged to the Partnership.

“Limited Partner” means, unless the context otherwise requires, (a) the Organizational Limited Partner, each Initial Limited Partner, each Substituted Limited Partner, each Additional Limited Partner and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3, in each case, in such Person’s capacity as a limited partner of the Partnership; provided, however, that when the term “Limited Partner” is used herein in the context of any vote or other approval, including Articles XIII and XIV, such term shall not, solely for such purpose, include any holder of a Management Incentive Unit (solely with respect to its Management Incentive Units and not with respect to any other Limited Partner Interest held by such Person) except as may otherwise be required by law or (b) solely for purposes of Articles V, VI, VII, IX and XII, each Assignee.

“Limited Partner Interest” means the ownership interest of a Limited Partner or Assignee in the Partnership, which may be evidenced by Common Units, Management Incentive Units, or other Partnership Securities or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner or Assignee is entitled as provided in this Agreement, together with all obligations of such Limited Partner or Assignee to comply with the terms and provisions of this Agreement; provided, however, that when the term “Limited Partner Interest” is used herein in the context of any vote or other approval, including Articles XIII and XIV, such term shall not, solely for such purpose, include a Management Incentive Unit except as may otherwise be required by law.

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“Liquidation Date” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to continue the business of the Partnership has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

“Liquidator” means one or more Persons selected by the General Partner to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

“Management Incentive Unit” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners and having the rights and obligations specified with respect to Management Incentive Units in this Agreement.

“Merger Agreement” has the meaning assigned to such term in Section 14.1.

“MIU Allocation Limit” has the meaning assigned to such term in Section 6.1(c)(i)(B).

“MIU Conversion Limit” has the meaning assigned to such term in Section 5.10(e).

“MIU Distribution Limit” has the meaning assigned to such term in Section 6.3(d).

“MIU Limits” has the meaning assigned to such term in Section 5.10(i).

“National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act, and any successor to such statute.

“Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any liabilities either assumed by the Partnership upon such contribution or to which such property is subject when contributed, and (b) in the case of any property distributed to a Partner or Assignee by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.5(d)(ii)) at the time such property is distributed, reduced by any indebtedness either assumed by such Partner or Assignee upon such distribution or to which such property is subject at the time of distribution, in either case, as determined under Section 752 of the Code.

“Net Income” means, for any taxable year, the excess, if any, of the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Income shall be determined in accordance with Section 5.5(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items specially allocated under Section 6.1(d); provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xii) were not in this Agreement.

“Net Loss” means, for any taxable year, the excess, if any, of the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.5(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items specially allocated under Section 6.1(d); provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xii) were not in this Agreement.

“Net Positive Adjustments” means, with respect to any Partner, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Partner pursuant to Book-Up Events and Book-Down Events.

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“Net Termination Gain” means, for any taxable year, the sum, if positive, of all items of income, gain, loss or deduction recognized by the Partnership after the Liquidation Date. The items included in the determination of Net Termination Gain shall be determined in accordance with Section 5.5(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

“Net Termination Loss” means, for any taxable year, the sum, if negative, of all items of income, gain, loss or deduction recognized by the Partnership after the Liquidation Date. The items included in the determination of Net Termination Loss shall be determined in accordance with Section 5.5(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

“Non-Eligible Holder” means a Person whom the General Partner has determined does not constitute an Eligible Holder and as to whose Partnership Interest the General Partner has become the Substituted Limited Partner, pursuant to Section 4.8.

“Non-Recourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Non-Recourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Sections 6.2(d)(i)(A), 6.2(d)(ii)(A) and 6.2(d)(iii) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

“Non-Recourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Non-Recourse Liability.

“Non-Recourse Liability” has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

“Notice of Election to Purchase” has the meaning assigned to such term in Section 15.1(b).

“Operating Company” means Encore Energy Partners Operating LLC, a Delaware limited liability company, and any successors thereto.

“Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner.

“Option Closing Date” means the date or dates on which any Common Units are sold by the Partnership to the Underwriters upon exercise of the Over-Allotment Option.

“Organizational Limited Partner” means Encore Partners LP Holdings LLC, a Delaware limited liability company, in its capacity as the organizational limited partner of the Partnership pursuant to this Agreement.

“Outstanding” means, with respect to Partnership Securities, all Partnership Securities that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of the Outstanding Partnership Securities of any class then Outstanding, all Partnership Securities owned by such Person or Group shall not be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Units so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Units shall not, however, be treated as a separate class of Partnership Securities for purposes of this Agreement); provided, further, that the foregoing limitation shall not apply to (i) any Person or Group who acquired 20% or more of the Outstanding Partnership Securities of any class then Outstanding directly from the General Partner or its Affiliates, (ii) any Person or Group who acquired 20% or more of the Outstanding Partnership Securities of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) provided that the General Partner shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) any Person or Group

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who acquired 20% or more of any Partnership Securities issued by the Partnership with the prior approval of the Board of Directors of the General Partner.

“Over-Allotment Option” means the over-allotment option granted to the Underwriters by the Partnership pursuant to the Underwriting Agreement.

“Parent” means Encore Acquisition Company and its successors and permitted assigns.

“Partner Non-Recourse Debt” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

“Partner Non-Recourse Debt Minimum Gain” has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

“Partner Non-Recourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Partner Non-Recourse Debt.

“Partners” means the General Partner and the Limited Partners.

“Partnership” means Encore Energy Partners LP, a Delaware limited partnership.

“Partnership Group” means the Partnership and its Subsidiaries treated as a single consolidated entity.

“Partnership Interest” means an interest in the Partnership, which shall include the General Partner Interest and Limited Partner Interests.

“Partnership Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(d).

“Partnership Security” means any class or series of equity interest in the Partnership (but excluding any options, rights, warrants and appreciation rights relating to an equity interest in the Partnership), including Common Units, Management Incentive Units and General Partner Units.

“Percentage Interest” means as of any date of determination (a) as to the General Partner (in its capacity as General Partner without reference to any Limited Partner Interests held by it) with respect to General Partner Units and as to any Unitholder or Assignee with respect to Common Units, the product obtained by multiplying (i) 100% less the percentage applicable to clause (b) below by (ii) the quotient obtained by dividing (A) the number of General Partner Units held by the General Partner, the number of Common Units held by such Unitholder or Assignee, or the number of Common Unit Equivalents held or, if the provisions of Section 6.3(c) apply, deemed to be held by such Unitholder or Assignee, as the case may be, by (B) the total number of Outstanding Common Units, the total number of Outstanding Common Unit Equivalents and General Partner Units, and (b) as to the holders of other Partnership Securities issued by the Partnership in accordance with Section 5.6, the percentage established as a part of such issuance; provided, that with respect to the calculations in Section 5.10(e)(vi) and Section 5.10(e)(vii), in-the-money options, rights, warrants and appreciation rights relating to Partnership Securities shall be deemed to be Outstanding in the form of the associated Partnership Securities to the extent vested.

“Permitted Transferee” means (i) the Partnership and (ii) an Executive’s Relatives, any trust of which there are no principal beneficiaries other than such Executive or one or more of such Executive’s Relatives, or a corporation, partnership, limited liability company or other Person of which there are no owners other than such Executive, one or more of such Executive’s Relatives or another entity of which there are no other owners other than such Executive or one or more of such Executive’s Relatives (provided that each such transferee agrees to be bound by the terms of this Agreement as if it were an original party hereto and further agrees that it shall not thereafter transfer such Management Incentive Units to any Person to whom such transferor would not be permitted to transfer such Management Incentive Units pursuant to the terms of this Agreement).

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“Person” means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

“Plan of Conversion” has the meaning assigned to such term in Section 14.1.

“Pro Rata” means (a) when used with respect to Units or any class thereof, apportioned equally among all designated Units in accordance with their relative Percentage Interests, (b) when used with respect to Partners and Assignees or Record Holders, apportioned among all Partners and Assignees or Record Holders in accordance with their relative Percentage Interests, and (c) when used with respect to holders of Management Incentive Units, apportioned equally among all holders of Management Incentive Units in accordance with the relative number or percentage of Management Incentive Units held by each such holder.

“Purchase Date” means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV.

“Quarter” means, unless the context requires otherwise, a fiscal quarter of the Partnership, or, with respect to the fiscal quarter of the Partnership which includes the Closing Date, the portion of such fiscal quarter after the Closing Date.

“Recapture Income” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

“Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

“Record Holder” means (a) the Person in whose name a Common Unit is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or (b) with respect to other Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the opening of business on such Business Day.

“Redeemable Interests” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.9.

“Registration Statement” means the Registration Statement on Form S-1 (Registration No. 333-142847) as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Offering.

“Relatives” means, collectively, an Executive’s spouse, parents, children, grandchildren, siblings, mothers and fathers-in-law, sons and daughters-in-law, and brothers and sisters-in-law.

“Remaining Net Positive Adjustments” means as of the end of any taxable period, (a) with respect to the Unitholders holding Common Units, the excess of (i) the Net Positive Adjustments of the Unitholders holding Common Units as of the end of such period over (ii) the sum of those Partners’ Share of Additional Book Basis Derivative Items for each prior taxable period, (b) with respect to the General Partner (as holder of the General Partner Interest), the excess of (i) the Net Positive Adjustments of the General Partner as of the end of such period over (ii) the sum of the General Partner’s Share of Additional Book Basis Derivative Items with respect to the General Partner Interest for each prior taxable period, and (c) with respect to the holders of Management Incentive Units, the excess of (a) the Net Positive Adjustments of the holders of Management Incentive Units as of the end of such period over (b) the sum of the Share of Additional Book Basis Derivative Items of the holders of the Management Incentive Units for each prior taxable period.

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“Required Allocations” means (a) any limitation imposed on any allocation of Net Losses or Net Termination Losses under Section 6.1(b) or 6.1(c)(ii) and (b) any allocation of an item of income, gain, loss, deduction, Simulated Depletion or Simulated Loss pursuant to Section 6.1(d)(i), 6.1(d)(ii), 6.1(d)(iv), 6.1(d)(vii) or 6.1(d)(ix).

“Residual Gain” or “Residual Loss” means any item of gain or loss, as the case may be, of the Partnership recognized for federal income tax purposes resulting from a sale, exchange or other disposition of a Contributed Property or Adjusted Property, to the extent such item of gain or loss or Simulated Depletion or Simulated Loss is not allocated pursuant to Section 6.2(d)(i)(A) or 6.2(d)(ii)(A), respectively, to eliminate Book-Tax Disparities.

“Second Conversion Milestone” has the meaning assigned to such term in Section 5.10(e)(i).

“Second Target Distribution” has the meaning assigned to such term in Section 5.10(d)(ii).

“Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

“Securities Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute.

“Seventh Target Distribution” has the meaning assigned to such term in Section 5.10(d)(vii).

“Share of Additional Book Basis Derivative Items” means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (a) with respect to the Unitholders holding Common Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time, (b) with respect to the General Partner (as holder of the General Partner Interest), the amount that bears the same ratio to such Additional Book Basis Derivative Items as the General Partner’s Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustment as of that time, and (c) with respect to the Partners holding Management Incentive Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Remaining Net Positive Adjustments of the Partners holding the Management Incentive Units as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

“Sharing Percentage” means as of any date of determination (a) as to the General Partner (in its capacity as General Partner without reference to any Limited Partner Interests held by it) with respect to General Partner Units and as to any Unitholder or Assignee with respect to Common Units, the product obtained by multiplying (i) 100% less the percentage applicable to clause (b) below by (ii) the quotient obtained by dividing (A) the number of General Partner Units held by the General Partner or the number of Common Units held by such Unitholder or Assignee, as the case may be, by (B) the total number of Outstanding Common Units and General Partner Units, and (b) as to the holders of other Partnership Securities issued by the Partnership in accordance with Section 5.6, the percentage established as a part of such issuance. The Management Incentive Units will be disregarded in the computation of “Sharing Percentage.”

“Simulated Basis” means the Carrying Value of any oil and gas property (as defined in Section 614 of the Code).

“Simulated Depletion” means, with respect to an oil and gas property (as defined in Section 614 of the Code), a depletion allowance computed in accordance with federal income tax principles (as if the Simulated Basis of the property was its adjusted tax basis) and in the manner specified in Treasury Regulation § 1.704-1(b)(2)(iv)(k)(2). For purposes of computing Simulated Depletion with respect to any property, the Simulated Basis of such property shall be deemed to be the Carrying Value of such property, and in no event shall such allowance for Simulated Depletion, in the aggregate, exceed such Simulated Basis.

“Simulated Gain” means the excess of the amount realized from the sale or other disposition of an oil or gas property over the Carrying Value of such property.

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“Simulated Loss” means the excess of the Carrying Value of an oil or gas property over the amount realized from the sale or other disposition of such property.

“Sixth Target Distribution” has the meaning assigned to such term in Section 5.10(d)(vi).

“Special Approval” means approval by a majority of the members of the Conflicts Committee acting in good faith.

“Stated Distribution” means $0.35 per Common Unit or such other amount determined by the Conflicts Committee upon reissuance of a Management Incentive Unit as contemplated by Section 5.10(f)(iii).

“Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) or limited liability company in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership or member of such limited liability company, but only if more than 50% of the partnership interests of such partnership or membership interests of such limited liability company (considering all of the partnership interests or membership interests as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation, a partnership or a limited liability company) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

“Substituted Limited Partner” means a Person who is admitted as a Limited Partner to the Partnership pursuant to Section 10.2 in place of and with all the rights of a Limited Partner and who is shown as a Limited Partner on the books and records of the Partnership.

“Surviving Business Entity” has the meaning assigned to such term in Section 14.2(b)(ii).

“Target Distribution” means the First Target Distribution, the Second Target Distribution, the Third Target Distribution, the Fourth Target Distribution, the Fifth Target Distribution, the Sixth Target Distribution or the Seventh Target Distribution, as the case may be.

“Third Conversion Milestone” has the meaning assigned to such term in Section 5.10(e)(i).

“Third Target Distribution” has the meaning assigned to such term in Section 5.10(d)(iii).

“Trading Day” means, for the purpose of determining the Current Market Price of any class of Limited Partner Interests, a day on which the principal National Securities Exchange on which such class of Limited Partner Interests is listed is open for the transaction of business or, if Limited Partner Interests of a class are not listed on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

“transfer” has the meaning assigned to such term in Section 4.4(a).

“Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as shall be appointed from time to time by the General Partner to act as registrar and transfer agent for the Common Units; provided, that if no Transfer Agent is specifically designated for any other Partnership Securities, the General Partner shall act in such capacity.

“Transfer Application” means an application and agreement for transfer of Units in the form set forth on the back of a Certificate or in a form substantially to the same effect in a separate instrument.

“Underwriter” means each Person named as an underwriter in Schedule I to the Underwriting Agreement who purchases Common Units pursuant thereto.

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“Underwriting Agreement” means that certain Underwriting Agreement dated as of , 2007, among the Underwriters, the Partnership, the General Partner, the Operating Company and the other parties thereto, providing for the purchase of Common Units by the Underwriters.

“Unit” means a Partnership Security that is designated as a “Unit” and shall include Common Units and Management Incentive Units but shall not include the General Partner Interest.

“Unitholders” means the holders of Units.

“Unit Majority” means at least a majority of the Outstanding Common Units.

“Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.5(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date).

“Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.5(d)).

“U.S. GAAP” means United States generally accepted accounting principles consistently applied.

“Withdrawal Opinion of Counsel” has the meaning assigned to such term in Section 11.1(b).

Section 1.2 Construction.

Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms “include”, “includes”, “including” and words of like import shall be deemed to be followed by the words “without limitation”; and (d) the terms “hereof”, “herein” and “hereunder” refer to this Agreement as a whole and not to any particular provision of this Agreement. The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement.

ARTICLE II

ORGANIZATION

Section 2.1 Formation.

The General Partner and the Organizational Limited Partners have previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware Act and hereby amend and restate the First Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act. All Partnership Interests shall constitute personal property of the owner thereof for all purposes.

Section 2.2 Name.

The name of the Partnership shall be “Encore Energy Partners LP” The Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “Limited Partnership,” “LP,” “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.

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Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices.

Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at 1209 Orange Street, Wilmington, New Castle County, Delaware 19801, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be The Corporation Trust Company. The principal office of the Partnership shall be located at 777 Main Street, Suite 1400, Fort Worth, Texas 76102 or such other place as the General Partner may from time to time designate by notice to the Limited Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner shall determine necessary or appropriate. The address of the General Partner shall be 777 Main Street, Suite 1400, Fort Worth, Texas 76102 or such other place as the General Partner may from time to time designate by notice to the Limited Partners.

Section 2.4 Purpose and Business.

The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity, and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may decline to propose or approve, the conduct by the Partnership of any business free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner or Assignee and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

Section 2.5 Powers.

The Partnership shall be empowered to do any and all acts and things necessary or appropriate for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

Section 2.6 Power of Attorney.

(a) Each Limited Partner and each Assignee hereby constitutes and appoints the General Partner and, if a Liquidator shall have been selected pursuant to Section 12.3, the Liquidator (and any successor to the Liquidator by merger, transfer, assignment, election or otherwise) and each of their authorized officers and attorneys-in-fact, as the case may be, with full power of substitution, as his true and lawful agent and attorney-in-fact, with full power and authority in his name, place and stead, to:

(i) execute, swear to, acknowledge, deliver, file and record in the appropriate public offices (A) all certificates, documents and other instruments (including this Agreement and the Certificate of Limited Partnership and all amendments or restatements hereof or thereof) that the General Partner or the Liquidator determines to be necessary or appropriate to form, qualify or continue the existence or qualification of the Partnership as a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware and in all other jurisdictions in which the Partnership may conduct business or own property; (B) all certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to reflect, in accordance with its terms, any amendment, change, modification or restatement of this Agreement; (C) all certificates, documents and other instruments (including conveyances and a certificate of cancellation) that the General Partner or the Liquidator determines to be necessary or appropriate to reflect the dissolution and liquidation of the Partnership pursuant to the terms of this Agreement; (D) all certificates, documents and

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other instruments relating to the admission, withdrawal, removal or substitution of any Partner pursuant to, or other events described in, Article IV, X, XI or XII; (E) all certificates, documents and other instruments relating to the determination of the rights, preferences and privileges of any class or series of Partnership Securities issued pursuant to Section 5.6; and (F) all certificates, documents and other instruments (including agreements and a certificate of merger) relating to a merger, consolidation or conversion of the Partnership pursuant to Article XIV; and

(ii) execute, swear to, acknowledge, deliver, file and record all ballots, consents, approvals, waivers, certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to (A) make, evidence, give, confirm or ratify any vote, consent, approval, agreement or other action that is made or given by the Partners hereunder or is consistent with the terms of this Agreement or (B) effectuate the terms or intent of this Agreement; provided, that when required by Section 13.3 or any other provision of this Agreement that establishes a percentage of the Limited Partners or of the Limited Partners of any class or series required to take any action, the General Partner and the Liquidator may exercise the power of attorney made in this Section 2.6(a)(ii) only after the necessary vote, consent or approval of the Limited Partners or of the Limited Partners of such class or series, as applicable.

Nothing contained in this Section 2.6(a) shall be construed as authorizing the General Partner to amend this Agreement except in accordance with Article XIII or as may be otherwise expressly provided for in this Agreement.

(b) The foregoing power of attorney is hereby declared to be irrevocable and a power coupled with an interest, and it shall survive and, to the maximum extent permitted by law, not be affected by the subsequent death, incompetency, disability, incapacity, dissolution, bankruptcy or termination of any Limited Partner or Assignee and the transfer of all or any portion of such Limited Partner’s or Assignee’s Partnership Interest and shall extend to such Limited Partner’s or Assignee’s heirs, successors, assigns and personal representatives. Each such Limited Partner or Assignee hereby agrees to be bound by any representation made by the General Partner or the Liquidator acting in good faith pursuant to such power of attorney; and each such Limited Partner or Assignee, to the maximum extent permitted by law, hereby waives any and all defenses that may be available to contest, negate or disaffirm the action of the General Partner or the Liquidator taken in good faith under such power of attorney. Each Limited Partner or Assignee shall execute and deliver to the General Partner or the Liquidator, within 15 days after receipt of the request therefor, such further designation, powers of attorney and other instruments as the General Partner or the Liquidator may request in order to effectuate this Agreement and the purposes of the Partnership.

Section 2.7 Term.

The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue in existence until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

Section 2.8 Title to Partnership Assets.

Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner or Assignee, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the

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Partnership as soon as reasonably practicable; provided, further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to the General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

Section 2.9 Certain Undertakings Relating to the Separateness of the Partnership.

(a) Separateness Generally. The Partnership shall conduct its business and operations separate and apart from those of any other Person (other than the General Partner) in accordance with this Section 2.9.

(b) Separate Records. The Partnership shall maintain (i) its books and records, (ii) its accounts, and (iii) its financial statements, separate from those of any other Person, except its consolidated Subsidiaries.

(c) Separate Assets. The Partnership shall not commingle or pool its funds or other assets with those of any other Person, except its consolidated Subsidiaries, and shall maintain its assets in a manner that is not costly or difficult to segregate, ascertain or otherwise identify as separate from those of any other Person.

(d) Separate Name. The Partnership shall (i) conduct its business in its own name, (ii) use separate stationery, invoices, and checks, (iii) correct any known misunderstanding regarding its separate identity, and (iv) generally hold itself out as a separate entity.

(e) Separate Credit. The Partnership shall not (i) pay its own liabilities from a source other than its own funds, (ii) guarantee or become obligated for the debts of any other Person, except its Subsidiaries, (iii) hold out its credit as being available to satisfy the obligations of any other Person, except its Subsidiaries, (iv) acquire obligations or debt securities of the General Partner or its Affiliates (other than the Partnership or its Subsidiaries), or (v) pledge its assets for the benefit of any Person or make loans or advances to any Person, except its Subsidiaries; provided that the Partnership may engage in any transaction described in clauses (ii)-(v) of this Section 2.9(e) if prior Special Approval has been obtained for such transaction and either (A) the Conflicts Committee has determined, or has obtained reasonable written assurance from a nationally recognized firm of independent public accountants or a nationally recognized investment banking or valuation firm, that the borrower or recipient of the credit extension is not then insolvent and will not be rendered insolvent as a result of such transaction or (B) in the case of transactions described in clause (iv), such transaction is completed through a public auction or a National Securities Exchange.

(f) Separate Formalities. The Partnership shall (i) observe all partnership formalities and other formalities required by its organizational documents, the laws of the jurisdiction of its formation, or other laws, rules, regulations and orders of governmental authorities exercising jurisdiction over it, (ii) engage in transactions with the General Partner and its Affiliates (other than another Group Member) in conformity with the requirements of Section 7.9, and (iii) promptly pay, from its own funds, and on a current basis, its allocable share of general and administrative expenses, capital expenditures, and costs for shared services performed by Affiliates of the General Partner (other than another Group Member). Each material contract between the Partnership or another Group Member, on the one hand, and the Affiliates of the General Partner (other than a Group Member), on the other hand, shall be in writing.

(g) No Effect. Failure by the General Partner or the Partnership to comply with any of the obligations set forth above shall not affect the status of the Partnership as a separate legal entity, with its separate assets and separate liabilities. The General Partner and the Partnership may be consolidated for financial reporting purposes with Encore Acquisition Company and its subsidiaries; provided, however, that such consolidation shall not affect the status of the Partnership as a separate legal entity with its separate assets and separate liabilities.

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ARTICLE III

RIGHTS OF LIMITED PARTNERS

Section 3.1 Limitation of Liability.

The Limited Partners and the Assignees shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

Section 3.2 Management of Business.

No Limited Partner or Assignee, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership. Any action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall not be deemed to be participation in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) and shall not affect, impair or eliminate the limitations on the liability of the Limited Partners or Assignees under this Agreement.

Section 3.3 Outside Activities of the Limited Partners.

Subject to the provisions of Section 7.5, any Limited Partner or Assignee shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group. Neither the Partnership nor any of the other Partners or Assignees shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner or Assignee.

Section 3.4 Rights of Limited Partners.

(a) In addition to other rights provided by this Agreement or by applicable law, and except as limited by Section 3.4(b), each Limited Partner shall have the right, for a purpose reasonably related to such Limited Partner’s interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand, and at such Limited Partner’s own expense:

(i) to obtain true and full information regarding the status of the business and financial condition of the Partnership;

(ii) promptly after its becoming available, to obtain a copy of the Partnership’s federal, state and local income tax returns for each year;

(iii) to obtain a current list of the name and last known business, residence or mailing address of each Partner;

(iv) to obtain a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed;

(v) to obtain true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution by each Partner and that each Partner has agreed to contribute in the future, and the date on which each became a Partner; and

(vi) to obtain such other information regarding the affairs of the Partnership as is just and reasonable.

(b) The General Partner may keep confidential from the Limited Partners and Assignees, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner in good faith believes (A) is not in the best interests of the Partnership Group, (B) could damage the

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Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).

ARTICLE IV

CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS

Section 4.1 Certificates.

Upon the Partnership’s issuance of Common Units to any Person, the Partnership shall issue, upon the request of such Person, one or more Certificates in the name of such Person evidencing the number of such Units being so issued. In addition, (a) upon the General Partner’s request, the Partnership shall issue to it one or more Certificates in the name of the General Partner evidencing its General Partner Interest and (b) upon the request of any Person owning Management Incentive Units or any other Partnership Securities other than Common Units, the Partnership shall issue to such Person one or more certificates evidencing such Management Incentive Units or other Partnership Securities other than Common Units. Certificates shall be executed on behalf of the Partnership by the Chairman of the Board, Chief Executive Officer, President or any Executive Vice President, Senior Vice President or Vice President and the Chief Financial Officer or the Secretary or any Assistant Secretary of the General Partner. No Common Unit Certificate shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, the Units may be certificated or uncertificated as provided in the Delaware Act; provided, further that if the General Partner elects to issue Common Units in global form, the Common Unit Certificates shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Common Units have been duly registered in accordance with the directions of the Partnership. Subject to the requirements of Section 6.4, the Partners holding Certificates evidencing Management Incentive Units may exchange such Certificates for Certificates evidencing Common Units on or after the date on which such Management Incentive Units are converted into Common Units pursuant to the terms of Section 5.10.

Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates.

(a) If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Securities as the Certificate so surrendered.

(b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent shall countersign, a new Certificate in place of any Certificate previously issued, or issue uncertificated Units, if the Record Holder of the Certificate:

(i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;

(ii) requests the issuance of a new Certificate or the issuance of uncertificated Units before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv) satisfies any other reasonable requirements imposed by the General Partner.

If a Limited Partner or Assignee fails to notify the General Partner within a reasonable period of time after he has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner

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Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner or Assignee shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate or uncertificated Units.

(c) As a condition to the issuance of any new Certificate or uncertificated Units under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders.

The Partnership shall be entitled to recognize the Record Holder as the Partner or Assignee with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person (a) shall be the Partner or Assignee (as the case may be) of record and beneficially, (b) must execute and deliver a Transfer Application and (c) shall be bound by this Agreement and shall have the rights and obligations of a Partner or Assignee (as the case may be) hereunder and as, and to the extent, provided for herein.

Section 4.4 Transfer Generally.

(a) The term “transfer,” when used in this Agreement with respect to a Partnership Interest, shall be deemed to refer to a transaction (i) by which the General Partner assigns its General Partner Interest to another Person or by which a holder of Management Incentive Units assigns its Management Incentive Units to another Person, and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange or any other disposition by law or otherwise or (ii) by which the holder of a Limited Partner Interest (other than a Management Incentive Unit) assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner or an Assignee, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.

(b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be null and void.

(c) Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of the General Partner of any or all of the shares of stock, membership interests, partnership interests or other ownership interests in the General Partner.

Section 4.5 Registration and Transfer of Limited Partner Interests.

(a) The General Partner shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Partnership will provide for the registration and transfer of Limited Partner Interests. The Transfer Agent is hereby appointed registrar and transfer agent for the purpose of registering Common Units and transfers of such Common Units as herein provided. The Partnership shall not recognize transfers of Certificates evidencing Limited Partner Interests unless such transfers are effected in the manner described in this Section 4.5. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions of Section 4.5(b), the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Common Units, the

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Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.

(b) Except as otherwise provided in Section 4.8, the General Partner shall not recognize any transfer of Limited Partner Interests until the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer and such Certificates are accompanied by a Transfer Application properly completed and duly executed by the transferee (or the transferee’s attorney-in-fact duly authorized in writing). No charge shall be imposed by the General Partner for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto. No distributions or allocations will be made in respect of the Limited Partner Interests until a properly completed Transfer Application has been delivered.

(c) Upon the receipt of proper transfer instructions from the registered owner of uncertificated Common Units, such uncertificated Common Units shall be cancelled, issuance of new equivalent uncertificated Common Units or Certificates shall be made to the holder of Common Units entitled thereto and the transaction shall be recorded upon the books of the Partnership.

(d) Limited Partner Interests may be transferred only in the manner described in this Section 4.5. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement.

(e) Until admitted as a Substituted Limited Partner pursuant to Section 10.2, the Record Holder of a Limited Partner Interest shall be an Assignee in respect of such Limited Partner Interest. Limited Partners may include custodians, nominees or any other individual or entity in its own or any representative capacity.

(f) A transferee of a Limited Partner Interest who has completed and delivered a Transfer Application shall be deemed to have (i) requested admission as a Substituted Limited Partner, (ii) agreed to comply with and be bound by and to have executed this Agreement, (iii) represented and warranted that such transferee has the right, power and authority and, if an individual, the capacity to enter into this Agreement, (iv) granted the powers of attorney set forth in this Agreement and (v) given the consents and approvals and made the waivers contained in this Agreement.

(g) The General Partner and its Affiliates shall have the right at any time to transfer their Common Units to one or more Persons.

(h) Notwithstanding the foregoing, no Executive may transfer any Management Incentive Unit, except to a Permitted Transferee, without the prior written consent of the General Partner, and any such purported transfer in conflict with the foregoing is void.

Section 4.6 Transfer of the General Partner’s General Partner Interest.

(a) Subject to Section 4.6(c) below, prior to June 30, 2017, the General Partner shall not transfer all or any part of its General Partner Interest to a Person unless such transfer (i) has been approved by the prior written consent or vote of the holders of at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) or (ii) is of all, but not less than all, of its General Partner Interest to (A) an Affiliate of the General Partner (other than an individual) or (B) another Person (other than an individual) in connection with the merger or consolidation of the General Partner with or into such other Person or the transfer by the General Partner of all or substantially all of its assets to such other Person.

(b) Subject to Section 4.6(c) below, on or after June 30, 2017, the General Partner may at its option transfer all or any of its General Partner Interest without Unitholder approval.

(c) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this

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Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability under Delaware law of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest of the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.3, be admitted to the Partnership as the General Partner immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

Section 4.7 Restrictions on Transfers.

(a) Except as provided in Section 4.7(c) below, and notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed).

(b) The General Partner may impose restrictions on the transfer of Partnership Interests if it receives an Opinion of Counsel that such restrictions are necessary to avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for federal income tax purposes. The General Partner may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.

(c) Nothing contained in this Article IV, or elsewhere in this Agreement, shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.

(d) Each certificate evidencing Partnership Interests shall bear a conspicuous legend in substantially the following form:

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF ENCORE ENERGY PARTNERS LP THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF ENCORE ENERGY PARTNERS LP UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE ENCORE ENERGY PARTNERS LP TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). ENCORE ENERGY PARTNERS GP LLC, THE GENERAL PARTNER OF ENCORE ENERGY PARTNERS LP, MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF ENCORE ENERGY PARTNERS LP BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO

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THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

Section 4.8 Eligible Holder Certifications; Non-Eligible Holders.

(a) If a transferee of a Limited Partner Interest fails to furnish a properly completed Eligible Holder Certification in a Transfer Application or if, upon receipt of such Eligible Holder Certification or otherwise, the General Partner determines that such transferee is not an Eligible Holder, the Limited Partner Interests owned by such transferee shall be subject to redemption in accordance with the provisions of Section 4.9.

(b) The General Partner may request any Limited Partner or Assignee to furnish to the General Partner, within 30 days after receipt of such request, an executed Eligible Holder Certification or such other information concerning his nationality, citizenship or other related status (or, if the Limited Partner or Assignee is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) as the General Partner may request. If a Limited Partner or Assignee fails to furnish to the General Partner within the aforementioned 30-day period such Eligible Holder Certification or other requested information or if upon receipt of such Eligible Holder Certification or other requested information the General Partner determines that a Limited Partner or Assignee is not an Eligible Holder, the Limited Partner Interests owned by such Limited Partner or Assignee shall be subject to redemption in accordance with the provisions of Section 4.9. In addition, the General Partner may require that the status of any such Limited Partner or Assignee be changed to that of a Non-Eligible Holder and, thereupon, the General Partner shall be substituted for such Non-Eligible Holder as the Limited Partner in respect of the Non-Eligible Holder’s Limited Partner Interests.

(c) The General Partner shall, in exercising voting rights in respect of Limited Partner Interests held by it on behalf of Non-Eligible Holders, distribute the votes in the same ratios as the votes of Partners (including the General Partner) in respect of Limited Partner Interests other than those of Non-Eligible Holders are cast, either for, against or abstaining as to the matter.

(d) Upon dissolution of the Partnership, a Non-Eligible Holder shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Non-Eligible Holder’s share of any distribution in kind. Such payment and assignment shall be treated for Partnership purposes as a purchase by the Partnership from the Non-Eligible Holder of its Limited Partner Interest (representing its right to receive its share of such distribution in kind).

(e) At any time after a Non-Eligible Holder can and does certify that it has become an Eligible Holder, a Non-Eligible Holder may, upon application to the General Partner, request admission as a Substituted Limited Partner with respect to any Limited Partner Interests of such Non-Eligible Holder not redeemed pursuant to Section 4.9, and upon admission of such Non-Eligible Holder pursuant to Section 10.2, the General Partner shall cease to be deemed to be the Limited Partner in respect of the Non-Eligible Holder’s Limited Partner Interests.

Section 4.9 Redemption of Partnership Interests of Non-Eligible Holders.

(a) If at any time a Limited Partner or Assignee fails to furnish an Eligible Holder Certification or other information requested within the 30-day period specified in Section 4.8(b), or if upon receipt of such Eligible Holder Certification or other information the General Partner determines, with the advice of counsel, that a Limited Partner or Assignee is not an Eligible Holder, the Partnership may, unless the Limited Partner or Assignee establishes to the satisfaction of the General Partner that such Limited Partner or Assignee is an Eligible Holder or has transferred his Partnership Interests to a Person who is an Eligible Holder and who furnishes an Eligible Holder Certification to the General Partner prior to the date fixed for redemption as provided below, redeem the Limited Partner Interest of such Limited Partner or Assignee as follows:

(i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Limited Partner or Assignee, at his last address designated on the records of the Partnership or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be

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deemed to have been given when so mailed. The notice shall specify the Redeemable Interests or, if uncertificated, upon receipt of evidence satisfactory to the General Partner of the ownership of the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon surrender of the Certificate evidencing the Redeemable Interests and that on and after the date fixed for redemption no further allocations or distributions to which the Limited Partner or Assignee would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Limited Partner Interests of the class to be so redeemed multiplied by the number of Limited Partner Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 5% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii) Upon surrender by or on behalf of the Limited Partner or Assignee, at the place specified in the notice of redemption, of (x) if certificated, the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank, or (y) if uncertificated, upon receipt of evidence satisfactory to the General Partner of the ownership of the Redeemable Interests, the Limited Partner or Assignee or his duly authorized representative shall be entitled to receive the payment therefor.

(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Limited Partner Interests.

(b) The provisions of this Section 4.9 shall also be applicable to Limited Partner Interests held by a Limited Partner or Assignee as nominee of a Person determined to be other than an Eligible Holder.

(c) Nothing in this Section 4.9 shall prevent the recipient of a notice of redemption from transferring his Limited Partner Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Limited Partner Interest certifies to the satisfaction of the General Partner in a Transfer Application that he is an Eligible Holder. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

ARTICLE V

CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS

Section 5.1 Organizational Contributions; Interim Closing.

(a) In connection with the formation of the Partnership under the Delaware Act, the General Partner made an initial Capital Contribution to the Partnership in the amount of $12.00 for the General Partner Interest in the Partnership and has been admitted as the general partner of the Partnership, and the Organizational Limited Partner made an initial Capital Contribution to the Partnership in the amount of $588.00 for a 98% Limited Partner Interest in the Partnership and has been admitted as a limited partner of the Partnership.

(b) On the Interim Closing Date, the Partnership converted the Limited Partner Interest of the Organizational Limited Partner into 10,279,639 Common Units and the General Partner Interest of the General

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Partner into 221,013 General Partner Units. Also on the Interim Closing Date, the Partnership issued to the Management Incentive Units as follows:


Name		Partnership Interest

I. Jon Brumley		143,000 Management Incentive Units
Jon S. Brumley		143,000 Management Incentive Units
Robert C. Reeves		110,000 Management Incentive Units
L. Ben Nivens		77,000 Management Incentive Units
John W. Arms		77,000 Management Incentive Units

Section 5.2 Contributions by the General Partner and its Affiliates.

(a) On the Closing Date and pursuant to the Contribution Agreement, Encore Operating, L.P. shall contribute to the Partnership, as a Capital Contribution, certain oil and natural gas properties located in the Permian Basin of West Texas in exchange for Common Units.

(b) Upon the issuance of any additional Limited Partner Interests by the Partnership, the General Partner may, in exchange for a proportionate number of General Partner Units, make additional Capital Contributions in an amount equal to the product obtained by multiplying (i) the quotient determined by dividing (A) the General Partner’s Percentage Interest by (B) 100 less the General Partner’s Percentage Interest times (ii) the amount contributed to the Partnership by the Limited Partners in exchange for such additional Limited Partner Interests. Except as set forth in Article XII, the General Partner shall not be obligated to make any additional Capital Contributions to the Partnership.

Section 5.3 Contributions by Initial Limited Partners.

(a) On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute to the Partnership cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter at the Closing Date. In exchange for such Capital Contributions by the Underwriters, the Partnership shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made in an amount equal to the quotient obtained by dividing (i) the cash contribution to the Partnership by or on behalf of such Underwriter by (ii) the Issue Price per Initial Common Unit.

(b) Upon the exercise of the Over-Allotment Option, each Underwriter shall contribute to the Partnership cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units to be purchased by such Underwriter at the Option Closing Date. In exchange for such Capital Contributions by the Underwriters, the Partnership shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made in an amount equal to the quotient obtained by dividing (i) the cash contributions to the Partnership by or on behalf of such Underwriter by (ii) the Issue Price per Initial Common Unit.

(c) No Limited Partner Interests will be issued or issuable as of or at the Closing Date other than (i) the Common Units issuable pursuant to Section 5.2(a) in aggregate number equal to , (ii) the Common Units issuable pursuant to subparagraph (a) hereof in aggregate number equal to , and (iii) the “Option Units” as such term is used in the Underwriting Agreement in an aggregate number up to issuable upon exercise of the Over-Allotment Option pursuant to subparagraph (b) hereof.

Section 5.4 Interest and Withdrawal.

No interest shall be paid by the Partnership on Capital Contributions. No Partner or Assignee shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon termination of the Partnership may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner or Assignee shall have priority over any other Partner or Assignee either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners and Assignees agree within the meaning of Section 17-502(b) of the Delaware Act.

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Section 5.5 Capital Accounts.

(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest and (ii) all items of Partnership income and gain (including Simulated Gain and income and gain exempt from tax) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest and (y) all items of Partnership deduction and loss (including Simulated Depletion and Simulated Loss) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1.

(b) For purposes of computing the amount of any item of income, gain, loss, deduction, Simulated Depletion, Simulated Gain or Simulated Loss which is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

(i) Solely for purposes of this Section 5.5, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement) of all property owned by any other Group Member that is classified as a partnership for federal income tax purposes and any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for federal income tax purposes of which a Group Member is, directly or indirectly, a partner.

(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

(iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss shall be made without regard to any election under Section 754 of the Code which may be made by the Partnership and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

(iv) Any income, gain, loss, Simulated Gain or Simulated Loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.

(v) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery, amortization or Simulated Depletion attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.5(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery, amortization or Simulated Depletion, any further deductions for such depreciation, cost recovery, amortization or Simulated Depletion attributable to such property shall be determined as if the adjusted

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basis of such property were equal to the Carrying Value of such property immediately following such adjustment.

(vi) If the Partnership’s adjusted basis in a depreciable or cost recovery property is reduced for federal income tax purposes pursuant to Section 48(q)(1) or 48(q)(3) of the Code, the amount of such reduction shall, solely for purposes hereof, be deemed to be an additional depreciation or cost recovery deduction in the year such property is placed in service and shall be allocated among the Partners pursuant to Section 6.1. Any restoration of such basis pursuant to Section 48(q)(2) of the Code shall, to the extent possible, be allocated in the same manner to the Partners to whom such deemed deduction was allocated.

(c) A transferee of a Partnership Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

(d) (i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests as consideration for the provision of services or the conversion of the General Partner’s Combined Interest to Common Units pursuant to Section 11.3(b), the Capital Account of all Partners and the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such issuance and had been allocated to the Partners at such time pursuant to Section 6.1(c) in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss, the aggregate cash amount and fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt; provided, however, that the General Partner, in arriving at such valuation, must take fully into account the fair market value of the Partnership Interests of all Partners at such time. The General Partner shall allocate such aggregate value among the assets of the Partnership (in such manner as it determines) to arrive at a fair market value for individual properties.

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized in a sale of such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Partners, at such time, pursuant to Section 6.1(c) in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate cash amount and fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined and allocated in the same manner as that provided in Section 5.5(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined and allocated by the Liquidator using such method of valuation as it may adopt.

Section 5.6 Issuances of Additional Partnership Securities.

(a) The Partnership may issue additional Partnership Securities and options, rights, warrants and appreciation rights relating to the Partnership Securities for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.

(b) Each additional Partnership Security authorized to be issued by the Partnership pursuant to Section 5.6(a) may be issued in one or more classes, or one or more series of any such classes, with such

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designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Partnership Securities), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may or shall be required to redeem the Partnership Security (including sinking fund provisions); (v) whether such Partnership Security is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Security will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Security; and (viii) the right, if any, of each such Partnership Security to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Security.

(c) The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Securities and options, rights, warrants and appreciation rights relating to Partnership Securities pursuant to this Section 5.6, (ii) the conversion of the General Partner Interest (represented by General Partner Units) or any Management Incentive Units into Common Units pursuant to the terms of this Agreement, (iii) the admission of Additional Limited Partners and (iv) all additional issuances of Partnership Securities. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Securities being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Securities or in connection with the conversion of the General Partner Interest or any Management Incentive Units into Common Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Securities are listed or admitted to trading.

(d) The Partnership shall not issue fractional Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units but for the provisions of this Section 5.6(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

Section 5.7 Limited Preemptive Right.

Except as provided in this Section 5.7 and in Section 5.2, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Security, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right, which it may from time to time assign in whole or in part to any of its Affiliates, to purchase Partnership Securities from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Securities to Persons other than the General Partner and its Affiliates, to the extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates equal to that which existed immediately prior to the issuance of such Partnership Securities.

Section 5.8 Splits and Combinations.

(a) Subject to Section 5.6(d), the Partnership may make a Pro Rata distribution of Partnership Securities to all Record Holders or may effect a subdivision or combination of Partnership Securities so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis or stated as a number of Units are proportionately adjusted.

(b) Whenever such a distribution, subdivision or combination of Partnership Securities is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Securities to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner

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shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c) Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates or uncertificated Partnership Securities to the Record Holders of Partnership Securities as of the applicable Record Date representing the new number of Partnership Securities held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Securities Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of such new Certificate or uncertificated Partnership Securities, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

Section 5.9 Fully Paid and Non-Assessable Nature of Limited Partner Interests.

All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Section 17-607 of the Delaware Act.

Section 5.10 Rights of Holders of Management Incentive Units.

(a) Vesting. If an Executive remains in Continuous Employment, the Management Incentive Units held by such Executive shall vest in three equal installments as follows: 331/3 percent on each of the Closing Date, the first anniversary of the Closing Date and the second anniversary of the Closing Date. If an Executive ceases to be in Continuous Employment, any unvested Management Incentive Units shall be immediately forfeited to the Partnership, except as expressly provided otherwise below.

(b) Voting and Other Rights. An Executive shall not be entitled to any voting rights or any Sharing Percentage with respect to a Management Incentive Unit, but for all other purposes an Executive shall have all of the rights and obligations of a Limited Partner holding Common Units hereunder.


	(c)	Termination of Employment; Forfeiture.

(i) Upon termination of an Executive’s Continuous Employment as a result of the death of such Executive, the conditions in Section 5.10(a) shall be deemed satisfied with respect to the Executive’s Management Incentive Units, and the restrictions on such units shall lapse and such units shall vest in the Executive’s legal representative, beneficiary or heir.

(ii) Upon termination of an Executive’s Continuous Employment as a result of the disability of such Executive, the Management Incentive Units held by such Executive shall continue to be subject to the restrictions set forth herein, which restrictions shall lapse and such units shall vest in the Executive. The disability of an Executive shall mean (1) the total disability of the Executive as determined in accordance with Parent’s long-term disability insurance benefit plan or (2) the total and permanent disability as determined by the Board of Directors of the General Partner in its sole discretion.

(iii) Upon termination of an Executive’s Continuous Employment for any reason other than as described in subsections (i) and (ii) above, all Management Incentive Units held by such Executive as to which the restrictions thereon shall not have previously lapsed shall be immediately forfeited to the Partnership.

(d) Common Unit Equivalents. For purposes of determining the right of a Management Incentive Unit to distributions under Section 6.3, each Management Incentive Unit will be considered to equal a number of Common Unit Equivalents determined as follows:

(i) if distributions of Available Cash per Common Unit with respect to a Quarter are less than the Stated Distribution multiplied by 1.1 (the “First Target Distribution”), each Management Incentive Unit shall represent 1.0000 Common Unit Equivalents with respect to such Quarter;

(ii) if distributions of Available Cash per Common Unit with respect to a Quarter are equal to or greater than the First Target Distribution but less than the First Target Distribution multiplied by 1.1 (the

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“Second Target Distribution”), each Management Incentive Unit shall represent 1.2500 Common Unit Equivalents with respect to such Quarter;

(iii) if distributions of Available Cash per Common Unit with respect to a Quarter are equal to or greater than the Second Target Distribution but less than the Second Target Distribution multiplied by 1.1 (the “Third Target Distribution”), each Management Incentive Unit shall represent 1.5625 Common Unit Equivalents with respect to such Quarter;

(iv) if distributions of Available Cash per Common Unit with respect to a Quarter are equal to or greater than the Third Target Distribution but less than the Third Target Distribution multiplied by 1.1 (the “Fourth Target Distribution”), each Management Incentive Unit shall represent 1.9531 Common Unit Equivalents with respect to such Quarter;

(v) if distributions of Available Cash per Common Unit with respect to a Quarter are equal to or greater than the Fourth Target Distribution but less than the Fourth Target Distribution multiplied by 1.1 (the “Fifth Target Distribution”), each Management Incentive Unit shall represent 2.4414 Common Unit Equivalents with respect to such Quarter;

(vi) if distributions of Available Cash per Common Unit with respect to a Quarter are equal to or greater than the Fifth Target Distribution but less than the Fifth Target Distribution multiplied by 1.1 (the “Sixth Target Distribution”), each Management Incentive Unit shall represent 3.0518 Common Unit Equivalents with respect to such Quarter;

(vii) if distributions of Available Cash per Common Unit with respect to a Quarter are equal to or greater than the Sixth Target Distribution but less than the Sixth Target Distribution multiplied by 1.1 (the “Seventh Target Distribution”), each Management Incentive Unit shall represent 3.8147 Common Unit Equivalents with respect to such Quarter; and

(viii) if distributions of Available Cash per Common Unit with respect to a Quarter are equal to or greater than the Seventh Target Distribution, each Management Incentive Unit shall represent 4.7684 Common Unit Equivalents.

For purposes of this Section 5.10, the determination of Available Cash per Common Unit will be tentatively determined based upon the number of Common Units represented by the then Outstanding number of Management Incentive Units under this Section 5.10(d) with respect to the previous Quarter (as adjusted for any conversions in the current Quarter). If the computation of the Available Cash per Common Unit under the previous sentence causes the number of Common Unit Equivalents to increase or decrease under the terms of this Section 5.10(d), the Available Cash per Common Unit will be recomputed using the increased or decreased number of Common Unit Equivalents. If the recomputation of the Available Cash per Common Unit taking into account the increased or decreased Common Unit Equivalents is less than (or greater than) the applicable Target Distribution that caused the Common Unit Equivalents to tentatively increase (or decrease), the Common Unit Equivalents will be the same as those Outstanding for the previous Quarter (or, if applicable, the Common Unit Equivalents associated with the level of Target Distribution which is supported following recomputation).

(e) Conversion of Management Incentive Units. Management Incentive Units shall convert into Common Units as provided in this Section 5.10(e). Immediately upon the conversion of a Management Incentive Unit into a Common Unit pursuant to this Section 5.10(e), the Executive shall possess all of the rights and obligations of a Unitholder holding a Common Unit hereunder. Common Units received upon conversion of Management Incentive Units shall be fully vested, regardless of the vesting schedule set forth in Section 5.10(a). Notwithstanding the foregoing, a Management Incentive Unit that has converted into a Common Unit pursuant to this Section 5.10(e) shall be subject to the provisions of Section 6.1(d)(x) and Section 6.4.

(i) If the Partnership makes distributions of Available Cash per Common Unit with respect to four consecutive Quarters in an amount equal to or greater than the Fourth Target Distribution multiplied by four (the “First Conversion Milestone”), the Fifth Target Distribution multiplied by four (the “Second

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Conversion Milestone”), the Sixth Target Distribution multiplied by four (the “Third Conversion Milestone”) or the Seventh Target Distribution multiplied by four (the “Fourth Conversion Milestone”), then, at any time and from time to time for so long as the Partnership makes distributions of Available Cash per Common Unit in an amount equal to or greater than the First Conversion Milestone, the Second Conversion Milestone, the Third Conversion Milestone or the Fourth Conversion Milestone, an Executive shall be entitled to convert such Executive’s Management Incentive Units, in whole or in part and whether vested or unvested, into Common Units at a conversion ratio equal to 2.4414, 3.0518, 3.8147 or 4.7864 Common Units per Management Incentive Unit, respectively. If an Executive desires to convert Management Incentive Units as provided in the immediately preceding sentence, then such Executive shall deliver to the General Partner a written notice of conversion (a “Conversion Notice”) together with any Certificates representing such Management Incentive Units duly endorsed for transfer. Upon receipt of the Conversion Notice and any Certificates representing such Management Incentive Units duly endorsed for transfer, an Executive shall be deemed to be the holder of record of the number of Common Units issuable upon conversion, notwithstanding that the Certificates representing such Common Units shall not then actually be delivered to such person. Upon conversion, each Management Incentive Unit shall be canceled by the General Partner, subject to the provisions of Section 5.10(f).

(ii) [Reserved]

(iii) If an Executive ceases Continuous Employment other than by reason of death or disability, then the Board of Directors of the General Partner may, in its sole discretion, elect to convert all or a portion of the Management Incentive Units held by such Executive into Common Units at a conversion ratio equal the number of Common Unit Equivalents then represented by a Management Incentive Unit pursuant to Section 5.10(d).

(iv) If an Executive ceases Continuous Employment due to death or disability (as described in Section 5.10(c)(i) or Section 5.10(c)(ii)), all of the Management Incentive Units held by such Executive shall be automatically converted into Common Units at a conversion ratio equal the number of Common Unit Equivalents then represented by a Management Incentive Unit pursuant to Section 5.10(d).

(v) All Management Incentive Units shall be fully vested and, at the election of the Executive, shall be convertible into Common Units at any time and from time to time following a Change-in-Control at a conversion ratio equal the number of Common Unit Equivalents represented by a Management Incentive Unit pursuant to Section 5.10(d) at the time of the Executive’s election.

(vi) Notwithstanding anything in this Section 5.10(e) to the contrary, in no event shall the Management Incentive Units, in the aggregate, be convertible into Common Units having a Percentage Interest of more than 5.1% (after giving effect to the conversion of such Management Incentive Units) (the “MIU Conversion Limit”). If at any time the Management Incentive Units would be convertible, except for the preceding sentence, into a number of Common Units that would exceed the MIU Conversion Limit, then the conversion ratio with respect to such Management Incentive Units shall be deemed to equal the conversion ratio that would result in the Management Incentive Units, in the aggregate, being convertible into Common Units having a Percentage Interest of 5.1% (after giving effect to the conversion of such Management Incentive Units). Any reduction in the deemed Common Unit Equivalents pursuant to the previous sentence shall be done on a pro rata basis, such that the Common Unit Equivalents associated with each Management Incentive Unit is reduced by an equal amount.

(vii) If the number of Common Units issued upon conversion of a Management Incentive Unit is limited by the provisions of Section 5.10(e)(vi) and the Partnership issues additional Partnership Securities prior to the Anniversary Date, then the holder who converted such Management Incentive Unit shall be entitled to receive as of the first distribution of available Cash after each Issuance Date a number of additional Common Units equal to (A) the number of Common Units which such holder would have been entitled to receive for such Management Incentive Unit if such conversion had occurred on the date of the first distribution of Available Cash after each Issuance Date (after taking into consideration any limitations in Section 5.10(e)(vi)) less (B) the number of Common Units which such holder has previously received in respect of such Management Incentive Unit. The provisions of this

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Section 5.10(e)(vii) shall be applied to each successive issuance of Partnership Securities prior to the Anniversary Date.

(f) Reissuance of Management Incentive Units. Management Incentive Units that have been forfeited or converted as provided in this Section 5.10 may be reissued, with the approval of the Conflicts Committee, as set forth in this Section 5.10(f):

(i) In the event any Management Incentive Units are forfeited to the Partnership as provided in Section 5.10(a) or Section 5.10(c)(iii), then the General Partner may, with the approval of the Conflicts Committee, reissue such Management Incentive Units to one or more Persons (a “Grantee”). In the event of any such reissuance, such Management Incentive Units shall have all of the rights and obligations under this Agreement as if such Management Incentive Units had been continuously held by the Grantee, subject to any vesting or other restrictions imposed by the Conflicts Committee.

(ii) In the event any Management Incentive Units are converted to Common Units as provided in Section 5.10(e)(i), Section 5.10(e)(iii) or Section 5.10(e)(iv), then the General Partner may, with the approval of the Conflicts Committee, reissue the Management Incentive Units that were so converted to one or more Grantees. In the event of any such reissuance, such Management Incentive Units shall have all of the rights and obligations under this Agreement as if such Management Incentive Units had been continuously held by the Grantee, subject to any vesting or other restrictions and restrictions on conversion privileges imposed by the Conflicts Committee.

(iii) In the event the Management Incentive Units are converted to Common Units and distributions of Available Cash per Common Unit with respect to a Quarter are equal to or greater than the Seventh Target Distribution, then the General Partner may, with the approval of the Conflicts Committee, reissue the Management Incentive Units that were so converted to one or more Grantees. In the event of any such reissuance, (i) the Stated Distribution with respect to such reissued Management Incentive Units shall be determined by the Conflicts Committee and (ii) the Management Incentive Units shall be subject to any vesting or other restrictions imposed by the Conflicts Committee.

(g) Deemed Distributions; Conversion Ratio Adjustments. For purposes of this Section 5.10, distributions of Available Cash with respect to a Quarter shall be deemed to have been made when the Board of Directors of the General Partner determines that such distributions shall be payable to holders of Common Units. If a conversion event described in Section 5.10(e) occurs during the period between the end of a Quarter and the date when the Board of Directors of the General Partner determines the amount of the distribution of Available Cash with respect to such Quarter, then the Board of Directors of the General Partner may determine that Management Incentive Units represent a greater or lesser number of Common Unit Equivalents based on the expected distribution of Available Cash with respect to such Quarter.

(h) Delivery of Certificates. The issuance or delivery of Certificates representing Common Units upon the conversion of Management Incentive Units shall be made without charge to an Executive or for any tax in respect of the issuance or delivery of such Certificates or the securities represented thereby, and such Certificates shall be issued or delivered in the respective names of, or in such names as may be directed by, such Executive; provided, however, that the Partnership shall not be required to pay any tax which may be payable in respect of any transfer involved in the issuance and delivery of any such Certificate in a name other than that of the Executive, and the Partnership shall not be required to issue or deliver such Certificate unless or until the Person or Persons requesting the issuance or delivery thereof shall have paid to the Partnership the amount of such tax or shall have established to the reasonable satisfaction of the Partnership that such tax has been paid; provided, further, however, that the Partnership shall not be required to issue or deliver any such Certificates to the extent such action would be in violation of federal or state securities laws.

(i) Adjustment of MIU Conversion Limit, MIU Distribution Limit and MIU Allocation Limit. In the event that Management Incentive Units are converted pursuant to Section 5.10(e) or are forfeited pursuant to Section 5.10(c), the MIU Conversion Limit, the MIU Distribution Limit and the MIU Allocation Limit (the “MIU Limits”) shall be adjusted by reducing each MIU Limit by the aggregate Percentage Interest of the forfeited or converted Management Incentive Units immediately prior to the conversion or forfeiture; provided,

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that if Management Incentive Units are subsequently reissued after forfeiture or conversion as provided in Section 5.10(f), then the MIU Limits shall again be adjusted by increasing each MIU Limit (up to a maximum of 5.1%) by the aggregate Percentage Interest of the Management Incentive Units that were reissued immediately following such reissuance.

(j) Fractional Common Units. The Partnership shall not issue fractional Common Units to a holder of Management Incentive Units upon any conversion of Management Incentive Units or upon the issuance of additional Common Units as contemplated by Section 5.10(e)(vii). If the conversion of Management Incentive Units or the issuance of additional Common Units as contemplated by Section 5.10(e)(vii), in the aggregate, would result in the issuance of fractional Common Units to such holder but for the provisions of this Section 5.10(j), each fractional Common Unit shall be rounded to the nearest whole Common Unit (and a 0.5 Common Unit shall be rounded to the next higher Common Unit).

ARTICLE VI

ALLOCATIONS AND DISTRIBUTIONS

Section 6.1 Allocations for Capital Account Purposes.

For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss (computed in accordance with Section 5.5(b)) shall be allocated among the Partners in each taxable year (or portion thereof) as provided herein below.

(a) Net Income. After giving effect to the special allocations set forth in Section 6.1(d) and any allocations to other Partnership Securities, Net Income for each taxable year and all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Income for such taxable year shall be allocated to the Partners in accordance with their respective Sharing Percentages.

(b) Net Losses. After giving effect to the special allocations set forth in Section 6.1(d) and any allocations to other Partnership Securities, Net Losses for each taxable period and all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Losses for such taxable period shall be allocated to the Partners in accordance with their respective Sharing Percentages; provided that Net Losses shall not be allocated pursuant to this Section 6.1(b) to the extent that such allocation would cause any Limited Partner to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account), instead any such Net Losses shall be allocated to the General Partner.

(c) Net Termination Gains and Losses. After giving effect to the special allocations set forth in Section 6.1(d), all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Termination Gain or Net Termination Loss for such taxable period shall be allocated in the same manner as such Net Termination Gain or Net Termination Loss is allocated hereunder. All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Section 6.3 have been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4.

(i) If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.5(d)), such Net Termination Gain shall be allocated among the Partners in the following manner (and the Capital Accounts of the Partners shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

(A) First, to each Partner having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Partners, until each such Partner has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account; and

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(B) Second, 100% to all Partners in accordance with their Percentage Interests; provided, however, that in no event shall the holders of Management Incentive Units be allocated, in the aggregate, Net Termination Gain in an amount in excess of the amount that, when all such Net Termination Gain is allocated to all Partners, would cause the Capital Accounts of the holders of the Management Incentive Units, in the aggregate, to exceed 5.1% of the Capital Accounts of all Partners immediately following the allocation of Net Termination Gain (the “MIU Allocation Limit”). If the holders of Management Incentive Units would be entitled, except for the preceding sentence, to be allocated Net Termination Gain in an amount in excess of the MIU Allocation Limit (“Excess Allocations”), then the holders of Management Incentive Units shall be deemed to hold, in the aggregate, such number of Common Unit Equivalents as would entitle such holders to an allocation of an amount of Net Termination Gain such that, when all such Net Termination Gain is allocated to all Partners, the Capital Accounts of the holders of the Management Incentive Units, in the aggregate, would equal 5.1% of the Capital Accounts of all Partners immediately following the allocation of Net Termination Gain, and all Excess Allocations shall instead be allocated to the Partners in accordance with their respective Percentage Interests (but ignoring the Percentage Interests of the holders of the Common Unit Equivalents). Any reduction in the Common Unit Equivalents pursuant to the previous sentence shall be done on a pro rata basis, such that the Common Unit Equivalents associated with each Management Incentive Unit is reduced by an equal amount.

(ii) If a Net Termination Loss is recognized (or deemed recognized pursuant to Section 5.5(d)), such Net Termination Loss shall be allocated among the Partners in the following manner:

(A) First, 100% to all Partners in the proportions of their relative Capital Accounts per Unit and per General Partner Unit, until the Capital Account in respect of each Common Unit then Outstanding, in respect of each Management Incentive Unit then Outstanding and each General Partner Unit then Outstanding have all been reduced to zero; and

(B) Second, the balance, if any, 100% to the General Partner.

(d) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

(i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Sections 6.1(d)(vi) and 6.1(d)(vii)). This Section 6.1(d)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

(ii) Chargeback of Partner Non-Recourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Non-Recourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Non-Recourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to Sections 6.1(d)(vi) and 6.1(d)(vii), with respect to such taxable period. This

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Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii) Priority Allocations. All or any portion of the remaining items of Partnership gross income or gain for the taxable period, if any, shall be allocated to the holders of Management Incentive Units in proportion to and to the extent of the excess of (A) the cumulative amount of all distributions made to such holder of Management Incentive Units with respect to each Management Incentive Unit held by such holder from the Closing Date to a date 45 days after the end of the current taxable year, over (B) the aggregate amount of such items allocated with respect to such Management Incentive Unit held by such holder pursuant to this Section 6.1(d)(iii) for the current taxable year and all previous taxable years.

(iv) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership income, gain and Simulated Gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible unless such deficit balance is otherwise eliminated pursuant to Section 6.1(d)(i) or (ii).

(v) Gross Income Allocations. In the event any Partner has a deficit balance in its Capital Account at the end of any Partnership taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership income, gain and Simulated Gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(v) were not in this Agreement.

(vi) Non-Recourse Deductions. Non-Recourse Deductions for any taxable period shall be allocated to the Partners in accordance with their respective Sharing Percentages. If the General Partner determines that the Partnership’s Non-Recourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

(vii) Partner Non-Recourse Deductions. Partner Non-Recourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Non-Recourse Debt to which such Partner Non-Recourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Non-Recourse Debt, such Partner Non-Recourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.

(viii) Non-Recourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Non-Recourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Non-Recourse Built-in Gain shall be allocated among the Partners in accordance with their respective Sharing Percentages.

(ix) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain or Simulated Gain (if the adjustment increases the basis of the asset) or loss or Simulated Loss (if the adjustment decreases such basis), and such item of gain, loss, Simulated Gain or Simulated Loss shall be specially allocated to

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the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(x) Economic Uniformity. With respect to any taxable period ending upon, or after, the date a Conversion Notice is given by a holder of Management Incentive Units pursuant to Section 5.10, items of Partnership income and gain shall be allocated 100% to each Partner holding such to be converted Management Incentive Units until each such Partner has been allocated an amount of Partnership income or gain that increases the Capital Account maintained with respect to each to be converted Management Incentive Unit to an amount equal to the product of (1) the number of Common Units into which such to be converted Management Incentive Units are to be converted and (2) the then existing Capital Account for each Common Unit. The purpose for this allocation is to establish uniformity between the Capital Accounts underlying converted Management Incentive Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates other than the Executives immediately prior to the conversion of Management Incentive Units into Common Units.

(xi) Curative Allocation.

(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. Notwithstanding the preceding sentence, Required Allocations relating to (1) Non-Recourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partnership Minimum Gain and (2) Partner Non-Recourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partner Non-Recourse Debt Minimum Gain. Allocations pursuant to this Section 6.1(d)(xi)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners. Further, allocations pursuant to this Section 6.1(d)(xi)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the General Partner determines that such allocations are likely to be offset by subsequent Required Allocations.

(B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.

(xii) Corrective Allocations. In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

(A) In the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) hereof), the General Partner shall allocate additional items of income and gain away from the holders of Management Incentive Units to the Unitholders and the General Partner, or additional items of deduction and loss away from the Unitholders and the General Partner to the holders of Management Incentive Units, to the extent that the Additional Book Basis Derivative Items allocated to the Unitholders or the General Partner exceed their Share of Additional Book Basis Derivative Items. For this purpose, the Unitholders and the General Partner shall be treated as being allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise have been allocated to the Unitholders or the General Partner under the Partnership Agreement (e.g., Additional Book Basis Derivative Items taken into

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account in computing cost of goods sold would reduce the amount of book income otherwise available for allocation among the Partners). Any allocation made pursuant to this Section 6.1(d)(xii)(A) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xii) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

(B) In the case of any negative adjustments to the Capital Accounts of the Partners resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the General Partner, that to the extent possible the aggregate Capital Accounts of the Partners will equal the amount that would have been the Capital Account balance of the Partners if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c) hereof.

(C) In making the allocations required under this Section 6.1(d)(xii), the General Partner may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(xii). The General Partner may, in its discretion, amend the provisions of this Section 6.1(d)(xii) to provide for an alternative mechanism for making special allocations to holders of Management Incentive Units and Common Units if it determines that such an alternative mechanism would be administrative convenient.

Section 6.2 Allocations for Tax Purposes.

(a) Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1.

(b) The deduction for depletion with respect to each separate oil and gas property (as defined in Section 614 of the Code) shall be computed for federal income tax purposes separately by the Partners rather than by the Partnership in accordance with Section 613A(c)(7)(D) of the Code. Except as provided in Section 6.2(c)(iii), for purposes of such computation (before taking into account any adjustments resulting from an election made by the Partnership under Section 754 of the Code), the adjusted tax basis of each oil and gas property (as defined in Section 614 of the Code) shall be allocated among the Partners in accordance with their respective Sharing Percentages.

Each Partner shall separately keep records of his share of the adjusted tax basis in each oil and gas property, allocated as provided above, adjust such share of the adjusted tax basis for any cost or percentage depletion allowable with respect to such property, and use such adjusted tax basis in the computation of its cost depletion or in the computation of his gain or loss on the disposition of such property by the Partnership.

(c) Except as provided in Section 6.2(c)(iii), for the purposes of the separate computation of gain or loss by each Partner on the sale or disposition of each separate oil and gas property (as defined in Section 614 of the Code), the Partnership’s allocable share of the “amount realized” (as such term is defined in Section 1001(b) of the Code) from such sale or disposition shall be allocated for federal income tax purposes among the Partners as follows:

(i) first, to the extent such amount realized constitutes a recovery of the Simulated Basis of the property, to the Partners in the same proportion as the depletable basis of such property was allocated to the Partners pursuant to Section 6.2(b) (without regard to any special allocation of basis under Section 6.2(c)(iii);

(ii) second, the remainder of such amount realized, if any, to the Partners so that, to the maximum extent possible, the amount realized allocated to each Partner under this Section 6.2(c)(ii) will equal such Partner’s share of the Simulated Gain recognized by the Partnership from such sale or disposition.

(iii) The Partners recognize that with respect to Contributed Property and Adjusted Property there will be a difference between the Carrying Value of such property at the time of contribution or

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revaluation, as the case may be, and the adjusted tax basis of such property at that time. All items of tax depreciation, cost recovery, amortization, adjusted tax basis of depletable properties, amount realized and gain or loss with respect to such Contributed Property and Adjusted Property shall be allocated among the Partners to take into account the disparities between the Carrying Values and the adjusted tax basis with respect to such properties in accordance with the principles of Treasury Regulation Section 1.704-3(d).

(iv) Any elections or other decisions relating to such allocations shall be made by the Board of Directors in any manner that reasonably reflects the purpose and intention of the Agreement.

(d) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, other than oil and gas properties pursuant to Section 6.2(c), items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Partners as follows:

(i) (A) In the case of a Contributed Property, such items attributable thereto shall be allocated among the Partners in the manner provided under Section 704(c) of the Code that takes into account the variation between the Agreed Value of such property and its adjusted basis at the time of contribution; and (B) any item of Residual Gain or Residual Loss attributable to a Contributed Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

(ii) (A) In the case of an Adjusted Property, such items shall (1) first, be allocated among the Partners in a manner consistent with the principles of Section 704(c) of the Code to take into account the Unrealized Gain or Unrealized Loss attributable to such property and the allocations thereof pursuant to Section 5.5(d)(i) or 5.5(d)(ii), and (2) second, in the event such property was originally a Contributed Property, be allocated among the Partners in a manner consistent with Section 6.2(d)(i)(A); and (B) any item of Residual Gain or Residual Loss attributable to an Adjusted Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

(iii) The General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) to eliminate Book-Tax Disparities.

(e) For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations for federal income tax purposes of income (including gross income) or deductions; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.2(e) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Limited Partner Interests issued and Outstanding or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.

(f) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the Partnership’s common basis of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6), Treasury Regulation Section 1.197-2(g)(3), the legislative history of Section 743 of the Code or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate

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as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.

(g) Any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(h) All items of income, gain, loss, deduction and credit recognized by the Partnership for federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(i) Each item of Partnership income, gain, loss and deduction, for federal income tax purposes, shall be determined on an annual basis and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the New York Stock Exchange on the first Business Day of each month; provided, however, that such items for the period beginning on the Closing Date and ending on the last day of the month in which the Option Closing Date or the expiration of the Over-Allotment Option occurs shall be allocated to the Partners as of the opening of the New York Stock Exchange on the first Business Day of the next succeeding month; and provided, further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the General Partner, shall be allocated to the Partners as of the opening of the New York Stock Exchange on the first Business Day of the month in which such gain or loss is recognized for federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

(j) Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

Section 6.3 Requirement and Characterization of Distributions; Distributions to Record Holders.

(a) Except as described in Section 6.3(b), Section 6.3(d) or Section 6.3(e), within 45 days following the end of each Quarter commencing with the Quarter ending on September 30, 2007, an amount equal to 100% of Available Cash with respect to such Quarter shall, subject to Section 17-607 of the Delaware Act, be distributed to the Partners in accordance with this Article VI by the Partnership to the Partners in accordance with their respective Percentage Interests as of the Record Date selected by the General Partner. All distributions required to be made under this Agreement shall be made subject to Section 17-607 of the Delaware Act.

(b) The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners.

(c) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

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(d) Notwithstanding anything in this Agreement to the contrary, in no event shall the holders of Management Incentive Units receive, in the aggregate, distributions of Available Cash with respect to a Quarter in an amount in excess of 5.1% of all distributions of Available Cash with respect to such Quarter (the “MIU Distribution Limit”). If the holders of Management Incentive Units would be entitled, except for the preceding sentence, to receive distributions of Available Cash with respect to a Quarter in an amount in excess of the MIU Distribution Limit (“Excess Available Cash”), then with respect to such Quarter the holders of Management Incentive Units shall be deemed to hold, in the aggregate, such number of Common Unit Equivalents as would entitle such holders to 5.1% of all distributions of Available Cash with respect to such Quarter and all Excess Available Cash shall be distributed by the Partnership to the Partners in accordance with their respective Percentage Interests (but ignoring the Percentage Interests of the holders of the Common Unit Equivalents). Any reduction in the deemed Common Unit Equivalents pursuant to the previous sentence shall be done on a pro rata basis, such that the Common Unit Equivalents associated with each Management Incentive Unit is reduced by an equal amount.

(e) With respect to the distribution for the Quarter in which the Closing Date occurs, the amount of Available Cash distributed to the Partners in accordance with Section 6.3(a) shall equal 100% of the Available Cash with respect to such Quarter multiplied by a fraction of which the numerator is the number of days in the period commencing on the Closing Date and ending on the last day of the Quarter in which the Closing Date occurs and of which the denominator is the number of days in such Quarter. The remaining Available Cash with respect to such Quarter shall be distributed to the Partners of the Partnership immediately prior to the closing of the Initial Closing Date Pro Rata.

Section 6.4 Special Provisions Relating to the Holders of Management Incentive Units.

The holder of a Management Incentive Unit that has converted into one or more Common Units pursuant to Section 5.10 shall not be issued a Certificate representing Common Units pursuant to Section 4.1 and shall not be permitted to transfer its converted Management Incentive Units to a Person that is not a Permitted Transferee until such time as the General Partner determines, based on advice of counsel, that a converted Management Incentive Unit should have, as a substantive matter, like intrinsic economic and United States federal income tax characteristics, in all material respects, to the intrinsic economic and United States federal income tax characteristics of the Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of such Management Incentive Units into Common Units. In connection with the condition imposed by this Section 6.4, the General Partner shall take whatever steps are required to provide economic uniformity to the converted Management Incentive Units in preparation for a transfer of such converted Management Incentive Units, including the application of Section 6.1(d)(xii); provided, however, that, except for the application of Section 6.1(d)(xii), the General Partner shall not take any such steps which would have a material adverse effect on the Unitholders holding Common Units.

ARTICLE VII

MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1 Management.

(a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner or Assignee shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness,

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including indebtedness that is convertible into Partnership Securities, and the incurring of any other obligations;

(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;

(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3 and Article XIV);

(iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;

(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

(vi) the distribution of Partnership cash;

(vii) the selection and dismissal of employees (including employees having titles such as “president,” “vice president,” “secretary” and “treasurer”) and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

(viii) the maintenance of insurance for the benefit of the Partnership Group, the Partners and Indemnitees;

(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;

(x) the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.7);

(xiii) the purchase, sale or other acquisition or disposition of Partnership Securities, or the issuance of options, rights, warrants, appreciation rights and tracking and phantom interests relating to Partnership Securities;

(xiv) the undertaking of any action in connection with the Partnership’s participation in any Group Member; and

(xv) the entering into of agreements with any of its Affiliates to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.

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(b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners and the Assignees and each other Person who may acquire an interest in Partnership Securities hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement, the Group Member Agreement of each other Group Member, the Underwriting Agreement, the Amended and Restated Administrative Services Agreement, the Contribution Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement; (ii) agrees that the General Partner (on its own or through any officer of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners or the Assignees or the other Persons who may acquire an interest in Partnership Securities; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV) shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty stated or implied by law or equity.

Section 7.2 Certificate of Limited Partnership.

The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Limited Partner.

Section 7.3 Restrictions on the General Partner’s Authority.

Except as provided in Articles XII and XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (including by way of merger, consolidation, other combination or sale of ownership interests of the Partnership’s Subsidiaries) without the approval of holders of a Unit Majority; provided, however, that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any forced sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance. Without the approval of holders of a Unit Majority, the General Partner shall not, on behalf of the Partnership, except as permitted under Sections 4.6, 11.1 and 11.2, elect or cause the Partnership to elect a successor general partner of the Partnership.

Section 7.4 Reimbursement of the General Partner.

(a) Except as provided in this Section 7.4 and elsewhere in this Agreement, the General Partner shall not be compensated for its services as a general partner or managing member of any Group Member.

(b) Subject to any limitations contained in the Amended and Restated Administrative Services Agreement, the General Partner shall be reimbursed on a quarterly basis, or such other basis as the General

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Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation and other amounts paid to any Person, including Affiliates of the General Partner to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group), and (ii) all other expenses allocable to the Partnership Group or otherwise incurred by the General Partner in connection with operating the Partnership Group’s business (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the Partnership Group. Reimbursements pursuant to this Section 7.4 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7.

(c) The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership employee benefit plans, employee programs and employee practices (including plans, programs and practices involving the issuance of Partnership Securities or options to purchase or rights, warrants or appreciation rights or phantom or tracking interests relating to Partnership Securities), or cause the Partnership to issue Partnership Securities in connection with, or pursuant to, any employee benefit plan, employee program or employee practice maintained or sponsored by the General Partner or any of its Affiliates, in each case for the benefit of employees and directors of the General Partner or its Affiliates, or any Group Member or its Affiliates, or any of them, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Securities that the General Partner or such Affiliates are obligated to provide to any employees and directors pursuant to any such employee benefit plans, employee programs or employee practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Securities purchased by the General Partner or such Affiliates from the Partnership to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.4(b). Any and all obligations of the General Partner under any employee benefit plans, employee programs or employee practices adopted by the General Partner as permitted by this Section 7.4(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or 11.2 or the transferee of or successor to all of the General Partner’s General Partner Interest pursuant to Section 4.6.

Section 7.5 Outside Activities.

(a) After the Closing Date, the General Partner, for so long as it is the General Partner of the Partnership (i) agrees that its sole business will be to act as a general partner or managing member, as the case may be, of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto (including being a limited partner in the Partnership) and (ii) shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the Registration Statement or (B) the acquiring, owning or disposing of debt or equity securities in any Group Member.

(b) Subject to the terms of Section 7.5(a), each Indemnitee (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty expressed or implied by law to any Group Member or any Partner or Assignee. None of any Group Member, any Limited Partner or any other Person shall have any rights by virtue of this Agreement, any Group Member Agreement, or the partnership relationship established hereby in any business ventures of any Indemnitee. Notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Indemnitees (other than the General Partner) in accordance with the provisions of this Section 7.5 is hereby approved by the Partnership and all Partners, (ii) it shall be deemed not to be a breach of any fiduciary duty or any other obligation of any type whatsoever of the General Partner or of any Indemnitee for the Indemnitees (other than the General

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Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership and (iii) the Indemnitees shall have no obligation hereunder or as a result of any duty expressed or implied by law to present business opportunities to the Partnership.

(c) Subject to the terms of Section 7.5(a) and Section 7.5(b), but otherwise notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Indemnitee (including the General Partner) and no Indemnitee (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership shall have any duty to communicate or offer such opportunity to the Partnership, and such Indemnitee (including the General Partner) shall not be liable to the Partnership, to any Limited Partner or any other Person for breach of any fiduciary or other duty by reason of the fact that such Indemnitee (including the General Partner) pursues or acquires for itself, directs such opportunity to another Person or does not communicate such opportunity or information to the Partnership; provided such Indemnitee does not engage in such business or activity as a result of or using confidential or proprietary information provided by or on behalf of the Partnership to such Indemnitee.

(d) The General Partner and each of its Affiliates may acquire Units or other Partnership Securities in addition to those acquired on the Closing Date and, except as otherwise provided in this Agreement, shall be entitled to exercise, at their option, all rights relating to all Units or other Partnership Securities acquired by them. The term “Affiliates” when used in this Section 7.5(d) with respect to the General Partner shall not include any Group Member.

(e) Notwithstanding anything to the contrary in this Agreement, to the extent that any provision of this Section 7.5 purports or is interpreted to have the effect of restricting, eliminating or otherwise modifying the fiduciary duties that might otherwise, as a result of Delaware or other applicable law, be owed by the General Partner to the Partnership and its Limited Partners, or to constitute a waiver or consent by the Limited Partners to any such fiduciary duty, such provisions in this Section 7.5 shall be deemed to have been approved by the Partners.

Section 7.6 Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.

(a) The General Partner or any of its Affiliates may lend to any Group Member, and any Group Member may borrow from the General Partner or any of its Affiliates, funds needed or desired by the Group Member for such periods of time and in such amounts as the General Partner may determine; provided, however, that in any such case the lending party may not charge the borrowing party interest at a rate greater than the rate that would be charged the borrowing party or impose terms less favorable to the borrowing party than would be charged or imposed on the borrowing party by unrelated lenders on comparable loans made on an arm’s-length basis (without reference to the lending party’s financial abilities or guarantees), all as determined by the General Partner. The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds. For purposes of this Section 7.6(a) and Section 7.6(b), the term “Group Member” shall include any Affiliate of a Group Member that is controlled by the Group Member.

(b) The Partnership may lend or contribute to any Group Member, and any Group Member may borrow from the Partnership, funds on terms and conditions determined by the General Partner. No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member).

Section 7.7 Indemnification.

(a) To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee; provided, that the Indemnitee shall not be indemnified and held harmless if there has been a final

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and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful; provided, further, no indemnification pursuant to this Section 7.7 shall be available to the General Partner or its Affiliates (other than a Group Member) with respect to its or their obligations incurred pursuant to the Underwriting Agreement, the Amended and Restated Administrative Services Agreement or the Contribution Agreement (other than obligations incurred by the General Partner on behalf of the Partnership). Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

(b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a determination that the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be determined that the Indemnitee is not entitled to be indemnified as authorized in this Section 7.7.

(c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(e) For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

(f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(h) The provisions of this Section 7.7 are for the benefit of the Indemnitees, their heirs, successors, assigns and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or

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repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.8 Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Partnership, the Limited Partners, the Assignees or any other Persons who have acquired interests in the Partnership Securities, for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal.

(b) Subject to its obligations and duties as General Partner set forth in Section 7.1(a), the General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.

(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner and any other Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership or to any Partner for its good faith reliance on the provisions of this Agreement.

(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates, on the one hand, and the Partnership, any Group Member, any Partner or any Assignee, on the other, any resolution or course of action by the General Partner or its Affiliates in respect of such conflict of interest shall be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the Common Units (excluding Common Units owned by the General Partner and its Affiliates), (iii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval of such resolution, and the General Partner may also adopt a resolution or course of action that has not received Special Approval. If Special Approval is sought, then it shall be presumed that, in making its decision, the Conflicts Committee acted in good faith, and if Special Approval is not sought and the Board of Directors of the General Partner determines that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above, then it shall be presumed that, in making its decision, the Board of Directors acted in good faith, and in either case, in any proceeding brought by any Limited Partner or Assignee or by or on behalf of such Limited Partner or Assignee or any other Limited Partner or Assignee or the Partnership challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the Registration Statement are hereby approved by all Partners and shall not constitute a breach of this Agreement.

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(b) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its capacity as the general partner of the Partnership as opposed to in its individual capacity, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the General Partner, or such Affiliates causing it to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. In order for a determination or other action to be in “good faith” for purposes of this Agreement, the Person or Persons making such determination or taking or declining to take such other action must believe that the determination or other action is in the best interests of the Partnership.

(c) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its capacity as the general partner of the Partnership, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then the General Partner, or such Affiliates causing it to do so, are entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner or Assignee, and the General Partner, or such Affiliates causing it to do so, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. By way of illustration and not of limitation, whenever the phrase, “at the option of the General Partner,” or some variation of that phrase, is used in this Agreement, it indicates that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner votes or transfers its General Partner Interest, to the extent permitted under this Agreement, or refrains from voting or transferring its General Partner Interest, it shall be acting in its individual capacity. The General Partner’s organizational documents may provide that determinations to take or decline to take any action in its individual, rather than representative, capacity may or shall be determined by its members, if the General Partner is a limited liability company, stockholders, if the General Partner is a corporation, or the members or stockholders of the General Partner’s general partner, if the General Partner is a limited partnership.

(d) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group other than in the ordinary course of business or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts shall be at its option.

(e) Except as expressly set forth in this Agreement, neither the General Partner nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership or any Limited Partner or Assignee and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, are agreed by the Partners to replace such other duties and liabilities of the General Partner or such other Indemnitee.

(f) The Unitholders hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve of actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

Section 7.10 Other Matters Concerning the General Partner.

(a) The General Partner may rely and shall be protected in acting or refraining from acting upon any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

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(b) The General Partner may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the advice or opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such advice or opinion.

(c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership or any Group Member.

Section 7.11 Purchase or Sale of Partnership Securities.

The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Securities. As long as Partnership Securities are held by any Group Member, such Partnership Securities shall not be considered Outstanding for any purpose, except as otherwise provided herein. The General Partner or any Affiliate of the General Partner may also purchase or otherwise acquire and sell or otherwise dispose of Partnership Securities for its own account, subject to the provisions of Articles IV and X.

Section 7.12 Registration Rights of the General Partner and its Affiliates.

(a) If (i) the General Partner or any Affiliate of the General Partner (including for purposes of this Section 7.12, any Person that is an Affiliate of the General Partner at the date hereof notwithstanding that it may later cease to be an Affiliate of the General Partner) (the “Holder”), holds Partnership Securities that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable the Holder to dispose of the number of Partnership Securities it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Securities covered by such registration statement have been sold, a registration statement under the Securities Act (including a “shelf” registration statement) registering the offering and sale of the number of Partnership Securities specified by the Holder; provided, however, that the Partnership shall not be required to effect more than three registrations pursuant to this Section 7.12(a); and provided further, however, that if the Conflicts Committee determines in good faith that the requested registration would be materially detrimental to the Partnership and its Partners because such registration would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Partnership, (y) require premature disclosure of material information that the Partnership has a bona fide business purpose for preserving as confidential or (z) render the Partnership unable to comply with requirements under applicable securities laws, then the Partnership shall have the right to postpone such requested registration for a period of not more than six months after receipt of the Holder’s request, such right pursuant to this Section 7.12(a) not to be utilized more than once in any twelve-month period. In connection with any registration pursuant to the first sentence of this Section 7.12(a), the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Securities subject to such registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Securities in such states. Except as set forth in Section 7.12(d), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

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(b) If the Partnership shall at any time propose to file a registration statement under the Securities Act for an offering of equity securities of the Partnership for cash (other than an offering relating solely to an employee benefit plan), the Partnership shall notify all Holders of such proposal and use all commercially reasonable efforts to include such number or amount of securities held by any Holder in such registration statement as the Holder shall request; provided, that the Partnership is not required to make any effort or take any action to so include the securities of the Holder once the registration statement becomes or is declared effective by the Commission, including any registration statement providing for the offering from time to time of securities pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 7.12(b) shall be an underwritten offering, then, in the event that the managing underwriter or managing underwriters of such offering advise the Partnership and the Holder in writing that in their opinion the inclusion of all or some of the Holder’s Partnership Securities would adversely and materially affect the success of the offering, the Partnership shall include in such offering only that number or amount, if any, of securities held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Except as set forth in Section 7.12(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(c) If underwriters are engaged in connection with any registration referred to in this Section 7.12, the Partnership shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not in limitation of the Partnership’s obligation under Section 7.7, the Partnership shall, to the fullest extent permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “Indemnified Persons”) from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(c) as a “claim” and in the plural as “claims”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Partnership Securities were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus (if used prior to the effective date of such registration statement), or in any summary or final prospectus or any free writing prospectus or in any amendment or supplement thereto (if used during the period the Partnership is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading; provided, however, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or any free writing prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

(d) The provisions of Section 7.12(a) and Section 7.12(b) shall continue to be applicable with respect to the General Partner (and any of the General Partner’s Affiliates) after it ceases to be a general partner of the Partnership, during a period of two years subsequent to the effective date of such cessation and for so long thereafter as is required for the Holder to sell all of the Partnership Securities with respect to which it has requested during such two-year period inclusion in a registration statement otherwise filed or that a registration statement be filed; provided, however, that the Partnership shall not be required to file successive registration statements covering the same Partnership Securities for which registration was demanded during such two-year period. The provisions of Section 7.12(c) shall continue in effect thereafter.

(e) The rights to cause the Partnership to register Partnership Securities pursuant to this Section 7.12 may be assigned (but only with all related obligations) by a Holder to a transferee or assignee of such Partnership Securities, provided (i) the Partnership is, within a reasonable time after such transfer, furnished with written

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notice of the name and address of such transferee or assignee and the Partnership Securities with respect to which such registration rights are being assigned; and (ii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 7.12.

(f) Any request to register Partnership Securities pursuant to this Section 7.12 shall (i) specify the Partnership Securities intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such Partnership Securities for distribution, (iii) describe the nature or method of the proposed offer and sale of Partnership Securities, and (iv) contain the undertaking of such Person to provide all such information and materials and take all action as may be required in order to permit the Partnership to comply with all applicable requirements in connection with the registration of such Partnership Securities.

Section 7.13 Reliance by Third Parties.

Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership’s sole party in interest, both legally and beneficially. Each Limited Partner hereby waives any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

ARTICLE VIII

BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1 Records and Accounting.

The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders and Assignees of Units or other Partnership Securities, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP.

Section 8.2 Fiscal Year.

The fiscal year of the Partnership shall be a fiscal year ending December 31.

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Section 8.3 Reports.

(a) As soon as practicable, but in no event later than 120 days after the close of each fiscal year of the Partnership, the General Partner shall cause to be mailed or made available, by any reasonable means (including posting on or accessible through the Partnership’s or the Commission’s website), to each Record Holder of a Unit as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by an independent registered public accounting firm selected by the General Partner.

(b) As soon as practicable, but in no event later than 90 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available, by any reasonable means (including posting on or accessible through the Partnership’s or the Commission’s website), to each Record Holder of a Unit, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

ARTICLE IX

TAX MATTERS

Section 9.1 Tax Returns and Information.

The Partnership shall timely file all returns of the Partnership that are required for federal, state and local income tax purposes on the basis of the accrual method and the taxable year or years that it is required by law to adopt, from time to time, as determined by the General Partner. In the event the Partnership is required to use a taxable year other than a year ending on December 31, the General Partner shall use reasonable efforts to change the taxable year of the Partnership to a year ending on December 31. The tax information reasonably required by Record Holders for federal and state income tax reporting purposes with respect to a taxable year shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable year ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.

Section 9.2 Tax Elections.

(a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Limited Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Limited Partner Interest will be deemed to be the lowest quoted closing price of the Limited Partner Interests on any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(i) without regard to the actual price paid by such transferee.

(b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

Section 9.3 Tax Controversies.

Subject to the provisions hereof, the General Partner is designated as the Tax Matters Partner (as defined in the Code) and is authorized and required to represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings.

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Section 9.4 Withholding.

Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Partner or Assignee (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Partner.

ARTICLE X

ADMISSION OF PARTNERS

Section 10.1 Admission of Initial Limited Partners.

(a) The Organizational Limited Partner, I. Jon Brumley, Jon S. Brumley, Robert C. Reeves, L. Ben Nivens and John W. Arms were admitted to the Partnership as Initial Limited Partners in respect of the Common Units and Management Incentive Units issued to them on the Interim Closing Date as described in Section 5.1(b).

(b) Upon the issuance by the Partnership of Common Units to Encore Operating, L.P. and to the Underwriters as described in Section 5.2(a) and Section 5.3, respectively, in connection with the Initial Offering, the General Partner shall admit such parties to the Partnership as Initial Limited Partners in respect of the Common Units issued to them.

Section 10.2 Admission of Substituted Limited Partners.

By transfer of a Limited Partner Interest in accordance with Article IV, the transferor shall be deemed to have given the transferee the right to seek admission as a Substituted Limited Partner subject to the conditions of, and in the manner permitted under, this Agreement. A transferor of a Certificate representing a Limited Partner Interest shall, however, only have the authority to convey to a purchaser or other transferee who does not execute and deliver a Transfer Application (a) the right to negotiate such Certificate to a purchaser or other transferee and (b) the right to transfer the right to request admission as a Substituted Limited Partner to such purchaser or other transferee in respect of the transferred Limited Partner Interests. No transferor of a Limited Partner Interest or other Person shall have any obligation or responsibility to provide a Transfer Application to a transferee or assist or participate in any way with respect to the completion or delivery thereof. Each transferee of a Limited Partner Interest (including any nominee holder or an agent acquiring such Limited Partner Interest for the account of another Person) who executes and delivers a properly completed Transfer Application shall, by virtue of such execution and delivery, be an Assignee. Such Assignee shall automatically be admitted to the Partnership as a Substituted Limited Partner with respect to the Limited Partner Interests so transferred to such Person at such time as such transfer is recorded in the books and records of the Partnership, and until so recorded, such transferee shall be an Assignee. The General Partner shall periodically, but no less frequently than on the first Business Day of each calendar quarter, cause any unrecorded transfers of Limited Partner Interests with respect to which a properly completed, duly executed Transfer Application has been received to be recorded in the books and records of the Partnership. An Assignee shall have an interest in the Partnership equivalent to that of a Limited Partner with respect to allocations and distributions, including liquidating distributions, of the Partnership. With respect to voting rights attributable to Limited Partner Interests that are held by Assignees, the General Partner shall be deemed to be the Limited Partner with respect thereto and shall, in exercising the voting rights in respect of such Limited Partner Interests on any matter, vote such Limited Partner Interests at the written direction of the Assignee who is the Record Holder of such Limited Partner Interests. If no such written direction is received, such Limited Partner Interests will not be voted. An Assignee shall have no other rights of a Limited Partner.

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Section 10.3 Admission of Successor General Partner.

A successor General Partner approved pursuant to Section 11.1 or 11.2 or the transferee of or successor to all of the General Partner Interest pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or 11.2 or the transfer of the General Partner Interest pursuant to Section 4.6, provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

Section 10.4 Admission of Additional Limited Partners.

(a) A Person (other than the General Partner, an Initial Limited Partner or a Substituted Limited Partner) who makes a Capital Contribution to the Partnership in accordance with this Agreement shall be admitted to the Partnership as an Additional Limited Partner only upon furnishing to the General Partner:

(i) evidence of acceptance in form satisfactory to the General Partner of all of the terms and conditions of this Agreement, including the power of attorney granted in Section 2.6, and

(ii) such other documents or instruments as may be required by the General Partner to effect such Person’s admission as an Additional Limited Partner.

(b) Notwithstanding anything to the contrary in this Section 10.4, no Person shall be admitted as an Additional Limited Partner without the consent of the General Partner. The admission of any Person as an Additional Limited Partner shall become effective on the date upon which the name of such Person is recorded as such in the books and records of the Partnership, following the consent of the General Partner to such admission.

Section 10.5 Amendment of Agreement and Certificate of Limited Partnership.

To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary or appropriate under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership, and the General Partner may for this purpose, among others, exercise the power of attorney granted pursuant to Section 2.6.

ARTICLE XI

WITHDRAWAL OR REMOVAL OF PARTNERS

Section 11.1 Withdrawal of the General Partner.

(a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “Event of Withdrawal”);

(i) The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;

(ii) The General Partner transfers all of its rights as General Partner pursuant to Section 4.6;

(iii) The General Partner is removed pursuant to Section 11.2;

(iv) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses

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(A)-(C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

(v) A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

(vi) (A) in the event the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) in the event the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) in the event the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) in the event the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise in the event of the termination of the General Partner.

If an Event of Withdrawal specified in Section 11.1(a)(iv), (v) or (vi)(A), (B), (C) or (E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

(b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 12:00 midnight, prevailing Central Time, on June 30, 2017, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners; provided, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel (“Withdrawal Opinion of Counsel”) that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability of any Limited Partner or any Group Member or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed); (ii) at any time after 12:00 midnight, prevailing Central Time, on June 30, 2017, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner’s withdrawal, a successor is not selected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.3.

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Section 11.2 Removal of the General Partner.

The General Partner may be removed if such removal is approved by the Unitholders holding at least 662/3% of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Unitholders of a Unit Majority. Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.3. The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.3, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the holders of Outstanding Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.3.

Section 11.3 Interest of Departing General Partner and Successor General Partner.

(a) In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Units under circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or 11.2, the Departing General Partner shall have the option, exercisable prior to the effective date of the departure of such Departing General Partner, to require its successor to purchase its General Partner Interest and its general partner interest (or equivalent interest), if any, in the other Group Members (collectively, the “Combined Interest”) in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its departure. If the General Partner is removed by the Unitholders under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the departure of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest for such fair market value of such Combined Interest of the Departing General Partner. In either event, the Departing General Partner shall be entitled to receive all reimbursements due such Departing General Partner pursuant to Section 7.4, including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing General Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.

For purposes of this Section 11.3(a), the fair market value of the Departing General Partner’s Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing General Partner’s departure, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such departure, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner’s successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest of the Departing General Partner. In making its determination, such third independent investment banking firm or other independent expert may consider the then current trading price of Units on any National Securities Exchange on which Units are then listed or

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admitted to trading, the value of the Partnership’s assets, the rights and obligations of the Departing General Partner and other factors it may deem relevant.

(b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing General Partner (or its transferee) shall become a Limited Partner and its Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner (or its transferee) as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner (or its transferee) becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest of the Departing General Partner to Common Units will be characterized as if the Departing General Partner (or its transferee) contributed its Combined Interest to the Partnership in exchange for the newly issued Common Units.

(c) If a successor General Partner is elected in accordance with the terms of Section 11.1 or 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner) and the option described in Section 11.3(a) is not exercised by the party entitled to do so, the successor General Partner shall, at the effective date of its admission to the Partnership, contribute to the Partnership cash in the amount equal to the product of the (x) quotient obtained by dividing (A) the Sharing Percentage of the General Partner Interest of the Departing General Partner by (B) a percentage equal to 100% less the Sharing Percentage of the General Partner Interest of the Departing General Partner and (y) the Net Agreed Value of the Partnership’s assets on such date. In such event, such successor General Partner shall, subject to the following sentence, be entitled to its Sharing Percentage and its Percentage Interest, as the case may be, of all Partnership allocations and distributions to which the Departing General Partner was entitled. In addition, the successor General Partner shall cause this Agreement to be amended to reflect that, from and after the date of such successor General Partner’s admission, the successor General Partner’s interest in all Partnership distributions and allocations shall be its Sharing Percentage or its Percentage Interest, as the case may be.

Section 11.4 Withdrawal of Limited Partners.

No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner’s Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.

ARTICLE XII

DISSOLUTION AND LIQUIDATION

Section 12.1 Dissolution.

The Partnership shall not be dissolved by the admission of Substituted Limited Partners or Additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1 or 11.2, the Partnership shall not be dissolved and such successor General Partner shall continue the business of the Partnership. The Partnership shall dissolve, and (subject to Section 12.2) its affairs shall be wound up, upon:

(a) an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and an Opinion of Counsel is received as provided in Section 11.1(b) or 11.2 and such successor is admitted to the Partnership pursuant to Section 10.3;

(b) an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;

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(d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

Section 12.2 Continuation of the Business of the Partnership After Dissolution.

Upon (a) dissolution of the Partnership following an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or (iii) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Section 11.1 or 11.2, then within 90 days thereafter, or (b) dissolution of the Partnership upon an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv), (v) or (vi), then, to the maximum extent permitted by law, within 180 days thereafter, the holders of a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing as a successor General Partner a Person approved by the holders of a Unit Majority. Unless such an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:

(i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;

(ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and

(iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement; provided, that the right of the holders of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability of any Limited Partner and (y) neither the Partnership nor any Group Member would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).

Section 12.3 Liquidator.

Upon dissolution of the Partnership, unless the business of the Partnership is continued pursuant to Section 12.2, the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of a Unit Majority. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of a Unit Majority. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of a Unit Majority. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

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Section 12.4 Liquidation.

The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:

(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

(b) Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

(c) All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable year of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable year (or, if later, within 90 days after said date of such occurrence).

Section 12.5 Cancellation of Certificate of Limited Partnership.

Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

Section 12.6 Return of Contributions.

The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

Section 12.7 Waiver of Partition.

To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

Section 12.8 Capital Account Restoration.

No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership. The General Partner shall be obligated to restore any negative balance in its Capital Account upon liquidation of its interest in the Partnership by the end of the taxable year of the Partnership during which such liquidation occurs, or, if later, within 90 days after the date of such liquidation.

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ARTICLE XIII

AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE

Section 13.1 Amendments to be Adopted Solely by the General Partner.

Each Partner agrees that the General Partner, without the approval of any Partner or Assignee, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

(b) admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

(c) a change that the General Partner determines to be necessary or advisable to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;

(d) a change that the General Partner determines, (i) does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect, (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be listed or admitted to trading, (iii) to be necessary or advisable in connection with action taken by the General Partner pursuant to Section 5.8 or (iv) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

(e) a change in the fiscal year or taxable year of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;

(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

(g) an amendment that the General Partner determines to be necessary or appropriate in connection with the authorization of issuance of any class or series of Partnership Securities pursuant to Section 5.6;

(h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

(i) an amendment effected, necessitated or contemplated by a Merger Agreement or Plan of Conversion approved in accordance with Section 14.3;

(j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4;

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(k) a change that the General Partner determines to be necessary or advisable to effect the reissuance of the Management Incentive Units as contemplated by Section 5.10(f) or, to the extent approved by the Conflicts Committee, a change in the definition of “Change-in-Control” or modification to other provisions of Section 5.10 relating to the vesting, forfeiture, conversion or delivery of the Management Incentive Units;

(l) a merger or conveyance or conversion pursuant to Section 14.3(d); or

(m) any other amendments substantially similar to the foregoing.

Section 13.2 Amendment Procedures.

Except as provided in Sections 13.1 and 13.3, all amendments to this Agreement shall be made in accordance with the following requirements. Amendments to this Agreement may be proposed only by the General Partner; provided, however, that the General Partner shall have no duty or obligation to propose any amendment to this Agreement and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner or Assignee and, in declining to propose an amendment, to the fullest extent permitted by law shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. A proposed amendment shall be effective upon its approval by the General Partner and the holders of a Unit Majority, unless a greater or different percentage is required under this Agreement or by Delaware law. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any such proposed amendments.

Section 13.3 Amendment Requirements.

(a) Notwithstanding the provisions of Sections 13.1 and 13.2, no provision of this Agreement that establishes a percentage of Outstanding Units (including Units deemed owned by the General Partner and its Affiliates) required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing such voting percentage unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced.

(b) Notwithstanding the provisions of Sections 13.1 and 13.2, no amendment to this Agreement may (i) enlarge the obligations of any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c) or (ii) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld at its option.

(c) Except as provided in Section 14.3, and without limitation of the General Partner’s authority to adopt amendments to this Agreement without the approval of any Partners or Assignees as contemplated in Section 13.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Units voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable law.

(e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of the holders of at least 90% of the Outstanding Units.

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Section 13.4 Special Meetings.

All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Units of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the general or specific purposes for which the special meeting is to be called. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the mailing of notice of the meeting. Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

Section 13.5 Notice of a Meeting.

Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1. The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

Section 13.6 Record Date.

For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals. If the General Partner does not set a Record Date, then (a) the Record Date for determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners shall be the close of business on the day next preceding the day on which notice is given, and (b) the Record Date for determining the Limited Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.11.

Section 13.7 Adjournment.

When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

Section 13.8 Waiver of Notice; Approval of Meeting; Approval of Minutes.

The transactions of any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove

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the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.

Section 13.9 Quorum and Voting.

The holders of a majority of the Outstanding Units of the class or classes for which a meeting has been called (including Outstanding Units deemed owned by the General Partner) represented in person or by proxy shall constitute a quorum at a meeting of Limited Partners of such class or classes unless any such action by the Limited Partners requires approval by holders of a greater percentage of such Units, in which case the quorum shall be such greater percentage. At any meeting of the Limited Partners duly called and held in accordance with this Agreement at which a quorum is present, the act of Limited Partners holding Outstanding Units that in the aggregate represent a majority of the Outstanding Units entitled to vote and be present in person or by proxy at such meeting shall be deemed to constitute the act of all Limited Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the Limited Partners holding Outstanding Units that in the aggregate represent at least such greater or different percentage shall be required. The Limited Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Limited Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Outstanding Units specified in this Agreement (including Outstanding Units deemed owned by the General Partner). In the absence of a quorum any meeting of Limited Partners may be adjourned from time to time by the affirmative vote of holders of at least a majority of the Outstanding Units entitled to vote at such meeting (including Outstanding Units deemed owned by the General Partner) represented either in person or by proxy, but no other business may be transacted, except as provided in Section 13.7.

Section 13.10 Conduct of a Meeting.

The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

Section 13.11 Action Without a Meeting.

If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage of the Outstanding Units (including Units deemed owned by the General Partner) that would be necessary to authorize or take such action at a meeting at which all the Limited Partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing. The General Partner may specify that any written ballot submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Units held by the Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Units that were not voted. If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written

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approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner, (b) approvals sufficient to take the action proposed are dated as of a date not more than 90 days prior to the date sufficient approvals are deposited with the Partnership and (c) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners.

Section 13.12 Right to Vote and Related Matters.

(a) Only those Record Holders of the Units on the Record Date set pursuant to Section 13.6 (and also subject to the limitations contained in the definition of “Outstanding”) shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.

(b) With respect to Units that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Units are registered, such other Person shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

ARTICLE XIV

MERGER OR CONVERSION

Section 14.1 Authority.

The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited (including a limited liability partnership)), or convert into any such entity, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written agreement of merger or consolidation (“Merger Agreement”), or a written plan of conversion (“Plan of Conversion”), as the case may be, in accordance with this Article XIV.

Section 14.2 Procedure for Merger, Consolidation or Conversion.

(a) Merger, consolidation or conversion of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner; provided, however, that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger, consolidation or conversion of the Partnership and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner or Assignee and, in declining to consent to a merger, consolidation or conversion, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

(b) If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:

(i) the names and jurisdictions of formation or organization of each of the business entities proposing to merge or consolidate;

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(ii) the name and jurisdiction of formation or organization of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

(iii) the terms and conditions of the proposed merger or consolidation;

(iv) the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any general or limited partner interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity, the cash, property or general or limited partner interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) which the holders of such interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights, and (ii) in the case of securities represented by certificates, upon the surrender of such certificates, which cash, property or interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership, operating agreement or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of merger and stated therein); and

(vii) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

(c) If the General Partner shall determine to consent to the conversion, the General Partner may approve and adopt a Plan of Conversion containing such terms and conditions that the General Partner determines to be necessary or appropriate.

Section 14.3 Approval by Limited Partners.

(a) Except as provided in Sections 14.3(d) and 14.3(e), the General Partner, upon its approval of the Merger Agreement or the Plan of Conversion, as the case may be, shall direct that the Merger Agreement or the Plan of Conversion, as applicable, be submitted to a vote of Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement or the Plan of Conversion, as the case may be, shall be included in or enclosed with the notice of a special meeting or the written consent.

(b) Except as provided in Sections 14.3(d) and 14.3(e), the Merger Agreement or the Plan of Conversion, as the case may be, shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority.

(c) Except as provided in Sections 14.3(d) and 14.3(e), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger or certificate of conversion pursuant to Section 14.4, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or the Plan of Conversion, as the case may be.

(d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s

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assets to, another limited liability entity which shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of the limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the sole purpose of such conversion, merger or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the governing instruments of the new entity provide the Limited Partners and the General Partner with the same rights and obligations as are herein contained.

(e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another entity if (A) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (B) the merger or consolidation would not result in an amendment to the Partnership Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (C) the Partnership is the Surviving Business Entity in such merger or consolidation, (D) each Unit Outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Unit of the Partnership after the effective date of the merger or consolidation, and (E) the number of Partnership Securities to be issued by the Partnership in such merger or consolidation do not exceed 20% of the Partnership Securities Outstanding immediately prior to the effective date of such merger or consolidation.

Section 14.4 Certificate of Merger or Conversion.

Upon the required approval by the General Partner and the Unitholders of a Merger Agreement or a Plan of Conversion, as the case may be, a certificate of merger or certificate of conversion, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

Section 14.5 Amendment of Partnership Agreement.

Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (a) effect any amendment to this Agreement or (b) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.5 shall be effective at the effective time or date of the merger or consolidation.

Section 14.6 Effect of Merger, Consolidation or Conversion.

(a) At the effective time of the certificate of merger:

(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

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(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(b) At the effective time of the certificate of conversion:

(i) the Partnership shall continue to exist, without interruption, but in the organizational form of the converted entity rather than in its prior organizational form;

(ii) all rights, title, and interests to all real estate and other property owned by the Partnership shall continue to be owned by the converted entity in its new organizational form without reversion or impairment, without further act or deed, and without any transfer or assignment having occurred, but subject to any existing liens or other encumbrances thereon;

(iii) all liabilities and obligations of the Partnership shall continue to be liabilities and obligations of the converted entity in its new organizational form without impairment or diminution by reason of the conversion;

(iv) all rights of creditors or other parties with respect to or against the prior interest holders or other owners of the Partnership in their capacities as such in existence as of the effective time of the conversion will continue in existence as to those liabilities and obligations and may be pursued by such creditors and obligees as if the conversion did not occur;

(v) a proceeding pending by or against the Partnership or by or against any of Partners in their capacities as such may be continued by or against the converted entity in its new organizational form and by or against the prior partners without any need for substitution of parties; and

(vi) the Partnership Securities that are to be converted into partnership interests, shares, evidences of ownership, or other securities in the converted entity as provided in the Plan of Conversion or certificate of conversion shall be so converted, and Partners shall be entitled only to the rights provided in the Plan of Conversion or certificate of conversion.

(c) A merger, consolidation or conversion effected pursuant to this Article shall not be deemed to result in a transfer or assignment of assets or liabilities from one entity to another.

ARTICLE XV

RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS

Section 15.1 Right to Acquire Limited Partner Interests.

(a) Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than 80% of the total Limited Partner Interests of any class then Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable at its option, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed.

(b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the Transfer Agent notice of such election to purchase (the “Notice of Election to Purchase”) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class (as of a Record Date selected by the General Partner) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in

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the English language and published in the Borough of Manhattan, New York. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Limited Partner Interests (including any rights pursuant to Articles IV, V, VI, and XII) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Limited Partner Interests, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the record books of the Transfer Agent and the Partnership, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the owner of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the owner of such Limited Partner Interests (including all rights as owner of such Limited Partner Interests pursuant to Articles IV, V, VI and XII).

(c) At any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such Limited Partner Interest to the Transfer Agent in exchange for payment of the amount described in Section 15.1(a), therefor, without interest thereon.

ARTICLE XVI

GENERAL PROVISIONS

Section 16.1 Addresses and Notices; Written Communications.

(a) Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner or Assignee under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner or Assignee at the address described below. Any notice, payment or report to be given or made to a Partner or Assignee hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Securities at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Securities by reason of any assignment or otherwise. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing on the books and records of the Transfer Agent or the Partnership is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another

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Person notifies the Transfer Agent or the Partnership of a change in his address) if they are available for the Partner or Assignee at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners and Assignees. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3. The General Partner may rely and shall be protected in relying on any notice or other document from a Partner, Assignee or other Person if believed by it to be genuine.

(b) The terms “in writing”, “written communications,” “written notice” and words of similar import shall be deemed satisfied under this Agreement by use of e-mail and other forms of electronic communication.

Section 16.2 Further Action.

The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

Section 16.3 Binding Effect.

This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 16.4 Integration.

This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 16.5 Creditors.

None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

Section 16.6 Waiver.

No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 16.7 Counterparts.

This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Unit, upon accepting the certificate evidencing such Unit or executing and delivering a Transfer Application as herein described, independently of the signature of any other party.

Section 16.8 Applicable Law.

This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

Section 16.9 Invalidity of Provisions.

If any provision of this Agreement is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not be affected thereby.

Section 16.10 Consent of Partners.

Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.

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EXHIBIT A
to the Second Amended and Restated
Agreement of Limited Partnership of
Encore Energy Partners LP

Certificate Evidencing Common Units
Representing Limited Partner Interests in
Encore Energy Partners LP


No.	Common Units

In accordance with Section 4.1 of the Second Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP, as amended, supplemented or restated from time to time (the “Partnership Agreement”), Encore Energy Partners LP, a Delaware limited partnership (the “Partnership”), hereby certifies that (the “Holder”) is the registered owner of Common Units representing limited partner interests in the Partnership (the “Common Units”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed and accompanied by a properly executed application for transfer of the Common Units represented by this Certificate. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 777 Main Street, Suite 1400, Fort Worth, Texas 76102. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement and is an Eligible Holder, (iii) granted the powers of attorney provided for in the Partnership Agreement and (iv) made the waivers and given the consents and approvals contained in the Partnership Agreement.

This Certificate shall be governed by, and construed in accordance with, the laws of the State of Delaware, without regard to principles of conflicts of laws thereof.

Exhibit A-1

ASSIGNMENT OF COMMON UNITS
IN
ENCORE ENERGY PARTNERS LP

FOR VALUE RECEIVED, hereby assigns, conveys, sells and transfers unto


(Please print or typewrite name and		(please insert Social Security or other
address of Assignee)		identifying number of Assignee)

Common Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint as its attorney-in-fact with full power of substitution to transfer the same on the books of Encore Energy Partners LP.


Date:		NOTE The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.



THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17A(d)-15		(Signature) (Signature)

No transfer of the Common Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration or transfer and an Application for Transfer of Common Units has been executed by a transferee either (a) on the form set forth below or (b) on a separate application that the Partnership will furnish on request without charge. A transferor of the Common Units shall have no duty to the transferee with respect to execution of the transfer application in order for such transferee to obtain registration of the transfer of the Common Units.

Exhibit A-4

APPLICATION FOR TRANSFER OF COMMON UNITS

Transferees of Common Units must execute and deliver this application to Encore Energy Partners LP, c/o Encore Energy Partners GP LLC, 777 Main Street, Suite 1400, Fort Worth, Texas 76102; Attn: Chief Financial Officer, to be admitted as limited partners to Encore Energy Partners LP.

The undersigned (“Assignee”) hereby applies for transfer to the name of the Assignee of the Common Units evidenced hereby and hereby certifies to Encore Energy Partners LP (the “Partnership”) that the Assignee (including to the best of Assignee’s knowledge, any person for whom the Assignee will hold the Common Units) is an Eligible Holder.¹

The Assignee (a) requests admission as a Substituted Limited Partner and agrees to comply with and be bound by, and hereby executes, the Second Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP, as amended, supplemented or restated to the date hereof (the “Partnership Agreement”), (b) represents and warrants that the Assignee has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (c) appoints the General Partner of the Partnership and, if a Liquidator shall be appointed, the Liquidator of the Partnership as the Assignee’s attorney-in-fact to execute, swear to, acknowledge and file any document, including, without limitation, the Partnership Agreement and any amendment thereto and the Certificate of Limited Partnership of the Partnership and any amendment thereto, necessary or appropriate for the Assignee’s admission as a Substituted Limited Partner and as a party to the Partnership Agreement, (d) gives the powers of attorney provided for in the Partnership Agreement, and (e) makes the waivers and gives the consents and approvals contained in the Partnership Agreement. Capitalized terms not defined herein have the meanings assigned to such terms in the Partnership Agreement.

Date:


Social Security or other identifying number of Assignee		Signature of Assignee

Purchase Price including commissions, if any		Name and Address of Assignee

Type of Entity (check one):



o Individual	o Partnership	o Corporation

o Trust	o Other (specify)

Nationality (check one):



o U.S. Citizen, Resident or Domestic Entity

o Foreign Corporation		o Non-resident Alien

¹ The term Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; (3) a public body, including a municipality; or (4) 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.

Exhibit A-5

If the U.S. Citizen, Resident or Domestic Entity box is checked, the following certification must be completed.

Under Section 1445(e) of the Internal Revenue Code of 1986, as amended (the “Code”), the Partnership must withhold tax with respect to certain transfers of property if a holder of an interest in the Partnership is a foreign person. To inform the Partnership that no withholding is required with respect to the undersigned interestholder’s interest in it, the undersigned hereby certifies the following (or, if applicable, certifies the following on behalf of the interestholder).

Complete Either A or B:

A. Individual Interestholder


	1.	I am not a non-resident alien for purposes of U.S. income taxation.

	2.	My U.S. taxpayer identification number (Social Security Number) is .

	3.	My home address is .

B. Partnership, Corporation or Other Interestholder


	1.	is not a foreign corporation, foreign partnership, foreign trust (Name of Interestholder) or foreign estate (as those terms are defined in the Code and Treasury Regulations).

	2.	The interestholder’s U.S. employer identification number is .

	3.	The interestholder’s office address and place of incorporation (if applicable) is .

The interestholder agrees to notify the Partnership within ten (10) days of the date the interestholder becomes a foreign person.

The interestholder understands that this certificate may be disclosed to the Internal Revenue Service by the Partnership and that any false statement contained herein could be punishable by fine, imprisonment or both.

Under penalties of perjury, I declare that I have examined this certification and to the best of my knowledge and belief, it is true, correct and complete and, if applicable, I further declare that I have authority to sign this document on behalf of:

Name of Interestholder

Signature and Date

Title (if applicable)

Note: If the Assignee is a broker, dealer, bank, trust company, clearing corporation, other nominee holder or an agent of any of the foregoing, and is holding for the account of any other person, this application should be completed by an officer thereof or, in the case of a broker or dealer, by a registered representative who is a member of a registered national securities exchange or a member of the Financial Industry Regulatory Authority, or, in the case of any other nominee holder, a person performing a similar function. If the Assignee is a broker, dealer, bank, trust company, clearing corporation, other nominee owner or an agent of any of the foregoing, the above certification as to any person for whom the Assignee will hold the Common Units shall be made to the best of the Assignee’s knowledge.

Exhibit A-6

APPENDIX B

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used in this prospectus. 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. The entire definitions of those terms can be viewed on the Web site at http://www.sec.gov/about/forms/regs-x.pdf.

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

Bbl/D: One Bbl per day.

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

BOE/D: One BOE per day.

Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

developed acreage: The number of acres which are 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.

exploitation: A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

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 found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

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

gross acres or gross wells: The total acres or wells, as the case may be, in which we have working interest.

MBbls: One thousand Bbls.

MBOE: One thousand BOE.

MBOE/D: One thousand BOE per day.

Mcf: One thousand cubic feet of natural gas.

Mcf/D: One Mcf per day.

Mcfe: One Mcf 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.

MMBOE: One million BOE.

MMBtu: One million British thermal units.

MMcf: One thousand Mcf.

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MMcfe: One MMcf equivalent, calculated by converting oil to natural gas equivalent at a ratio of one Bbl of oil to six Mcf of natural gas.

MMcfe/D: One MMcfe per day.

net acres or net wells: Gross acres or wells, as the case may be, multiplied by our working interest ownership percentage working interest owned by us.

net production: Production that is owned by us less royalties and production due others.

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.

productive well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.

proved developed reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. This definition of proved developed reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the Web site at http://www.sec.gov/about/forms/regs-x.pdf.

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. This definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the Web site at http://www.sec.gov/about/forms/regs-x.pdf.

proved undeveloped reserves: Proved reserves that are expected to be recovered from new wells drilled to known reservoirs on acreage yet to be drilled 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. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the Web site at http://www.sec.gov/about/forms/regs-x.pdf.

realized price: The cash market price less all expected quality, transportation and demand adjustments.

recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

reserve: That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

spot price: The cash market price without reduction for expected quality, transportation and demand adjustments.

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, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Our standardized measure does not reflect any future income tax expenses because we are not subject to federal income taxes, although we have provided for the payment of Texas franchise taxes. Standardized measure does not give effect to derivative transactions.

B-2

APPENDIX C

APPLICATION FOR TRANSFER OF COMMON UNITS

The undersigned (“Assignee”) hereby applies for transfer to the name of the Assignee of the Common Units evidenced hereby and hereby certifies to Encore Energy Partners LP (the “Partnership”) that the Assignee (including to the best of Assignee’s knowledge, any person for whom the Assignee will hold the Common Units) is an Eligible Holder.¹

The Assignee (a) requests admission as a Substituted Limited Partner and agrees to comply with and be bound by, and hereby executes, the Second Amended and Restated Agreement of Limited Partnership of the Encore Energy Partners LP, as amended, supplemented or restated to the date hereof (the “Partnership Agreement”), (b) represents and warrants that the Assignee has all right, power and authority and, if an individual, capacity necessary to enter into the Partnership Agreement, (c) appoints the General Partner of the Partnership and, if a Liquidator shall be appointed, the Liquidator of the Partnership as the Assignee’s attorney-in-fact to execute, swear to, acknowledge and file any document, including, without limitation, the Partnership Agreement and any amendment thereto and the Certificate of Limited Partnership of the Partnership and any amendment thereto, necessary or appropriate for the Assignee’s admission as a Substituted Limited Partner and as a party to the Partnership Agreement, (d) gives the powers of attorney provided for in the Partnership Agreement, and (e) makes the waivers and gives the consents and approvals contained in the Partnership Agreement. Capitalized terms not defined herein have the meanings assigned to such terms in the Partnership Agreement.

Date:




Social Security or other identifying number of Assignee		Signature of Assignee


Purchase Price including commissions, if any

Name and address of Assignee

Type of Entity (check one):


o Individual	o Partnership	o Corporation
o Trust	o Other (specify)

Nationality (check one):


o U.S. citizen, Resident or Domestic Entity		o Non-resident Alien
o Foreign Corporation

¹ The term “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: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; (3) a public body, including a municipality; or (4) 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.

C-1

If the U.S. Citizen, Resident or Domestic Entity box is checked, the following certification must be completed.

Under Section 1445(e) of the Internal Revenue Code of 1986, as amended (the “Code”), the Partnership must withhold tax with respect to certain transfers of property if a holder of an interest in the Partnership is a foreign person. To inform the Partnership that no withholding is required with respect to the undersigned interestholder’s interest in it, the undersigned hereby certifies the following (or, if applicable, certifies the following on behalf of the interestholder).

Complete Either A or B:

A. Individual Interestholder

1. I am not a non-resident alien for purposes of U.S. income taxation.

2. My U.S. taxpayer identification number (Social Security Number) is .

3. My home address is .

B. Partnership, Corporation or Other Interestholder


	1.	is not a foreign corporation, foreign partnership, foreign trust or (Name of Interestholder) foreign estate (as those terms are defined in the Code and Treasury Regulations).

2. The interestholder’s U.S. employer identification number is .

3. The interestholder’s office address and place of incorporation (if applicable) is .

The interestholder agrees to notify the Partnership within ten (10) days of the date the interestholder becomes a foreign person.

Under penalties of perjury, I declare that I have examined this certification and, to the best of my knowledge and belief, it is true, correct and complete and, if applicable, I further declare that I have authority to sign this document on behalf of:

Name of Interestholder

Signature and Date

Title (if applicable)

C-2

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS


ITEM 13.	*OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.*

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the National Association of Securities Dealers filing fee and the New York Stock Exchange listing fee, the amounts set forth below are estimates.


Securities and Exchange Commission registration fee	$	7,626
National Association of Securities Dealers filing fee		25,340
New York Stock Exchange listing fee		150,000
Legal fees and expenses		1,500,000
Accounting fees and expenses		1,150,000
Transfer agent and registrar fees		50,000
Printing expenses		750,000
Miscellaneous		167,034

Total	$	3,800,000


ITEM 14.	*INDEMNIFICATION OF DIRECTORS AND OFFICERS.*

The partnership agreement of Encore Energy Partners LP provides that the partnership will, to the fullest extent permitted by law but subject to the limitations expressly provided therein, indemnify and hold harmless its general partner, any Departing General Partner (as defined therein), any person who is or was an affiliate of the general partner, including any person who is or was a member, partner, officer, director, fiduciary or trustee of the general partner, any Departing General Partner, any Group Member (as defined therein) or any affiliate of the general partner, any Departing General Partner or any Group Member, or any person who is or was serving at the request of the general partner, including any affiliate of the general partner or any Departing General Partner or any affiliate of any Departing General Partner as an officer, director, member, partner, fiduciary or trustee of another person, or any person that the general partner designates as a Partnership Indemnitee for purposes of the partnership agreement (each, a “Partnership Indemnitee”) from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Partnership Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as a Partnership Indemnitee, provided that the Partnership Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Partnership Indemnitee is seeking indemnification, the Partnership Indemnitee acted in bad faith or engaged in fraud, willful misconduct or in the case of a criminal matter, acted with knowledge that the Partnership Indemnitee’s conduct was unlawful. This indemnification would under certain circumstances include indemnification for liabilities under the Securities Act. To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by a Partnership Indemnitee who is indemnified pursuant to the partnership agreement in defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the partnership prior to a determination that the Partnership Indemnitee is not entitled to be indemnified upon receipt by the partnership of any undertaking by or on behalf of the Partnership Indemnitee to repay such amount if it shall be determined that the Partnership Indemnitee is not entitled to be indemnified under the partnership agreement. Any indemnification under these provisions will be only out of the assets of the partnership.

Encore Energy Partners LP is authorized to purchase (or to reimburse their respective general partners for the costs of) insurance against liabilities asserted against and expenses incurred by their respective general partners, their affiliates and such other persons as the respective general partners may determine and described in the paragraph above in connection with their activities, whether or not they would have the power to

II-1

indemnify such person against such liabilities under the provisions described in the paragraphs above. Each general partner has purchased insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of the general partner or any of its direct or indirect subsidiaries.

Any underwriting agreement entered into in connection with the sale of the securities offered pursuant to this registration statement will provide for indemnification of officers and directors of the applicable general partner, including liabilities under the Securities Act.


ITEM 15.	*RECENT SALES OF UNREGISTERED SECURITIES.*

On February 13, 2007, in connection with the formation of Encore Energy Partners LP, we issued (i) the 2% general partner interest in us to Encore Energy Partners GP LLC for $12 and (ii) the 98% limited partner interest in us to Encore Partners LP Holdings LLC for $588, in each case, in an offering exempt from registration under Section 4(2) of the Securities Act.

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

There have been no other sales of unregistered securities within the past three years.


ITEM 16.	*EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.*

The following documents are filed as exhibits to this registration statement:


Exhibit
Number			Description

	1	.1	Form of Underwriting Agreement.
	3	.1†	Certificate of Limited Partnership of Encore Energy Partners LP.
	3	.2	Form of Second Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP (included as Appendix A to the Prospectus).
	3	.3†	Certificate of Formation of Encore Energy Partners GP LLC.
	3	.4†	Limited Liability Company Agreement of Encore Energy Partners GP LLC.
	4	.1	Specimen Unit Certificate (included as Exhibit A to the Second Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP, which is included as Appendix A to the Prospectus)
	5	.1†	Opinion of Baker Botts L.L.P. as to the legality of the securities being registered.
	8	.1	Opinion of Baker Botts L.L.P. relating to tax matters.
	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 on March 13, 2007).
	10	.2	First Amendment to Credit Agreement 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.
	10	.3†	Subordinated Credit Agreement dated as of March 7, 2007 by and among Encore Energy Partners Operating LLC, as borrower, Encore Energy Partners LP, as guarantor, and EAP Operating, Inc., as lender.
	10	.4	Amendment No. 1 to Subordinated Credit Agreement, dated as of July 1, 2007, by and among Encore Energy Partners Operating LLC, as borrower, Encore Energy Partners LP, as guarantor, and EAP Operating, Inc., as lender.
	10	.5†	Intercreditor Agreement dated as of March 7, 2007 by and among Bank of America, N.A., as administrative agent for the senior creditors, EAP Operating, Inc., as subordinate creditor, Encore Energy Partners Operating LLC, as borrower, and Encore Energy Partners LP, as parent and a credit party.

II-2


Exhibit
Number			Description

	10	.6	Form of Amended and Restated Administrative Services Agreement among Encore Energy Partners GP LLC, Encore Energy Partners LP, Encore Energy Partners Operating LLC and Encore Operating, L.P.
	10	.7*	Purchase and Sale Agreement dated January 16, 2007 among Clear Fork Pipeline Company, Howell Petroleum Corporation, Kerr-McGee Oil & Gas Onshore LP, and Encore Acquisition Company (incorporated by reference to Exhibit 2.1 to Encore Acquisition Company’s Current Report on Form 8-K filed on January 17, 2007).
	10	.8†	Assignment and Assumption Agreement dated as of March 6, 2007 among Encore Acquisition Company, Encore Partners GP Holdings LLC, Encore Partners LP Holdings LLC, Encore Energy Partners GP LLC, Encore Energy Partners LP, Encore Energy Partners Operating LLC and Encore Clear Fork Pipeline LLC.
	10	.9†	Form of Contribution, Conveyance and Assumption Agreement.
	10	.10†	Form of Encore Energy Partners GP LLC Long-Term Incentive Plan.
	10	.11†	Form of Indemnification Agreement.
	10	.12†	Form of Phantom Unit Award Agreement.
	21	.1†	List of Subsidiaries of Encore Energy Partners LP.
	23	.1	Consent of Ernst & Young, LLP.
	23	.2	Consent of KPMG LLP.
	23	.3	Consent of Miller and Lents, Ltd.
	23	.4†	Consent of Baker Botts L.L.P. (contained in Exhibit 5.1).
	23	.5	Consent of Baker Botts L.L.P. (contained in Exhibit 8.1).
	24	.1	Powers of Attorney (included on signature page).


*		Incorporated by reference to the filing indicated.


†		Previously filed.


ITEM 17.	*UNDERTAKINGS*

The undersigned registrant hereby undertakes:

(a) to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

(b) Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the provisions described in Item 14, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

(c) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(d) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities

II-3

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized in the City of Fort Worth, State of Texas, on August 27, 2007.

ENCORE ENERGY PARTNERS LP


	By:	Encore Energy Partners GP LLC, its General Partner

	By:	/s/ Jon S. Brumley

Jon S. Brumley

Chief Executive Officer and President

Each person whose signature appears below appoints Jon S. Brumley and Robert C. Reeves, and each of them, as his true and lawful attorney or attorneys-in-fact and agents, with full power to act with or without the others and with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including pre-effective and post-effective amendments) to this Registration Statement and any registration statement for this offering that is to be effective upon filing pursuant to Rule 462 under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing necessary and desirable to be done, as fully to all intents and purposes as he might or could do in person, hereby ratifying, approving and confirming all that said attorneys-in-fact and agents or their substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities indicated on August 27, 2007.


Signature				Title

/s/ Jon S. Brumley Jon S. Brumley				Chief Executive Officer, President and Director (Principal Executive Officer)

/s/ I. Jon Brumley I. Jon Brumley				Chairman of the Board

/s/ Robert C. Reeves Robert C. Reeves				Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer and Principal Accounting Officer)

/s/ J. Luther King, Jr. J. Luther King, Jr.				Director

/s/ Clayton E. Melton Clayton E. Melton				Director

/s/ George W. Passela George W. Passela				Director

II-5

Exhibit Index


Exhibit
Number			Description

	1	.1	Form of Underwriting Agreement.
	3	.1†	Certificate of Limited Partnership of Encore Energy Partners LP.
	3	.2	Form of Second Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP (included as Appendix A to the Prospectus).
	3	.3†	Certificate of Formation of Encore Energy Partners GP LLC.
	3	.4†	Limited Liability Company Agreement of Encore Energy Partners GP LLC.
	4	.1	Specimen Unit Certificate (included as Exhibit A to the Second Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP, which is included as Appendix A to the Prospectus)
	5	.1†	Opinion of Baker Botts L.L.P. as to the legality of the securities being registered.
	8	.1	Opinion of Baker Botts L.L.P. relating to tax matters.
	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 on March 13, 2007).
	10	.2	First Amendment to Credit Agreement 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.
	10	.3†	Subordinated Credit Agreement dated as of March 7, 2007 by and among Encore Energy Partners Operating LLC, as borrower, Encore Energy Partners LP, as guarantor, and EAP Operating, Inc., as lender.
	10	.4	Amendment No. 1 to Subordinated Credit Agreement, dated as of July 1, 2007, by and among Encore Energy Partners Operating LLC, as borrower, Encore Energy Partners LP, as guarantor, and EAP Operating, Inc., as lender.
	10	.5†	Intercreditor Agreement dated as of March 7, 2007 by and among Bank of America, N.A., as administrative agent for the senior creditors, EAP Operating, Inc., as subordinate creditor, Encore Energy Partners Operating LLC, as borrower, and Encore Energy Partners LP, as parent and a credit party.
	10	.6	Form of Amended and Restated Administrative Services Agreement among Encore Energy Partners GP LLC, Encore Energy Partners LP, Encore Energy Partners Operating LLC and Encore Operating, L.P.
	10	.7*	Purchase and Sale Agreement dated January 16, 2007 among Clear Fork Pipeline Company, Howell Petroleum Corporation, Kerr-McGee Oil & Gas Onshore LP, and Encore Acquisition Company (incorporated by reference to Exhibit 2.1 to Encore Acquisition Company’s Current Report on Form 8-K filed on January 17, 2007).
	10	.8†	Assignment and Assumption Agreement dated as of March 6, 2007 among Encore Acquisition Company, Encore Partners GP Holdings LLC, Encore Partners LP Holdings LLC, Encore Energy Partners GP LLC, Encore Energy Partners LP, Encore Energy Partners Operating LLC and Encore Clear Fork Pipeline LLC.
	10	.9†	Form of Contribution, Conveyance and Assumption Agreement.
	10	.10†	Form of Encore Energy Partners GP LLC Long-Term Incentive Plan.
	10	.11†	Form of Indemnification Agreement.
	10	.12†	Form of Phantom Unit Award Agreement.
	21	.1†	List of Subsidiaries of Encore Energy Partners LP.
	23	.1	Consent of Ernst & Young, LLP.
	23	.2	Consent of KPMG LLP.
	23	.3	Consent of Miller and Lents, Ltd.
	23	.4†	Consent of Baker Botts L.L.P. (contained in Exhibit 5.1).
	23	.5	Consent of Baker Botts L.L.P. (contained in Exhibit 8.1).
	24	.1	Powers of Attorney (included on signature page).


*		Incorporated by reference to the filing indicated.


†		Previously filed.


		Page

PROSPECTUS SUMMARY		1
Encore Energy Partners LP		1
Our Properties		1
Business Strategy		2
Competitive Strengths		2
Our Relationship with Encore Acquisition Company		3
Summary of Risk Factors		4
Other Information		6
Formation and Closing Transactions		6
Simplified Organizational Structure and Ownership of Encore Energy Partners LP		8
Management of Encore Energy Partners LP		9
Summary of Conflicts of Interest and Fiduciary Duties		10
Restrictions on Ownership of Common Units		10
The Offering		11
Summary Historical and Pro Forma Financial Data		14
Non-GAAP Financial Measures		16
Summary Historical and Pro Forma Reserve and Operating Data		18
RISK FACTORS		20
Risks Related to Our Business		20
Risks Inherent in an Investment in Us		30
Tax Risks to Common Unitholders		36
USE OF PROCEEDS		39
CAPITALIZATION		40
DILUTION		41
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS		42
General		42
Our Initial Distribution Rate		43
Unaudited Pro Forma Available Cash for the Year Ended December 31, 2006 and for the Twelve Months Ended June 30, 2007		45
Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2008		47
Assumptions and Considerations		50
HOW WE MAKE CASH DISTRIBUTIONS		56
Distributions of Available Cash		56
Management Incentive Units		56
Distributions of Cash Upon Liquidation		58
Adjustments to Capital Accounts		58
SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA		59
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		62
Overview		62
How We Evaluate Our Operations		62
Outlook		66
Factors Affecting Comparability of Future Results		67
Results of Operations for Encore Energy Partners LP		70
Liquidity and Capital Resources		79
Critical Accounting Policies and Estimates		85


		Page

New Accounting Pronouncements		87
Quantitative and Qualitative Disclosures About Market Risk		88
BUSINESS		90
Overview		90
Formation and Closing Transactions		90
Business Strategy		91
Competitive Strengths		92
Hydrocarbon Recovery		93
Our Areas of Operation		94
Our Relationship with Encore Acquisition Company		98
Crude Oil and Natural Gas Prices		102
Our Pro Forma Oil and Natural Gas Data		103
Encore Energy Partners LP Predecessor’s Oil and Natural Gas Data		107
Delivery Commitments		109
Operations		109
Environmental Matters and Regulation		112
Other Regulation of the Oil and Natural Gas Industry		115
Employees		118
Offices		118
Legal Proceedings		118
MANAGEMENT		119
Management of Encore Energy Partners		119
Directors and Executive Officers of Our General Partner		121
Reimbursement of Expenses of Our General Partner		123
Executive Compensation		123
Compensation of Directors		124
Long-Term Incentive Plan		124
Management Incentive Units		126
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		131
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		133
Distributions and Payments to Our General Partner and Its Affiliates		133
Agreements Governing the Transactions		134
Amended and Restated Administrative Services Agreement		135
Contribution, Conveyance and Assumption Agreement		136
Subordinated Term Loan		136
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		138
Conflicts of Interest		138
Fiduciary Duties		143
DESCRIPTION OF THE COMMON UNITS		146
The Units		146
Transfer Agent and Registrar		146
Transfer of Common Units		146
THE PARTNERSHIP AGREEMENT		148
Organization and Duration		148
Purpose		148
Power of Attorney		148
Capital Contributions		148
Voting Rights		149
Limited Liability		150


		Page

Issuance of Additional Securities		150
Amendment of the Partnership Agreement		151
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets		153
Termination and Dissolution		153
Liquidation and Distribution of Proceeds		154
Withdrawal or Removal of the General Partner		154
Transfer of General Partner Units		155
Transfer of Ownership Interests in the General Partner		155
Change of Management Provisions		155
Limited Call Right		155
Meetings; Voting		156
Status as Limited Partner		156
Non-Eligible Holders; Redemption		157
Indemnification		157
Reimbursement of Expenses		158
Books and Reports		158
Right to Inspect Our Books and Records		158
Registration Rights		158
UNITS ELIGIBLE FOR FUTURE SALE		159
MATERIAL TAX CONSEQUENCES		160
Partnership Status		160
Limited Partner Status		161
Tax Consequences of Unit Ownership		162
Tax Treatment of Operations		167
Disposition of Common Units		170
Uniformity of Units		172
Tax-Exempt Organizations and Non-U.S. Investors		172
Administrative Matters		173
State, Local, Foreign and Other Tax Considerations		175
INVESTMENT IN ENCORE ENERGY PARTNERS LP BY EMPLOYEE BENEFIT PLANS		176
UNDERWRITING		177
VALIDITY OF THE COMMON UNITS		182
EXPERTS		182
WHERE YOU CAN FIND MORE INFORMATION		182
FORWARD-LOOKING STATEMENTS		183
INDEX TO FINANCIAL STATEMENTS		F-1
APPENDIX A — SECOND AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF ENCORE ENERGY PARTNERS LP		A-1
APPENDIX B — GLOSSARY OF OIL AND NATURAL GAS TERMS		B-1
APPENDIX C — APPLICATION FOR TRANSFER OF COMMON UNITS		C-1
Form of Underwriting Agreement
Opinion of Baker Botts L.L.P.
First Amendment to Credit Agreement
Amendment to Subordinated Credit Agreement
Form of Amended and Restated Administrative Services Agreement
Consent of Ernst & Young LLP
Consent of KPMG LLP
Consent of Miller and Lents Ltd


	Units(1)(2)		Percentage(1)

Public Common Units		9,000,000		37.4	%
Encore Acquisition Company and its affiliates:
Common Units		14,062,247		58.3	%
General Partner Units		481,883		2.0	%
Management Incentive Units		550,000		2.3	%

Total		24,094,130		100.0	%


(1)		Does not include units to be issued upon exercise of the underwriters’ option to purchase an additional 1,350,000 common units.

(2)		We do not have any subordinated units, and our general partner is not entitled to receive any incentive distributions.


	Page

ENCORE ENERGY PARTNERS LP
Introduction		F-2
Unaudited Pro Forma Balance Sheet as of June 30, 2007		F-3
Unaudited Pro Forma Statement of Operations for the Six Months Ended June 30, 2007		F-4
Unaudited Pro Forma Statement of Operations for the Year Ended December 31, 2006		F-5
Notes to Unaudited Pro Forma Financial Statements		F-6

ENCORE ENERGY PARTNERS LP
Unaudited Combined Historical and Predecessor Carve Out Balance Sheet as of June 30, 2007		F-12
Unaudited Combined Historical and Predecessor Carve Out Statements of Operations for the Six Months Ended June 30, 2007 and 2006		F-13
Unaudited Combined Historical and Predecessor Carve Out Statements of Cash Flows for the Six Months Ended June 30, 2007 and 2006		F-14
Unaudited Combined Historical and Predecessor Carve Out Statement of Owner’s Net Equity for the Six Months Ended June 30, 2007		F-15
Notes to Unaudited Combined Historical and Predecessor Carve Out Financial Statements		F-16

ENCORE ENERGY PARTNERS LP PREDECESSOR
Report of Independent Registered Public Accounting Firm		F-25
Carve Out Balance Sheets as of December 31, 2006 and 2005		F-26
Carve Out Statements of Operations for the Years Ended December 31, 2006, 2005, and 2004		F-27
Carve Out Statements of Cash Flows for the Years Ended December 31, 2006, 2005, and 2004		F-28
Carve Out Statements of Owner’s Net Equity for the Years Ended December 31, 2006, 2005, and 2004		F-29
Notes to Carve Out Financial Statements		F-30
Supplementary Information		F-36

ENCORE ENERGY PARTNERS LP
Report of Independent Registered Public Accounting Firm		F-40
Consolidated Balance Sheet as of February 13, 2007		F-41
Notes to Consolidated Balance Sheet		F-42

ENCORE ENERGY PARTNERS GP LLC
Unaudited Consolidated Balance Sheet as of June 30, 2007		F-46
Notes to the Unaudited Consolidated Balance Sheet		F-47

ENCORE ENERGY PARTNERS GP LLC
Report of Independent Registered Public Accounting Firm		F-53
Consolidated Balance Sheet as of February 13, 2007		F-54
Notes to the Consolidated Balance Sheet		F-55

ANADARKO ELK BASIN OPERATIONS
Independent Auditors’ Report		F-56
Statements of Revenues and Direct Operating Expenses for the Years Ended December 31, 2006, 2005, and 2004		F-57
Notes to Statements of Revenues and Direct Operating Expenses		F-58

ANADARKO ELK BASIN OPERATIONS
Unaudited Statements of Revenues and Direct Operating Expenses for the Six Months Ended June 30, 2007 and 2006		F-62
Notes to Unaudited Statements of Revenues and Direct Operating Expenses		F-63


	Total
	Owner’s
	Net Equity

Balance at December 31, 2006	$	25,719
Net loss		(6,115	)
Net contributions		99,689

Balance at June 30, 2007	$	119,293


	February 13,
	2007

ASSETS
Current assets:
Contributions receivable from general partner	$	12
Contributions receivable from limited partner		588

Total assets	$	600


PARTNERS’ EQUITY
Partners’ equity:
General partner:
Contributed capital	$	12

Partner’s equity - general partner		12

Limited partner:
Contributed capital		588

Partner’s equity - limited partner		588

Total partners’ equity	$	600




ARTICLE I

DEFINITIONS
	Section 1.1	Definitions	A-1
	Section 1.2	Construction	A-14

ARTICLE II

ORGANIZATION
	Section 2.1	Formation	A-14
	Section 2.2	Name	A-14
	Section 2.3	Registered Office; Registered Agent; Principal Office; Other Offices	A-15
	Section 2.4	Purpose and Business	A-15
	Section 2.5	Powers	A-15
	Section 2.6	Power of Attorney	A-15
	Section 2.7	Term	A-16
	Section 2.8	Title to Partnership Assets	A-16
	Section 2.9	Certain Undertakings Relating to the Separateness of the Partnership	A-17

ARTICLE III

RIGHTS OF LIMITED PARTNERS
	Section 3.1	Limitation of Liability	A-18
	Section 3.2	Management of Business	A-18
	Section 3.3	Outside Activities of the Limited Partners	A-18
	Section 3.4	Rights of Limited Partners	A-18

ARTICLE IV

CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS
	Section 4.1	Certificates	A-19
	Section 4.2	Mutilated, Destroyed, Lost or Stolen Certificates	A-19
	Section 4.3	Record Holders	A-20
	Section 4.4	Transfer Generally	A-20
	Section 4.5	Registration and Transfer of Limited Partner Interests	A-20
	Section 4.6	Transfer of the General Partner’s General Partner Interest	A-21
	Section 4.7	Restrictions on Transfers	A-22
	Section 4.8	Eligible Holder Certifications; Non-Eligible Holders	A-23
	Section 4.9	Redemption of Partnership Interests of Non-Eligible Holders	A-23


ARTICLE V

CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS
	Section 5.1	Organizational Contributions; Interim Closing	A-24
	Section 5.2	Contributions by the General Partner and its Affiliates	A-25
	Section 5.3	Contributions by Initial Limited Partners	A-25
	Section 5.4	Interest and Withdrawal	A-25
	Section 5.5	Capital Accounts	A-26
	Section 5.6	Issuances of Additional Partnership Securities	A-27
	Section 5.7	Limited Preemptive Right	A-28
	Section 5.8	Splits and Combinations	A-28
	Section 5.9	Fully Paid and Non-Assessable Nature of Limited Partner Interests	A-29
	Section 5.10	Rights of Holders of Management Incentive Units	A-29

ARTICLE VI

ALLOCATIONS AND DISTRIBUTIONS
	Section 6.1	Allocations for Capital Account Purposes	A-33
	Section 6.2	Allocations for Tax Purposes	A-37
	Section 6.3	Requirement and Characterization of Distributions; Distributions to Record Holders	A-39
	Section 6.4	Special Provisions Relating to the Holders of Management Incentive Units	A-40

ARTICLE VII

MANAGEMENT AND OPERATION OF BUSINESS
	Section 7.1	Management	A-40
	Section 7.2	Certificate of Limited Partnership	A-42
	Section 7.3	Restrictions on the General Partner’s Authority	A-42
	Section 7.4	Reimbursement of the General Partner	A-42
	Section 7.5	Outside Activities	A-43
	Section 7.6	Loans from the General Partner; Loans or Contributions from the Partnership or Group Members	A-44
	Section 7.7	Indemnification	A-44
	Section 7.8	Liability of Indemnitees	A-46
	Section 7.9	Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties	A-46
	Section 7.10	Other Matters Concerning the General Partner	A-47
	Section 7.11	Purchase or Sale of Partnership Securities	A-48
	Section 7.12	Registration Rights of the General Partner and its Affiliates	A-48
	Section 7.13	Reliance by Third Parties	A-50

ARTICLE VIII

BOOKS, RECORDS, ACCOUNTING AND REPORTS
	Section 8.1	Records and Accounting	A-50
	Section 8.2	Fiscal Year	A-50
	Section 8.3	Reports	A-51


ARTICLE IX

TAX MATTERS
	Section 9.1	Tax Returns and Information	A-51
	Section 9.2	Tax Elections	A-51
	Section 9.3	Tax Controversies	A-51
	Section 9.4	Withholding	A-52

ARTICLE X

ADMISSION OF PARTNERS
	Section 10.1	Admission of Initial Limited Partners	A-52
	Section 10.2	Admission of Substituted Limited Partners	A-52
	Section 10.3	Admission of Successor General Partner	A-53
	Section 10.4	Admission of Additional Limited Partners	A-53
	Section 10.5	Amendment of Agreement and Certificate of Limited Partnership	A-53

ARTICLE XI

WITHDRAWAL OR REMOVAL OF PARTNERS
	Section 11.1	Withdrawal of the General Partner	A-53
	Section 11.2	Removal of the General Partner	A-55
	Section 11.3	Interest of Departing General Partner and Successor General Partner	A-55
	Section 11.4	Withdrawal of Limited Partners	A-56

ARTICLE XII

DISSOLUTION AND LIQUIDATION
	Section 12.1	Dissolution	A-56
	Section 12.2	Continuation of the Business of the Partnership After Dissolution	A-57
	Section 12.3	Liquidator	A-57
	Section 12.4	Liquidation	A-58
	Section 12.5	Cancellation of Certificate of Limited Partnership	A-58
	Section 12.6	Return of Contributions	A-58
	Section 12.7	Waiver of Partition	A-58
	Section 12.8	Capital Account Restoration	A-58


ARTICLE XIII

AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE
	Section 13.1	Amendments to be Adopted Solely by the General Partner	A-59
	Section 13.2	Amendment Procedures	A-60
	Section 13.3	Amendment Requirements	A-60
	Section 13.4	Special Meetings	A-61
	Section 13.5	Notice of a Meeting	A-61
	Section 13.6	Record Date	A-61
	Section 13.7	Adjournment	A-61
	Section 13.8	Waiver of Notice; Approval of Meeting; Approval of Minutes	A-61
	Section 13.9	Quorum and Voting	A-62
	Section 13.10	Conduct of a Meeting	A-62
	Section 13.11	Action Without a Meeting	A-62
	Section 13.12	Right to Vote and Related Matters	A-63

ARTICLE XIV

MERGER OR CONVERSION
	Section 14.1	Authority	A-63
	Section 14.2	Procedure for Merger, Consolidation or Conversion	A-63
	Section 14.3	Approval by Limited Partners	A-64
	Section 14.4	Certificate of Merger or Conversion	A-65
	Section 14.5	Amendment of Partnership Agreement	A-65
	Section 14.6	Effect of Merger, Consolidation or Conversion	A-65

ARTICLE XV

RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS
	Section 15.1	Right to Acquire Limited Partner Interests	A-66

ARTICLE XVI

GENERAL PROVISIONS
	Section 16.1	Addresses and Notices; Written Communications	A-67
	Section 16.2	Further Action	A-68
	Section 16.3	Binding Effect	A-68
	Section 16.4	Integration	A-68
	Section 16.5	Creditors	A-68
	Section 16.6	Waiver	A-68
	Section 16.7	Counterparts	A-68
	Section 16.8	Applicable Law	A-68
	Section 16.9	Invalidity of Provisions	A-68
	Section 16.10	Consent of Partners	A-68
	Section 16.11	Facsimile Signatures	A-69
	Section 16.12	Third-Party Beneficiaries	A-69


Dated:		Encore Energy Partners LP

Countersigned and Registered by:		By: Encore Energy Partners GP LLC, its General Partner

		By:
as Transfer Agent and Registrar		Name:

By:		By:
Authorized Signature		Secretary


TEN COM — as tenants in common		UNIF GIFT MIN ACT

TEN ENT — as tenants by the entireties		Custodian
		(Cust) (Minor)

JT TEN — as joint tenants with right of survivorship and not as tenants in common		under Uniform Gifts to Minors Act (State)