8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 8-K

CURRENT REPORT PURSUANT
TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): February 2, 2010

DENBURY RESOURCES INC.

(Exact name of Registrant as specified in its charter)

Delaware
(State or other jurisdiction
of incorporation or organization)

1-12935	20-0467835
(Commission File Number)	(I.R.S. Employer
	Identification No.)
5100 Tennyson Parkway
Suite 1200
Plano, Texas	75024
(Address of principal executive offices)	(Zip code)
Registrant’s telephone number, including area code:	(972) 673-2000

N/A

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

þ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01. Other Events

Denbury Resources Inc. (“Denbury”) is hereby filing the following documents of Encore Acquisition Company (“Encore”) to accommodate their incorporation by reference into Denbury’s existing and future registration statements on Forms S-3 and S-8 (the “Registration Statements”):

(i)	Consent of Ernst & Young LLP, independent public accounting firm for Encore Acquisition Company, attached hereto as Exhibit 23.1;
(ii)	Consent of Miller and Lents, Ltd., independent petroleum engineering firm for Encore Acquisition Company, attached as Exhibit 23.2;
(iii)	Items 1, 2, and 1A of Part I and Items 5, 7A and 9A of Part II of Encore’s Form 10-K for the year ended December 31, 2008, attached as Exhibit 99.1;
(iv)	Part I and Part II, except for Item 6 of Part II, of Encore’s Form 10-Q for the quarter ended March 31, 2009, as filed with the Commission on May 6, 2009, attached as Exhibit 99.2;
(v)	Part I and Part II, except for Item 6 of Part II, of Encore’s Form 10-Q for the quarter ended June 30, 2009, as filed with the Commission on August 5, 2009, attached as Exhibit 99.3;
(vi)	Part I and Part II, except for Item 6 of Part II, of Encore’s Form 10-Q for the quarter ended September 30, 2009, as filed with the Commission on November 2, 2009, attached as Exhibit 99.4;
(vii)	Encore’s Current Report on Form 8-K as filed with the Commission on January 25, 2010, including exhibits 99.1, 99.2 and 99.3 thereto, attached as Exhibit 99.5; and
(viii)	Encore’s Current Report on Form 8-K as filed with the Commission on February 1, 2010, including exhibits thereto, attached as Exhibit 99.6.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

See exhibit index hereto.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	Denbury Resources Inc. (Registrant)
Date: February 2, 2010	By:	/s/ Alan Rhoades
		Alan Rhoades
		Vice President--Accounting

EXHIBIT INDEX

Exhibit 23.1 — Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm.
Exhibit 23.2 — Consent of Miller and Lents, Ltd., Independent Petroleum Engineering Firm.
Exhibit 99.1 — Items 1, 2 and 1A of Part I and Items 5, 7A and 9A of Part II of Encore’s Form 10-K for the year ended December 31, 2008.
Exhibit 99.2 — Part I and Items 1, 1A and 2 of Part II of Encore Form 10-Q for the quarter ended March 31, 2009.
Exhibit 99.3 — Part I and Items 1, 1A, 2 and 4 of Part II of Encore Form 10-Q for the quarter ended June 30, 2009.
Exhibit 99.4 — Part I and Items 1, 1A and 2 of Part II of Encore Form 10-Q for the quarter ended September 30, 2009.

Exhibit 99.5 — Encore’s Current Report on Form 8-K as filed with the Commission on January 25, 2010, including exhibits 99.1, 99.2 and 99.3 thereto.

Exhibit 99.6 — Encore’s Current Report on Form 8-K as filed with the Commission on February 1, 2010, including all exhibits thereto.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the following Registration Statements:

(1)	Registration Statement (Form S-8 Nos. 333-1006, 333-70485 and 333-90398) pertaining to the Amended and Restated Stock Option Plan and the Employee Stock Purchase Plan of Denbury Resources Inc.;
(2)	Registration Statement (Form S-8 Nos. 333-27995, 333-55999, 333-63198 and 333-106253) pertaining to the Amended and Restated Stock Option Plan of Denbury Resources Inc.;
(3)	Registration Statement (Form S-8 No. 333-39172) pertaining to the Director Compensation Plan of Denbury Resources Inc.;
(4)	Registration Statement (Form S-8 Nos. 333-39218) pertaining to the Employee Stock Purchase Plan of Denbury Resources Inc.;
(5)	Registration Statement (Form S-8 No. 333-116249) pertaining to the 2004 Omnibus Stock and Incentive Plan of Denbury Resources Inc.; and
(6)	Registration Statement (Form S-8 Nos. 333-143848 and 333-160178) pertaining to the 2004 Omnibus Stock and Incentive Plan and Employee Stock Purchase Plan of Denbury Resources Inc.;

of our report dated February 24, 2009 (except for the matters related to the retrospective adoptions of SFAS No. 160 and FSP EITF 03-6-1 and the reorganization of operating segments described in Notes 2, 11 and 18 as to which the date is January 25, 2010) with respect to the consolidated financial statements of Encore Acquisition Company and of our report dated February 24, 2009 with respect to the effectiveness of internal control over financial reporting of Encore Acquisition Company, included herein.

/s/ Ernst & Young LLP

Fort Worth, Texas
February 1, 2010

EX-23.2

Exhibit 23.2

Miller and Lents, Ltd.

INTERNATIONAL OIL AND GAS CONSULTANTS

FOUNDED 1948

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

     The firm of Miller and Lents, Ltd. hereby consents to the use of its name, and to the reference to its report dated January 19, 2009 regarding Encore Acquisition Company’s Reserves and Future Net Revenues as of December 31, 2008, in Denbury Resources Inc.’s Current Report filed on Form 8-K with the United States Securities and Exchange Commission.

     The Current Report contains references to certain reports prepared by Miller and Lents, Ltd. for the exclusive use of Encore Acquisition Company. The analysis, conclusions, and methods contained in the reports are based upon information that was in existence at the time the reports were rendered and Miller and Lents, Ltd. has not updated and undertakes no duty to update anything contained in the reports. While the reports may be used as a descriptive resource, investors are advised that Miller and Lents, Ltd. has not verified information provided by others except as specifically noted in the reports, and Miller and Lents, Ltd. makes no representation or warranty as to the accuracy of such information. Moreover, the conclusions contained in such reports are based on assumptions that Miller and Lents, Ltd. believed were reasonable at the time of their preparation and that are described in such reports in reasonable detail. However, there are a wide range on uncertainties and risks that are outside of the control of Miller and Lents, Ltd. which may impact these assumptions, including but not limited to unforeseen market changes, actions of governments or individuals, natural events, economic changes, and changes of laws and regulations or interpretation of laws and regulations.

MILLER AND LENTS, LTD. Texas Registered Engineering Firm No. F-1442
By:	/s/ Carl D. Richard
	Carl D. Richard, p.e.
	Senior Vice President

Houston, Texas
February 1, 2010

Two Houston Center • 909 Fannin Street, Suite 1300 • Houston, Texas 77010
Telephone 713-651-9455 • Telefax 713-654-9914 • e-mail: mail@millerandlents.com

EX-99.1

Exhibit 99.1

Excerpts from the Form 10-K of Encore Acquisition Company for the year ended December 31, 2008

ENCORE ACQUISITION COMPANY

GLOSSARY

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

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

•  Bbl/D.  One Bbl per day.

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

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

•  BOE/D.  One BOE per day.

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

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

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

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

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

•  Dry Hole or Unsuccessful 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 costs.

•  EAC.  Encore Acquisition Company, a publicly traded Delaware corporation, together with its subsidiaries.

•  ENP.  Encore Energy Partners LP, a publicly traded Delaware limited partnership, together with its subsidiaries.

•  Exploratory Well.  A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously producing oil or natural gas in another reservoir, or to extend a known reservoir.

•  Farm-out.  Transfer of all or part of the operating rights from the working interest holder to an assignee, who assumes all or some of the burden of development, in return for an interest in the property. The assignor usually retains an overriding royalty, but may retain any type of interest.

•  FASB.  Financial Accounting Standards Board.

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

•  GAAP.  Accounting principles generally accepted in the United States.

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

•  Horizontal Drilling.  A drilling operation in which a portion of a well is drilled horizontally within a productive or potentially productive formation. This operation usually yields a well which has the ability to produce higher volumes than a vertical well drilled in the same formation.

•  Lease Operations Expense (“LOE”).  All direct and allocated indirect costs of producing oil and natural gas after completion of drilling and before removal of production from the property. Such costs include labor, superintendence, supplies, repairs, maintenance, and direct overhead charges.

•  LIBOR.  London Interbank Offered Rate.

•  MBbl.  One thousand Bbls.

•  MBOE.  One thousand BOE.

•  MBOE/D.  One thousand BOE per day.

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

•  Mcf/D.  One Mcf per day.

•  Mcfe.  One 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.

•  MMBbl.  One million Bbls.

•  MMBOE.  One million BOE.

•  MMBtu.  One million British thermal units. One British thermal unit is the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

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

•  Natural Gas Liquids (“NGLs”).  The combination of ethane, propane, butane, and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

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

•  Net Production.  Production owned by an entity less royalties, net profits interests, and production due others.

•  Net Profits Interest.  An interest that entitles the owner to a specified share of net profits from production of hydrocarbons.

•  NYMEX.  New York Mercantile Exchange.

•  NYSE.  The New York Stock Exchange.

•  Oil.  Crude oil, condensate, and NGLs.

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

•  Present Value of Future Net Revenues (“PV-10”).  The present value of estimated future revenues to be generated from the production of proved reserves, net of estimated future production and development costs, using prices and costs as of the date of estimation without future escalation, without

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giving effect to commodity derivative activities, non-property related expenses such as general and administrative expenses, debt service, depletion, depreciation, and amortization, and income taxes, discounted at an annual rate of 10 percent.

•  Production Margin.  Oil and natural gas wellhead revenues less production expenses.

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

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

•  Proved Reserves.  The estimated quantities of crude oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions.

•  Proved Undeveloped Reserves.  Proved reserves that are expected to be recovered from new wells on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves include unrealized production response from enhanced recovery techniques that have been proved effective by actual tests in the area and in the same reservoir.

•  Recompletion.  The completion for production of an existing well bore in another formation from that in which the well has been previously completed.

•  Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

•  Royalty.  An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

•  SEC.  The United States Securities and Exchange Commission.

•  Secondary Recovery.  Enhanced recovery of oil or natural gas from a reservoir beyond the oil or natural gas that can be recovered by normal flowing and pumping operations. Secondary recovery techniques involve maintaining or enhancing reservoir pressure by injecting water, gas, or other substances into the formation. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and waterflooding.

•  SFAS.  Statement of Financial Accounting Standards.

•  Standardized Measure.  Future cash inflows from proved oil and natural gas reserves, less future production costs, development costs, net abandonment costs, and income taxes, discounted at 10 percent per annum to reflect the timing of future net cash flows. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of estimated future income taxes.

•  Successful Well.  A well capable of producing oil and/or natural gas in commercial quantities.

•  Tertiary Recovery.  An enhanced recovery operation that normally occurs after waterflooding in which chemicals or natural gases are used as the injectant.

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

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

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

•  Working Interest.  An interest in an oil or natural gas lease that gives the owner the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the production and development costs.

•  Workover.  Operations on a producing well to restore or increase production.

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ENCORE ACQUISITION COMPANY

References in this Report to “EAC,” “we,” “our,” “us,” or similar terms refer to Encore Acquisition Company and its subsidiaries. References in this Report to “ENP” refers to Encore Energy Partners LP and its subsidiaries. The financial position, results of operations, and cash flows of ENP are consolidated with those of EAC. This Report contains forward-looking statements, which give our current expectations and forecasts of future events. The Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for forward-looking statements made by us or on our behalf. Please read “Item 1A. Risk Factors” for a description of various factors that could materially affect our ability to achieve the anticipated results described in the forward-looking statements. Certain terms commonly used in the oil and natural gas industry and in this Report are defined above under the caption “Glossary.” In addition, all production and reserve volumes disclosed in this Report represent amounts net to us, unless otherwise noted.

PART I

ITEMS 1 and 2.  BUSINESS AND PROPERTIES

General

Our Business.  We are a Delaware corporation engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States. Since 1998, we have acquired producing properties with proven reserves and leasehold acreage and grown the production and proven reserves by drilling, exploring, and reengineering or expanding existing waterflood projects. Our properties — and our oil and natural gas reserves — are located in four core areas:

•  the Cedar Creek Anticline (“CCA”) in the Williston Basin of Montana and North Dakota;

•  the Permian Basin of West Texas and southeastern New Mexico;

•  the Rockies, which includes non-CCA assets in the Williston, Big Horn, and Powder River Basins in Wyoming, Montana, and North Dakota, and the Paradox Basin in southeastern Utah; and

•  the Mid-Continent area, which includes the Arkoma and Anadarko Basins in Oklahoma, the North Louisiana Salt Basin, the East Texas Basin, and the Mississippi Salt Basin.

Proved Reserves.  Our estimated total proved reserves at December 31, 2008 were 134.5 MMBbls of oil and 307.5 Bcf of natural gas, based on December 31, 2008 spot market prices of $44.60 per Bbl for oil and $5.62 per Mcf for natural gas. On a BOE basis, our proved reserves were 185.7 MMBOE at December 31, 2008, of which approximately 72 percent was oil and approximately 80 percent was proved developed. Based on 2008 production, our ratio of reserves to production was approximately 12.9 years for total proved reserves and 10.3 years for proved developed reserves as of December 31, 2008.

Most Valuable Asset.  The CCA represented approximately 40 percent of our total proved reserves as of December 31, 2008 and is our most valuable asset today and in the foreseeable future. A large portion of our future success revolves around current and future CCA exploitation and production through primary, secondary, and tertiary recovery techniques.

Drilling.  In 2008, we drilled 88 gross (67.8 net) operated productive wells and participated in drilling 194 gross (37.0 net) non-operated productive wells for a total of 282 gross (104.8 net) productive wells. Also in 2008, we drilled 7 gross (4.9 net) operated dry holes and participated in drilling another 6 gross (1.9 net) dry holes for a total of 13 gross (6.8 net) dry holes. This represents a success rate of over 95 percent during 2008. We invested $619.0 million in development, exploitation, and exploration activities in 2008, of which $14.7 million related to exploratory dry holes.

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Oil and Natural Gas Reserve Replacement.  Our average reserve replacement for the three years ended December 31, 2008 was 125 percent. The following table sets forth the calculation of our reserve replacement for the periods indicated:

	Year Ended December 31,									Three-Year
	2008			2007			2006			Average
	(In MBOE, except percentages)
Acquisition Reserve Replacement:
Changes in Proved Reserves:
Acquisitions of minerals-in-place		1,303			43,146			64			14,838
Divided by:
Production		14,446			13,539			11,244			13,076
Acquisition Reserve Replacement		9	%		319	%		1	%		113	%
Development Reserve Replacement:
Changes in Proved Reserves:
Extensions, discoveries, and improved recovery		19,952			15,983			27,504			21,146
Revisions of previous estimates		(52,432	)		896			(7,461	)		(19,666	)
Total development program		(32,480	)		16,879			20,043			1,480
Divided by:
Production		14,446			13,539			11,244			13,076
Development Reserve Replacement		(225	)%		125	%		178	%		11	%
Total Reserve Replacement:
Changes in Proved Reserves:
Acquisitions of minerals-in-place		1,303			43,146			64			14,838
Extensions, discoveries, and improved recovery		19,952			15,983			27,504			21,146
Revisions of previous estimates		(52,432	)		896			(7,461	)		(19,666	)
Total reserve additions		(31,177	)		60,025			20,107			16,318
Divided by:
Production		14,446			13,539			11,244			13,076
Total Reserve Replacement		(216	)%		443	%		179	%		125	%

During the three years ended December 31, 2008, we invested $1.0 billion in acquiring proved oil and natural gas properties and leasehold acreage and $1.3 billion on development, exploitation, and exploration.

Given the inherent decline of reserves resulting from production, we must more than offset produced volumes with new reserves in order to grow. Management uses reserve replacement as an indicator of our ability to replenish annual production volumes and grow our reserves. Management believes that reserve replacement is relevant and useful information as it is commonly used to evaluate the performance and prospects of entities engaged in the production and sale of depleting natural resources. It should be noted that reserve replacement is a statistical indicator that has limitations. As an annual measure, reserve replacement is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. The predictive and comparative value of reserve replacement is also limited for the same reasons. In addition, since reserve replacement does not consider the cost or timing of future production of new reserves or the prices used to determine period end reserve volumes, it cannot be used as a measure of value creation. Reserve replacement does not distinguish between changes in reserve quantities that are developed and those that will require additional time and funding to develop. The lower commodity prices and higher service costs at December 31, 2008 had the effect of decreasing the economic life of our oil and natural gas properties and making development of some previously recorded undeveloped reserves uneconomic.

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ENCORE ACQUISITION COMPANY

Encore Energy Partners.  As of February 18, 2009, we owned 20,924,055 of ENP’s outstanding common units, representing an approximate 62 percent limited partner interest. Through our indirect ownership of ENP’s general partner, we also hold all 504,851 general partner units, representing a 1.5 percent general partner interest in ENP. As we control ENP’s general partner, ENP’s financial position, results of operations, and cash flows are consolidated with ours.

In February 2008, we sold certain oil and natural gas producing properties and related assets in the Permian and Williston Basins to ENP. The consideration for the sale consisted of approximately $125.3 million in cash and 6,884,776 common units representing limited partner interests in ENP.

In January 2009, we sold certain oil and natural gas producing properties and related assets in the Arkoma Basin and royalty interest properties in Oklahoma as well as 10,300 unleased mineral acres to ENP. The purchase price was $49 million in cash, subject to customary adjustments (including a reduction in the purchase price for acquisition-related commodity derivative premiums of approximately $3 million).

Financial Information About Operating Segments.  We have operations in only one industry segment: the oil and natural gas exploration and production industry in the United States. However, we are organizationally structured along two operating segments: EAC Standalone and ENP. The contribution of each operating segment to revenues and operating income (loss), and the identifiable assets and liabilities attributable to each operating segment, are set forth in Note 18 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

Business Strategy

Our primary business objective is to maximize shareholder value by growing production, repaying debt or repurchasing shares of our common stock, prudently investing internally generated cash flows, efficiently operating our properties, and maximizing long-term profitability. Our strategy for achieving this objective is to:

•  Maintain a development program to maximize existing reserves and production.  Our technological expertise, combined with our proficient field operations and reservoir engineering, has allowed us to increase production on our properties through infill, offset, and re-entry drilling, workovers, and recompletions. Our plan is to maintain an inventory of exploitation and development projects that provide a good source of future production.

•  Utilize enhanced oil recovery techniques to maximize existing reserves and production.  We budget a portion of internally generated cash flows for secondary and tertiary recovery projects that are longer-term in nature to increase production and proved reserves on our properties. Throughout our Williston and Permian Basin properties, we have successfully used waterfloods to increase production. On certain of our non-operated properties in the Rockies, a tertiary recovery technique that uses carbon dioxide instead of water is being used successfully. Throughout our Bell Creek properties, we have successfully used a polymer injection program to increase our production. We believe that these enhanced oil recovery projects will continue to be a source of reserve and production growth.

•  Expand our reserves, production, and development inventory through a disciplined acquisition program.  Using our experience, we have developed and refined an acquisition program designed to increase our reserves and complement our core properties. We have a staff of engineering and geoscience professionals who manage our core properties and use their experience and expertise to target and evaluate attractive acquisition opportunities. Following an acquisition, our technical professionals seek to enhance the value of the new assets through a proven development and exploitation program. We will continue to evaluate acquisition opportunities with the same disciplined commitment to acquire assets that fit our existing portfolio of properties and create value for our shareholders.

•  Explore for reserves.  We believe exploration programs can provide a rate of return comparable to property acquisitions in certain areas. We seek to acquire undeveloped acreage and/or enter into

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development arrangements to explore in areas that complement our existing portfolio of properties. Successful exploration projects would expand our existing fields and could set up multi-well exploitation projects in the future.

•  Operate in a cost effective, efficient, and safe manner.  As of December 31, 2008, we operated properties representing approximately 79 percent of our proved reserves, which allows us to better control expenses, capital allocation, operate in a safe manner, and control timing of investments.

Challenges to Implementing Our Strategy.  We face a number of challenges to implementing our strategy and achieving our goals. One challenge is to generate superior rates of return on our investments in a volatile commodity pricing environment, while replenishing our development inventory. Changing commodity prices and increased costs of goods and services affect the rate of return on property acquisitions, and the amount of our internally generated cash flows, and, in turn, can affect our capital budget. For example, if cash flow is invested in periods of higher commodity prices, a subsequent decline in commodity prices could result in a lower rate of return, if any. In addition to commodity price risk, we face strong competition from other independents and major oil and natural gas companies. Our views and the views of our competitors about future commodity prices affect our success in acquiring properties and the expected rate of return on each acquisition. For more information on the challenges to implementing our strategy and achieving our goals, please read “Item 1A. Risk Factors.”

Operations

Well Operations

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

As of December 31, 2008, we operated properties representing approximately 79 percent of our proved reserves. As the operator, we are able to better control expenses, capital allocation, and the timing of exploitation and development activities on our properties. We also own working interests in properties that are operated by third parties, and are required to pay our share of production, exploitation, and development costs. Please read “Properties — Nature of Our Ownership Interests.” During 2008, 2007, and 2006, our costs for development activities on non-operated properties were approximately 22 percent, 40 percent, and 47 percent, respectively, of our total development costs. We also own royalty interests in wells operated by third parties that are not burdened by production or capital costs; however, we have little or no control over the implementation of projects on these properties.

Natural Gas Gathering

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

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

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

•  control compression costs and fuel use;

•  maintain system integrity;

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

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

Seasonal Nature of Business

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

Production and Price History

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

	Year Ended December 31,
	2008			2007			2006
Total Production Volumes:
Oil (MBbls)		10,050			9,545			7,335
Natural gas (MMcf)		26,374			23,963			23,456
Combined (MBOE)		14,446			13,539			11,244
Average Daily Production Volumes:
Oil (Bbls/D)		27,459			26,152			20,096
Natural gas (Mcf/D)		72,060			65,651			64,262
Combined (BOE/D)		39,470			37,094			30,807
Average Realized Prices:
Oil (per Bbl)	$	89.30		$	58.96		$	47.30
Natural gas (per Mcf)		8.63			6.26			6.24
Combined (per BOE)		77.87			52.66			43.87
Average Costs per BOE:
Lease operations expense	$	12.12		$	10.59		$	8.73
Production, ad valorem, and severance taxes		7.66			5.51			4.43
Depletion, depreciation, and amortization		15.80			13.59			10.09
Impairment of long-lived assets		4.12			—			—
Exploration		2.71			2.05			2.71
Derivative fair value loss (gain)		(23.97	)		8.31			(2.17	)
General and administrative		3.35			2.89			2.06
Provision for doubtful accounts		0.14			0.43			0.18
Other operating expense		0.90			1.26			0.71
Marketing loss (gain)		(0.06	)		(0.11	)		0.09

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Productive Wells

The following table sets forth information relating to productive wells in which we owned a working interest at December 31, 2008. Wells are classified as oil or natural gas wells according to their predominant production stream. Gross wells are the total number of productive wells in which we have an interest, and net wells are determined by multiplying gross wells by our average working interest. As of December 31, 2008, we owned a working interest in 5,774 gross wells. We also hold royalty interests in units and acreage beyond the wells in which we own a working interest.

	Oil Wells							Natural Gas Wells
					Average							Average
	Gross		Net		Working			Gross		Net		Working
	Wells(a)		Wells		Interest			Wells(a)		Wells		Interest
CCA		743		659		89	%		22		6		27	%
Permian Basin		1,967		769		39	%		634		314		50	%
Rockies		1,437		837		58	%		60		45		75	%
Mid-Continent		235		141		60	%		676		181		27	%
Total		4,382		2,406		55	%		1,392		546		39	%

(a) Our total wells include 3,094 operated wells and 2,680 non-operated wells. At December 31, 2008, 52 of our wells had multiple completions.

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Acreage

The following table sets forth information relating to our leasehold acreage at December 31, 2008. Developed acreage is assigned to productive wells. Undeveloped acreage is acreage held under lease, permit, contract, or option that is not in a spacing unit for a producing well, including leasehold interests identified for exploitation or exploratory drilling. As of December 31, 2008, our undeveloped acreage in the Rockies represented approximately 60 percent of our total net undeveloped acreage. Our current leases expire at various dates between 2009 and 2028, with leases representing $18.6 million of cost set to expire in 2009 if not developed.

	Gross		Net
	Acreage		Acreage
CCA:
Developed		117,209		109,775
Undeveloped		150,283		117,793
		267,492		227,568
Permian Basin:
Developed		66,280		45,173
Undeveloped		21,564		17,232
		87,844		62,405
Rockies:
Developed		231,846		156,350
Undeveloped		809,323		574,323
		1,041,169		730,673
Mid-Continent:
Developed		79,231		41,122
Undeveloped		344,963		245,472
		424,194		286,594
Total:
Developed		494,566		352,420
Undeveloped		1,326,133		954,820
		1,820,699		1,307,240

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Development Results

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

	Year Ended December 31,
	2008				2007				2006
	Gross		Net		Gross		Net		Gross		Net
Development Wells:
Productive		186		73		165		62		182		72
Dry holes		5		3		5		3		4		3
		191		76		170		65		186		75
Exploratory Wells:
Productive		96		32		63		21		71		19
Dry holes		8		4		5		3		14		8
		104		36		68		24		85		27
Total:
Productive		282		105		228		83		253		91
Dry holes		13		7		10		6		18		11
		295		112		238		89		271		102

Present Activities

As of December 31, 2008, we had a total of 63 gross (31.6 net) wells that had begun drilling and were in varying stages of drilling operations, of which 31 gross (17.9 net) were development wells. As of December 31, 2008, we had a total of 29 gross (14.7 net) wells that had reached total depth and were in the process of being completed pending first production, of which 19 gross (13.7 net) were development wells.

Delivery Commitments and Marketing Arrangements

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

The marketing of our CCA oil production is mainly dependent on transportation through the Bridger, Poplar, and Butte Pipelines to markets in the Guernsey, Wyoming area. Alternative transportation routes and markets have been developed by moving a portion of the crude oil production through the Enbridge Pipeline to the Clearbrook, Minnesota hub. To a lesser extent, our production also depends on transportation through the Platte Pipeline to Wood River, Illinois as well as other pipelines connected to the Guernsey, Wyoming area. While shipments on the Platte Pipeline are oversubscribed and have been subject to apportionment since December 2005, we were allocated sufficient pipeline capacity to move our crude oil production effective January 1, 2007. Enbridge Pipeline completed an expansion, which moved the total Rockies area pipeline takeaway closer to a balancing point with increasing production volumes and thereby provided greater stability to oil differentials in the area. In spite of the increase in capacity, the Enbridge Pipeline continues to run at full capacity and is scheduled to complete an additional expansion by the beginning of 2010. However, further

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restrictions on available capacity to transport oil through any of the above-mentioned pipelines, any other pipelines, or any refinery upsets could have a material adverse effect on our production volumes and the prices we receive for our production.

The difference between quoted NYMEX market prices and the price received at the wellhead for oil and natural gas production is commonly referred to as a differential. In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have affected this differential. We cannot accurately predict future crude oil and natural gas differentials. Increases in the percentage differential between the NYMEX price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial position, and cash flows. The following table illustrates the relationship between oil and natural gas wellhead prices as a percentage of average NYMEX prices by quarter for 2008, as well as our expected differentials for the first quarter of 2009:

	Actual												Forecast
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			First Quarter
	of 2008			of 2008			of 2008			of 2008			of 2009
Oil wellhead to NYMEX percentage		91	%		94	%		91	%		80	%		78	%
Natural gas wellhead to NYMEX percentage		103	%		102	%		93	%		86	%		103	%

Principal Customers

For 2008, our largest purchasers were Eighty-Eight Oil and Tesoro, which accounted for approximately 14 percent and 12 percent, respectively, of our total sales of oil and natural gas production. Our marketing of oil and natural gas can be affected by factors beyond our control, the potential effects of which cannot be accurately predicted. Management believes that the loss of any one purchaser would not have a material adverse effect on our ability to market our oil and natural gas production.

Competition

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

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

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

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Properties

Nature of Our Ownership Interests

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

										Proved Reserve Quantities
	2008 Net Production									at December 31, 2008									PV-10
			Natural									Natural							at December 31, 2008
	Oil		Gas		Total		Percent			Oil		Gas		Total		Percent			Amount(a)		Percent
	(MBbls)		(MMcf)		(MBOE)					(MBbls)		(MMcf)		(MBOE)					(In thousands)
CCA		4,146		978		4,309		30	%		71,892		13,327		74,113		40	%	$	550,734		39	%
Permian Basin		1,246		12,442		3,320		23	%		19,736		161,720		46,689		25	%		362,000		26	%
Rockies		4,256		1,870		4,567		32	%		40,074		16,552		42,833		23	%		326,196		23	%
Mid-Continent		402		11,084		2,250		15	%		2,750		115,921		22,070		12	%		170,019		12	%
Total		10,050		26,374		14,446		100	%		134,452		307,520		185,705		100	%	$	1,408,949		100	%

(a) Giving effect to commodity derivative contracts, our PV-10 would increase by $339.1 million at December 31, 2008. Standardized Measure at December 31, 2008 was $1.2 billion. Standardized Measure differs from PV-10 by $189.0 million because Standardized Measure includes the effects of future net abandonment costs and future income taxes. Since we are taxed at the corporate level, future income taxes are determined on a combined property basis and cannot be accurately subdivided among our core areas. Therefore, we believe PV-10 provides the best method for assessing the relative value of each of our areas.

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

During 2008, we filed the estimates of our oil and natural gas reserves as of December 31, 2007 with the U.S. Department of Energy on Form EIA-23. As required by Form EIA-23, the filing reflected only gross production that comes from our operated wells at year-end. Those estimates came directly from our reserve report prepared by Miller and Lents.

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CCA Properties

Our initial purchase of interests in the CCA was in 1999, and we continue to acquire additional working interests. As of December 31, 2008, we operated virtually all of our CCA properties with an average working interest of approximately 89 percent in the oil wells and 27 percent in the natural gas wells.

The CCA is a major structural feature of the Williston Basin in southeastern Montana and northwestern North Dakota. Our acreage is concentrated on the two-to-six-mile-wide “crest” of the CCA, giving us access to the greatest accumulation of oil in the structure. Our 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. Our 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.

Our CCA reserves are primarily produced through waterfloods. Our average daily net production from the CCA remained approximately constant at 12,153 BOE/D in the fourth quarter of 2008 as compared to 12,080 BOE/D in the fourth quarter of 2007. We have been able to maintain or grow production through a combination of:

•  effective management of the existing wellbores;

•  addition of strategically positioned horizontal and vertical wellbores;

•  re-entry horizontal drilling using existing wellbores;

•  waterflood enhancements;

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•  extensional drilling; and

•  other enhanced oil recovery techniques.

In 2008, we drilled 10 gross wells in the CCA, some of which were horizontal re-entry wells that (1) reestablished production from non-producing wells, (2) added additional production to existing producing wells, or (3) served as injection wells for secondary and tertiary recovery projects. We invested $37.3 million, $41.6 million, and $103.9 million in capital projects in the CCA during 2008, 2007, and 2006, respectively.

The CCA represents approximately 40 percent of our total proved reserves as of December 31, 2008 and is our most valuable asset today and in the foreseeable future. A large portion of our future success revolves around current and future exploitation of and production from this area.

We pursued HPAI in the CCA beginning in 2002 because CO₂ was not readily available and HPAI was an attractive alternative. The initial project was successful and continues to be successful; however, the political environment is changing in favor of CO₂ sequestration. We believe this will increase the amount of CO₂ available to be used in tertiary recovery projects. Although CO₂ is currently not readily available, we believe we will be able to secure an economical source of CO₂ in the future. Therefore, we have made a strategic decision to move away from HPAI and focus on CO₂.

Existing HPAI project areas in the CCA are in Pennel and Cedar Creek fields. In both fields, HPAI wells will be converted to water injection in three to four phases over a period of approximately 18 months. Priority will be largely based on economics of incremental production uplift and air injection utilization. We anticipate that we will continue injecting air in a small number of HPAI patterns beyond the planned 18-month conversion period. We expect to realize significant LOE savings while achieving current production estimates.

Net Profits Interest.  A major portion of our acreage position in the CCA is subject to net profits interests ranging from one percent to 50 percent. The holders of these net profits interests are entitled to receive a fixed percentage of the cash flow remaining after specified costs have been subtracted from net revenue. The net profits calculations are contractually defined. In general, net profits are determined after considering operating expense, overhead expense, interest expense, and development costs. The amounts of reserves and production attributable to net profits interests are deducted from our reserves and production data, and our revenues are reported net of net profits interests. The reserves and production attributed to net profits interests are calculated by dividing estimated future net profits interests (in the case of reserves) or prior period actual net profits interests (in the case of production) by commodity prices at the determination date. Fluctuations in commodity prices and the levels of development activities in the CCA from period to period will impact the reserves and production attributable to the net profits interests and will have an inverse effect on our reported reserves and production. For 2008, 2007, and 2006, we reduced revenue for net profits interests by $56.5 million, $32.5 million, and $23.4 million, respectively.

Permian Basin Properties

West Texas.  Our 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, Glorieta, Clearfork, Wolfcamp, and Pennsylvanian zones. Production from the southern portion of the Permian Basin comes mainly from the Canyon, Devonian, Ellenberger, Mississippian, Montoya, Strawn, and Wolfcamp formations with multiple pay intervals.

In March 2006, we entered into a joint development agreement with ExxonMobil Corporation (“ExxonMobil”) to develop legacy natural gas fields in West Texas. The 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.

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Under the terms of the agreement, we have the opportunity to develop approximately 100,000 gross acres. We earn 30 percent of ExxonMobil’s working interest and 22.5 percent of ExxonMobil’s net revenue interest in each well drilled. We operate each well during the drilling and completion phase, after which ExxonMobil assumes operational control of the well.

In July 2008, we earned the right to participate in all fields by drilling the final well of the 24-well commitment phase and are entitled to a 30 percent working interest in future drilling locations. We also have the right to propose and drill wells for as long as we are engaged in continuous drilling operations.

We have entered into a side letter agreement with ExxonMobil to: (1) combine a group of specified fields into one development area, and extend the period within which we must drill a well in this development area and one additional development area in order to be considered as conducting continuous drilling operations; (2) transfer ExxonMobil’s full working interest in a specified well along with a majority of its net royalty interest to us, while reserving its portion of an overriding royalty interest; (3) allow ExxonMobil to participate in any re-entry of the specified well under the original terms of a “subsequent well” (as defined in the joint development agreement), in which they will pay their proportional share of agreed costs incurred; and (4) reduce the non-consent penalty for 10 specified wells from 200 percent to 150 percent in exchange for ExxonMobil agreeing not to elect the carry for reduced working interest option for these wells.

Average daily production for our West Texas properties increased 19 percent from 7,122 BOE/D in the fourth quarter of 2007 to 8,497 BOE/D in the fourth quarter of 2008. We believe these properties will be an area of growth over the next several years. During 2008, we drilled 36 gross wells and invested approximately $203.8 million of capital to develop these properties.

In 2009, we intend to drill approximately 7 gross wells and invest approximately $51 million of net capital in the development areas. We anticipate operating one to two rigs in West Texas for most of 2009.

New Mexico.  We began investing in New Mexico in May 2006 with the strategy of deploying capital to develop low- to medium-risk development projects in southeastern New Mexico where multiple reservoir targets are available. Average daily production for these properties decreased 14 percent from 7,793 Mcfe/D in the fourth quarter of 2007 to 6,732 Mcfe/D in the fourth quarter of 2008. During 2008, we drilled 8 gross operated wells and invested approximately $39.7 million of capital to develop these properties.

Mid-Continent Properties

In January 2009, we sold certain oil and natural gas producing properties and related assets in the Arkoma Basin and royalty interest properties in Oklahoma as well as 10,300 unleased mineral acres to ENP for $49 million in cash, subject to customary adjustments (including a reduction in the purchase price for acquisition-related commodity derivative premiums of approximately $3 million).

Oklahoma, Arkansas, and Kansas.  We own various interests, including operated, non-operated, royalty, and mineral interests, on properties located in the Anadarko Basin of western Oklahoma and the Arkoma Basin of eastern Oklahoma and western Arkansas. Our average daily production for these properties decreased 5 percent from 8,555 Mcfe/D in the fourth quarter of 2007 to 8,159 Mcfe/D for the fourth quarter of 2008. During 2008, we drilled 52 gross wells and invested $29.9 million of development and exploration capital in these properties.

North Louisiana Salt Basin and East Texas Basin.  Our North Louisiana Salt Basin and East Texas Basin properties consist of operated working interests, non-operated working interests, and undeveloped leases acquired primarily in the Elm Grove and Overton acquisitions in 2004 and development in the Stockman and Danville fields in east Texas. Our 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 one percent to 47 percent across 1,800 net acres in 15 sections.

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Our East Texas and North Louisiana properties are in the same core area 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 from 8,000 to 11,500 feet.

In the fourth quarter of 2008, we began our Haynesville shale drilling program with the spudding of the first Haynesville shale well at the Greenwood Waskom field in Caddo Parish, Louisiana. This well reached total depth in January 2009 ahead of schedule. We plan to complete the well with an 11 stage fracture stimulation in the first quarter of 2009 and have recently spud our second horizontal well in the area. Since entering the Haynesville play, we have accumulated over 18,000 acres.

Tuscaloosa Marine Shale.  Since entering into the Tuscaloosa Marina Shale, we have accumulated over 290,000 gross (220,000 net) acres, the majority of which is locked up through the end of 2010. During 2008, we drilled 4 gross wells at a drilling cost of over $11 million per well. As a result of the significant decline in commodity prices during the second half of 2008, we recorded a $59.5 million impairment on these wells and have approximately $15 million of net unproved costs remaining in these properties.

During 2008, we drilled 95 gross wells and invested approximately $147.6 million of capital to develop our Mid-Continent properties. Average daily production for these properties increased 81 percent from 20,038 Mcfe/D in the fourth quarter of 2007 to 36,239 Mcfe/D for the fourth quarter of 2008. We drilled 8 gross operated wells in the Stockman and Danville fields.

Rockies Properties

Big Horn Basin.  In March 2007, ENP acquired the Big Horn Basin properties, which are located in the Big Horn Basin in northwestern Wyoming and south central Montana. The Big Horn Basin is characterized by oil and natural gas fields with long production histories and multiple producing formations. The Big Horn Basin is a prolific basin and has produced over 1.8 billion Bbls of oil since its discovery in 1906.

ENP also owns and operates (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 natural gas gathering system that transports higher sulfur natural gas from the Elk Basin Field to our Elk Basin natural gas processing facility.

Average daily production for these properties decreased slightly from 4,255 BOE/D in the fourth quarter of 2007 to 4,212 BOE/D in the fourth quarter of 2008. During 2008, ENP drilled 3 gross wells and invested approximately $10.8 million of capital to develop these properties.

Williston Basin.  Our Williston Basin properties have historically consisted of working and overriding royalty interests in several geographically concentrated fields. The properties are located in western North Dakota and eastern Montana, near our CCA properties. In April 2007, we acquired additional properties in the Williston Basin including 50 different fields across Montana and North Dakota. As part of this acquisition, we also acquired approximately 70,000 net unproved acres in the Bakken play of Montana and North Dakota. Since the acquisition, we have increased our acreage position in the Bakken play to approximately 300,000 acres. During 2008, we drilled and completed twelve wells in the Bakken and Sanish. The average seven day initial production rate of these wells was 411 BOE/D. Also during 2008, we re-fraced a total of six wells in North Dakota. The average thirty-day uplift in production rate for these re-frac wells was 118 BOE/D. In the first quarter of 2009, we plan to complete our first Sanish well in the Almond prospect. The Almond prospect contains 70,000 net acres and is located near the northeast border of Mountrail County, North Dakota.

Average daily production for our Rockies properties increased nine percent from 6,363 BOE/D in the fourth quarter of 2007 to 6,919 BOE/D in the fourth quarter of 2008. During 2008, we drilled 59 gross wells and invested approximately $125.6 million of capital to develop our Rockies properties.

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Bell Creek.  Our Bell Creek properties are located in the Powder River Basin of southeastern Montana. We operate seven production units in Bell Creek, each with a 100 percent working interest. The shallow (less than 5,000 feet) Cretaceous-aged Muddy Sandstone reservoir produces oil. We have successfully implemented a polymer injection program on both injection and producing wells on our Bell Creek properties whereby a polymer is injected into a well to reduce the amount of water cycling in the higher permeability interval of the reservoir, reducing operating costs and increasing reservoir recovery. This process is generally more efficient than standard waterflooding.

We invested $11.5 million of capital to develop these properties in 2008. Average daily production from these properties decreased seven percent from 958 BOE/D in the fourth quarter of 2007 to 890 BOE/D in the fourth quarter of 2008.

In 2009, we plan to initiate a CO₂ pilot in Bell Creek. We believe the field is an excellent candidate for CO₂ tertiary recovery and are attempting to procure a CO₂ source.

Paradox Basin.  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. In 2008, the operator continued the implementation of a tertiary project in the Aneth Unit. We believe these properties have additional potential in horizontal redevelopment, secondary development, and tertiary recovery potential.

Average daily production for these properties decreased approximately eight percent from 688 BOE/D in the fourth quarter of 2007 to 631 BOE/D in the fourth quarter of 2008. During 2008, we invested approximately $8.0 million of capital to develop these properties.

Title to Properties

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

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

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

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

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

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

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

We believe that the burdens and obligations affecting our properties do not in the aggregate materially interfere with the use of the properties. As previously discussed, a major portion of our acreage position in the CCA, our primary asset, is subject to net profits interests.

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

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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 pollution control equipment;

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

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

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

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

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

•  impose substantial liabilities for pollution resulting from operations; and

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

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

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

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

Site Remediation.  The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or operator of the site where

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the release occurred, and anyone who disposed of or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA authorizes the EPA, and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

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

ENP’s Elk Basin assets have been used for oil and natural gas exploration and production for many years. There have been known releases of hazardous substances, wastes, or hydrocarbons at the properties, and some of these sites are undergoing active remediation. The risks associated with these environmental conditions, and the cost of remediation, were assumed by ENP, 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, ENP assumed the risk of various other unknown or unasserted liabilities associated with the Elk Basin assets that relate to events that occurred prior to ENP’s 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.

ENP’s Elk Basin assets include a natural gas processing plant. Previous environmental investigations of the Elk Basin natural gas processing plant indicate historical soil and groundwater contamination by hydrocarbons and the presence of asbestos-containing material at the site. Although the environmental investigations did not identify an immediate need for remediation of the suspected historical contamination, the extent of the contamination is not known and, therefore, the potential liability for remediating this contamination may be significant. In the event ENP ceased operating the gas plant, the cost of decommissioning it and addressing the previously identified environmental conditions and other conditions, such as waste disposal, could be significant. ENP does not anticipate ceasing operations at the Elk Basin natural gas processing plant in the near future nor a need to commence remedial activities at this time. However, a regulatory agency could require ENP to investigate and remediate any contamination even while the gas plant remains in operation. As of December 31, 2008, ENP has recorded $4.4 million as future abandonment liability for decommissioning the Elk Basin natural gas processing plant. Due to the significant level of uncertainty associated with the known and unknown environmental liabilities at the gas plant, ENP’s estimate of the future abandonment liability includes a large contingency. ENP’s estimates of the future abandonment liability and compliance costs are subject to change and the actual cost of these items could vary significantly from those estimates.

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

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

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

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

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

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compliance costs or additional operating restrictions and could have a material adverse effect on our business, financial position, demand for our operations, results of operations, and cash flows.

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

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

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We did not incur any material capital expenditures for remediation or pollution control activities during 2008, and, as of the date of this Report, we are not aware of any environmental issues or claims that will require material capital expenditures during 2009. However, accidental spills or releases may occur in the course of our operations, and we may incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. Moreover, the passage of more stringent laws or regulations in the future may have a negative impact on our business, financial condition, or results of operations.

Other Regulation of the Oil and Natural Gas Industry

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

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

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

•  location of wells;

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•  methods of developing and casing wells;

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

•  plugging and abandoning of wells; and

•  notification of surface owners and other third parties.

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

Interstate Crude Oil Transportation.  ENP’s Clearfork crude oil pipeline is an interstate common carrier pipeline, which is subject to regulation by the Federal Energy Regulatory Commission (the “FERC”) under the Interstate Commerce Act (the “ICA”) and the Energy Policy Act of 1992 (“EP Act 1992”). The ICA and its implementing regulations give the FERC authority to regulate the rates ENP charges for service on that interstate common carrier pipeline and generally require the rates and practices of interstate oil pipelines to be just, reasonable, and nondiscriminatory. The ICA also requires ENP to maintain tariffs on file with the FERC that set forth the rates ENP charges for providing transportation services on its 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 and require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful. The FERC and interested parties can also challenge tariff rates that have become final and effective. EP Act 1992 deemed certain rates in effect prior to its passage to be just and reasonable and limited the circumstances under which a complaint can be made against such “grandfathered” rates. EP Act 1992 and its implementing regulations also allow interstate common carrier oil pipelines to annually index their rates up to a prescribed ceiling level. In addition, the FERC retains cost-of-service ratemaking, market-based rates, and settlement rates as alternatives to the indexing approach.

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

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels since the FERC has taken a less stringent approach to regulation of the offshore gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. ENP’s gathering operations could be adversely affected should they become subject to the application of state or federal regulation of rates and services. ENP’s 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 ENP’s 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 is not subject to federal regulation and, for the most part, is not subject to state regulation. Our sales of natural gas are affected by the availability, terms, and cost of pipeline transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes on our natural gas marketing operations, and we note that some of the FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers with which we compete.

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

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

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

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

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

Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including fires, explosions, blowouts, environmental hazards, and other potential events that can adversely affect our ability to conduct

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operations and cause us to incur substantial losses. Such losses could reduce or eliminate the funds available for exploration, exploitation, or leasehold acquisitions or result in loss of properties.

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

Employees

As of December 31, 2008, we had a staff of 394 persons, including 34 engineers, 17 geologists, and 14 landmen, none of which are represented by labor unions or covered by any collective bargaining agreement. We believe that relations with our employees are satisfactory.

Principal Executive Office

Our principal executive office is located at 777 Main Street, Suite 1400, Fort Worth, Texas 76102. Our main telephone number is (817) 877-9955.

Available Information

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

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

We have filed the required certifications under Section 302 of the Sarbanes-Oxley Act of 2002 as Exhibits 31.1 and 31.2 to this Report. In 2008, we submitted to the NYSE the CEO certification required by Section 303A.12(a) of the NYSE’s Listed Company Manual. In 2009, we expect to submit this certification to the NYSE after our annual meeting of stockholders.

Our board of directors (the “Board”) has four standing committees: (1) audit; (2) compensation; (3) nominating and corporate governance; and (4) special stock award. Our Board committee charters, code of business conduct and ethics, and corporate governance guidelines are available on our website and are also available in print upon written request to: Corporate Secretary, Encore Acquisition Company, 777 Main Street, Suite 1400, Fort Worth, Texas 76102.

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

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ITEM 1A.   RISK FACTORS

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

Oil and natural gas prices are very volatile. A decline in commodity prices could materially and adversely affect our financial condition, results of operations, liquidity, and cash flows.

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

•  overall domestic and global economic conditions;

•  weather conditions;

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

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

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

•  technological advances affecting energy consumption and energy supply;

•  domestic and foreign governmental regulations and taxation;

•  the impact of energy conservation efforts;

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

•  the availability of refining capacity; and

•  the price and availability of alternative fuels.

The worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with substantial losses in worldwide equity markets could lead to an extended worldwide economic recession. A slowdown in economic activity caused by a recession has reduced worldwide demand for energy and resulted in lower oil and natural gas prices. Oil prices declined from record levels in early July 2008 of over $140 per Bbl to below $39 per Bbl in mid-February 2009 and natural gas prices have declined from over $13 per Mcf to below $4.25 per Mcf over the same period. In addition, the forecasted prices for 2009 have also declined. Notwithstanding significant declines in oil and natural gas prices since July 2008, there has not been a corresponding decrease in oilfield service costs as of February 2009. If oilfield service costs remain elevated in relation to prevailing oil and natural gas prices, our results of operations and cash flows could be adversely affected.

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;

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•  reduce the amount of cash flow available for capital expenditures, repayment of indebtedness, and other corporate purposes; and

•  result in a decrease in the borrowing base under our revolving credit facility or otherwise limit our ability to borrow money or raise additional capital.

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

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

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

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

Our Standardized Measure is calculated using prices and costs in effect as of the date of estimation, less future development, production, abandonment, and income tax expenses, and discounted at 10 percent per annum to reflect the timing of future net revenue in accordance with the rules and regulations of the SEC. The Standardized Measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production.

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

The timing of both our production and our incurrence of expenses in connection with the development, production, and abandonment of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

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Our oil and natural gas reserves naturally decline and the failure to replace our reserves could adversely affect our financial condition.

Because our oil and natural gas properties are a depleting asset, our future oil and natural gas reserves, production volumes, and cash flows 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.

We need to make substantial capital expenditures to maintain and grow our asset base. If lower oil and natural gas prices or operating difficulties result in our cash flows from operations being less than expected or limit our ability to borrow under our revolving credit facility, we may be unable to expend the capital necessary to find, develop, or acquire additional reserves.

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

Declines in oil and natural gas prices may result in our having to make substantial downward revisions to our estimated reserves. If this occurs, or if our estimates of development costs increase, production data factors change, or development results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties and goodwill. If we incur such impairment charges, it could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our revolving credit facility. In addition, any write-downs that result in a reduction in our borrowing base could require prepayments of indebtedness under our revolving credit facility.

If we do not make acquisitions, our future growth could be limited.

Acquisitions are an essential part of our growth strategy, and our ability to acquire additional properties on favorable terms is important to our long-term growth. We may be unable to make acquisitions because we are:

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

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

•  outbid by competitors.

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

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

Any acquisition involves potential risks, including, among other things:

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

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•  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 incurrence 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 fully assess their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.

A substantial portion of our producing properties is located in one geographic area and adverse developments in any of our operating areas would negatively affect our financial condition and results of operations.

We have extensive operations in the CCA. Our CCA properties represented approximately 40 percent of our proved reserves as of December 31, 2008 and accounted for 30 percent of our 2008 production. Any circumstance or event that negatively impacts production or marketing of oil and natural gas in the CCA would materially affect our results of operations and cash flows.

Our commodity derivative contract activities could result in financial losses or could reduce our income and cash flows. Furthermore, in the future our commodity derivative contract positions may not adequately protect us from changes in commodity prices.

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

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

•  a counterparty may not perform its obligation under the applicable derivative instrument, which risk may have been exacerbated by the worldwide financial and credit crisis; and

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

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

We have oil and natural gas commodity derivative contracts covering a significant portion of our forecasted production for 2009. These contracts are intended to reduce our exposure to fluctuations in the price of oil and natural gas. We have a much smaller commodity derivative contract portfolio covering our forecasted production for 2010, 2011, and 2012, and no commodity derivative contracts covering production beyond 2012. After 2009 and unless we enter into new commodity derivative contracts, our exposure to oil and natural gas price volatility will increase significantly each year as our commodity derivative contracts expire. We may not be able to obtain additional commodity derivative contracts on acceptable terms, if at all. Our failure to mitigate our exposure to commodity price volatility through commodity derivative contracts could have a negative effect on our financial condition and results of operation and significantly reduce our cash flows.

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

As of December 31, 2008, we were entitled to future payments of approximately $387.6 million from counterparties under our commodity derivative contracts. The worldwide financial and credit crisis may have adversely affected the ability of these counterparties to fulfill their obligations to us. If one or more of our counterparties is unable or unwilling to make required payments to us under our commodity derivative contracts, it could have a material adverse effect on our financial condition and results of operations.

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

Other companies operated approximately 21 percent of our properties (measured by total reserves) and approximately 46 percent of our wells as of December 31, 2008. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in development or acquisition activities and lead to unexpected future costs.

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

Development and exploratory drilling and production activities are subject to many risks, including the risk that we will not discover commercially productive oil or natural gas reserves. In order to further our development efforts, we acquire both producing and unproved properties as well as lease undeveloped acreage

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that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not be required to impair our initial investments.

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

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

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.

The cost of developing, completing, and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. If commodity prices decline, the cost of developing, completing and operating a well may not decline in proportion to the prices that we receive for our production, resulting in higher operating and capital costs as a percentage of oil and natural gas revenues. For instance, oil and natural gas prices declined from record levels in early July 2008 of over $140 per Bbl and $13 per Mcf, respectively, to below $39 per Bbl and $4.25 per Mcf, respectively, in mid-February 2009. Notwithstanding significant declines in oil and natural gas prices since July 2008, there has not been a corresponding decrease in oilfield service costs as of February 2009. If oilfield service costs remain elevated in relation to prevailing oil and natural gas prices, our results of operations and cash flows could be adversely affected. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce as much oil and natural gas as we had estimated. Furthermore, our development and production operations may be curtailed, delayed, or canceled as a result of other factors, including:

•  higher costs, shortages, 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;

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•  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.

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

•  lower than expected production;

•  longer response times;

•  higher operating and capital costs;

•  shortages of equipment; and

•  lack of technical expertise.

If any of these risks occur, it could adversely affect our financial condition or results of operations.

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 weather and adverse economic conditions have made it more difficult for us to obtain certain types of coverage. We may not be able to obtain the levels or types of insurance we would otherwise

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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, and results of operations.

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

We make and will continue to make substantial capital expenditures in development, exploitation, and exploration projects. For example, our Board approved a $310 million capital budget for 2009, excluding proved property acquisitions. We intend to finance these capital expenditures through operating cash flows. However, additional financing sources may be required in the future to fund our capital expenditures. Financing may not continue to be available under existing or new financing arrangements, or on acceptable terms, if at all. If additional capital resources are not available, we may be forced to curtail our development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.

Shortages of rigs, equipment, and crews could delay our operations.

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

The loss of key personnel could adversely affect our business.

We depend to a large extent on the efforts and continued employment of I. Jon Brumley, our Chairman of the Board, Jon S. Brumley, our Chief Executive Officer and President, and other key personnel. The loss of the services of any of these persons could adversely affect our business, and we do not have employment agreements with, and do not maintain key person insurance on the lives of, any of these persons.

Our development success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, and other professionals. Competition for experienced geologists, engineers, and other professionals is extremely intense and the cost of attracting and retaining technical personnel has increased significantly in recent years. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed. Furthermore, escalating personnel costs could adversely affect our results of operations and financial condition.

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 contracted 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.

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Competition in the oil and natural gas industry is intense, and many of our competitors have greater resources than we do. As a result, we may be unable to effectively compete with larger competitors.

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

We 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, and results of operations. Please read “Items 1 and 2. Business and Properties — Environmental Matters and Regulation” and “ — Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.

We have significant indebtedness and may incur significant additional indebtedness, which could negatively impact our financial condition, results of operations, and business prospects.

As of December 31, 2008, we had total consolidated debt of $1.3 billion and $615 million of consolidated available borrowing capacity under our revolving credit facility. We have the ability to incur additional debt under our revolving credit facilities, subject to borrowing base limitations. Our future indebtedness could have important consequences to us, including:

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

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

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•  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 and future business opportunities; and

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

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

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

We are unable to predict the impact of the recent downturn in the credit markets and the resulting costs or constraints in obtaining financing on our business and financial results.

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

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

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

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

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PART II

ITEM 5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock, par value $0.01 per share, is listed on the NYSE under the symbol “EAC.” The following table sets forth high and low sales prices of our common stock for the periods indicated:

	High		Low
2008
Quarter ended December 31	$	41.05	$	17.89
Quarter ended September 30	$	79.62	$	36.84
Quarter ended June 30	$	77.35	$	38.45
Quarter ended March 31	$	40.74	$	26.10
2007
Quarter ended December 31	$	38.55	$	30.59
Quarter ended September 30	$	33.00	$	25.79
Quarter ended June 30	$	29.96	$	24.21
Quarter ended March 31	$	26.50	$	21.74

On February 18, 2009, the closing sales price of our common stock as reported by the NYSE was $23.09 per share, and we had approximately 387 shareholders of record. This number does not include owners for whom common stock may be held in “street” name.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

In October 2008, we announced that the Board authorized a share repurchase program of up to $40 million of our common stock. As of December 31, 2008, we had repurchased and retired 620,265 shares of our outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. The following table summarizes purchases of our common stock during the fourth quarter of 2008:

					Total Number of		Approximate Dollar
					Shares Purchased		Value of Shares
	Total Number				as Part of Publicly		That May Yet Be
	of Shares		Average Price		Announced Plans		Purchased Under the
Month	Purchased		Paid per Share		or Programs		Plans or Programs
October		620,265	$	27.68		620,265
November(a)		4,753	$	21.31		—
December		—	$	—		—
Total		625,018	$	27.63		620,265	$	22,830,139

(a) During the fourth quarter of 2008, certain employees directed us to withhold 4,753 shares of common stock to satisfy minimum tax withholding obligations in conjunction with vesting of restricted shares.

Dividends

No dividends have been declared or paid on our common stock. We anticipate that we will retain all future earnings and other cash resources for the future operation and development of our business. Accordingly, we do not intend to declare or pay any cash dividends in the foreseeable future. Payment of any future dividends will be at the discretion of the Board after taking into account many factors, including our operating results, financial condition, current and anticipated cash needs, and plans for expansion. The

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declaration and payment of dividends is restricted by our existing revolving credit facility and the indentures governing our senior subordinated notes. Future debt agreements may also restrict our ability to pay dividends.

Stock Performance Graph

The following graph compares our cumulative total stockholder return during the period from January 1, 2004 to December 31, 2008 with total stockholder return during the same period for the Independent Oil and Gas Index and the Standard & Poor’s 500 Index. The graph assumes that $100 was invested in our common stock and each index on January 1, 2004 and that all dividends, if any, were reinvested. The following graph is being furnished pursuant to SEC rules and will not be incorporated by reference into any filing under the Securities Act of 1933 or the Exchange Act except to the extent we specifically incorporate it by reference.

Comparison of Total Return Since January 1, 2004 Among Encore
Acquisition Company, the Standard & Poor’s 500 Index, and the
Independent Oil and Gas Index

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ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of exposure, but rather indicators of potential exposure. This information provides indicators of how we view and manage our ongoing market risk exposures. We do not enter into market risk sensitive instruments for speculative trading purposes.

Derivative policy.  Due to the volatility of crude oil and natural gas prices, we enter into various derivative instruments to manage our exposure to changes in the market price of crude oil and natural gas. We use options (including floors and collars) and fixed price swaps to mitigate the impact of downward swings in prices. 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 in times of higher oil and natural gas prices than we would otherwise have, had we not utilized these instruments, management believes that the resulting reduced volatility of cash flow is beneficial.

Counterparties.  At December 31, 2008, we had committed greater than 10 percent of either our outstanding oil or natural gas commodity derivative contracts to the following counterparties:

	Percentage of			Percentage of
	Oil Derivative			Natural Gas Derivative
Counterparty	Contracts Committed			Contracts Committed
BNP Paribas		22	%		24	%
Calyon		15	%		31	%
Fortis		11	%		—
UBS		16	%		—
Wachovia		11	%		38	%

In order to mitigate the credit risk of financial instruments, we enter into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating separately each derivative financial transaction between our counterparty and us, the master netting agreement enables our counterparty and us to aggregate all financial trades and treat them as a single agreement. This arrangement benefits us in three ways: (1) the netting of the value of all trades reduces the likelihood of our counterparties requiring daily collateral posting by us; (2) default by a counterparty under one financial trade can trigger rights for us to terminate all financial trades with such counterparty; and (3) netting of settlement amounts reduces our credit exposure to a given counterparty in the event of close-out.

Commodity price sensitivity.  We manage commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of sales volumes. Put

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contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collars provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price. From time to time, we sell floors with a strike price below the strike price of the purchased floors in order to partially finance the premiums paid on the purchased floors. Together the two floors, known as a floor spread or put spread, have a lower premium cost than a traditional floor contract but provide price protection only down to the strike price of the short floor.

As of December 31, 2008, the fair market values of our oil and natural gas commodity derivative contracts were net assets of approximately $374.8 million and $12.8 million, respectively. Based on our open commodity derivative positions at December 31, 2008, a 10 percent increase in the respective NYMEX prices for oil and natural gas would decrease our net derivative fair value asset by approximately $29.2 million, while a 10 percent decrease in the respective NYMEX prices for oil and natural gas would increase our net derivative fair value asset by approximately $29.8 million. These amounts exclude deferred premiums of $67.6 million at December 31, 2008 that are not subject to changes in commodity prices.

The following tables summarize our open commodity derivative contracts as of December 31, 2008:

Oil Derivative Contracts

	Average		Weighted		Average			Weighted		Average		Weighted		Average		Weighted		Asset
	Daily		Average		Daily			Average		Daily		Average		Daily		Average		Fair
	Floor		Floor		Short Floor			Short Floor		Cap		Cap		Swap		Swap		Market
Period	Volume		Price		Volume			Price		Volume		Price		Volume		Price		Value
	(Bbl)		(per Bbl)		(Bbl)			(per Bbl)		(Bbl)		(per Bbl)		(Bbl)		(per Bbl)		(In thousands)
2009(a)																		$	342,063
		11,630	$	110.00		—		$	—		—	$	—		2,000	$	90.46
		8,000		80.00		—			—		440		97.75		500		89.39
		—		—		(5,000	)		50.00		—		—		1,000		68.70
2010																			17,618
		880		80.00		—			—		440		93.80		—		—
		2,000		75.00		—			—		1,000		77.23		—		—
2011		1,880		80.00		—			—		1,440		95.41		—		—		15,112
		1,000		70.00		—			—		—		—		—		—
																		$	374,793

(a) In addition, ENP has a floor contract for 1,000 Bbls/D at $63.00 per Bbl and a short floor contract for 1,000 Bbls/D at $65.00 per Bbl.

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Natural Gas Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted		Average		Weighted		Asset
	Daily		Average		Daily		Average		Daily		Average		Daily		Average		Fair
	Floor		Floor		Short Floor		Short Floor		Cap		Cap		Swap		Swap		Market
Period	Volume		Price		Volume		Price		Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(In thousands)
2009																	$	7,281
		3,800	$	8.20		—	$	—		3,800	$	9.83		—	$	—
		3,800		7.20		—		—		—		—		—		—
		1,800		6.76		—		—		—		—		—		—
2010																		4,690
		3,800		8.20		—		—		3,800		9.58		902		6.30
		4,698		7.26		—		—		—		—		—		—
2011																		424
		898		6.76		—		—		—		—		902		6.70
2012																		424
		898		6.76		—		—		—		—		902		6.66
																	$	12,819

Interest rate sensitivity.  At December 31, 2008, we had total long-term debt of $1.3 billion, net of discount of $5.2 million. Of this amount, $150 million bears interest at a fixed rate of 6.25 percent, $300 million bears interest at a fixed rate of 6.0 percent, and $150 million bears interest at a fixed rate of 7.25 percent. The remaining long-term debt balance of $725 million consists of outstanding borrowings on our revolving credit facilities and is subject to floating market rates of interest that are linked to LIBOR.

At this level of floating rate debt, if LIBOR increased 10 percent, we would incur an additional $2.0 million of interest expense per year on our revolving credit facilities, and if LIBOR decreased 10 percent, we would incur $2.0 million less. Additionally, if the bond discount rate increased 10 percent, we estimate the fair value of our fixed rate debt at December 31, 2008 would decrease from approximately $390 million to approximately $351 million, and if the bond discount rate decreased 10 percent, we estimate the fair value would increase to approximately $429 million.

ENP manages interest rate risk with interest rate swaps whereby it swaps floating rate debt under the OLLC Credit Agreement with a weighted average fixed rate. As of December 31, 2008, the fair market value of ENP’s interest rate swaps was a net liability of approximately $4.6 million. If LIBOR increased 10 percent, we estimate the liability would decrease to approximately $4.1 million, and if LIBOR decreased 10 percent, we estimate the liability would increase to approximately $5.0 million.

The following table summarizes ENP’s open interest rate swaps as of December 31, 2008:

	Notional		Fixed			Floating
Term	Amount		Rate			Rate
	(In thousands)
Jan. 2009 — Jan. 2011	$	50,000		3.1610	%		1-month LIBOR
Jan. 2009 — Jan. 2011		25,000		2.9650	%		1-month LIBOR
Jan. 2009 — Jan. 2011		25,000		2.9613	%		1-month LIBOR
Jan. 2009 — Mar. 2012		50,000		2.4200	%		1-month LIBOR

37

ITEM 9A.   CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2008 to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control Over Financial Reporting

EAC’s management is responsible for establishing and maintaining adequate internal control over financial reporting. EAC’s internal control over financial reporting is a process designed under the supervision of EAC’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of EAC’s financial statements for external purposes in accordance with GAAP.

As of December 31, 2008, management assessed the effectiveness of EAC’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control — Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, management determined that EAC maintained effective internal control over financial reporting as of December 31, 2008, based on those criteria.

Ernst & Young, LLP, the independent registered public accounting firm that audited the consolidated financial statements of EAC included in this annual report on Form 10-K, has issued an attestation report on the effectiveness of EAC’s internal control over financial reporting as of December 31, 2008. The report, which expresses an unqualified opinion on the effectiveness of EAC’s internal control over financial reporting as of December 31, 2008, is included below.

38

ENCORE ACQUISITION COMPANY

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of
Encore Acquisition Company:

We have audited Encore Acquisition Company’s (the “Company”) internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Encore Acquisition Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Encore Acquisition Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Encore Acquisition Company as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2008 and our report dated February 24, 2009 expressed an unqualified opinion thereon.

/s/  Ernst & Young LLP

Fort Worth, Texas
February 24, 2009

39

ENCORE ACQUISITION COMPANY

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

40

EX-99.2

Exhibit 99.2

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2009

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission File Number: 001-16295

ENCORE ACQUISITION COMPANY

(Exact name of registrant as specified in its charter)

Delaware	75-2759650
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

777 Main Street, Suite 1400, Fort Worth, Texas	76102
(Address of principal executive offices)	(Zip Code)

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

Not applicable
(Former name, former address and former fiscal year, if changed since last report)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o     No o

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

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

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

Number of shares of common stock, $0.01 par value, outstanding as of April 28, 2009 52,772,669

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENCORE ACQUISITION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share amounts)

	March 31,			December 31,
	2009			2008
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	23,472		$	2,039
Accounts receivable, net of allowance for doubtful accounts of $381		90,618			129,065
Inventory		33,291			24,798
Derivatives		81,378			349,344
Income taxes receivable		4,448			29,445
Other		5,839			6,239
Total current assets		239,046			540,930
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		3,653,719			3,538,459
Unproved properties		120,464			124,339
Accumulated depletion, depreciation, and amortization		(840,857	)		(771,564	)
		2,933,326			2,891,234
Other property and equipment		25,480			25,192
Accumulated depreciation		(13,696	)		(12,753	)
		11,784			12,439
Goodwill		60,606			60,606
Derivatives		45,642			38,497
Long-term receivables, net of allowance for doubtful accounts of $7,669 and $7,643, respectively		59,853			60,915
Other		27,671			28,574
Total assets	$	3,377,928		$	3,633,195
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	11,393		$	10,017
Accrued liabilities:
Lease operations expense		24,214			19,108
Development capital		66,654			79,435
Interest		12,473			11,808
Production, ad valorem, and severance taxes		23,872			25,133
Derivatives		8,163			63,476
Oil and natural gas revenues payable		10,462			10,821
Deferred taxes		92,106			105,768
Other		33,892			26,686
Total current liabilities		283,229			352,252
Derivatives		15,635			8,922
Future abandonment cost, net of current portion		47,255			48,058
Deferred taxes		421,787			416,915
Long-term debt		1,132,962			1,319,811
Other		4,521			3,989
Total liabilities		1,905,389			2,149,947
Commitments and contingencies (see Note 15)
Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par value, 144,000,000 shares authorized, 51,819,037 and 51,551,937 issued and outstanding, respectively		518			516
Additional paid-in capital		530,440			525,763
Treasury stock, at cost, 111,353 and 4,753 shares, respectively		(2,945	)		(101	)
Retained earnings		782,089			789,698
Accumulated other comprehensive loss		(2,089	)		(1,748	)
Total EAC stockholders’ equity		1,308,013			1,314,128
Noncontrolling interest		164,526			169,120
Total equity		1,472,539			1,483,248
Total liabilities and equity	$	3,377,928		$	3,633,195

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

1

ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
(unaudited)

	Three months ended
	March 31,
	2009			2008
Revenues:
Oil	$	88,289		$	220,534
Natural gas		25,254			48,312
Marketing		806			4,056
Total revenues		114,349			272,902
Expenses:
Production:
Lease operating		44,225			40,350
Production, ad valorem, and severance taxes		11,819			27,452
Depletion, depreciation, and amortization		70,300			49,543
Exploration		11,199			5,488
General and administrative		13,694			9,687
Marketing		739			3,782
Derivative fair value loss (gain)		(48,591	)		65,138
Other operating		6,343			2,506
Total expenses		109,728			203,946
Operating income		4,621			68,956
Other income (expenses):
Interest		(15,963	)		(19,760	)
Other		554			851
Total other expenses		(15,409	)		(18,909	)
Income (loss) before income taxes		(10,788	)		50,047
Income tax benefit (provision)		4,885			(18,733	)
Consolidated net income (loss)		(5,903	)		31,314
Less: net income attributable to noncontrolling interest		(1,653	)		(94	)
Net income (loss) attributable to EAC	$	(7,556	)	$	31,220
Net income (loss) per common share:
Basic	$	(0.15	)	$	0.58
Diluted	$	(0.15	)	$	0.58
Weighted average common shares outstanding:
Basic		51,688			52,799
Diluted		51,688			53,332

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

2

ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENT OF EQUITY AND COMPREHENSIVE LOSS
(in thousands)
(unaudited)

	Issued																				Accumulated
	Shares of					Additional			Shares of												Other
	Common			Common		Paid-in			Treasury			Treasury			Retained			Noncontrolling			Comprehensive			Total
	Stock			Stock		Capital			Stock			Stock			Earnings			Interest			Loss			Equity
Balance at December 31, 2008		51,557		$	516	$	525,763			(5	)	$	(101	)	$	789,698		$	169,120		$	(1,748	)	$	1,483,248
Exercise of stock options and vesting of restricted stock		378			2		72			—			—			—			—			—			74
Purchase of treasury stock		—			—		—			(111	)		(2,945	)		—			—			—			(2,945	)
Cancellation of treasury stock		(5	)		—		(48	)		5			101			(53	)		—			—			—
Non-cash equity-based compensation		—			—		4,613			—			—			—			34			—			4,647
ENP cash distributions to noncontrolling interests		—			—		—			—			—			—			(6,077	)		—			(6,077	)
Other		—			—		40			—			—			—			—			—			40
Components of comprehensive loss:
Net loss		—			—		—			—			—			(7,556	)		1,653			—			(5,903	)
Change in deferred hedge loss on interest rate swaps, net of tax of $169		—			—		—			—			—			—			(204	)		(341	)		(545	)
Total comprehensive loss																									(6,448	)
Balance at March 31, 2009		51,930		$	518	$	530,440			(111	)	$	(2,945	)	$	782,089		$	164,526		$	(2,089	)	$	1,472,539

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

3

ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)

	Three months ended
	March 31,
	2009			2008
Cash flows from operating activities:
Net income (loss) attributable to EAC	$	(7,556	)	$	31,220
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization		70,300			49,543
Non-cash exploration expense		10,991			3,656
Deferred taxes		(8,609	)		14,623
Non-cash equity-based compensation expense		4,080			2,896
Non-cash derivative loss		13,474			62,176
Gain on disposition of assets		(8	)		(23	)
Noncontrolling interest		1,653			94
Other		1,928			2,376
Changes in operating assets and liabilities:
Accounts receivable		58,496			(16,753	)
Current derivatives		266,118			(670	)
Other current assets		7,716			(18,459	)
Long-term derivatives		—			(1,196	)
Other assets		(41	)		(67	)
Accounts payable		5,870			(6,303	)
Other current liabilities		27,371			8,953
Other noncurrent liabilities		(158	)		(339	)
Net cash provided by operating activities		451,625			131,727
Cash flows from investing activities:
Proceeds from disposition of assets		259			184
Purchases of other property and equipment		(458	)		(1,054	)
Acquisition of oil and natural gas properties		(9,484	)		(30,780	)
Development of oil and natural gas properties		(153,092	)		(97,802	)
Net collections from (advances to) working interest partners		1,651			(8,972	)
Net cash used in investing activities		(161,124	)		(138,424	)
Cash flows from financing activities:
Repurchase and retirement of common stock		—			(39,118	)
Exercise of stock options and vesting of restricted stock, net of treasury stock purchases		(2,871	)		684
Proceeds from long-term debt, net of issuance costs		66,000			357,274
Payments on long-term debt		(253,000	)		(303,500	)
ENP cash distributions to noncontrolling interests		(6,077	)		(4,198	)
Payment of commodity derivative contract premiums		(68,626	)		(8,534	)
Change in cash overdrafts		(4,494	)		2,590
Net cash provided by (used in) financing activities		(269,068	)		5,198
Increase (decrease) in cash and cash equivalents		21,433			(1,499	)
Cash and cash equivalents, beginning of period		2,039			1,704
Cash and cash equivalents, end of period	$	23,472		$	205

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

4

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

Note 1. Description of Business

     EAC is engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States. Since 1998, EAC has acquired producing properties with proven reserves and leasehold acreage and grown the production and proven reserves by drilling, exploring, and reengineering or expanding existing waterflood projects. EAC’s properties — and oil and natural gas reserves — are located in four core areas:

• the Cedar Creek Anticline (“CCA”) in the Williston Basin in Montana and North Dakota;

• the Permian Basin in West Texas and southeastern New Mexico;

• the Rockies, which includes non-CCA assets in the Williston, Big Horn, and Powder River Basins in Wyoming, Montana, and North Dakota, and the Paradox Basin in southeastern Utah; and

• the Mid-Continent area, which includes the Arkoma and Anadarko Basins in Arkansas and Oklahoma, the North Louisiana Salt Basin, and the East Texas Basin.

Note 2. Basis of Presentation

     EAC’s consolidated financial statements include the accounts of its wholly owned and majority-owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.

     In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments necessary to present fairly, in all material respects, EAC’s financial position as of March 31, 2009 and results of operations and cash flows for the three months ended March 31, 2009 and 2008. All adjustments are of a normal recurring nature. These interim results are not necessarily indicative of results for an entire year.

     Certain amounts and disclosures have been condensed or omitted from these consolidated financial statements pursuant to the rules and regulations of the SEC. Therefore, these consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in EAC’s 2008 Annual Report on Form 10-K.

Noncontrolling Interest

     As of March 31, 2009 and December 31, 2008, EAC owned approximately 63 percent of ENP’s common units, as well as all of the interests of Encore Energy Partners GP LLC (“GP LLC”), a Delaware limited liability company and indirect wholly owned non-guarantor subsidiary of EAC. GP LLC is ENP’s general partner. Considering the presumption of control of GP LLC in accordance with Emerging Issues Task Force (“EITF”) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” the financial position, results of operations, and cash flows of ENP are consolidated with those of EAC.

     As presented in the accompanying Consolidated Balance Sheets, “Noncontrolling interest” as of March 31, 2009 and December 31, 2008 of $164.5 million and $169.1 million, respectively, represents third-party ownership interests in ENP. As presented in the accompanying Consolidated Statements of Operations, “Net income attributable to noncontrolling interest” for the three months ended March 31, 2009 and 2008 of $1.7 million and $0.1 million, respectively, represents the net income of ENP attributable to third-party owners.

Supplemental Disclosures of Cash Flow Information

     The following table sets forth supplemental disclosures of cash flow information for the periods indicated:

	Three months ended March 31,
	2009		2008
	(In thousands)
Non-cash investing and financing activities:
Deferred premiums on commodity derivative contracts	$	17,044	$	25,685

Reclassifications

     Certain amounts in prior periods have been reclassified to conform to the current period presentation. In particular, certain amounts in the Consolidated Financial Statements have been either combined or classified in more detail.

5

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

New Accounting Pronouncements

FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”)

     In February 2008, the FASB issued FSP FAS 157-2, which delayed the effective date of SFAS No. 157, “Fair Value Measurements” (“SFAS 157”) for one year for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). EAC elected a partial deferral of SFAS 157 for all instruments within the scope of FSP FAS 157-2, including, but not limited to, its asset retirement obligations and indefinite lived assets. FSP FAS 157-2 was prospectively effective for nonfinancial assets and liabilities for financial statements issued for fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The adoption of FSP FAS 157-2 on January 1, 2009, as it relates to nonfinancial assets and liabilities, did not have a material impact on EAC’s results of operations or financial condition. Please read “Note 6. Fair Value Measurements” for additional discussion.

SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”)

     In December 2007, the FASB issued SFAS 141R, which replaces SFAS No. 141, “Business Combinations.” SFAS 141R establishes principles and requirements for the reporting entity in a business combination, including: (1) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. In April 2009, the FASB issued FSP No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arises from Contingencies” (“FSP FAS 141R-1”), which amends and clarifies SFAS 141R to address application issues, including: (1) initial recognition and measurement; (2) subsequent measurement and accounting; and (3) disclosure of assets and liabilities arising from contingencies in a business combination. SFAS 141R and FSP FAS 141R-1 were prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008, with early application prohibited. The adoption of SFAS 141R and FSP FAS 141R-1 on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition. However, the application of SFAS 141R and FSP FAS 141R-1 to future acquisitions could impact EAC’s results of operations and financial condition and the reporting of acquisitions in the consolidated financial statements.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment to ARB No. 51” (“SFAS 160”)

     In December 2007, the FASB issued SFAS 160, which amends Accounting Research Bulletin No. 51, "Consolidated Financial Statements” to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 was prospectively effective for fiscal years beginning on or after December 15, 2008, except for the presentation and disclosure requirements which are retrospective. SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 requires consolidated net income to be reported for the amounts attributable to both the parent and the noncontrolling interest on the face of the consolidated statement of operations and gains on a subsidiaries’ issuance of equity to be accounted for as capital transactions. The adoption of SFAS 160 on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161”)

     In March 2008, the FASB issued SFAS 161, which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), to require enhanced disclosures, including: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 was effective for fiscal years beginning on or after November 15, 2008, with early application encouraged. The adoption of SFAS 161 on January 1, 2009 required additional disclosures regarding EAC’s derivative instruments; however, it did not impact EAC’s results of operations or financial condition. Please read “Note 5. Derivative Financial Instruments” for additional discussion.

FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”)

6

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

     In June 2008, the FASB issued FSP EITF 03-6-1, which addresses whether instruments granted in equity-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation for computing basic earnings per share (“EPS”) under the two-class method described by SFAS No. 128, “Earnings per Share” (“SFAS 128”). FSP EITF 03-6-1 was retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years, with early application prohibited. The adoption of FSP EITF 03-6-1 on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition. All periods presented in the accompanying Consolidated Financial Statements have been restated to reflect the adoption of FSP EITF 03-6-1. Please read “Note 11. Earnings Per Share” for additional discussion.

SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting” (“Release 33-8995”)

     In December 2008, the SEC issued Release 33-8995, which amends oil and natural gas reporting requirements under Regulations S-K and S-X. Release 33-8995 also adds a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being phased out. Release 33-8995 permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. Release 33-8995 will also allow companies to disclose their probable and possible reserves to investors at the company’s option. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor; (2) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (3) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. Release 33-8995 is prospectively effective for fiscal years ending on or after December 31, 2009, with early application prohibited. EAC is evaluating the impact the adoption of Release 33-8995 will have on its financial condition, results of operations, and disclosures.

FSP No. FAS 107-1 and APB 28-1, “Disclosure of Fair Value of Financial Instruments in Interim Statements” (“FSP FAS 107-1 and APB 28-1”)

     In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which requires that disclosures concerning the fair value of financial instruments be presented in interim as well as annual financial statements. FSP FAS 107-1 and APB 28-1 is prospectively effective for interim reporting periods ending after June 15, 2009. The adoption of FSP FAS 107-1 and APB 28-1 will require additional disclosures regarding EAC’s financial instruments; however, it will not impact EAC’s results of operations or financial condition.

Note 3. Inventory

     Inventory includes materials and supplies and oil in pipelines, which are stated at the lower of cost (determined on an average basis) or market. Oil produced at the lease which resides unsold in pipelines is carried at an amount equal to its operating costs to produce. Oil in pipelines purchased from third parties is carried at average purchase price. Inventory consisted of the following as of the dates indicated:

	March 31,		December 31,
	2009		2008
	(in thousands)
Materials and supplies	$	24,969	$	15,933
Oil in pipelines		8,322		8,865
Total inventory	$	33,291	$	24,798

7

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

Note 4. Proved Properties

     Amounts shown in the accompanying Consolidated Balance Sheets as “Proved properties, including wells and related equipment” consisted of the following as of the dates indicated:

	March 31,		December 31,
	2009		2008
	(in thousands)
Proved leasehold costs	$	1,423,174	$	1,421,859
Wells and related equipment — Completed		2,097,192		1,943,275
Wells and related equipment — In process		133,353		173,325
Total proved properties	$	3,653,719	$	3,538,459

Note 5. Derivative Financial Instruments

Derivative Policy

     EAC uses various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with its oil and natural gas production. These arrangements are structured to reduce EAC’s exposure to commodity price decreases, but they can also limit the benefit EAC might otherwise receive from commodity price increases. EAC’s risk management activity is generally accomplished through over-the-counter derivative contracts with large financial institutions. EAC also uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation.

     EAC applies the provisions of SFAS 133, which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, changes in fair value can be recognized in accumulated other comprehensive loss until such time as the hedged item is recognized in earnings.

     In order to qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically. Cash flow hedges are marked to market through accumulated other comprehensive loss each period.

     EAC has elected to designate its current interest rate swaps as cash flow hedges. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized in earnings immediately as “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.

     EAC has not elected to designate its current portfolio of commodity derivative contracts as hedges and therefore, changes in fair value of these instruments are recognized in earnings as “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.

Commodity Derivative Contracts

     EAC manages commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of sales volumes. Put contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collars provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price.

     From time to time, EAC sells floors with a strike price below the strike price of the purchased floors in order to partially finance the premiums paid on the purchased floors. Together the two floors, known as a floor spread or put spread, have a lower premium cost than a traditional floor contract but provide price protection only down to the strike price of the short floor. As with EAC’s other commodity derivative contracts, these are marked-to-market each quarter through “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations. In the following tables, the purchased floor component of these floor spreads are shown net and included with EAC’s other floor contracts.

8

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

     The following tables summarize EAC’s open commodity derivative contracts as of March 31, 2009:

Oil Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Daily		Average		Asset
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(in thousands)
Apr. — Dec. 2009 (a)													$	50,326
		3,130	$	110.00		440	$	97.75		—	$	—
		—		—		—		—		1,000		68.70
2010														29,759
		880		80.00		440		93.80		—		—
		2,000		75.00		2,500		73.43		—		—
		5,000		60.80		500		65.60		—		—
		1,000		56.00		—		—		2,000		60.84
2011														15,550
		1,880		80.00		1,440		95.41		—		—
		1,000		70.00		—		—		—		—
													$	95,635

(a) In addition, ENP has a floor contract for 1,000 Bbls/D at $63.00 per Bbl and a short floor contract for 1,000 Bbls/D at $65.00 per Bbl.

Natural Gas Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Daily		Average		Asset
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(in thousands)
Apr. — Dec. 2009													$	20,259
		3,800	$	8.20		3,800	$	9.83		—	$	—
		3,800		7.20		5,000		7.45		—		—
		6,800		6.57		15,000		6.63		—		—
		15,000		5.64		—		—		—		—
2010														7,747
		3,800		8.20		3,800		9.58		—		—
		4,698		7.26		—		—		902		6.30
2011														761
		898		6.76		—		—		902		6.70
2012														575
		898		6.76		—		—		902		6.66
													$	29,342

     The following table summarizes the fair value of EAC’s commodity derivative contracts as of March 31, 2009:

(in thousands)

Asset Derivatives

Liability Derivatives

Current

Long-Term

Current

Long-Term

Derivatives not designated as

hedging instruments

Balance Sheet

Balance Sheet

Balance Sheet

Balance Sheet

under SFAS 133

Location

Fair Value

Location

Fair Value

Location

Fair Value

Location

Fair Value

Commodity derivative contracts

Derivatives —

Derivatives —

Derivatives —

Derivatives —

current assets

$

81,378

long-term assets

$

45,642

current liabilities

$

36

long-term liabilities

$

2,007

     As of March 31, 2009, EAC had $16.6 million of deferred premiums payable, of which $11.6 million was long-term and included in “Derivatives” in the non-current liabilities section of the accompanying Consolidated Balance Sheet and $5.0 million was current and included in “Derivatives” in the current liabilities section of the accompanying Consolidated Balance Sheet. The premiums relate

9

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

to various oil and natural gas floor contracts and are payable on a monthly basis from April 2009 to January 2011. EAC recorded these premiums at their net present value at the time the contracts were entered into and accretes that value to the eventual settlement price by recording interest expense each period.

     Counterparty Risk. At March 31, 2009, EAC had committed greater than 10 percent (in terms of fair market value) of either its oil or natural gas derivative contracts to the following counterparties:

	Percentage of			Percentage of
	Oil Derivative			Natural Gas Derivative
	Contracts			Contracts
Counterparty	Committed			Committed
BNP Paribas		53	%		18	%
Calyon		24	%		40	%
JP Morgan		7	%		18	%
Wachovia Bank		3	%		23	%

     In order to mitigate the credit risk of financial instruments, EAC enters into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and EAC. Instead of treating each derivative financial transaction between the counterparty and EAC separately, the master netting agreement enables the counterparty and EAC to aggregate all financial trades and treat them as a single agreement. This arrangement benefits EAC in three ways: (1) the netting of the value of all trades reduces the likelihood of counterparties requiring daily collateral posting by EAC; (2) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (3) netting of settlement amounts reduces EAC’s credit exposure to a given counterparty in the event of close-out. EAC’s accounting policy is to not offset fair value amounts recognized for derivative instruments.

Interest Rate Swaps

     ENP uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation, whereby it converts the interest due on certain floating rate debt under its revolving credit facility to a weighted average fixed rate. The following table summarizes ENP’s open interest rate swaps as of March 31, 2009, all of which were entered into with Bank of America, N.A.:

	Notional		Fixed			Floating
Term	Amount		Rate			Rate
	(in thousands)
Apr. 2009 - Jan. 2011	$	50,000		3.1610	%	1-month LIBOR
Apr. 2009 - Jan. 2011		25,000		2.9650	%	1-month LIBOR
Apr. 2009 - Jan. 2011		25,000		2.9613	%	1-month LIBOR
Apr. 2009 - Mar. 2012		50,000		2.4200	%	1-month LIBOR

     The following table summarizes the fair value of EAC’s interest rate swaps as of March 31, 2009:

(in thousands)	Liability Derivatives
	Current			Long-Term
Derivatives designated as	Balance Sheet			Balance Sheet
hedging instruments under SFAS 133	Location	Fair Value		Location	Fair Value
Interest rate swaps	Derivatives —			Derivatives —
	current liabilities	$	3,143	long-term liabilities	$	2,043

     The actual gains or losses ENP will realize from its interest rate swaps may vary significantly from the deferred loss recorded in accumulated other comprehensive loss due to the fluctuation of interest rates.

Current Period Impact

     EAC recognized derivative fair value gains and losses related to: (1) ineffectiveness on derivative contracts designated as hedges; (2) changes in the fair market value of derivative contracts not designated as hedges; (3) settlements on derivative contracts not

10

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

designated as hedges; and (4) premium amortization. The following table summarizes the components of “Derivative fair value loss (gain)” for the periods indicated:

	Three months ended
	March 31,
	2009			2008
	(in thousands)
Ineffectiveness	$	89		$	(381	)
Mark-to-market loss		202,782			45,614
Premium amortization		77,955			15,513
Settlements		(329,417	)		4,392
Total derivative fair value loss (gain)	$	(48,591	)	$	65,138

     In March 2009, EAC elected to monetize certain of its 2009 oil derivative contracts representing approximately 77 percent of its consolidated 2009 oil derivative contracts. EAC received proceeds of approximately $190.4 million from these settlements, which were used to reduce outstanding borrowings under EAC’s revolving credit facility.

     The following table summarizes the effect of derivative instruments not designated as hedges under SFAS 133 on the Consolidated Statements of Operations for the periods indicated:

		Amount of Loss (Gain) Recognized
		In Income
Derivatives Not Designated as	Location of Loss (Gain)	Three Months Ended March 31,
Hedges Under SFAS 133	Recognized In Income	2009			2008
		(in thousands)
Commodity derivative contracts	Derivative fair value loss (gain)	$	(48,680	)	$	65,519

     The following table summarizes the effect of derivative instruments designated as hedges under SFAS 133 on the Consolidated Statements of Operations for the periods indicated:

(in thousands)						Amount of Loss (Gain)
	Amount of Loss (Gain)					Reclassified from						Amount of Loss (Gain)
	Recognized in OCI				Location of Loss	Accumulated OCI into						Recognized In Income
	(Effective Portion)				(Gain) Reclassified	Income (Effective Portion)						as Ineffective
	Three months ended				from Accumulated	Three months ended					Location of Loss (Gain)	Three months ended
Derivatives Designated as	March 31,				OCI into Income	March 31,					Recognized in Income	March 31,
Hedges Under SFAS 133	2009		2008		(Effective Portion)	2009		2008			as Ineffective	2009			2008
Interest rate swaps	$	715	$	1,568	Interest expense	$	881	$	(18	)	Derivative fair value loss (gain)	$	(89	)	$	(381	)
Commodity derivative contracts		—		—	Oil and natural gas revenues		—		1,429				—			—
Total	$	715	$	1,568		$	881	$	1,411			$	(89	)	$	(381	)

Accumulated Other Comprehensive Loss

     At March 31, 2009 and December 31, 2008, accumulated other comprehensive loss consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps of $2.1 million and $1.7 million, respectively. During the twelve months ending March 31, 2010, EAC expects to reclassify $3.1 million of deferred losses associated with ENP’s interest rate swaps from accumulated other comprehensive loss to interest expense and $1.1 million of deferred income taxes to income tax benefit.

Note 6. Fair Value Measurements

     As discussed in “Note 2. Basis of Presentation,” EAC adopted FSP FAS 157-2 on January 1, 2009, as it relates to nonfinancial assets and liabilities. EAC adopted SFAS 157 on January 1, 2008, as it relates to financial assets and liabilities. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

• Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities.

11

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

• Level 2 — Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.

• Level 3 — Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.

     EAC’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the financial assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions were used to estimate the fair values of EAC’s financial assets and liabilities that are accounted for at fair value on a recurring basis:

• Level 2 — Fair values of oil and natural gas swaps were estimated using a combined income and market-based valuation methodology based upon forward commodity price curves obtained from independent pricing services reflecting broker market quotes. Fair values of interest rate swaps were estimated using a combined income and market-based valuation methodology based upon credit ratings and forward interest rate yield curves obtained from independent pricing services reflecting broker market quotes.

• Level 3 — Fair values of oil and natural gas floors and caps were estimated using pricing models and discounted cash flow methodologies based on inputs that are not readily available in public markets.

     The following table sets forth EAC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2009:

				Fair Value Measurements at Reporting Date Using
				Quoted Prices in
				Active Markets for		Significant Other			Significant
	Asset (Liability) at			Identical Assets		Observable Inputs			Unobservable Inputs
Description	March 31, 2009			(Level 1)		(Level 2)			(Level 3)
	(in thousands)
Oil derivative contracts — swaps	$	2,467		$	—	$	2,467		$	—
Oil derivative contracts — floors and caps		93,168			—		—			93,168
Natural gas derivative contracts — swaps		707			—		707			—
Natural gas derivative contracts — floors and caps		28,635			—		—			28,635
Interest rate swaps		(5,186	)		—		(5,186	)		—
Total	$	119,791		$	—	$	(2,012	)	$	121,803

     The following table summarizes the changes in the fair value of EAC’s Level 3 financial assets and liabilities for the three months ended March 31, 2009:

	Fair Value Measurements Using Significant
	Unobservable Inputs (Level 3)
	Oil Derivative			Natural Gas
	Contracts —			Derivative Contracts —
	Floors and Caps			Floors and Caps			Total
				(in thousands)
Balance at January 1, 2009	$	337,335		$	12,741		$	350,076
Total gains (losses):
Included in earnings		39,008			21,607			60,615
Purchases, issuances, and settlements		(283,175	)		(5,713	)		(288,888	)
Balance at March 31, 2009	$	93,168		$	28,635		$	121,803
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	39,008		$	21,607		$	60,615

     Since EAC does not use hedge accounting for its commodity derivative contracts, all gains and losses on its Level 3 financial assets and liabilities are included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations. All fair values have been adjusted for non-performance risk, resulting in a reduction of the net commodity derivative asset of approximately $2.0 million as of March 31, 2009.

12

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

     EAC’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the nonfinancial assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions were used to estimate the fair values of EAC’s nonfinancial assets and liabilities that are accounted for at fair value on a nonrecurring basis:

• Level 3 — Fair value of goodwill is determined using the estimated price EAC would receive to sell the reportable units. These inputs are not readily available in public markets. Fair values of other intangibles and asset retirement obligations are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets.

     The following table sets forth EAC’s nonfinancial assets and liabilities that were accounted for at fair value on a nonrecurring basis as of March 31, 2009:

				Fair Value Measurements Using
				Quoted Prices in
				Active Markets for		Significant Other		Significant
	Asset (Liability) at			Identical Assets		Observable Inputs		Unobservable Inputs			Total Gains
Description	March 31, 2009			(Level 1)		(Level 2)		(Level 3)			(Losses)
	(in thousands)
Goodwill	$	60,606		$	—	$	—	$	60,606		$	—
Other intangibles, net		3,575			—		—		3,575			—
Asset retirement obligations		(48,762	)		—		—		(48,762	)		—
Total	$	15,419		$	—	$	—	$	15,419		$	—

Note 7. Asset Retirement Obligations

     Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in EAC’s asset retirement obligations for the three months ended March 31, 2009 (in thousands):

Future abandonment liability at January 1, 2009	$	49,569
Wells drilled		165
Accretion of discount		598
Plugging and abandonment costs incurred		(158	)
Revision of previous estimates		(1,412	)
Future abandonment liability at March 31, 2009	$	48,762

     As of March 31, 2009, $47.3 million of EAC’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $1.5 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheets. Approximately $4.4 million of the future abandonment liability represents the estimated cost for decommissioning ENP’s Elk Basin natural gas processing plant. ENP expects to continue reserving additional amounts based on the estimated timing to cease operations of the natural gas processing plant.

     As of March 31, 2009 and December 31, 2008, EAC held $9.2 million in escrow, which is to be released only for reimbursement of actual plugging and abandonment costs incurred on its Bell Creek properties, which is included in other long-term assets in the accompanying Consolidated Balance Sheets.

13

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

Note 8. Long-Term Debt

     Long-term debt consisted of the following as of the dates indicated:

	Maturity		March 31,		December 31,
	Date		2009		2008
			(in thousands)
Revolving credit facilities		3/7/2012	$	538,000	$	725,000
6.25% Senior Subordinated Notes		4/15/2014		150,000		150,000
6.0% Senior Subordinated Notes, net of unamortized discount of $3,834 and $3,960, respectively		7/15/2015		296,166		296,040
7.25% Senior Subordinated Notes, net of unamortized discount of $1,204 and $1,229, respectively		12/1/2017		148,796		148,771
Total			$	1,132,962	$	1,319,811

Encore Acquisition Company Senior Secured Credit Agreement

     EAC is a party to a five-year amended and restated credit agreement dated March 7, 2007 (as amended, the “EAC Credit Agreement”). The EAC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, EAC amended the EAC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the EAC Credit Agreement. The EAC Credit Agreement provides for revolving credit loans to be made to EAC from time to time and letters of credit to be issued from time to time for the account of EAC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the EAC Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. In March 2009, the borrowing base of the EAC Credit Agreement was reaffirmed at $1.1 billion before an adjustment of $200 million solely as a result of the monetization of certain of EAC’s 2009 oil derivative contracts during the first quarter of 2009. As of March 31, 2009, the borrowing base was $900 million and there were $353 million of outstanding borrowings and $547 million of borrowing capacity under the EAC Credit Agreement. As of March 31, 2009, EAC was in compliance with all covenants of the EAC Credit Agreement.

     Eurodollar loans under the EAC Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the EAC Credit Agreement bear interest at the base rate plus the applicable margin indicated in the following table:

	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.750	%		0.500	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.000	%		0.750	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.250	%		1.000	%
Greater than or equal to .90 to 1		2.500	%		1.250	%

     The “Eurodollar Rate” for any interest period (either one, two, three, or six months, as selected by EAC) is the rate equal to the British Bankers Association LIBOR Rate for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) during a “LIBOR Unavailability Period,” the “Eurodollar Rate” (for dollar deposits for a one-month term) for such day plus 1.0 percent.

     The following table summarizes the commitment fee percentage under the EAC Credit Agreement:

	Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .90 to 1		0.375	%
Greater than or equal to .90 to 1		0.500	%

14

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

Encore Energy Partners Operating LLC Credit Agreement

     Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly owned subsidiary of ENP, is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “OLLC Credit Agreement”). The OLLC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, OLLC amended the OLLC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. In March 2009, the borrowing base under the OLLC Credit Agreement was redetermined with no change. As of March 31, 2009, the borrowing base was $240 million and there were $185 million of outstanding borrowings and $55 million of borrowing capacity under the OLLC Credit Agreement. As of March 31, 2009, OLLC was in compliance with all covenants of the OLLC Credit Agreement.

     Eurodollar loans under the OLLC Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the OLLC Credit Agreement bear interest at the base rate plus the applicable margin indicated in the following table:

	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.750	%		0.750	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.000	%		0.750	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.250	%		1.000	%
Greater than or equal to .90 to 1		2.500	%		1.250	%

     The “Eurodollar Rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate equal to the British Bankers Association LIBOR Rate for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) during a “LIBOR Unavailability Period,” the “Eurodollar Rate” (for dollar deposits for a one-month term) for such day plus 1.0 percent.

     The following table summarizes the commitment fee percentage under the OLLC Credit Agreement:

	Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .90 to 1		0.375	%
Greater than or equal to .90 to 1		0.500	%

Note 9. Stockholders’ Equity

     In October 2008, EAC announced that its Board of Directors (the “Board”) approved a share repurchase program authorizing EAC to repurchase up to $40 million of its common stock. As of March 31, 2009, EAC had repurchased and retired 620,265 shares of its outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. During the three months ended March 31, 2009, EAC did not repurchase any shares of its outstanding common stock under the share repurchase program. As of March 31, 2009, approximately $22.8 million of EAC’s common stock remained authorized for repurchase.

     During the three months ended March 31, 2009, employees of EAC exercised 1,736 options for which EAC received proceeds of approximately $31 thousand. During the three months ended March 31, 2009, employees elected to satisfy minimum tax withholding obligations related to the vesting of restricted stock by directing EAC to withhold 111,353 shares of common stock, which are accounted for as treasury stock until they are formally retired.

15

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

Note 10. Income Taxes

     The components of income tax benefit (provision) were as follows for the periods indicated:

	Three months ended
	March 31,
	2009			2008
	(in thousands)
Federal:
Current	$	(3,373	)	$	(3,544	)
Deferred		8,008			(13,804	)
Total federal		4,635			(17,348	)
State, net of federal benefit:
Current		(351	)		(566	)
Deferred		601			(819	)
Total state		250			(1,385	)
Income tax benefit (provision)	$	4,885		$	(18,733	)

     The following table reconciles income tax benefit (provision) with income tax at the Federal statutory rate for the periods indicated:

	Three months ended
	March 31,
	2009			2008
	(in thousands)
Income (loss) before income taxes	$	(10,788	)	$	50,047
Income taxes at the Federal statutory rate	$	3,776		$	(17,516	)
State income taxes, net of federal benefit		250			(1,328	)
Tax on income attributable to noncontrolling interest		579			33
Nondeductible deferred compensation expense		—			(263	)
Permanent and other		280			341
Income tax benefit (provision)	$	4,885		$	(18,733	)

     At March 31, 2009, EAC had federal alternative minimum tax (“AMT”) credits of $2.3 million, which are available to reduce future federal regular tax liabilities in excess of AMT. The AMT credits have no expiration and EAC anticipates sufficient taxable income in future years to utilize the credits. Therefore, a valuation allowance against these deferred tax assets is not considered necessary.

     As of March 31, 2009 and December 31, 2008, all of EAC’s tax positions met the “more-likely-than-not” threshold prescribed by FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109.” As a result, no additional tax expense, interest, or penalties have been accrued. EAC includes interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its Consolidated Statements of Operations. For the three months ended March 31, 2009 and 2008, EAC recorded only a nominal amount of interest and penalties on certain tax positions.

Note 11. Earnings Per Share

     As discussed in “Note 2. Basis of Presentation,” EAC adopted FSP EITF 03-06-1 on January 1, 2009, and all periods have been restated to calculate EPS in accordance with this pronouncement. Under the two-class method of calculating EPS, earnings are allocated to participating securities as if all the earnings for the period had been distributed. A participating security is any security that contains nonforfeitable rights to dividends or dividend equivalents paid to common stockholders. For purposes of calculating EPS, unvested restricted stock awards are considered participating securities.

16

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

     EPS is calculated by dividing the common stockholders’ interest in net income (loss), after deducting the interests of participating securities, by the weighted average shares outstanding.

     The following table reflects the allocation of net income (loss) to the common stockholders and EPS computations for the periods indicated:

	Three months ended
	March 31,
	2009			2008 (c)
	(in thousands, except per share amounts)
Basic Earnings Per Share
Numerator:
Undistributed net income (loss) — attributable to EAC	$	(7,556	)	$	31,220
Participation rights of unvested restricted stock in undistributed earnings (a)		—			(544	)
Basic undistributed net income (loss) — attributable to EAC common shares	$	(7,556	)	$	30,676
Denominator:
Basic weighted average shares outstanding		51,688			52,799
Basic EPS — attributable to EAC common shares	$	(0.15	)	$	0.58
Diluted Earnings Per Share
Numerator:
Undistributed net income (loss) — attributable to EAC	$	(7,556	)	$	31,220
Participation rights of unvested restricted stock in undistributed earnings (a)		—			(544	)
Basic undistributed net income (loss) — attributable to EAC common shares	$	(7,556	)	$	30,676
Denominator:
Basic weighted average shares outstanding		51,688			52,799
Effect of dilutive options (b)		—			533
Diluted weighted average shares outstanding		51,688			53,332
Diluted EPS — attributable to EAC common shares	$	(0.15	)	$	0.58

(a)	Unvested restricted stock has no contractual obligation to absorb losses of EAC. Therefore, for the three months ended March 31, 2009, 921,652 shares of restricted stock were outstanding but excluded from the EPS calculations because their effect would have been antidilutive. Please read “Note 12. Incentive Stock Plans” for additional discussion of restricted stock.
(b)	For the three months ended March 31, 2009 and 2008, options to purchase 1,752,377 and 121,653 shares of common stock, respectively, were outstanding but excluded from the EPS calculations because their effect would have been antidilutive. Please read “Note 12. Incentive Stock Plans” for additional discussion of stock options.
(c)	For the three months ended March 31, 2008, EAC considered the impact of the conversion of vested management incentive units held by certain executive officers of GP LLC. The conversion of the management incentive units into limited partner units of ENP would reduce EAC’s share of ENP’s earnings. For the three months ended March 31, 2008, the impact of this conversion would have been immaterial and was thus excluded from the above calculation of diluted EPS. Please read “Note 17. ENP” for additional discussion of ENP’s management incentive units.

Note 12. Incentive Stock Plans

     In May 2008, EAC’s stockholders approved the 2008 Incentive Stock Plan (the “2008 Plan”). No additional awards will be granted under EAC’s 2000 Incentive Stock Plan (the “2000 Plan”) and any outstanding awards granted under the 2000 Plan will remain outstanding in accordance with their terms. The purpose of the 2008 Plan is to attract, motivate, and retain selected employees of EAC and to provide EAC with the ability to provide incentives more directly linked to the profitability of the business and increases in stockholder value. All directors and full-time regular employees of EAC and its subsidiaries and affiliates are eligible to be granted awards under the 2008 Plan. The 2008 Plan provides for the granting of cash awards, incentive stock options, non-qualified stock options, restricted stock, and stock appreciation rights at the discretion of the Compensation Committee of the Board. The Board also has a Special Stock Award Committee whose sole member is Jon S. Brumley, EAC’s Chief Executive Officer and President. The Special Stock Award Committee may grant up to 25,000 shares of restricted stock on an annual basis to non-executive employees at its discretion.

     The total number of shares of EAC’s common stock reserved for issuance pursuant to the 2008 Plan is 2,400,000, of which no more than 1,600,000 are available for grants of “full value” stock awards, such as restricted stock or stock units. As of March 31, 2009, there were 1,749,608 shares available for issuance under the 2008 Plan. Shares delivered or withheld for payment of the exercise price of an option, shares withheld for payment of tax withholding, shares subject to options or other awards that expire or are forfeited, and restricted shares that are forfeited will again become available for issuance under the 2008 Plan.

17

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

     The 2008 Plan contains the following individual limits:

• an employee may not be granted awards covering or relating to more than 300,000 shares of common stock during any calendar year;

• a non-employee director may not be granted awards covering or relating to more than 20,000 shares of common stock during any calendar year; and

• an employee may not receive awards consisting of cash (including cash awards that are granted as performance awards) in respect of any calendar year having a value determined on the grant date in excess of $5.0 million.

     During the three months ended March 31, 2009 and 2008, EAC recorded non-cash stock-based compensation expense related to its incentive stock plans of $4.0 million and $1.8 million, respectively, which was allocated to LOE and general and administrative expense in the accompanying Consolidated Statements of Operations based on the allocation of the respective employees’ cash compensation. During the three months ended March 31, 2009 and 2008, EAC also capitalized $0.6 million and $0.4 million, respectively, of non-cash stock-based compensation cost related to its incentive stock plans as a component of “Properties and equipment” in the accompanying Consolidated Balance Sheets. During the three months ended March 31, 2009 and 2008, EAC recognized income tax benefits related to its incentive stock plans of $1.5 million and $0.7 million, respectively.

     Please read “Note 18. ENP” for a discussion of ENP’s unit-based compensation plans.

Stock Options

     All options have a strike price equal to the fair market value of EAC’s common stock on the grant date, have a ten-year life, and vest over a three-year period. The fair value of options granted during the three months ended March 31, 2009 and 2008 was estimated on the grant date using a Black-Scholes option valuation model based on the following assumptions:

	Three months ended March 31,
	2009			2008
Expected volatility		51.9	%		33.7	%
Expected dividend yield		0.0	%		0.0	%
Expected term (in years)		6.25			6.25
Risk-free interest rate		2.1	%		3.0	%
Weighted-average fair value per share	$	15.81		$	13.15

     The expected volatility was based on the historical volatility of EAC’s common stock for a period of time commensurate with the expected term of the options. EAC determined the expected life of the options based on an analysis of historical exercise and forfeiture behavior as well as expectations about future behavior. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the grant date for a period of time commensurate with the expected term of the options.

     The following table summarizes the changes in EAC’s outstanding options for the three months ended March 31, 2009:

						Weighted
				Weighted		Average		Aggregate
	Number of			Average		Remaining		Intrinsic
	Options			Strike Price		Contractual Term		Value
								(in thousands)
Outstanding at January 1, 2009		1,497,413		$	18.02
Granted		269,417			30.55
Forfeited or expired		(12,717	)		30.91
Exercised		(1,736	)		17.59
Outstanding at March 31, 2009		1,752,377			19.86		5.6	$	10,988
Exercisable at March 31, 2009		1,319,671			16.30		4.4		10,988

18

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

     The total intrinsic value of options exercised during the three months ended March 31, 2009 and 2008 was $22 thousand and $0.2 million, respectively. During the three months ended March 31, 2009 and 2008, EAC received proceeds from the exercise of stock options of $31 thousand and $0.3 million, respectively, and recognized income tax benefits related to stock options of $4 thousand and $0.7 million, respectively. At March 31, 2009, EAC had $3.6 million of total unrecognized compensation cost related to unvested stock options, which is expected to be recognized over a weighted average period of 2.6 years.

Restricted Stock

     Restricted stock awards vest over varying periods from one to five years, subject to performance-based vesting for certain members of senior management. During the three months ended March 31, 2009 and 2008, EAC recognized expense related to restricted stock of $3.0 million and $1.5 million, respectively, and recognized income tax benefits (losses) related to the vesting of restricted stock of $(0.3) million and $0.5 million, respectively. The following table summarizes the changes in EAC’s unvested restricted stock awards for the three months ended March 31, 2009:

				Weighted
				Average
	Number of			Grant Date
	Shares			Fair Value
Outstanding at January 1, 2009		938,407		$	30.67
Granted		378,511			30.55
Vested		(376,717	)		28.87
Forfeited		(18,549	)		30.27
Outstanding at March 31, 2009		921,652			31.36

     As of March 31, 2009, there were 702,632 shares of unvested restricted stock, 155,129 shares of which were granted during 2009, in which the vesting is dependent only on the passage of time and continued employment. Additionally, as of March 31, 2009, there were 219,020 shares of unvested restricted stock, all of which were granted during 2009, in which the vesting is dependent not only on the passage of time and continued employment, but also on the achievement of certain performance measures.

     None of EAC’s unvested restricted stock awards are subject to variable accounting. During the three months ended March 31, 2009 and 2008, there were 376,717 shares and 212,586 shares, respectively, of restricted stock that vested for which certain employees elected to satisfy minimum tax withholding obligations related thereto by directing EAC to withhold 111,353 shares and 28,193 shares of common stock, respectively. EAC accounts for these shares as treasury stock until they are formally retired and have been reflected as such in the accompanying consolidated financial statements. The total fair value of restricted stock that vested during the three months ended March 31, 2009 and 2008 was $10.0 million and $7.2 million, respectively. As of March 31, 2009, EAC had $13.8 million of total unrecognized compensation cost related to unvested restricted stock, which is expected to be recognized over a weighted average period of 3.2 years.

Note 13. Comprehensive Income (Loss)

     The components of comprehensive income (loss), net of tax, were as follows for the periods indicated:

	Three months ended
	March 31,
	2009			2008
	(in thousands)
Consolidated net income (loss)	$	(5,903	)	$	31,314
Amortization of deferred loss on commodity derivative contracts		—			879
Change in deferred hedge loss on interest rate swaps		(545	)		(1,171	)
Consolidated comprehensive income (loss)		(6,448	)		31,022
Less: comprehensive loss (income) attributable to noncontrolling interest		(1,449	)		410
Comprehensive income (loss) — attributable to EAC	$	(7,897	)	$	31,432

19

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

Note 14. Financial Statements of Subsidiary Guarantors

     Certain of EAC’s wholly owned subsidiaries are subsidiary guarantors of EAC’s senior subordinated notes. The subsidiary guarantees are full and unconditional, and joint and several. The subsidiary guarantors may, without restriction, transfer funds to EAC in the form of cash dividends, loans, and advances. The following Condensed Consolidating Balance Sheets as of March 31, 2009 and December 31, 2008, and Condensed Consolidating Statements of Operations and Comprehensive Income (Loss) and Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 2009 and 2008 present consolidating financial information for Encore Acquisition Company (the “Parent”) on a stand alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries. As of March 31, 2009, EAC’s guarantor subsidiaries were:

• EAP Properties, Inc.;

• EAP Operating, LLC;

• Encore Operating, L.P.; and

• Encore Operating Louisiana, LLC.

     As of March 31, 2009, EAC’s non-guarantor subsidiaries were:

• ENP;

• OLLC;

• GP LLC;

• Encore Partners GP Holdings LLC;

• Encore Partners LP Holdings LLC;

• Encore Energy Partners Finance Corporation; and

• Encore Clear Fork Pipeline LLC.

     All intercompany investments in, loans due to/from, subsidiary equity, revenues, and expenses between the Parent, guarantor subsidiaries, and non-guarantor subsidiaries are shown prior to consolidation with the Parent and then eliminated to arrive at consolidated totals per the accompanying consolidated financial statements.

20

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET
March 31, 2009
(in thousands)

			Guarantor			Non-Guarantor						Consolidated
	Parent		Subsidiaries			Subsidiaries			Eliminations			Total
ASSETS
Current assets:
Cash and cash equivalents	$	1,779	$	21,451		$	242		$	—		$	23,472
Other current assets		4,889		129,727			84,468			(3,510	)		215,574
Total current assets		6,668		151,178			84,710			(3,510	)		239,046
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		—		3,108,412			545,307			—			3,653,719
Unproved properties		—		120,408			56			—			120,464
Accumulated depletion, depreciation, and amortization		—		(722,848	)		(118,009	)		—			(840,857	)
		—		2,505,972			427,354			—			2,933,326
Other property and equipment, net		—		11,273			511			—			11,784
Other assets, net		12,027		136,873			44,872			—			193,772
Investment in subsidiaries		2,767,366		18,744			—			(2,786,110	)		—
Total assets	$	2,786,061	$	2,824,040		$	557,447		$	(2,789,620	)	$	3,377,928
LIABILITIES AND EQUITY
Current liabilities	$	108,471	$	151,831		$	26,437		$	(3,510	)	$	283,229
Deferred taxes		421,615		—			172			—			421,787
Long-term debt		947,962		—			185,000			—			1,132,962
Other liabilities		—		55,129			12,282			—			67,411
Total liabilities		1,478,048		206,960			223,891			(3,510	)		1,905,389
Commitments and contingencies (see Note 15)
Total equity		1,308,013		2,617,080			333,556			(2,786,110	)		1,472,539
Total liabilities and equity	$	2,786,061	$	2,824,040		$	557,447		$	(2,789,620	)	$	3,377,928

21

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2008
(in thousands)

			Guarantor			Non-Guarantor						Consolidated
	Parent		Subsidiaries			Subsidiaries			Eliminations			Total
ASSETS
Current assets:
Cash and cash equivalents	$	607	$	813		$	619		$	—		$	2,039
Other current assets		29,004		421,392			90,797			(2,302	)		538,891
Total current assets		29,611		422,205			91,416			(2,302	)		540,930
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		—		3,016,937			521,522			—			3,538,459
Unproved properties		—		124,272			67			—			124,339
Accumulated depletion, depreciation, and amortization		—		(670,991	)		(100,573	)		—			(771,564	)
		—		2,470,218			421,016			—			2,891,234
Other property and equipment, net		—		11,877			562			—			12,439
Other assets, net		12,846		129,482			46,264			—			188,592
Investment in subsidiaries		2,976,208		(12,865	)		—			(2,963,343	)		—
Total assets	$	3,018,665	$	3,020,917		$	559,258		$	(2,965,645	)	$	3,633,195
LIABILITIES AND EQUITY
Current liabilities	$	118,089	$	215,640		$	20,825		$	(2,302	)	$	352,252
Deferred taxes		416,637		—			278			—			416,915
Long-term debt		1,169,811		—			150,000			—			1,319,811
Other liabilities		—		48,000			12,969			—			60,969
Total liabilities		1,704,537		263,640			184,072			(2,302	)		2,149,947
Commitments and contingencies (see Note 15)
Total equity		1,314,128		2,757,277			375,186			(2,963,343	)		1,483,248
Total liabilities and equity	$	3,018,665	$	3,020,917		$	559,258		$	(2,965,645	)	$	3,633,195

22

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2009
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	73,587		$	14,702		$	—		$	88,289
Natural gas		—			21,475			3,779			—			25,254
Marketing		—			636			170			—			806
Total revenues		—			95,698			18,651			—			114,349
Expenses:
Production:
Lease operating		—			36,964			7,261			—			44,225
Production, ad valorem, and severance taxes		—			9,591			2,228			—			11,819
Depletion, depreciation, and amortization		—			59,915			10,385			—			70,300
Exploration		—			11,177			22			—			11,199
General and administrative		5,477			7,272			2,035			(1,090	)		13,694
Marketing		—			609			130			—			739
Derivative fair value gain		—			(37,684	)		(10,907	)		—			(48,591	)
Other operating		40			5,586			717			—			6,343
Total expenses		5,517			93,430			11,871			(1,090	)		109,728
Operating income (loss)		(5,517	)		2,268			6,780			1,090			4,621
Other income (expenses):
Interest		(13,747	)		—			(2,216	)		—			(15,963	)
Equity income from subsidiaries		7,002			1,487			—			(8,489	)		—
Other		(63	)		1,702			5			(1,090	)		554
Total other income (expenses)		(6,808	)		3,189			(2,211	)		(9,579	)		(15,409	)
Income (loss) before income taxes		(12,325	)		5,457			4,569			(8,489	)		(10,788	)
Income tax benefit (provision)		4,769			117			(1	)		—			4,885
Consolidated net income (loss)		(7,556	)		5,574			4,568			(8,489	)		(5,903	)
Change in deferred hedge loss on interest rate swaps, net of tax		168			—			(713	)		—			(545	)
Comprehensive income (loss)	$	(7,388	)	$	5,574		$	3,855		$	(8,489	)	$	(6,448	)

23

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME
For the Three Months Ended March 31, 2008
(in thousands)

				Guarantor		Non-Guarantor						Consolidated
	Parent			Subsidiaries		Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	183,339	$	37,195		$	—		$	220,534
Natural gas		—			41,310		7,002			—			48,312
Marketing		—			1,197		2,859			—			4,056
Total revenues		—			225,846		47,056			—			272,902
Expenses:
Production:
Lease operating		—			34,292		6,058			—			40,350
Production, ad valorem, and severance taxes		—			22,654		4,798			—			27,452
Depletion, depreciation, and amortization		—			40,423		9,120			—			49,543
Exploration		—			5,459		29			—			5,488
General and administrative		3,034			4,750		2,922			(1,019	)		9,687
Marketing		—			1,389		2,393			—			3,782
Derivative fair value loss		—			49,551		15,587			—			65,138
Other operating		41			2,114		351			—			2,506
Total expenses		3,075			160,632		41,258			(1,019	)		203,946
Operating income (loss)		(3,075	)		65,214		5,798			1,019			68,956
Other income (expenses):
Interest		(18,120	)		—		(1,640	)		—			(19,760	)
Equity income from subsidiaries		70,755			1,960		—			(72,715	)		—
Other		37			1,816		17			(1,019	)		851
Total other income (expenses)		52,672			3,776		(1,623	)		(73,734	)		(18,909	)
Income before income taxes		49,597			68,990		4,175			(72,715	)		50,047
Income tax provision		(18,643	)		—		(90	)		—			(18,733	)
Consolidated net income		30,954			68,990		4,085			(72,715	)		31,314
Amortization of deferred loss on commodity derivative contracts, net of tax		(549	)		1,428		—			—			879
Change in deferred hedge loss on interest rate swaps, net of tax		397			—		(1,568	)		—			(1,171	)
Comprehensive income	$	30,802		$	70,418	$	2,517		$	(72,715	)	$	31,022

24

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Three Months Ended March 31, 2009
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Cash flows from operating activities:
Net cash provided by operating activities	$	17,708		$	405,309		$	28,608		$	—		$	451,625
Cash flows from investing activities:
Acquisition of oil and natural gas properties		—			(9,484	)		—			—			(9,484	)
Development of oil and natural gas properties		—			(152,090	)		(1,002	)		—			(153,092	)
Investments in subsidiaries		203,337			—			—			(203,337	)		—
Other		—			1,452			—			—			1,452
Net cash provided by (used in) investing activities		203,337			(160,122	)		(1,002	)		(203,337	)		(161,124	)
Cash flows from financing activities:
Proceeds from long-term debt		15,000			—			51,000			—			66,000
Payments on long-term debt		(237,000	)		—			(16,000	)		—			(253,000	)
Net equity distributions		—			(157,066	)		(46,271	)		203,337			—
Other		2,127			(67,483	)		(16,712	)		—			(82,068	)
Net cash used in financing activities		(219,873	)		(224,549	)		(27,983	)		203,337			(269,068	)
Increase (decrease) in cash and cash equivalents		1,172			20,638			(377	)		—			21,433
Cash and cash equivalents, beginning of period		607			813			619			—			2,039
Cash and cash equivalents, end of period	$	1,779		$	21,451		$	242		$	—		$	23,472

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Three Months Ended March 31, 2008
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Cash flows from operating activities:
Net cash provided by operating activities	$	49,477		$	59,302		$	22,948		$	—		$	131,727
Cash flows from investing activities:
Acquisition of oil and natural gas properties		—			(30,780	)		—			—			(30,780	)
Development of oil and natural gas properties		—			(92,944	)		(4,858	)		—			(97,802	)
Investments in subsidiaries		48,619			—			—			(48,619	)		—
Other		—			(9,680	)		(162	)		—			(9,842	)
Net cash provided by (used in) investing activities		48,619			(133,404	)		(5,020	)		(48,619	)		(138,424	)
Cash flows from financing activities:
Repurchase and retirement of common stock		(39,118	)		—			—			—			(39,118	)
Proceeds from long-term debt, net of issuance costs		214,964			—			142,310			—			357,274
Payments on long-term debt		(278,500	)		—			(25,000	)		—			(303,500	)
Net equity contributions (distributions)		—			76,796			(125,415	)		48,619			—
Other		4,557			(4,390	)		(9,625	)		—			(9,458	)
Net cash provided by (used in) financing activities		(98,097	)		72,406			(17,730	)		48,619			5,198
Increase (decrease) in cash and cash equivalents		(1	)		(1,696	)		198			—			(1,499	)
Cash and cash equivalents, beginning of period		1			1,700			3			—			1,704
Cash and cash equivalents, end of period	$	—		$	4		$	201		$	—		$	205

25

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

Note 15. Commitments and Contingencies

     EAC 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 EAC’s business, financial condition, results of operations, or liquidity.

     Additionally, EAC has contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal, long-term debt, derivative contracts, capital and operating leases, and development commitments. Please read the “Capital Commitments, Capital Resources, and Liquidity — Capital commitments — Contractual obligations” included in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Report for a description of EAC’s contractual obligations as of March 31, 2009.

Note 16. Related Party Transactions

     During the three months ended March 31, 2008, EAC received approximately $40.6 million from affiliates of Tesoro Corporation (“Tesoro”) related to gross oil and gas production sold from wells operated by Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly owned subsidiary of EAC. Mr. John V. Genova, a member of the Board, served as an employee of Tesoro until May 2008.

     Please read “Note 17. ENP” for a discussion of related party transactions with ENP.

Note 17. ENP

Administrative Services Agreement

     ENP does not have any employees. The employees supporting ENP’s operations are employees of EAC. Encore Operating performs administrative services for ENP, such as accounting, corporate development, finance, land, legal, and engineering, pursuant to an administrative services agreement. In addition, Encore Operating provides all personnel, facilities, goods, and equipment necessary to perform these services which are not otherwise provided for by ENP. Encore Operating is not liable to ENP for its performance of, or failure to perform, services under the administrative services agreement unless its acts or omissions constitute gross negligence or willful misconduct.

     Encore Operating initially received an administrative fee of $1.75 per BOE of ENP’s production for such services. From April 1, 2008 to March 31, 2009, the administration fee was $1.88 per BOE of ENP’s production. Encore Operating also charges ENP for reimbursement of actual third-party expenses incurred on ENP’s behalf and has substantial discretion in determining which third-party expenses to incur on ENP’s behalf. In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator of a well.

     The administrative fee will increase in the following circumstances:

• beginning on the first day of April in each year by an amount equal to the product of the then-current administrative fee multiplied by the COPAS Wage Index Adjustment for that year;

• if ENP or one of its subsidiaries acquires additional assets, Encore Operating may propose an increase in its administrative fee that covers the provision of services for such additional assets; however, such proposal must be approved by the board of directors of GP LLC upon the recommendation of its conflicts committee; and

• otherwise as agreed upon by Encore Operating and GP LLC, with the approval of the conflicts committee of the board of directors of GP LLC.

     ENP reimburses EAC for any state income, franchise, or similar tax incurred by EAC resulting from the inclusion of ENP and its subsidiaries in consolidated tax returns with EAC and its subsidiaries as required by applicable law. The amount of any such reimbursement is limited to the tax that ENP and its subsidiaries would have incurred had they not been included in a combined group with EAC.

Sales of Assets to ENP

     In December 2008, Encore Operating entered into a purchase and sale agreement with OLLC and ENP pursuant to which OLLC

26

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

acquired certain oil and natural gas producing properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres. The transaction closed in January 2009. The purchase price was approximately $49.5 million in cash, subject to customary adjustments (including a reduction in the purchase price for acquisition-related commodity derivative premiums of approximately $3.1 million), which OLLC financed through borrowings under the OLLC Credit Agreement. EAC used the proceeds from the sale to reduce outstanding borrowings under the EAC Credit Agreement.

     In December 2007, Encore Operating entered into a purchase and investment agreement with OLLC and ENP pursuant to which OLLC acquired certain oil and natural gas properties and related assets in the Permian Basin in West Texas and in the Williston Basin in North Dakota. The transaction closed in February 2008. The consideration for the acquisition consisted of approximately $125.3 million in cash, including post-closing adjustments, and 6,884,776 common units representing limited partner interests in ENP. In determining the total purchase price, the common units were valued at $125.0 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s historical carrying value of the properties. OLLC financed the cash portion of the purchase price through borrowings under the OLLC Credit Agreement. EAC used the proceeds from the sale to reduce outstanding borrowings under the EAC Credit Agreement.

Long-Term Incentive Plan

     In September 2007, the board of directors of GP LLC adopted the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “ENP Plan”), which provides for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. All employees, consultants, and directors of EAC, GP LLC, and any of their subsidiaries and affiliates who perform services for ENP are eligible to be granted awards under the ENP Plan. The ENP Plan is administered by the board of directors of GP LLC or a committee thereof, referred to as the plan administrator. To satisfy common unit awards under the ENP Plan, ENP may issue common units, acquire common units in the open market, or use common units owned by EAC and its affiliates.

     The total number of common units reserved for issuance pursuant to the ENP Plan is 1,150,000. As of March 31, 2009, there were 1,100,000 common units available for issuance under the ENP Plan.

     Phantom Units. Each October, ENP issues 5,000 phantom units to each member of GP LLC’s board of directors pursuant to the ENP Plan. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the plan administrator, cash equivalent to the value of a common unit. ENP intends to settle the phantom units at vesting by issuing common units; therefore, these phantom units are classified as equity instruments. Phantom units vest over a four-year period. The holders of phantom units are also entitled to receive distribution equivalent rights prior to vesting, which entitle them to receive cash equal to the amount of any cash distributions made by ENP with respect to a common unit during the period the right is outstanding. During the three months ended March 31, 2009 and 2008, ENP recognized non-cash unit-based compensation expense related to phantom units of approximately $0.1 million, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations.

     The following table summarizes the changes in ENP’s unvested phantom units for the three months ended March 31, 2009:

			Weighted
			Average
	Number of		Grant Date
	Shares		Fair Value
Outstanding at January 1, 2009		43,750	$	18.67
Granted		—		—
Vested		—		—
Forfeited		—		—
Outstanding at March 31, 2009		43,750		18.67

     As of March 31, 2009, ENP had $0.5 million of total unrecognized compensation cost related to unvested phantom units, which is expected to be recognized over a weighted average period of 2.1 years.

27

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

Management Incentive Units

     In May 2007, the board of directors of GP LLC issued 550,000 management incentive units to certain executive officers of GP LLC. During the fourth quarter of 2008, the management incentive units became convertible into ENP common units, at the option of the holder, at a ratio of one management incentive unit to approximately 3.1186 ENP common units, and all 550,000 management incentive units were converted into 1,715,205 ENP common units.

     During the three months ended March 31, 2008, ENP recognized non-cash unit-based compensation expense for the management incentive units of $1.1 million, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. As of March 31, 2009, there have been no additional issuances of management incentive units.

Distributions

     During the three months ended March 31, 2009 and 2008, ENP paid distributions of approximately $16.8 million and $9.8 million, respectively, of which $10.7 million and $5.6 million, respectively, was paid to EAC and its subsidiaries and had no impact on EAC’s consolidated cash.

Note 18. Segment Information

     EAC operates in only one industry: the oil and natural gas exploration and production industry in the United States. However, EAC is organizationally structured along two reportable segments: EAC Standalone and ENP. EAC’s segments are components of its business for which separate financial information is available and regularly evaluated by the chief operating decision maker in deciding how to allocate capital resources to projects and in assessing performance. The accounting policies used in the generation of segment financial statements are the same as those described in “Note 2. Summary of Significant Accounting Policies” in EAC’s 2008 Annual Report on Form 10-K.

     The following tables provide EAC’s operating segment information required by SFAS No. 131, “Disclosure about Segments of an Enterprise and Related Information”:

28

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

	For the Three Months Ended March 31, 2009
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	73,587		$	14,702		$	—		$	88,289
Natural gas		21,475			3,779			—			25,254
Marketing		636			170			—			806
Total revenues		95,698			18,651			—			114,349
Expenses:
Production:
Lease operating		36,964			7,261			—			44,225
Production, ad valorem, and severance taxes		9,591			2,228			—			11,819
Depletion, depreciation, and amortization		59,915			10,385			—			70,300
Exploration		11,177			22			—			11,199
General and administrative		12,749			2,035			(1,090	)		13,694
Marketing		609			130			—			739
Derivative fair value gain		(37,684	)		(10,907	)		—			(48,591	)
Other operating		5,626			717			—			6,343
Total expenses		98,947			11,871			(1,090	)		109,728
Operating income		(3,249	)		6,780			1,090			4,621
Other income (expenses):
Interest		(13,747	)		(2,216	)		—			(15,963	)
Other		1,639			5			(1,090	)		554
Total other expenses		(12,108	)		(2,211	)		(1,090	)		(15,409	)
Income (loss) before income taxes		(15,357	)		4,569			—			(10,788	)
Income tax provision		4,886			(1	)		—			4,885
Consolidated net income (loss)		(10,471	)		4,568			—			(5,903	)
Change in deferred hedge loss on interest rate swaps, net of tax		168			(713	)		—			(545	)
Comprehensive income (loss)	$	(10,303	)	$	3,855		$	—		$	(6,448	)
Segment assets (as of March 31, 2009)	$	2,821,284		$	557,447		$	(803	)	$	3,377,928
Segment liabilities (as of March 31, 2009)	$	1,683,550		$	223,891		$	(2,052	)	$	1,905,389

29

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

	For the Three Months Ended March 31, 2008
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	183,339		$	37,195		$	—		$	220,534
Natural gas		41,310			7,002			—			48,312
Marketing		1,197			2,859			—			4,056
Total revenues		225,846			47,056			—			272,902
Expenses:
Production:
Lease operating		34,292			6,058			—			40,350
Production, ad valorem, and severance taxes		22,654			4,798			—			27,452
Depletion, depreciation, and amortization		40,423			9,120			—			49,543
Exploration		5,459			29			—			5,488
General and administrative		7,770			2,922			(1,005	)		9,687
Marketing		1,389			2,393			—			3,782
Derivative fair value loss		49,551			15,587			—			65,138
Other operating		2,155			351			—			2,506
Total expenses		163,693			41,258			(1,005	)		203,946
Operating income		62,153			5,798			1,005			68,956
Other income (expenses):
Interest		(18,120	)		(1,640	)		—			(19,760	)
Other		1,839			17			(1,005	)		851
Total other expenses		(16,281	)		(1,623	)		(1,005	)		(18,909	)
Income before income taxes		45,872			4,175			—			50,047
Income tax provision		(18,643	)		(90	)		—			(18,733	)
Consolidated net income		27,229			4,085			—			31,314
Amortization of deferred loss on commodity derivative contracts, net of tax		879			—			—			879
Change in deferred hedge loss on interest rate swaps, net of tax		397			(1,568	)		—			(1,171	)
Comprehensive income	$	28,505		$	2,517		$	—		$	31,022
Segment assets (as of December 31, 2008)	$	3,074,614		$	559,258		$	(677	)	$	3,633,195
Segment liabilities (as of December 31, 2008)	$	1,967,518		$	184,072		$	(1,643	)	$	2,149,947

     In January 2009, ENP acquired certain oil and natural gas properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma as well as 10,300 unleased mineral acres from Encore Operating. For segment information, the financial results for these properties were not retroactively included under ENP for 2008.

Note 19. Subsequent Events

     Effective April 1, 2009, the administrative fee under ENP’s administrative services agreement with Encore Operating increased to $2.02 per BOE of ENP’s production as a result of the COPAS Wage Index Adjustment.

     On April 27, 2009, ENP announced a cash distribution for the first quarter of 2009 to unitholders of record as of the close of business on May 11, 2009 at a rate of $0.50 per unit. Approximately $16.8 million is expected to be paid to unitholders on or about May 15, 2009.

     On April 27, 2009, EAC issued $225 million of its 9.50% Senior Subordinated Notes due 2016 (the “9.5% Notes”), at 92.228 percent of par value. EAC received net proceeds of approximately $202.7 million, after deducting the underwriters’ discounts and

30

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

commissions of $4.5 million and offering expenses of approximately $0.4 million, which were used to reduce outstanding borrowings under the EAC Credit Agreement. Interest on the 9.5% Notes is due semi-annually on May 1 and November 1, beginning November 1, 2009. The 9.5% Notes mature on May 1, 2016. The provisions of the EAC Credit Agreement require the borrowing base to be reduced by 33 1/3 percent of the principal amount of the 9.5% Notes. As a result, the borrowing base on the EAC Credit Agreement was reduced to $825 million in April 2009.

31

ENCORE ACQUISITION COMPANY

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     The following discussion and analysis contains forward-looking statements, which give our current expectations or forecasts of future events. Actual results could differ materially from those stated in the forward-looking statements due to many factors, including, but not limited to, those set forth under “Item 1A. Risk Factors” and elsewhere in our 2008 Annual Report on Form 10-K. The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto included in “Item 1. Financial Statements” of this Report and in “Item 8. Financial Statements and Supplementary Data” of our 2008 Annual Report on Form 10-K.

Introduction

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

• First Quarter 2009 Highlights

• Second Quarter 2009 Outlook

• Results of Operations — Comparison of Quarter Ended March 31, 2009 to Quarter Ended March 31, 2008

• Capital Commitments, Capital Resources, and Liquidity

• Critical Accounting Policies and Estimates

• New Accounting Pronouncements

First Quarter 2009 Highlights

     Our financial and operating results for the first quarter of 2009 included the following:

• Our average daily production volumes increased 10 percent to 41,900 BOE/D as compared to 38,196 BOE/D in the first quarter of 2008. Oil represented 66 percent of our total production volumes in the first quarter of 2009 as compared to 72 percent in the first quarter of 2008.

• We invested $124.0 million in oil and natural gas activities, of which $120.6 million was invested in development, exploitation, and exploration activities, yielding 57 gross (25.4 net) productive wells, and $3.4 million was invested in acquisitions, primarily of unproved acreage.

• In January, we completed the sale of certain oil and natural gas properties and related assets primarily in the Arkoma Basin in Oklahoma to ENP for approximately $49.5 million in cash.

• In March 2009, we elected to monetize certain of our 2009 oil derivative contracts and received net proceeds of approximately $190.4 million, which were used to reduce outstanding borrowings under our revolving credit facility.

• Subsequent to the end of the first quarter of 2009, we issued $225 million of our 9.5% Senior Subordinated Notes due 2016, at 92.228 percent of par value. We received net proceeds of approximately $202.7 million, which were used to reduce outstanding borrowings under our revolving credit facility.

Second Quarter 2009 Outlook

     We expect our average daily production volumes to be approximately 39,100 to 40,550 BOE/D in the second quarter of 2009, net of average daily net profits production volumes of approximately 1,700 to 1,900 BOE/D. In the second quarter of 2009, we expect our oil wellhead differential as a percentage of NYMEX to be negative 12 percent and our natural gas wellhead differential as a percentage of NYMEX for dry gas to be negative 15 percent. We expect to incur development and exploration capital costs of $70 million to $80 million and approximately $5 million on the acquisition of unproved properties in the second quarter of 2009.

     In the second quarter of 2009, we expect our LOE to average $12.00 to $13.00 per BOE, including approximately $3.9 million ($1.08 per BOE) for retention bonuses to be paid in August 2009 related to our 2008 strategic alternatives process. We expect our production, ad valorem, and severance taxes (“production taxes”) to average approximately 11 percent of wellhead revenues in the second quarter of 2009. In the second quarter of 2009, we expect our depletion, depreciation, and amortization (“DD&A”) expense to average $18.50 to $19.00 per BOE. In the second quarter of 2009, we expect our general and administrative (“G&A”) expense to average $3.35 to $3.85 per BOE, including approximately $3.5 million ($0.96 per BOE) for retention bonuses to be paid in August 2009 related to our 2008 strategic alternatives process.

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ENCORE ACQUISITION COMPANY

     During the second quarter of 2009, we expect our effective tax rate to be approximately 39 percent and to pay current income taxes of $3.0 to $4.0 million.

Results of Operations

Comparison of Quarter Ended March 31, 2009 to Quarter Ended March 31, 2008

     Revenues. The following table illustrates the components of our revenues for the periods indicated, as well as each period’s respective production volumes and average prices:

	Three months ended March 31,					Increase / (Decrease)
	2009		2008			$			%
Revenues (in thousands):
Oil wellhead	$	88,289	$	221,963		$	(133,674	)
Oil hedges		—		(1,429	)		1,429
Total oil revenues	$	88,289	$	220,534		$	(132,245	)		-60	%
Natural gas wellhead	$	25,254	$	48,312		$	(23,058	)
Natural gas hedges		—		—			—
Total natural gas revenues	$	25,254	$	48,312		$	(23,058	)		-48	%
Combined wellhead	$	113,543	$	270,275		$	(156,732	)
Combined hedges		—		(1,429	)		1,429
Total combined oil and natural gas revenues		113,543		268,846			(155,303	)		-58	%
Marketing		806		4,056			(3,250	)		-80	%
Total revenues	$	114,349	$	272,902		$	(158,553	)		-58	%
Average realized prices:
Oil wellhead ($/Bbl)	$	35.48	$	88.65		$	(53.17	)
Oil hedges ($/Bbl)		—		(0.57	)		0.57
Total oil revenues ($/Bbl)	$	35.48	$	88.08		$	(52.60	)		-60	%
Natural gas wellhead ($/Mcf)	$	3.28	$	8.28		$	(5.00	)
Natural gas hedges ($/Mcf)		—		—			—
Total natural gas revenues ($/Mcf)	$	3.28	$	8.28		$	(5.00	)		-60	%
Combined wellhead ($/BOE)	$	30.11	$	77.76		$	(47.65	)
Combined hedges ($/BOE)		—		(0.41	)		0.41
Total combined oil and natural gas revenues ($/BOE)	$	30.11	$	77.35		$	(47.24	)		-61	%
Total production volumes:
Oil (MBbls)		2,488		2,504			(16	)		-1	%
Natural gas (MMcf)		7,698		5,831			1,867			32	%
Combined (MBOE)		3,771		3,476			295			8	%
Average daily production volumes:
Oil (Bbls/D)		27,645		27,516			129			0	%
Natural gas (Mcf/D)		85,528		64,081			21,447			33	%
Combined (BOE/D)		41,900		38,196			3,704			10	%
Average NYMEX prices:
Oil (per Bbl)	$	43.31	$	97.74		$	(54.43	)		-56	%
Natural gas (per Mcf)	$	4.92	$	8.02		$	(3.10	)		-39	%

     Oil revenues decreased 60 percent from $220.5 million in the first quarter of 2008 to $88.3 million in the first quarter of 2009 as a result of a $52.60 per Bbl decrease in our average realized oil price and a 16 MBbls decrease in our oil production volumes. Our lower oil production volumes decreased oil revenues by approximately $1.4 million and was primarily due to natural production declines in our Elk Basin field.

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     Our average realized oil price decreased primarily due to our lower average oil wellhead price, which decreased oil revenues by approximately $132.3 million, or $53.17 per Bbl. Our average oil wellhead price decreased primarily due to a lower average NYMEX price, which decreased from $97.74 per Bbl in the first quarter of 2008 to $43.31 Bbl in the first quarter of 2009. In addition, as a result of our discontinuance of hedge accounting in July 2006, oil revenues in the first quarter of 2008 were reduced by approximately $1.4 million, or $0.57 per Bbl.

     Our average daily production volumes were decreased by 1,406 BOE/D and 1,822 BOE/D in the first quarter of 2009 and 2008, respectively, for net profits interests related to our CCA properties, which reduced our oil wellhead revenues by approximately $3.8 million and $12.9 million in the first quarter of 2009 and 2008, respectively.

     Natural gas revenues decreased 48 percent from $48.3 million in the first quarter of 2008 to $25.3 million in the first quarter of 2009 as a result of a $5.00 per Mcf decrease in our average realized natural gas price, partially offset by a 1,867 MMcf increase in our natural gas production volumes. Our lower average realized natural gas price decreased natural gas revenues by approximately $38.5 million and was primarily due to a lower average NYMEX price, which decreased from $8.02 per Mcf in the first quarter of 2008 to $4.92 per Mcf in the first quarter of 2009. Our higher natural gas production increased natural gas revenues by approximately $15.5 million and was primarily due to successful development programs in our Permian Basin and Mid-Continent areas.

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

	Three months ended March 31,
	2009			2008
Average oil wellhead ($/Bbl)	$	35.48		$	88.65
Average NYMEX ($/Bbl)	$	43.31		$	97.74
Differential to NYMEX	$	(7.83	)	$	(9.09	)
Average oil wellhead to NYMEX percentage		82	%		91	%
Average natural gas wellhead ($/Mcf)	$	3.28		$	8.28
Average NYMEX ($/Mcf)	$	4.92		$	8.02
Differential to NYMEX	$	(1.64	)	$	0.26
Average natural gas wellhead to NYMEX percentage		67	%		103	%

     Our average oil wellhead price as a percentage of the average NYMEX price was 82 percent in the first quarter of 2009 as compared to 91 percent in the first quarter of 2008. The percentage differential widened as a result of a 56 percent decrease in NYMEX as compared to the first quarter of 2008. However, the per Bbl differential improved from $9.09 per Bbl in the first quarter of 2008 to $7.83 per Bbl in the first quarter of 2009.

     Our average natural gas wellhead price as a percentage of the average NYMEX price was 67 percent in the first quarter of 2009 as compared to 103 percent in the first quarter of 2008. Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of liquids extracted. Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas in Mcf as production. During the first quarter of 2008, the price of NGLs increased at a much faster pace than did the price of natural gas. As a result, the price we were paid per Mcf for natural gas sold under certain contracts increased to a level above NYMEX.

     Because of a negative natural gas price revision related to the fourth quarter of 2008 resulting from the rapid decline in NGLs pricing, the natural gas price for the first quarter of 2009 was reduced from its actual wellhead price of $3.81 per Mcf by an additional $0.53 to result in the $3.28 per Mcf price.

     Marketing revenues decreased 80 percent from $4.1 million in the first quarter of 2008 to $0.8 million in the first quarter of 2009 primarily as a result of a reduction in natural gas throughput in our Wildhorse pipeline. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

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Expenses. The following table summarizes our expenses for the periods indicated:

	Three months ended March 31,					Increase / (Decrease)
	2009			2008		$			%
Expenses (in thousands):
Production:
Lease operating	$	44,225		$	40,350	$	3,875
Production, ad valorem, and severance taxes		11,819			27,452		(15,633	)
Total production expenses		56,044			67,802		(11,758	)		-17	%
Other:
Depletion, depreciation, and amortization		70,300			49,543		20,757
Exploration		11,199			5,488		5,711
General and administrative		13,694			9,687		4,007
Marketing		739			3,782		(3,043	)
Derivative fair value loss (gain)		(48,591	)		65,138		(113,729	)
Other operating		6,343			2,506		3,837
Total operating		109,728			203,946		(94,218	)		-46	%
Interest		15,963			19,760		(3,797	)
Income tax provision (benefit)		(4,885	)		18,733		(23,618	)
Total expenses	$	120,806		$	242,439	$	(121,633	)		-50	%
Expenses (per BOE):
Production:
Lease operating	$	11.73		$	11.61	$	0.12
Production, ad valorem, and severance taxes		3.13			7.90		(4.77	)
Total production expenses		14.86			19.51		(4.65	)		-24	%
Other:
Depletion, depreciation, and amortization		18.64			14.25		4.39
Exploration		2.97			1.58		1.39
General and administrative		3.63			2.79		0.84
Marketing		0.20			1.09		(0.89	)
Derivative fair value loss (gain)		(12.89	)		18.74		(31.63	)
Other operating		1.68			0.72		0.96
Total operating		29.09			58.68		(29.59	)		-50	%
Interest		4.23			5.68		(1.45	)
Income tax provision (benefit)		(1.30	)		5.39		(6.69	)
Total expenses	$	32.02		$	69.75	$	(37.73	)		-54	%

     Production expenses. Total production expenses decreased 17 percent from $67.8 million in the first quarter of 2008 to $56.0 million in the first quarter of 2009. Our production margin decreased 72 percent from $202.5 million in the first quarter of 2008 to $57.5 million in the first quarter of 2009. Total oil and natural gas wellhead revenues per BOE decreased by 61 percent and total production expenses per BOE decreased by 24 percent. On a per BOE basis, our production margin decreased 74 percent to $15.25 per BOE in the first quarter of 2009 as compared to $58.25 per BOE in the first quarter of 2008.

     Production expense attributable to LOE increased $3.9 million from $40.4 million in the first quarter of 2008 to $44.2 million in the first quarter of 2009 as a result of a $0.12 increase in the per BOE rate and higher production volumes. Our higher production volumes increased LOE by approximately $3.4 million. The increase in our average LOE per BOE rate contributed approximately $0.4 million of additional LOE and was primarily attributable to approximately $3.8 million ($1.01 per BOE) for retention bonuses to be paid in August 2009 related to our 2008 strategic alternatives process, partially offset by decreases in prices paid to oilfield companies and suppliers due to an attempt to control costs.

     Production expense attributable to production taxes decreased $15.6 million from $27.5 million in the first quarter of 2008 to $11.8 million in the first quarter of 2009 primarily due to lower wellhead revenues. As a percentage of oil and natural gas wellhead revenues, production taxes remained relatively constant at 10.4 percent in the first quarter of 2009 as compared to 10.2 percent in the first quarter of 2008.

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     DD&A expense. DD&A expense increased $20.8 million from $49.5 million in the first quarter of 2008 to $70.3 million in the first quarter of 2009 as a result of a $4.39 increase in the per BOE rate and higher production volumes. Our higher production volumes increased DD&A expense by approximately $4.2 million. The increase in our average DD&A per BOE rate contributed approximately $16.6 million of additional DD&A expense and was primarily due to the decrease in our total proved reserves as a result of lower average commodity prices in the first quarter of 2009 as compared to the first quarter of 2008.

     Exploration expense. Exploration expense increased $5.7 million from $5.5 million in the first quarter of 2008 to $11.2 million in the first quarter of 2009. During the first quarter of 2009, we expensed one net exploratory dry hole totaling $5.0 million. During the first quarter of 2008, we expensed 0.5 net exploratory dry holes totaling $0.6 million. Impairment of unproved acreage increased $1.8 million from $4.1 million in the first quarter of 2008 to $5.9 million in the first quarter of 2009, primarily due to our larger unproved property base, as well as the impairment of certain acreage through the normal course of evaluation. The following table illustrates the components of exploration expense for the periods indicated:

	Three months ended March 31,				Increase /
	2009		2008		(Decrease)
	(in thousands)
Dry holes	$	5,047	$	622	$	4,425
Geological and seismic		114		378		(264	)
Delay rentals		94		346		(252	)
Impairment of unproved acreage		5,944		4,142		1,802
Total	$	11,199	$	5,488	$	5,711

     G&A expense. G&A expense increased $4.0 million from $9.7 million in the first quarter of 2008 to $13.7 million in the first quarter of 2009 primarily due to approximately $3.3 million for retention bonuses to be paid in August 2009 related to our 2008 strategic alternatives process and an increase of $0.8 million in non-cash equity-based compensation.

     Marketing expenses. Marketing expenses decreased $3.0 million from $3.8 million in the first quarter of 2008 to $0.7 million in the first quarter of 2009 primarily due to a reduction in natural gas throughput in our Wildhorse pipeline. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

     Derivative fair value loss (gain). During the first quarter of 2009, we recorded a $48.6 million derivative fair value gain as compared to a $65.1 million derivative fair value loss in the first quarter of 2008, the components of which were as follows:

	Three months ended
	March 31,						Increase /
	2009			2008			(Decrease)
	(in thousands)
Ineffectiveness	$	89		$	(381	)	$	470
Mark-to-market loss		202,782			45,614			157,168
Premium amortization		77,955			15,513			62,442
Settlements		(329,417	)		4,392			(333,809	)
Total derivative fair value loss (gain)	$	(48,591	)	$	65,138		$	(113,729	)

     The change in our derivative fair value loss (gain) was a result of commodity derivative contracts entered into during the first quarter of 2008, when prices were higher, and the significantly lower prices during the first quarter of 2009, which favorably impacted the fair values of those contracts.

     In March 2009, we elected to monetize certain of our 2009 oil derivative contracts representing approximately 77 percent of our consolidated 2009 oil derivative contracts. We received proceeds of approximately $190.4 million from these settlements, which were used to reduce outstanding borrowings under our revolving credit facility.

     Interest expense. Interest expense decreased $3.8 million from $19.8 million in the first quarter of 2008 to $16.0 million in the first quarter of 2009 primarily due to a reduction in LIBOR, partially offset by a higher weighted average long-term debt balance. Our weighted average interest rate was 4.6 percent for the first quarter of 2009 as compared to 6.4 percent for the first quarter of 2008.

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ENCORE ACQUISITION COMPANY

     The following table illustrates the components of interest expense for the periods indicated:

	Three months ended March 31,				Increase /
	2009		2008		(Decrease)
	(in thousands)
6.25% Senior Subordinated Notes	$	2,436	$	2,430	$	6
6.0% Senior Subordinated Notes		4,644		4,635		9
7.25% Senior Subordinated Notes		2,751		2,748		3
Revolving credit facilities		4,721		8,390		(3,669	)
Other		1,411		1,557		(146	)
Total	$	15,963	$	19,760	$	(3,797	)

     Income taxes. In the first quarter of 2009, we recorded an income tax benefit of $4.9 million as compared to an income tax provision of $18.7 million in the first quarter of 2008. In the first quarter of 2009, we had loss before income taxes and noncontrolling interest of $10.8 million as compared to income of $50.0 million in the first quarter of 2008. Our effective tax rate increased to 45.3 percent in the first quarter of 2009 as compared to 37.4 percent in the first quarter of 2008 primarily due to the noncontrolling interest rate effect upon adoption of SFAS 160.

Capital Commitments, Capital Resources, and Liquidity

     Capital commitments

     Our primary needs for cash are:

• Development, exploitation, and exploration of oil and natural gas properties;

• Acquisitions of oil and natural gas properties;

• Funding of working capital; and

• Contractual obligations.

     Development, exploitation, and exploration of oil and natural gas properties. The following table summarizes our costs incurred (excluding asset retirement obligations) related to development, exploitation, and exploration activities for the periods indicated:

	Three months ended March 31,
	2009		2008
	(in thousands)
Development and exploitation	$	50,347	$	57,372
Exploration		70,086		43,826
Total	$	120,433	$	101,198

     Our development and exploitation expenditures primarily relate to drilling development and infill wells, workovers of existing wells, and field related facilities. Our development and exploitation capital for the first quarter of 2009 yielded 34 gross (17.9 net) successful wells and no dry holes. Our exploration expenditures primarily relate to drilling exploratory wells, seismic costs, delay rentals, and geological and geophysical costs. Our exploration capital for the first quarter of 2009 yielded 23 gross (7.5 net) successful wells and one gross (1.0 net) dry hole.

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ENCORE ACQUISITION COMPANY

     Acquisitions of oil and natural gas properties and leasehold acreage. The following table summarizes our costs incurred (excluding asset retirement obligations) related to oil and natural gas property acquisitions for the periods indicated:

	Three months ended March 31,
	2009		2008
	(in thousands)
Acquisitions of proved property	$	82	$	14,781
Acquisitions of leasehold acreage		3,302		15,999
Total	$	3,384	$	30,780

     During the first quarter of 2009 and 2008, our capital expenditures for leasehold acreage totaled $3.3 million and $16.0 million, respectively, all of which related to the acquisition of unproved acreage in various areas.

     Funding of working capital. As of March 31, 2009 and December 31, 2008, our working capital (defined as total current assets less total current liabilities) was a negative $44.2 million and a positive $188.7 million, respectively. The decrease was primarily attributable to the monetization of certain of our 2009 oil derivative contracts and an increase in commodity prices at March 31, 2009 as compared to December 31, 2008, which negatively impacted the fair value of our outstanding commodity derivative contracts.

     For the remainder of 2009, we expect working capital to remain negative, primarily due to lower commodity prices for which we have not seen a corresponding decrease in service costs. We anticipate cash reserves to be close to zero because we intend to use any excess cash to fund capital obligations and reduce outstanding borrowings and related interest expense under our revolving credit facility. However, we have availability under our revolving credit facility to fund our obligations as they become due. We do not plan to pay cash dividends in the foreseeable future. Our production volumes, commodity prices, and differentials for oil and natural gas will be the largest variables affecting working capital. Our operating cash flow is determined in large part by production volumes and commodity prices. Assuming relatively stable commodity prices and constant or increasing production volumes, our operating cash flow should remain positive for the remainder of 2009.

     The Board approved a capital budget of $310 million for 2009, excluding proved property acquisitions. The level of these and other future expenditures are largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects, and market conditions. We plan to finance our ongoing expenditures using internally generated cash flow and availability under our revolving credit facility.

     Off-balance sheet arrangements. We have no investments in unconsolidated entities or persons that could materially affect our liquidity or availability of capital resources. We have no off-balance sheet arrangements that are material to our financial position or results of operations.

     Contractual obligations. The following table illustrates our contractual obligations and commitments at March 31, 2009:

			Payments Due by Period
					Nine Months Ending		Years Ending		Years Ending
Contractual Obligations	Maturity				December 31,		December 31,		December 31,
and Commitments	Date		Total		2009		2010 - 2011		2012 - 2013		Thereafter
			(in thousands)
6.25% Senior Subordinated Notes (a)		4/15/2014	$	201,563	$	9,375	$	18,750	$	18,750	$	154,688
6.0% Senior Subordinated Notes (a)		7/15/2015		417,000		9,000		36,000		36,000		336,000
7.25% Senior Subordinated Notes (a)		12/1/2017		247,875		10,875		21,750		21,750		193,500
Revolving credit facilities (a)		3/7/2012		571,608		8,402		22,405		540,801		—
Commodity derivative contracts (b)				—		—		—		—		—
Interest rate swaps				5,191		2,381		2,810		—		—
Capital lease obligations				1,630		349		932		349		—
Development commitments (c)				82,821		64,381		18,440		—		—
Operating leases and commitments (d)				16,474		2,932		7,577		5,965		—
Asset retirement obligations (e)				179,465		1,507		3,014		3,014		171,930
Total			$	1,723,627	$	109,202	$	131,678	$	626,629	$	856,118

(a) Includes principal and projected interest payments. Please read Note 8 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our long-term debt.

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(b)	At March 31, 2009, our commodity derivative contracts were in a net asset position. With the exception of $16.6 million of deferred premiums on commodity derivative contracts, the ultimate settlement amounts of our commodity derivative contracts are unknown because they are subject to continuing market risk. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” and Notes 5 and 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our commodity derivative contracts.
(c)	Includes authorized purchases for work in process of $73.8 million and future minimum payments for drilling rig operations of $9.1 million. Also at March 31, 2009, we had approximately $163.6 million of authorized purchases not placed with vendors (authorized AFEs), which were not accrued and are excluded from the above table but are budgeted for and expected to be made unless circumstances change.
(d)	Includes office space and equipment obligations that have non-cancelable initial lease terms in excess of one year of $15.8 million and future minimum payments for other operating commitments of $0.6 million.
(e)	Represents the undiscounted future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal at the end of field life. Please read Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our asset retirement obligations.

     Other contingencies and commitments. In order to facilitate ongoing sales of our oil production in the CCA, we ship a portion of our production in pipelines downstream and sell to purchasers at major market hubs. From time to time, shipping delays, purchaser stipulations, or other conditions may require that we sell our oil production in periods subsequent to the period in which it is produced. In such case, the deferred sale would have an adverse effect in the period of production on reported production volumes, oil and natural gas revenues, and costs as measured on a unit-of-production basis.

     The marketing of our CCA oil production is mainly dependent on transportation through the Bridger, Poplar, and Butte pipelines to markets in the Guernsey, Wyoming area. Alternative transportation routes and markets have been developed by moving a portion of the crude oil production through the Enbridge Pipeline to the Clearbrook, Minnesota hub. To a lesser extent, our production also depends on transportation through the Platte Pipeline to Wood River, Illinois as well as other pipelines connected to the Guernsey, Wyoming area. While shipments on the Platte Pipeline are oversubscribed and subject to apportionment, we have been allocated sufficient pipeline capacity to move our crude oil production. An expansion of the Enbridge Pipeline was completed in early 2008, which moved the total Rockies area pipeline takeaway closer to a balancing point with increasing production volumes and thereby provided greater stability to oil differentials in the area. In spite of the increase in capacity, the Enbridge Pipeline continues to run at full capacity and is scheduled to complete an additional expansion by the beginning of 2010. However, further restrictions on available capacity to transport oil through any of the above-mentioned pipelines, any other pipelines, or any refinery upsets could have a material adverse effect on our production volumes and the prices we receive for our production.

     The difference between NYMEX market prices and the price received at the wellhead for oil and natural gas production is commonly referred to as a differential. In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have affected this differential. We cannot accurately predict future oil and natural gas differentials. Increases in the percentage differential between the NYMEX price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial position, and cash flows.

     Capital resources

     Cash flows from operating activities. Cash provided by operating activities increased $319.9 million from $131.7 million for the first quarter of 2008 to $451.6 million for the first quarter of 2009, primarily due to the unwinding of certain of our 2009 oil derivative contracts and decreased settlements paid under our commodity derivative contracts as a result of lower average commodity prices in the first quarter of 2009 as compared to the first quarter of 2008, partially offset by a decrease in our production margin.

     Cash flows from investing activities. Cash used in investing activities increased $22.7 million from $138.4 million in the first quarter of 2008 to $161.1 million in the first quarter of 2009, primarily due to a $55.3 million increase in amounts paid to develop oil and natural gas properties, partially offset by a $21.3 million decrease in amounts paid to acquire oil and natural gas properties and a $10.6 million decrease in the net amount advanced to working interest partners. During the first quarter of 2009, we collected $1.7 million (net of advancements) from ExxonMobil for their portion of costs incurred drilling wells under the joint development agreement. During the first quarter of 2008, we advanced $9.0 million (net of collections) to ExxonMobil for their portion of costs incurred drilling wells under the joint development agreement.

     Cash flows from financing activities. Our cash flows from financing activities consist primarily of proceeds from and payments on long-term debt and repurchases of our common stock. We periodically draw on our revolving credit facility to fund acquisitions and other capital commitments.

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ENCORE ACQUISITION COMPANY

     During the first quarter of 2009, we used net cash of $269.1 million in financing activities, including net repayments on revolving credit facilities of $187 million, payments for deferred commodity premiums of $68.6 million, and ENP distributions to non-affiliate unitholders of $6.1 million. Net repayments decreased the outstanding borrowings under revolving credit facilities from $725 million at December 31, 2008 to $538 million at March 31, 2009.

     In October 2008, we announced that the Board approved a share repurchase program authorizing us to repurchase up to $40 million of our common stock. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions, and may be suspended or discontinued at any time. The share repurchase program will be funded using our available cash. As of March 31, 2009, we had repurchased and retired 620,265 shares of our outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. During the first quarter of 2009, we did not repurchase any shares of our outstanding common stock under the share repurchase program. As of March 31, 2009, approximately $22.8 million of our common stock remained authorized for repurchase.

     During the first quarter of 2008, we received net cash of $5.2 million from financing activities, including net borrowings on revolving credit facilities of $54 million, partially offset by $39.1 million of share repurchases and payments for deferred commodity premiums of $8.5 million.

     Liquidity

     Our primary sources of liquidity are internally generated cash flows and the borrowing capacity under our revolving credit facility. We also have the ability to adjust the level of our capital expenditures. We may use other sources of capital, including the issuance of debt or equity securities, to fund acquisitions or maintain our financial flexibility. We believe that our internally generated cash flows and availability under our revolving credit facility will be sufficient to fund our planned capital expenditures for the foreseeable future. However, should commodity prices decline or the capital markets remain tight, the borrowing capacity under our revolving credit facilities could be adversely affected. In the event of a reduction in the borrowing base under our revolving credit facilities, we do not believe it will result in any required prepayments of indebtedness.

     We plan to make substantial capital expenditures in the future for the acquisition, exploitation, and development of oil and natural gas properties. We intend to finance these capital expenditures with cash flows from operations. We intend to finance our acquisition and future development and exploitation activities with a combination of cash flows from operations and issuances of debt, equity, or a combination thereof.

     Issuance of 9.5% Senior Subordinated Notes Due 2016. On April 27, 2009, we issued $225 million of our 9.50% Senior Subordinated Notes due 2016 (the “9.5% Notes”), at 92.228 percent of par value. We received net proceeds of approximately $202.7 million, after deducting the underwriters’ discounts and commissions of $4.5 million and offering expenses of approximately $0.4 million, which were used to reduce outstanding borrowings under the EAC Credit Agreement. Interest on the 9.5% Notes is due semi-annually on May 1 and November 1, beginning November 1, 2009. The 9.5% Notes mature on May 1, 2016.

     Internally generated cash flows. Our internally generated cash flows, results of operations, and financing for our operations are largely dependent on oil and natural gas prices. During the first quarter of 2009, our average realized oil and natural gas prices decreased by 60 percent as compared to the first quarter of 2008. Realized oil and natural gas prices fluctuate widely in response to changing market forces. For the first quarter of 2009, approximately 66 percent of our production was oil as compared to 72 percent for the first quarter of 2008. As previously discussed, our oil wellhead differentials during the first quarter of 2009 deteriorated as compared to the first quarter of 2008, negatively impacting the prices we received for our oil production. If oil and natural gas prices decline or we experience a significant widening of our differentials, then our earnings, cash flows from operations, and availability under our revolving credit facility may be adversely impacted. Prolonged periods of lower oil and natural gas prices or sustained wider differentials could cause us to not be in compliance with financial covenants under our revolving credit facility and thereby affect our liquidity.

     Revolving credit facilities. The syndicate of lenders underwriting our revolving credit facility includes 32 banking and other financial institutions, and the syndicate of lenders underwriting ENP’s revolving credit facility includes 13 banking and other financial institutions. None of the lenders are underwriting more than eight percent of the respective total commitment. We believe the large number of lenders, the relatively small percentage participation of each, and the relatively high level of availability under each facility provides adequate diversity and flexibility should further consolidation occur within the financial services industry.

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     Encore Acquisition Company Senior Secured Credit Agreement

     In March 2007, we entered into a five-year amended and restated credit agreement (as amended, the “EAC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The EAC Credit Agreement matures on March 7, 2012. Effective February 7, 2008, we amended the EAC Credit Agreement to, among other things, provide that certain negative covenants in the EAC Credit Agreement restricting hedge transactions do not apply to any oil and natural gas hedge transaction that is a floor or put transaction not requiring any future payments or delivery by us or any of our restricted subsidiaries. Effective March 10, 2009, we amended the EAC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the EAC Credit Agreement. The EAC Credit Agreement provides for revolving credit loans to be made to us from time to time and letters of credit to be issued from time to time for the account of us or any of our restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the EAC Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. In March 2009, the borrowing base of our revolving credit facility was reaffirmed at $1.1 billion before an adjustment of $200 million solely as a result of the monetization of certain of our 2009 oil derivative contracts during the first quarter of 2009. The provisions of the EAC Credit Agreement require the borrowing base to be reduced by 33 1/3 percent of the principal amount of the 9.5% Notes. As a result, the borrowing base on the EAC Credit Agreement was reduced to $825 million in April 2009. The reductions in the borrowing base under the EAC Credit Agreement did not result in any required prepayments of indebtedness.

     Our obligations under the EAC Credit Agreement are secured by a first-priority security interest in our restricted subsidiaries’ proved oil and natural gas reserves and in our equity interests in our restricted subsidiaries. In addition, our obligations under the EAC Credit Agreement are guaranteed by our restricted subsidiaries.

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

	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.750	%		0.500	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.000	%		0.750	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.250	%		1.000	%
Greater than or equal to .90 to 1		2.500	%		1.250	%

     The “Eurodollar Rate” for any interest period (either one, two, three, or six months, as selected by EAC) is the rate equal to the British Bankers Association LIBOR Rate for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the “Eurodollar Rate” (for dollar deposits for a one-month term) for such day plus 1.0 percent.

     Any outstanding letters of credit reduce the availability under the EAC Credit Agreement. Borrowings under the EAC Credit Agreement may be repaid from time to time without penalty.

     The EAC Credit Agreement contains covenants that, among others, include:

• 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 and our restricted subsidiaries’ assets, 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;

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ENCORE ACQUISITION COMPANY

• a requirement that we maintain a ratio of consolidated current assets (as defined in the EAC Credit Agreement) to consolidated current liabilities (as defined in the EAC Credit Agreement) of not less than 1.0 to 1.0; and

• a requirement that we maintain a ratio of consolidated EBITDA (as defined in the EAC 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 EAC 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 EAC Credit Agreement to be immediately due and payable.

     We incur a commitment fee on the unused portion of the EAC Credit Agreement determined based on the ratio of amounts outstanding under the EAC Credit Agreement to the borrowing base in effect on such date. The following table summarizes the commitment fee percentage under the EAC Credit Agreement:

	Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .90 to 1		0.375	%
Greater than or equal to .90 to 1		0.500	%

     On March 31, 2009, there were $353 million of outstanding borrowings and $547 million of borrowing capacity under the EAC Credit Agreement. On April 28, 2009, there were $330 million of outstanding borrowings and $495 million of borrowing capacity under the EAC Credit Agreement.

     Encore Energy Partners Operating LLC Credit Agreement

     In March 2007, OLLC entered into a five-year credit agreement (as amended, the “OLLC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The OLLC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, OLLC amended the OLLC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. In March 2009, the borrowing base under the OLLC Credit Agreement was redetermined with no change. As of March 31, 2009, the borrowing base was $240 million.

     OLLC’s obligations under the OLLC Credit Agreement are secured by a first-priority security interest in OLLC’s 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 ENP and OLLC’s restricted subsidiaries. We consolidate the debt of ENP with that of our own; however, obligations under the OLLC Credit Agreement are non-recourse to us and our restricted subsidiaries.

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

	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.750	%		0.750	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.000	%		0.750	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.250	%		1.000	%
Greater than or equal to .90 to 1		2.500	%		1.250	%

     The “Eurodollar Rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate equal to the British Bankers Association LIBOR Rate for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the “Eurodollar Rate” (for dollar deposits for a one-month term) for such day plus 1.0 percent.

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ENCORE ACQUISITION COMPANY

     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, among others, include:

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

• a prohibition against purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;

• a restriction on creating liens on the assets of ENP, OLLC and 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 ENP and OLLC maintain a ratio of consolidated current assets (as defined in the OLLC Credit Agreement) to consolidated current liabilities (as defined in the OLLC Credit Agreement) of not less than 1.0 to 1.0;

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC Credit Agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 1.5 to 1.0;

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC Credit Agreement) to consolidated senior interest expense of not less than 2.5 to 1.0; and

• a requirement that ENP and 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.

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

	Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .90 to 1		0.375	%
Greater than or equal to .90 to 1		0.500	%

     On March 31, 2009, there were $185 million of outstanding borrowings and $55 million of borrowing capacity under the OLLC Credit Agreement. On April 28, 2009, there were $176 million of outstanding borrowings and $64 million of borrowing capacity under the OLLC Credit Agreement.

     Please read Note 8 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our long-term debt.

     Debt covenants. At March 31, 2009, we and ENP were in compliance with all debt covenants.

     Capitalization. At March 31, 2009, we had total assets of $3.4 billion and total capitalization of $2.6 billion, of which 57 percent was represented by equity and 43 percent by long-term debt. At December 31, 2008, we had total assets of $3.6 billion and total capitalization of $2.8 billion, of which 53 percent was represented by equity and 47 percent by long-term debt. The percentages of our capitalization represented by equity and long-term debt could vary in the future if debt or equity is used to finance capital projects or acquisitions.

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ENCORE ACQUISITION COMPANY

Critical Accounting Policies and Estimates

     Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in our 2008 Annual Report on Form 10-K for additional information regarding our critical accounting policies and estimates.

New Accounting Pronouncements

     The effects of new accounting pronouncements are discussed in Note 2 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.”

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of exposure, but rather indicators of potential exposure. This information provides indicators of how we view and manage our ongoing market risk exposures. We do not enter into market risk sensitive instruments for speculative trading purposes.

     The information included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2008 Annual Report on Form 10-K is incorporated herein by reference. Such information includes a description of our potential exposure to market risks, including commodity price risk and interest rate risk.

Commodity Price Sensitivity

     Our commodity derivative contracts are discussed in Notes 5 and 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” The counterparties to our commodity derivative contracts are a diverse group comprising seven institutions, all of which are currently rated A or better by Standard & Poor’s and/or Fitch, with the majority rated AA- or better. As of March 31, 2009, the fair market value of our oil derivative contracts was a net asset of approximately $95.6 million. As of March 31, 2009, the fair market value of our natural gas derivative contracts was a net asset of approximately $29.3 million. These amounts exclude deferred premiums of $16.6 million that are not subject to changes in commodity prices. Based on our open commodity derivative positions at March 31, 2009, a 10 percent increase in the respective NYMEX prices for oil and natural gas would decrease our net commodity derivative asset by approximately $12.7 million, while a 10 percent decrease in the respective NYMEX prices for oil and natural gas would increase our net commodity derivative asset by approximately $13.8 million.

Interest Rate Sensitivity

     Our long-term debt is discussed in Note 8 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” At March 31, 2009, we had total long-term debt of $1.1 billion, net of discount of $5.0 million. Of this amount, $150 million bears interest at a fixed rate of 6.25 percent, $300 million bears interest at a fixed rate of 6.0 percent, and $150 million bears interest at a fixed rate of 7.25 percent. The remaining long-term debt balance of $538 million as of March 31, 2009 consisted of outstanding borrowings under revolving credit facilities, which are subject to floating market rates of interest that are linked to LIBOR.

     At this level of floating rate debt, if LIBOR increased by 10 percent, we would incur an additional $1.1 million of interest expense per year on revolving credit facilities, and if LIBOR decreased by 10 percent, we would incur $1.1 million less. Additionally, if the discount rates on our senior notes increased by 10 percent, we estimate the fair value of our fixed rate debt at March 31, 2009 would increase from approximately $437.8 million to approximately $454.0 million, and if the discount rates on our senior notes decreased by 10 percent, we estimate the fair value would decrease to approximately $421.6 million.

     ENP’s interest rate swaps are discussed in Notes 5 and 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” As of March 31, 2009, the fair market value of ENP’s interest rate swaps was a net liability of approximately $5.2 million. If LIBOR increased by 10 percent, we estimate the liability would decrease to approximately $4.8 million, and if LIBOR decreased by 10 percent, we estimate the liability would increase to approximately $5.5 million.

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ENCORE ACQUISITION COMPANY

Item 4. Controls and Procedures

     In accordance with the Securities Exchange Act of 1934 (the “Exchange Act”) Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2009 to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

     There were no changes in our internal control over financial reporting during the first quarter of 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

     We are a party to ongoing legal proceedings in the ordinary course of business. Management does not believe the result of these legal proceedings will have a material adverse effect on our business, financial condition, results of operations, or liquidity.

Item 1A. Risk Factors

     In addition to the other information set forth in this Report, you should carefully consider the factors discussed in “Item 1A. Risk Factors” and elsewhere in our 2008 Annual Report on Form 10-K, which could materially affect our business, financial condition, or results of operations. The risks described in our 2008 Annual Report on Form 10-K are not the only risks we face. Additional risks and uncertainties currently unknown to us or that we currently deem to be immaterial may also materially adversely affect our business, financial condition, or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

     In October 2008, the Board approved a share repurchase program authorizing us to repurchase up to $40 million of our common stock. As of March 31, 2009, we had repurchased and retired 620,265 shares of our outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. During the first quarter of 2009, we did not repurchase any shares of our outstanding common stock under the share repurchase program. As of March 31, 2009, approximately $22.8 million of our common stock remained authorized for repurchase.

     The following table summarizes purchases of our common stock during the first quarter of 2009:

					Total Number of		Approximate Dollar
					Shares Purchased		Value of Shares
	Total Number				as Part of Publicly		That May Yet Be
	of Shares		Average Price		Announced Plans		Purchased Under the
Month	Purchased		Paid per Share		or Programs		Plans or Programs
January		—	$	—		—
February (a)		111,353	$	26.45		—
March		—	$	—		—
Total		111,353	$	26.45		—	$	22,830,139

(a) Certain employees directed us to withhold 111,353 shares of common stock to satisfy minimum tax withholding obligations in conjunction with the vesting of restricted stock awards.

45

EX-99.3

Exhibit 99.3

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2009

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission File Number: 001-16295

ENCORE ACQUISITION COMPANY

(Exact name of registrant as specified in its charter)

Delaware	75-2759650
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

777 Main Street, Suite 1400, Fort Worth, Texas	76102
(Address of principal executive offices)	(Zip Code)

(817) 877-9955

(Registrant’s telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o    No o

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

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

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

Number of shares of common stock, $0.01 par value, outstanding as of July 31, 2009  52,793,909

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENCORE ACQUISITION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and par value amounts)

	June 30,			December 31,
	2009			2008
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	35,840		$	2,039
Accounts receivable, net of allowance for doubtful accounts of $434 and $381, respectively		96,591			117,995
Current portion of long-term receivables		13,260			11,070
Inventory		27,266			24,798
Derivatives		53,204			349,344
Income taxes receivable		5,452			29,445
Other		5,286			6,239
Total current assets		236,899			540,930
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		3,743,817			3,538,459
Unproved properties		114,168			124,339
Accumulated depletion, depreciation, and amortization		(914,021	)		(771,564	)
		2,943,964			2,891,234
Other property and equipment		25,794			25,192
Accumulated depreciation		(14,854	)		(12,753	)
		10,940			12,439
Acquisition deposit		37,500			—
Goodwill		60,606			60,606
Derivatives		48,151			38,497
Long-term receivables, net of allowance for doubtful accounts of $11,981 and $7,643, respectively		51,419			60,915
Other		31,490			28,574
Total assets	$	3,420,969		$	3,633,195
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	15,808		$	10,017
Accrued liabilities:
Lease operating expense		24,796			19,108
Development capital		56,144			79,435
Interest		16,059			11,808
Production, ad valorem, and severance taxes		28,392			25,133
Compensation		19,865			16,216
Derivatives		23,214			63,476
Oil and natural gas revenues payable		11,373			10,821
Deferred taxes		76,862			105,768
Other		17,411			10,470
Total current liabilities		289,924			352,252
Derivatives		47,861			8,922
Future abandonment cost, net of current portion		47,985			48,058
Deferred taxes		408,514			416,915
Long-term debt		1,172,912			1,319,811
Other		3,647			3,989
Total liabilities		1,970,843			2,149,947
Commitments and contingencies (see Note 14)
Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par value, 144,000,000 shares authorized, 51,870,080 and 51,551,937 issued and outstanding, respectively		519			516
Additional paid-in capital		542,278			525,763
Treasury stock, at cost, 466 and 4,753 shares, respectively		(16	)		(101	)
Retained earnings		733,309			789,698
Accumulated other comprehensive loss		(1,434	)		(1,748	)
Total EAC stockholders’ equity		1,274,656			1,314,128
Noncontrolling interest		175,470			169,120
Total equity		1,450,126			1,483,248
Total liabilities and equity	$	3,420,969		$	3,633,195

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

1

ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
(unaudited)

	Three months ended						Six months ended
	June 30,						June 30,
	2009			2008			2009			2008
Revenues:
Oil	$	133,677		$	286,924		$	221,966		$	507,458
Natural gas		29,486			67,889			54,740			116,201
Marketing		315			2,521			1,121			6,577
Total revenues		163,478			357,334			277,827			630,236
Expenses:
Production:
Lease operating		40,451			40,697			84,676			81,047
Production, ad valorem, and severance taxes		17,033			35,043			28,852			62,495
Depletion, depreciation, and amortization		74,434			51,026			144,734			100,569
Exploration		15,934			11,593			27,133			17,081
General and administrative		13,779			11,559			27,473			21,246
Marketing		515			3,725			1,254			7,507
Derivative fair value loss		61,106			256,390			12,515			321,528
Other operating		14,835			3,226			21,178			5,732
Total expenses		238,087			413,259			347,815			617,205
Operating income (loss)		(74,609	)		(55,925	)		(69,988	)		13,031
Other income (expenses):
Interest		(19,126	)		(16,785	)		(35,089	)		(36,545	)
Other		657			686			1,211			1,537
Total other expenses		(18,469	)		(16,099	)		(33,878	)		(35,008	)
Loss before income taxes		(93,078	)		(72,024	)		(103,866	)		(21,977	)
Income tax benefit		31,558			21,322			36,443			2,589
Consolidated net loss		(61,520	)		(50,702	)		(67,423	)		(19,388	)
Less: net loss attributable to noncontrolling interest		14,545			14,982			12,892			14,888
Net loss attributable to EAC	$	(46,975	)	$	(35,720	)	$	(54,531	)	$	(4,500	)
Net loss per common share:
Basic	$	(0.91	)	$	(0.68	)	$	(1.05	)	$	(0.09	)
Diluted	$	(0.91	)	$	(0.68	)	$	(1.05	)	$	(0.09	)
Weighted average common shares outstanding:
Basic		51,849			52,344			51,769			52,571
Diluted		51,849			52,344			51,769			52,571

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

2

ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENT OF EQUITY AND COMPREHENSIVE LOSS
(in thousands)
(unaudited)

	EAC Stockholders
	Issued																	Accumulated
	Shares of					Additional			Shares of									Other
	Common			Common		Paid-in			Treasury			Treasury			Retained			Comprehensive			Noncontrolling			Total
	Stock			Stock		Capital			Stock			Stock			Earnings			Loss			Interest			Equity
Balance at December 31, 2008		51,557		$	516	$	525,763			(5	)	$	(101	)	$	789,698		$	(1,748	)	$	169,120		$	1,483,248
Exercise of stock options and vesting of restricted stock		429			3		415			—			—			—			—			—			418
Purchase of treasury stock		—			—		—			(111	)		(2,961	)		—			—			—			(2,961	)
Cancellation of treasury stock		(116	)		—		(1,188	)		116			3,046			(1,858	)		—			—			—
Non-cash equity-based compensation		—			—		7,859			—			—			—			—			69			7,928
ENP cash distributions to noncontrolling interest		—			—		—			—			—			—			—			(12,153	)		(12,153	)
ENP issuance of common units		—			—		—			—			—			—			—			40,520			40,520
Adjustment to reflect gain on ENP issuance of common units		—			—		9,312			—			—			—			—			(9,312	)		—
Other		—			—		117			—			—			—			—			—			117
Components of comprehensive loss:
Consolidated net loss		—			—		—			—			—			(54,531	)		—			(12,892	)		(67,423	)
Change in deferred hedge loss on interest rate swaps, net of tax of $219		—			—		—			—			—			—			314			118			432
Total comprehensive loss																									(66,991	)
Balance at June 30, 2009		51,870		$	519	$	542,278			—		$	(16	)	$	733,309		$	(1,434	)	$	175,470		$	1,450,126

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

3

ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)

	Six months ended
	June 30,
	2009			2008
Cash flows from operating activities:
Consolidated net loss	$	(67,423	)	$	(19,388	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation, and amortization		144,734			100,569
Non-cash exploration expense		26,264			15,545
Deferred taxes		(37,514	)		(26,756	)
Non-cash equity-based compensation expense		6,863			6,205
Non-cash derivative loss		98,325			300,370
Gain on disposition of assets		(43	)		(79	)
Other		14,039			6,619
Changes in operating assets and liabilities:
Accounts receivable		39,030			(47,301	)
Current derivatives		257,137			(670	)
Other current assets		16,142			(9,680	)
Long-term derivatives		—			(1,196	)
Other assets		5,835			(1,033	)
Accounts payable		10,719			4,208
Other current liabilities		30,702			25,825
Other noncurrent liabilities		(663	)		(923	)
Net cash provided by operating activities		544,147			352,315
Cash flows from investing activities:
Proceeds from disposition of assets		514			631
Purchases of other property and equipment		(772	)		(1,622	)
Acquisition of oil and natural gas properties		(39,990	)		(49,280	)
Divestiture of oil and natural gas properties		(220	)		—
Deposit on acquisition of oil and natural gas properties		(37,500	)		—
Development of oil and natural gas properties		(235,101	)		(233,225	)
Net collections from (advances to) working interest partners		3,709			(22,907	)
Net cash used in investing activities		(309,360	)		(306,403	)
Cash flows from financing activities:
Repurchase and retirement of common stock		—			(39,118	)
Exercise of stock options and vesting of restricted stock, net of treasury stock purchases		(2,543	)		374
Proceeds from long-term debt, net of issuance costs		320,450			618,339
Payments on long-term debt		(473,000	)		(598,500	)
ENP cash distributions to noncontrolling interest		(12,153	)		(11,168	)
Proceeds from ENP issuance of common units, net of offering costs		40,724			—
Payments of deferred commodity derivative contract premiums		(69,536	)		(20,583	)
Change in cash overdrafts		(4,928	)		4,634
Net cash used in financing activities		(200,986	)		(46,022	)
Increase (decrease) in cash and cash equivalents		33,801			(110	)
Cash and cash equivalents, beginning of period		2,039			1,704
Cash and cash equivalents, end of period	$	35,840		$	1,594

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

4

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

Note 1. Description of Business

     EAC is engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States. Since 1998, EAC has acquired producing properties with proven reserves and leasehold acreage and grown the production and proven reserves by drilling, exploring, and reengineering or expanding existing waterflood projects. EAC’s properties and oil and natural gas reserves are located in four core areas:

• the Cedar Creek Anticline (“CCA”) in the Williston Basin in Montana and North Dakota;

• the Permian Basin in West Texas and southeastern New Mexico;

• the Rockies, which includes non-CCA assets in the Williston, Big Horn, and Powder River Basins in Wyoming, Montana, and North Dakota, and the Paradox Basin in southeastern Utah; and

• the Mid-Continent area, which includes the Arkoma and Anadarko Basins in Arkansas and Oklahoma, the North Louisiana Salt Basin, and the East Texas Basin.

Note 2. Basis of Presentation

     EAC’s consolidated financial statements include the accounts of its wholly owned and majority-owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.

     In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments necessary to present fairly, in all material respects, EAC’s financial position as of June 30, 2009, results of operations for the three and six months ended June 30, 2009 and 2008, and cash flows for the six months ended June 30, 2009 and 2008. All adjustments are of a normal recurring nature. These interim results are not necessarily indicative of results for an entire year.

     Certain amounts and disclosures have been condensed or omitted from these consolidated financial statements pursuant to the rules and regulations of the SEC. Therefore, these consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in EAC’s 2008 Annual Report on Form 10-K.

Noncontrolling Interest

     As of June 30, 2009 and December 31, 2008, EAC owned approximately 58 percent and 63 percent, respectively, of ENP’s common units, as well as all of the interests of Encore Energy Partners GP LLC (“GP LLC”), a Delaware limited liability company and indirect wholly owned non-guarantor subsidiary of EAC. GP LLC is ENP’s general partner. Considering the presumption of control of GP LLC in accordance with Emerging Issues Task Force (“EITF”) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” the financial position, results of operations, and cash flows of ENP are consolidated with those of EAC.

     As presented in the accompanying Consolidated Balance Sheets, “Noncontrolling interest” as of June 30, 2009 and December 31, 2008 of $175.5 million and $169.1 million, respectively, represents third-party ownership interests in ENP. As presented in the accompanying Consolidated Statements of Operations, “Net loss attributable to noncontrolling interest” for the three and six months ended June 30, 2009 of $14.5 million and $12.9 million, respectively, and for the three and six months ended June 30, 2008 of $15.0 million and $14.9 million, respectively, represents the net loss of ENP attributable to third-party owners.

5

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following table summarizes the effects of changes in EAC’s ownership interest in ENP on EAC’s equity for the periods indicated:

	Three months ended						Six months ended
	June 30,						June 30,
	2009			2008			2009			2008
	(in thousands)
Net loss attributable to EAC	$	(46,975	)	$	(35,720	)	$	(54,531	)	$	(4,500	)
Transfer from (to) noncontrolling interest:
Increase in EAC’s paid-in capital for ENP’s issuance of 283,700 common units in connection with acquisition of net profits interest in certain Crockett County properties		—			3,458			—			3,458
Increase in EAC’s paid-in capital for ENP’s issuance of 2,760,000 common units in public offering		9,312			—			9,312			—
Net transfer from (to) noncontrolling interest		9,312			3,458			9,312			3,458
Change from net loss attributable to EAC and transfers from (to) noncontrolling interest	$	(37,663	)	$	(32,262	)	$	(45,219	)	$	(1,042	)

Supplemental Disclosures of Cash Flow Information

     The following table sets forth supplemental disclosures of cash flow information for the periods indicated:

	Six months ended June 30,
	2009		2008
	(in thousands)
Non-cash investing and financing activities:
Deferred premiums on commodity derivative contracts	$	40,087	$	25,685
ENP’s issuance of common units in connection with acquisition of net profits interest in certain Crockett County properties		—		5,748

Allowance for Doubtful Accounts

     During the three months ended June 30, 2009, EAC recorded bad debt expense of approximately $4.7 million, primarily related to balances due from ExxonMobil Corporation (“ExxonMobil”) in connection with EAC’s joint development agreement, which is included in “Other operating expense” in the accompanying Consolidated Statements of Operations. The following table summarizes the changes in allowance for doubtful accounts for the six months ended June 30, 2009 (in thousands):

Allowance for doubtful accounts at January 1, 2009	$	8,024
Bad debt expense		4,678
Write off		(287	)
Allowance for doubtful accounts at June 30, 2009	$	12,415

     Of the $12.4 million allowance for doubtful accounts at June 30, 2009, $0.4 million is short-term and $12.0 million is long-term.

Reclassifications

     Certain amounts in prior periods have been reclassified to conform to the current period presentation. In particular, certain amounts in the Consolidated Financial Statements have been either combined or classified in more detail.

6

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

New Accounting Pronouncements

FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”)

     In February 2008, the FASB issued FSP FAS 157-2, which delayed the effective date of SFAS No. 157, “Fair Value Measurements” (“SFAS 157”) for one year for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). EAC elected a partial deferral of SFAS 157 for all instruments within the scope of FSP FAS 157-2, including, but not limited to, its asset retirement obligations and indefinite lived assets. FSP FAS 157-2 was prospectively effective for financial statements issued for fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The adoption of FSP FAS 157-2 on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition. Please read “Note 5. Fair Value Measurements” for additional discussion.

SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”)

     In December 2007, the FASB issued SFAS 141R, which replaces SFAS No. 141, “Business Combinations.” SFAS 141R establishes principles and requirements for the reporting entity in a business combination, including: (1) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. In April 2009, the FASB issued FSP No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arises from Contingencies” (“FSP FAS 141R-1”), which amends and clarifies SFAS 141R to address application issues, including: (1) initial recognition and measurement; (2) subsequent measurement and accounting; and (3) disclosure of assets and liabilities arising from contingencies in a business combination. SFAS 141R and FSP FAS 141R-1 were prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008. The adoption of SFAS 141R and FSP FAS 141R-1 on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition. However, the application of SFAS 141R and FSP FAS 141R-1 to future acquisitions could impact EAC’s results of operations and financial condition and the reporting of acquisitions in the consolidated financial statements.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment to ARB No. 51” (“SFAS 160”)

     In December 2007, the FASB issued SFAS 160, which amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 was prospectively effective for fiscal years beginning on or after December 15, 2008, except for the presentation and disclosure requirements which were retrospectively effective. SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which was often referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 requires consolidated net income to be reported for the amounts attributable to both the parent and the noncontrolling interest on the face of the consolidated statement of operations and gains on a subsidiaries’ issuance of equity to be accounted for as capital transactions. The adoption of SFAS 160 on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161”)

     In March 2008, the FASB issued SFAS 161, which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), to require enhanced disclosures, including: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 was prospectively effective for financial statements issued for fiscal years beginning on or after November 15, 2008, and interim periods within those fiscal years. The adoption of SFAS 161 on January 1, 2009 required additional disclosures regarding EAC’s derivative instruments; however, it did not impact EAC’s results of operations or financial condition. Please read “Note 5. Fair Value Measurements” for additional discussion.

7

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”)

     In June 2008, the FASB issued FSP EITF 03-6-1, which addresses whether instruments granted in equity-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation for computing basic earnings per share (“EPS”) under the two-class method prescribed by SFAS No. 128, “Earnings per Share” (“SFAS 128”). FSP EITF 03-6-1 was retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The adoption of FSP EITF 03-6-1 on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition. All periods presented in the accompanying Consolidated Financial Statements have been restated to reflect the adoption of FSP EITF 03-6-1. Please read “Note 10. Earnings Per Share” for additional discussion.

SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting” (“Release 33-8995”)

     In December 2008, the SEC issued Release 33-8995, which amends oil and natural gas reporting requirements under Regulations S-K and S-X. Release 33-8995 also adds a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being phased out. Release 33-8995 permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. Release 33-8995 will also allow companies to disclose their probable and possible reserves to investors at the company’s option. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor; (2) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (3) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. Release 33-8995 is prospectively effective for financial statements issued for fiscal years ending on or after December 31, 2009. EAC is evaluating the impact Release 33-8995 will have on its financial condition, results of operations, and disclosures.

FSP No. FAS 107-1 and APB 28-1, “Disclosure of Fair Value of Financial Instruments in Interim Statements” (“FSP FAS 107-1 and APB 28-1”)

     In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which requires that disclosures concerning the fair value of financial instruments be presented in interim as well as annual financial statements. FSP FAS 107-1 and APB 28-1 is prospectively effective for financial statements issued for interim periods ending after June 15, 2009. The adoption of FSP FAS 107-1 and APB 28-1 required additional disclosures regarding EAC’s financial instruments; however, it did not impact EAC’s results of operations or financial condition. Please read “Note 5. Fair Value Measurements” for additional discussion.

SFAS No. 165, “Subsequent Events” (“SFAS 165”)

     In June 2009, the FASB issued SFAS 165 to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or available to be issued. In particular, SFAS 165 sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. SFAS 165 is prospectively effective for financial statements issued for interim or annual periods ending after June 15, 2009. The adoption of SFAS 165 on June 30, 2009 did not impact EAC’s results of operations or financial condition.

SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“SFAS 168”)

     In June 2009, the FASB issued SFAS 168, which replaces SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” SFAS 168 establishes the FASB Accounting Standards Codification as the sole source of authoritative accounting principles recognized by the FASB to be applied by all nongovernmental entities in the preparation of financial statements in conformity with GAAP. SFAS 168 is prospectively effective for financial statements for fiscal years ending on or after September 15, 2009, and interim periods within those fiscal years. The adoption of SFAS 168 on July 1, 2009 did not impact EAC’s results of operations or financial condition.

8

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 3. Inventory

     Inventory includes materials and supplies and oil in pipelines, which are stated at the lower of cost (determined on an average basis) or market. Oil produced at the lease which resides unsold in pipelines is carried at an amount equal to its operating costs to produce. Oil in pipelines purchased from third parties is carried at average purchase price. Inventory consisted of the following as of the dates indicated:

	June 30,		December 31,
	2009		2008
	(in thousands)
Materials and supplies	$	19,766	$	15,933
Oil in pipelines		7,500		8,865
Total inventory	$	27,266	$	24,798

     During the three months ended June 30, 2009, EAC recorded a lower of cost or market adjustment of approximately $5.7 million to the carrying value of pipe and other tubular inventory whose market value had declined below cost, which is included in “Other operating expense” in the accompanying Consolidated Statements of Operations.

Note 4. Proved Properties

     Amounts shown in the accompanying Consolidated Balance Sheets as “Proved properties, including wells and related equipment” consisted of the following as of the dates indicated:

	June 30,		December 31,
	2009		2008
	(in thousands)
Proved leasehold costs	$	1,448,959	$	1,421,859
Wells and related equipment — Completed		2,252,196		1,943,275
Wells and related equipment — In process		42,662		173,325
Total proved properties	$	3,743,817	$	3,538,459

Note 5. Fair Value Measurements

     The following table sets forth EAC’s book value and estimated fair value of financial instruments as of the dates indicated:

	June 30, 2009				December 31, 2008
	Book		Fair		Book		Fair
	Value		Value		Value		Value
	(in thousands)
Assets:
Cash and cash equivalents	$	35,840	$	35,840	$	2,039	$	2,039
Accounts receivable, net		96,591		96,591		117,995		117,995
Plugging bond		849		1,003		824		1,202
Bell Creek escrow		9,257		9,258		9,229		9,241
Commodity derivative contracts		101,355		101,355		387,841		387,841
Long-term receivables, net		64,679		64,679		71,986		71,986
Liabilities:
Accounts payable		15,808		15,808		10,017		10,017
6.25% Senior Subordinated Notes		150,000		126,000		150,000		101,250
6.0% Senior Subordinated Notes		296,292		249,000		296,040		194,250
9.5% Senior Subordinated Notes		207,799		222,188		—		—
7.25% Senior Subordinated Notes		148,821		127,500		148,771		94,500
Revolving credit facilities		370,000		370,000		725,000		725,000
Commodity derivative contracts		28,323		28,323		229		229
Deferred premiums on commodity derivative contracts		38,927		38,927		67,610		67,610
Interest rate swaps		3,825		3,825		4,559		4,559

9

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The book values of cash and cash equivalents, accounts receivable, net, and accounts payable approximate fair value due to the short-term nature of these instruments. The book value of long-term receivables, net, approximates fair value as it is net of amounts deemed to be uncollectible and bears interest at market rates. The plugging bond and Bell Creek escrow are included in “Other assets” on the accompanying Consolidated Balance Sheets and are classified as “held to maturity” and therefore, are recorded at amortized cost, which was less than fair value. The fair values of the plugging bond and Bell Creek escrow were determined using open market quotes. The fair values of the senior subordinated notes were determined using open market quotes. The difference between book value and fair value represents the premium or discount on that date. The book value of the revolving credit facilities approximates fair value as the interest rate is variable. Commodity derivative contracts and interest rate swaps are marked-to-market each quarter. Deferred premiums on commodity derivative contracts were recorded at their net present value at the time the contracts were entered into and EAC accretes that value to the eventual settlement price by recording interest expense each period.

Derivative Policy

     EAC uses various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with its oil and natural gas production. These arrangements are structured to reduce EAC’s exposure to commodity price decreases, but they can also limit the benefit EAC might otherwise receive from commodity price increases. EAC’s risk management activity is generally accomplished through over-the-counter derivative contracts with large financial institutions. EAC also uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation.

     EAC applies the provisions of SFAS 133, which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, changes in fair value can be recognized in accumulated other comprehensive loss until such time as the hedged item is recognized in earnings.

     In order to qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically. The effective portion of cash flow hedges are marked to market through accumulated other comprehensive loss each period.

     EAC has elected to designate its current interest rate swaps as cash flow hedges. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized in earnings as “Derivative fair value loss” in the accompanying Consolidated Statements of Operations.

     EAC has not elected to designate its current portfolio of commodity derivative contracts as hedges. Therefore, changes in fair value of these derivative instruments are recognized in earnings as “Derivative fair value loss” in the accompanying Consolidated Statements of Operations.

Commodity Derivative Contracts

     EAC manages commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of sales volumes. Put contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collars provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price.

     From time to time, EAC enters into floor spreads. In a floor spread, EAC purchases puts at a specified price (a “purchased put”) and also sells a put at a lower price (a “short put”). This strategy enables EAC to achieve downside protection for a portion of its production, while funding the cost of such protection by selling a put at a lower price. If the price of the commodity falls below the strike price of the purchased put, then EAC has protection against commodity price decreases for the covered production down to the strike price of the short put. At commodity prices below the strike price of the short put, the benefit from the purchased put is generally offset by the expense associated with the short put. For example, in 2007, EAC purchased oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. As NYMEX prices increased in 2008, EAC wished to protect downside price exposure at the higher price. In order to do this, EAC purchased oil put options for 2,000 Bbls/D in 2010 at $75 per Bbl and simultaneously sold oil put options for

10

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

2,000 Bbls/D in 2010 at $65 per Bbl. Thus, after these transactions were completed, EAC had purchased two oil put options for 2,000 Bbls/D in 2010 (one at $65 per Bbl and one at $75 per Bbl) and sold one oil put option for 2,000 Bbls/D in 2010 at $65 per Bbl. However, the net effect resulted in EAC owning one oil put option for 2,000 Bbls/D at $75 per Bbl. In the following tables, the purchased floor component of these floor spreads are shown net and included with EAC’s other floor contracts.

     The following tables summarize EAC’s open commodity derivative contracts as of June 30, 2009:

Oil Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted		Asset
	Daily		Average		Daily		Average		Daily		Average		(Liability)
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(in thousands)
July — Dec. 2009 (a)													$	21,227
		3,130	$	110.00		440	$	97.75		—	$	—
		—		—		—		—		1,000		68.70
2010														(172	)
		880		80.00		440		93.80		—		—
		2,000		75.00		3,000		74.13		1,385		75.78
		8,385		62.83		500		65.60		1,750		64.08
		1,000		56.00		—		—		1,000		59.70
2011														23,343
		1,880		80.00		1,440		95.41		325		80.00
		2,500		70.00		—		—		1,060		78.42
		4,385		65.00		—		—		250		69.65
2012														2,918
		750		70.00		500		82.05		835		81.19
		2,135		65.00		250		79.25		1,300		76.54
													$	47,316

(a) In addition, ENP has a floor contract for 1,000 Bbls/D at $63.00 per Bbl and a short floor contract for 1,000 Bbls/D at $65.00 per Bbl.

Natural Gas Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted		Asset
	Daily		Average		Daily		Average		Daily		Average		(Liability)
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(in thousands)
July — Dec. 2009													$	12,715
		3,800	$	8.20		3,800	$	9.83		—	$	—
		3,800		7.20		5,000		7.45		—		—
		6,800		6.57		15,000		6.63		—		—
		15,000		5.64		—		—		—		—
2010														14,169
		3,800		8.20		3,800		9.58		25,452		6.46
		4,698		7.26		—		—		550		5.86
2011														993
		3,398		6.31		—		—		27,952		6.48
		—		—		—		—		550		5.86
2012														(2,161	)
		898		6.76		—		—		25,452		6.47
		—		—		—		—		550		5.86
													$	25,716

     As of June 30, 2009, EAC had $38.9 million of deferred premiums payable, of which $29.0 million was long-term and included in “Derivatives” in the non-current liabilities section of the accompanying Consolidated Balance Sheet and $9.9 million was current and included in “Derivatives” in the current liabilities section of the accompanying Consolidated Balance Sheet. The premiums relate to various oil and natural gas floor contracts and are payable on a monthly basis from July 2009 to January 2013.

11

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     Counterparty Risk. At June 30, 2009, EAC had committed greater than 10 percent (in terms of fair market value) of either its oil or natural gas derivative contracts to the following counterparties:

	Percentage of			Percentage of
	Oil Derivative			Natural Gas Derivative
	Contracts			Contracts
Counterparty	Committed			Committed
BNP Paribas		42	%		24	%
Calyon		19	%		39	%
JP Morgan		11	%		14	%
Wachovia Bank		12	%		22	%

     In order to mitigate the credit risk of financial instruments, EAC enters into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and EAC. Instead of treating each derivative financial transaction between the counterparty and EAC separately, the master netting agreement enables the counterparty and EAC to aggregate all financial trades and treat them as a single agreement. This arrangement benefits EAC in three ways: (1) the netting of the value of all trades reduces the likelihood of counterparties requiring daily collateral posting by EAC; (2) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (3) netting of settlement amounts reduces EAC’s credit exposure to a given counterparty in the event of close-out. EAC’s accounting policy is to not offset fair value amounts recorded in the accompanying Consolidated Balance Sheets for derivative instruments.

Interest Rate Swaps

     ENP uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation, whereby it converts the interest due on certain floating rate debt under its revolving credit facility to a weighted average fixed rate. The following table summarizes ENP’s open interest rate swaps as of June 30, 2009, all of which were entered into with Bank of America, N.A.:

	Notional		Fixed			Floating
Term	Amount		Rate			Rate
	(in thousands)
July 2009 - Jan. 2011	$	50,000		3.1610	%	1-month LIBOR
July 2009 - Jan. 2011		25,000		2.9650	%	1-month LIBOR
July 2009 - Jan. 2011		25,000		2.9613	%	1-month LIBOR
July 2009 - Mar. 2012		50,000		2.4200	%	1-month LIBOR

     The actual gains or losses ENP will realize from its interest rate swaps may vary significantly from the deferred loss recorded in accumulated other comprehensive loss due to the fluctuation of interest rates.

Current Period Impact

     EAC recognized derivative fair value gains and losses related to: (1) ineffectiveness on derivative contracts designated as hedges; (2) changes in the fair market value of derivative contracts not designated as hedges; (3) settlements on derivative contracts not designated as hedges; and (4) premium amortization. The following table summarizes the components of “Derivative fair value loss” for the periods indicated:

	Three months ended					Six months ended
	June 30,					June 30,
	2009			2008		2009			2008
	(in thousands)
Ineffectiveness	$	6		$	39	$	(34	)	$	(343	)
Mark-to-market loss		78,082			219,433		280,993			265,048
Premium amortization		6,764			17,293		84,719			32,806
Settlements		(23,746	)		19,625		(353,163	)		24,017
Total derivative fair value loss	$	61,106		$	256,390	$	12,515		$	321,528

12

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     In March 2009, EAC elected to monetize certain of its 2009 oil derivative contracts and received proceeds of approximately $190.4 million from these settlements, which were used to reduce outstanding borrowings under EAC’s revolving credit facility.

Accumulated Other Comprehensive Loss

     At June 30, 2009 and December 31, 2008, accumulated other comprehensive loss consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps of $1.4 million and $1.7 million, respectively. During the twelve months ending June 30, 2010, EAC expects to reclassify $3.3 million of deferred losses associated with ENP’s interest rate swaps from accumulated other comprehensive loss to interest expense.

Tabular Disclosures of Fair Value Measurements

     The following table summarizes the fair value of EAC’s derivative contracts as of the dates indicated (in thousands):

	Asset Derivatives						Liability Derivatives
	June 30, 2009			December 31, 2008			June 30, 2009			December 31, 2008
	Balance Sheet	Fair		Balance Sheet	Fair		Balance Sheet			Balance Sheet
	Location	Value		Location	Value		Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments under SFAS 133
Commodity derivative contracts	Derivatives - current	$	53,204	Derivatives - current	$	349,344	Derivatives - current	$	10,037	Derivatives - current	$	—
Commodity derivative contracts	Derivatives - noncurrent		48,151	Derivatives - noncurrent		38,497	Derivatives - noncurrent		18,286	Derivatives - noncurrent		229
Total derivatives not designated as hedging instruments under SFAS 133		$	101,355		$	387,841		$	28,323		$	229
			`
Derivatives designated as hedging instruments under SFAS 133
Interest rate swaps	Derivatives - current	$	—	Derivatives - current	$	—	Derivatives - current	$	3,272	Derivatives - current	$	1,297
Interest rate swaps	Derivatives - noncurrent		—	Derivatives - noncurrent		—	Derivatives - noncurrent		553	Derivatives - noncurrent		3,262
Total derivatives designated as hedging instruments under SFAS 133		$	—		$	—		$	3,825		$	4,559
Total derivatives		$	101,355		$	387,841		$	32,148		$	4,788

     The following table summarizes the effect of derivative instruments not designated as hedges under SFAS 133 on the Consolidated Statements of Operations for the periods indicated (in thousands):

		Amount of Loss Recognized In Income
Derivatives Not Designated as	Location of Loss	Three Months Ended June 30,				Six Months Ended June 30,
Hedges Under SFAS 133	Recognized In Income	2009		2008		2009		2008
Commodity derivative contracts	Derivative fair value loss	$	61,100	$	256,351	$	12,549	$	321,871

     The following tables summarize the effect of derivative instruments designated as hedges under SFAS 133 on the Consolidated Statements of Operations for the periods indicated (in thousands):

						Amount of Loss
	Amount of Gain					Reclassified from					Amount of Loss
	Recognized in OCI				Location of Loss	Accumulated OCI into					Recognized In Income
	(Effective Portion)				(Gain) Reclassified	Income (Effective Portion)					as Ineffective
	Three months ended				from Accumulated	Three months ended				Location of Loss (Gain)	Three months ended
Derivatives Designated as	June 30,				OCI into Income	June 30,				Recognized in Income	June 30,
Hedges Under SFAS 133	2009		2008		(Effective Portion)	2009		2008		as Ineffective	2009		2008
Interest rate swaps	$	267	$	942	Interest expense	$	922	$	125	Derivative fair value loss	$	6	$	39
Commodity derivative contracts		—		—	Oil and natural gas revenues		—		1,428			—		—
Total	$	267	$	942		$	922	$	1,553		$	6	$	39

13

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

						Amount of Loss
	Amount of Loss					Reclassified from					Amount of Gain
	Recognized in OCI				Location of Loss	Accumulated OCI into					Recognized In Income
	(Effective Portion)				(Gain) Reclassified	Income (Effective Portion)					as Ineffective
	Six months ended				from Accumulated	Six months ended				Location of Loss (Gain)	Six months ended
Derivatives Designated as	June 30,				OCI into Income	June 30,				Recognized in Income	June 30,
Hedges Under SFAS 133	2009		2008		(Effective Portion)	2009		2008		as Ineffective	2009		2008
Interest rate swaps	$	1,489	$	762	Interest expense	$	1,803	$	108	Derivative fair value loss	$	34	$	343
Commodity derivative contracts		—		—	Oil and natural gas revenues		—		2,857			—		—
Total	$	1,489	$	762		$	1,803	$	2,965		$	34	$	343

Fair Value Hierarchy

     As discussed in “Note 2. Basis of Presentation,” EAC adopted FSP FAS 157-2 on January 1, 2009, as it relates to nonfinancial assets and liabilities. EAC adopted SFAS 157 on January 1, 2008, as it relates to financial assets and liabilities. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

• Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities.

• Level 2 — Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.

• Level 3 — Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.

     EAC’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the financial assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions were used to estimate the fair values of EAC’s assets and liabilities that are accounted for at fair value on a recurring basis:

• Level 2 — Fair values of oil and natural gas swaps were estimated using a combined income-based and market-based valuation methodology based upon forward commodity price curves obtained from independent pricing services reflecting broker market quotes. Fair values of interest rate swaps were estimated using a combined income and market-based valuation methodology based upon credit ratings and forward interest rate yield curves obtained from independent pricing services reflecting broker market quotes.

• Level 3 — EAC’s oil and natural gas calls, puts, and short puts are average value options, which are not exchange-traded contracts. Settlement is determined by the average underlying price over a predetermined period of time. EAC uses both observable and unobservable inputs in a Black-Scholes valuation model to determine fair value. Accordingly, these derivative instruments are classified within the Level 3 valuation hierarchy. The observable inputs of EAC’s valuation model include: (1) current market and contractual prices for the underlying instruments; (2) quoted forward prices for oil and natural gas; and (3) interest rates, such as a LIBOR curve for a term similar to the commodity derivative contract. The unobservable inputs of EAC’s valuation model include volatility. The implied volatilities for EAC’s calls, puts, and short puts with comparable strike prices are based on the settlement values from certain exchange-traded contracts. The implied volatilities for calls, puts, and short puts where there are no exchange-traded contracts with the same strike price are extrapolated from exchange-traded implied volatilities by an independent party.

     EAC adjusts the valuations from the valuation model for nonperformance risk, using management’s estimate of the counterparty’s credit quality for asset positions and EAC’s credit quality for liability positions. EAC uses the multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps. EAC considers the impact of netting and offset provisions in the agreements on counterparty credit risk, including whether the position with the counterparty is a net asset or net liability. There have been no changes in the valuation techniques used to measure the fair value of EAC’s oil and natural gas calls, puts, or short puts during 2009.

14

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following table sets forth EAC’s assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2009:

				Fair Value Measurements at Reporting Date Using
				Quoted Prices in
				Active Markets for		Significant Other			Significant
	Asset (Liability) at			Identical Assets		Observable Inputs			Unobservable Inputs
Description	June 30, 2009			(Level 1)		(Level 2)			(Level 3)
	(in thousands)
Oil derivative contracts — swaps	$	(14,733	)	$	—	$	(14,733	)	$	—
Oil derivative contracts — floors and caps		62,049			—		—			62,049
Natural gas derivative contracts — swaps		4,693			—		4,693			—
Natural gas derivative contracts — floors and caps		21,023			—		—			21,023
Interest rate swaps		(3,825	)		—		(3,825	)		—
Total	$	69,207		$	—	$	(13,865	)	$	83,072

     The following table summarizes the changes in the fair value of EAC’s Level 3 assets and liabilities for the six months ended June 30, 2009:

	Fair Value Measurements Using Significant
	Unobservable Inputs (Level 3)
	Oil Derivative			Natural Gas
	Contracts -			Derivative Contracts -
	Floors and Caps			Floors and Caps			Total
				(in thousands)
Balance at January 1, 2009	$	337,335		$	12,741		$	350,076
Total gains (losses):
Included in earnings		13,106			21,840			34,946
Purchases, issuances, and settlements		(288,392	)		(13,558	)		(301,950	)
Balance at June 30, 2009	$	62,049		$	21,023		$	83,072
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	13,106		$	21,840		$	34,946

     Since EAC does not use hedge accounting for its commodity derivative contracts, all gains and losses on its Level 3 assets and liabilities are included in “Derivative fair value loss” in the accompanying Consolidated Statements of Operations. All fair values have been adjusted for non-performance risk, resulting in a reduction of the net commodity derivative asset of approximately $0.8 million as of June 30, 2009.

     EAC’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the nonfinancial assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions were used to estimate the fair values of EAC’s assets and liabilities that are accounted for at fair value on a nonrecurring basis:

• Level 3 — Fair values of asset retirement obligations are determined using discounted cash flow methodologies based on inputs, such as plugging costs and reserve lives, which are not readily available in public markets. See “Note 6. Asset Retirement Obligations” for additional discussion of EAC’s asset retirement obligations.

15

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following table sets forth EAC’s assets and liabilities that were measured at fair value on a nonrecurring basis as of June 30, 2009:

			Fair Value Measurements Using
			Quoted Prices in
			Active Markets for		Significant Other		Significant
	Liability at		Identical Assets		Observable Inputs		Unobservable Inputs		Total Gains
Description	June 30, 2009		(Level 1)		(Level 2)		(Level 3)		(Losses)
	(in thousands)
Asset retirement obligations	$	255	$	—	$	—	$	255	$	—

Note 6. Asset Retirement Obligations

     Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in EAC’s asset retirement obligations for the six months ended June 30, 2009 (in thousands):

Future abandonment liability at January 1, 2009	$	49,569
Wells drilled		194
Acquisition of properties		61
Divestiture		(221	)
Accretion of discount		1,181
Plugging and abandonment costs incurred		(663	)
Revision of previous estimates		(469	)
Future abandonment liability at June 30, 2009	$	49,652

     As of June 30, 2009, $48.0 million of EAC’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $1.7 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheets. Approximately $4.6 million of the future abandonment liability represents the estimated cost for decommissioning ENP’s Elk Basin natural gas processing plant. ENP expects to continue reserving additional amounts based on the estimated timing to cease operations of the natural gas processing plant.

     As of June 30, 2009 and December 31, 2008, EAC held $9.3 million and $9.2 million, respectively, in escrow, which is to be released only for reimbursement of actual plugging and abandonment costs incurred on its Bell Creek properties, which is included in other long-term assets in the accompanying Consolidated Balance Sheets.

Note 7. Long-Term Debt

     Long-term debt consisted of the following as of the dates indicated:

	Maturity		June 30,		December 31,
	Date		2009		2008
			(in thousands)
Revolving credit facilities		3/7/2012	$	370,000	$	725,000
6.25% Senior Subordinated Notes		4/15/2014		150,000		150,000
6.0% Senior Subordinated Notes, net of unamortized discount of $3,708 and $3,960, respectively		7/15/2015		296,292		296,040
9.5% Senior Subordinated Notes, net of unamortized discount of $17,201 and zero, respectively		5/1/2016		207,799		—
7.25% Senior Subordinated Notes, net of unamortized discount of $1,179 and $1,229, respectively		12/1/2017		148,821		148,771
Total			$	1,172,912	$	1,319,811

16

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Encore Acquisition Company Senior Secured Credit Agreement

     EAC is a party to a five-year amended and restated credit agreement dated March 7, 2007 (as amended, the “EAC Credit Agreement”). The EAC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, EAC amended the EAC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the EAC Credit Agreement. The EAC Credit Agreement provides for revolving credit loans to be made to EAC from time to time and letters of credit to be issued from time to time for the account of EAC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the EAC Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. In March 2009, the borrowing base of the EAC Credit Agreement was reaffirmed at $1.1 billion before a reduction of $200 million solely as a result of the monetization of certain of EAC’s 2009 oil derivative contracts during the first quarter of 2009. In April 2009, the borrowing base of the EAC Credit Agreement was reduced by $75 million as a result of EAC’s issuance of senior subordinated notes. As of June 30, 2009, the borrowing base was $825 million and there were $175 million of outstanding borrowings and $650 million of borrowing capacity under the EAC Credit Agreement.

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

	Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .90 to 1		0.375	%
Greater than or equal to .90 to 1		0.500	%

     EAC’s obligations under the EAC Credit Agreement are secured by a first-priority security interest in substantially all of EAC’s restricted subsidiaries’ proved oil and natural gas reserves and in EAC’s equity interests in its restricted subsidiaries. In addition, EAC’s obligations under the EAC Credit Agreement are guaranteed by its restricted subsidiaries.

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

	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.750	%		0.500	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.000	%		0.750	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.250	%		1.000	%
Greater than or equal to .90 to 1		2.500	%		1.250	%

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by EAC) is the rate equal to the British Bankers Association LIBOR Rate for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0 percent.

     Any outstanding letters of credit reduce the availability under the EAC Credit Agreement. Borrowings under the EAC Credit Agreement may be repaid from time to time without penalty.

     The EAC Credit Agreement contains covenants that, among others, include:

• 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;

17

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

• a restriction on creating liens on the assets of EAC 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 EAC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0; and

• a requirement that EAC maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0.

     As of June 30, 2009, EAC was in compliance with all covenants of the EAC Credit Agreement.

     The EAC Credit Agreement contains customary events of default including, among others, the following:

• failure to pay principal on any loan when due;

• failure to pay accrued interest on any loan or fees when due and such failure continues for more than three days;

• failure to observe or perform covenants and agreements contained in the OLLC Credit Agreement, subject in some cases to a 30-day grace period after discovery or notice of such failure;

• failure to make a payment when due on any other debt in a principal amount equal to or greater than $15 million or any other event or condition occurs which results in the acceleration of such debt or entitles the holder of such debt to accelerate the maturity of such debt;

• the commencement of liquidation, reorganization, or similar proceedings with respect to OLLC or any guarantor under bankruptcy or insolvency law, or the failure of OLLC or any guarantor generally to pay its debts as they become due;

• the entry of one or more judgments in excess of $15 million (to the extent not covered by insurance) and such judgment(s) remain unsatisfied and unstayed for 30 days;

• the occurrence of certain ERISA events involving an amount in excess of $15 million;

• there cease to exist liens covering at least 80 percent of the borrowing base properties; or

• the occurrence of a change in control.

     If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the EAC Credit Agreement to be immediately due and payable.

Encore Energy Partners Operating LLC Credit Agreement

     Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly owned subsidiary of ENP, is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “OLLC Credit Agreement”). The OLLC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, OLLC amended the OLLC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. In March 2009, the borrowing base under the OLLC Credit Agreement was redetermined with no change. As of June 30, 2009, the borrowing base was $240 million and there were $195 million of outstanding borrowings and $45 million of borrowing capacity under the OLLC Credit Agreement.

18

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

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

	Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .90 to 1		0.375	%
Greater than or equal to .90 to 1		0.500	%

     OLLC’s obligations under the OLLC Credit Agreement are secured by a first-priority security interest in substantially all of OLLC’s proved oil and natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition, OLLC’s obligations under the OLLC Credit Agreement are guaranteed by ENP and OLLC’s restricted subsidiaries. Obligations under the OLLC Credit Agreement are non-recourse to EAC and its restricted subsidiaries.

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

	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.750	%		0.750	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.000	%		0.750	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.250	%		1.000	%
Greater than or equal to .90 to 1		2.500	%		1.250	%

     The “Eurodollar Rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate equal to the British Bankers Association LIBOR Rate for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0 percent.

     Any outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.

     The OLLC Credit Agreement contains covenants that, among others, include:

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

• a prohibition against purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;

• a restriction on creating liens on the assets of ENP, OLLC, and OLLC’s restricted subsidiaries, subject to permitted exceptions;

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

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

• a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

• a requirement that ENP and OLLC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0;

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 1.5 to 1.0;

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA to consolidated senior interest expense of not less than 2.5 to 1.0; and

• a requirement that ENP and OLLC maintain a ratio of consolidated funded debt (excluding certain related party debt) to consolidated adjusted EBITDA of not more than 3.5 to 1.0.

19

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     As of June 30, 2009, OLLC was in compliance with all covenants of the OLLC Credit Agreement.

     The OLLC Credit Agreement contains customary events of default including, among others, the following:

• failure to pay principal on any loan when due;

• failure to pay accrued interest on any loan or fees when due and such failure continues for more than three days;

• failure to observe or perform covenants and agreements contained in the OLLC Credit Agreement, subject in some cases to a 30-day grace period after discovery or notice of such failure;

• failure to make a payment when due on any other debt in a principal amount equal to or greater than $3 million or any other event or condition occurs which results in the acceleration of such debt or entitles the holder of such debt to accelerate the maturity of such debt;

• the commencement of liquidation, reorganization, or similar proceedings with respect to OLLC or any guarantor under bankruptcy or insolvency law, or the failure of OLLC or any guarantor generally to pay its debts as they become due;

• the entry of one or more judgments in excess of $3 million (to the extent not covered by insurance) and such judgment(s) remain unsatisfied and unstayed for 30 days;

• the occurrence of certain ERISA events involving an amount in excess of $3 million;

• there cease to exist liens covering at least 80 percent of the borrowing base properties; or

• the occurrence of a change in control.

     If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately due and payable.

9.50% Senior Subordinated Notes due 2016 (the “9.5% Notes”)

     In April 2009, EAC issued $225 million of its 9.5% Notes at 92.228 percent of par value. EAC received net proceeds of approximately $202.5 million, after deducting the underwriters’ discounts and commissions of $4.5 million, in the aggregate, and offering expenses of approximately $0.6 million. EAC used the net proceeds to reduce outstanding borrowings under the EAC Credit Agreement. Interest on the 9.5% Notes is due semi-annually on May 1 and November 1, beginning November 1, 2009. The 9.5% Notes mature on May 1, 2016.

Note 8. Stockholders’ Equity

Stock Repurchase Program

     In October 2008, EAC announced that its Board of Directors (the “Board”) approved a share repurchase program authorizing EAC to repurchase up to $40 million of its common stock. As of June 30, 2009, EAC had repurchased and retired 620,265 shares of its outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. During the three and six months ended June 30, 2009, EAC did not repurchase any shares of its outstanding common stock under the share repurchase program. As of June 30, 2009, approximately $22.8 million of EAC’s common stock remained authorized for repurchase.

Stock Option Exercises and Restricted Stock Vestings

     During the three and six months ended June 30, 2009, certain employees exercised 19,748 options and 21,484 options, respectively, for which EAC received proceeds of approximately $0.4 million and $0.4 million, respectively. During the three and six months ended June 30, 2009, certain employees elected to satisfy minimum tax withholding obligations in conjunction with the vesting of restricted stock by directing EAC to withhold 466 shares and 111,819 shares of common stock, respectively, which are accounted for as treasury stock until they are formally retired.

Issuance of ENP Common Units

     In May 2009, ENP issued 2,760,000 common units at a price to the public of $15.60 per unit. As a result, EAC’s ownership percentage of ENP’s common units decreased from approximately 63 percent to approximately 58 percent. Additionally, EAC increased “Noncontrolling interest” and “Additional paid-in capital” on the accompanying Consolidated Balance Sheets by $31.2 million and $9.3 million, respectively, to recognize the net proceeds from the issuance of ENP’s common units.

20

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 9. Income Taxes

     The components of income tax benefit were as follows for the periods indicated:

	Six months ended
	June 30,
	2009			2008
	(in thousands)
Federal:
Current	$	80		$	(20,110	)
Deferred		34,568			22,877
Total federal		34,648			2,767
State, net of federal benefit:
Current		(1,151	)		(4,057	)
Deferred		2,946			3,879
Total state		1,795			(178	)
Income tax benefit	$	36,443		$	2,589

     The following table reconciles income tax benefit with income tax at the Federal statutory rate for the periods indicated:

	Six months ended
	June 30,
	2009			2008
	(in thousands)
Loss before income taxes	$	(103,866	)	$	(21,977	)
Income taxes at the Federal statutory rate	$	36,353		$	7,692
State income taxes, net of federal benefit		1,912			165
Tax on income attributable to noncontrolling interest		(4,512	)		(5,211	)
Permanent and other		2,690			(57	)
Income tax benefit	$	36,443		$	2,589

     As of June 30, 2009 and December 31, 2008, all of EAC’s tax positions met the “more-likely-than-not” threshold prescribed by FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109.” As a result, no additional tax expense, interest, or penalties have been accrued. EAC includes interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its Consolidated Statements of Operations. During the six months ended June 30, 2009 and 2008, EAC recorded only a nominal amount of interest and penalties on certain tax positions.

Note 10. Earnings Per Share

     As discussed in “Note 2. Basis of Presentation,” EAC adopted FSP EITF 03-6-1 on January 1, 2009, and all periods presented have been restated to calculate EPS in accordance with this pronouncement. Under the two-class method of calculating EPS, earnings are allocated to participating securities as if all the earnings for the period had been distributed. A participating security is any security that contains nonforfeitable rights to dividends or dividend equivalents paid to common stockholders. For purposes of calculating EPS, unvested restricted stock awards are considered participating securities. EPS is calculated by dividing the common stockholders’ interest in net income (loss), after deducting the interests of participating securities, by the weighted average shares outstanding. For the three and six months ended June 30, 2008, basic EPS and diluted EPS were unaffected by the adoption of FSP EITF 03-6-1.

21

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following table reflects the allocation of net loss to EAC’s common stockholders and EPS computations for the periods indicated:

	Three months ended						Six months ended
	June 30,						June 30,
	2009			2008 (c)			2009			2008 (c)
	(in thousands, except per share amounts)
Basic Earnings Per Share
Numerator:
Undistributed net loss — attributable to EAC	$	(46,975	)	$	(35,720	)	$	(54,531	)	$	(4,500	)
Participation rights of unvested restricted stock in undistributed earnings (a)		—			—			—			—
Basic undistributed net loss — attributable to EAC common shares	$	(46,975	)	$	(35,720	)	$	(54,531	)	$	(4,500	)
Denominator:
Basic weighted average shares outstanding		51,849			52,344			51,769			52,571
Basic EPS — attributable to EAC common shares	$	(0.91	)	$	(0.68	)	$	(1.05	)	$	(0.09	)
Diluted Earnings Per Share
Numerator:
Basic undistributed net loss — attributable to EAC common shares	$	(46,975	)	$	(35,720	)	$	(54,531	)	$	(4,500	)
Denominator:
Basic weighted average shares outstanding		51,849			52,344			51,769			52,571
Effect of dilutive options (b)		—			—			—			—
Diluted weighted average shares outstanding		51,849			52,344			51,769			52,571
Diluted EPS — attributable to EAC common shares	$	(0.91	)	$	(0.68	)	$	(1.05	)	$	(0.09	)

(a)	Unvested restricted stock has no contractual obligation to absorb losses of EAC. Therefore, for the three and six months ended June 30, 2009, 923,829 shares of restricted stock were outstanding but excluded from the EPS calculations because their effect would have been antidilutive and for the three and six months ended June 30, 2008, 966,740 shares of restricted stock were outstanding but excluded from the EPS calculations because their effect would have been antidilutive. Please read “Note 11. Incentive Stock Plans” for additional discussion of restricted stock.
(b)	For the three and six months ended June 30, 2009, options to purchase 1,732,383 shares of common stock were outstanding but excluded from the EPS calculations because their effect would have been antidilutive. For the three and six months ended June 30, 2008, options to purchase 1,524,107 shares of common stock were outstanding but excluded from the EPS calculations because their effect would have been antidilutive. Please read “Note 11. Incentive Stock Plans” for additional discussion of stock options.
(c)	For the three and six months ended June 30, 2008, EAC considered the impact of the conversion of vested management incentive units held by certain executive officers of GP LLC. The conversion of the management incentive units into limited partner units of ENP would reduce EAC’s share of ENP’s earnings and therefore, the impact of this conversion was excluded from the diluted EPS calculations because the effect would have been antidilutive. Please read “Note 16. ENP” for additional discussion of ENP’s management incentive units.

Note 11. Incentive Stock Plans

     In May 2008, EAC’s stockholders approved the 2008 Incentive Stock Plan (the “2008 Plan”). No additional awards will be granted under EAC’s 2000 Incentive Stock Plan (the “2000 Plan”) and any outstanding awards granted under the 2000 Plan will remain outstanding in accordance with their terms. The purpose of the 2008 Plan is to attract, motivate, and retain selected employees of EAC and to provide EAC with the ability to provide incentives more directly linked to the profitability of the business and increases in stockholder value. All directors and full-time regular employees of EAC and its subsidiaries and affiliates are eligible to be granted awards under the 2008 Plan. The 2008 Plan provides for the granting of cash awards, incentive stock options, non-qualified stock options, restricted stock, and stock appreciation rights at the discretion of the Compensation Committee of the Board. The Board also has a Special Stock Award Committee whose sole member is Jon S. Brumley, EAC’s Chief Executive Officer and President. The Special Stock Award Committee may grant up to 25,000 shares of restricted stock on an annual basis to non-executive employees at its discretion.

     The total number of shares of EAC’s common stock reserved for issuance pursuant to the 2008 Plan is 2,400,000, of which no more than 1,600,000 are available for grants of “full value” stock awards, such as restricted stock or stock units. As of June 30, 2009, there were 1,715,670 shares available for issuance under the 2008 Plan, of which 1,180,913 are available for grants of “full value” stock awards. Shares delivered or withheld for payment of the exercise price of an option, shares withheld for payment of tax withholding, shares subject to options or other awards that expire or are forfeited, and restricted shares that are forfeited will again become available for issuance under the 2008 Plan.

22

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The 2008 Plan contains the following individual limits:

• an employee may not be granted awards covering or relating to more than 300,000 shares of common stock during any calendar year;

• a non-employee director may not be granted awards covering or relating to more than 20,000 shares of common stock during any calendar year; and

• an employee may not receive awards consisting of cash (including cash awards that are granted as performance awards) in respect of any calendar year having a value determined on the grant date in excess of $5.0 million.

     During the six months ended June 30, 2009 and 2008, EAC recorded non-cash stock-based compensation expense related to its incentive stock plans of $6.7 million and $4.1 million, respectively, which was allocated to LOE and general and administrative expense in the accompanying Consolidated Statements of Operations based on the allocation of the respective employees’ cash compensation. During the six months ended June 30, 2009 and 2008, EAC also capitalized $1.2 million and $1.0 million, respectively, of non-cash stock-based compensation expense related to its incentive stock plans as a component of “Proved properties” in the accompanying Consolidated Balance Sheets. During the six months ended June 30, 2009 and 2008, EAC recognized income tax benefits related to its incentive stock plans of $2.5 million and $1.5 million, respectively.

     Please read “Note 16. ENP” for a discussion of ENP’s unit-based compensation plans.

Stock Options

     All options have a strike price equal to the fair market value of EAC’s common stock on the grant date, have a ten-year life, and vest over a three-year period. The fair value of options granted during the six months ended June 30, 2009 and 2008 was estimated on the grant date using a Black-Scholes option valuation model based on the following assumptions:

	Six months ended June 30,
	2009			2008
Expected volatility		51.9	%		33.7	%
Expected dividend yield		0.0	%		0.0	%
Expected term (in years)		6.25			6.25
Risk-free interest rate		2.1	%		3.0	%
Weighted-average fair value per share	$	15.81		$	13.15

     The expected volatility was based on the historical volatility of EAC’s common stock for a period of time commensurate with the expected term of the options. EAC determined the expected life of the options based on an analysis of historical exercise and forfeiture behavior as well as expectations about future behavior. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the grant date for a period of time commensurate with the expected term of the options.

     The following table summarizes the changes in EAC’s outstanding options for the six months ended June 30, 2009:

						Weighted
				Weighted		Average		Aggregate
	Number of			Average		Remaining		Intrinsic
	Options			Strike Price		Contractual Term		Value
								(in thousands)
Outstanding at January 1, 2009		1,497,413		$	18.02
Granted		269,417			30.55
Forfeited or expired		(12,963	)		30.91
Exercised		(21,484	)		19.42
Outstanding at June 30, 2009		1,732,383			19.86		5.4	$	19,527
Exercisable at June 30, 2009		1,299,677			16.25		4.1		19,145

     The total intrinsic value of options exercised during the six months ended June 30, 2009 and 2008 was $0.3 million and $0.6 million, respectively. During each of the six months ended June 30, 2009 and 2008, EAC received proceeds from the exercise of stock options of $0.4 million. During the six months ended June 30, 2009 and 2008, EAC recognized income tax benefits related to

23

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

stock options of $40 thousand and $0.2 million, respectively. At June 30, 2009, EAC had $3.0 million of total unrecognized compensation cost related to unvested stock options, which is expected to be recognized over a weighted average period of 2.3 years.

Restricted Stock

     Restricted stock awards vest over varying periods from one to five years, subject to performance-based vesting for certain members of senior management. During the six months ended June 30, 2009, EAC recognized expense related to restricted stock of $5.1 million and recognized an income tax provision related to the vesting of restricted stock of $0.4 million. During the six months ended June 30, 2008, EAC recognized expense related to restricted stock of $3.4 million and recognized an income tax benefit related to the vesting of restricted stock of $0.8 million. The following table summarizes the changes in EAC’s unvested restricted stock awards for the six months ended June 30, 2009:

				Weighted
				Average
	Number of			Grant Date
	Shares			Fair Value
Outstanding at January 1, 2009		938,407		$	30.67
Granted		412,449			30.52
Vested		(408,478	)		29.25
Forfeited		(18,549	)		30.27
Outstanding at June 30, 2009		923,829			31.20

     As of June 30, 2009, there were 704,809 shares of unvested restricted stock, 189,067 shares of which were granted during 2009, in which the vesting is dependent only on the passage of time and continued employment. Additionally, as of June 30, 2009, there were 219,020 shares of unvested restricted stock, all of which were granted during 2009, in which the vesting is dependent not only on the passage of time and continued employment, but also on the achievement of certain performance measures.

     None of EAC’s unvested restricted stock awards are subject to variable accounting. During the six months ended June 30, 2009 and 2008, there were 408,478 shares and 235,086 shares, respectively, of restricted stock that vested for which certain employees elected to satisfy minimum tax withholding obligations related thereto by directing EAC to withhold 111,819 shares and 28,193 shares of common stock, respectively. EAC accounts for these shares as treasury stock until they are formally retired and have been reflected as such in the accompanying consolidated financial statements. The total fair value of restricted stock that vested during the six months ended June 30, 2009 and 2008 was $11.0 million and $8.2 million, respectively. As of June 30, 2009, EAC had $12.7 million of total unrecognized compensation cost related to unvested restricted stock, which is expected to be recognized over a weighted average period of 3.1 years.

Note 12. Comprehensive Loss

     The components of comprehensive loss, net of tax, were as follows for the periods indicated:

	Three months ended						Six months ended
	June 30,						June 30,
	2009			2008			2009			2008
				(in thousands)
Consolidated net loss	$	(61,520	)	$	(50,702	)	$	(67,423	)	$	(19,388	)
Amortization of deferred loss on commodity derivative contracts		—			907			—			1,786
Change in deferred hedge loss on interest rate swaps		977			1,588			432			417
Consolidated comprehensive loss		(60,543	)		(48,207	)		(66,991	)		(17,185	)
Less: comprehensive loss attributable to noncontrolling interest		14,223			14,161			12,774			14,571
Comprehensive loss — attributable to EAC	$	(46,320	)	$	(34,046	)	$	(54,217	)	$	(2,614	)

24

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 13. Financial Statements of Subsidiary Guarantors

     Certain of EAC’s wholly owned subsidiaries are subsidiary guarantors of EAC’s senior subordinated notes. The subsidiary guarantees are full and unconditional, and joint and several. The subsidiary guarantors may, without restriction, transfer funds to EAC in the form of cash dividends, loans, and advances. The following Condensed Consolidating Balance Sheets as of June 30, 2009 and December 31, 2008, Condensed Consolidating Statements of Operations and Comprehensive Income (Loss) for the three and six months ended June 30, 2009 and 2008, and Condensed Consolidating Statements of Cash Flows for the six months ended June 30, 2009 and 2008 present consolidating financial information for Encore Acquisition Company (the “Parent”) on a stand alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries. As of June 30, 2009, EAC’s guarantor subsidiaries were:

• EAP Properties, Inc.;

• EAP Operating, LLC;

• Encore Operating, L.P.; and

• Encore Operating Louisiana, LLC.

As of June 30, 2009, EAC’s non-guarantor subsidiaries were:

• ENP;

• OLLC;

• GP LLC;

• Encore Partners GP Holdings LLC;

• Encore Partners LP Holdings LLC;

• Encore Energy Partners Finance Corporation; and

• Encore Clear Fork Pipeline LLC.

     All intercompany investments in, loans due to/from, subsidiary equity, revenues, and expenses between the Parent, guarantor subsidiaries, and non-guarantor subsidiaries are shown prior to consolidation with the Parent and then eliminated to arrive at consolidated totals per the accompanying consolidated financial statements.

25

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET
June 30, 2009
(in thousands)

			Guarantor			Non-Guarantor						Consolidated
	Parent		Subsidiaries			Subsidiaries			Eliminations			Total
ASSETS
Current assets:
Cash and cash equivalents	$	44	$	35,724		$	72		$	—		$	35,840
Other current assets		5,223		141,923			56,752			(2,839	)		201,059
Total current assets		5,267		177,647			56,824			(2,839	)		236,899
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		—		3,130,887			612,930			—			3,743,817
Unproved properties		—		114,118			50			—			114,168
Accumulated depletion, depreciation, and amortization		—		(779,057	)		(134,964	)		—			(914,021	)
		—		2,465,948			478,016			—			2,943,964
Other property and equipment, net		—		10,479			461			—			10,940
Other assets, net		16,207		178,961			33,998			—			229,166
Investment in subsidiaries		2,733,354		3,325			—			(2,736,679	)		—
Total assets	$	2,754,828	$	2,836,360		$	569,299		$	(2,739,518	)	$	3,420,969
LIABILITIES AND EQUITY
Current liabilities	$	93,828	$	167,618		$	31,317		$	(2,839	)	$	289,924
Deferred taxes		408,432		9			73			—			408,514
Long-term debt		977,912		—			195,000			—			1,172,912
Other liabilities		—		82,886			16,607			—			99,493
Total liabilities		1,480,172		250,513			242,997			(2,839	)		1,970,843
Commitments and contingencies (see Note 14)
Total equity		1,274,656		2,585,847			326,302			(2,736,679	)		1,450,126
Total liabilities and equity	$	2,754,828	$	2,836,360		$	569,299		$	(2,739,518	)	$	3,420,969

26

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2008
(in thousands)

			Guarantor			Non-Guarantor						Consolidated
	Parent		Subsidiaries			Subsidiaries			Eliminations			Total
ASSETS
Current assets:
Cash and cash equivalents	$	607	$	813		$	619		$	—		$	2,039
Other current assets		29,004		421,392			90,797			(2,302	)		538,891
Total current assets		29,611		422,205			91,416			(2,302	)		540,930
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		—		3,016,937			521,522			—			3,538,459
Unproved properties		—		124,272			67			—			124,339
Accumulated depletion, depreciation, and amortization		—		(670,991	)		(100,573	)		—			(771,564	)
		—		2,470,218			421,016			—			2,891,234
Other property and equipment, net		—		11,877			562			—			12,439
Other assets, net		12,846		129,482			46,264			—			188,592
Investment in subsidiaries		2,976,208		(12,865	)		—			(2,963,343	)		—
Total assets	$	3,018,665	$	3,020,917		$	559,258		$	(2,965,645	)	$	3,633,195
LIABILITIES AND EQUITY
Current liabilities	$	118,089	$	215,640		$	20,825		$	(2,302	)	$	352,252
Deferred taxes		416,637		—			278			—			416,915
Long-term debt		1,169,811		—			150,000			—			1,319,811
Other liabilities		—		48,000			12,969			—			60,969
Total liabilities		1,704,537		263,640			184,072			(2,302	)		2,149,947
Commitments and contingencies (see Note 14)
Total equity		1,314,128		2,757,277			375,186			(2,963,343	)		1,483,248
Total liabilities and equity	$	3,018,665	$	3,020,917		$	559,258		$	(2,965,645	)	$	3,633,195

27

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE LOSS
For the Three Months Ended June 30, 2009
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	110,495		$	23,182		$	—		$	133,677
Natural gas		—			25,531			3,955			—			29,486
Marketing		—			206			109			—			315
Total revenues		—			136,232			27,246			—			163,478
Expenses:
Production:
Lease operating		—			33,502			6,949			—			40,451
Production, ad valorem, and severance taxes		—			13,971			3,062			—			17,033
Depletion, depreciation, and amortization		—			63,140			11,294			—			74,434
Exploration		—			15,916			18			—			15,934
General and administrative		4,237			7,958			2,810			(1,226	)		13,779
Marketing		—			454			61			—			515
Derivative fair value loss		—			23,666			37,440			—			61,106
Other operating		43			14,134			658			—			14,835
Total expenses		4,280			172,741			62,292			(1,226	)		238,087
Operating loss		(4,280	)		(36,509	)		(35,046	)		1,226			(74,609	)
Other income (expenses):
Interest		(16,775	)		—			(2,351	)		—			(19,126	)
Equity loss from subsidiaries		(57,646	)		(11,918	)		—			69,564			—
Other		(33	)		1,915			1			(1,226	)		657
Total other expenses		(74,454	)		(10,003	)		(2,350	)		68,338			(18,469	)
Loss before income taxes		(78,734	)		(46,512	)		(37,396	)		69,564			(93,078	)
Income tax benefit (provision)		31,758			—			(200	)		—			31,558
Consolidated net loss		(46,976	)		(46,512	)		(37,596	)		69,564			(61,520	)
Change in deferred hedge loss on interest rate swaps, net of tax		(384	)		—			1,361			—			977
Comprehensive loss	$	(47,360	)	$	(46,512	)	$	(36,235	)	$	69,564		$	(60,543	)

28

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE LOSS
For the Three Months Ended June 30, 2008
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	239,783		$	47,141		$	—		$	286,924
Natural gas		—			56,081			11,808			—			67,889
Marketing		—			1,618			903			—			2,521
Total revenues		—			297,482			59,852			—			357,334
Expenses:
Production:
Lease operating		—			33,775			6,922			—			40,697
Production, ad valorem, and severance taxes		—			29,261			5,782			—			35,043
Depletion, depreciation, and amortization		—			41,811			9,215			—			51,026
Exploration		—			11,555			38			—			11,593
General and administrative		3,911			5,830			2,933			(1,115	)		11,559
Marketing		—			2,116			1,609			—			3,725
Derivative fair value loss		—			179,962			76,428			—			256,390
Other operating		42			2,853			331			—			3,226
Total expenses		3,953			307,163			103,258			(1,115	)		413,259
Operating loss		(3,953	)		(9,681	)		(43,406	)		1,115			(55,925	)
Other income (expenses):
Interest		(14,876	)		—			(1,909	)		—			(16,785	)
Equity loss from subsidiaries		(38,923	)		(15,800	)		—			54,723			—
Other		(85	)		1,821			65			(1,115	)		686
Total other expenses		(53,884	)		(13,979	)		(1,844	)		53,608			(16,099	)
Loss before income taxes		(57,837	)		(23,660	)		(45,250	)		54,723			(72,024	)
Income tax benefit (provision)		21,151			(81	)		252			—			21,322
Consolidated net loss		(36,686	)		(23,741	)		(44,998	)		54,723			(50,702	)
Amortization of deferred loss on commodity derivative contracts, net of tax		(522	)		1,429			—			—			907
Change in deferred hedge gain on interest rate swaps, net of tax		(647	)		—			2,235			—			1,588
Comprehensive loss	$	(37,855	)	$	(22,312	)	$	(42,763	)	$	54,723		$	(48,207	)

29

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE LOSS
For the Six Months Ended June 30, 2009
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	183,051		$	38,915		$	—		$	221,966
Natural gas		—			46,867			7,873			—			54,740
Marketing		—			842			279			—			1,121
Total revenues		—			230,760			47,067			—			277,827
Expenses:
Production:
Lease operating		—			69,845			14,831			—			84,676
Production, ad valorem, and severance taxes		—			23,450			5,402			—			28,852
Depletion, depreciation, and amortization		—			122,449			22,285			—			144,734
Exploration		—			27,093			40			—			27,133
General and administrative		9,714			15,076			4,999			(2,316	)		27,473
Marketing		—			1,063			191			—			1,254
Derivative fair value loss (gain)		—			(14,018	)		26,533			—			12,515
Other operating		83			19,720			1,375			—			21,178
Total expenses		9,797			264,678			75,656			(2,316	)		347,815
Operating loss		(9,797	)		(33,918	)		(28,589	)		2,316			(69,988	)
Other income (expenses):
Interest		(30,522	)		—			(4,567	)		—			(35,089	)
Equity loss from subsidiaries		(50,644	)		(10,432	)		—			61,076			—
Other		(96	)		3,617			6			(2,316	)		1,211
Total other expenses		(81,262	)		(6,815	)		(4,561	)		58,760			(33,878	)
Loss before income taxes		(91,059	)		(40,733	)		(33,150	)		61,076			(103,866	)
Income tax benefit (provision)		36,527			117			(201	)		—			36,443
Consolidated net loss		(54,532	)		(40,616	)		(33,351	)		61,076			(67,423	)
Change in deferred hedge loss on interest rate swaps, net of tax		(216	)		—			648			—			432
Comprehensive loss	$	(54,748	)	$	(40,616	)	$	(32,703	)	$	61,076		$	(66,991	)

30

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2008
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	423,122		$	84,336		$	—		$	507,458
Natural gas		—			97,391			18,810			—			116,201
Marketing		—			2,815			3,762			—			6,577
Total revenues		—			523,328			106,908			—			630,236
Expenses:
Production:
Lease operating		—			68,067			12,980			—			81,047
Production, ad valorem, and severance taxes		—			51,915			10,580			—			62,495
Depletion, depreciation, and amortization		—			82,234			18,335			—			100,569
Exploration		—			17,014			67			—			17,081
General and administrative		6,945			10,580			5,855			(2,134	)		21,246
Marketing		—			3,505			4,002			—			7,507
Derivative fair value loss		—			229,513			92,015			—			321,528
Other operating		83			4,967			682			—			5,732
Total expenses		7,028			467,795			144,516			(2,134	)		617,205
Operating income (loss)		(7,028	)		55,533			(37,608	)		2,134			13,031
Other income (expenses):
Interest		(32,996	)		—			(3,549	)		—			(36,545	)
Equity income (loss) from subsidiaries		31,832			(13,840	)		—			(17,992	)		—
Other		(48	)		3,637			82			(2,134	)		1,537
Total other expenses		(1,212	)		(10,203	)		(3,467	)		(20,126	)		(35,008	)
Income (loss) before income taxes		(8,240	)		45,330			(41,075	)		(17,992	)		(21,977	)
Income tax benefit (provision)		2,508			(81	)		162			—			2,589
Consolidated net income (loss)		(5,732	)		45,249			(40,913	)		(17,992	)		(19,388	)
Amortization of deferred loss on commodity derivative contracts, net of tax		(1,071	)		2,857			—			—			1,786
Change in deferred hedge gain on interest rate swaps, net of tax		(250	)		—			667			—			417
Comprehensive income (loss)	$	(7,053	)	$	48,106		$	(40,246	)	$	(17,992	)	$	(17,185	)

31

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Six Months Ended June 30, 2009
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(53,206	)	$	546,035		$	51,318		$	—		$	544,147
Cash flows from investing activities:
Acquisition of oil and natural gas properties		—			(12,452	)		(27,538	)		—			(39,990	)
Deposit on acquisition of oil and natural gas properties		—			(37,500	)		—			—			(37,500	)
Development of oil and natural gas properties		—			(231,624	)		(3,477	)		—			(235,101	)
Investments in subsidiaries		242,740			—			—			(242,740	)		—
Other		—			3,231			—			—			3,231
Net cash provided by (used in) investing activities		242,740			(278,345	)		(31,015	)		(242,740	)		(309,360	)
Cash flows from financing activities:
Proceeds from long-term debt, net of issuance costs		242,450			—			78,000			—			320,450
Payments on long-term debt		(440,000	)		—			(33,000	)		—			(473,000	)
Proceeds from ENP issuance of common units, net of offering costs		—			—			40,724			—			40,724
Net equity distributions		—			(170,102	)		(72,638	)		242,740			—
Other		7,453			(62,677	)		(33,936	)		—			(89,160	)
Net cash used in financing activities		(190,097	)		(232,779	)		(20,850	)		242,740			(200,986	)
Increase (decrease) in cash and cash equivalents		(563	)		34,911			(547	)		—			33,801
Cash and cash equivalents, beginning of period		607			813			619			—			2,039
Cash and cash equivalents, end of period	$	44		$	35,724		$	72		$	—		$	35,840

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Six Months Ended June 30, 2008
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(15,147	)	$	303,826		$	63,636		$	—		$	352,315
Cash flows from investing activities:
Acquisition of oil and natural gas properties		—			(49,199	)		(81	)		—			(49,280	)
Development of oil and natural gas properties		—			(221,175	)		(12,050	)		—			(233,225	)
Investments in subsidiaries		128,148			—			—			(128,148	)		—
Other		—			(23,681	)		(217	)		—			(23,898	)
Net cash provided by (used in) investing activities		128,148			(294,055	)		(12,348	)		(128,148	)		(306,403	)
Cash flows from financing activities:
Repurchase of common stock		(39,118	)		—			—			—			(39,118	)
Proceeds from long-term debt, net of issuance costs		455,029			—			163,310			—			618,339
Payments on long-term debt		(538,500	)		—			(60,000	)		—			(598,500	)
Net equity distributions		—			(3,121	)		(125,027	)		128,148			—
Other		10,000			(8,086	)		(28,657	)		—			(26,743	)
Net cash used in financing activities		(112,589	)		(11,207	)		(50,374	)		128,148			(46,022	)
Increase (decrease) in cash and cash equivalents		412			(1,436	)		914			—			(110	)
Cash and cash equivalents, beginning of period		1			1,700			3			—			1,704
Cash and cash equivalents, end of period	$	413		$	264		$	917		$	—		$	1,594

32

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 14. Commitments and Contingencies

     EAC 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 EAC’s business, financial condition, results of operations, or liquidity.

     Additionally, EAC has contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal, long-term debt, derivative contracts, capital and operating leases, and development commitments. Please read “Capital Commitments, Capital Resources, and Liquidity — Capital commitments — Contractual obligations” included in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Report for a description of EAC’s contractual obligations as of June 30, 2009.

Note 15. Related Party Transactions

     During the three and six months ended June 30, 2008, EAC received approximately $48.7 million and $89.3 million, respectively, from affiliates of Tesoro Corporation (“Tesoro”) related to gross oil and gas production sold from wells operated by Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly owned subsidiary of EAC. Mr. John V. Genova, a member of the Board, served as an employee of Tesoro until May 2008.

     Please read “Note 16. ENP” for a discussion of related party transactions with ENP.

Note 16. ENP

Administrative Services Agreement

     ENP does not have any employees. The employees supporting ENP’s operations are employees of EAC. Encore Operating performs administrative services for ENP, such as accounting, corporate development, finance, land, legal, and engineering, pursuant to an administrative services agreement. In addition, Encore Operating provides all personnel, facilities, goods, and equipment necessary to perform these services which are not otherwise provided for by ENP. Encore Operating is not liable to ENP for its performance of, or failure to perform, services under the administrative services agreement unless its acts or omissions constitute gross negligence or willful misconduct.

     Encore Operating initially received an administrative fee of $1.75 per BOE of ENP’s production for such services. From April 1, 2008 to March 31, 2009, the administration fee was $1.88 per BOE of ENP’s production. Effective April 1, 2009, the administrative fee increased to $2.02 per BOE of ENP’s production as a result of the COPAS Wage Index Adjustment. ENP also reimburses Encore Operating for actual third-party expenses incurred on ENP’s behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on ENP’s behalf. In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator.

     The administrative fee will increase in the following circumstances:

• beginning on the first day of April in each year by an amount equal to the product of the then-current administrative fee multiplied by the COPAS Wage Index Adjustment for that year;

• if ENP or one of its subsidiaries acquires additional assets, Encore Operating may propose an increase in its administrative fee that covers the provision of services for such additional assets; however, such proposal must be approved by the board of directors of GP LLC upon the recommendation of its conflicts committee; and

• otherwise as agreed upon by Encore Operating and GP LLC, with the approval of the conflicts committee of the board of directors of GP LLC.

     ENP reimburses EAC for any state income, franchise, or similar tax incurred by EAC resulting from the inclusion of ENP and its subsidiaries in consolidated tax returns with EAC and its subsidiaries as required by applicable law. The amount of any such reimbursement is limited to the tax that ENP and its subsidiaries would have incurred had they not been included in a combined group with EAC.

33

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Sales of Assets to ENP

     In June 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Williston Basin in North Dakota and Montana (the “Williston Basin Assets”) to ENP for approximately $25.7 million in cash, including post-closing adjustments, which was financed through borrowings under the OLLC Credit Agreement and proceeds from the issuance of ENP common units to the public. EAC used the proceeds from the sale of the properties to reduce outstanding borrowings under the EAC Credit Agreement.

     In January 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”), to ENP for approximately $46.4 million in cash, including post-closing adjustments, which was financed through borrowings under the OLLC Credit Agreement. EAC used the proceeds from the sale of the properties to reduce outstanding borrowings under the EAC Credit Agreement.

     In February 2008, Encore Operating sold certain oil and natural gas properties and related assets in the Permian Basin in West Texas and in the Williston Basin in North Dakota to ENP for approximately $125.0 million in cash, including post-closing adjustments, and 6,884,776 ENP common units. In determining the total purchase price, the common units were valued at $125.0 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s carrying value of the properties. The cash portion of the purchase price was financed through borrowings under the OLLC Credit Agreement. EAC used the proceeds from the sale of the properties to reduce outstanding borrowings under the EAC Credit Agreement.

Shelf Registration Statement on Form S-3

     In November 2008, ENP’s “shelf” registration statement on Form S-3 was declared effective by the SEC. Under the shelf registration statement, ENP may offer common units, senior debt, or subordinated debt in one or more offerings with a total initial offering price of up to $1 billion.

Public Offering of Common Units

     In May 2009, ENP issued 2,760,000 common units under its shelf registration statement at a price to the public of $15.60 per common unit. ENP used the net proceeds of approximately $40.8 million, after deducting the underwriters’ discounts and commissions of $1.9 million, in the aggregate, and offering costs of approximately $0.4 million, to fund the acquisition of certain natural gas producing properties in the Vinegarone Field in Val Verde County, Texas (the “Vinegarone Assets”) from an independent energy company for $27.5 million, including post-closing adjustments, and a portion of the purchase price of the Williston Basin Assets.

Long-Term Incentive Plan

     In September 2007, the board of directors of GP LLC adopted the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “ENP Plan”), which provides for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. All employees, consultants, and directors of EAC, GP LLC, and any of their subsidiaries and affiliates who perform services for ENP are eligible to be granted awards under the ENP Plan. The ENP Plan is administered by the board of directors of GP LLC or a committee thereof, referred to as the plan administrator. To satisfy common unit awards under the ENP Plan, ENP may issue common units, acquire common units in the open market, or use common units owned by EAC and its affiliates.

     The total number of common units reserved for issuance pursuant to the ENP Plan is 1,150,000. As of June 30, 2009, there were 1,100,000 common units available for issuance under the ENP Plan.

     Phantom Units. Each October, ENP issues 5,000 phantom units to each member of GP LLC’s board of directors pursuant to the ENP Plan. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the plan administrator, cash equivalent to the value of a common unit. ENP intends to settle the phantom units at vesting by issuing common units to the grantee; therefore, these phantom units are classified as equity instruments. Phantom units vest equally over a four-year period. The holders of phantom units are also entitled to receive distribution equivalent rights prior to vesting, which entitle

34

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

them to receive cash equal to the amount of any cash distributions made by ENP with respect to a common unit during the period the right is outstanding. During each of the six months ended June 30, 2009 and 2008, ENP recognized non-cash unit-based compensation expense related to phantom units of approximately $0.2 million, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations.

     The following table summarizes the changes in ENP’s unvested phantom units for the six months ended June 30, 2009:

			Weighted
			Average
	Number of		Grant Date
	Shares		Fair Value
Outstanding at January 1, 2009		43,750	$	18.67
Granted		—		—
Vested		—		—
Forfeited		—		—
Outstanding at June 30, 2009		43,750		18.67

     As of June 30, 2009, ENP had $0.4 million of total unrecognized compensation cost related to unvested phantom units, which is expected to be recognized over a weighted average period of 2.0 years.

Management Incentive Units

     In May 2007, the board of directors of GP LLC issued 550,000 management incentive units to certain executive officers of GP LLC. During the fourth quarter of 2008, the management incentive units became convertible into ENP common units, at the option of the holder, at a ratio of one management incentive unit to approximately 3.1186 ENP common units, and all 550,000 management incentive units were converted into 1,715,205 ENP common units.

     During the three and six months ended June 30, 2008, ENP recognized non-cash unit-based compensation expense for the management incentive units of $1.1 million and $2.1 million, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. There have been no additional issuances of management incentive units.

Distributions

     During the three and six months ended June 30, 2009, ENP distributed approximately $16.8 million and $33.6 million, respectively, of which $10.7 million and $21.4 million, respectively, was paid to EAC and its subsidiaries and had no impact on EAC’s consolidated cash. During the three and six months ended June 30, 2008, ENP distributed approximately $19.3 million and $29.2 million, respectively, of which $12.3 million and $18.0 million, respectively, was paid to EAC and its subsidiaries and had no impact on EAC’s consolidated cash.

     During the three and six months ended June 30, 2008, ENP distributed approximately $1.0 million and $1.2 million, respectively, to certain executive officers of GP LLC, who serve in the same capacities for EAC, based on their ownership of management incentive units.

Note 17. Segment Information

     EAC operates in only one industry: the oil and natural gas exploration and production industry in the United States. However, EAC is organizationally structured along two reportable segments: EAC Standalone and ENP. EAC’s segments are components of its business for which separate financial information is available and regularly evaluated by the chief operating decision maker in deciding how to allocate capital resources to projects and in assessing performance. The accounting policies used in the generation of segment financial statements are the same as those described in “Note 2. Summary of Significant Accounting Policies” in EAC’s 2008 Annual Report on Form 10-K.

     The following tables provide EAC’s operating segment information required by SFAS No. 131, "Disclosure about Segments of an Enterprise and Related Information.” The prior period financial information of ENP in the following tables was recast to include the financial results of the Arkoma Basin Assets and the Williston Basin Assets.

35

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

	For the Three Months Ended June 30, 2009
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	110,495		$	23,182		$	—		$	133,677
Natural gas		25,531			3,955			—			29,486
Marketing		206			109			—			315
Total revenues		136,232			27,246			—			163,478
Expenses:
Production:								—
Lease operating		33,502			6,949			—			40,451
Production, ad valorem, and severance taxes		13,971			3,062			—			17,033
Depletion, depreciation, and amortization		63,140			11,294			—			74,434
Exploration		15,916			18			—			15,934
General and administrative		12,198			2,807			(1,226	)		13,779
Marketing		454			61			—			515
Derivative fair value loss		23,666			37,440			—			61,106
Other operating		14,177			658			—			14,835
Total expenses		177,024			62,289			(1,226	)		238,087
Operating loss		(40,792	)		(35,043	)		1,226			(74,609	)
Other income (expenses):
Interest		(16,775	)		(2,351	)		—			(19,126	)
Other		1,882			1			(1,226	)		657
Total other expenses		(14,893	)		(2,350	)		(1,226	)		(18,469	)
Loss before income taxes		(55,685	)		(37,393	)		—			(93,078	)
Income tax benefit (provision)		31,758			(200	)		—			31,558
Consolidated net loss		(23,927	)		(37,593	)		—			(61,520	)
Change in deferred hedge loss on interest rate swaps, net of tax		(384	)		1,361			—			977
Comprehensive loss	$	(24,311	)	$	(36,232	)	$	—		$	(60,543	)

36

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

	For the Three Months Ended June 30, 2008
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	235,321		$	51,603		$	—		$	286,924
Natural gas		53,235			14,654			—			67,889
Marketing		1,618			903			—			2,521
Total revenues		290,174			67,160			—			357,334
Expenses:
Production:
Lease operating		33,062			7,635			—			40,697
Production, ad valorem, and severance taxes		28,735			6,308			—			35,043
Depletion, depreciation, and amortization		40,710			10,316			—			51,026
Exploration		11,555			38			—			11,593
General and administrative		9,436			3,252			(1,129	)		11,559
Marketing		2,116			1,609			—			3,725
Derivative fair value loss		179,962			76,428			—			256,390
Other operating		2,835			391			—			3,226
Total expenses		308,411			105,977			(1,129	)		413,259
Operating loss		(18,237	)		(38,817	)		1,129			(55,925	)
Other income (expenses):
Interest		(14,876	)		(1,909	)		—			(16,785	)
Other		1,750			65			(1,129	)		686
Total other expenses		(13,126	)		(1,844	)		(1,129	)		(16,099	)
Loss before income taxes		(31,363	)		(40,661	)		—			(72,024	)
Income tax benefit		21,187			135			—			21,322
Consolidated net loss		(10,176	)		(40,526	)		—			(50,702	)
Amortization of deferred loss on commodity derivative contracts, net of tax		907			—			—			907
Change in deferred hedge gain on interest rate swaps, net of tax		(967	)		2,552			—			1,585
Comprehensive loss	$	(10,236	)	$	(37,974	)	$	—		$	(48,210	)

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ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

	For the Six Months Ended June 30, 2009
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	183,051		$	38,915		$	—		$	221,966
Natural gas		46,867			7,873			—			54,740
Marketing		842			279			—			1,121
Total revenues		230,760			47,067			—			277,827
Expenses:
Production:								—
Lease operating		69,845			14,831			—			84,676
Production, ad valorem, and severance taxes		23,450			5,402			—			28,852
Depletion, depreciation, and amortization		122,449			22,285			—			144,734
Exploration		27,093			40			—			27,133
General and administrative		24,793			4,996			(2,316	)		27,473
Marketing		1,063			191			—			1,254
Derivative fair value loss (gain)		(14,018	)		26,533			—			12,515
Other operating		19,803			1,375			—			21,178
Total expenses		274,478			75,653			(2,316	)		347,815
Operating loss		(43,718	)		(28,586	)		2,316			(69,988	)
Other income (expenses):
Interest		(30,522	)		(4,567	)		—			(35,089	)
Other		3,521			6			(2,316	)		1,211
Total other expenses		(27,001	)		(4,561	)		(2,316	)		(33,878	)
Loss before income taxes		(70,719	)		(33,147	)		—			(103,866	)
Income tax benefit (provision)		36,644			(201	)		—			36,443
Consolidated net loss		(34,075	)		(33,348	)		—			(67,423	)
Change in deferred hedge loss on interest rate swaps, net of tax		(216	)		648			—			432
Comprehensive loss	$	(34,291	)	$	(32,700	)	$	—		$	(66,991	)

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ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

	For the Six Months Ended June 30, 2008
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	415,014		$	92,444		$	—		$	507,458
Natural gas		92,458			23,743			—			116,201
Marketing		2,815			3,762			—			6,577
Total revenues		510,287			119,949			—			630,236
Expenses:
Production:
Lease operating		66,718			14,329			—			81,047
Production, ad valorem, and severance taxes		50,956			11,539			—			62,495
Depletion, depreciation, and amortization		80,049			20,520			—			100,569
Exploration		17,014			67			—			17,081
General and administrative		16,956			6,424			(2,134	)		21,246
Marketing		3,505			4,002			—			7,507
Derivative fair value loss		229,513			92,015			—			321,528
Other operating		4,939			793			—			5,732
Total expenses		469,650			149,689			(2,134	)		617,205
Operating income (loss)		40,637			(29,740	)		2,134			13,031
Other income (expenses):
Interest		(32,996	)		(3,549	)		—			(36,545	)
Other		3,589			82			(2,134	)		1,537
Total other expenses		(29,407	)		(3,467	)		(2,134	)		(35,008	)
Income (loss) before income taxes		11,230			(33,207	)		—			(21,977	)
Income tax benefit		2,451			138			—			2,589
Consolidated net income (loss)		13,681			(33,069	)		—			(19,388	)
Amortization of deferred loss on commodity derivative contracts, net of tax		1,786			—			—			1,786
Change in deferred hedge gain on interest rate swaps, net of tax		(567	)		984			—			417
Comprehensive income (loss)	$	14,900		$	(32,085	)	$	—		$	(17,185	)

The following table provides EAC’s balance sheet segment information as of the dates indicated:

	June 30, 2009			December 31, 2008
	(in thousands)
Segment assets:
EAC Standalone	$	2,852,020		$	3,023,571
ENP		569,299			610,792
Eliminations		(350	)		(1,168	)
Total consolidated assets	$	3,420,969		$	3,633,195
Segment liabilities:
EAC Standalone	$	1,730,466		$	1,966,399
ENP		242,997			186,360
Eliminations		(2,620	)		(2,812	)
Total consolidated liabilities	$	1,970,843		$	2,149,947

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ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 18. Subsequent Events

     Subsequent events were evaluated through August 5, 2009, which is the date financial statements were issued.

Acquisitions from EXCO and Sale to ENP

     On June 28, 2009, Encore Operating entered into purchase and sale agreements with EXCO Resources, Inc. (together with its affiliates, “EXCO”), which provides for the acquisition by Encore Operating from EXCO of certain oil and natural gas properties and related assets in the Mid-Continent and East Texas for $375 million in cash, subject to customary purchase price adjustments and closing conditions. In conjunction with the signing of the purchase and sale agreements, EAC made a $37.5 million deposit with EXCO, which is reflected as “Acquisition deposit” in the accompanying Consolidated Balance Sheets. The acquisitions will be effective April 1, 2009 and are expected to close in August 2009. EAC expects to finance the acquisitions through borrowings under the EAC Credit Agreement and proceeds from the sale of assets to ENP as discussed below.

     Also on June 28, 2009, Encore Operating entered into a purchase and sale agreement with ENP, which provides for the sale by Encore Operating to ENP of certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota (the “Rockies and Permian Basin Assets”) for $190 million in cash, subject to customary purchase price adjustments. The sale will be effective April 1, 2009 and is expected to close in August 2009. In connection with the pending acquisition of the Rockies and Permian Basin Assets, ENP requested the syndicate of lenders underwriting the OLLC Credit Agreement to increase the borrowing base from $240 million to $375 million.

     The acquisitions of properties from EXCO and the sale of properties to ENP are intended to qualify as a like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended, and I.R.S. Revenue Procedure 2000-37.

ENP Distribution

     On July 28, 2009, ENP announced a cash distribution for the second quarter of 2009 to unitholders of record as of the close of business on August 10, 2009 at a rate of $0.5125 per unit. Approximately $23.5 million is expected to be paid to unitholders on or about August 14, 2009.

Public Offering of ENP Common Units

     In July 2009, ENP issued 9,430,000 common units under its shelf registration statement at a price to the public of $14.30 per common unit. ENP expects to use the net proceeds of approximately $129.1 million, after deducting the underwriters’ discounts and commissions of $5.4 million, in the aggregate, and offering costs of $0.4 million, to fund a portion of the purchase price of the Rockies and Permian Basin Assets. Pending the closing of the acquisition of the Rockies and Permian Basin Assets from Encore Operating, ENP may use the net proceeds to reduce outstanding borrowings under the OLLC Credit Agreement. As a result of ENP’s issuance of common units, EAC’s ownership percentage of ENP’s common units decreased from approximately 58 percent to approximately 46 percent.

CO2 Supply Agreement

     In July 2009, EAC entered into a purchase and sale agreement to acquire a private company. This acquisition procures a CO2 supply that is expected to be used for a tertiary oil recovery project in EAC’s Bell Creek Field. Under the terms of the agreement, EAC will purchase all of the volumes available from the Lost Cabin Gas Plant located in Freemont County, Wyoming. Initially, the volumes are estimated to be approximately 50 MMcf per day. The initial term of the contract is 15 years. EAC plans to build compression facilities adjacent to the plant and construct a 206-mile pipeline to transport the compressed CO2 to its Bell Creek Field in Southeastern Montana, where EAC intends to upgrade its current waterflood secondary recovery project into a miscible CO2 flood tertiary recovery project.

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ENCORE ACQUISITION COMPANY

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     The following discussion and analysis contains forward-looking statements, which give our current expectations or forecasts of future events. Actual results could differ materially from those stated in the forward-looking statements due to many factors, including, but not limited to, those set forth under “Item 1A. Risk Factors” and elsewhere in our 2008 Annual Report on Form 10-K. The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto included in “Item 1. Financial Statements” of this Report and in “Item 8. Financial Statements and Supplementary Data” of our 2008 Annual Report on Form 10-K.

Introduction

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

• Second Quarter 2009 Highlights

• Results of Operations

• Comparison of Quarter Ended June 30, 2009 to Quarter Ended June 30, 2008

• Comparison of Six Months Ended June 30, 2009 to Six Months Ended June 30, 2008

• Capital Commitments, Capital Resources, and Liquidity

• Critical Accounting Policies and Estimates

• New Accounting Pronouncements

Second Quarter 2009 Highlights

     Our financial and operating results for the second quarter of 2009 included the following:

• Our average daily production volumes increased 8 percent to 41,407 BOE/D as compared to 38,214 BOE/D in the second quarter of 2008. Oil represented 64 percent of our total production volumes as compared to 71 percent in the second quarter of 2008.

• We invested $100.4 million in oil and natural gas activities, of which $71.9 million was invested in development, exploitation, and exploration activities, yielding 24 gross (7.0 net) productive wells, and $28.3 million was invested in acquisitions, primarily related to the acquisition of the Vinegarone Assets.

• In June, we sold the Williston Basin Assets to ENP for approximately $25.7 million in cash, including post-closing adjustments. Also in June, we entered into a purchase and sale agreement with ENP, which provides for the sale of the Rockies and Permian Basin Assets to ENP for $190 million in cash, subject to customary purchase price adjustments. This transaction is expected to close in August 2009.

• In June, we entered into purchase and sale agreements with EXCO Resources, Inc., which provides for the acquisition from EXCO of certain oil and natural gas properties and related assets in the Mid-Continent and East Texas for $375 million in cash, subject to customary purchase price adjustments and closing conditions. This transaction is expected to close in August 2009.

• In May, ENP issued 2,760,000 common units under its shelf registration statement at a price to the public of $15.60 per common unit. The net proceeds of approximately $40.8 million were used to fund a portion of the purchase price of the Williston Basin Assets and the Vinegarone Assets.

• In April, we issued $225 million of our 9.5% Senior Subordinated Notes due 2016 at 92.228 percent of par value. We used the net proceeds of approximately $202.5 million to reduce outstanding borrowings under our revolving credit facility.

• Subsequent to the end of the second quarter of 2009, ENP issued 9,430,000 common units under its shelf registration statement at a price to the public of $14.30 per common unit. ENP expects to use the net proceeds of approximately $129.1 million to fund a portion of the purchase price of the Rockies and Permian Basin Assets.

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ENCORE ACQUISITION COMPANY

Results of Operations

Comparison of Quarter Ended June 30, 2009 to Quarter Ended June 30, 2008

     Revenues. The following table illustrates the components of our revenues for the periods indicated, as well as each period’s respective production volumes and average prices:

	Three months ended June 30,					Increase / (Decrease)
	2009		2008			$			%
Revenues (in thousands):
Oil wellhead	$	133,677	$	288,352		$	(154,675	)
Oil hedges		—		(1,428	)		1,428
Total oil revenues	$	133,677	$	286,924		$	(153,247	)		-53	%
Natural gas wellhead	$	29,486	$	67,889		$	(38,403	)		-57	%
Combined wellhead	$	163,163	$	356,241		$	(193,078	)
Combined hedges		—		(1,428	)		1,428
Total combined oil and natural gas revenues		163,163		354,813			(191,650	)		-54	%
Marketing		315		2,521			(2,206	)		-88	%
Total revenues	$	163,478	$	357,334		$	(193,856	)		-54	%
Average realized prices:
Oil wellhead ($/Bbl)	$	55.02	$	117.22		$	(62.20	)
Oil hedges ($/Bbl)		—		(0.58	)		0.58
Total oil revenues ($/Bbl)	$	55.02	$	116.64		$	(61.62	)		-53	%
Natural gas wellhead ($/Mcf)	$	3.67	$	11.12		$	(7.45	)		-67	%
Combined wellhead ($/BOE)	$	43.30	$	102.44		$	(59.14	)
Combined hedges ($/BOE)		—		(0.41	)		0.41
Total combined oil and natural gas revenues ($/BOE)	$	43.30	$	102.03		$	(58.73	)		-58	%
Total production volumes:
Oil (MBbls)		2,430		2,460			(30	)		-1	%
Natural gas (MMcf)		8,030		6,105			1,925			32	%
Combined (MBOE)		3,768		3,477			291			8	%
Average daily production volumes:
Oil (Bbls/D)		26,701		27,032			(331	)		-1	%
Natural gas (Mcf/D)		88,236		67,090			21,146			32	%
Combined (BOE/D)		41,407		38,214			3,193			8	%
Average NYMEX prices:
Oil (per Bbl)	$	59.83	$	124.30		$	(64.47	)		-52	%
Natural gas (per Mcf)	$	3.49	$	10.94		$	(7.45	)		-68	%

     Oil revenues decreased 53 percent from $286.9 million in the second quarter of 2008 to $133.7 million in the second quarter of 2009 as a result of a $61.62 per Bbl decrease in our average realized oil price and a 30 MBbls decrease in our oil production volumes. Our lower oil production volumes decreased oil revenues by approximately $3.5 million and was primarily due to natural production declines in our Elk Basin field.

     Our average realized oil price decreased primarily due to our lower average oil wellhead price, which decreased oil revenues by approximately $151.1 million, or $62.20 per Bbl. Our average oil wellhead price decreased primarily due to a lower average NYMEX price, which decreased from $124.30 per Bbl in the second quarter of 2008 to $59.83 Bbl in the second quarter of 2009. Oil revenues in the second quarter of 2008 were also reduced by approximately $1.4 million, or $0.58 per Bbl, for commodity derivative contracts previously designated as hedges.

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ENCORE ACQUISITION COMPANY

     In the second quarter of 2009 and 2008, our average daily production volumes were decreased by 2,065 BOE/D and 1,943 BOE/D, respectively, for net profits interests related to our CCA properties, which reduced our oil wellhead revenues by approximately $8.6 million and $18.3 million, respectively.

     Natural gas revenues decreased 57 percent from $67.9 million in the second quarter of 2008 to $29.5 million in the second quarter of 2009 as a result of a $7.45 per Mcf decrease in our average realized natural gas price, partially offset by a 1,925 MMcf increase in our natural gas production volumes. Our lower average realized natural gas price decreased natural gas revenues by approximately $59.8 million and was primarily due to a lower average NYMEX price, which decreased from $10.94 per Mcf in the second quarter of 2008 to $3.49 per Mcf in the second quarter of 2009. Our higher natural gas production increased natural gas revenues by approximately $21.4 million and was primarily due to successful development programs in our Permian Basin and Mid-Continent areas.

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

	Three months ended June 30,
	2009			2008
Average oil wellhead ($/Bbl)	$	55.02		$	117.22
Average NYMEX ($/Bbl)	$	59.83		$	124.30
Differential to NYMEX	$	(4.81	)	$	(7.08	)
Average oil wellhead to NYMEX percentage		92	%		94	%
Average natural gas wellhead ($/Mcf)	$	3.67		$	11.12
Average NYMEX ($/Mcf)	$	3.49		$	10.94
Differential to NYMEX	$	0.18		$	0.18
Average natural gas wellhead to NYMEX percentage		105	%		102	%

     Our average oil wellhead price as a percentage of the average NYMEX price was 92 percent in the second quarter of 2009 as compared to 94 percent in the second quarter of 2008.

     Our average natural gas wellhead price as a percentage of the average NYMEX price was 105 percent in the second quarter of 2009 as compared to 102 percent in the second quarter of 2008. Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of liquids extracted. Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas in Mcf as production. Additionally in the second quarter of 2009, we recorded a one-time positive $1.0 million value price adjustment for NGLs marketed by a third party. As a result, the price we were paid per Mcf for natural gas sold under certain contracts during the second quarter of 2009 increased to a level above NYMEX.

     Marketing revenues decreased 88 percent from $2.5 million in the second quarter of 2008 to $0.3 million in the second quarter of 2009 primarily as a result of a reduction in natural gas throughput in our Wildhorse pipeline. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

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ENCORE ACQUISITION COMPANY

     Expenses. The following table summarizes our expenses for the periods indicated:

	Three months ended June 30,						Increase / (Decrease)
	2009			2008			$			%
Expenses (in thousands):
Production:
Lease operating	$	40,451		$	40,697		$	(246	)
Production, ad valorem, and severance taxes		17,033			35,043			(18,010	)
Total production expenses		57,484			75,740			(18,256	)		-24	%
Other:
Depletion, depreciation, and amortization		74,434			51,026			23,408
Exploration		15,934			11,593			4,341
General and administrative		13,779			11,559			2,220
Marketing		515			3,725			(3,210	)
Derivative fair value loss		61,106			256,390			(195,284	)
Other operating		14,835			3,226			11,609
Total operating expenses		238,087			413,259			(175,172	)		-42	%
Interest		19,126			16,785			2,341
Income tax benefit		(31,558	)		(21,322	)		(10,236	)
Total expenses	$	225,655		$	408,722		$	(183,067	)		-45	%
Expenses (per BOE):
Production:
Lease operating	$	10.74		$	11.70		$	(0.96	)
Production, ad valorem, and severance taxes		4.52			10.08			(5.56	)
Total production expenses		15.26			21.78			(6.52	)		-30	%
Other:
Depletion, depreciation, and amortization		19.75			14.67			5.08
Exploration		4.23			3.33			0.90
General and administrative		3.66			3.32			0.34
Marketing		0.14			1.07			(0.93	)
Derivative fair value loss		16.22			73.73			(57.51	)
Other operating		3.94			0.93			3.01
Total operating expenses		63.20			118.83			(55.63	)		-47	%
Interest		5.08			4.83			0.25
Income tax benefit		(8.38	)		(6.13	)		(2.25	)
Total expenses	$	59.90		$	117.53		$	(57.63	)		-49	%

     Production expenses. Total production expenses decreased 24 percent from $75.7 million in the second quarter of 2008 to $57.5 million in the second quarter of 2009. Our production margin decreased 62 percent from $280.5 million in the second quarter of 2008 to $105.7 million in the second quarter of 2009. Total oil and natural gas wellhead revenues per BOE decreased by 58 percent and total production expenses per BOE decreased by 30 percent. On a per BOE basis, our production margin decreased 65 percent to $28.04 per BOE in the second quarter of 2009 as compared to $80.66 per BOE in the second quarter of 2008.

     Production expense attributable to LOE remained flat at $40.5 million in the second quarter of 2009 as compared to $40.7 million in the second quarter of 2008. Our higher production volumes increased LOE by approximately $3.4 million. The $0.96 decrease in our average LOE per BOE rate decreased LOE by approximately $3.6 million and was primarily due to decreases in natural gas prices resulting in lower electricity costs and gas plant fuel costs, as well as lower prices paid to oilfield service companies and suppliers, partially offset by an increase of $3.2 million for retention bonuses to be paid in August 2009 related to our 2008 strategic alternatives process.

     Production expense attributable to production, ad valorem, and severance taxes (“production taxes”) decreased $18.0 million from $35.0 million in the second quarter of 2008 to $17.0 million in the second quarter of 2009 primarily due to lower wellhead revenues, which exclude the effects of commodity derivative contracts. As a percentage of oil and natural gas wellhead revenues, production taxes increased to 10.4 percent in the second quarter of 2009 as compared to 9.8 percent in the second quarter of 2008 primarily due to higher ad valorem taxes, which are based on a flat rate of production volumes as opposed to a percentage of wellhead revenues.

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ENCORE ACQUISITION COMPANY

     Depletion, depreciation, and amortization expense (“DD&A”). DD&A expense increased $23.4 million from $51.0 million in the second quarter of 2008 to $74.4 million in the second quarter of 2009 as a result of a $5.08 increase in the per BOE rate and higher production volumes. Our higher average DD&A per BOE rate increased DD&A expense by approximately $19.1 million and was primarily due to the decrease in our proved reserves as a result of lower average commodity prices. Our higher production volumes increased DD&A expense by approximately $4.3 million.

     Exploration expense. Exploration expense increased $4.3 million from $11.6 million in the second quarter of 2008 to $15.9 million in the second quarter of 2009. During the second quarter of 2009, we expensed 2.9 net exploratory dry holes totaling $9.5 million. During the second quarter of 2008, we expensed 2.0 net exploratory dry holes totaling $6.6 million. Impairment of unproved acreage increased $1.6 million from $4.2 million in the second quarter of 2008 to $5.8 million in the second quarter of 2009, primarily due to our larger unproved property base, as well as the impairment of certain acreage through the normal course of evaluation. The following table illustrates the components of exploration expense for the periods indicated:

	Three months ended June 30,				Increase /
	2009		2008		(Decrease)
	(in thousands)
Dry holes	$	9,467	$	6,612	$	2,855
Geological and seismic		525		455		70
Delay rentals		136		357		(221	)
Impairment of unproved acreage		5,806		4,169		1,637
Total	$	15,934	$	11,593	$	4,341

     General and administrative expense (“G&A”). G&A expense increased $2.2 million from $11.6 million in the second quarter of 2008 to $13.8 million in the second quarter of 2009 primarily due to an increase of $1.4 million for retention bonuses to be paid in August 2009 related to our 2008 strategic alternatives process and the expensing of transaction costs related to our 2009 acquisitions pursuant to SFAS 141R.

     Marketing expenses. Marketing expenses decreased $3.2 million from $3.7 million in the second quarter of 2008 to $0.5 million in the second quarter of 2009 primarily due to a reduction in natural gas throughput in our Wildhorse pipeline. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

     Derivative fair value loss. During the second quarter of 2009, we recorded a $61.1 million derivative fair value loss as compared to $256.4 million in the second quarter of 2008, the components of which were as follows:

	Three months ended June 30,
	2009			2008		Decrease
	(in thousands)
Ineffectiveness	$	6		$	39	$	(33	)
Mark-to-market loss		78,082			219,433		(141,351	)
Premium amortization		6,764			17,293		(10,529	)
Settlements		(23,746	)		19,625		(43,371	)
Total derivative fair value loss	$	61,106		$	256,390	$	(195,284	)

     Other operating expense. Other operating expense increased $11.6 million from $3.2 million in the second quarter of 2008 to $14.8 million in the second quarter of 2009. Other operating expense for the second quarter of 2009 includes a $5.6 million adjustment to the carrying value of pipe and other tubular inventory whose market value had declined below cost and a $4.7 million adjustment to the carrying value of certain receivables, primarily from ExxonMobil related to our West Texas joint venture.

     Interest expense. Interest expense increased $2.3 million from $16.8 million in the second quarter of 2008 to $19.1 million in the second quarter of 2009 primarily due to the issuance of $225 million of our 9.50% Notes, partially offset by a reduction in LIBOR. We received net proceeds of approximately $202.5 million from the issuance of the 9.5% Notes, which we used to reduce outstanding borrowings under our revolving credit facility. Our weighted average interest rate was 6.1 percent for the second quarter of 2009 as compared to 5.4 percent for the second quarter of 2008.

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ENCORE ACQUISITION COMPANY

     The following table illustrates the components of interest expense for the periods indicated:

	Three months ended June 30,					Increase /
	2009		2008			(Decrease)
	(in thousands)
6.25% Senior Subordinated Notes	$	2,436	$	2,431		$	5
6.0% Senior Subordinated Notes		4,644		4,636			8
9.5% Senior Subordinated Notes		4,169		—			4,169
7.25% Senior Subordinated Notes		2,751		2,749			2
Revolving credit facilities		3,966		7,215			(3,249	)
Other		1,160		(246	)		1,406
Total	$	19,126	$	16,785		$	2,341

     Income taxes. In the second quarter of 2009, we recorded an income tax benefit of $31.6 million as compared to $21.3 million in the second quarter of 2008. In the second quarter of 2009, we had a loss before income taxes and noncontrolling interest of $93.1 million as compared to $72.0 million in the second quarter of 2008. Our effective tax rate increased to 33.9 percent in the second quarter of 2009 as compared to 29.6 percent in the second quarter of 2008 primarily due to a permanent increase in the production activities deduction.

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ENCORE ACQUISITION COMPANY

Comparison of Six Months Ended June 30, 2009 to Six Months Ended June 30, 2008

     Revenues. The following table illustrates the components of our revenues for the periods indicated, as well as each period’s respective production volumes and average prices:

	Six months ended June 30,					Increase / (Decrease)
	2009		2008			$			%
Revenues (in thousands):
Oil wellhead	$	221,966	$	510,315		$	(288,349	)
Oil hedges		—		(2,857	)		2,857
Total oil revenues	$	221,966	$	507,458		$	(285,492	)		-56	%
Natural gas wellhead	$	54,740	$	116,201		$	(61,461	)		-53	%
Combined wellhead	$	276,706	$	626,516		$	(349,810	)
Combined hedges		—		(2,857	)		2,857
Total combined oil and natural gas revenues		276,706		623,659			(346,953	)		-56	%
Marketing		1,121		6,577			(5,456	)		-83	%
Total revenues	$	277,827	$	630,236		$	(352,409	)		-56	%
Average realized prices:
Oil wellhead ($/Bbl)	$	45.14	$	102.81		$	(57.67	)
Oil hedges ($/Bbl)		—		(0.58	)		0.58
Total oil revenues ($/Bbl)	$	45.14	$	102.23		$	(57.09	)		-56	%
Natural gas wellhead ($/Mcf)	$	3.48	$	9.73		$	(6.25	)		-64	%
Combined wellhead ($/BOE)	$	36.70	$	90.10		$	(53.40	)
Combined hedges ($/BOE)		—		(0.41	)		0.41
Total combined oil and natural gas revenues ($/BOE)	$	36.70	$	89.69		$	(52.99	)		-59	%
Total production volumes:
Oil (MBbls)		4,918		4,964			(46	)		-1	%
Natural gas (MMcf)		15,727		11,937			3,790			32	%
Combined (MBOE)		7,539		6,953			586			8	%
Average daily production volumes:
Oil (Bbls/D)		27,170		27,274			(104	)		0	%
Natural gas (Mcf/D)		86,890		65,586			21,304			32	%
Combined (BOE/D)		41,652		38,205			3,447			9	%
Average NYMEX prices:
Oil (per Bbl)	$	51.61	$	111.02		$	(59.41	)		-54	%
Natural gas (per Mcf)	$	4.20	$	9.48		$	(5.28	)		-56	%

     Oil revenues decreased 56 percent from $507.5 million in the first six months of 2008 to $222.0 million in the first six months of 2009 as a result of a $57.09 per Bbl decrease in our average realized oil price and a 46 MBbls decrease in our oil production volumes. Our lower oil production volumes decreased oil revenues by approximately $4.7 million and was primarily due to natural production declines in our Elk Basin field.

     Our average realized oil price decreased primarily due to our lower average oil wellhead price, which decreased oil revenues by approximately $283.6 million, or $57.67 per Bbl. Our average oil wellhead price decreased primarily due to a lower average NYMEX price, which decreased from $111.02 per Bbl in the first six months of 2008 to $51.61 Bbl in the first six months of 2009. Oil revenues in the first six months of 2008 were also reduced by approximately $2.9 million, or $0.58 per Bbl, for commodity derivative contracts previously designated as hedges.

     In the first six months of 2009 and 2008, our average daily production volumes were decreased by 1,738 BOE/D and 1,883 BOE/D, respectively, for net profits interests related to our CCA properties, which reduced our oil wellhead revenues by approximately $12.4 million and $31.2 million, respectively.

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ENCORE ACQUISITION COMPANY

     Natural gas revenues decreased 53 percent from $116.2 million in the first six months of 2008 to $54.7 million in the first six months of 2009 as a result of a $6.25 per Mcf decrease in our average realized natural gas price, partially offset by a 3,790 MMcf increase in our natural gas production volumes. Our lower average realized natural gas price decreased natural gas revenues by approximately $98.4 million and was primarily due to a lower average NYMEX price, which decreased from $9.48 per Mcf in the first six months of 2008 to $4.20 per Mcf in the first six months of 2009. Our higher natural gas production increased natural gas revenues by approximately $36.9 million and was primarily due to successful development programs in our Permian Basin and Mid-Continent areas.

     The table below illustrates the relationship between our oil and natural gas wellhead prices as a percentage of average NYMEX prices for the periods indicated:

	Six months ended June 30,
	2009			2008
Average oil wellhead ($/Bbl)	$	45.14		$	102.81
Average NYMEX ($/Bbl)	$	51.61		$	111.02
Differential to NYMEX	$	(6.47	)	$	(8.21	)
Average oil wellhead to NYMEX percentage		87	%		93	%
Average natural gas wellhead ($/Mcf)	$	3.48		$	9.73
Average NYMEX ($/Mcf)	$	4.20		$	9.48
Differential to NYMEX	$	(0.72	)	$	0.25
Average natural gas wellhead to NYMEX percentage		83	%		103	%

     Our average oil wellhead price as a percentage of the average NYMEX price was 87 percent in the first six months of 2009 as compared to 93 percent in the first six months of 2008. The percentage differential widened as a result of a 54 percent decrease in NYMEX as compared to the first six months of 2008. However, the per Bbl differential improved from $8.21 per Bbl in the first six months of 2008 to $6.47 per Bbl in the first six months of 2009.

     Our average natural gas wellhead price as a percentage of the average NYMEX price was 83 percent in the first six months of 2009 as compared to 103 percent in the first six months of 2008. Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of liquids extracted. Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas in Mcf as production. During the first six months of 2008, the price of NGLs increased at a much faster pace than did the price of natural gas resulting in a price we were paid per Mcf under certain contracts to be higher than the NYMEX. During the first half of 2009, we recorded a one-time positive $1.0 million value price adjustment for NGLs marketed by a third party. However, the natural gas index prices related to our West Texas, Permian, East Texas, and Rocky Mountains natural gas contracts all widened in their relationship to NYMEX causing an overall wider differential for the first six months of 2009.

     Marketing revenues decreased 83 percent from $6.6 million in the first six months of 2008 to $1.1 million in the first six months of 2009 primarily as a result of a reduction in natural gas throughput in our Wildhorse pipeline. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

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ENCORE ACQUISITION COMPANY

Expenses. The following table summarizes our expenses for the periods indicated:

	Six months ended June 30,						Increase / (Decrease)
	2009			2008			$			%
Expenses (in thousands):
Production:
Lease operating	$	84,676		$	81,047		$	3,629
Production, ad valorem, and severance taxes		28,852			62,495			(33,643	)
Total production expenses		113,528			143,542			(30,014	)		-21	%
Other:
Depletion, depreciation, and amortization		144,734			100,569			44,165
Exploration		27,133			17,081			10,052
General and administrative		27,473			21,246			6,227
Marketing		1,254			7,507			(6,253	)
Derivative fair value loss		12,515			321,528			(309,013	)
Other operating		21,178			5,732			15,446
Total operating expenses		347,815			617,205			(269,390	)		-44	%
Interest		35,089			36,545			(1,456	)
Income tax benefit		(36,443	)		(2,589	)		(33,854	)
Total expenses	$	346,461		$	651,161		$	(304,700	)		-47	%
Expenses (per BOE):
Production:
Lease operating	$	11.23		$	11.66		$	(0.43	)
Production, ad valorem, and severance taxes		3.83			8.99			(5.16	)
Total production expenses		15.06			20.65			(5.59	)		-27	%
Other:
Depletion, depreciation, and amortization		19.20			14.46			4.74
Exploration		3.60			2.46			1.14
General and administrative		3.64			3.06			0.58
Marketing		0.17			1.08			(0.91	)
Derivative fair value loss		1.66			46.24			(44.58	)
Other operating		2.81			0.82			1.99
Total operating expenses		46.14			88.77			(42.63	)		-48	%
Interest		4.65			5.26			(0.61	)
Income tax benefit		(4.83	)		(0.37	)		(4.46	)
Total expenses	$	45.96		$	93.66		$	(47.70	)		-51	%

     Production expenses. Total production expenses decreased 21 percent from $143.5 million in the first six months of 2008 to $113.5 million in the first six months of 2009. Our production margin decreased 66 percent from $483.0 million in the first six months of 2008 to $163.2 million in the first six months of 2009. Total oil and natural gas wellhead revenues per BOE decreased by 59 percent and total production expenses per BOE decreased by 27 percent. On a per BOE basis, our production margin decreased 69 percent to $21.64 per BOE in the first six months of 2009 as compared to $69.45 per BOE in the first six months of 2008.

     Production expense attributable to LOE increased $3.6 million from $81.0 million in the first six months of 2008 to $84.7 million in the first six months of 2009 as a result of higher production volumes, partially offset by a $0.43 decrease in the per BOE rate. Our higher production volumes increased LOE by approximately $6.8 million. Our lower average LOE per BOE rate decreased LOE by approximately $3.2 million and was primarily due to decreases in natural gas prices resulting in lower electricity costs and gas plant fuel costs, as well as lower prices paid to oilfield service companies and suppliers, partially offset by an increase of $7.0 million for retention bonuses to be paid in August 2009 related to our 2008 strategic alternatives process.

     Production expense attributable to production taxes decreased $33.6 million from $62.5 million in the first six months of 2008 to $28.9 million in the first six months of 2009 primarily due to lower wellhead revenues, which exclude the effects of commodity derivative contracts. As a percentage of oil and natural gas wellhead revenues, production taxes increased to 10.4 percent in the first six months of 2009 as compared to 10.0 percent in the first six months of 2008 primarily due to higher ad valorem taxes, which are based on a flat rate of production volumes as opposed to a percentage of wellhead revenues.

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ENCORE ACQUISITION COMPANY

     DD&A expense. DD&A expense increased $44.2 million from $100.6 million in the first six months of 2008 to $144.7 million in the first six months of 2009 as a result of a $4.74 increase in the per BOE rate and higher production volumes. Our higher average DD&A per BOE rate increased DD&A expense by approximately $35.7 million and was primarily due to the decrease in our proved reserves as a result of lower average commodity prices. Our higher production volumes increased DD&A expense by approximately $8.5 million.

     Exploration expense. Exploration expense increased $10.1 million from $17.1 million in the first six months of 2008 to $27.1 million in the first six months of 2009. During the first six months of 2009, we expensed 3.9 net exploratory dry holes totaling $14.5 million. During the first six months of 2008, we expensed 2.5 net exploratory dry holes totaling $7.2 million. Impairment of unproved acreage increased $3.5 million from $8.3 million in the first six months of 2008 to $11.8 million in the first six months of 2009, primarily due to our larger unproved property base, as well as the impairment of certain acreage through the normal course of evaluation. The following table illustrates the components of exploration expense for the periods indicated:

	Six months ended June 30,				Increase /
	2009		2008		(Decrease)
	(in thousands)
Dry holes	$	14,513	$	7,234	$	7,279
Geological and seismic		639		833		(194	)
Delay rentals		230		703		(473	)
Impairment of unproved acreage		11,751		8,311		3,440
Total	$	27,133	$	17,081	$	10,052

     G&A expense. G&A expense increased $6.2 million from $21.2 million in the first six months of 2008 to $27.5 million in the first six months of 2009 primarily due to an increase of $3.0 million for retention bonuses to be paid in August 2009 related to our 2008 strategic alternatives process and the expensing of transaction costs related to our 2009 acquisitions pursuant to SFAS 141R.

     Marketing expenses. Marketing expenses decreased $6.3 million from $7.5 million in the first six months of 2008 to $1.3 million in the first six months of 2009 primarily due to a reduction in natural gas throughput in our Wildhorse pipeline. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

     Derivative fair value loss. During the first six months of 2009, we recorded a $12.5 million derivative fair value loss as compared to $321.5 million in the first six months of 2008, the components of which were as follows:

	Six Months Ended June 30,						Increase /
	2009			2008			(Decrease)
	(in thousands)
Ineffectiveness	$	(34	)	$	(343	)	$	309
Mark-to-market loss		280,993			265,048			15,945
Premium amortization		84,719			32,806			51,913
Settlements		(353,163	)		24,017			(377,180	)
Total derivative fair value loss	$	12,515		$	321,528		$	(309,013	)

     Other operating expense. Other operating expense increased $15.4 million from $5.7 million in the first six months of 2008 to $21.2 million in the first six months of 2009. Other operating expense for the first six months of 2009 includes a $5.7 million adjustment to the carrying value of pipe and other tubular inventory whose market value had declined below cost and a $4.7 million adjustment to the carrying value of certain receivables, primarily from ExxonMobil related to our West Texas joint venture.

     Interest expense. Interest expense decreased $1.5 million from $36.5 million in the first six months of 2008 to $35.1 million in the first six months of 2009 primarily due to a reduction in LIBOR, partially offset by the issuance of our 9.5% Notes. Our weighted average interest rate was 5.0 percent for the first six months of 2009 as compared to 5.9 percent for the first six months of 2008.

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ENCORE ACQUISITION COMPANY

     The following table illustrates the components of interest expense for the periods indicated:

	Six months ended June 30,				Increase /
	2009		2008		(Decrease)
	(in thousands)
6.25% Senior Subordinated Notes	$	4,872	$	4,861	$	11
6.0% Senior Subordinated Notes		9,288		9,271		17
9.5% Senior Subordinated Notes		4,169		—		4,169
7.25% Senior Subordinated Notes		5,501		5,497		4
Revolving credit facilities		8,687		15,605		(6,918	)
Other		2,572		1,311		1,261
Total	$	35,089	$	36,545	$	(1,456	)

     Income taxes. In the first six months of 2009, we recorded an income tax benefit of $36.4 million as compared to $2.6 million in the first six months of 2008. In the first six months of 2009, we had a loss before income taxes and noncontrolling interest of $103.9 million as compared to $22.0 million in the first six months of 2008. Our effective tax rate increased to 35.1 percent in the first six months of 2009 as compared to 11.8 percent in the first six months of 2008 primarily due to the permanent adjustment for ENP’s pre-tax loss remaining flat while EAC’s consolidated pre-tax loss increased $81.9 million, or 373 percent.

Capital Commitments, Capital Resources, and Liquidity

     Capital commitments

     Our primary needs for cash are:

• Development, exploitation, and exploration of oil and natural gas properties;

• Acquisitions of oil and natural gas properties;

• Funding of working capital; and

• Contractual obligations.

     Development, exploitation, and exploration of oil and natural gas properties. The following table summarizes our costs incurred (excluding asset retirement obligations) related to development, exploitation, and exploration activities for the periods indicated:

	Three months ended June 30,				Six months ended June 30,
	2009		2008		2009		2008
	(in thousands)
Development and exploitation	$	24,993	$	76,876	$	75,340	$	134,248
Exploration		46,930		65,431		117,016		109,257
Total	$	71,923	$	142,307	$	192,356	$	243,505

     Our development and exploitation expenditures primarily relate to drilling development and infill wells, workovers of existing wells, and field related facilities. Our development and exploitation capital for the second quarter of 2009 yielded 14 gross (4.7 net) successful wells and no dry holes. Our development and exploitation capital for the first six months of 2009 yielded 48 gross (13.6 net) successful wells and no dry holes.

     Our exploration expenditures primarily relate to drilling exploratory wells, seismic costs, delay rentals, and geological and geophysical costs. Our exploration capital for the second quarter of 2009 yielded 10 gross (2.3 net) successful wells and 3 gross (2.9 net) dry holes. Our exploration capital for the first six months of 2009 yielded 33 gross (9.8 net) successful wells and 4 gross (3.9 net) dry holes.

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ENCORE ACQUISITION COMPANY

     Acquisitions of oil and natural gas properties and leasehold acreage. The following table summarizes our costs incurred (excluding asset retirement obligations) related to oil and natural gas property acquisitions for the periods indicated:

	Three months ended June 30,				Six months ended June 30,
	2009		2008		2009		2008
	(in thousands)
Acquisitions of proved property	$	27,470	$	5,687	$	27,552	$	20,468
Acquisitions of leasehold acreage		874		18,642		4,176		34,641
Total	$	28,344	$	24,329	$	31,728	$	55,109

     In May 2009, ENP acquired the Vinegarone Assets for approximately $27.5 million in cash, including post-closing adjustments. Our capital expenditures for leasehold acreage relate to the acquisition of unproved acreage in various areas.

     Funding of working capital. As of June 30, 2009 and December 31, 2008, our working capital (defined as total current assets less total current liabilities) was a negative $53.0 million and a positive $188.7 million, respectively. The decrease was primarily due to the monetization of certain of our 2009 oil derivative contracts in March 2009 and higher commodity prices at June 30, 2009 as compared to December 31, 2008, which negatively impacted the fair value of our outstanding commodity derivative contracts.

     For the remainder of 2009, we expect working capital to remain negative, primarily due to lower commodity prices. We anticipate cash reserves to be close to zero because we intend to use any excess cash to fund capital obligations and reduce outstanding borrowings and related interest expense under our revolving credit facility. However, we have availability under our revolving credit facility to fund our obligations as they become due. We do not plan to pay cash dividends in the foreseeable future. Our production volumes, commodity prices, and differentials for oil and natural gas will be the largest variables affecting working capital. Our operating cash flow is determined in large part by production volumes and commodity prices. Given our current commodity derivative contracts, assuming relatively stable commodity prices and constant or increasing production volumes, our operating cash flow should remain positive for the remainder of 2009.

     The Board approved a revised capital budget of $340 million for 2009, excluding proved property acquisitions, which is a $30 million increase from our previously approved capital budget for 2009. The level of these and other future expenditures are largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects, and market conditions. We plan to finance our ongoing expenditures using internally generated cash flow and availability under our revolving credit facility.

     Off-balance sheet arrangements. We have no investments in unconsolidated entities or persons that could materially affect our liquidity or availability of capital resources. We have no off-balance sheet arrangements that are material to our financial position or results of operations.

     Contractual obligations. The following table illustrates our contractual obligations and commitments at June 30, 2009:

			Payments Due by Period
					Six Months Ending		Years Ending		Years Ending
Contractual Obligations	Maturity				December 31,		December 31,		December 31,
and Commitments	Date		Total		2009		2010 - 2011		2012 - 2013		Thereafter
			(in thousands)
6.25% Senior Subordinated Notes (a)		4/15/2014	$	196,875	$	4,687	$	18,750	$	18,750	$	154,688
6.0% Senior Subordinated Notes (a)		7/15/2015		417,000		9,000		36,000		36,000		336,000
9.5% Senior Subordinated Notes (a)		5/1/2016		374,625		10,687		42,750		42,750		278,438
7.25% Senior Subordinated Notes (a)		12/1/2017		242,438		5,438		21,750		21,750		193,500
Revolving credit facilities (a)		3/7/2012		395,778		4,687		18,748		372,343		—
Commodity derivative contracts (b)				43,817		—		20,066		16,500		7,251
Interest rate swaps (c)				3,925		1,772		2,153		—		—
Capital lease obligations				1,514		233		932		349		—
Development commitments (d)				58,281		30,429		27,852		—		—
Operating leases and commitments (e)				15,497		1,956		7,577		5,964		—
Asset retirement obligations (f)				179,854		1,668		3,336		2,502		172,348
Total			$	1,929,604	$	70,557	$	199,914	$	516,908	$	1,142,225

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(a)	Includes principal and projected interest payments. Please read Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our long-term debt.
(b)	Represents net liabilities for commodity derivative contracts. With the exception of $38.9 million of deferred premiums on commodity derivative contracts, the ultimate settlement amounts of our commodity derivative contracts are unknown because they are subject to continuing market risk. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” and Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our commodity derivative contracts.
(c)	Represents net liabilities for interest rate swaps, the ultimate settlement of which are unknown because they are subject to continuing market risk. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” and Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our interest rate swaps.
(d)	Includes authorized purchases for work in process of $55.7 million and future minimum payments for drilling rig operations of $2.6 million. Also at June 30, 2009, we had approximately $149.7 million of authorized purchases not placed with vendors (authorized AFEs), which were not accrued and are excluded from the above table but are budgeted for and expected to be made unless circumstances change.
(e)	Includes office space and equipment obligations that have non-cancelable initial lease terms in excess of one year of $15.0 million and future minimum payments for other operating commitments of $0.5 million.
(f)	Represents the undiscounted future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal at the end of field life. Please read Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our asset retirement obligations.

     Other contingencies and commitments. In order to facilitate ongoing sales of our oil production in the CCA, we ship a portion of our production in pipelines downstream and sell to purchasers at major market hubs. From time to time, shipping delays, purchaser stipulations, or other conditions may require that we sell our oil production in periods subsequent to the period in which it is produced. In such case, the deferred sale would have an adverse effect in the period of production on reported production volumes, oil and natural gas revenues, and costs as measured on a unit-of-production basis.

     The marketing of our CCA oil production is mainly dependent on transportation through the Bridger, Poplar, and Butte pipelines to markets in the Guernsey, Wyoming area. Alternative transportation routes and markets have been developed by moving a portion of the crude oil production through the Enbridge Pipeline to the Clearbrook, Minnesota hub. To a lesser extent, our production also depends on transportation through the Platte Pipeline to Wood River, Illinois as well as other pipelines connected to the Guernsey, Wyoming area. While shipments on the Platte Pipeline are oversubscribed and subject to apportionment, we have been allocated sufficient pipeline capacity to move our crude oil production. An expansion of the Enbridge Pipeline was completed in early 2008, which moved the total Rockies area pipeline takeaway closer to a balancing point with increasing production volumes and thereby provided greater stability to oil differentials in the area. In spite of the increase in capacity, the Enbridge Pipeline continues to run at full capacity and is scheduled to complete an additional expansion by the beginning of 2010. However, further restrictions on available capacity to transport oil through any of the above-mentioned pipelines, any other pipelines, or any refinery upsets could have a material adverse effect on our production volumes and the prices we receive for our production.

     The difference between NYMEX market prices and the price received at the wellhead for oil and natural gas production is commonly referred to as a differential. In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have affected this differential. We cannot accurately predict future oil and natural gas differentials. Increases in the percentage differential between the NYMEX price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial position, and cash flows.

     Capital resources

     Cash flows from operating activities. Cash provided by operating activities increased $191.8 million from $352.3 million for the first six months of 2008 to $544.1 million for the first six months of 2009, primarily due to the monetization of certain of our 2009 oil derivative contracts in March 2009 and decreased settlements paid under our commodity derivative contracts as a result of lower average commodity prices in the first six months of 2009 as compared to the first six months of 2008, partially offset by a decrease in our production margin.

     Cash flows from investing activities. Cash used in investing activities increased $3.0 million from $306.4 million in the first six months of 2008 to $309.4 million in the first six months of 2009, primarily due to a $28.2 million increase in amounts paid to acquire oil and natural gas properties, partially offset by a $26.6 million decrease in net advancements to working interest partners. During the first six months of 2009, we collected $3.7 million (net of advancements) from ExxonMobil for their portion of costs incurred drilling wells under the joint development agreement. During the first six months of 2008, we advanced $22.9 million (net of collections) to ExxonMobil for their portion of costs incurred drilling wells under the joint development agreement.

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     Cash flows from financing activities. Our cash flows from financing activities consist primarily of proceeds from and payments on long-term debt and issuances of ENP common units. We periodically draw on our revolving credit facility to fund acquisitions and other capital commitments.

     During the first six months of 2009, we used net cash of $201.0 million in financing activities, including net repayments on revolving credit facilities of $355 million, payments for deferred commodity derivative contract premiums of $69.5 million, and ENP distributions to noncontrolling interests of $12.2 million, partially offset by $202.5 million of net proceeds from the issuance of the 9.5% Notes and $40.7 million of net proceeds from ENP issuance of common units. Net repayments decreased the outstanding borrowings under revolving credit facilities from $725 million at December 31, 2008 to $370 million at June 30, 2009.

     In October 2008, we announced that the Board approved a share repurchase program authorizing us to repurchase up to $40 million of our common stock. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions, and may be suspended or discontinued at any time. The share repurchase program will be funded using our available cash. As of June 30, 2009, we had repurchased and retired 620,265 shares of our outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. During the first six months of 2009, we did not repurchase any shares of our outstanding common stock under the share repurchase program. As of June 30, 2009, approximately $22.8 million of our common stock remained authorized for repurchase.

     During the first six months of 2008, we used net cash of $46.0 million in financing activities, including net borrowings on revolving credit facilities of $21 million, partially offset by $39.1 million of share repurchases, payments for deferred commodity derivative contract premiums of $20.6 million, and ENP distributions to noncontrolling interests of $11.2 million.

      Liquidity

     Our primary sources of liquidity are internally generated cash flows and the borrowing capacity under our revolving credit facility. We also have the ability to adjust the level of our capital expenditures. We may use other sources of capital, including the issuance of debt or equity securities, to fund acquisitions or maintain our financial flexibility. We believe that our internally generated cash flows and availability under our revolving credit facility will be sufficient to fund our planned capital expenditures for the foreseeable future. However, should commodity prices decline or the capital markets remain tight, the borrowing capacity under our revolving credit facilities could be adversely affected. In the event of a reduction in the borrowing base under our revolving credit facilities, we do not believe it will result in any required prepayments of indebtedness.

     We plan to make substantial capital expenditures in the future for the acquisition, exploitation, and development of oil and natural gas properties. We intend to finance these capital expenditures with cash flows from operations. We intend to finance our acquisition and future development and exploitation activities with a combination of cash flows from operations and issuances of debt, equity, or a combination thereof.

     Issuance of 9.5% Senior Subordinated Notes Due 2016. On April 27, 2009, we issued $225 million of our 9.5% Notes at 92.228 percent of par value. We used the net proceeds of approximately $202.5 million to reduce outstanding borrowings under our revolving credit facility. Interest on the 9.5% Notes is due semi-annually on May 1 and November 1, beginning November 1, 2009. The 9.5% Notes mature on May 1, 2016.

     Internally generated cash flows. Our internally generated cash flows, results of operations, and financing for our operations are largely dependent on oil and natural gas prices. During the first six months of 2009, our average realized oil and natural gas prices decreased by 56 percent and 64 percent, respectively, as compared to the first six months of 2008. Realized oil and natural gas prices fluctuate widely in response to changing market forces. If oil and natural gas prices decline or we experience a significant widening of our differentials, then our earnings, our cash flows from operations, and the borrowing base under our revolving credit facilities may be adversely impacted. Prolonged periods of lower oil and natural gas prices or sustained wider differentials could cause us to not be in compliance with financial covenants under our revolving credit facilities and thereby affect our liquidity. However, we have protected a portion of our forecasted production through 2012 against declining commodity prices. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” and Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our commodity derivative contracts.

     Revolving credit facilities. The syndicate of lenders underwriting our revolving credit facility includes 29 banking and other financial institutions, and the syndicate of lenders underwriting ENP’s revolving credit facility includes 12 banking and other financial

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institutions. None of the lenders are underwriting more than 16 percent of the respective total commitment. We believe the number of lenders, the small percentage participation of each, and the level of availability under each facility provides adequate diversity and flexibility should further consolidation occur within the financial services industry.

     Encore Acquisition Company Senior Secured Credit Agreement

     In March 2007, we entered into a five-year amended and restated credit agreement (as amended, the “EAC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The EAC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, we amended the EAC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the EAC Credit Agreement. The EAC Credit Agreement provides for revolving credit loans to be made to us from time to time and letters of credit to be issued from time to time for the account of us or any of our restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the EAC Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. In March 2009, the borrowing base of our revolving credit facility was reaffirmed at $1.1 billion before a reduction of $200 million solely as a result of the monetization of certain of our 2009 oil derivative contracts during the first quarter of 2009. In addition, the provisions of the EAC Credit Agreement require the borrowing base to be reduced by 33 1/3 percent of the principal amount of the 9.5% Notes. As a result, the borrowing base on the EAC Credit Agreement was reduced by $75 million in April 2009. The reductions in the borrowing base under the EAC Credit Agreement did not result in any required prepayments of indebtedness. As of June 30, 2009, the borrowing base was $825 million.

     We incur a commitment fee on the unused portion of the EAC Credit Agreement determined based on the ratio of amounts outstanding under the EAC Credit Agreement to the borrowing base in effect on such date. The following table summarizes the commitment fee percentage under the EAC Credit Agreement:

	Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base	Percentage
Less than .90 to 1		0.375	%
Greater than or equal to .90 to 1		0.500	%

     Our obligations under the EAC Credit Agreement are secured by a first-priority security interest in substantially all of our restricted subsidiaries’ proved oil and natural gas reserves and in our equity interests in our restricted subsidiaries. In addition, our obligations under the EAC Credit Agreement are guaranteed by our restricted subsidiaries.

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

	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.750	%		0.500	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.000	%		0.750	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.250	%		1.000	%
Greater than or equal to .90 to 1		2.500	%		1.250	%

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by us) is the rate equal to the British Bankers Association LIBOR Rate for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0 percent.

     Any outstanding letters of credit reduce the availability under the EAC Credit Agreement. Borrowings under the EAC Credit Agreement may be repaid from time to time without penalty.

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     The EAC Credit Agreement contains covenants that, among others, include:

• 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 and our restricted subsidiaries’ assets, subject to permitted exceptions;

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

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

• a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

• a requirement that we maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0 (the “EAC Current Ratio”); and

• a requirement that we maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0 (the “EAC Total Interest Coverage Ratio”).

     In order to show EAC’s compliance with the covenants of the EAC Credit Agreement, the use of non-GAAP financial measures is required. The presentation of these non-GAAP financial measures provides useful information to investors as they allow readers to understand how much cushion there is between the required ratios and the actual ratios. These non-GAAP financial measures should not be considered an alternative to any measure of financial performance presented in accordance with GAAP.

     As of June 30, 2009, EAC was in compliance with all covenants in the EAC Credit Agreement, including the following financial covenants:

		Actual Ratio as of
Financial Covenant	Required Ratio	June 30, 2009
EAC Current Ratio	Minimum 1.0 to 1.0	3.2 to 1.0
EAC Total Interest Coverage Ratio	Minimum 2.5 to 1.0	11.2 to 1.0

     The following table shows the calculation of the EAC Current Ratio as of June 30, 2009 ($ in thousands):

EAC current assets	$	180,425
Availability under the EAC Credit Agreement		650,000
EAC consolidated current assets	$	830,425
Divided by: EAC consolidated current liabilities	$	261,227
EAC Current Ratio		3.2

     The following table shows the calculation of the EAC Total Interest Coverage Ratio for the twelve months ended June 30, 2009 ($ in thousands):

EAC Consolidated EBITDA (a)	$	671,832
Divided by: EAC consolidated net interest expense and letter of credit fees	$	60,181
EAC Total Interest Coverage Ratio		11.2

(a) EAC Consolidated EBITDA is defined in the EAC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense. EAC Consolidated EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.

     The following table presents a calculation of EAC Consolidated EBITDA for the twelve months ended June 30, 2009 (in thousands) as required under the EAC Credit Agreement, together with a reconciliation of such amount to its most directly comparable financial measures calculated and presented in accordance with GAAP. This EBITDA measure should not be considered an alternative to net income (loss), operating income (loss), cash flow from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. This EBITDA measure may not be comparable to similarly titled measures of another company because all companies may not calculate this measure in the same manner.

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EAC consolidated net income	$	257,182
EAC unrealized non-cash hedge gain		(218,479	)
EAC consolidated net interest expense		60,181
EAC income and franchise taxes		206,725
EAC depletion, depreciation, and amortization expense		231,914
EAC non-cash equity-based compensation		11,452
EAC exploration expense		108,631
EAC other non-cash		14,226
EAC Consolidated EBITDA	$	671,832

     The EAC Credit Agreement contains customary events of default, which would permit the lenders to accelerate the debt if not cured within applicable grace periods. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the EAC Credit Agreement to be immediately due and payable.

     On June 30, 2009 and July 31, 2009, there were $175 million of outstanding borrowings and $650 million of borrowing capacity under the EAC Credit Agreement.

     Encore Energy Partners Operating LLC Credit Agreement

     In March 2007, OLLC entered into a five-year credit agreement (as amended, the “OLLC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The OLLC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, OLLC amended the OLLC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. As of June 30, 2009, the borrowing base was $240 million. In July 2009, ENP requested the syndicate of lenders underwriting the OLLC Credit Agreement to increase the borrowing base from $240 million to $375 million.

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

	Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .90 to 1		0.375%	(a)
Greater than or equal to .90 to 1		0.500	%

(a) In connection with the proposed increase in the borrowing base under the OLLC Credit Agreement from $240 million to $375 million, ENP expects this commitment fee percentage to increase to 0.500 percent.

     OLLC’s obligations under the OLLC Credit Agreement are secured by a first-priority security interest in substantially all of OLLC’s proved oil and natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition, OLLC’s obligations under the OLLC Credit Agreement are guaranteed by ENP and OLLC’s restricted subsidiaries. We consolidate the debt of ENP with that of our own; however, obligations under the OLLC Credit Agreement are non-recourse to us and our restricted subsidiaries.

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

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	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans (a)			Base Rate Loans (a)
Less than .50 to 1		1.750	%		0.750	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.000	%		0.750	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.250	%		1.000	%
Greater than or equal to .90 to 1		2.500	%		1.250	%

(a) In connection with the proposed increase in the borrowing base under the OLLC Credit Agreement from $240 million to $375 million, ENP expects the applicable margin for Eurodollar loans to increase by 0.500 percent at each tier and the applicable margin for base rate loans to increase by 0.500 percent for the first tier and by 0.750 percent for the other three tiers.

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate equal to the British Bankers Association LIBOR Rate for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0 percent.

     Any outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.

     The OLLC Credit Agreement contains covenants that, among others, include:

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

• a prohibition against purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;

• a restriction on creating liens on the assets of ENP, OLLC, and OLLC’s restricted subsidiaries, subject to permitted exceptions;

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

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

• a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

• a requirement that ENP and OLLC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0 (the “ENP Current Ratio”);

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 1.5 to 1.0 (the “ENP Total Interest Coverage Ratio”);

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA to consolidated senior interest expense of not less than 2.5 to 1.0 (the “ENP Senior Interest Coverage Ratio”); and

• a requirement that ENP and OLLC maintain a ratio of consolidated funded debt (excluding certain related party debt) to consolidated adjusted EBITDA of not more than 3.5 to 1.0 (the “ENP Leverage Ratio”).

     In order to show ENP’s and OLLC’s compliance with the covenants of the OLLC Credit Agreement, the use of non-GAAP financial measures is required. The presentation of these non-GAAP financial measures provides useful information to investors as they allow readers to understand how much cushion there is between the required ratios and the actual ratios. These non-GAAP financial measures should not be considered an alternative to any measure of financial performance presented in accordance with GAAP.

     As of June 30, 2009, ENP and OLLC were in compliance with all covenants in the OLLC Credit Agreement, including the following financial covenants:

		Actual Ratio as of
Financial Covenant	Required Ratio	June 30, 2009
ENP Current Ratio	Minimum 1.0 to 1.0		3.3 to 1.0
ENP Total Interest Coverage Ratio	Minimum 1.5 to 1.0		13.0 to 1.0
ENP Senior Interest Coverage Ratio	Minimum 2.5 to 1.0		17.2 to 1.0
ENP Leverage Ratio	Maximum 3.5 to 1.0		1.7 to 1.0

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     The following table shows the calculation of the ENP Current Ratio as of June 30, 2009 ($ in thousands):

ENP current assets	$	56,824
Availability under the OLLC Credit Agreement		45,000
ENP consolidated current assets	$	101,824
Divided by: ENP consolidated current liabilities	$	31,317
ENP Current Ratio		3.3

     The following table shows the calculation of the ENP Total Interest Coverage Ratio for the twelve months ended June 30, 2009 ($ in thousands):

ENP Consolidated EBITDA (a)	$	103,785
Divided by:
ENP consolidated interest expense and letter of credit fees	$	7,987
ENP consolidated interest income		(23	)
ENP consolidated net interest expense and letter of credit fees	$	7,964
ENP Total Interest Coverage Ratio		13.0

(a) ENP Consolidated EBITDA is defined in the OLLC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense. ENP Consolidated EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.

     The following table shows the calculation of the ENP Senior Interest Coverage Ratio for the twelve months ended June 30, 2009 ($ in thousands):

ENP Consolidated EBITDA (a)	$	103,785
Divided by:
ENP consolidated senior interest expense	$	6,045
ENP consolidated interest income		(23	)
ENP consolidated net senior interest expense	$	6,022
ENP Senior Interest Coverage Ratio		17.2

(a) ENP Consolidated EBITDA is defined in the OLLC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense. ENP Consolidated EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.

     The following table shows the calculation of the ENP Leverage Ratio for the twelve months ended June 30, 2009 ($ in thousands):

ENP consolidated funded debt	$	195,000
Divided by: ENP Consolidated Adjusted EBITDA (a)	$	114,577
ENP Leverage Ratio		1.7

(a) ENP Consolidated Adjusted EBITDA is defined in the OLLC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense, after giving pro forma effect to one or more acquisitions or dispositions in excess of $20 million in the aggregate. ENP Consolidated Adjusted EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.

     The following table presents a calculation of ENP Consolidated EBITDA and ENP Consolidated Adjusted EBITDA for the twelve months ended June 30, 2009 (in thousands) as required under the OLLC Credit Agreement, together with a reconciliation of such amounts to their most directly comparable financial measures calculated and presented in accordance with GAAP. These EBITDA measures should not be considered an alternative to net income (loss), operating income (loss), cash flow from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. These EBITDA measures may not be comparable to similarly titled measures of another company because all companies may not calculate these measures in the same manner.

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ENP consolidated net income	$	180,405
ENP unrealized non-cash hedge gain		(130,390	)
ENP consolidated net interest expense		7,964
ENP income and franchise taxes		998
ENP depletion, depreciation, amortization, and exploration expense		41,202
ENP non-cash unit-based compensation		3,321
ENP other non-cash		285
ENP Consolidated EBITDA		103,785
Pro forma effect of acquisitions		10,792
ENP Consolidated Adjusted EBITDA	$	114,577

     The OLLC Credit Agreement contains customary events of default, which would permit the lenders to accelerate the debt if not cured within applicable grace periods. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately due and payable.

     On June 30, 2009, there were $195 million of outstanding borrowings and $45 million of borrowing capacity under the OLLC Credit Agreement. On July 31, 2009, there were $150 million of outstanding borrowings and $90 million of borrowing capacity under the OLLC Credit Agreement.

     Please read Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our long-term debt.

     Debt covenants. At June 30, 2009, we and ENP were in compliance with all debt covenants.

     Capitalization. At June 30, 2009, we had total assets of $3.4 billion and total capitalization of $2.6 billion, of which 55 percent was represented by equity and 45 percent by long-term debt. At December 31, 2008, we had total assets of $3.6 billion and total capitalization of $2.8 billion, of which 53 percent was represented by equity and 47 percent by long-term debt. The percentages of our capitalization represented by equity and long-term debt could vary in the future if debt or equity is used to finance capital projects or acquisitions.

Critical Accounting Policies and Estimates

     Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in our 2008 Annual Report on Form 10-K for additional information regarding our critical accounting policies and estimates.

New Accounting Pronouncements

     The effects of new accounting pronouncements are discussed in Note 2 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.”

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of exposure, but rather indicators of potential exposure. This information provides indicators of how we view and manage our ongoing market risk exposures. We do not enter into market risk sensitive instruments for speculative trading purposes.

     The information included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2008 Annual Report on Form 10-K is incorporated herein by reference. Such information includes a description of our potential exposure to market risks, including commodity price risk and interest rate risk.

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Commodity Price Sensitivity

     Our commodity derivative contracts are discussed in Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” The counterparties to our commodity derivative contracts are a diverse group of seven institutions, all of which are currently rated A+ or better by Standard & Poor’s and/or Fitch, with the majority rated AA- or better. As of June 30, 2009, the fair market value of our oil derivative contracts was a net asset of approximately $47.3 million and the fair market value of our natural gas derivative contracts was a net asset of approximately $25.7 million. These amounts exclude deferred premiums of $38.9 million that are not subject to changes in commodity prices. Based on our open commodity derivative positions at June 30, 2009, a 10 percent increase in the respective NYMEX prices for oil and natural gas would decrease our net commodity derivative asset by approximately $36.4 million, while a 10 percent decrease in the respective NYMEX prices for oil and natural gas would increase our net commodity derivative asset by approximately $38.3 million.

Interest Rate Sensitivity

     Our long-term debt is discussed in Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” At June 30, 2009, we had total long-term debt of $1.2 billion, net of discount of $22.1 million. Of this amount, $150 million bears interest at a fixed rate of 6.25 percent, $300 million bears interest at a fixed rate of 6.0 percent, $225 million bears interest at a fixed rate of 9.5 percent, and $150 million bears interest at a fixed rate of 7.25 percent. The remaining long-term debt balance of $370 million as of June 30, 2009 consisted of outstanding borrowings under revolving credit facilities, which are subject to floating market rates of interest that are linked to the Eurodollar rate.

     At this level of floating rate debt, if the Eurodollar rate increased by 10 percent, we would incur an additional $0.9 million of interest expense per year on revolving credit facilities, and if the Eurodollar rate decreased by 10 percent, we would incur $0.9 million less. Additionally, if the discount rates on our senior notes increased by 10 percent, we estimate the fair value of our fixed rate debt at June 30, 2009 would increase from approximately $724.7 million to approximately $734.7 million, and if the discount rates on our senior notes decreased by 10 percent, we estimate the fair value would decrease to approximately $714.7 million.

     ENP’s interest rate swaps are discussed in Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” As of June 30, 2009, the fair market value of ENP’s interest rate swaps was a net liability of approximately $3.8 million. If the Eurodollar rate increased by 10 percent, we estimate the liability would decrease to approximately $3.4 million, and if the Eurodollar rate decreased by 10 percent, we estimate the liability would increase to approximately $4.2 million.

Item 4. Controls and Procedures

     In accordance with the Securities Exchange Act of 1934 (the “Exchange Act”) Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2009 to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

     There were no changes in our internal control over financial reporting during the second quarter of 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

     We are a party to ongoing legal proceedings in the ordinary course of business. Management does not believe the result of these legal proceedings will have a material adverse effect on our business, financial condition, results of operations, or liquidity.

Item 1A. Risk Factors

     In addition to the other information set forth in this Report, you should carefully consider the factors discussed in “Item 1A. Risk Factors” and elsewhere in our 2008 Annual Report on Form 10-K, which could materially affect our business, financial condition, or results of operations. The risks described in our 2008 Annual Report on Form 10-K are not the only risks we face. Unknown risks and uncertainties or risks and uncertainties that we currently believe to be immaterial may also have a material adverse effect on our business, financial condition, or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

     In October 2008, the Board approved a share repurchase program authorizing us to repurchase up to $40 million of our common stock. As of June 30, 2009, we had repurchased and retired 620,265 shares of our outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. During the second quarter of 2009, we did not repurchase any shares of our outstanding common stock under the share repurchase program. As of June 30, 2009, approximately $22.8 million of our common stock remained authorized for repurchase.

     The following table summarizes purchases of our common stock during the second quarter of 2009:

					Total Number of		Approximate Dollar
					Shares Purchased		Value of Shares
	Total Number				as Part of Publicly		That May Yet Be
	of Shares		Average Price		Announced Plans		Purchased Under the
Month	Purchased		Paid per Share		or Programs		Plans or Programs
April		—	$	—		—
May (a)		466	$	34.41		—
June		—	$	—		—
Total		466	$	34.41		—	$	22,830,139

(a) Certain employees directed us to withhold 466 shares of common stock to satisfy minimum tax withholding obligations in conjunction with the vesting of restricted stock awards.

Item 4. Submission of Matters to a Vote of Security Holders

     Our annual meeting of stockholders was held on April 28, 2009. The items submitted to stockholders for vote were (1) the election of eight nominees to serve as directors until our next annual meeting and (2) the ratification of the appointment of Ernst & Young LLP as our independent registered public accounting firm for 2009. Notice of the meeting and proxy information was distributed to stockholders prior to the meeting in accordance with law. There were no solicitations in opposition to the nominees. Out of a total of 52,754,036 shares of our common stock outstanding and entitled to vote at the meeting, 50,091,968 shares (95.0 percent) were present in person or by proxy.

Election of Directors

     The Board recommended that our stockholders elect all eight nominees to serve as our directors until our next annual meeting. The vote tabulation with respect to each nominee to the Board was as follows:

62

ENCORE ACQUISITION COMPANY

NOMINEE	FOR		WITHHELD
I. Jon Brumley		31,100,906		18,991,062
Jon S. Brumley		30,942,150		19,149,818
John A. Bailey		31,239,381		18,852,587
Martin C. Bowen		31,239,182		18,852,786
Ted Collins, Jr.		31,115,413		18,976,555
Ted A. Gardner		31,239,381		18,852,587
John V. Genova		31,240,623		18,851,345
James A. Winne III		31,253,638		18,838,330

Appointment of Independent Registered Public Accounting Firm for 2009

     The Board recommended that our stockholders ratify the appointment of Ernst & Young LLP as our independent registered public accounting firm for 2009. The vote tabulation with respect to the ratification of the appointment of the independent registered public accounting firm for 2009 was as follows:

FOR	AGAINST		ABSTAIN
49,965,408		109,497		17,063

63

EX-99.4

Exhibit 99.4

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2009

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission File Number: 001-16295

ENCORE ACQUISITION COMPANY

(Exact name of registrant as specified in its charter)

Delaware	75-2759650
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

777 Main Street, Suite 1400, Fort Worth, Texas	76102
(Address of principal executive offices)	(Zip Code)

(817) 877-9955

(Registrant’s telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).                                                                                                        Yes o       No o

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

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

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

Number of shares of common stock, $0.01 par value, outstanding as of October 27, 2009   55,541,823

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENCORE ACQUISITION COMPANY

CONSOLIDATED BALANCE SHEETS
(in thousands, except share and par value amounts)

	September 30,			December 31,
	2009			2008
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	6,683		$	2,039
Accounts receivable, net of allowance for doubtful accounts of $434 and $381, respectively		104,980			117,995
Current portion of long-term receivables		8,325			11,070
Inventory		24,593			24,798
Derivatives		51,974			349,344
Income taxes		9,801			29,445
Other		7,310			6,239
Total current assets		213,666			540,930
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		4,146,881			3,538,459
Unproved properties		104,931			124,339
Accumulated depletion, depreciation, and amortization		(985,349	)		(771,564	)
		3,266,463			2,891,234
Other property and equipment		28,598			25,192
Accumulated depreciation		(16,100	)		(12,753	)
		12,498			12,439
Goodwill		60,606			60,606
Derivatives		47,694			38,497
Long-term receivables, net of allowance for doubtful accounts of $13,725 and $7,643, respectively		53,454			60,915
Other		59,433			28,574
Total assets	$	3,713,814		$	3,633,195
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	10,412		$	10,017
Accrued liabilities:
Lease operating		18,115			19,108
Development capital		48,266			79,435
Interest		21,839			11,808
Production, ad valorem, and severance taxes		34,475			25,133
Compensation		9,434			16,216
Derivatives		37,238			63,476
Oil and natural gas revenues payable		16,658			10,821
Deferred taxes		63,968			105,768
Other		15,202			10,470
Total current liabilities		275,607			352,252
Derivatives		39,370			8,922
Future abandonment cost, net of current portion		51,664			48,058
Deferred taxes		431,075			416,915
Long-term debt		1,243,496			1,319,811
Other		3,837			3,989
Total liabilities		2,045,049			2,149,947
Commitments and contingencies (see Note 15)
Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par value, 144,000,000 shares authorized, 54,621,701 and 51,551,937 issued and outstanding, respectively		546			516
Additional paid-in capital		666,386			525,763
Treasury stock, at cost, none and 4,753 shares, respectively		—			(101	)
Retained earnings		728,299			789,698
Accumulated other comprehensive loss		(1,184	)		(1,748	)
Total EAC stockholders’ equity		1,394,047			1,314,128
Noncontrolling interest		274,718			169,120
Total equity		1,668,765			1,483,248
Total liabilities and equity	$	3,713,814		$	3,633,195

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

1

ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
(unaudited)

	Three months ended						Nine months ended
	September 30,						September 30,
	2009			2008			2009			2008
Revenues:
Oil	$	152,949		$	268,543		$	374,915		$	776,001
Natural gas		32,168			66,772			86,908			182,973
Marketing		887			2,163			2,008			8,740
Total revenues		186,004			337,478			463,831			967,714
Expenses:
Production:
Lease operating		38,141			48,966			122,817			130,013
Production, ad valorem, and severance taxes		19,222			33,350			48,074			95,845
Depletion, depreciation, and amortization		72,627			58,545			217,361			159,114
Impairment of long-lived assets		—			26,292			—			26,292
Exploration		16,668			13,381			43,801			30,462
General and administrative		13,270			15,303			40,743			36,549
Marketing		358			1,855			1,612			9,362
Derivative fair value loss (gain)		(13,256	)		(239,435	)		(741	)		82,093
Other operating		8,241			4,073			29,419			9,805
Total expenses		155,271			(37,670	)		503,086			579,535
Operating income (loss)		30,733			375,148			(39,255	)		388,179
Other income (expenses):
Interest		(21,920	)		(18,124	)		(57,009	)		(54,669	)
Other		600			1,553			1,811			3,090
Total other expenses		(21,320	)		(16,571	)		(55,198	)		(51,579	)
Income (loss) before income taxes		9,413			358,577			(94,453	)		336,600
Income tax benefit (provision)		(11,189	)		(121,184	)		25,254			(118,595	)
Consolidated net income (loss)		(1,776	)		237,393			(69,199	)		218,005
Less: net loss (income) attributable to noncontrolling interest		(3,223	)		(31,086	)		9,669			(16,198	)
Net income (loss) attributable to EAC stockholders	$	(4,999	)	$	206,307		$	(59,530	)	$	201,807
Net income (loss) per common share:
Basic	$	(0.10	)	$	3.88		$	(1.15	)	$	3.78
Diluted	$	(0.10	)	$	3.77		$	(1.15	)	$	3.67
Weighted average common shares outstanding:
Basic		52,349			52,258			51,964			52,466
Diluted		52,349			52,979			51,964			53,134

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

2

ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENT OF EQUITY AND COMPREHENSIVE LOSS
(in thousands)
(unaudited)

	EAC Stockholders
	Issued																	Accumulated
	Shares of					Additional			Shares of									Other
	Common			Common		Paid-in			Treasury			Treasury			Retained			Comprehensive			Noncontrolling			Total
	Stock			Stock		Capital			Stock			Stock			Earnings			Loss			Interest			Equity
Balance at December 31, 2008		51,557		$	516	$	525,763			(5	)	$	(101	)	$	789,698		$	(1,748	)	$	169,120		$	1,483,248
Exercise of stock options and vesting of restricted stock		430			3		37			—			—			—			—			—			40
Net proceeds from issuance of common stock		2,750			27		100,663			—			—			—			—			—			100,690
Purchase of treasury stock		—			—		—			(111	)		(2,961	)		—			—			—			(2,961	)
Cancellation of treasury stock		(116	)		—		(1,193	)		116			3,062			(1,869	)		—			—			—
Non-cash equity-based compensation		—			—		11,308			—			—			—			—			117			11,425
ENP cash distributions to noncontrolling interest		—			—		—			—			—			—			—			(24,629	)		(24,629	)
Net proceeds from ENP issuance of common units		—			—		—			—			—			—			—			169,945			169,945
Adjustment to reflect gain on ENP issuance of common units		—			—		29,691			—			—			—			—			(29,691	)		—
Other		—			—		117			—			—			—			—			—			117
Components of comprehensive loss:
Consolidated net loss		—			—		—			—			—			(59,530	)		—			(9,669	)		(69,199	)
Change in deferred hedge loss on interest rate swaps, net of tax of $256		—			—		—			—			—			—			564			(475	)		89
Total comprehensive loss																									(69,110	)
Balance at September 30, 2009		54,621		$	546	$	666,386			—		$	—		$	728,299		$	(1,184	)	$	274,718		$	1,668,765

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

3

ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)

	Nine months ended
	September 30,
	2009			2008
Cash flows from operating activities:
Consolidated net income (loss)	$	(69,199	)	$	218,005
Adjustments to reconcile consolidated net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization		217,361			159,114
Impairment of long-lived assets		—			26,292
Non-cash exploration expense		42,374			27,699
Deferred taxes		(25,903	)		109,653
Non-cash equity-based compensation expense		9,761			9,963
Non-cash derivative loss		105,757			38,203
Loss (gain) on disposition of assets		26			(691	)
Other		17,992			7,349
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		37,719			(31,135	)
Current derivatives		256,261			(12,196	)
Other current assets		12,565			(30,745	)
Long-term derivatives		—			(7,028	)
Other assets		(413	)		(2,094	)
Accounts payable		5,511			(2,476	)
Other current liabilities		24,563			20,581
Other noncurrent liabilities		(1,222	)		(1,507	)
Net cash provided by operating activities		633,153			528,987
Cash flows from investing activities:
Proceeds from disposition of assets		5,205			1,230
Purchases of other property and equipment		(3,576	)		(2,416	)
Acquisition of oil and natural gas properties		(423,959	)		(116,767	)
Development of oil and natural gas properties		(293,443	)		(384,864	)
Net collections from (advances to) working interest partners		5,457			(33,277	)
Net cash used in investing activities		(710,316	)		(536,094	)
Cash flows from financing activities:
Repurchase and retirement of common stock		—			(50,000	)
Exercise of stock options and vesting of restricted stock, net of treasury stock purchases		(2,921	)		799
Proceeds from long-term debt, net of issuance costs		590,090			1,070,238
Payments on long-term debt		(676,000	)		(974,500	)
Proceeds from EAC issuance of common stock, net of offering costs		100,690			—
ENP cash distributions to noncontrolling interest		(24,629	)		(19,525	)
Proceeds from ENP issuance of common units, net of offering costs		170,149			—
Payments of deferred commodity derivative contract premiums		(70,456	)		(30,822	)
Change in cash overdrafts		(5,116	)		13,040
Net cash provided by financing activities		81,807			9,230
Increase in cash and cash equivalents		4,644			2,123
Cash and cash equivalents, beginning of period		2,039			1,704
Cash and cash equivalents, end of period	$	6,683		$	3,827

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

4

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

Note 1. Description of Business

     EAC is engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States. Since 1998, EAC has acquired producing properties with proven reserves and leasehold acreage and grown the production and proven reserves by drilling, exploring, reengineering or expanding existing waterflood projects, and applying tertiary recovery techniques. EAC’s properties and oil and natural gas reserves are located in four core areas:

• the Cedar Creek Anticline (“CCA”) in the Williston Basin in Montana and North Dakota;

• the Permian Basin in West Texas and southeastern New Mexico;

• the Rockies, which includes non-CCA assets in the Williston, Big Horn, and Powder River Basins in Wyoming, Montana, and North Dakota, and the Paradox Basin in southeastern Utah; and

• the Mid-Continent area, which includes the Arkoma and Anadarko Basins in Arkansas and Oklahoma, the North Louisiana Salt Basin, and the East Texas Basin.

Note 2. Basis of Presentation

     EAC’s consolidated financial statements include the accounts of its wholly owned and majority-owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.

     In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments necessary to present fairly, in all material respects, EAC’s financial position as of September 30, 2009, results of operations for the three and nine months ended September 30, 2009 and 2008, and cash flows for the nine months ended September 30, 2009 and 2008. All adjustments are of a normal recurring nature. These interim results are not necessarily indicative of results for an entire year.

     Certain amounts and disclosures have been condensed or omitted from these consolidated financial statements pursuant to the rules and regulations of the SEC. Therefore, these consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in EAC’s 2008 Annual Report on Form 10-K.

Noncontrolling Interest

     As of September 30, 2009 and December 31, 2008, EAC owned approximately 46 percent and 63 percent, respectively, of ENP’s common units. EAC also owns 100 percent of Encore Energy Partners GP LLC (“GP LLC”), a Delaware limited liability company and indirect wholly owned non-guarantor subsidiary of EAC, which is ENP’s general partner. Considering the presumption of control of GP LLC in accordance with Emerging Issues Task Force (“EITF”) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights” (ASC 810-20), the financial position, results of operations, and cash flows of ENP are fully consolidated with those of EAC.

     As presented in the accompanying Consolidated Balance Sheets, “Noncontrolling interest” as of September 30, 2009 and December 31, 2008 of approximately $274.7 million and $169.1 million, respectively, represents third-party partnership interests in ENP. As presented in the accompanying Consolidated Statements of Operations, “Net income attributable to noncontrolling interest” for the three months ended September 30, 2009 of approximately $3.2 million, “Net loss attributable to noncontrolling interest” for the nine months ended September 30, 2009 of approximately $9.7 million, and “Net income attributable to noncontrolling interest” for the three and nine months ended September 30, 2008 of approximately $31.1 million and $16.2 million, respectively, represents the net income or loss of ENP attributable to third-party partners.

5

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following table summarizes the effects of changes in EAC’s partnership interest in ENP on EAC’s equity for the periods indicated:

	Three months ended					Nine months ended
	September 30,					September 30,
	2009			2008		2009			2008
	(in thousands)
Net income (loss) attributable to EAC stockholders	$	(4,999	)	$	206,307	$	(59,530	)	$	201,807
Transfer from (to) noncontrolling interest:
Increase in EAC’s paid-in capital for ENP’s issuance of 283,700 common units in connection with acquisition of net profits interest in certain Crockett County properties		—			—		—			3,458
Increase in EAC’s paid-in capital for ENP’s issuance of 2,760,000 common units in public offering		—			—		9,312			—
Increase in EAC’s paid-in capital for ENP’s issuance of 9,430,000 common units in public offering		20,379			—		20,379			—
Net transfer from noncontrolling interest		20,379			—		29,691			3,458
Change from net income (loss) attributable to EAC stockholders and transfers from (to) noncontrolling interest	$	15,380		$	206,307	$	(29,839	)	$	205,265

Supplemental Disclosures of Non-cash Investing and Financing Activities

     The following table sets forth supplemental disclosures of non-cash investing and financing activities for the periods indicated:

	Nine months ended September 30,
	2009		2008
	(in thousands)
Non-cash investing and financing activities:
Deferred premiums on commodity derivative contracts	$	44,907	$	53,387
ENP’s issuance of common units in connection with acquisition of net profits interest in certain Crockett County properties		—		5,748

Allowance for Doubtful Accounts

     During the three and nine months ended September 30, 2009, EAC recorded an allowance for doubtful accounts of approximately $2.4 million and $7.1 million, respectively, primarily related to balances due from ExxonMobil Corporation (“ExxonMobil”) in connection with EAC’s joint development agreement, which are included in “Other operating expense” in the accompanying Consolidated Statements of Operations. The following table summarizes the changes in the allowance for doubtful accounts for the nine months ended September 30, 2009 (in thousands):

Allowance for doubtful accounts at January 1, 2009	$	8,024
Bad debt expense		7,116
Write off		(981	)
Allowance for doubtful accounts at September 30, 2009	$	14,159

     As of September 30, 2009, $0.4 million of EAC’s allowance for doubtful accounts was current and $13.7 million was long-term.

Reclassifications

     Certain amounts in prior periods have been reclassified to conform to the current period presentation. In particular, certain amounts in the Consolidated Financial Statements have been either combined or classified in more detail.

6

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

FASB Launches Accounting Standards Codification

     In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“SFAS 168” or ASC 105-10). SFAS 168 (ASC 105-10) establishes the Codification as the sole source of authoritative accounting principles recognized by the FASB to be applied by all nongovernmental entities in the preparation of financial statements in conformity with GAAP. SFAS 168 (ASC 105-10) was prospectively effective for financial statements issued for fiscal years ending on or after September 15, 2009, and interim periods within those fiscal years. The adoption of SFAS 168 (ASC 105-10) on July 1, 2009 did not impact EAC’s results of operations or financial condition.

     Following the Codification, the FASB will not issue new standards in the form of Statements, FASB Staff Positions (“FSP”), or EITF Abstracts. Instead, it will issue Accounting Standards Updates (“ASU”), which will serve to update the Codification, provide background information about the guidance, and provide the basis for conclusions on the changes to the Codification.

     The Codification did not change GAAP; however, it did change the way GAAP is organized and presented. As a result, these changes impact how companies, including EAC, reference GAAP in their financial statements and in their significant accounting policies. EAC implemented the Codification in this Report by providing references to the Codification topics alongside references to the corresponding standards.

New Accounting Pronouncements

FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2” or ASC 820.10)

     In February 2008, the FASB issued FSP FAS 157-2, which delayed the effective date of SFAS No. 157, “Fair Value Measurements” (“SFAS 157” or ASC 820-10) for one year for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). EAC elected a partial deferral of SFAS 157 (ASC 820-10) for all instruments within the scope of FSP FAS 157-2 (ASC 820-10), including, but not limited to, its asset retirement obligations and indefinite lived assets. FSP FAS 157-2 (ASC 820-10) was prospectively effective for financial statements issued for fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The adoption of FSP FAS 157-2 (ASC 820-10) on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition. Please read “Note 6. Fair Value Measurements” for additional discussion.

SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R” or ASC 805)

     In December 2007, the FASB issued SFAS 141R, which replaces SFAS No. 141, “Business Combinations” (ASC 805). SFAS 141R (ASC 805) establishes principles and requirements for the acquiror in a business combination, including: (1) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. In April 2009, the FASB issued FSP No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arises from Contingencies” (“FSP FAS 141R-1” or ASC 805), which amends and clarifies SFAS 141R (ASC 805) to address application issues, including: (1) initial recognition and measurement; (2) subsequent measurement and accounting; and (3) disclosure of assets and liabilities arising from contingencies in a business combination. SFAS 141R (ASC 805) and FSP FAS 141R-1 (ASC 805) were prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008. The adoption of SFAS 141R (ASC 805) and FSP FAS 141R-1 (ASC 805) on January 1, 2009 did not impact EAC’s results of operations or financial condition. However, the application of SFAS 141R (ASC 805) and FSP FAS 141R-1 (ASC 805) to future acquisitions could impact EAC’s results of operations and financial condition and the reporting of acquisitions in the consolidated financial statements.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment to ARB No. 51” (“SFAS 160” or ASC 810-10-65-1)

     In December 2007, the FASB issued SFAS 160 (ASC 810-10-65-1), which amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” (ASC 810-10, 860-10-60-1, 850-10-60, 970-810-25-1, 958-810-60, and 505-10), to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 (ASC 810-10-65-1) was prospectively effective for financial statements issued for fiscal years beginning on or after December 15,

7

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

2008, except for the presentation and disclosure requirements which were retrospectively effective. SFAS 160 (ASC 810-10-65-1) clarifies that a noncontrolling interest in a subsidiary, which was often referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 (ASC 810-10-65-1) requires consolidated net income to be reported for the amounts attributable to both the parent and the noncontrolling interest on the face of the consolidated statement of operations and gains or losses on a subsidiaries’ issuance of equity to be accounted for as capital transactions. The adoption of SFAS 160 (ASC 810-10-65-1) on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition; however, it did impact the presentation of noncontrolling interest in the accompanying Consolidated Financial Statements.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161” or ASC 815-10-65-1)

     In March 2008, the FASB issued SFAS 161 (ASC 815-10-65-1), which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133” or ASC 815), to require enhanced disclosures, including: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS 133 (ASC 815) and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 (ASC 815-10-65-1) was prospectively effective for financial statements issued for fiscal years beginning on or after November 15, 2008, and interim periods within those fiscal years. The adoption of SFAS 161 (ASC 815-10-65-1) on January 1, 2009 required additional disclosures regarding EAC’s derivative instruments; however, it did not impact EAC’s results of operations or financial condition. Please read “Note 6. Fair Value Measurements” for additional discussion.

FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1” or ASC 260-10)

     In June 2008, the FASB issued FSP EITF 03-6-1 (ASC 260-10), which addresses whether instruments granted in equity-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation for computing basic earnings per share (“EPS”) under the two-class method prescribed by SFAS No. 128, “Earnings per Share” (“SFAS 128” or ASC 260-10). FSP EITF 03-6-1 (ASC 260-10) was retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The adoption of FSP EITF 03-6-1 (ASC 260-10) on January 1, 2009 did not have a material impact on EAC’s EPS calculations. In the accompanying Consolidated Financial Statements, periods prior to the adoption of FSP EITF 03-6-1 (ASC 260-10) have been restated to calculate EPS in accordance with this pronouncement. Please read “Note 11. Earnings Per Share” for additional discussion.

SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting” (“Release 33-8995”)

     In December 2008, the SEC issued Release 33-8995, which amends oil and natural gas reporting requirements under Regulations S-K and S-X. Release 33-8995 also adds a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being phased out. Release 33-8995 permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. Release 33-8995 will also allow companies to disclose their probable and possible reserves to investors at the company’s option. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor; (2) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (3) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. Release 33-8995 is prospectively effective for financial statements issued for fiscal years ending on or after December 31, 2009. EAC is evaluating the impact Release 33-8995 will have on its financial condition, results of operations, and disclosures.

FSP No. FAS 107-1 and APB 28-1, “Disclosure of Fair Value of Financial Instruments in Interim Statements” (“FSP FAS 107-1 and APB 28-1” or ASC 825-10-65-1)

     In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1 (ASC 825-10-65-1), which requires that disclosures concerning the fair value of financial instruments be presented in interim as well as annual financial statements. FSP FAS 107-1 and APB 28-1 (ASC 825-10-65-1) was prospectively effective for financial statements issued for interim periods ending after June 15, 2009. The adoption of FSP FAS 107-1 and APB 28-1 (ASC 825-10-65-1) on June 30, 2009 required additional disclosures regarding EAC’s

8

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

financial instruments; however, it did not impact EAC’s results of operations or financial condition. Please read “Note 6. Fair Value Measurements” for additional discussion.

SFAS No. 165, “Subsequent Events” (“SFAS 165” or ASC 855-10)

     In June 2009, the FASB issued SFAS 165 (ASC 855-10) to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or available to be issued. In particular, SFAS 165 (ASC 855-10) sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. SFAS 165 (ASC 855-10) was prospectively effective for financial statements issued for interim or annual periods ending after June 15, 2009. The adoption of SFAS 165 (ASC 855-10) on June 30, 2009 did not impact EAC’s results of operations or financial condition.

ASU No. 2009-05, “Fair Value Measurement and Disclosure: Measuring Liabilities at Fair Value” (“ASU 2009-05” or ASC 820-10)

     In August 2009, the FASB issued ASU 2009-05 (ASC 820-10) to provide clarification on measuring liabilities at fair value when a quoted price in an active market is not available. In particular, ASU 2009-05 specifies that a valuation technique should be applied that uses either the quote of the liability when traded as an asset, the quoted prices for similar liabilities when traded as assets, or another valuation technique consistent with existing fair value measurement guidance. ASU 2009-05 (ASC 820-10) is prospectively effective for financial statements issued for interim or annual periods ending after October 1, 2009. The adoption of ASU 2009-05 (ASC 820-10) on December 31, 2009 will not impact EAC’s results of operations or financial condition.

Note 3. Acquisitions

Acquisitions from EXCO

     In August 2009, Encore Operating acquired certain oil and natural gas properties and related assets in the Mid-Continent and East Texas from EXCO Resources, Inc. (together with its affiliates, “EXCO”) for approximately $357.0 million in cash, substantially all of which are proved producing. The operations of these properties have been included with those of EAC from the date of acquisition forward. EAC financed the acquisitions through borrowings under its revolving credit facilities and proceeds from the issuance of ENP common units to the public. A portion of the properties acquired in the EXCO acquisition and the sale of properties to ENP in August 2009, as discussed in “Note 17. ENP,” qualified as a like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended, and I.R.S. Revenue Procedure 2000-37.

CO2 Supply Agreement

     In July 2009, EAC acquired contract rights for $24 million in cash, which procures a CO2 supply to be used for a tertiary oil recovery project in EAC’s Bell Creek Field. The initial term of the contract is 15 years. The contract is classified as an intangible asset and is included in “Other” assets in the accompanying Consolidated Balance Sheet as of September 30, 2009.

Note 4. Inventory

     Inventory includes materials and supplies and oil in pipelines, which are stated at the lower of cost (determined on an average basis) or market. Oil produced at the lease which resides unsold in pipelines is carried at an amount equal to its operating costs to produce. Oil in pipelines purchased from third parties is carried at average purchase price. Inventory consisted of the following as of the dates indicated:

	September 30,		December 31,
	2009		2008
	(in thousands)
Materials and supplies	$	17,592	$	15,933
Oil in pipelines		7,001		8,865
Total inventory	$	24,593	$	24,798

     During the three and nine months ended September 30, 2009, EAC recorded a lower of cost or market adjustment of approximately $0.7 million and $6.5 million, respectively, to the carrying value of pipe and other tubular inventory whose market value had declined below cost, which are included in “Other operating expense” in the accompanying Consolidated Statements of Operations.

9

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 5. Proved Properties

     Amounts shown in the accompanying Consolidated Balance Sheets as “Proved properties, including wells and related equipment” consisted of the following as of the dates indicated:

	September 30,		December 31,
	2009		2008
	(in thousands)
Proved leasehold costs	$	1,775,500	$	1,421,859
Wells and related equipment — Completed		2,336,717		1,943,275
Wells and related equipment — In process		34,664		173,325
Total proved properties	$	4,146,881	$	3,538,459

     EAC follows FSP No. 19-1 “Accounting for Suspended Well Costs” (“FSP 19-1” or ASC 932), which permits the continued capitalization of exploratory well costs beyond one year if the well found a sufficient quantity of reserves to justify its completion as a producing well or the entity is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The following table reflects the net changes in capitalized exploratory well costs during the periods indicated, and does not include amounts that were capitalized and subsequently expensed in the same period.

	Three Months Ended			Nine Months Ended
	September 30, 2009			September 30, 2009
	(in thousands)
Beginning balance	$	28,948		$	18,220
Additions to capitalized exploratory well costs pending the determination of proved reserves		1,456			4,588
Reclassification to proved property and equipment based on the determination of proved reserves		(20,201	)		(15,054	)
Capitalized exploratory well costs charged to expense		(5,614	)		(3,165	)
Total	$	4,589		$	4,589

     The following table provides an aging, as of the dates indicated, of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year:

	September 30,		December 31,
	2009		2008
	(in thousands, except project counts)
Capitalized exploratory well costs that have been suspended:
One year or less	$	2,755	$	18,220
More than one year		1,834		—
Total	$	4,589	$	18,220
Number of projects with exploratory well costs that have been suspended for a period of greater than one year		1		0

     The following table provides an aging of gross capitalized costs of exploration projects with exploratory well costs which have been suspended for more than one year as of September 30, 2009:

	Total		2009		2008
	(in thousands)
Tuscaloosa Marine Shale	$	1,834	$	1,834	$	—

10

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 6. Fair Value Measurements

     The following table sets forth EAC’s book value and estimated fair value of financial instruments as of the dates indicated:

	September 30, 2009				December 31, 2008
	Book		Fair		Book		Fair
	Value		Value		Value		Value
	(in thousands)
Assets:
Cash and cash equivalents	$	6,683	$	6,683	$	2,039	$	2,039
Accounts receivable, net		104,980		104,980		117,995		117,995
Plugging bond		862		1,059		824		1,202
Bell Creek escrow		9,260		9,260		9,229		9,241
Commodity derivative contracts		99,668		99,668		387,841		387,841
Long-term receivables, net		61,779		61,779		71,986		71,986
Liabilities:
Accounts payable		10,412		10,412		10,017		10,017
6.25% Senior Subordinated Notes		150,000		140,250		150,000		101,250
6.0% Senior Subordinated Notes		296,421		276,000		296,040		194,250
9.5% Senior Subordinated Notes		208,228		234,000		—		—
7.25% Senior Subordinated Notes		148,847		140,250		148,771		94,500
Revolving credit facilities		440,000		440,000		725,000		725,000
Commodity derivative contracts		29,230		29,230		229		229
Deferred premiums on commodity derivative contracts		43,228		43,228		67,610		67,610
Interest rate swaps		4,150		4,150		4,559		4,559

     The book values of cash and cash equivalents, accounts receivable, net, and accounts payable approximate fair value due to the short-term nature of these instruments. The book value of long-term receivables, net, approximates fair value as it is net of amounts deemed to be uncollectible and bears interest at market rates. The plugging bond and Bell Creek escrow are included in “Other assets” in the accompanying Consolidated Balance Sheets and are classified as “held to maturity” and therefore, are recorded at amortized cost, which was less than fair value. The fair values of the plugging bond, Bell Creek escrow, and senior subordinated notes were determined using open market quotes. The difference between book value and fair value of the senior subordinated notes represents the premium or discount on that date. The book value of the revolving credit facilities approximates fair value as the interest rate is variable. EAC’s and ENP’s credit risk have not changed materially from the date the revolving credit facilities were entered into. Commodity derivative contracts and interest rate swaps are marked-to-market each period and are thus stated at fair value in the accompanying Consolidated Balance Sheets. Deferred premiums on commodity derivative contracts were recorded at their net present value at the time the contracts were entered into and EAC accretes that value to the eventual settlement price by recording interest expense each period.

Derivative Policy

     EAC uses various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with its oil and natural gas production. These arrangements are structured to reduce EAC’s exposure to commodity price decreases, but they can also limit the benefit EAC might otherwise receive from commodity price increases. EAC’s risk management activity is generally accomplished through over-the-counter derivative contracts with large financial institutions. EAC also uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation.

     EAC applies the provisions of SFAS 133 (ASC 815), which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be

11

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, the effective portion of changes in fair value can be recognized in accumulated other comprehensive income or loss until such time as the hedged item is recognized in earnings. In order to qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically.

     EAC has elected to designate its outstanding interest rate swaps as cash flow hedges. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized in earnings and included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.

     EAC has not elected to designate its current portfolio of commodity derivative contracts as hedges. Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.

Commodity Derivative Contracts

     EAC manages commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of sales volumes. Put contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collars provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price.

     From time to time, EAC enters into floor spreads. In a floor spread, EAC purchases puts at a specified price (a “purchased put”) and also sells a put at a lower price (a “short put”). This strategy enables EAC to achieve some downside protection for a portion of its production, while funding the cost of such protection by selling a put at a lower price. If the price of the commodity falls below the strike price of the purchased put, then EAC has protection against commodity price decreases for the covered production down to the strike price of the short put. At commodity prices below the strike price of the short put, the benefit from the purchased put is generally offset by the expense associated with the short put. For example, in 2007, EAC purchased oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. As NYMEX prices increased in 2008, EAC wished to protect downside price exposure at the higher price. In order to do this, EAC purchased oil put options for 2,000 Bbls/D in 2010 at $75 per Bbl and simultaneously sold oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. Thus, after these transactions were completed, EAC had purchased two oil put options for 2,000 Bbls/D in 2010 (one at $65 per Bbl and one at $75 per Bbl) and sold one oil put option for 2,000 Bbls/D in 2010 at $65 per Bbl. However, the net effect resulted in EAC owning one oil put option for 2,000 Bbls/D at $75 per Bbl. In the following tables, the purchased floor component of these floor spreads are shown net and included with EAC’s other floor contracts.

12

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following tables summarize EAC’s open commodity derivative contracts as of September 30, 2009:

Oil Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Daily		Average		Asset
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(in thousands)
Oct. - Dec. 2009 (a)													$	10,941
		3,130	$	110.00		440	$	97.75		1,000	$	68.70
2010														16,086
		880		80.00		2,940		90.57		—		—
		5,500		73.47		3,000		74.13		3,885		77.79
		8,385		62.83		500		65.60		1,750		64.08
		1,000		56.00		—		—		1,000		59.70
2011														27,767
		1,880		80.00		1,440		95.41		325		80.00
		2,500		70.00		—		—		1,060		78.42
		4,385		65.00		—		—		250		69.65
2012														4,628
		750		70.00		500		82.05		835		81.19
		2,135		65.00		250		79.25		1,300		76.54
													$	59,422

(a) In addition, ENP has a floor contract for 1,000 Bbls/D at $63.00 per Bbl and a short floor contract for 1,000 Bbls/D at $65.00 per Bbl.

Natural Gas Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted		Asset
	Daily		Average		Daily		Average		Daily		Average		(Liability)
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(in thousands)
Oct. - Dec. 2009													$	4,829
		3,800	$	8.20		3,800	$	9.83		—	$	—
		3,800		7.20		5,000		7.45		—		—
		6,800		6.57		15,000		6.63		—		—
		15,000		5.64		—		—		—		—
Jan. - June 2010														4,434
		3,800		8.20		3,800		9.58		25,452		6.46
		4,698		7.26		—		—		20,550		5.23
July - Dec. 2010														3,005
		3,800		8.20		3,800		9.58		—		—
		4,698		7.26		10,000		6.25		25,452		6.46
		10,000		5.13		—		—		550		5.86
2011														212
		3,398		6.31		—		—		27,952		6.48
		—		—		—		—		550		5.86
2012														(1,463	)
		898		6.76		—		—		25,452		6.47
		—		—		—		—		550		5.86
													$	11,017

     As of September 30, 2009, EAC had $43.2 million of deferred premiums payable, of which $26.0 million was long-term and included in “Derivatives” in the non-current liabilities section of the accompanying Consolidated Balance Sheet and $17.2 million was current and included in “Derivatives” in the current liabilities section of the accompanying Consolidated Balance Sheet. The premiums relate to various oil and natural gas floor contracts and are payable on a monthly basis from October 2009 to January 2013.

13

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     Counterparty Risk. At September 30, 2009, EAC had committed 10 percent or greater (in terms of fair market value) of either its oil or natural gas derivative contracts to the following counterparties:

	Percentage of			Percentage of
	Oil Derivative			Natural Gas Derivative
	Contracts			Contracts
Counterparty	Committed			Committed
BNP Paribas		33	%		23	%
Calyon		15	%		43	%
JP Morgan		14	%		6	%
RBC		17	%		2	%
Wachovia Bank		14	%		26	%

     In order to mitigate the credit risk of financial instruments, EAC enters into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and EAC. Instead of treating each derivative financial transaction between the counterparty and EAC separately, the master netting agreement enables the counterparty and EAC to aggregate all financial trades and treat them as a single agreement. This arrangement benefits EAC in three ways: (1) the netting of the value of all trades reduces the likelihood of counterparties requiring daily collateral posting by EAC; (2) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (3) netting of settlement amounts reduces EAC’s credit exposure to a given counterparty in the event of close-out. EAC’s accounting policy is to not offset fair value amounts for derivative instruments.

Interest Rate Swaps

     ENP uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation, whereby it converts the interest due on certain floating rate debt under its revolving credit facility to a weighted average fixed rate. The following table summarizes ENP’s open interest rate swaps as of September 30, 2009, all of which were entered into with Bank of America, N.A.:

	Notional		Fixed			Floating
Term	Amount		Rate			Rate
	(in thousands)
Oct. 2009 - Jan. 2011	$	50,000		3.1610	%	1-month LIBOR
Oct. 2009 - Jan. 2011		25,000		2.9650	%	1-month LIBOR
Oct. 2009 - Jan. 2011		25,000		2.9613	%	1-month LIBOR
Oct. 2009 - Mar. 2012		50,000		2.4200	%	1-month LIBOR

     The actual gains or losses ENP will realize from its interest rate swaps may vary significantly from the deferred loss recorded in “Accumulated other comprehensive loss” in the accompanying Consolidated Balance Sheet due to the fluctuation of interest rates.

Current Period Impact

     EAC recognizes derivative fair value gains and losses related to: (1) ineffectiveness on derivative contracts designated as hedges; (2) changes in the fair market value of derivative contracts not designated as hedges; (3) settlements on derivative contracts not designated as hedges; and (4) premium amortization. The following table summarizes the components of “Derivative fair value loss (gain)” for the periods indicated:

14

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

	Three months ended						Nine months ended
	September 30,						September 30,
	2009			2008			2009			2008
	(in thousands)
Ineffectiveness	$	18		$	(6	)	$	(16	)	$	(349	)
Mark-to-market loss (gain)		576			(276,932	)		281,569			(11,884	)
Premium amortization		6,838			14,773			91,557			47,579
Settlements		(20,688	)		22,730			(373,851	)		46,747
Total derivative fair value loss (gain)	$	(13,256	)	$	(239,435	)	$	(741	)	$	82,093

     In March 2009, EAC elected to monetize certain of its 2009 oil derivative contracts and received proceeds of approximately $190.4 million from these settlements, which were used to reduce outstanding borrowings under EAC’s revolving credit facility.

Accumulated Other Comprehensive Loss

     At September 30, 2009 and December 31, 2008, “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheet consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps of $1.2 million and $1.7 million, respectively. During the twelve months ending September 30, 2010, EAC expects to reclassify $3.5 million of deferred losses associated with ENP’s interest rate swaps from accumulated other comprehensive loss to interest expense.

Tabular Disclosures of Fair Value Measurements

     The following table summarizes the fair value of EAC’s derivative contracts as of the dates indicated (in thousands):

	Asset Derivatives						Liability Derivatives
	September 30, 2009			December 31, 2008			September 30, 2009			December 31, 2008
	Balance Sheet	Fair		Balance Sheet	Fair		Balance Sheet			Balance Sheet
	Location	Value		Location	Value		Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments under SFAS 133 (ASC 815)
Commodity derivative contracts	Derivatives - current	$	51,974	Derivatives - current	$	349,344	Derivatives - current	$	16,532	Derivatives - current	$	—
Commodity derivative contracts	Derivatives - noncurrent		47,694	Derivatives - noncurrent		38,497	Derivatives - noncurrent		12,698	Derivatives - noncurrent		229
Total derivatives not designated as hedging instruments under SFAS 133 (ASC 815)		$	99,668		$	387,841		$	29,230		$	229
Derivatives designated as hedging instruments under SFAS 133 (ASC 815)
Interest rate swaps	Derivatives - current	$	—	Derivatives - current	$	—	Derivatives - current	$	3,470	Derivatives - current	$	1,297
Interest rate swaps	Derivatives - noncurrent		—	Derivatives - noncurrent		—	Derivatives - noncurrent		680	Derivatives-noncurrent		3,262
Total derivatives designated as hedging instruments under SFAS 133 (ASC 815)		$	—		$	—		$	4,150		$	4,559
Total derivatives		$	99,668		$	387,841		$	33,380		$	4,788

     The following table summarizes the effect of derivative instruments not designated as hedges under SFAS 133 (ASC 815) on the Consolidated Statements of Operations for the periods indicated (in thousands):

		Amount of Loss (Gain) Recognized In Income
Derivatives Not Designated as	Location of Loss	Three Months Ended September 30,						Nine Months Ended September 30,
Hedges Under SFAS 133 (ASC 815)	Recognized In Income	2009			2008			2009			2008
Commodity derivative contracts	Derivative fair value loss (gain)	$	(13,274	)	$	(239,429	)	$	(725	)	$	82,442

15

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following tables summarize the effect of derivative instruments designated as hedges under SFAS 133 (ASC 815) on the Consolidated Statements of Operations for the periods indicated (in thousands):

						Amount of Loss
	Amount of Loss					Reclassified from					Amount of Loss (Gain)
	Recognized in Accumulated OCI				Location of Loss	Accumulated OCI into					Recognized In Income
	(Effective Portion)				(Gain) Reclassified	Income (Effective Portion)					as Ineffective
Derivatives Designated as	Three months ended				from Accumulated	Three months ended				Location of Loss (Gain)	Three months ended
Hedges Under	September 30,				OCI into Income	September 30,				Recognized in Income	September 30,
SFAS 133 (ASC 815)	2009		2008		(Effective Portion)	2009		2008		as Ineffective	2009		2008
Interest rate swaps	$	725	$	381	Interest expense	$	983	$	117	Derivative fair value loss (gain)	$	18	$	(6	)
						Amount of Loss
	Amount of Loss					Reclassified from					Amount of Gain
	Recognized in Accumulated OCI				Location of Loss	Accumulated OCI into					Recognized In Income
	(Effective Portion)				(Gain) Reclassified	Income (Effective Portion)					as Ineffective
Derivatives Designated as	Nine months ended				from Accumulated	Nine months ended				Location of Gain	Nine months ended
Hedges Under	September 30,				OCI into Income	September 30,				Recognized in Income	September 30,
SFAS 133 (ASC 815)	2009		2008		(Effective Portion)	2009		2008		as Ineffective	2009		2008
Interest rate swaps	$	2,214	$	1,142	Interest expense	$	2,786	$	224	Derivative fair value gain	$	16	$	349
Commodity derivative contracts		—		—	Oil and natural gas revenues		—		2,857			—		—
Total	$	2,214	$	1,142		$	2,786	$	3,081		$	16	$	349

Fair Value Hierarchy

     As discussed in “Note 2. Basis of Presentation,” EAC adopted FSP FAS 157-2 (ASC 820-10) on January 1, 2009 and SFAS 157 (ASC 820-10) on January 1, 2008. SFAS 157 (ASC 820-10) establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy defined by SFAS 157 (ASC 820-10) are as follows:

• Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities.

• Level 2 — Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.

• Level 3 — Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.

     EAC’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the financial assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions were used to estimate the fair values of EAC’s assets and liabilities that are accounted for at fair value on a recurring basis:

• Level 2 — Fair values of oil and natural gas swaps were estimated using a combined income-based and market-based valuation methodology based upon forward commodity price curves obtained from independent pricing services reflecting broker market quotes. Fair values of interest rate swaps were estimated using a combined income-based and market-based valuation methodology based upon credit ratings and forward interest rate yield curves obtained from independent pricing services reflecting broker market quotes.

• Level 3 — EAC’s oil and natural gas calls, puts, and short puts are average value options, which are not exchange-traded contracts. Settlement is determined by the average underlying price over a predetermined period of time. EAC uses both observable and unobservable inputs in a Black-Scholes valuation model to determine fair value. Accordingly, these derivative instruments are classified within the Level 3 valuation hierarchy. The observable inputs of EAC’s valuation model include: (1) current market and contractual prices for the underlying instruments; (2) quoted forward prices for oil and natural gas; and (3) interest rates, such as a LIBOR curve for a term similar to the commodity derivative contract. The unobservable input of EAC’s valuation model is volatility. The implied volatilities for EAC’s calls, puts, and short puts with comparable strike prices are based on the settlement values from certain exchange-traded contracts. The implied volatilities for calls, puts, and short puts where there are no exchange-traded contracts with the same strike price are extrapolated from exchange-traded implied volatilities by an independent party.

     EAC adjusts the valuations from the valuation model for nonperformance risk, using management’s estimate of the counterparty’s credit quality for asset positions and EAC’s credit quality for liability positions. EAC uses the multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps. EAC considers the impact of netting and offset

16

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

provisions in the agreements on counterparty credit risk, including whether the position with the counterparty is a net asset or net liability. There have been no changes in the valuation techniques used to measure the fair value of EAC’s oil and natural gas calls, puts, or short puts during 2009.

     The following table sets forth EAC’s assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2009:

				Fair Value Measurements at Reporting Date Using
				Quoted Prices in
				Active Markets for		Significant Other			Significant
	Asset (Liability) at			Identical Assets		Observable Inputs			Unobservable Inputs
Description	September 30, 2009			(Level 1)		(Level 2)			(Level 3)
	(in thousands)
Oil derivative contracts — swaps	$	(7,860	)	$	—	$	(7,860	)	$	—
Oil derivative contracts — floors and caps		67,282			—		—			67,282
Natural gas derivative contracts — swaps		(387	)		—		(387	)		—
Natural gas derivative contracts — floors and caps		11,404			—		—			11,404
Interest rate swaps		(4,150	)		—		(4,150	)		—
Total	$	66,289		$	—	$	(12,397	)	$	78,686

     The following table summarizes the changes in the fair value of EAC’s Level 3 assets and liabilities for the nine months ended September 30, 2009:

	Fair Value Measurements Using Significant
	Unobservable Inputs (Level 3)
	Oil Derivative			Natural Gas
	Contracts -			Derivative Contracts -
	Floors and Caps			Floors and Caps			Total
	(in thousands)
Balance at January 1, 2009	$	337,335		$	12,741		$	350,076
Total gains (losses):
Included in earnings		30,329			20,882			51,211
Purchases, issuances, and settlements		(300,382	)		(22,219	)		(322,601	)
Balance at September 30, 2009	$	67,282		$	11,404		$	78,686
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	30,329		$	20,882		$	51,211

     Since EAC does not use hedge accounting for its commodity derivative contracts, all gains and losses on its Level 3 assets and liabilities are included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.

     All fair values have been adjusted for nonperformance risk resulting in a reduction of the net commodity derivative asset of approximately $0.5 million as of September 30, 2009. For commodity derivative contracts which are in an asset position, EAC uses the counterparty’s credit default swap rating. For commodity derivative contracts which are in a liability position, EAC uses the average credit default swap rating of its peer companies as EAC does not have its own credit default swap rating.

     EAC’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the nonfinancial assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions were used to estimate the fair values of EAC’s assets and liabilities that are accounted for at fair value on a nonrecurring basis:

• Level 3 — Fair values of asset retirement obligations are determined using discounted cash flow methodologies based on inputs, such as plugging costs and reserve lives, which are not readily available in public markets. See “Note 7. Asset Retirement Obligations” for additional discussion of EAC’s asset retirement obligations.

17

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following table sets forth EAC’s assets and liabilities that were measured at fair value on a nonrecurring basis as of September 30, 2009:

			Fair Value Measurements Using
			Quoted Prices in
			Active Markets for		Significant Other		Significant
	Liability at		Identical Assets		Observable Inputs		Unobservable Inputs		Total Gains
Description	September 30, 2009		(Level 1)		(Level 2)		(Level 3)		(Losses)
	(in thousands)
Asset retirement obligations	$	3,775	$	—	$	—	$	3,775	$	—

Note 7. Asset Retirement Obligations

     Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in EAC’s asset retirement obligations for the nine months ended September 30, 2009 (in thousands):

Future abandonment liability at January 1, 2009	$	49,569
Wells drilled		283
Acquisition of properties		3,492
Disposition of properties		(220	)
Accretion of discount		1,761
Plugging and abandonment costs incurred		(1,223	)
Revision of previous estimates		49
Future abandonment liability at September 30, 2009	$	53,711

     As of September 30, 2009, $51.7 million of EAC’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $2.0 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheets. Approximately $4.7 million of the future abandonment liability represents the estimated cost for decommissioning ENP’s Elk Basin natural gas processing plant.

     As of September 30, 2009 and December 31, 2008, EAC held $9.3 million and $9.2 million, respectively, in escrow, which is to be released only for reimbursement of actual plugging and abandonment costs incurred on its Bell Creek properties. These amounts are included in “Other assets” in the accompanying Consolidated Balance Sheets.

Note 8. Long-Term Debt

     Long-term debt consisted of the following as of the dates indicated:

	Maturity		September 30,		December 31,
	Date		2009		2008
			(in thousands)
Revolving credit facilities		3/7/2012	$	440,000	$	725,000
6.25% Senior Subordinated Notes		4/15/2014		150,000		150,000
6.0% Senior Subordinated Notes, net of unamortized discount of $3,579 and $3,960, respectively		7/15/2015		296,421		296,040
9.5% Senior Subordinated Notes, net of unamortized discount of $16,772 and zero, respectively		5/1/2016		208,228		—
7.25% Senior Subordinated Notes, net of unamortized discount of $1,153 and $1,229, respectively		12/1/2017		148,847		148,771
Total			$	1,243,496	$	1,319,811

18

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Encore Acquisition Company Credit Agreement

     EAC is a party to a five-year amended and restated credit agreement dated March 7, 2007 (as amended, the “EAC Credit Agreement”). The EAC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, EAC amended the EAC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the EAC Credit Agreement. The EAC Credit Agreement provides for revolving credit loans to be made to EAC from time to time and letters of credit to be issued from time to time for the account of EAC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the EAC Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. In March 2009, the borrowing base of the EAC Credit Agreement was reaffirmed at $1.1 billion before a reduction of $200 million solely as a result of the monetization of certain of EAC’s 2009 oil derivative contracts during the first quarter of 2009. In April 2009, the borrowing base of the EAC Credit Agreement was reduced by $75 million as a result of EAC’s issuance of senior subordinated notes. As of September 30, 2009, the borrowing base was $825 million and there were $180 million of outstanding borrowings, $0.3 million of outstanding letters of credit, and $644.7 million of borrowing capacity under the EAC Credit Agreement.

     EAC incurs a commitment fee on the unused portion of the EAC Credit Agreement determined based on the ratio of outstanding borrowings under the EAC Credit Agreement to the borrowing base in effect on such date. The following table summarizes the commitment fee percentage under the EAC Credit Agreement:

	Commitment
Ratio of Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .90 to 1		0.375	%
Greater than or equal to .90 to 1		0.500	%

     Obligations under the EAC Credit Agreement are secured by a first-priority security interest in substantially all of EAC’s restricted subsidiaries’ proved oil and natural gas reserves and in EAC’s equity interests in its restricted subsidiaries. In addition, obligations under the EAC Credit Agreement are guaranteed by EAC’s restricted subsidiaries.

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

	Applicable Margin for			Applicable Margin for
Ratio of Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.750	%		0.500	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.000	%		0.750	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.250	%		1.000	%
Greater than or equal to .90 to 1		2.500	%		1.250	%

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by EAC) is the rate equal to the British Bankers Association LIBOR for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0 percent.

     Any outstanding letters of credit reduce the availability under the EAC Credit Agreement. Borrowings under the EAC Credit Agreement may be repaid from time to time without penalty.

     The EAC Credit Agreement contains covenants including, among others, the following:

• 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;

19

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

• a restriction on creating liens on the assets of EAC 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 EAC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0; and

• a requirement that EAC maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0.

     As of September 30, 2009, EAC was in compliance with all covenants of the EAC Credit Agreement.

     The EAC Credit Agreement contains customary events of default including, among others, the following:

• failure to pay principal on any loan when due;

• failure to pay accrued interest on any loan or fees when due and such failure continues for more than three days;

• failure to observe or perform covenants and agreements contained in the EAC Credit Agreement, subject in some cases to a 30-day grace period after discovery or notice of such failure;

• failure to make a payment when due on any other debt in a principal amount equal to or greater than $15 million or any other event or condition occurs which results in the acceleration of such debt or entitles the holder of such debt to accelerate the maturity of such debt;

• the commencement of liquidation, reorganization, or similar proceedings with respect to EAC or any guarantor under bankruptcy or insolvency law, or the failure of EAC or any guarantor generally to pay its debts as they become due;

• the entry of one or more judgments in excess of $15 million (to the extent not covered by insurance) and such judgment(s) remain unsatisfied and unstayed for 30 days;

• the occurrence of certain ERISA events involving an amount in excess of $15 million;

• there cease to exist liens covering at least 80 percent of the borrowing base properties; or

• the occurrence of a change in control.

     If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the EAC Credit Agreement to be immediately due and payable.

Encore Energy Partners Operating LLC Credit Agreement

     Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly owned subsidiary of ENP, is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “OLLC Credit Agreement”). The OLLC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, OLLC amended the OLLC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. Effective August 11, 2009, OLLC amended the OLLC Credit Agreement to, among other things, (1) increase the borrowing base from $240 million to $375 million, (2) increase the aggregate commitments of the lenders from $300 million to $475 million, and (3) increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $475 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. As of September 30, 2009, the borrowing base was $375 million and there were $260 million of outstanding borrowings and $115 million of borrowing capacity under the OLLC Credit Agreement.

     OLLC incurs a commitment fee of 0.5 percent on the unused portion of the OLLC Credit Agreement.

     Obligations under the OLLC Credit Agreement are secured by a first-priority security interest in substantially all of OLLC’s proved oil and natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition, Obligations under

20

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

the OLLC Credit Agreement are guaranteed by ENP and OLLC’s restricted subsidiaries. Obligations under the OLLC Credit Agreement are non-recourse to EAC and its restricted subsidiaries.

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

	Applicable Margin for			Applicable Margin for
Ratio of Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		2.250	%		1.250	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.500	%		1.500	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.750	%		1.750	%
Greater than or equal to .90 to 1		3.000	%		2.000	%

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate equal to the British Bankers Association LIBOR for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0 percent.

     Any outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.

     The OLLC Credit Agreement contains covenants including, among others, the following:

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

• a prohibition against purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;

• a restriction on creating liens on the assets of ENP, OLLC, and OLLC’s restricted subsidiaries, subject to permitted exceptions;

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

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

• a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

• a requirement that ENP and OLLC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0;

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0; and

• a requirement that ENP and OLLC maintain a ratio of consolidated funded debt to consolidated adjusted EBITDA of not more than 3.5 to 1.0.

     As of September 30, 2009, ENP and OLLC were in compliance with all covenants of the OLLC Credit Agreement.

     The OLLC Credit Agreement contains customary events of default including, among others, the following:

• failure to pay principal on any loan when due;

• failure to pay accrued interest on any loan or fees when due and such failure continues for more than three days;

• failure to observe or perform covenants and agreements contained in the OLLC Credit Agreement, subject in some cases to a 30-day grace period after discovery or notice of such failure;

• failure to make a payment when due on any other debt in a principal amount equal to or greater than $3 million or any other event or condition occurs which results in the acceleration of such debt or entitles the holder of such debt to accelerate the maturity of such debt;

• the commencement of liquidation, reorganization, or similar proceedings with respect to OLLC or any guarantor under bankruptcy or insolvency law, or the failure of OLLC or any guarantor generally to pay its debts as they become due;

21

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

• the entry of one or more judgments in excess of $3 million (to the extent not covered by insurance) and such judgment(s) remain unsatisfied and unstayed for 30 days;

• the occurrence of certain ERISA events involving an amount in excess of $3 million;

• there cease to exist liens covering at least 80 percent of the borrowing base properties; or

• the occurrence of a change in control.

     If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately due and payable.

9.50% Senior Subordinated Notes due 2016 (the “9.5% Notes”)

     In April 2009, EAC issued $225 million of its 9.5% Notes at 92.228 percent of par value. EAC used the net proceeds of approximately $202.5 million, after deducting the underwriters’ discounts and commissions of $4.5 million, in the aggregate, and offering expenses of approximately $0.6 million. EAC used the net proceeds to reduce outstanding borrowings under the EAC Credit Agreement. Interest on the 9.5% Notes is due semi-annually on May 1 and November 1, beginning November 1, 2009. The 9.5% Notes mature on May 1, 2016.

Note 9. Stockholders’ Equity

Stock Repurchase Program

     In October 2008, EAC announced that its Board of Directors (the “Board”) approved a share repurchase program authorizing EAC to repurchase up to $40 million of its common stock. As of September 30, 2009, EAC had repurchased and retired 620,265 shares of its outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. During the three and nine months ended September 30, 2009, EAC did not repurchase any shares of its outstanding common stock under the share repurchase program. As of September 30, 2009, approximately $22.8 million of EAC’s common stock remained authorized for repurchase.

Stock Option Exercises and Restricted Stock Vestings

     During the three and nine months ended September 30, 2009, certain employees exercised 1,621 options and 23,105 options, respectively, for which EAC received proceeds of approximately $49 thousand and $0.5 million, respectively. During the nine months ended September 30, 2009, certain employees elected to satisfy minimum tax withholding obligations in conjunction with the vesting of restricted stock by directing EAC to withhold 111,819 shares of common stock, which are accounted for as treasury stock until they are formally retired.

Issuance of EAC Common Stock

     In September 2009, EAC issued 2,750,000 shares of common stock under its shelf registration statement at a price to the public of $37.40 per common share. EAC used the net proceeds of approximately $100.7 million, after deducting the underwriters’ discounts and commissions of $2.0 million, in the aggregate, and offering costs of approximately $0.1 million, to reduce outstanding borrowings under the EAC Credit Facility.

Issuance of ENP Common Units

     In May 2009, ENP issued 2,760,000 common units at a price to the public of $15.60 per common unit. As a result, EAC’s partnership percentage of ENP’s common units decreased from approximately 63 percent to approximately 58 percent. Additionally, EAC increased “Noncontrolling interest” and “Additional paid-in capital” on the accompanying Consolidated Balance Sheets by $31.2 million and $9.3 million, respectively, to recognize the net proceeds from the issuance of ENP’s common units.

     In July 2009, ENP issued 9,430,000 common units under its shelf registration statement at a price to the public of $14.30 per common unit. As a result, EAC’s partnership percentage of ENP’s common units decreased from approximately 58 percent to its current partnership of approximately 46 percent. Additionally, EAC increased “Noncontrolling interest” and “Additional paid-in capital” on the accompanying Consolidated Balance Sheets by $109.0 million and $20.4 million, respectively, to recognize the net proceeds from the issuance of ENP’s common units.

     The following table summarizes EAC’s change of ownership of ENP since December 31, 2008:

	Common Units Owned						EAC %			GP Units Owned		EAC % of
Date	EAC		Others		Total		of Common Units			by EAC		All Units
12/31/2008		20,924,055		12,153,555		33,077,610		63.3	%		504,851		63.8	%
Equity Offering		—		2,760,000		2,760,000
5/22/2009		20,924,055		14,913,555		35,837,610		58.4	%		504,851		59.0	%
Equity Offering		—		9,430,000		9,430,000
7/22/2009		20,924,055		24,343,555		45,267,610		46.2	%		504,851		46.8	%

22

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 10. Income Taxes

     The components of income tax benefit (provision) were as follows for the periods indicated:

	Nine months ended
	September 30,
	2009			2008
	(in thousands)
Federal:
Current	$	2,683		$	(6,693	)
Deferred		25,117			(104,436	)
Total federal		27,800			(111,129	)
State, net of federal benefit:
Current		(3,332	)		(2,249	)
Deferred		786			(5,217	)
Total state		(2,546	)		(7,466	)
Income tax benefit (provision)	$	25,254		$	(118,595	)

     The following table reconciles income tax benefit (provision) with income tax at the Federal statutory rate for the periods indicated:

	Nine months ended
	September 30,
	2009			2008
	(in thousands)
Income (loss) before income taxes	$	(94,453	)	$	336,600
Income taxes at the Federal statutory rate	$	33,059		$	(117,810	)
State income taxes, net of federal benefit		(2,546	)		(7,466	)
Tax on income attributable to noncontrolling interest		(3,384	)		5,669
2008 provision to return adjustment		(1,735	)		872
Permanent and other		(140	)		140
Income tax benefit (provision)	$	25,254		$	(118,595	)

     As of September 30, 2009 and December 31, 2008, all of EAC’s tax positions met the “more-likely-than-not” threshold prescribed by FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” (ASC 740, 805-740, and 835-10). As a result, no additional tax expense, interest, or penalties have been accrued. EAC includes interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its Consolidated Statements of Operations. During the nine months ended September 30, 2009 and 2008, EAC recorded only a nominal amount of interest and penalties on certain tax positions.

Note 11. Earnings Per Share

     As discussed in “Note 2. Basis of Presentation,” EAC adopted FSP EITF 03-6-1 (ASC 260-10) on January 1, 2009, and all periods prior to adoption have been restated to calculate EPS in accordance with this pronouncement. Under the two-class method of calculating EPS, earnings are allocated to participating securities as if all earnings for the period had been distributed. A participating security is any security that contains nonforfeitable rights to dividends or dividend equivalents paid to common stockholders. For purposes of calculating EPS, unvested restricted stock awards are considered participating securities. EPS is calculated by dividing the common stockholders’ interest in net income (loss), after deducting the interests of participating securities, by the weighted average shares outstanding. The adoption of EITF 03-6-1 (ASC 260-10) reduced EAC’s basic EPS by $0.07 for the three and nine months ended September 30, 2008 and reduced EAC’s diluted EPS by $0.03 for the three and nine months ended September 30, 2008.

23

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following table reflects the allocation of net income (loss) to EAC’s common stockholders and EPS computations for the periods indicated:

	Three months ended						Nine months ended
	September 30,						September 30,
	2009			2008			2009			2008
	(in thousands, except per share amounts)
Basic Earnings Per Share
Numerator:
Undistributed net income (loss) — attributable to EAC	$	(4,999	)	$	206,307		$	(59,530	)	$	201,807
Participation rights of unvested restricted stock in undistributed earnings (a)		—			(3,737	)		—			(3,642	)
Basic undistributed net income (loss) — attributable to EAC common shares	$	(4,999	)	$	202,570		$	(59,530	)	$	198,165
Denominator:
Basic weighted average shares outstanding		52,349			52,258			51,964			52,466
Basic EPS — attributable to EAC common shares	$	(0.10	)	$	3.88		$	(1.15	)	$	3.78
Diluted Earnings Per Share
Numerator:
Basic undistributed net income (loss) — attributable to EAC common shares	$	(4,999	)	$	206,307		$	(59,530	)	$	201,807
Participation rights of unvested restricted stock in undistributed earnings (a)		—			(3,631	)		—			(3,535	)
Incremental noncontrolling interest from assumed conversion of ENP MIUs		—			(3,143	)		—			(3,461	)
Basic undistributed net income (loss) — attributable to EAC common shares	$	(4,999	)	$	199,533		$	(59,530	)	$	194,811
Denominator:
Basic weighted average shares outstanding		52,349			52,258			51,964			52,466
Effect of dilutive options (b)		—			721			—			668
Diluted weighted average shares outstanding		52,349			52,979			51,964			53,134
Diluted EPS — attributable to EAC common shares	$	(0.10	)	$	3.77		$	(1.15	)	$	3.67

(a)	Unvested restricted stock has no contractual obligation to absorb losses of EAC. Therefore, for the three and nine months ended September 30, 2009, 923,122 shares of restricted stock were outstanding but excluded from the EPS calculations because their effect would have been antidilutive. Please read “Note 12. Incentive Stock Plans” for additional discussion of restricted stock.
(b)	For the three and nine months ended September 30, 2009, options to purchase 1,730,762 shares of common stock were outstanding but excluded from the EPS calculations because their effect would have been antidilutive. Please read “Note 12. Incentive Stock Plans” for additional discussion of stock options.

Note 12. Incentive Stock Plans

     In May 2008, EAC’s stockholders approved the 2008 Incentive Stock Plan (the “2008 Plan”). No additional awards will be granted under EAC’s 2000 Incentive Stock Plan (the “2000 Plan”) and any outstanding awards granted under the 2000 Plan will remain outstanding in accordance with their terms. The purpose of the 2008 Plan is to attract, motivate, and retain selected employees of EAC and to provide EAC with the ability to provide incentives more directly linked to the profitability of the business and increases in stockholder value. All directors and full-time regular employees of EAC and its subsidiaries and affiliates are eligible to be granted awards under the 2008 Plan. The 2008 Plan provides for the granting of cash awards, incentive stock options, non-qualified stock options, restricted stock, and stock appreciation rights at the discretion of the Compensation Committee of the Board. The Board also has a Special Stock Award Committee whose sole member is Jon S. Brumley, EAC’s Chief Executive Officer and President. The Special Stock Award Committee may grant up to 25,000 shares of restricted stock on an annual basis to non-executive employees at its discretion.

     The total number of shares of EAC’s common stock reserved for issuance pursuant to the 2008 Plan is 2,400,000, of which 1,600,000 are available for grants of “full value” stock awards, such as restricted stock or stock units. As of September 30, 2009, there were 1,715,900 shares available for issuance under the 2008 Plan, of which 1,181,143 are available for grants of “full value” stock awards. Shares delivered or withheld for payment of the exercise price of an option, shares withheld for payment of tax withholding, shares subject to options or other awards that expire or are forfeited, and restricted shares that are forfeited will again become available for issuance under the 2008 Plan.

     The 2008 Plan contains the following individual limits:

• an employee may not be granted awards covering or relating to more than 300,000 shares of common stock during any calendar year;

24

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

• a non-employee director may not be granted awards covering or relating to more than 20,000 shares of common stock during any calendar year; and

• an employee may not receive awards consisting of cash (including cash awards that are granted as performance awards) in respect of any calendar year having grant date fair value in excess of $5.0 million.

     During the nine months ended September 30, 2009 and 2008, EAC recorded non-cash stock-based compensation expense related to its incentive stock plans of $9.5 million and $6.5 million, respectively, which was allocated to LOE and general and administrative expense in the accompanying Consolidated Statements of Operations based on the allocation of the respective employees’ cash compensation. During the nine months ended September 30, 2009 and 2008, EAC also capitalized $1.8 million and $1.7 million, respectively, of non-cash stock-based compensation expense related to its incentive stock plans as a component of “Proved properties” in the accompanying Consolidated Balance Sheets. During the nine months ended September 30, 2009 and 2008, EAC recognized income tax benefits related to its incentive stock plans of $3.5 million and $2.4 million, respectively.

     Please read “Note 17. ENP” for a discussion of ENP’s unit-based compensation plans.

Stock Options

     All options have a strike price equal to the fair market value of EAC’s common stock on the grant date, have a ten-year life, and vest over a three-year period. The fair value of options granted during the nine months ended September 30, 2009 and 2008 was estimated on the grant date using a Black-Scholes option valuation model based on the following assumptions:

	Nine months ended September 30,
	2009			2008
Expected volatility		51.9	%		33.7	%
Expected dividend yield		0.0	%		0.0	%
Expected term (in years)		6.25			6.25
Risk-free interest rate		2.1	%		3.0	%
Weighted-average fair value per share	$	15.81		$	13.15

     The expected volatility was based on the historical volatility of EAC’s common stock for a period of time commensurate with the expected term of the options. EAC determined the expected term of the options based on an analysis of historical exercise and forfeiture behavior as well as expectations about future behavior. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the grant date for a period of time commensurate with the expected term of the options.

     The following table summarizes the changes in EAC’s outstanding options for the nine months ended September 30, 2009:

						Weighted
				Weighted		Average		Aggregate
	Number of			Average		Remaining		Intrinsic
	Options			Strike Price		Contractual Term		Value
								(in thousands)
Outstanding at January 1, 2009		1,497,413		$	18.02
Granted		269,417			30.55
Forfeited or expired		(12,963	)		30.91
Exercised		(23,105	)		20.17
Outstanding at September 30, 2009		1,730,762			19.85		5.1	$	30,377
Exercisable at September 30, 2009		1,298,056			16.23		3.9		27,477

     The total intrinsic value of options exercised during the nine months ended September 30, 2009 and 2008 was $0.3 million and $1.6 million, respectively. During the nine months ended September 30, 2009 and 2008, EAC received proceeds from the exercise of stock options of $0.5 million and $0.5 million, respectively. During the nine months ended September 30, 2009 and 2008, EAC recognized income tax benefits related to stock options of $38 thousand and $0.5 million, respectively. At September 30, 2009, EAC had $2.4 million of total unrecognized compensation cost related to unvested stock options, which is expected to be recognized over a weighted average period of 2.1 years.

25

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Restricted Stock

     Restricted stock awards vest over varying periods from one to five years, subject to performance-based vesting for certain members of senior management. During the nine months ended September 30, 2009, EAC recognized expense related to restricted stock of $7.3 million and recognized an income tax provision related to the vesting of restricted stock of $0.4 million. During the nine months ended September 30, 2008, EAC recognized expense related to restricted stock of $5.5 million and recognized an income tax benefit related to the vesting of restricted stock of $0.8 million. The following table summarizes the changes in EAC’s unvested restricted stock awards for the nine months ended September 30, 2009:

				Weighted
				Average
	Number of			Grant Date
	Shares			Fair Value
Outstanding at January 1, 2009		938,407		$	30.67
Granted		412,449			30.52
Vested		(408,478	)		29.25
Forfeited		(19,256	)		30.26
Outstanding at June 30, 2009		923,122			31.20

     As of September 30, 2009, there were 704,102 shares of unvested restricted stock, 188,837 shares of which were granted during 2009, in which the vesting is dependent only on the passage of time and continued employment. Additionally, as of September 30, 2009, there were 219,020 shares of unvested restricted stock, all of which were granted during 2009, in which the vesting is dependent not only on the passage of time and continued employment, but also on the achievement of certain performance measures.

     None of EAC’s unvested restricted stock awards are subject to variable accounting. During the nine months ended September 30, 2009 and 2008, there were 408,478 shares and 235,086 shares, respectively, of restricted stock that vested for which certain employees elected to satisfy minimum tax withholding obligations related thereto by directing EAC to withhold 111,819 shares and 28,193 shares of common stock, respectively. EAC accounts for these shares as treasury stock until they are formally retired and have been reflected as such in the accompanying consolidated financial statements. The total fair value of restricted stock that vested during the nine months ended September 30, 2009 and 2008 was $11.0 million and $8.2 million, respectively. As of September 30, 2009, EAC had $10.6 million of total unrecognized compensation cost related to unvested restricted stock, which is expected to be recognized over a weighted average period of 2.9 years.

Note 13. Comprehensive Income (Loss)

     The components of comprehensive income (loss), net of tax, were as follows for the periods indicated:

	Three months ended						Nine months ended
	September 30,						September 30,
	2009			2008			2009			2008
	(in thousands)
Consolidated net income (loss)	$	(1,776	)	$	237,393		$	(69,199	)	$	218,005
Amortization of deferred loss on commodity derivative contracts		—			—			—			1,786
Change in deferred hedge loss on interest rate swaps		(343	)		(264	)		89			153
Consolidated comprehensive income (loss)		(2,119	)		237,129			(69,110	)		219,944
Less: comprehensive loss (income) attributable to noncontrolling interest		(2,630	)		(30,901	)		10,144			(16,330	)
Comprehensive income (loss) attributable to EAC stockholders	$	(4,749	)	$	206,228		$	(58,966	)	$	203,614

Note 14. Financial Statements of Subsidiary Guarantors

     Certain of EAC’s wholly owned subsidiaries are subsidiary guarantors of EAC’s senior subordinated notes. The subsidiary guarantees are full and unconditional, and joint and several. The subsidiary guarantors may, without restriction, transfer funds to EAC in the form of cash dividends, loans, and advances. The following Condensed Consolidating Balance Sheets as of September 30, 2009 and December 31, 2008, Condensed Consolidating Statements of Operations and Comprehensive Income (Loss) for the three and nine

26

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

months ended September 30, 2009 and 2008, and Condensed Consolidating Statements of Cash Flows for the nine months ended September 30, 2009 and 2008 present consolidating financial information for Encore Acquisition Company (the “Parent”) on a stand alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries. As of September 30, 2009, EAC’s guarantor subsidiaries were:

• EAP Properties, Inc.;

• EAP Operating, LLC;

• Encore Operating, L.P.;

• Encore Operating Louisiana, LLC;

• Greencore Pipeline Company LLC;

• Green Rock LLC; and

• Belle Aire LLC.

As of September 30, 2009, EAC’s non-guarantor subsidiaries were:

• ENP;

• OLLC;

• GP LLC;

• Encore Partners GP Holdings LLC;

• Encore Partners LP Holdings LLC;

• Encore Energy Partners Finance Corporation; and

• Encore Clear Fork Pipeline LLC.

     All intercompany investments in, loans due to/from, subsidiary equity, revenues, and expenses between the Parent, guarantor subsidiaries, and non-guarantor subsidiaries are shown prior to consolidation with the Parent and then eliminated to arrive at consolidated totals per the accompanying consolidated financial statements. Prior period amounts have not been adjusted for ENP’s acquisitions from EAC. Please read “Note 17. ENP” for a discussion of transactions with ENP.

27

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET
September 30, 2009
(in thousands)

			Guarantor			Non-Guarantor						Consolidated
	Parent		Subsidiaries			Subsidiaries			Eliminations			Total
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	3,246		$	3,437		$	—		$	6,683
Other current assets		9,522		150,710			51,369			(4,618	)		206,983
Total current assets		9,522		153,956			54,806			(4,618	)		213,666
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		—		3,295,370			851,511			—			4,146,881
Unproved properties		—		104,870			61			—			104,931
Accumulated depletion, depreciation, and amortization		—		(787,211	)		(198,138	)		—			(985,349	)
		—		2,613,029			653,434			—			3,266,463
Other property and equipment, net		—		12,087			411			—			12,498
Other assets, net		15,462		166,180			39,551			(6	)		221,187
Investment in subsidiaries		2,869,292		(3,473	)		—			(2,865,819	)		—
Total assets	$	2,894,276	$	2,941,779		$	748,202		$	(2,870,443	)	$	3,713,814
LIABILITIES AND EQUITY
Current liabilities	$	85,661	$	160,997		$	33,567		$	(4,618	)	$	275,607
Deferred taxes		431,072		9			—			(6	)		431,075
Long-term debt		983,496		—			260,000			—			1,243,496
Other liabilities		—		76,238			18,633			—			94,871
Total liabilities		1,500,229		237,244			312,200			(4,624	)		2,045,049
Commitments and contingencies (see Note 15)
Total equity		1,394,047		2,704,535			436,002			(2,865,819	)		1,668,765
Total liabilities and equity	$	2,894,276	$	2,941,779		$	748,202		$	(2,870,443	)	$	3,713,814

28

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2008
(in thousands)

			Guarantor			Non-Guarantor						Consolidated
	Parent		Subsidiaries			Subsidiaries			Eliminations			Total
ASSETS
Current assets:
Cash and cash equivalents	$	607	$	813		$	619		$	—		$	2,039
Other current assets		29,004		421,392			90,797			(2,302	)		538,891
Total current assets		29,611		422,205			91,416			(2,302	)		540,930
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		—		3,016,937			521,522			—			3,538,459
Unproved properties		—		124,272			67			—			124,339
Accumulated depletion, depreciation, and amortization		—		(670,991	)		(100,573	)		—			(771,564	)
		—		2,470,218			421,016			—			2,891,234
Other property and equipment, net		—		11,877			562			—			12,439
Other assets, net		12,846		129,482			46,264			—			188,592
Investment in subsidiaries		2,976,208		(12,865	)		—			(2,963,343	)		—
Total assets	$	3,018,665	$	3,020,917		$	559,258		$	(2,965,645	)	$	3,633,195
LIABILITIES AND EQUITY
Current liabilities	$	118,089	$	215,640		$	20,825		$	(2,302	)	$	352,252
Deferred taxes		416,637		—			278			—			416,915
Long-term debt		1,169,811		—			150,000			—			1,319,811
Other liabilities		—		48,000			12,969			—			60,969
Total liabilities		1,704,537		263,640			184,072			(2,302	)		2,149,947
Commitments and contingencies (see Note 15)
Total equity		1,314,128		2,757,277			375,186			(2,963,343	)		1,483,248
Total liabilities and equity	$	3,018,665	$	3,020,917		$	559,258		$	(2,965,645	)	$	3,633,195

29

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended September 30, 2009
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	117,669		$	35,280		$	—		$	152,949
Natural gas		—			26,518			5,650			—			32,168
Marketing		—			785			102			—			887
Total revenues		—			144,972			41,032			—			186,004
Expenses:
Production:
Lease operating		—			29,124			9,017			—			38,141
Production, ad valorem, and severance taxes		—			14,529			4,693			—			19,222
Depletion, depreciation, and amortization		—			58,169			14,458			—			72,627
Exploration		—			13,634			3,034			—			16,668
General and administrative		3,881			8,011			2,912			(1,534	)		13,270
Marketing		—			304			54			—			358
Derivative fair value gain		—			(8,434	)		(4,822	)		—			(13,256	)
Other operating		48			6,890			1,303			—			8,241
Total expenses		3,929			122,227			30,649			(1,534	)		155,271
Operating income (loss)		(3,929	)		22,745			10,383			1,534			30,733
Other income (expenses):
Interest		(18,936	)		—			(2,984	)		—			(21,920	)
Equity income from subsidiaries		29,184			2,162			—			(31,346	)		—
Other		(91	)		2,202			23			(1,534	)		600
Total other expenses		10,157			4,364			(2,961	)		(32,880	)		(21,320	)
Income (loss) before income taxes		6,228			27,109			7,422			(31,346	)		9,413
Income tax benefit (provision)		(11,228	)		1			38			—			(11,189	)
Consolidated net income (loss)		(5,000	)		27,110			7,460			(31,346	)		(1,776	)
Change in deferred hedge loss on interest rate swaps, net of tax		(37	)		—			(306	)		—			(343	)
Consolidated comprehensive income (loss)	$	(5,037	)	$	27,110		$	7,154		$	(31,346	)	$	(2,119	)

30

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME
For the Three Months Ended September 30, 2008
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	224,101		$	44,442		$	—		$	268,543
Natural gas		—			56,956			9,816			—			66,772
Marketing		—			718			1,445			—			2,163
Total revenues		—			281,775			55,703			—			337,478
Expenses:
Production:
Lease operating		—			40,124			8,842			—			48,966
Production, ad valorem, and severance taxes		—			27,609			5,741			—			33,350
Depletion, depreciation, and amortization		—			49,481			9,064			—			58,545
Impairment of long-lived assets		—			26,292			—			—			26,292
Exploration		—			13,335			46			—			13,381
General and administrative		4,723			9,050			2,600			(1,070	)		15,303
Marketing		—			539			1,316			—			1,855
Derivative fair value gain		—			(168,992	)		(70,443	)		—			(239,435	)
Other operating		41			3,688			344			—			4,073
Total expenses		4,764			1,126			(42,490	)		(1,070	)		(37,670	)
Operating income (loss)		(4,764	)		280,649			98,193			1,070			375,148
Other income (expenses):
Interest		(16,357	)		—			(1,767	)		—			(18,124	)
Equity income from subsidiaries		347,114			32,564			—			(379,678	)		—
Other		78			2,535			10			(1,070	)		1,553
Total other income (expenses)		330,835			35,099			(1,757	)		(380,748	)		(16,571	)
Income before income taxes		326,071			315,748			96,436			(379,678	)		358,577
Income tax benefit (provision)		(120,943	)		81			(322	)		—			(121,184	)
Consolidated net income		205,128			315,829			96,114			(379,678	)		237,393
Change in deferred hedge gain on interest rate swaps, net of tax		150			—			(414	)		—			(264	)
Consolidated comprehensive income	$	205,278		$	315,829		$	95,700		$	(379,678	)	$	237,129

31

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE LOSS
For the Nine Months Ended September 30, 2009
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	286,482		$	88,433		$	—		$	374,915
Natural gas		—			71,765			15,143			—			86,908
Marketing		—			1,627			381			—			2,008
Total revenues		—			359,874			103,957			—			463,831
Expenses:
Production:
Lease operating		—			91,697			31,120			—			122,817
Production, ad valorem, and severance taxes		—			36,488			11,586			—			48,074
Depletion, depreciation, and amortization		—			173,677			43,684			—			217,361
Exploration		—			40,727			3,074			—			43,801
General and administrative		13,595			21,860			9,138			(3,850	)		40,743
Marketing		—			1,367			245			—			1,612
Derivative fair value loss (gain)		—			(22,452	)		21,711			—			(741	)
Other operating		131			26,558			2,730			—			29,419
Total expenses		13,726			369,922			123,288			(3,850	)		503,086
Operating loss		(13,726	)		(10,048	)		(19,331	)		3,850			(39,255	)
Other income (expenses):
Interest		(49,458	)		—			(7,551	)		—			(57,009	)
Equity loss from subsidiaries		(21,460	)		(8,845	)		—			30,305			—
Other		(187	)		5,819			29			(3,850	)		1,811
Total other expenses		(71,105	)		(3,026	)		(7,522	)		26,455			(55,198	)
Loss before income taxes		(84,831	)		(13,074	)		(26,853	)		30,305			(94,453	)
Income tax benefit (provision)		25,299			118			(163	)		—			25,254
Consolidated net loss		(59,532	)		(12,956	)		(27,016	)		30,305			(69,199	)
Change in deferred hedge loss on interest rate swaps, net of tax		(253	)		—			342			—			89
Consolidated comprehensive loss	$	(59,785	)	$	(12,956	)	$	(26,674	)	$	30,305		$	(69,110	)

32

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME
For the Nine Months Ended September 30, 2008
(in thousands)

				Guarantor		Non-Guarantor						Consolidated
	Parent			Subsidiaries		Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	647,223	$	128,778		$	—		$	776,001
Natural gas		—			154,347		28,626			—			182,973
Marketing		—			3,533		5,207			—			8,740
Total revenues		—			805,103		162,611			—			967,714
Expenses:
Production:
Lease operating		—			108,191		21,822			—			130,013
Production, ad valorem, and severance taxes		—			79,524		16,321			—			95,845
Depletion, depreciation, and amortization		—			131,715		27,399			—			159,114
Impairment of long-lived assets		—			26,292		—			—			26,292
Exploration		—			30,349		113			—			30,462
General and administrative		11,668			19,630		8,455			(3,204	)		36,549
Marketing		—			4,044		5,318			—			9,362
Derivative fair value loss		—			60,521		21,572			—			82,093
Other operating		124			8,655		1,026			—			9,805
Total expenses		11,792			468,921		102,026			(3,204	)		579,535
Operating income (loss)		(11,792	)		336,182		60,585			3,204			388,179
Other income (expenses):
Interest		(49,353	)		—		(5,316	)		—			(54,669	)
Equity income from subsidiaries		378,946			18,724		—			(397,670	)		—
Other		30			6,172		92			(3,204	)		3,090
Total other income (expenses)		329,623			24,896		(5,224	)		(400,874	)		(51,579	)
Income before income taxes		317,831			361,078		55,361			(397,670	)		336,600
Income tax provision		(118,435	)		—		(160	)		—			(118,595	)
Consolidated net income		199,396			361,078		55,201			(397,670	)		218,005
Amortization of deferred loss on commodity derivative contracts, net of tax		(1,071	)		2,857		—			—			1,786
Change in deferred hedge gain on interest rate swaps, net of tax		(103	)		—		256			—			153
Consolidated comprehensive income	$	198,222		$	363,935	$	55,457		$	(397,670	)	$	219,944

33

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Nine Months Ended September 30, 2009
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(42,913	)	$	583,522		$	92,544		$	—		$	633,153
Cash flows from investing activities:
Acquisition of oil and natural gas properties		—			(391,975	)		(31,984	)		—			(423,959	)
Development of oil and natural gas properties		—			(286,113	)		(7,330	)		—			(293,443	)
Investments in subsidiaries		122,389			—			—			(122,389	)		—
Other		—			7,086			—			—			7,086
Net cash provided by (used in) investing activities		122,389			(671,002	)		(39,314	)		(122,389	)		(710,316	)
Cash flows from financing activities:
Proceeds from long-term debt, net of issuance costs		387,029			—			203,061			—			590,090
Payments on long-term debt		(580,000	)		—			(96,000	)		—			(676,000	)
Proceeds from issuance of common stock, net of offering costs		100,690			—			—			—			100,690
Proceeds from ENP issuance of common units, net of offering costs		—			—			170,149			—			170,149
Net equity contributions (distributions)		—			147,600			(269,989	)		122,389			—
Other		12,198			(57,687	)		(57,633	)		—			(103,122	)
Net cash provided by (used in) financing activities		(80,083	)		89,913			(50,412	)		122,389			81,807
Increase (decrease) in cash and cash equivalents		(607	)		2,433			2,818			—			4,644
Cash and cash equivalents, beginning of period		607			813			619			—			2,039
Cash and cash equivalents, end of period	$	—		$	3,246		$	3,437		$	—		$	6,683

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Nine Months Ended September 30, 2008
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Cash flows from operating activities:
Net cash provided by operating activities	$	289,310		$	141,580		$	98,097		$	—		$	528,987
Cash flows from investing activities:
Acquisition of oil and natural gas properties		—			(116,679	)		(88	)		—			(116,767	)
Development of oil and natural gas properties		—			(369,396	)		(15,468	)		—			(384,864	)
Investments in subsidiaries		(259,105	)		—			—			259,105			—
Other		—			(34,161	)		(302	)		—			(34,463	)
Net cash used in investing activities		(259,105	)		(520,236	)		(15,858	)		259,105			(536,094	)
Cash flows from financing activities:
Repurchase of common stock		(50,000	)		—			—			—			(50,000	)
Proceeds from long-term debt, net of issuance costs		864,969			—			205,269			—			1,070,238
Payments on long-term debt		(861,500	)		—			(113,000	)		—			(974,500	)
Net equity contributions (distributions)		—			383,823			(124,718	)		(259,105	)		—
Other		17,303			(4,175	)		(49,636	)		—			(36,508	)
Net cash provided by (used in) financing activities		(29,228	)		379,648			(82,085	)		(259,105	)		9,230
Increase in cash and cash equivalents		977			992			154			—			2,123
Cash and cash equivalents, beginning of period		1			1,700			3			—			1,704
Cash and cash equivalents, end of period	$	978		$	2,692		$	157		$	—		$	3,827

34

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 15. Commitments and Contingencies

     EAC 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 EAC’s business, financial condition, results of operations, or liquidity.

     Additionally, EAC has contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal, long-term debt, derivative contracts, capital and operating leases, and development commitments. Please read “Capital Commitments, Capital Resources, and Liquidity — Capital commitments — Contractual obligations” included in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Report for a description of EAC’s contractual obligations as of September 30, 2009.

Note 16. Related Party Transactions

     During the nine months ended September 30, 2008, EAC received approximately $132.3 million, from affiliates of Tesoro Corporation (“Tesoro”) related to gross oil and gas production sold from wells operated by Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly owned subsidiary of EAC. Mr. John V. Genova, a member of the Board, served as an employee of Tesoro until May 2008.

     Please read “Note 17. ENP” for a discussion of transactions with ENP.

Note 17. ENP

Administrative Services Agreement

     ENP does not have any employees. The employees supporting ENP’s operations are employees of EAC. Encore Operating performs administrative services for ENP, such as accounting, corporate development, finance, land, legal, and engineering, pursuant to an administrative services agreement. In addition, Encore Operating provides all personnel, facilities, goods, and equipment necessary to perform these services which are not otherwise provided for by ENP. Encore Operating is not liable to ENP for its performance of, or failure to perform, services under the administrative services agreement unless its acts or omissions constitute gross negligence or willful misconduct.

     Encore Operating initially received an administrative fee of $1.75 per BOE of ENP’s production for such services. From April 1, 2008 to March 31, 2009, the administration fee was $1.88 per BOE of ENP’s production. Effective April 1, 2009, the administrative fee increased to $2.02 per BOE of ENP’s production. ENP also reimburses Encore Operating for actual third-party expenses incurred on ENP’s behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on ENP’s behalf. In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator.

     The administrative fee will increase in the following circumstances:

• beginning on the first day of April in each year by an amount equal to the product of the then-current administrative fee multiplied by the COPAS Wage Index Adjustment for that year;

• if ENP or one of its subsidiaries acquires additional assets, Encore Operating may propose an increase in its administrative fee that covers the provision of services for such additional assets; however, such proposal must be approved by the board of directors of GP LLC upon the recommendation of its conflicts committee; and

• otherwise as agreed upon by Encore Operating and GP LLC, with the approval of the conflicts committee of the board of directors of GP LLC.

     ENP reimburses EAC for any state income, franchise, or similar tax incurred by EAC resulting from the inclusion of ENP and its subsidiaries in consolidated tax returns with EAC and its subsidiaries as required by applicable law. The amount of any such reimbursement is limited to the tax that ENP and its subsidiaries would have incurred had they not been included in a combined group with EAC.

35

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Sales of Assets to ENP

     In August 2009, Encore Operating sold certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota (the “Rockies and Permian Basin Assets”) to ENP for approximately $186.8 million in cash, which ENP financed through borrowings under the OLLC Credit Agreement and proceeds from the issuance of ENP common units to the public. EAC used the proceeds from the sale of properties to fund a portion of the purchase price of its acquisitions from EXCO.

     In June 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Williston Basin in North Dakota and Montana (the “Williston Basin Assets”) to ENP for approximately $25.2 million in cash, which ENP financed through borrowings under the OLLC Credit Agreement and proceeds from the issuance of ENP common units to the public. EAC used the proceeds from the sale of the properties to reduce outstanding borrowings under the EAC Credit Agreement.

     In January 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”), to ENP for approximately $46.4 million in cash, which ENP financed through borrowings under the OLLC Credit Agreement. EAC used the proceeds from the sale of the properties to reduce outstanding borrowings under the EAC Credit Agreement.

     In February 2008, Encore Operating sold certain oil and natural gas properties and related assets in the Permian Basin in West Texas and in the Williston Basin in North Dakota to ENP for approximately $125.0 million in cash and 6,884,776 ENP common units. In determining the total purchase price, the common units were valued at $125.0 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s carrying value of the properties. ENP financed the cash portion of the purchase price through borrowings under the OLLC Credit Agreement. EAC used the proceeds from the sale of the properties to reduce outstanding borrowings under the EAC Credit Agreement.

Shelf Registration Statement on Form S-3

     In November 2008, ENP’s “shelf” registration statement on Form S-3 was declared effective by the SEC. Under the shelf registration statement, ENP may offer common units, senior debt, or subordinated debt in one or more offerings with a total initial offering price of up to $1 billion.

Public Offerings of Common Units

     In July 2009, ENP issued 9,430,000 common units under its shelf registration statement at a price to the public of $14.30 per common unit. ENP used the net proceeds of approximately $129.2 million, after deducting the underwriters’ discounts and commissions of $5.4 million, in the aggregate, and offering costs of $0.2 million, to fund a portion of the purchase price of the Rockies and Permian Basin Assets.

     In May 2009, ENP issued 2,760,000 common units under its shelf registration statement at a price to the public of $15.60 per common unit. ENP used the net proceeds of approximately $40.9 million, after deducting the underwriters’ discounts and commissions of $1.9 million, in the aggregate, and offering costs of approximately $0.2 million, to fund the acquisition of certain natural gas producing properties in the Vinegarone Field in Val Verde County, Texas (the “Vinegarone Assets”) from an independent energy company for approximately $27.5 million, and a portion of the purchase price of the Williston Basin Assets.

Long-Term Incentive Plan

     In September 2007, the board of directors of GP LLC adopted the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “ENP Plan”), which provides for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. All employees, consultants, and directors of EAC, GP LLC, and any of their subsidiaries and affiliates who perform services for ENP are eligible to be granted awards under the ENP Plan. The ENP Plan is administered by the board of directors of GP LLC or a committee thereof, referred to as the plan administrator. To satisfy common unit awards under the ENP Plan, ENP may issue common units, acquire common units in the open market, or use common units owned by EAC and its affiliates.

36

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The total number of common units reserved for issuance pursuant to the ENP Plan is 1,150,000. As of September 30, 2009, there were 1,100,000 common units available for issuance under the ENP Plan.

     Phantom Units. Each October, ENP issues 5,000 phantom units to each member of GP LLC’s board of directors pursuant to the ENP Plan. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the plan administrator, cash equivalent to the value of a common unit. ENP intends to settle the phantom units at vesting by issuing common units to the grantee; therefore, these phantom units are classified as equity instruments. Phantom units vest equally over a four-year period. The holders of phantom units are also entitled to distribution equivalent rights prior to vesting, which entitle them to receive cash equal to the amount of any cash distributions paid by ENP with respect to a common unit during the period the right is outstanding. During the nine months ended September 30, 2009 and 2008, ENP recognized non-cash unit-based compensation expense related to phantom units of approximately $0.3 million and $0.2 million, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations.

     The following table summarizes the changes in ENP’s unvested phantom units for the nine months ended September 30, 2009:

			Weighted
			Average
	Number of		Grant Date
	Shares		Fair Value
Outstanding at January 1, 2009		43,750	$	18.67
Granted		—		—
Vested		—		—
Forfeited		—		—
Outstanding at September 30, 2009		43,750		18.67

     As of September 30, 2009, ENP had $0.4 million of total unrecognized compensation cost related to unvested phantom units, which is expected to be recognized over a weighted average period of 1.9 years.

Management Incentive Units

     In May 2007, the board of directors of GP LLC issued 550,000 management incentive units to certain executive officers of GP LLC. During the fourth quarter of 2008, the management incentive units became convertible into ENP common units, at the option of the holder, at a ratio of one management incentive unit to approximately 3.1186 ENP common units, and all 550,000 management incentive units were converted into 1,715,205 ENP common units.

     During the three and nine months ended September 30, 2008, ENP recognized non-cash unit-based compensation expense related to management incentive units of $1.1 million and $3.2 million, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. There have been no additional issuances of management incentive units.

Distributions

     During the three and nine months ended September 30, 2009, ENP paid cash distributions of approximately $23.5 million and $57.1 million, respectively, of which $11.0 million and $32.4 million, respectively, was paid to EAC and its subsidiaries and had no impact on EAC’s consolidated cash. During the three and nine months ended September 30, 2008, ENP paid cash distributions of approximately $23.1 million and $52.3 million, respectively, of which $14.7 million and $32.7 million, respectively, was paid to EAC and its subsidiaries and had no impact on EAC’s consolidated cash.

     During the three and nine months ended September 30, 2008, ENP paid cash distributions of approximately $1.2 million and $2.4 million, respectively, to certain executive officers of GP LLC, who serve in the same capacities for EAC, based on their ownership of management incentive units.

37

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 18. Segment Information

     EAC operates in only one industry: the oil and natural gas exploration and production industry in the United States. However, EAC is organizationally structured along two reportable segments: EAC Standalone and ENP. EAC’s segments are components of its business for which separate financial information is available and regularly evaluated by the chief operating decision maker in deciding how to allocate capital resources to projects and in assessing performance. The accounting policies used in the generation of segment financial statements are the same as those described in Note 2 to Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Date” of EAC’s 2008 Annual Report on Form 10-K.

     The following tables provide EAC’s operating segment information required by SFAS No. 131, “Disclosure about Segments of an Enterprise and Related Information” (ASC 280-10). The prior period financial information of ENP in the following tables was recast to include the financial results of the Rockies and Permian Basin Assets, the Arkoma Basin Assets, and the Williston Basin Assets.

	For the Three Months Ended September 30, 2009
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	117,669		$	35,280		$	—		$	152,949
Natural gas		26,518			5,650			—			32,168
Marketing		785			102			—			887
Total revenues		144,972			41,032			—			186,004
Expenses:
Production:
Lease operating		29,124			9,017			—			38,141
Production, ad valorem, and severance taxes		14,529			4,693			—			19,222
Depletion, depreciation, and amortization		58,169			14,458			—			72,627
Exploration		13,634			3,034			—			16,668
General and administrative		11,892			2,912			(1,534	)		13,270
Marketing		304			54			—			358
Derivative fair value gain		(8,434	)		(4,822	)		—			(13,256	)
Other operating		6,938			1,303			—			8,241
Total expenses		126,156			30,649			(1,534	)		155,271
Operating income		18,816			10,383			1,534			30,733
Other income (expenses):
Interest		(18,936	)		(2,984	)		—			(21,920	)
Other		2,111			23			(1,534	)		600
Total other expenses		(16,825	)		(2,961	)		(1,534	)		(21,320	)
Income before income taxes		1,991			7,422			—			9,413
Income tax benefit (provision)		(11,227	)		38			—			(11,189	)
Consolidated net income (loss)		(9,236	)		7,460			—			(1,776	)
Change in deferred hedge loss on interest rate swaps, net of tax		(37	)		(306	)		—			(343	)
Consolidated comprehensive income (loss)	$	(9,273	)	$	7,154		$	—		$	(2,119	)

38

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

	For the Three Months Ended September 30, 2008
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	201,322		$	67,221		$	—		$	268,543
Natural gas		51,328			15,444			—			66,772
Marketing		718			1,445			—			2,163
Total revenues		253,368			84,110			—			337,478
Expenses:
Production:
Lease operating		35,999			12,967			—			48,966
Production, ad valorem, and severance taxes		25,140			8,210			—			33,350
Depletion, depreciation, and amortization		44,725			13,820			—			58,545
Impairment of long-lived assets		26,292			—			—			26,292
Exploration		13,334			47			—			13,381
General and administrative		12,601			3,772			(1,070	)		15,303
Marketing		539			1,316			—			1,855
Derivative fair value gain		(168,992	)		(70,443	)		—			(239,435	)
Other operating		3,633			440			—			4,073
Total expenses		(6,729	)		(29,871	)		(1,070	)		(37,670	)
Operating income		260,097			113,981			1,070			375,148
Other income (expenses):
Interest		(16,357	)		(1,767	)		—			(18,124	)
Other		2,613			10			(1,070	)		1,553
Total other expenses		(13,744	)		(1,757	)		(1,070	)		(16,571	)
Income before income taxes		246,353			112,224			—			358,577
Income tax provision		(120,852	)		(332	)		—			(121,184	)
Consolidated net income		125,501			111,892			—			237,393
Change in deferred hedge gain on interest rate swaps, net of tax		333			(597	)		—			(264	)
Consolidated comprehensive income	$	125,834		$	111,295		$	—		$	237,129

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ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

	For the Nine Months Ended September 30, 2009
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	286,482		$	88,433		$	—		$	374,915
Natural gas		71,765			15,143			—			86,908
Marketing		1,627			381			—			2,008
Total revenues		359,874			103,957			—			463,831
Expenses:
Production:
Lease operating		91,697			31,120			—			122,817
Production, ad valorem, and severance taxes		36,488			11,586			—			48,074
Depletion, depreciation, and amortization		173,677			43,684			—			217,361
Exploration		40,727			3,074			—			43,801
General and administrative		35,458			9,135			(3,850	)		40,743
Marketing		1,367			245			—			1,612
Derivative fair value loss (gain)		(22,452	)		21,711			—			(741	)
Other operating		26,689			2,730			—			29,419
Total expenses		383,651			123,285			(3,850	)		503,086
Operating loss		(23,777	)		(19,328	)		3,850			(39,255	)
Other income (expenses):
Interest		(49,458	)		(7,551	)		—			(57,009	)
Other		5,632			29			(3,850	)		1,811
Total other expenses		(43,826	)		(7,522	)		(3,850	)		(55,198	)
Loss before income taxes		(67,603	)		(26,850	)		—			(94,453	)
Income tax benefit (provision)		25,417			(163	)		—			25,254
Consolidated net loss		(42,186	)		(27,013	)		—			(69,199	)
Change in deferred hedge loss on interest rate swaps, net of tax		(253	)		342			—			89
Consolidated comprehensive loss	$	(42,439	)	$	(26,671	)	$	—		$	(69,110	)

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ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

	For the Nine Months Ended September 30, 2008
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	578,414		$	197,587		$	—		$	776,001
Natural gas		137,563			45,410			—			182,973
Marketing		3,533			5,207			—			8,740
Total revenues		719,510			248,204			—			967,714
Expenses:
Production:
Lease operating		95,944			34,069			—			130,013
Production, ad valorem, and severance taxes		72,134			23,711			—			95,845
Depletion, depreciation, and amortization		116,618			42,496			—			159,114
Impairment of long-lived assets		26,292			—			—			26,292
Exploration		30,347			115			—			30,462
General and administrative		27,854			11,899			(3,204	)		36,549
Marketing		4,044			5,318			—			9,362
Derivative fair value loss		60,521			21,572			—			82,093
Other operating		8,511			1,294			—			9,805
Total expenses		442,265			140,474			(3,204	)		579,535
Operating income		277,245			107,730			3,204			388,179
Other income (expenses):
Interest		(49,353	)		(5,316	)		—			(54,669	)
Other		6,202			92			(3,204	)		3,090
Total other expenses		(43,151	)		(5,224	)		(3,204	)		(51,579	)
Income before income taxes		234,094			102,506			—			336,600
Income tax provision		(118,401	)		(194	)		—			(118,595	)
Consolidated net income		115,693			102,312			—			218,005
Amortization of deferred loss on commodity derivative contracts, net of tax		1,786			—			—			1,786
Change in deferred hedge gain on interest rate swaps, net of tax		(234	)		387			—			153
Consolidated comprehensive income	$	117,245		$	102,699		$	—		$	219,944

     The following table provides EAC’s balance sheet segment information as of the dates indicated:

	September 30, 2009			December 31, 2008
	(in thousands)
Segment assets:
EAC Standalone	$	2,967,971		$	2,823,778
ENP		748,202			813,313
Eliminations		(2,359	)		(3,896	)
Total consolidated assets	$	3,713,814		$	3,633,195
Segment liabilities:
EAC Standalone	$	1,735,108		$	1,961,453
ENP		312,200			193,962
Eliminations		(2,259	)		(5,468	)
Total consolidated liabilities	$	2,045,049		$	2,149,947

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ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 19. Subsequent Events

     Subsequent events were evaluated through November 2, 2009, which is the date the financial statements were issued.

     On October 26, 2009, the board of directors of GP LLC declared an ENP cash distribution for the third quarter of 2009 to unitholders of record as of the close of business on November 9, 2009 at a rate of $0.5375 per unit. Approximately $24.6 million is expected to be paid to unitholders on or about November 13, 2009.

     On October 26, 2009, ENP issued 25,000 phantom units to members of GP LLC’s board of directors pursuant to the ENP Plan. The phantom units vest in four equal installments beginning on the first anniversary of the date of grant.

     On November 1, 2009, EAC announced that it had entered into a definitive merger agreement with Denbury Resources Inc. (“Denbury”) pursuant to which Denbury will acquire EAC in a transaction valued at approximately $4.5 billion, including the assumption of debt and the value of the minority interest in ENP. Under the definitive agreement, EAC stockholders will receive $50.00 per share for each share of EAC common stock, comprised of $15.00 in cash and $35.00 in Denbury common stock subject to both an election feature and a collar mechanism on the stock portion of the consideration. Completion of the transaction is subject to the approval of both Denbury and EAC stockholders, regulatory approvals, and other conditions.

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ENCORE ACQUISITION COMPANY

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     The following discussion and analysis contains forward-looking statements, which give our current expectations or forecasts of future events. Actual results could differ materially from those discussed in the forward-looking statements due to many factors, including, but not limited to, those set forth under “Item 1A. Risk Factors” and elsewhere in our 2008 Annual Report on Form 10-K. The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto included in “Item 1. Financial Statements” of this Report and in “Item 8. Financial Statements and Supplementary Data” of our 2008 Annual Report on Form 10-K.

Introduction

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

• Third Quarter 2009 Highlights

• Results of Operations

o Comparison of Quarter Ended September 30, 2009 to Quarter Ended September 30, 2008

o Comparison of Nine Months Ended September 30, 2009 to Nine Months Ended September 30, 2008

• Capital Commitments, Capital Resources, and Liquidity

• Critical Accounting Policies and Estimates

• New Accounting Pronouncements

Third Quarter 2009 Highlights

     Our financial and operating results for the third quarter of 2009 included the following:

• Our average daily production volumes increased nine percent to 43,225 BOE/D as compared to 39,617 BOE/D in the third quarter of 2008. Oil represented 64 percent of our total production volumes as compared to 68 percent in the third quarter of 2008.

• In September 2009, we issued 2,750,000 shares of our common stock at a price to the public of $37.40 per common share. The net proceeds of approximately $100.7 million were used to reduce outstanding borrowings under our revolving credit facility.

• In August, we purchased certain oil and natural gas properties and related assets in the Mid-Continent and East Texas from EXCO for approximately $357.0 million in cash (including a deposit of $37.5 million made in June 2009).

• In August, we sold the Rockies and Permian Basin Assets to ENP for approximately $186.8 million in cash.

• In July, ENP issued 9,430,000 common units under its shelf registration statement at a price to the public of $14.30 per common unit. The net proceeds of approximately $129.1 million were used to fund a portion of the purchase price of the Rockies and Permian Basin Assets.

• We invested $411.5 million in oil and natural gas activities (excluding $3.5 million of asset retirement obligations), of which $42.7 million was invested in development, exploitation, and exploration activities, yielding 22 gross (7.7 net) productive wells, and $368.8 million was invested in acquisitions, primarily related to our EXCO asset acquisition.

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ENCORE ACQUISITION COMPANY

Results of Operations

Comparison of Quarter Ended September 30, 2009 to Quarter Ended September 30, 2008

     Revenues. The following table provides the components of our revenues for the periods indicated, as well as each period’s respective production volumes and average prices:

	Three months ended September 30,				Increase / (Decrease)
	2009		2008		$			%
Revenues (in thousands):
Oil wellhead	$	152,949	$	268,543	$	(115,594	)		-43	%
Natural gas wellhead		32,168		66,772		(34,604	)		-52	%
Total combined oil and natural gas revenues		185,117		335,315		(150,198	)		-45	%
Marketing		887		2,163		(1,276	)		-59	%
Total revenues	$	186,004	$	337,478	$	(151,474	)		-45	%
Average realized prices:
Oil ($/Bbl)	$	60.45	$	108.21	$	(47.76	)		-44	%
Natural gas ($/Mcf)	$	3.71	$	9.57	$	(5.86	)		-61	%
Total combined oil and natural gas revenues ($/BOE)	$	46.55	$	92.00	$	(45.45	)		-49	%
Total production volumes:
Oil (MBbls)		2,530		2,482		48			2	%
Natural gas (MMcf)		8,681		6,978		1,703			24	%
Combined (MBOE)		3,977		3,645		332			9	%
Average daily production volumes:
Oil (Bbls/D)		27,500		26,975		525			2	%
Natural gas (Mcf/D)		94,353		75,847		18,506			24	%
Combined (BOE/D)		43,225		39,617		3,608			9	%
Average NYMEX prices:
Oil (per Bbl)	$	68.24	$	118.67	$	(50.43	)		-42	%
Natural gas (per Mcf)	$	3.40	$	10.27	$	(6.87	)		-67	%

     Oil revenues decreased 43 percent from $268.5 million in the third quarter of 2008 to $152.9 million in the third quarter of 2009 as a result of a $47.76 per Bbl decrease in our average realized oil price, partially offset by a 48 MBbls increase in our oil production volumes. Our lower average realized oil price decreased oil revenues by approximately $120.8 million and was primarily due to a lower average NYMEX price, which decreased from $118.67 per Bbl in the third quarter of 2008 to $68.24 per Bbl in the third quarter of 2009. Our higher oil production volumes increased oil revenues by approximately $5.2 million and was primarily due to our acquisitions of properties from EXCO in August 2009.

     In the third quarter of 2009 and 2008, our average daily production volumes were decreased by 1,654 BOE/D and 1,535 BOE/D, respectively, for net profits interests related to our CCA properties, which reduced our oil wellhead revenues by approximately $8.8 million and $18.5 million, respectively.

     Natural gas revenues decreased 52 percent from $66.8 million in the third quarter of 2008 to $32.2 million in the third quarter of 2009 as a result of a $5.86 per Mcf decrease in our average realized natural gas price, partially offset by a 1,703 MMcf increase in our natural gas production volumes. Our lower average realized natural gas price decreased natural gas revenues by approximately $50.9 million and was primarily due to a lower average NYMEX price, which decreased from $10.27 per Mcf in the third quarter of 2008 to $3.40 per Mcf in the third quarter of 2009. Our higher natural gas production increased natural gas revenues by approximately $16.3 million and was primarily due to our acquisitions of properties from EXCO in August 2009.

     The following table shows the relationship between our oil and natural gas wellhead prices as a percentage of average NYMEX prices for the periods indicated. Management uses the wellhead price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.

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ENCORE ACQUISITION COMPANY

	Three months ended September 30,
	2009			2008
Average realized oil price ($/Bbl)	$	60.45		$	108.21
Average NYMEX ($/Bbl)	$	68.24		$	118.67
Differential to NYMEX	$	(7.79	)	$	(10.46	)
Average realized oil price to NYMEX percentage		89	%		91	%
Average realized natural gas price ($/Mcf)	$	3.71		$	9.57
Average NYMEX ($/Mcf)	$	3.40		$	10.27
Differential to NYMEX	$	0.31		$	(0.70	)
Average realized natural gas price to NYMEX percentage		109	%		93	%

     Our average oil wellhead price as a percentage of the average NYMEX price was 89 percent in the third quarter of 2009 as compared to 91 percent in the third quarter of 2008.

     Our average natural gas wellhead price as a percentage of the average NYMEX price was 109 percent in the third quarter of 2009 as compared to 93 percent in the third quarter of 2008. Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of liquids extracted. Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas in Mcf as production. In the third quarter of 2009, the natural gas index prices related to our West Texas, East Texas, and Rocky Mountains natural gas contracts all improved in their relationship to NYMEX narrowing the average differential. As a result of the incremental NGLs value and the narrower differentials, the price we were paid per Mcf for natural gas sold under certain contracts during the third quarter of 2009 increased to a level above NYMEX.

     Marketing revenues decreased 59 percent from $2.2 million in the third quarter of 2008 to $0.9 million in the third quarter of 2009 primarily as a result of a reduction in natural gas throughput in our Wildhorse pipeline and the decrease in natural gas prices. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

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     Expenses. The following table provides the components of our expenses for the periods indicated:

	Three months ended September 30,						Increase / (Decrease)
	2009			2008			$			%
Expenses (in thousands):
Production:
Lease operating	$	38,141		$	48,966		$	(10,825	)
Production, ad valorem, and severance taxes		19,222			33,350			(14,128	)
Total production expenses		57,363			82,316			(24,953	)		-30	%
Other:
Depletion, depreciation, and amortization		72,627			58,545			14,082
Impairment of long-lived assets		—			26,292			(26,292	)
Exploration		16,668			13,381			3,287
General and administrative		13,270			15,303			(2,033	)
Marketing		358			1,855			(1,497	)
Derivative fair value gain		(13,256	)		(239,435	)		226,179
Other operating		8,241			4,073			4,168
Total operating expenses		155,271			(37,670	)		192,941			-512	%
Interest		21,920			18,124			3,796
Income tax provision		11,189			121,184			(109,995	)
Total expenses	$	188,380		$	101,638		$	86,742			85	%
Expenses (per BOE):
Production:
Lease operating	$	9.59		$	13.43		$	(3.84	)
Production, ad valorem, and severance taxes		4.83			9.15			(4.32	)
Total production expenses		14.42			22.58			(8.16	)		-36	%
Other:
Depletion, depreciation, and amortization		18.26			16.06			2.20
Impairment of long-lived assets		—			7.21			(7.21	)
Exploration		4.19			3.67			0.52
General and administrative		3.34			4.20			(0.86	)
Marketing		0.09			0.51			(0.42	)
Derivative fair value gain		(3.33	)		(65.69	)		62.36
Other operating		2.07			1.12			0.95
Total operating expenses		39.04			(10.34	)		49.38			-478	%
Interest		5.51			4.97			0.54
Income tax provision		2.81			33.25			(30.44	)
Total expenses	$	47.36		$	27.88		$	19.48			70	%

     Production expenses. Total production expenses decreased 30 percent from $82.3 million in the third quarter of 2008 to $57.4 million in the third quarter of 2009. Our production margin decreased 50 percent from $253.0 million in the third quarter of 2008 to $127.8 million in the third quarter of 2009. Total oil and natural gas wellhead revenues per BOE decreased by 49 percent and total production expenses per BOE decreased by 36 percent. On a per BOE basis, our production margin decreased 54 percent to $32.13 per BOE in the third quarter of 2009 as compared to $69.42 per BOE in the third quarter of 2008.

     Production expense attributable to LOE decreased $10.8 million from $49.0 million in the third quarter of 2008 to $38.1 million in the third quarter of 2009 as a result of a $3.84 decrease in the per BOE rate, partially offset by higher production volumes. Our lower average LOE per BOE rate decreased LOE by approximately $15.3 million and was primarily due to decreases in natural gas prices resulting in lower electricity costs and gas plant fuel costs, lower prices paid to oilfield service companies and suppliers, and retention bonuses paid in August 2008 related to our 2008 strategic alternatives process. Our higher production volumes increased LOE by approximately $4.5 million.

     Production expense attributable to production taxes decreased $14.1 million from $33.4 million in the third quarter of 2008 to $19.2 million in the third quarter of 2009 primarily due to lower wellhead revenues, which exclude the effects of commodity derivative contracts. As a percentage of wellhead revenues, production taxes increased to 10.4 percent in the third quarter of 2009 as

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compared to 9.9 percent in the third quarter of 2008 primarily due to higher ad valorem taxes, which are based on production volumes as opposed to a percentage of wellhead revenues.

     Depletion, depreciation, and amortization expense (“DD&A”). DD&A expense increased $14.1 million from $58.5 million in the third quarter of 2008 to $72.6 million in the third quarter of 2009 as a result of a $2.20 increase in the per BOE rate and higher production volumes. Our higher average DD&A per BOE rate increased DD&A expense by approximately $8.7 million and was primarily due to the decrease in our proved reserves as a result of lower average commodity prices, partially offset by reserves added through our EXCO asset acquisition. Our higher production volumes increased DD&A expense by approximately $5.3 million.

     Impairment of long-lived assets. During the third quarter of 2008, circumstances indicated that the carrying value of the two wells we drilled in the Tuscaloosa Marine Shale may not be recoverable. We compared the assets’ carrying value to the undiscounted expected future net cash flows, which indicated a need for an impairment charge. We then compared the net book value of the impaired assets to their estimated discounted value, which resulted in a write-down of the value of proved oil and natural gas properties of $26.3 million. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes, discounted to a present value.

     Exploration expense. Exploration expense increased $3.3 million from $13.4 million in the third quarter of 2008 to $16.7 million in the third quarter of 2009. During the third quarter of 2009, we expensed 1.6 net exploratory dry holes totaling $9.8 million. During the third quarter of 2008, we expensed 1.3 net exploratory dry holes totaling $7.2 million. Impairment of unproved acreage increased $1.4 million from $5.0 million in the third quarter of 2008 to $6.4 million in the third quarter of 2009, primarily due to our larger unproved property base, as well as the impairment of certain acreage through the normal course of evaluation. The following table provides the components of exploration expense for the periods indicated:

	Three months ended September 30,				Increase /
	2009		2008		(Decrease)
	(in thousands)
Dry holes	$	9,759	$	7,161	$	2,598
Geological and seismic		282		1,070		(788	)
Delay rentals		276		157		119
Impairment of unproved acreage		6,351		4,993		1,358
Total	$	16,668	$	13,381	$	3,287

     General and administrative expense (“G&A”). G&A expense decreased $2.0 million from $15.3 million in the third quarter of 2008 to $13.3 million in the third quarter of 2009 primarily due to retention bonuses paid in August 2008 related to our 2008 strategic alternatives process and a decrease in non-cash equity-based compensation related to ENP’s management incentive units, partially offset by the expensing of transaction costs related to our EXCO asset acquisition.

     Marketing expenses. Marketing expenses decreased $1.5 million from $1.9 million in the third quarter of 2008 to $0.4 million in the third quarter of 2009 primarily due to a reduction in natural gas throughput in our Wildhorse pipeline and the decrease in natural gas prices. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

     Derivative fair value gain. During the third quarter of 2009, we recorded a $13.3 million derivative fair value gain as compared to $239.4 million in the third quarter of 2008, the components of which were as follows:

	Three months ended September 30,						Increase /
	2009			2008			(Decrease)
	(in thousands)
Ineffectiveness	$	18		$	(6	)	$	24
Mark-to-market loss (gain)		576			(276,932	)		277,508
Premium amortization		6,838			14,773			(7,935	)
Settlements		(20,688	)		22,730			(43,418	)
Total derivative fair value gain	$	(13,256	)	$	(239,435	)	$	226,179

     Other operating expense. Other operating expense increased $4.2 million from $4.1 million in the third quarter of 2008 to $8.2

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million in the third quarter of 2009 primarily due to a $0.7 million adjustment to the carrying value of pipe and other tubular inventory whose market value had declined below cost, a $2.4 million adjustment to the carrying value of certain receivables, primarily from ExxonMobil related to our West Texas joint venture, and higher gathering and transportation fees.

     Interest expense. Interest expense increased $3.8 million from $18.1 million in the third quarter of 2008 to $21.9 million in the third quarter of 2009 primarily due to the issuance of $225 million of our 9.5% Notes. We received net proceeds of approximately $202.5 million from the issuance of the 9.5% Notes, which we used to reduce outstanding borrowings under our revolving credit facility. Our weighted average interest rate was 6.5 percent for the third quarter of 2009 as compared to 5.6 percent for the third quarter of 2008.

     The following table provides the components of interest expense for the periods indicated:

	Three months ended September 30,				Increase /
	2009		2008		(Decrease)
	(in thousands)
6.25% Senior Subordinated Notes	$	2,439	$	2,433	$	6
6.0% Senior Subordinated Notes		4,648		4,640		8
9.5% Senior Subordinated Notes		5,904		—		5,904
7.25% Senior Subordinated Notes		2,752		2,749		3
Revolving credit facilities		4,786		7,478		(2,692	)
Other		1,391		824		567
Total	$	21,920	$	18,124	$	3,796

     Income taxes. In the third quarter of 2009, we recorded an income tax provision of $11.2 million as compared to $121.2 million in the third quarter of 2008. In the third quarter of 2009, we had income before income taxes and noncontrolling interest of $9.4 million as compared to $358.6 million in the third quarter of 2008. Our effective tax rate increased to 118.9 percent in the third quarter of 2009 as compared to 33.8 percent in the third quarter of 2008 primarily due to the loss of the production activities deduction in 2009, the 2008 provision to return difference in the production activities deduction estimated at the end of 2008 due to a change in tax planning as a result of the hedge monetization in the first quarter of 2009, and an increase in the effective state income tax rate due to changes in apportionment associated with our 2009 acquisitions.

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Comparison of Nine Months Ended September 30, 2009 to Nine Months Ended September 30, 2008

     Revenues. The following table provides the components of our revenues for the periods indicated, as well as each period’s respective production volumes and average prices:

	Nine months ended September 30,					Increase / (Decrease)
	2009		2008			$			%
Revenues (in thousands):
Oil wellhead	$	374,915	$	778,858		$	(403,943	)
Oil hedges		—		(2,857	)		2,857
Total oil revenues	$	374,915	$	776,001		$	(401,086	)		-52	%
Natural gas wellhead	$	86,908	$	182,973		$	(96,065	)		-53	%
Combined wellhead	$	461,823	$	961,831		$	(500,008	)
Combined hedges		—		(2,857	)		2,857
Total combined oil and natural gas revenues		461,823		958,974			(497,151	)		-52	%
Marketing		2,008		8,740			(6,732	)		-77	%
Total revenues	$	463,831	$	967,714		$	(503,883	)		-52	%
Average realized prices:
Oil wellhead ($/Bbl)	$	50.34	$	104.61		$	(54.27	)
Oil hedges ($/Bbl)		—		(0.38	)		0.38
Total oil revenues ($/Bbl)	$	50.34	$	104.23		$	(53.89	)		-52	%
Natural gas wellhead ($/Mcf)	$	3.56	$	9.67		$	(6.11	)		-63	%
Combined wellhead ($/BOE)	$	40.10	$	90.76		$	(50.66	)
Combined hedges ($/BOE)		—		(0.27	)		0.27
Total combined oil and natural gas revenues ($/BOE)	$	40.10	$	90.49		$	(50.39	)		-56	%
Total production volumes:
Oil (MBbls)		7,448		7,446			2			0	%
Natural gas (MMcf)		24,408		18,915			5,493			29	%
Combined (MBOE)		11,516		10,598			918			9	%
Average daily production volumes:
Oil (Bbls/D)		27,281		27,174			107			0	%
Natural gas (Mcf/D)		89,405		69,031			20,374			30	%
Combined (BOE/D)		42,182		38,679			3,503			9	%
Average NYMEX prices:
Oil (per Bbl)	$	57.22	$	113.59		$	(56.37	)		-50	%
Natural gas (per Mcf)	$	3.93	$	9.74		$	(5.81	)		-60	%

     Oil revenues decreased 52 percent from $776.0 million in the first nine months of 2008 to $374.9 million in the first nine months of 2009 as a result of a $53.89 per Bbl decrease in our average realized oil price. Our lower average oil wellhead price decreased oil revenues by approximately $404.2 million, or $54.27 per Bbl, and was primarily due to a lower average NYMEX price, which decreased from $113.59 per Bbl in the first nine months of 2008 to $57.22 Bbl in the first nine months of 2009. Oil revenues in the first nine months of 2008 were also reduced by approximately $2.9 million, or $0.38 per Bbl, for oil derivative contracts previously designated as hedges.

     In the first nine months of 2009 and 2008, our average daily production volumes were decreased by 1,710 BOE/D and 1,766 BOE/D, respectively, for net profits interests related to our CCA properties, which reduced our oil wellhead revenues by approximately $21.1 million and $49.7 million, respectively.

     Natural gas revenues decreased 53 percent from $183.0 million in the first nine months of 2008 to $86.9 million in the first nine months of 2009 as a result of a $6.11 per Mcf decrease in our average realized natural gas price, partially offset by a 5,493 MMcf increase in our natural gas production volumes. Our lower average realized natural gas price decreased natural gas revenues by approximately $149.2 million and was primarily due to a lower average NYMEX price, which decreased from $9.74 per Mcf in the

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first nine months of 2008 to $3.93 per Mcf in the first nine months of 2009. Our higher natural gas production increased natural gas revenues by approximately $53.1 million and was primarily due to successful development programs in our Permian Basin and Mid-Continent areas and our acquisitions of properties from EXCO in August 2009.

     The following table shows the relationship between our oil and natural gas wellhead prices as a percentage of average NYMEX prices for the periods indicated:

	Nine months ended September 30,
	2009			2008
Average oil wellhead ($/Bbl)	$	50.34		$	104.61
Average NYMEX ($/Bbl)	$	57.22		$	113.59
Differential to NYMEX	$	(6.88	)	$	(8.98	)
Average oil wellhead to NYMEX percentage		88	%		92	%
Average natural gas wellhead ($/Mcf)	$	3.56		$	9.67
Average NYMEX ($/Mcf)	$	3.93		$	9.74
Differential to NYMEX	$	(0.37	)	$	(0.07	)
Average natural gas wellhead to NYMEX percentage		91	%		99	%

     Our average oil wellhead price as a percentage of the average NYMEX price was 88 percent in the first nine months of 2009 as compared to 92 percent in the first nine months of 2008. The percentage differential widened as a result of a 50 percent decrease in NYMEX as compared to the first nine months of 2008. However, the per Bbl differential improved from $8.98 per Bbl in the first nine months of 2008 to $6.88 per Bbl in the first nine months of 2009.

     Our average natural gas wellhead price as a percentage of the average NYMEX price was 91 percent in the first nine months of 2009 as compared to 99 percent in the first nine months of 2008. Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of liquids extracted. Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas in Mcf as production. During the first nine months of 2008, the price of NGLs increased at a much faster pace than did the price of natural gas resulting in a price we were paid per Mcf under certain contracts to be higher than the average NYMEX price. However, in the first nine months of 2009, the total average natural gas index prices related to our West Texas, East Texas, and Rocky Mountains natural gas contracts all deteriorated in their relationship to NYMEX widening the year-to-date average differential.

     Marketing revenues decreased 77 percent from $8.7 million in the first nine months of 2008 to $2.0 million in the first nine months of 2009 primarily as a result of a reduction in natural gas throughput in our Wildhorse pipeline and the decrease in natural gas prices. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

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     Expenses. The following table provides the components of our expenses for the periods indicated:

	Nine months ended September 30,					Increase / (Decrease)
	2009			2008		$			%
Expenses (in thousands):
Production:
Lease operating	$	122,817		$	130,013	$	(7,196	)
Production, ad valorem, and severance taxes		48,074			95,845		(47,771	)
Total production expenses		170,891			225,858		(54,967	)		-24	%
Other:
Depletion, depreciation, and amortization		217,361			159,114		58,247
Impairment of long-lived assets		—			26,292		(26,292	)
Exploration		43,801			30,462		13,339
General and administrative		40,743			36,549		4,194
Marketing		1,612			9,362		(7,750	)
Derivative fair value loss (gain)		(741	)		82,093		(82,834	)
Other operating		29,419			9,805		19,614
Total operating expenses		503,086			579,535		(76,449	)		-13	%
Interest		57,009			54,669		2,340
Income tax provision (benefit)		(25,254	)		118,595		(143,849	)
Total expenses	$	534,841		$	752,799	$	(217,958	)		-29	%
Expenses (per BOE):
Production:
Lease operating	$	10.67		$	12.27	$	(1.60	)
Production, ad valorem, and severance taxes		4.17			9.04		(4.87	)
Total production expenses		14.84			21.31		(6.47	)		-30	%
Other:
Depletion, depreciation, and amortization		18.88			15.01		3.87
Impairment of long-lived assets		—			2.48		(2.48	)
Exploration		3.80			2.87		0.93
General and administrative		3.54			3.45		0.09
Marketing		0.14			0.88		(0.74	)
Derivative fair value loss (gain)		(0.06	)		7.75		(7.81	)
Other operating		2.55			0.93		1.62
Total operating expenses		43.69			54.68		(10.99	)		-20	%
Interest		4.95			5.16		(0.21	)
Income tax provision (benefit)		(2.19	)		11.19		(13.38	)
Total expenses	$	46.45		$	71.03	$	(24.58	)		-35	%

     Production expenses. Total production expenses decreased 24 percent from $225.9 million in the first nine months of 2008 to $170.9 million in the first nine months of 2009. Our production margin decreased 60 percent from $736.0 million in the first nine months of 2008 to $290.9 million in the first nine months of 2009. Total oil and natural gas wellhead revenues per BOE decreased by 56 percent and total production expenses per BOE decreased by 30 percent. On a per BOE basis, our production margin decreased 64 percent to $25.26 per BOE in the first nine months of 2009 as compared to $69.45 per BOE in the first nine months of 2008.

     Production expense attributable to LOE decreased $7.2 million from $130.0 million in the first nine months of 2008 to $122.8 million in the first nine months of 2009 as a result of a $1.60 decrease in the per BOE rate, partially offset by higher production volumes. Our lower average LOE per BOE rate decreased LOE by approximately $18.5 million and was primarily due to decreases in natural gas prices resulting in lower electricity costs and gas plant fuel costs and lower prices paid to oilfield service companies and suppliers. Our higher production volumes increased LOE by approximately $11.3 million.

     Production expense attributable to production taxes decreased $47.8 million from $95.8 million in the first nine months of 2008 to $48.1 million in the first nine months of 2009 primarily due to lower wellhead revenues, which exclude the effects of commodity derivative contracts. As a percentage of wellhead revenues, production taxes increased to 10.4 percent in the first nine months of 2009 as compared to 10.0 percent in the first nine months of 2008 primarily due to higher ad valorem taxes, which are based on production volumes as opposed to a percentage of wellhead revenues.

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     DD&A expense. DD&A expense increased $58.2 million from $159.1 million in the first nine months of 2008 to $217.4 million in the first nine months of 2009 as a result of a $3.87 increase in the per BOE rate and higher production volumes. Our higher average DD&A per BOE rate increased DD&A expense by approximately $44.5 million and was primarily due to the decrease in our proved reserves as a result of lower average commodity prices, partially offset by reserves added through our EXCO asset acquisition. Our higher production volumes increased DD&A expense by approximately $13.8 million.

     Impairment of long-lived assets. During the third quarter of 2008, circumstances indicated that the carrying value of the two wells we drilled in the Tuscaloosa Marine Shale may not be recoverable. We compared the assets’ carrying value to the undiscounted expected future net cash flows, which indicated a need for an impairment charge. We then compared the net book value of the impaired assets to their estimated discounted value, which resulted in a write-down of the value of proved oil and natural gas properties of $26.3 million. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes, discounted to a present value.

     Exploration expense. Exploration expense increased $13.3 million from $30.5 million in the first nine months of 2008 to $43.8 million in the first nine months of 2009. During the first nine months of 2009, we expensed 5.6 net exploratory dry holes totaling $24.3 million. During the first nine months of 2008, we expensed 3.8 net exploratory dry holes totaling $14.4 million. Impairment of unproved acreage increased $4.8 million from $13.3 million in the first nine months of 2008 to $18.1 million in the first nine months of 2009, primarily due to our larger unproved property base, as well as the impairment of certain acreage through the normal course of evaluation. The following table provides the components of exploration expense for the periods indicated:

	Nine months ended September 30,				Increase /
	2009		2008		(Decrease)
	(in thousands)
Dry holes	$	24,272	$	14,395	$	9,877
Geological and seismic		921		1,903		(982	)
Delay rentals		506		860		(354	)
Impairment of unproved acreage		18,102		13,304		4,798
Total	$	43,801	$	30,462	$	13,339

     G&A expense. G&A expense increased $4.2 million from $36.5 million in the first nine months of 2008 to $40.7 million in the first nine months of 2009 primarily due to retention bonuses paid in August 2009 related to our 2008 strategic alternatives process and the expensing of transaction costs related to our EXCO asset acquisition.

     Marketing expenses. Marketing expenses decreased $7.8 million from $9.4 million in the first nine months of 2008 to $1.6 million in the first nine months of 2009 primarily due to a reduction in natural gas throughput in our Wildhorse pipeline and the decrease in natural gas prices. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

     Derivative fair value loss (gain). During the first nine months of 2009, we recorded a $0.7 million derivative fair value gain as compared to an $82.1 million derivative fair value loss in the first nine months of 2008, the components of which were as follows:

	Nine Months Ended September 30,						Increase /
	2009			2008			(Decrease)
	(in thousands)
Ineffectiveness	$	(16	)	$	(349	)	$	333
Mark-to-market loss (gain)		281,569			(11,884	)		293,453
Premium amortization		91,557			47,579			43,978
Settlements		(373,851	)		46,747			(420,598	)
Total derivative fair value loss (gain)	$	(741	)	$	82,093		$	(82,834	)

     Other operating expense. Other operating expense increased $19.6 million from $9.8 million in the first nine months of 2008 to $29.4 million in the first nine months of 2009 primarily due to a $6.5 million adjustment to the carrying value of pipe and other tubular inventory whose market value had declined below cost, a $7.1 million adjustment to the carrying value of certain receivables, primarily from ExxonMobil related to our West Texas joint venture, and higher gathering and transportation fees.

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     Interest expense. Interest expense increased $2.3 million from $54.7 million in the first nine months of 2008 to $57.0 million in the first nine months of 2009 primarily due to the issuance of our 9.5% Notes. Our weighted average interest rate was 5.5 percent for the first nine months of 2009 as compared to 5.8 percent for the first nine months of 2008.

     The following table provides the components of interest expense for the periods indicated:

	Nine months ended September 30,				Increase /
	2009		2008		(Decrease)
	(in thousands)
6.25% Senior Subordinated Notes	$	7,312	$	7,294	$	18
6.0% Senior Subordinated Notes		13,936		13,910		26
9.5% Senior Subordinated Notes		10,073		—		10,073
7.25% Senior Subordinated Notes		8,253		8,247		6
Revolving credit facilities		13,472		23,082		(9,610	)
Other		3,963		2,136		1,827
Total	$	57,009	$	54,669	$	2,340

     Income taxes. In the first nine months of 2009, we recorded an income tax benefit of $25.3 million as compared to an income tax provision of $118.6 million in the first nine months of 2008. In the first nine months of 2009, we had a loss before income taxes and noncontrolling interest of $94.5 million as compared to income before income taxes and noncontrolling interest of $336.6 million in the first nine months of 2008. Our effective tax rate decreased to 26.7 percent in the first nine months of 2009 as compared to 35.2 percent in the first nine months of 2008 primarily due to the 2008 provision to return difference in the production activities deduction estimated at the end of 2008 due to a change in tax planning as a result of the hedges monetization in the first quarter of 2009 and an increase in the effective state income tax rate due to changes in apportionment associated with our 2009 acquisitions.

Capital Commitments, Capital Resources, and Liquidity

     Capital commitments

     Our primary uses of cash are:

• Development, exploitation, and exploration of oil and natural gas properties;

• Acquisitions of oil and natural gas properties;

• Funding of working capital; and

• Contractual obligations.

     Development, exploitation, and exploration of oil and natural gas properties. The following table summarizes our costs incurred (excluding asset retirement obligations) related to development, exploitation, and exploration activities for the periods indicated:

	Three months ended September 30,				Nine months ended September 30,
	2009		2008		2009		2008
	(in thousands)
Development and exploitation	$	22,670	$	116,376	$	94,934	$	250,624
Exploration		20,046		69,960		140,138		179,217
Total	$	42,716	$	186,336	$	235,072	$	429,841

     Our development and exploitation expenditures primarily relate to drilling development and infill wells, workovers of existing wells, and field related facilities. Our development and exploitation capital for the third quarter of 2009 yielded 6 gross (2.0 net) successful wells and no dry holes. Our development and exploitation capital for the first nine months of 2009 yielded 54 gross (24.7 net) successful wells and no dry holes.

     Our exploration expenditures primarily relate to drilling exploratory wells, seismic costs, delay rentals, and geological and geophysical costs. Our exploration capital for the third quarter of 2009 yielded 16 gross (5.7 net) successful wells and 3 gross (1.6 net) dry holes. Our exploration capital for the first nine months of 2009 yielded 48 gross (15.5 net) successful wells and 7 gross (5.6 net) dry holes.

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     Acquisitions of oil and natural gas properties and leasehold acreage. The following table summarizes our costs incurred (excluding asset retirement obligations) related to oil and natural gas property acquisitions for the periods indicated:

	Three months ended September 30,				Nine months ended September 30,
	2009		2008		2009		2008
	(in thousands)
Acquisitions of proved property	$	366,930	$	8,725	$	394,482	$	29,193
Acquisitions of leasehold acreage		1,828		61,275		6,004		95,916
Total	$	368,758	$	70,000	$	400,486	$	125,109

     In August 2009, we acquired certain oil and natural gas properties from EXCO for approximately $357.0 million in cash (including a deposit of $37.5 million made in June 2009). In May 2009, ENP acquired the Vinegarone Assets for approximately $27.5 million in cash.

     During the three and nine months ended September 30, 2009, our capital expenditures for leasehold acreage related to the acquisition of unproved acreage in various areas. During the three and nine months ended September 30, 2008, $44.0 million of our capital expenditures for leasehold acreage related to the exercise of preferential rights in the Haynesville area and the remainder related to the acquisition of unproved acreage in various areas.

     Funding of working capital. As of September 30, 2009 and December 31, 2008, our working capital (defined as total current assets less total current liabilities) was a negative $61.9 million and a positive $188.7 million, respectively. The decrease was primarily due to the monetization of certain of our 2009 oil derivative contracts in March 2009 and higher oil prices at September 30, 2009 as compared to December 31, 2008, which negatively impacted the fair value of our outstanding oil derivative contracts.

     For the remainder of 2009, we expect working capital to remain negative primarily due to higher oil prices as compared to December 31, 2008. We anticipate cash reserves to be close to zero because we intend to use any excess cash to fund capital obligations and reduce outstanding borrowings and related interest expense under our revolving credit facility. However, we have availability under our revolving credit facility to fund our obligations as they become due. We do not plan to pay cash dividends in the foreseeable future. Our production volumes, commodity prices, and differentials for oil and natural gas will be the largest variables affecting working capital. Our operating cash flow is determined in large part by production volumes and commodity prices. Given our current commodity derivative contracts, assuming relatively stable commodity prices and constant or increasing production volumes, our operating cash flow should remain positive for the remainder of 2009.

     The Board approved a capital budget of $340 million for 2009, excluding proved property acquisitions. The level of these and other future expenditures are largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects, and market conditions. We plan to finance our ongoing expenditures using internally generated cash flow and availability under our revolving credit facility.

     Off-balance sheet arrangements. We have no investments in unconsolidated entities or persons that could materially affect our liquidity or availability of capital resources. We have no off-balance sheet arrangements that are material to our financial position or results of operations.

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     Contractual obligations. The following table provides the components of our contractual obligations and commitments at September 30, 2009:

		Payments Due by Period
				Three Months Ending		Years Ending		Years Ending
Contractual Obligations	Maturity			December 31,		December 31,		December 31,
and Commitments	Date	Total		2009		2010 - 2011		2012 - 2013		Thereafter
		(in thousands)
6.25% Senior Subordinated Notes (a)	4/15/2014	$	196,875	$	4,687	$	18,750	$	18,750	$	154,688
6.0% Senior Subordinated Notes (a)	7/15/2015		408,000		—		36,000		36,000		336,000
9.5% Senior Subordinated Notes (a)	5/1/2016		374,625		10,687		42,750		42,750		278,438
7.25% Senior Subordinated Notes (a)	12/1/2017		242,438		5,438		21,750		21,750		193,500
Revolving credit facilities (a)	3/7/2012		467,527		5,005		20,020		442,502		—
Commodity derivative contracts (b)			44,652		—		38,810		5,842		—
Interest rate swaps (c)			4,239		942		3,297		—		—
Capital lease obligations			1,398		117		932		349		—
Development commitments (d)			47,704		12,044		35,660		—		—
Operating leases and commitments (e)			14,556		988		7,603		5,965		—
Asset retirement obligations (f)			192,735		511		4,093		4,093		184,038
Total		$	1,994,749	$	40,419	$	229,665	$	578,001	$	1,146,664

(a)	Includes principal and projected interest payments. Please read Note 8 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our long-term debt.
(b)	Represents net liabilities for commodity derivative contracts. With the exception of $43.2 million of deferred premiums on commodity derivative contracts, the ultimate settlement amounts of our commodity derivative contracts are unknown because they are subject to continuing market risk. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” and Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our commodity derivative contracts.
(c)	Represents net liabilities for interest rate swaps, the ultimate settlement of which are unknown because they are subject to continuing market risk. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” and Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our interest rate swaps.
(d)	Includes authorized purchases for work in process of $47.5 million and future minimum payments for drilling rig operations of $0.2 million. Also at September 30, 2009, we had approximately $155.1 million of authorized purchases not placed with vendors (authorized AFEs), which were not accrued and are excluded from the above table but are budgeted for and expected to be made unless circumstances change.
(e)	Includes office space and equipment obligations that have non-cancelable initial lease terms in excess of one year of $14.1 million and future minimum payments for other operating commitments of $0.5 million.
(f)	Represents the undiscounted future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal at the end of field life. Please read Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our asset retirement obligations.

     Other contingencies and commitments. In order to facilitate ongoing sales of our oil production in the CCA, we ship a portion of our production in pipelines downstream and sell to purchasers at major market hubs. From time to time, shipping delays, purchaser stipulations, or other conditions may require that we sell our oil production in periods subsequent to the period in which it is produced. In such case, the deferred sale would have an adverse effect in the period of production on reported production volumes, oil and natural gas revenues, and costs as measured on a unit-of-production basis.

     The marketing of our CCA oil production is mainly dependent on transportation through the Bridger, Poplar, and Butte pipelines to markets in the Guernsey, Wyoming area. Alternative transportation routes and markets have been developed by moving a portion of the crude oil production through the Enbridge Pipeline to the Clearbrook, Minnesota hub. To a lesser extent, our production also depends on transportation through the Platte Pipeline to Wood River, Illinois as well as other pipelines connected to the Guernsey, Wyoming area. While shipments on the Platte Pipeline are oversubscribed and subject to apportionment, we have been allocated sufficient pipeline capacity to move our crude oil production. An expansion of the Enbridge Pipeline was completed in early 2008, which moved the total Rockies area pipeline takeaway closer to a balancing point with increasing production volumes and thereby provided greater stability to oil differentials in the area. In spite of the increase in capacity, the Enbridge Pipeline continues to run at full capacity and is scheduled to complete an additional expansion by the beginning of 2010. However, further restrictions on available capacity to transport oil through any of the above-mentioned pipelines, any other pipelines, or any refinery upsets could have a material adverse effect on our production volumes and the prices we receive for our production.

     The difference between NYMEX market prices and the price received at the wellhead for oil and natural gas production is commonly referred to as a differential. In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have affected this differential. We cannot accurately predict future oil and natural gas differentials. Increases in the percentage differential between the NYMEX

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price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial position, and cash flows.

     Capital resources

     Cash flows from operating activities. Cash provided by operating activities increased $104.2 million from $529.0 million for the first nine months of 2008 to $633.2 million for the first nine months of 2009, primarily due to the monetization of certain of our 2009 oil derivative contracts in March 2009 and decreased settlements paid under our oil derivative contracts as a result of lower average oil prices in the first nine months of 2009 as compared to the first nine months of 2008, partially offset by a decrease in our production margin.

     Cash flows from investing activities. Cash used in investing activities increased $174.2 million from $536.1 million in the first nine months of 2008 to $710.3 million in the first nine months of 2009, primarily due to a $307.2 million increase in amounts paid to acquire oil and natural gas properties, namely our EXCO asset acquisition, partially offset by a $91.4 million decrease in amounts paid to develop oil and natural gas properties and a $38.7 million decrease in net advancements to working interest partners. During the first nine months of 2009, we collected $5.5 million (net of advancements) from ExxonMobil for their portion of costs incurred drilling wells under the joint development agreement. During the first nine months of 2008, we advanced $33.3 million (net of collections) to ExxonMobil for their portion of costs incurred drilling wells under the joint development agreement.

     Cash flows from financing activities. Our cash flows from financing activities consist primarily of proceeds from and payments on long-term debt and issuances of EAC shares of common stock and ENP common units. We periodically draw on our revolving credit facility to fund acquisitions and other capital commitments.

     During the first nine months of 2009, we received net cash of $81.8 million in financing activities, including $202.5 million of net proceeds from the issuance of the 9.5% Notes, $100.7 million of net proceeds from EAC’s issuance of common stock, and $170.1 million of net proceeds from ENP’s issuance of common units, partially offset by net repayments on revolving credit facilities of $285 million, payments for deferred commodity derivative contract premiums of $70.5 million, and ENP distributions to noncontrolling interests of $24.6 million. Net repayments decreased the outstanding borrowings under revolving credit facilities from $725 million at December 31, 2008 to $440 million at September 30, 2009.

     In October 2008, we announced that the Board approved a share repurchase program authorizing us to repurchase up to $40 million of our common stock. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions, and may be suspended or discontinued at any time. The share repurchase program will be funded using our available cash. As of September 30, 2009, we had repurchased and retired 620,265 shares of our outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. During the first nine months of 2009, we did not repurchase any shares of our outstanding common stock under the share repurchase program. As of September 30, 2009, approximately $22.8 million of our common stock remained authorized for repurchase.

     During the first nine months of 2008, we received net cash of $9.2 million from financing activities, including net borrowings on revolving credit facilities of $96.9 million, partially offset by $50 million of share repurchases, payments for deferred commodity derivative contract premiums of $30.8 million, and ENP distributions to noncontrolling interests of $19.5 million.

     Liquidity

     Our primary sources of liquidity are internally generated cash flows and the borrowing capacity under our revolving credit facility. We also have the ability to adjust the level of our capital expenditures. We may use other sources of capital, including the issuance of debt or equity securities, to fund acquisitions or maintain our financial flexibility. We believe that our internally generated cash flows and availability under our revolving credit facility will be sufficient to fund our planned capital expenditures for the foreseeable future. However, should commodity prices decline or the capital markets remain tight, the borrowing capacity under our revolving credit facilities could be adversely affected. In the event of a reduction in the borrowing base under our revolving credit facilities, we do not believe it will result in any required prepayments of indebtedness.

     We plan to make substantial capital expenditures in the future for the acquisition, exploitation, and development of oil and natural gas properties. We intend to finance these capital expenditures with cash flows from operations. We intend to finance our acquisition

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and future development and exploitation activities with a combination of cash flows from operations and issuances of debt, equity, or a combination thereof.

     Issuance of 9.5% Senior Subordinated Notes Due 2016. On April 27, 2009, we issued $225 million of our 9.5% Notes at 92.228 percent of par value. We used the net proceeds of approximately $202.5 million to reduce outstanding borrowings under our revolving credit facility. Interest on the 9.5% Notes is due semi-annually on May 1 and November 1, beginning November 1, 2009. The 9.5% Notes mature on May 1, 2016.

     Internally generated cash flows. Our internally generated cash flows, results of operations, and financing for our operations are largely dependent on oil and natural gas prices. During the first nine months of 2009, our average realized oil and natural gas prices decreased by 52 percent and 63 percent, respectively, as compared to the first nine months of 2008. Realized oil and natural gas prices fluctuate widely in response to changing market forces. If oil and natural gas prices decline or we experience a significant widening of our differentials, then our earnings, cash flows from operations, and borrowing base under our revolving credit facilities may be adversely impacted. Prolonged periods of lower oil and natural gas prices or sustained wider differentials could cause us to not be in compliance with financial covenants under our revolving credit facilities and thereby affect our liquidity. However, we have protected a portion of our forecasted production through 2012 against declining commodity prices. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” and Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our commodity derivative contracts.

     Revolving credit facilities. The syndicate of lenders underwriting our revolving credit facility includes 29 banking and other financial institutions, and the syndicate of lenders underwriting ENP’s revolving credit facility includes 15 banking and other financial institutions. None of the lenders are underwriting more than ten percent of the respective total commitment. We believe the number of lenders, the small percentage participation of each, and the level of availability under each facility provides adequate diversity and flexibility should further consolidation occur within the financial services industry.

     Encore Acquisition Company Credit Agreement

     In March 2007, we entered into a five-year amended and restated credit agreement (as amended, the “EAC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The EAC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, we amended the EAC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the EAC Credit Agreement. The EAC Credit Agreement provides for revolving credit loans to be made to us from time to time and letters of credit to be issued from time to time for the account of us or any of our restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the EAC Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. In March 2009, the borrowing base of our revolving credit facility was reaffirmed at $1.1 billion before a reduction of $200 million solely as a result of the monetization of certain of our 2009 oil derivative contracts during the first quarter of 2009. In addition, the provisions of the EAC Credit Agreement require the borrowing base to be reduced by 33 1/3 percent of the principal amount of the 9.5% Notes. As a result, the borrowing base on the EAC Credit Agreement was reduced by $75 million in April 2009. The reductions in the borrowing base under the EAC Credit Agreement did not result in any required prepayments of indebtedness. As of September 30, 2009, the borrowing base was $825 million.

     We incur a commitment fee on the unused portion of the EAC Credit Agreement determined based on the ratio of outstanding borrowings under the EAC Credit Agreement to the borrowing base in effect on such date. The following table summarizes the commitment fee percentage under the EAC Credit Agreement:

	Commitment
Ratio of Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .90 to 1		0.375	%
Greater than or equal to .90 to 1		0.500	%

     Obligations under the EAC Credit Agreement are secured by a first-priority security interest in substantially all of our restricted subsidiaries’ proved oil and natural gas reserves and in our equity interests in our restricted subsidiaries. In addition, obligations under the EAC Credit Agreement are guaranteed by our restricted subsidiaries.

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

	Applicable Margin for			Applicable Margin for
Ratio of Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.750	%		0.500	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.000	%		0.750	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.250	%		1.000	%
Greater than or equal to .90 to 1		2.500	%		1.250	%

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by us) is the rate equal to the British Bankers Association LIBOR for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0 percent.

     Any outstanding letters of credit reduce the availability under the EAC Credit Agreement. Borrowings under the EAC Credit Agreement may be repaid from time to time without penalty.

     The EAC Credit Agreement contains covenants including, among others, the following:

• 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 and our restricted subsidiaries’ assets, subject to permitted exceptions;

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

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

• a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

• a requirement that we maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0 (the “EAC Current Ratio”); and

• a requirement that we maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0 (the “EAC Interest Coverage Ratio”).

     In order to show EAC’s compliance with the covenants of the EAC Credit Agreement, the use of non-GAAP financial measures is required. The presentation of these non-GAAP financial measures provides useful information to investors as they allow readers to understand how much cushion there is between the required ratios and the actual ratios. These non-GAAP financial measures should not be considered an alternative to any measure of financial performance presented in accordance with GAAP.

     As of September 30, 2009, EAC was in compliance with all covenants in the EAC Credit Agreement, including the following financial covenants:

		Actual Ratio as of
Financial Covenant	Required Ratio	September 30, 2009
EAC Current Ratio	Minimum 1.0 to 1.0	3.3 to 1.0
EAC Interest Coverage Ratio	Minimum 2.5 to 1.0	9.4 to 1.0

     The following table shows the calculation of the EAC Current Ratio as of September 30, 2009 ($ in thousands):

EAC current assets	$	161,219
Availability under the EAC Credit Agreement		644,700
EAC consolidated current assets	$	805,919
Divided by: EAC consolidated current liabilities	$	244,299
EAC Current Ratio		3.3

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     The following table shows the calculation of the EAC Interest Coverage Ratio for the twelve months ended September 30, 2009 ($ in thousands):

EAC Consolidated EBITDA (a)	$	599,808
Divided by: EAC consolidated net interest expense and letter of credit fees	$	63,726
EAC Interest Coverage Ratio		9.4

(a) EAC Consolidated EBITDA is defined in the EAC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense. EAC Consolidated EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.

     The following table presents a calculation of EAC Consolidated EBITDA for the twelve months ended September 30, 2009 (in thousands) as required under the EAC Credit Agreement, together with a reconciliation of such amount to its most directly comparable financial measures calculated and presented in accordance with GAAP. This EBITDA measure should not be considered an alternative to consolidated net income (loss), operating income (loss), cash flow from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. This EBITDA measure may not be comparable to similarly titled measures of another company because all companies may not calculate this measure in the same manner.

EAC consolidated net income	$	108,314
EAC unrealized non-cash hedge gain		(21,456	)
EAC consolidated net interest expense		63,726
EAC income and franchise taxes		97,025
EAC depletion, depreciation, and amortization expense		242,358
EAC non-cash equity-based compensation		11,805
EAC exploration expense		82,638
EAC other non-cash		15,398
EAC Consolidated EBITDA	$	599,808

     The EAC Credit Agreement contains customary events of default, which would permit the lenders to accelerate the debt if not cured within applicable grace periods. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the EAC Credit Agreement to be immediately due and payable.

     On September 30, 2009, there were $180 million of outstanding borrowings, $0.3 million of outstanding letters of credit, and $644.7 million of borrowing capacity under the EAC Credit Agreement. On October 27, 2009, there were $200 million of outstanding borrowings, $0.3 million of outstanding letters of credit, and $624.7 million of borrowing capacity under the EAC Credit Agreement.

     Encore Energy Partners Operating LLC Credit Agreement

     In March 2007, OLLC entered into a five-year credit agreement (as amended, the “OLLC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The OLLC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, OLLC amended the OLLC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. Effective August 11, 2009, OLLC amended the OLLC Credit Agreement to, among other things, (1) increase the borrowing base from $240 million to $375 million, (2) increase the aggregate commitments of the lenders from $300 million to $475 million, and (3) increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $475 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. As of September 30, 2009, the borrowing base was $375 million.

     OLLC incurs a commitment fee of 0.5 percent on the unused portion of the OLLC Credit Agreement.

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     Obligations under the OLLC Credit Agreement are secured by a first-priority security interest in substantially all of OLLC’s proved oil and natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition, obligations under the OLLC Credit Agreement are guaranteed by ENP and OLLC’s restricted subsidiaries. We consolidate the debt of ENP with that of our own; however, obligations under the OLLC Credit Agreement are non-recourse to us and our restricted subsidiaries.

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

	Applicable Margin for			Applicable Margin for
Ratio of Outstanding Borrowings to Borrowing Base	Eurodollar Loans (a)			Base Rate Loans (a)
Less than .50 to 1		2.250	%		1.250	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.500	%		1.500	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.750	%		1.750	%
Greater than or equal to .90 to 1		3.000	%		2.000	%

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate equal to the British Bankers Association LIBOR for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0 percent.

     Any outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.

     The OLLC Credit Agreement contains covenants including, among others, the following:

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

• a prohibition against purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;

• a restriction on creating liens on the assets of ENP, OLLC, and OLLC’s restricted subsidiaries, subject to permitted exceptions;

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

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

• a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

• a requirement that ENP and OLLC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0 (the “ENP Current Ratio”);

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0 (the “ENP Interest Coverage Ratio”); and

• a requirement that ENP and OLLC maintain a ratio of consolidated funded debt to consolidated adjusted EBITDA of not more than 3.5 to 1.0 (the “ENP Leverage Ratio”).

     In order to show ENP’s and OLLC’s compliance with the covenants of the OLLC Credit Agreement, the use of non-GAAP financial measures is required. The presentation of these non-GAAP financial measures provides useful information to investors as they allow readers to understand how much cushion there is between the required ratios and the actual ratios. These non-GAAP financial measures should not be considered an alternative to any measure of financial performance presented in accordance with GAAP.

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     As of September 30, 2009, ENP and OLLC were in compliance with all covenants in the OLLC Credit Agreement, including the following financial covenants:

		Actual Ratio as of
Financial Covenant	Required Ratio	September 30, 2009
ENP Current Ratio	Minimum 1.0 to 1.0	5.1 to 1.0
ENP Interest Coverage Ratio	Minimum 2.5 to 1.0	10.8 to 1.0
ENP Leverage Ratio	Maximum 3.5 to 1.0	2.2 to 1.0

     The following table shows the calculation of the ENP Current Ratio as of September 30, 2009 ($ in thousands):

ENP current assets	$	54,806
Availability under the OLLC Credit Agreement		115,000
ENP consolidated current assets	$	169,806
Divided by: ENP consolidated current liabilities	$	33,567
ENP Current Ratio		5.1

     The following table shows the calculation of the ENP Interest Coverage Ratio for the twelve months ended September 30, 2009 ($ in thousands):

ENP Consolidated EBITDA (a)	$	98,721
Divided by:
ENP consolidated interest expense and letter of credit fees	$	9,204
ENP consolidated interest income		(36	)
ENP consolidated net interest expense and letter of credit fees	$	9,168
ENP Interest Coverage Ratio		10.8

(a) ENP Consolidated EBITDA is defined in the OLLC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense. ENP Consolidated EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.

     The following table shows the calculation of the ENP Leverage Ratio for the twelve months ended September 30, 2009 ($ in thousands):

ENP consolidated funded debt	$	260,000
Divided by: ENP Consolidated Adjusted EBITDA (a)	$	116,179
ENP Leverage Ratio		2.2

(a) ENP Consolidated Adjusted EBITDA is defined in the OLLC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense, after giving pro forma effect to one or more acquisitions or dispositions in excess of $20 million in the aggregate. ENP Consolidated Adjusted EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.

     The following table presents a calculation of ENP Consolidated EBITDA and ENP Consolidated Adjusted EBITDA for the twelve months ended September 30, 2009 (in thousands) as required under the OLLC Credit Agreement, together with a reconciliation of such amounts to their most directly comparable financial measures calculated and presented in accordance with GAAP. These EBITDA measures should not be considered an alternative to net income (loss), operating income (loss), cash flow from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. These EBITDA measures may not be comparable to similarly titled measures of another company because all companies may not calculate these measures in the same manner.

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ENP consolidated net income	$	90,122
ENP unrealized non-cash hedge gain		(51,881	)
ENP consolidated net interest expense		9,168
ENP income and franchise taxes		638
ENP depletion, depreciation, amortization, and exploration expense		47,282
ENP non-cash unit-based compensation		2,108
ENP other non-cash		1,284
ENP Consolidated EBITDA		98,721
Pro forma effect of acquisitions		17,458
ENP Consolidated Adjusted EBITDA	$	116,179

     The OLLC Credit Agreement contains customary events of default, which would permit the lenders to accelerate the debt if not cured within applicable grace periods. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately due and payable.

     On September 30, 2009 and October 27, 2009, there were $260 million of outstanding borrowings and $115 million of borrowing capacity under the OLLC Credit Agreement.

     Please read Note 8 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our long-term debt.

     Capitalization. At September 30, 2009, we had total assets of $3.7 billion and total capitalization of $2.9 billion, of which 57 percent was represented by equity and 43 percent by long-term debt. At December 31, 2008, we had total assets of $3.6 billion and total capitalization of $2.8 billion, of which 53 percent was represented by equity and 47 percent by long-term debt. The percentages of our capitalization represented by equity and long-term debt could vary in the future if debt or equity is used to finance capital projects or acquisitions.

Critical Accounting Policies and Estimates

     Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in our 2008 Annual Report on Form 10-K for information regarding our critical accounting policies and estimates.

New Accounting Pronouncements

     The effects of new accounting pronouncements are discussed in Note 2 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.”

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of exposure, but rather indicators of potential exposure. This information provides indicators of how we view and manage our ongoing market risk exposures. We do not enter into market risk sensitive instruments for speculative trading purposes.

     The information included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2008 Annual Report on Form 10-K is incorporated herein by reference. Such information includes a description of our potential exposure to market risks, including commodity price risk and interest rate risk.

Commodity Price Sensitivity

     Our commodity derivative contracts are discussed in Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” The counterparties to our commodity derivative contracts are a diverse group of seven institutions, all of

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which are currently rated A- or better by Standard & Poor’s and/or Fitch. As of September 30, 2009, the fair market value of our oil derivative contracts was a net asset of approximately $59.4 million and the fair market value of our natural gas derivative contracts was a net asset of approximately $11.0 million. These amounts exclude deferred premiums of $43.2 million that are not subject to changes in commodity prices. Based on our open commodity derivative positions at September 30, 2009, a 10 percent increase in the respective NYMEX prices for oil and natural gas would decrease our net commodity derivative asset by approximately $50.4 million, while a 10 percent decrease in the respective NYMEX prices for oil and natural gas would increase our net commodity derivative asset by approximately $52.4 million.

Interest Rate Sensitivity

     Our long-term debt is discussed in Note 8 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” At September 30, 2009, we had total long-term debt of $1.2 billion, net of discount of $21.5 million. Of this amount, $150 million bears interest at a fixed rate of 6.25 percent, $300 million bears interest at a fixed rate of 6.0 percent, $225 million bears interest at a fixed rate of 9.5 percent, and $150 million bears interest at a fixed rate of 7.25 percent. The remaining long-term debt balance of $440 million as of September 30, 2009 consisted of outstanding borrowings under revolving credit facilities, which are subject to floating market rates of interest that are linked to the Eurodollar rate.

     At this level of floating rate debt, if the Eurodollar rate increased by 10 percent, we would incur an additional $1.0 million of interest expense per year on revolving credit facilities, and if the Eurodollar rate decreased by 10 percent, we would incur $1.0 million less. Additionally, if the discount rates on our senior notes increased by 10 percent, we estimate the fair value of our fixed rate debt at September 30, 2009 would increase from approximately $790.5 million to approximately $794.0 million, and if the discount rates on our senior notes decreased by 10 percent, we estimate the fair value would decrease to approximately $787.1 million.

     ENP’s interest rate swaps are discussed in Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” As of September 30, 2009, the fair market value of ENP’s interest rate swaps was a net liability of approximately $4.1 million. If the Eurodollar rate increased by 10 percent, we estimate the liability would decrease to approximately $3.9 million, and if the Eurodollar rate decreased by 10 percent, we estimate the liability would increase to approximately $4.4 million.

Item 4. Controls and Procedures

     In accordance with the Securities Exchange Act of 1934 (the “Exchange Act”) Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2009 to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

     There were no changes in our internal control over financial reporting during the third quarter of 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

     We are a party to ongoing legal proceedings in the ordinary course of business. Management does not believe the result of these legal proceedings will have a material adverse effect on our business, financial condition, results of operations, or liquidity.

Item 1A. Risk Factors

     In addition to the other information set forth in this Report, you should carefully consider the factors discussed in “Item 1A. Risk Factors” and elsewhere in our 2008 Annual Report on Form 10-K, which could materially affect our business, financial condition, or results of operations. The risks described in our 2008 Annual Report on Form 10-K are not the only risks we face. Unknown risks and uncertainties or risks and uncertainties that we currently believe to be immaterial may also have a material adverse effect on our business, financial condition, or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

     In October 2008, the Board approved a share repurchase program authorizing us to repurchase up to $40 million of our common stock. As of September 30, 2009, we had repurchased and retired 620,265 shares of our outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. During the third quarter of 2009, we did not repurchase any shares of our outstanding common stock under the share repurchase program. As of September 30, 2009, approximately $22.8 million of our common stock remained authorized for repurchase.

     The following table summarizes purchases of our common stock during the third quarter of 2009:

					Total Number of		Approximate Dollar
					Shares Purchased		Value of Shares
	Total Number				as Part of Publicly		That May Yet Be
	of Shares		Average Price		Announced Plans		Purchased Under the
Month	Purchased		Paid per Share		or Programs		Plans or Programs
July		—	$	—		—
August		—	$	—		—
September		—	$	—		—
Total		—	$	—		—	$	22,830,139

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EX-99.5

Exhibit 99.5

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): January 25, 2010

ENCORE ACQUISITION COMPANY

(Exact name of registrant as specified in its charter)

Delaware	001-16295	75-2759650
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

777 Main Street, Suite 1400, Fort Worth, Texas	76102
(Address of principal executive offices)	(Zip Code)

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

Not applicable (Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o      Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o      Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o      Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o      Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01 Other Events.

     On January 1, 2009, Encore Acquisition Company (together with its subsidiaries, “EAC”) adopted new guidance issued by the Financial Accounting Standards Board on the accounting for noncontrolling interests and new guidance relating to the treatment of equity-based payment transactions in the calculation of earnings per share.

     In August 2009, Encore Operating, L.P. (“Encore Operating”), a wholly owned subsidiary of EAC, sold certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota to Encore Energy Partners LP (together with its subsidiaries, “ENP”). In June 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Williston Basin in North Dakota and Montana to ENP. In January 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres, to ENP. Because these assets were sold to an affiliate, the dispositions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby ENP recorded the assets and liabilities of the acquired properties at Encore Operating’s carrying value and ENP’s historical financial information was recast to include the acquired properties for all periods presented. EAC has recast segment information in its consolidated financial statements to reflect these transactions.

     Accordingly, EAC has recast certain information included in its 2008 Annual Report on Form 10-K (the “2008 Annual Report”) filed with the United States Securities and Exchange Commission (“SEC”) on February 24, 2009 as follows:

• Item 6. Selected Financial Data;

• Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations; and

• Item 8. Financial Statements and Supplementary Data.

     The recast financial information is filed as Exhibits 99.1, 99.2, and 99.3 to this Current Report on Form 8-K (the “Report”) and is incorporated herein by reference. Except with respect to the limited matters described above, the recast information included in this Report has not been updated to reflect events subsequent to the filing of the 2008 Annual Report. This Report should be read in conjunction with the portions of the 2008 Annual Report that have not been recast herein, as well as in conjunction with EAC’s other filings with the SEC.

     All references in this Report to “EAC,” “we,” “us,” “our,” and similar terms refer to Encore Acquisition Company and its subsidiaries.

Cautionary Statement Regarding Forward-Looking Statements

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

• items of income and expense (including, without limitation, lease operating expense, production taxes, depletion, depreciation, and amortization expense, general and administrative expense, and effective income tax rates);

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

• areas of future growth;

• our development and exploitation programs;

• future secondary development and tertiary recovery potential;

• anticipated prices for oil and natural gas and expectations regarding differentials between wellhead prices and benchmark prices (including, without limitation, the effects of the worldwide economic recession);

• projected results of operations;

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

• availability of pipeline capacity;

• expected commodity derivative positions and payments related thereto (including the ability of counterparties to fulfill obligations);

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

• projected borrowings or repayments under our revolving credit facility (and the ability of lenders to fund their commitments); and

• the marketing of our oil and natural gas production.

     You are cautioned not to place undue reliance on such forward-looking statements, which speak only as of the date of this Report. Our actual results may differ significantly from the results discussed in the forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, the matters discussed in “Item 1A. Risk Factors” and elsewhere in our 2008 Annual Report and in our other filings with the SEC. If one or more of these risks or uncertainties materialize (or the consequences of such a development changes), or should underlying assumptions prove incorrect, actual outcomes may vary materially from those forecasted or expected. We undertake no responsibility to update forward-looking statements for changes related to these or any other factors that may occur subsequent to this filing for any reason.

Item 9.01 Financial Statements and Exhibits

     (d) Exhibits

99.1	Selected Financial Data.
99.2	Management’s Discussion and Analysis of Financial Condition and Results of Operations.
99.3	Financial Statements and Supplementary Data.

SIGNATURE

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	ENCORE ACQUISITION COMPANY
Date: January 25, 2010	By:	/s/ Andrea Hunter
		Andrea Hunter
		Vice President, Controller, and Principal Accounting Officer

EXHIBIT INDEX

Exhibit No.	Description
99.1	Selected Financial Data.
99.2	Management’s Discussion and Analysis of Financial Condition and Results of Operations.
99.3	Financial Statements and Supplementary Data.

Exhibit 99.1

ENCORE ACQUISITION COMPANY

ITEM 6. SELECTED FINANCIAL DATA

     The selected financial data shown below as of December 31, 2008 and 2007 and for the years ended December 31, 2008, 2007, and 2006 (collectively, the “Recast Financial Statements”) was derived from our recast audited consolidated financial statements. The selected historical financial data shown below as of December 31, 2006, 2005, and 2004 and for the years ended December 31, 2005 and 2004 was derived from recast unaudited consolidated financial statements. The following recast selected financial and operating data should be read in conjunction with our recast “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our Recast Financial Statements included as Exhibits 99.2 and 99.3, respectively, to this Current Report on Form 8-K.

	Year Ended December 31, (a)
	2008			2007			2006			2005			2004
	(in thousands, except per share and per unit amounts)
Consolidated Statements of Operations Data:
Revenues (b):
Oil	$	897,443		$	562,817		$	346,974		$	307,959		$	220,649
Natural gas		227,479			150,107			146,325			149,365			77,884
Marketing (c)		10,496			42,021			147,563			—			—
Total revenues		1,135,418			754,945			640,862			457,324			298,533
Expenses:
Production:
Lease operating (d)		175,115			143,426			98,194			69,744			47,807
Production, ad valorem, and severance taxes		110,644			74,585			49,780			45,601			30,313
Depletion, depreciation, and amortization		228,252			183,980			113,463			85,627			48,522
Impairment of long-lived assets (e)		59,526			—			—			—			—
Exploration		39,207			27,726			30,519			14,443			3,935
General and administrative (d)		48,421			39,124			23,194			17,268			12,059
Marketing (c)		9,570			40,549			148,571			—			—
Derivative fair value loss (gain) (f)		(346,236	)		112,483			(24,388	)		5,290			5,011
Loss on early redemption of debt (g)		—			—			—			19,477			—
Provision for doubtful accounts		1,984			5,816			1,970			231			—
Other operating		12,975			17,066			8,053			9,254			5,028
Total expenses		339,458			644,755			449,356			266,935			152,675
Operating income		795,960			110,190			191,506			190,389			145,858
Other income (expenses):
Interest		(73,173	)		(88,704	)		(45,131	)		(34,055	)		(23,459	)
Other		3,898			2,667			1,429			1,039			240
Total other expenses		(69,275	)		(86,037	)		(43,702	)		(33,016	)		(23,219	)
Income before income taxes		726,685			24,153			147,804			157,373			122,639
Income tax provision		(241,621	)		(14,476	)		(55,406	)		(53,948	)		(40,492	)
Consolidated net income		485,064			9,677			92,398			103,425			82,147
Less: net loss (income) attributable to noncontrolling interest		(54,252	)		7,478			—			—			—
Net income attributable to EAC stockholders	$	430,812		$	17,155		$	92,398		$	103,425		$	82,147
Net income per common share:
Basic	$	8.10		$	0.32		$	1.75		$	2.10		$	1.73	(h)
Diluted	$	8.01		$	0.31		$	1.74		$	2.07		$	1.71	(h)
Weighted average common shares outstanding:
Basic		52,270			53,170			51,865			48,682			47,090	(h)
Diluted		52,866			53,629			52,356			49,303			47,522	(h)
Total Production Volumes:
Oil (Bbls)		10,050			9,545			7,335			6,871			6,679
Natural gas (Mcf)		26,374			23,963			23,456			21,059			14,089
Combined (BOE)		14,446			13,539			11,244			10,381			9,027
Average Realized Prices:
Oil ($/Bbl)	$	89.30		$	58.96		$	47.30		$	44.82		$	33.04
Natural gas ($/Mcf)		8.63			6.26			6.24			7.09			5.53
Combined ($/BOE)		77.87			52.66			43.87			44.05			33.07
Average Costs per BOE:
Lease operating (d)	$	12.12		$	10.59		$	8.73		$	6.72		$	5.30
Production, ad valorem, and severance taxes		7.66			5.51			4.43			4.39			3.36
Depletion, depreciation, and amortization		15.80			13.59			10.09			8.25			5.38
Impairment of long-lived assets (e)		4.12			—			—			—			—
Exploration		2.71			2.05			2.71			1.39			0.44
General and administrative (d)		3.35			2.89			2.06			1.67			1.33
Derivative fair value loss (gain) (f)		(23.97	)		8.31			(2.17	)		0.51			0.56
Provision for doubtful accounts		0.14			0.43			0.18			0.02			—
Other operating		0.90			1.26			0.72			0.89			0.56
Marketing, net of revenues (c)		(0.06	)		(0.11	)		0.09			—			—
Consolidated Statements of Cash Flows Data:
Cash provided by (used in):
Operating activities	$	663,237		$	319,707		$	297,333		$	292,269		$	171,821
Investing activities		(728,346	)		(929,556	)		(397,430	)		(573,560	)		(433,470	)
Financing activities		65,444			610,790			99,206			281,842			262,321

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ENCORE ACQUISITION COMPANY

	As of December 31, (a)
	2008		2007			2006			2005			2004
	(in thousands)
Proved Reserves:
Oil (Bbls)		134,452		188,587			153,434			148,387			134,048
Natural gas (Mcf)		307,520		256,447			306,764			283,865			234,030
Combined (BOE)		185,705		231,328			204,561			195,698			173,053
Consolidated Balance Sheets Data:
Working capital	$	188,678	$	(16,220	)	$	(40,745	)	$	(56,838	)	$	(15,566	)
Total assets		3,633,195		2,784,561			2,006,900			1,705,705			1,123,400
Long-term debt		1,319,811		1,120,236			661,696			673,189			379,000
Equity		1,483,248		1,070,689			816,865			546,781			473,575

(a)	We acquired certain oil and natural gas properties and related assets in the Big Horn and Williston Basins in March 2007 and April 2007, respectively. We also acquired Crusader Energy Corporation in October 2005 and Cortez Oil & Gas, Inc. in April 2004. The operating results of these acquisitions are included with ours from the date of acquisition forward. We disposed of certain oil and natural gas properties and related assets in the Mid-Continent in June 2007. The operating results of this disposition are included with ours through the date of disposition.
(b)	For 2008, 2007, 2006, 2005, and 2004, we reduced oil and natural gas revenues for net profits interests owned by others by $56.5 million, $32.5 million, $23.4 million, $21.2 million, and $12.6 million, respectively.
(c)	In 2006, we began purchasing third-party oil Bbls from a counterparty other than to whom the Bbls were sold for aggregation and sale with our own equity production in various markets. These purchases assisted us in marketing our production by decreasing our dependence on individual markets. These activities allowed us to aggregate larger volumes, facilitated our efforts to maximize the prices we received for production, provided for a greater allocation of future pipeline capacity in the event of curtailments, and enabled us to reach other markets. In 2007, we discontinued purchasing oil from third party companies as market conditions changed and pipeline space was gained. Implementing this change allowed us to focus on the marketing of our own oil production, leveraging newly gained pipeline space, and delivering oil to various newly developed markets in an effort to maximize the value of the oil at the wellhead. In March 2007, ENP acquired a natural gas pipeline as part of the Big Horn Basin asset acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet to the pipeline and resold downstream to various local and off-system markets. Marketing expenses include pipeline tariffs, storage, truck facility fees, and tank bottom costs used to support the sale of equity crude, the revenues of which are included in our oil revenues instead of marketing revenues.
(d)	On January 1, 2006, we adopted new guidance issued by the FASB in the “Compensation — Stock Compensation” topic of the FASC. Due to the adoption, non-cash equity-based compensation expense for 2005 and 2004 has been reclassified to allocate the amount to the same respective income statement lines as the respective employees’ cash compensation. This resulted in increases in LOE of $1.3 million and $0.7 million during 2005 and 2004, respectively, increases in general and administrative expense of $2.6 million and $1.1 million during 2005 and 2004, respectively.
(e)	During 2008, circumstances indicated that the carrying amounts of certain oil and natural gas properties, primarily four wells in the Tuscaloosa Marine Shale, may not be recoverable. We compared the assets’ carrying amounts to the undiscounted expected future net cash flows, which indicated a need for an impairment charge. We then compared the net carrying amounts of the impaired assets to their estimated fair value, which resulted in a write-down of the value of proved oil and natural gas properties of $59.5 million. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes, discounted to a present value.
(f)	During July 2006, we elected to discontinue hedge accounting prospectively for all of our remaining commodity derivative contracts which were previously accounted for as hedges. From that point forward, mark-to-market gains or losses on commodity derivative contracts are recorded in “Derivative fair value loss (gain)” while in periods prior to that point, only the ineffective portions of commodity derivative contracts which were designated as hedges were recorded in “Derivative fair value loss (gain).”
(g)	In 2005, we recorded a $19.5 million loss on early redemption of debt related to the redemption premium and the expensing of unamortized debt issuance costs of our 8 3/8% Senior Subordinated Notes due 2012. We redeemed all $150 million of such notes with proceeds received from the issuance of $300 million of our 6.0% Senior Subordinated Notes due 2015.
(h)	Adjusted for the effects of the 3-for-2 stock split in July 2005.

2

Exhibit 99.2

ENCORE ACQUISITION COMPANY

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

     On January 1, 2009, Encore Acquisition Company (together with its subsidiaries, “EAC”) adopted new guidance issued by the Financial Accounting Standards Board (the “FASB”) on the accounting for noncontrolling interests and new guidance relating to the treatment of equity-based payment transactions in the calculation of earnings per share.

     In August 2009, Encore Operating, L.P. (“Encore Operating”), a wholly owned subsidiary of EAC, sold certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota to Encore Energy Partners LP (together with its subsidiaries, “ENP”). In June 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Williston Basin in North Dakota and Montana to ENP. In January 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres, to ENP. Because these assets were sold to an affiliate, the dispositions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby ENP recorded the assets and liabilities of the acquired properties at Encore Operating’s carrying value and ENP’s historical financial information was recast to include the acquired properties for all periods presented.

     The following recast discussion and analysis of our consolidated financial condition and results of operations should be read in conjunction with our recast consolidated financial statements and notes and supplementary data thereto as of December 31, 2008 and 2007 and for the years ended December 31, 2008, 2007, and 2006 (collectively, the “Recast Financial Statements”) included as Exhibit 99.3 to this Current Report on Form 8-K. The following recast discussion and analysis contains forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions, and resources. Actual results could differ materially from those discussed in the forward-looking statements. We do not undertake to update, revise, or correct any of the forward-looking information unless required to do so under federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with our disclosures under “Cautionary Statement Regarding Forward-Looking Statements” included in this Current Report on Form 8-K and “Item 1A. Risk Factors” included in our 2008 Annual Report.

Introduction

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

• Overview of Business

• 2008 Highlights

• Recent Developments

• 2009 Outlook

• Results of Operations

— Comparison of 2008 to 2007

— Comparison of 2007 to 2006

• Capital Commitments, Capital Resources, and Liquidity

• Changes in Prices

• Critical Accounting Policies and Estimates

• New Accounting Pronouncements

• Information Concerning Forward-Looking Statements

Overview of Business

     We are a Delaware corporation engaged in the acquisition, development, exploitation, exploration, and production of oil and natural gas reserves from onshore fields in the United States. Our business strategies include:

• Maintaining an active development program to maximize existing reserves and production;

• Utilizing enhanced oil recovery techniques to maximize existing reserves and production;

• Expanding our reserves, production, and development inventory through a disciplined acquisition program;

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ENCORE ACQUISITION COMPANY

• Exploring for reserves; and

• Operating in a cost effective, efficient, and safe manner.

     At December 31, 2008, our oil and natural gas properties had estimated total proved reserves of 134.5 MMBbls of oil and 307.5 Bcf of natural gas, based on December 31, 2008 spot market prices of $44.60 per Bbl of oil and $5.62 per Mcf of natural gas. On a BOE basis, our proved reserves were 185.7 MMBOE at December 31, 2008, of which approximately 72 percent was oil and approximately 80 percent was proved developed. Based on 2008 production, our ratio of reserves to production was approximately 12.9 years for total proved reserves and 10.3 years for proved developed reserves as of December 31, 2008.

     Our financial results and ability to generate cash depend upon many factors, particularly the price of oil and natural gas. Average NYMEX oil prices strengthened in the first half of 2008 to record levels, but have since experienced a significant deterioration. In addition, our oil wellhead differentials to NYMEX improved in 2008 as we realized 90 percent of the average NYMEX oil price, as compared to 88 percent in 2007. Average NYMEX natural gas prices strengthened in the first half of 2008 to their highest levels since 2005, but have since experienced a significant deterioration. Our natural gas wellhead differentials to NYMEX deteriorated slightly in 2008 as we realized 95 percent of the average NYMEX natural gas price, as compared to 98 percent in 2007. Commodity prices are influenced by many factors that are outside of our control. We cannot accurately predict future commodity prices. For this reason, we attempt to mitigate the effect of commodity price risk by entering into commodity derivative contracts for a portion of our forecasted future production. For a discussion of factors that influence commodity prices and risks associated with our commodity derivative contracts, please read “Item 1A. Risk Factors” included in our 2008 Annual Report.

     During 2008, we did not make a significant acquisition of proved reserves. Instead, we acquired unproved acreage in our core areas, continued to make significant investments within our core areas to develop proved undeveloped reserves and increase production from proved developed reserves through various recovery techniques, and made significant investments for exploration within our areas of unproved acreage. We continue to believe that a portfolio of long-lived quality assets will position us for future success.

     In May 2008, we announced that our Board had authorized our management team to explore a broad range of strategic alternatives to further enhance shareholder value, including, but not limited to, a sale or merger of the company. In conjunction, our Board approved a retention plan for all of our then-current employees, excluding members of our strategic team, providing for the payment of four months of base salary or base rate of pay, as applicable, upon the completion of the strategic alternatives process, subject to continued employment. This bonus was paid in August 2008.

     In July 2008, our Board and management team decided that a sale or merger of the company was not currently in the best interest of our shareholders. In conjunction, our Board approved a separate retention plan for all of our then-current employees, excluding our Chairman and Chief Executive Officer, providing for the payment of eight months of base salary or base rate of pay, as applicable, in August 2009, subject to continued employment.

     Our 2008 results of operations include approximately $7.6 million of pre-tax expense related to the four-month retention plan and approximately $6.9 million of pre-tax expense related to the eight-month retention plan.

2008 Highlights

     Our financial and operating results for 2008 included the following:

• Our oil and natural gas revenues increased 58 percent to $1.1 billion as compared to $712.9 million in 2007 as a result of increased production volumes and higher average realized prices.

• Our average realized oil price increased 51 percent to $89.30 per Bbl as compared to $58.96 per Bbl in 2007. Our average realized natural gas price increased 38 percent to $8.63 per Mcf as compared to $6.26 per Mcf in 2007.

• Our average daily production volumes increased six percent to 39,470 BOE/D as compared to 37,094 BOE/D in 2007. Oil represented 70 percent and 71 percent of our total production volumes in 2008 and 2007, respectively.

• Our production margin (defined as oil and natural gas wellhead revenues less production expenses) increased 54 percent to $842.0 million as compared to $548.5 million in 2007. Total oil and natural gas wellhead revenues per BOE increased by 38 percent while total production expenses per BOE increased by 23 percent. On a per BOE basis, our production margin increased 44 percent to $58.29 per BOE as compared to $40.52 per BOE for 2007.

• We reported record net income attributable to EAC stockholders for 2008, which increased to $430.8 million ($8.01 per diluted share) from the $17.2 million ($0.31 per diluted share) reported for 2007.

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ENCORE ACQUISITION COMPANY

• We invested $775.9 million in oil and natural gas activities (excluding asset retirement obligations of $0.6 million), of which $618.5 million was invested in development, exploitation, and exploration activities, yielding 282 gross (104.8 net) productive wells, and $157.4 million was invested in acquisitions, primarily of unproved acreage.

Recent Developments

     In January 2009, we sold certain oil and natural gas producing properties and related assets in the Arkoma Basin and royalty interest properties in Oklahoma as well as 10,300 unleased mineral acres to ENP. The sales price was $49 million in cash, subject to customary adjustments (including a reduction in the purchase price for acquisition-related commodity derivative premiums of approximately $3 million).

2009 Outlook

     For 2009, the Board has approved a $310 million capital budget for oil and natural gas related activities, excluding proved property acquisitions. We expect to fund our 2009 capital expenditures within cash flows from operations and use the additional cash flows from operations to reduce our debt levels. The following table represents the components of our 2009 capital budget (in thousands):

Drilling	$	215,000
Improved oil recovery, workovers		60,000
Land, seismic, and other		35,000
Total	$	310,000

     The prices we receive for our oil and natural gas production are largely based on current market prices, which are beyond our control. For comparability and accountability, we take a constant approach to budgeting commodity prices. We presently analyze our inventory of capital projects based on management’s outlook of future commodity prices. If NYMEX prices continue trend downward, we may further reevaluate our capital projects. Since the end of 2008, oil NYMEX prices have declined from $44.60 per Bbl to below $39.00 per Bbl in mid-February 2009 and natural gas NYMEX prices have declined from $5.62 per Mcf to below $4.25 per Mcf over the same period. The price risk on a significant portion of our forecasted oil and natural gas production for 2009 is mitigated using commodity derivative contracts. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” for additional information regarding our commodity derivative contracts. We intend to continue to enter into commodity derivative transactions to mitigate the impact of price volatility on our oil and natural gas revenues. Significant factors that will impact near-term commodity prices include the following:

• the duration and severity of the worldwide economic recession;

• 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;

• the level of economic growth in China, India, and other developing countries;

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

• the level of interest rates;

• oilfield service costs;

• the potential for terrorist activity; and

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

     We expect to continue to pursue asset acquisitions, but expect to confront intense competition for these assets from third parties.

     First Quarter 2009 Outlook

     We expect our total average daily production volumes to be approximately 39,900 to 41,100 BOE/D in the first quarter of 2009, net of average daily net profits production volumes of approximately 900 to 1,100 BOE/D. We expect our oil wellhead differentials as a percentage of NYMEX to widen in the first quarter of 2009 to a negative 22 percent as compared to the negative 20 percent differential we realized in the fourth quarter of 2008. We expect our natural gas wellhead differentials as a percentage of NYMEX to improve in the first quarter of 2009 to a positive three percent as compared to the negative 14 percent differential we realized in the fourth quarter of 2008.

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ENCORE ACQUISITION COMPANY

     In the first quarter of 2009, we expect our LOE to average $12.75 to $13.25 per BOE, including approximately $2.5 million ($0.68 per BOE) for retention bonuses related to the strategic alternatives process to be paid in August 2009. We expect our production taxes to average approximately 9.5 percent of wellhead revenues in the first quarter of 2009. In the first quarter of 2009, we expect our depletion, depreciation, and amortization (“DD&A”) expense to average $18.00 to $18.50 per BOE. In the first quarter of 2009, we expect our G&A expense to average $3.50 to $4.00 per BOE, including approximately $1.7 million ($0.46 per BOE) for retention bonuses related to the strategic alternatives process to be paid in August 2009.

     During the first quarter of 2009, we expect our effective tax rate to be approximately 38 percent, 95 percent of which is expected to be deferred.

     We do not expect to reduce our total debt levels during the first quarter of 2009.

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ENCORE ACQUISITION COMPANY

Results of Operations

Comparison of 2008 to 2007

     Oil and natural gas revenues. The following table illustrates the components of oil and natural gas revenues for the periods indicated, as well as each period’s respective production volumes and average prices:

	Year Ended December 31,						Increase
	2008			2007			$		%
Revenues (in thousands):
Oil wellhead	$	900,300		$	606,112		$	294,188
Oil commodity derivative contracts		(2,857	)		(43,295	)		40,438
Total oil revenues	$	897,443		$	562,817		$	334,626		59	%
Natural gas wellhead	$	227,479		$	160,399		$	67,080
Natural gas commodity derivative contracts		—			(10,292	)		10,292
Total natural gas revenues	$	227,479		$	150,107		$	77,372		52	%
Combined wellhead	$	1,127,779		$	766,511		$	361,268
Combined commodity derivative contracts		(2,857	)		(53,587	)		50,730
Total combined oil and natural gas revenues	$	1,124,922		$	712,924		$	411,998		58	%
Average realized prices:
Oil wellhead ($/Bbl)	$	89.58		$	63.50		$	26.08
Oil commodity derivative contracts ($/Bbl)		(0.28	)		(4.54	)		4.26
Total oil revenues ($/Bbl)	$	89.30		$	58.96		$	30.34		51	%
Natural gas wellhead ($/Mcf)	$	8.63		$	6.69		$	1.94
Natural gas commodity derivative contracts ($/Mcf)		—			(0.43	)		0.43
Total natural gas revenues ($/Mcf)	$	8.63		$	6.26		$	2.37		38	%
Combined wellhead ($/BOE)	$	78.07		$	56.62		$	21.45
Combined commodity derivative contracts ($/BOE)		(0.20	)		(3.96	)		3.76
Total combined oil and natural gas revenues ($/BOE)	$	77.87		$	52.66		$	25.21		48	%
Total production volumes:
Oil (MBbls)		10,050			9,545			505		5	%
Natural gas (MMcf)		26,374			23,963			2,411		10	%
Combined (MBOE)		14,446			13,539			907		7	%
Average daily production volumes:
Oil (Bbl/D)		27,459			26,152			1,307		5	%
Natural gas (Mcf/D)		72,060			65,651			6,409		10	%
Combined (BOE/D)		39,470			37,094			2,376		6	%
Average NYMEX prices:
Oil (per Bbl)	$	99.75		$	72.45		$	27.30		38	%
Natural gas (per Mcf)	$	9.04		$	6.86		$	2.18		32	%

     Oil revenues increased 59 percent from $562.8 million in 2007 to $897.4 million in 2008 as a result of an increase in our average realized oil price and an increase in oil production volumes of 505 MBbls. The increase in oil production volumes contributed approximately $32.1 million in additional oil revenues and was primarily the result of a full year of production from our Big Horn Basin acquisition in March 2007 and our Williston Basin acquisition in April 2007, as well as our development program in the Bakken.

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ENCORE ACQUISITION COMPANY

     Our average realized oil price increased $30.34 per Bbl from 2007 to 2008 primarily as a result of an increase in our average realized oil wellhead price, which increased oil revenues by approximately $262.1 million, or $26.08 per Bbl. Our average realized oil wellhead price increased primarily as a result of the increase in the average NYMEX price from $72.45 per Bbl in 2007 to $99.75 per Bbl in 2008.

     During July 2006, we elected to discontinue hedge accounting prospectively for all remaining commodity derivative contracts which were previously accounted for as hedges. While this change had no effect on our cash flows, results of operations are affected by mark-to-market gains and losses, which fluctuate with the changes in oil and natural gas prices. As a result, oil revenues for 2008 included amortization of net losses on certain commodity derivative contracts that were previously designated as hedges of approximately $2.9 million, or $0.28 per Bbl, while 2007 included approximately $43.3 million, or $4.54 per Bbl, of net losses.

     Our average daily production volumes were decreased by 1,530 BOE/D and 1,466 BOE/D in 2008 and 2007, respectively, for net profits interests related to our CCA properties, which reduced our oil wellhead revenues by $55.3 million and $31.9 million in 2008 and 2007, respectively.

     Natural gas revenues increased 52 percent from $150.1 million in 2007 to $227.5 million in 2008 as a result of an increase in our average realized natural gas price and an increase in natural gas production volumes of 2,411 MMcf. The increase in natural gas production volumes contributed approximately $16.1 million in additional natural gas revenues and was primarily the result of our development program in our Permian Basin and Mid-Continent regions.

     Our average realized natural gas price increased $2.37 per Mcf from 2007 to 2008 primarily as a result of an increase in our average realized natural gas wellhead price, which increased natural gas revenues by approximately $50.9 million, or $1.94 per Mcf. Our average realized natural gas wellhead price increased primarily as a result of the increase in the average NYMEX price from $6.86 per Mcf in 2007 to $9.04 per Mcf in 2008. In addition, as a result of our discontinuance of hedge accounting in July 2006, natural gas revenues for 2007 included amortization of net losses on certain commodity derivative contracts that were previously designated as hedges of approximately $10.3 million, or $0.43 per Mcf.

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

	Year Ended December 31,
	2008			2007
Oil wellhead ($/Bbl)	$	89.58		$	63.50
Average NYMEX ($/Bbl)	$	99.75		$	72.45
Differential to NYMEX	$	(10.17	)	$	(8.95	)
Oil wellhead to NYMEX percentage		90	%		88	%
Natural gas wellhead ($/Mcf)	$	8.63		$	6.69
Average NYMEX ($/Mcf)	$	9.04		$	6.86
Differential to NYMEX	$	(0.41	)	$	(0.17	)
Natural gas wellhead to NYMEX percentage		95	%		98	%

     Our oil wellhead price as a percentage of the average NYMEX price was 90 percent in 2008 as compared to 88 percent in 2007. Our natural gas wellhead price as a percentage of the average NYMEX price was 95 percent in 2008 as compared to 98 percent in 2007.

     Marketing revenues and expenses. In 2007, we discontinued purchasing oil from third party companies as market conditions changed and pipeline space was gained. Implementing this change allowed us to focus on the marketing of our own oil production, leveraging newly gained pipeline space, and delivering oil to various newly developed markets in an effort to maximize the value of the oil at the wellhead. In March 2007, ENP acquired a natural gas pipeline from Anadarko as part of the Big Horn Basin asset acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet to the pipeline and resold downstream to various local and off-system markets. Marketing expenses include pipeline tariffs, storage, truck facility fees, and tank bottom costs used to support the sale of oil production, the revenues of which are included in our oil revenues instead of marketing revenues. The following table summarizes our marketing activities for the periods indicated:

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ENCORE ACQUISITION COMPANY

	Year ended December 31,				Decrease
	2008		2007		$			%
	($ in thousands, except per BOE amounts)
Marketing revenues	$	10,496	$	42,021	$	(31,525	)		-75	%
Marketing expenses		9,570		40,549		(30,979	)		-76	%
Marketing gain	$	926	$	1,472	$	(546	)		-37	%
Marketing revenues per BOE	$	0.72	$	3.10	$	(2.38	)		-77	%
Marketing expenses per BOE		0.66		2.99		(2.33	)		-78	%
Marketing gain, per BOE	$	0.06	$	0.11	$	(0.05	)		-45	%

     Expenses. The following table summarizes our expenses, excluding marketing expenses shown above, for the periods indicated:

	Year Ended December 31,					Increase / (Decrease)
	2008			2007		$			%
Expenses (in thousands):
Production:
Lease operations	$	175,115		$	143,426	$	31,689
Production, ad valorem, and severance taxes		110,644			74,585		36,059
Total production expenses		285,759			218,011		67,748			31	%
Other:
Depletion, depreciation, and amortization		228,252			183,980		44,272
Impairment of long-lived assets		59,526			—		59,526
Exploration		39,207			27,726		11,481
General and administrative		48,421			39,124		9,297
Derivative fair value loss (gain)		(346,236	)		112,483		(458,719	)
Provision for doubtful accounts		1,984			5,816		(3,832	)
Other operating		12,975			17,066		(4,091	)
Total operating		329,888			604,206		(274,318	)		-45	%
Interest		73,173			88,704		(15,531	)
Income tax provision		241,621			14,476		227,145
Total expenses	$	644,682		$	707,386	$	(62,704	)		-9	%
Expenses (per BOE):
Production:
Lease operations	$	12.12		$	10.59	$	1.53
Production, ad valorem, and severance taxes		7.66			5.51		2.15
Total production expenses		19.78			16.10		3.68			23	%
Other:
Depletion, depreciation, and amortization		15.80			13.59		2.21
Impairment of long-lived assets		4.12			—		4.12
Exploration		2.71			2.05		0.66
General and administrative		3.35			2.89		0.46
Derivative fair value loss (gain)		(23.97	)		8.31		(32.28	)
Provision for doubtful accounts		0.14			0.43		(0.29	)
Other operating		0.90			1.26		(0.36	)
Total operating		22.83			44.63		(21.80	)		-49	%
Interest		5.07			6.55		(1.48	)
Income tax provision		16.73			1.07		15.66
Total expenses	$	44.63		$	52.25	$	(7.62	)		-15	%

     Production expenses. Total production expenses increased 31 percent from $218.0 million in 2007 to $285.8 million in 2008 as a result of higher total production volumes and an increase in the per BOE rate.

     Production expense attributable to LOE increased $31.7 million from $143.4 million in 2007 to $175.1 million in 2008 as a result

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ENCORE ACQUISITION COMPANY

of a $1.53 increase in the average per BOE rate, which contributed approximately $22.1 million of additional LOE, and an increase in production volumes, which contributed approximately $9.6 million of additional LOE. The increase in our average LOE per BOE rate was attributable to:

• increases in prices paid to oilfield service companies and suppliers;

• increases in natural gas prices resulting in higher electricity costs and gas plant fuel costs;

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

• an increase of (1) approximately $4.7 million ($0.32 per BOE) for retention bonuses paid in August 2008 and (2) approximately $4.1 million ($0.28 per BOE) for retention bonuses to be paid in August 2009, related to our strategic alternatives process.

     Production expense attributable to production, ad valorem, and severance taxes (“production taxes”) increased $36.1 million from $74.6 million in 2007 to $110.6 million in 2008 primarily due to higher wellhead revenues. As a percentage of oil and natural gas wellhead revenues, production taxes remained approximately constant at 9.8 percent in 2008 as compared to 9.7 percent in 2007.

     DD&A expense. DD&A expense increased $44.3 million from $184.0 million in 2007 to $228.3 million in 2008 as a result of a $2.21 increase in the per BOE rate, which contributed approximately $32.0 million of additional DD&A expense, and an increase in production volumes, which contributed approximately $12.3 million of additional DD&A expense. The increase in our average DD&A per BOE rate was attributable to higher costs incurred resulting from increases in rig rates, pipe costs, and acquisition costs and the decrease in our total proved reserves to 185.7 MMBOE as of December 31, 2008 as compared to 231.3 MMBOE as of December 31, 2007.

     Impairment of long-lived assets. During 2008, circumstances indicated that the carrying amounts of certain oil and natural gas properties, primarily four wells in the Tuscaloosa Marine Shale, may not be recoverable. We compared the assets’ carrying amounts to the undiscounted expected future net cash flows, which indicated a need for an impairment charge. We then compared the net carrying amounts of the impaired assets to their estimated fair value, which resulted in a write-down of the value of proved oil and natural gas properties of $59.5 million. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes, discounted to a present value.

     Exploration expense. Exploration expense increased $11.5 million from $27.7 million in 2007 to $39.2 million in 2008. During 2008, we expensed 8 exploratory dry holes totaling $14.7 million. During 2007, we expensed 5 exploratory dry holes totaling $14.7 million. Impairment of unproved acreage increased $9.4 million from $10.8 million in 2007 to $20.2 million in 2008, primarily due to our larger unproved property base, as well as the impairment of certain acreage through the normal course of evaluation. The following table illustrates the components of exploration expenses for the periods indicated:

	Year Ended December 31,
	2008		2007		Increase
			(in thousands)
Dry holes	$	14,683	$	14,673	$	10
Geological and seismic		2,851		1,455		1,396
Delay rentals		1,482		784		698
Impairment of unproved acreage		20,191		10,814		9,377
Total	$	39,207	$	27,726	$	11,481

     G&A expense. G&A expense increased $9.3 million from $39.1 million in 2007 to $48.4 million in 2008, primarily due to:

• a full year of ENP public entity expenses;

• higher activity levels;

• increased personnel costs due to intense competition for human resources within the industry; and

• an increase of (1) approximately $2.9 million for retention bonuses paid in August 2008 and (2) approximately $2.8 million for retention bonuses to be paid in August 2009, related to our strategic alternatives process;

• partially offset by a $3.1 million decrease in non-cash equity-based compensation.

     Derivative fair value loss (gain). During 2008, we recorded a $346.2 million derivative fair value gain as compared to a $112.5 million derivative fair value loss in 2007, the components of which were as follows:

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ENCORE ACQUISITION COMPANY

	Year Ended December 31,					Increase /
	2008			2007		(Decrease)
				(in thousands)
Ineffectiveness on designated derivative contracts	$	372		$	—	$	372
Mark-to-market loss (gain) on derivative contracts		(365,495	)		36,272		(401,767	)
Premium amortization		62,352			41,051		21,301
Settlements on commodity derivative contracts		(43,465	)		35,160		(78,625	)
Total derivative fair value loss (gain)	$	(346,236	)	$	112,483	$	(458,719	)

     The change in our derivative fair value loss (gain) was a result of the addition of commodity derivative contracts in the first part of 2008 when prices were high and the significant decrease in prices during the end of 2008, which favorably impacted the fair values of those contracts.

     During 2009, 2010, and 2011, we expect to make payments for deferred premiums of commodity derivative contracts of $67.0 million, $15.7 million, and $0.9 million, respectively.

     Provision for doubtful accounts. In 2008 and 2007, we recorded a provision for doubtful accounts of $2.0 million and $5.8 million, respectively, for the payout allowance related to the ExxonMobil joint development agreement.

     Other operating expense. Other operating expense decreased $4.1 million from $17.1 million in 2007 to $13.0 million in 2008, primarily due to a $7.4 million loss on the sale of certain Mid-Continent properties in 2007, partially offset by a $3.4 million increase during 2008 in third-party transportation costs to move our production to markets outside the immediate area of production.

     Interest expense. Interest expense decreased $15.5 million from $88.7 million in 2007 to $73.2 million in 2008, primarily due to (1) the use of net proceeds from our Mid-Continent asset disposition and ENP’s IPO to reduce weighted average outstanding borrowings on our revolving credit facilities, (2) a reduction in LIBOR, and (3) our use of interest rate swaps to fix the rate on a portion of outstanding borrowings on ENP’s revolving credit facility. The weighted average interest rate for all long-term debt for 2008 was 5.6 percent as compared to 6.9 percent for 2007.

     The following table illustrates the components of interest expense for the periods indicated:

	Year Ended December 31,				Increase /
	2008		2007		(Decrease)
	(in thousands)
6.25% Notes	$	9,727	$	9,705	$	22
6.0% Notes		18,550		18,517		33
7.25% Notes		10,996		10,988		8
Revolving credit facilities		31,038		46,085		(15,047	)
Other		2,862		3,409		(547	)
Total	$	73,173	$	88,704	$	(15,531	)

     Income taxes. In 2008, we recorded an income tax provision of $241.6 million as compared to $14.5 million in 2007. In 2008, we had income before income taxes of $726.7 million as compared to $24.2 million in 2007. Our effective tax rate decreased to 33.2 percent in 2008 as compared to 59.9 percent in 2007 primarily due to the 2007 recognition of non-deductible deferred compensation.

     Noncontrolling interest. As of December 31, 2008, public unitholders owned approximately 37 percent of ENP’s common units. We consolidate ENP’s results of operations in our consolidated financial statements and show the public ownership as noncontrolling interest. Net income attributable to noncontrolling interest was approximately $54.3 million for 2008 as compared to a loss of $7.5 million for 2007.

Comparison of 2007 to 2006

     Oil and natural gas revenues. The following table illustrates the components of oil and natural gas revenues for the periods indicated, as well as each period’s respective production volumes and average prices:

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ENCORE ACQUISITION COMPANY

	Year Ended December 31,						Increase / (Decrease)
	2007			2006			$			%
Revenues (in thousands):
Oil wellhead	$	606,112		$	399,180		$	206,932
Oil commodity derivative contracts		(43,295	)		(52,206	)		8,911
Total oil revenues	$	562,817		$	346,974		$	215,843			62	%
Natural gas wellhead	$	160,399		$	154,458		$	5,941
Natural gas commodity derivative contracts		(10,292	)		(8,133	)		(2,159	)
Total natural gas revenues	$	150,107		$	146,325		$	3,782			3	%
Combined wellhead	$	766,511		$	553,638		$	212,873
Combined commodity derivative contracts		(53,587	)		(60,339	)		6,752
Total combined oil and natural gas revenues	$	712,924		$	493,299		$	219,625			45	%
Average realized prices:
Oil wellhead ($/Bbl)	$	63.50		$	54.42		$	9.08
Oil commodity derivative contracts ($/Bbl)		(4.54	)		(7.12	)		2.58
Total oil revenues ($/Bbl)	$	58.96		$	47.30		$	11.66			25	%
Natural gas wellhead ($/Mcf)	$	6.69		$	6.59		$	0.10
Natural gas commodity derivative contracts ($/Mcf)		(0.43	)		(0.35	)		(0.08	)
Total natural gas revenues ($/Mcf)	$	6.26		$	6.24		$	0.02			0	%
Combined wellhead ($/BOE)	$	56.62		$	49.24		$	7.38
Combined commodity derivative contracts ($/BOE)		(3.96	)		(5.37	)		1.41
Total combined oil and natural gas revenues ($/BOE)	$	52.66		$	43.87		$	8.79			20	%
Total production volumes:
Oil (MBbls)		9,545			7,335			2,210			30	%
Natural gas (MMcf)		23,963			23,456			507			2	%
Combined (MBOE)		13,539			11,244			2,295			20	%
Average daily production volumes:
Oil (Bbl/D)		26,152			20,096			6,056			30	%
Natural gas (Mcf/D)		65,651			64,262			1,389			2	%
Combined (BOE/D)		37,094			30,807			6,287			20	%
Average NYMEX prices:
Oil (per Bbl)	$	72.45		$	66.26		$	6.19			9	%
Natural gas (per Mcf)	$	6.86		$	7.17		$	(0.31	)		-4	%

     Oil revenues increased $215.8 million from $347.0 million in 2006 to $562.8 million in 2007, primarily due to an increase in oil production volumes and an increase in our average realized oil price. Our production volumes increased 2,210 MBbls from 2007 to 2008, which contributed approximately $120.3 million in additional oil revenues. The increase in production volumes was the result of our Big Horn Basin acquisition in March 2007, our Williston Basin acquisition in April 2007, and our development program.

     Our average realized oil price increased $11.66 per Bbl primarily as a result of an increase in our average realized wellhead price, which increased oil revenues by $86.7 million, or $9.08 per Bbl. Our average realized oil wellhead price increased primarily as a result of the increase in the average NYMEX price from $66.26 per Bbl in 2006 to $72.45 per Bbl in 2007. In addition, as a result of our discontinuance of hedge accounting in July 2006, oil revenues for 2007 included amortization of net losses of certain commodity derivative contracts that were previously designated as hedges of approximately $43.3 million, or $4.54 per Bbl, while 2006 included approximately $52.2 million, or $7.12 per Bbl, of net losses.

     Our oil wellhead revenue was reduced by $31.9 million and $22.8 million in 2007 and 2006, respectively, for net profits interests related to our CCA properties.

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ENCORE ACQUISITION COMPANY

     Natural gas revenues increased $3.8 million from $146.3 million in 2006 to $150.1 million in 2007, primarily due to an increase in production volumes of 507 MMcf, which contributed approximately $3.3 million in additional natural gas revenues. The increase in natural gas production volumes was the result of our West Texas joint development agreement with ExxonMobil and our development program in the Mid-Continent area, partially offset by natural gas production sold in conjunction with our Mid-Continent asset disposition in 2007.

     Our average realized natural gas price increased $0.02 per Mcf primarily as a result of an increase in our wellhead price, which increased natural gas revenues by $2.6 million, or $0.10 per Mcf. Our average natural gas wellhead price increased as a result of the tightening of our natural gas differential despite decreases in the overall market price for natural gas, as reflected in the decrease in the average NYMEX price from $7.17 per Mcf in 2006 to $6.86 per Mcf in 2007. In addition, as a result of our discontinuance of hedge accounting in July 2006, natural gas revenues for 2007 included amortization of net losses of certain commodity derivative contracts that were previously designated as hedges of approximately $10.3 million, or $0.43 per Mcf, while 2006 included approximately $8.1 million, or $0.35 per Mcf, of net losses.

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

	Year Ended December 31,
	2007			2006
Oil wellhead ($/Bbl)	$	63.50		$	54.42
Average NYMEX ($/Bbl)	$	72.45		$	66.26
Differential to NYMEX	$	(8.95	)	$	(11.84	)
Oil wellhead to NYMEX percentage		88	%		82	%
Natural gas wellhead ($/Mcf)	$	6.69		$	6.59
Average NYMEX ($/Mcf)	$	6.86		$	7.17
Differential to NYMEX	$	(0.17	)	$	(0.58	)
Natural gas wellhead to NYMEX percentage		98	%		92	%

     Our oil wellhead price as a percentage of the average NYMEX price tightened to 88 percent in 2007 as compared to 82 percent in 2006. Our natural gas wellhead price as a percentage of the average NYMEX price improved to 98 percent in 2007 as compared to 92 percent in 2006. The differential improved because of efforts to reduce natural gas transportation and gathering costs.

     Marketing revenues and expenses. In 2006, we purchased third-party oil Bbls from counterparties other than to whom the Bbls were sold for aggregation and sale with our own production in various markets. These purchases assisted us in marketing our production by decreasing our dependence on individual markets. These activities allowed us to aggregate larger volumes, facilitated our efforts to maximize the prices we received for production, provided for a greater allocation of future pipeline capacity in the event of curtailments, and enabled us to reach other markets.

     In 2007, we discontinued purchasing oil from third party companies as market conditions changed and historical pipeline space was realized. Implementing this change allowed us to focus on the marketing of our own production, leveraging newly gained pipeline space, and delivering oil to various newly developed markets in an effort to maximize the value of the oil at the wellhead. In March 2007, ENP acquired a natural gas pipeline from Anadarko as part of the Big Horn Basin asset acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet to the pipeline and resold downstream to various local and off-system markets.

     The following table summarizes our marketing activities for the periods indicated:

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ENCORE ACQUISITION COMPANY

	Year ended December 31,					Increase / (Decrease)
	2007		2006			$			%
	($ in thousands, except per BOE amounts)
Marketing revenues	$	42,021	$	147,563		$	(105,542	)		-72	%
Marketing expenses		40,549		148,571			(108,022	)		-73	%
Marketing gain (loss)	$	1,472	$	(1,008	)	$	2,480			-246	%
Marketing revenues per BOE	$	3.10	$	13.12		$	(10.02	)		-76	%
Marketing expenses per BOE		2.99		13.21			(10.22	)		-77	%
Marketing gain (loss), per BOE	$	0.11	$	(0.09	)	$	0.20			-222	%

     Expenses. The following table summarizes our expenses, excluding marketing expenses shown above, for the periods indicated:

	Year Ended December 31,					Increase / (Decrease)
	2007		2006			$			%
Expenses (in thousands):
Production:
Lease operations	$	143,426	$	98,194		$	45,232
Production, ad valorem, and severance taxes		74,585		49,780			24,805
Total production expenses		218,011		147,974			70,037			47	%
Other:
Depletion, depreciation, and amortization		183,980		113,463			70,517
Exploration		27,726		30,519			(2,793	)
General and administrative		39,124		23,194			15,930
Derivative fair value loss (gain)		112,483		(24,388	)		136,871
Provision for doubtful accounts		5,816		1,970			3,846
Other operating		17,066		8,053			9,013
Total operating		604,206		300,785			303,421			101	%
Interest		88,704		45,131			43,573
Income tax provision		14,476		55,406			(40,930	)
Total expenses	$	707,386	$	401,322		$	306,064			76	%
Expenses (per BOE):
Production:
Lease operations	$	10.59	$	8.73		$	1.86
Production, ad valorem, and severance taxes		5.51		4.43			1.08
Total production expenses		16.10		13.16			2.94			22	%
Other:
Depletion, depreciation, and amortization		13.59		10.09			3.50
Exploration		2.05		2.71			(0.66	)
General and administrative		2.89		2.06			0.83
Derivative fair value loss (gain)		8.31		(2.17	)		10.48
Provision for doubtful accounts		0.43		0.18			0.25
Other operating		1.26		0.71			0.55
Total operating		44.63		26.74			17.89			67	%
Interest		6.55		4.01			2.54
Income tax provision		1.07		4.93			(3.86	)
Total expenses	$	52.25	$	35.68		$	16.57			46	%

     Production expenses. Total production expenses increased $70.0 million from $148.0 million in 2006 to $218.0 million in 2007 due to higher total production volumes and a $2.94 increase in production expenses per BOE. Our production margin increased by $142.8 million (35 percent) to $548.5 million in 2007 as compared to $405.7 million in 2006. Total production expenses per BOE increased by 22 percent while total oil and natural gas wellhead revenues per BOE increased by 15 percent. On a per BOE basis, our production margin increased 12 percent to $40.52 per BOE for 2007 as compared to $36.08 per BOE for 2006.

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     Production expense attributable to LOE increased $45.2 million from $98.2 million in 2006 to $143.4 million in 2007, primarily as a result of a $1.86 increase in the average per BOE rate, which contributed approximately $25.2 million of additional LOE, and higher production volumes, which contributed approximately $20.0 million of additional LOE. The increase in our average LOE per BOE rate was attributable to:

• increases in prices paid to oilfield service companies and suppliers;

• increased operational activity to maximize production;

• HPAI expenses at the CCA; and

• higher salary levels for engineers and other technical professionals.

     Production expense attributable to production taxes increased $24.8 million from $49.8 million in 2006 to $74.6 million in 2007. The increase was primarily due to higher wellhead revenues. As a percentage of oil and natural gas revenues (excluding the effects of commodity derivative contracts), production taxes increased to 9.7 percent in 2007 as compared to 9.0 percent in 2006 as a result of higher rates in the states where the properties associated with our Big Horn Basin and Williston Basin asset acquisitions are located.

     DD&A expense. DD&A expense increased $70.5 million from $113.5 million in 2006 to $184.0 million in 2007 due to a $3.50 increase in the per BOE rate and higher production volumes. The per BOE rate increased due to the higher cost basis of the properties associated with our Big Horn Basin and Williston Basin asset acquisitions, development of proved undeveloped reserves, and higher costs incurred resulting from increases in rig rates, oilfield services costs, and acquisition costs. These factors resulted in additional DD&A expense of approximately $47.3 million, while the increase in production volumes resulted in additional DD&A expense of approximately $23.2 million.

     Exploration expense. Exploration expense decreased $2.8 million from $30.5 million in 2006 to $27.7 million in 2007. During 2007, we expensed 5 exploratory dry holes totaling $14.7 million. During 2006, we expensed 14 exploratory dry holes totaling $17.3 million. The following table details our exploration expenses for the periods indicated:

	Year Ended December 31,				Increase /
	2007		2006		(Decrease)
	(in thousands)
Dry holes	$	14,673	$	17,257	$	(2,584	)
Geological and seismic		1,455		1,720		(265	)
Delay rentals		784		670		114
Impairment of unproved acreage		10,814		10,872		(58	)
Total	$	27,726	$	30,519	$	(2,793	)

     G&A expense. G&A expense increased $15.9 million from $23.2 million in 2006 to $39.1 million in 2007, primarily due to:

• a $6.4 million increase in non-cash equity-based compensation expense;

• increased staffing to manage our larger asset base;

• higher activity levels; and

• increased personnel costs due to intense competition for human resources within the industry.

     Derivative fair value loss (gain). During 2007, we recorded a $112.5 million derivative fair value loss as compared to a $24.4 million derivative fair value gain in 2006, the components of which were as follows:

	Year Ended December 31,					Increase /
	2007		2006			(Decrease)
	(in thousands)
Ineffectiveness on designated cash flow hedges	$	—	$	1,748		$	(1,748	)
Mark-to-market loss (gain) on commodity derivative contracts		36,272		(31,205	)		67,477
Premium amortization		41,051		13,926			27,125
Settlements on commodity derivative contracts		35,160		(8,857	)		44,017
Total derivative fair value loss (gain)	$	112,483	$	(24,388	)	$	136,871

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     Provision for doubtful accounts. Provision for doubtful accounts increased $3.8 million from $2.0 million in 2006 to $5.8 million in 2007, primarily due to an increase in the payout allowance related to the ExxonMobil joint development agreement.

     Other operating expense. Other operating expense increased $9.0 million from $8.1 million in 2006 to $17.1 million in 2007, primarily due to a $7.4 million loss on the sale of certain Mid-Continent properties and increases in third-party transportation costs attributable to moving our CCA production into markets outside the immediate area of production.

     Interest expense. Interest expense increased $43.6 million from $45.1 million in 2006 to $88.7 million in 2007, primarily due to additional debt used to finance the Big Horn Basin and Williston Basin asset acquisitions. The weighted average interest rate for all long-term debt for 2007 was 6.9 percent as compared to 6.1 percent for 2006.

     The following table illustrates the components of interest expense for the periods indicated:

	Year Ended December 31,				Increase /
	2007		2006		(Decrease)
	(in thousands)
6.25% Notes	$	9,705	$	9,684	$	21
6.0% Notes		18,517		18,418		99
7.25% Notes		10,988		10,984		4
Revolving credit facilities		46,085		3,609		42,476
Other		3,409		2,436		973
Total	$	88,704	$	45,131	$	43,573

     Income taxes. During 2007, we recorded an income tax provision of $14.5 million as compared to $55.4 million in 2006. Our effective tax rate increased to 59.9 percent in 2007 as compared to 37.5 percent in 2006 primarily due to a permanent rate adjustment for ENP’s management incentive units, a state rate adjustment due to larger apportionment of future taxable income to states with higher tax rates, and permanent timing adjustments that will not reverse in future periods.

     Noncontrolling interest. As of December 31, 2007, public unitholders in ENP had a limited partner interest of approximately 40 percent. We consolidate ENP in our consolidated financial statements and show the ownership by the public as a noncontrolling interest. Net loss attributable to noncontrolling interest was $7.5 million for 2007.

Capital Commitments, Capital Resources, and Liquidity

     Capital commitments. Our primary needs for cash are:

• Development, exploitation, and exploration of oil and natural gas properties;

• Acquisitions of oil and natural gas properties;

• Funding of necessary working capital; and

• Contractual obligations.

     Development, exploitation, and exploration of oil and natural gas properties. The following table summarizes our costs incurred (excluding asset retirement obligations) related to development, exploitation, and exploration activities for the periods indicated:

	Year Ended December 31,
	2008		2007		2006
	(in thousands)
Development and exploitation	$	362,111	$	270,016	$	253,484
Exploration		256,437		97,453		95,205
Total	$	618,548	$	367,469	$	348,689

     Our development and exploitation expenditures primarily relate to drilling development and infill wells, workovers of existing wells, and field related facilities. Our development and exploitation capital for 2008 yielded 186 gross (73.4 net) successful wells and 5 gross (3.1 net) dry holes. Our exploration expenditures primarily relate to drilling exploratory wells, seismic costs, delay rentals, and geological and geophysical costs. Our exploration capital for 2008 yielded 96 gross (31.4 net) successful wells and 8 gross (3.8

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net) dry holes. Please read “Items 1 and 2. Business and Properties – Development Results” included in our 2008 Annual Report for a description of the areas in which we drilled wells during 2008.

     Acquisitions of oil and natural gas properties and leasehold acreage. The following table summarizes our costs incurred (excluding asset retirement obligations) related to oil and natural gas property acquisitions for the periods indicated:

	Year Ended December 31,
	2008		2007		2006
	(in thousands)
Acquisitions of proved property	$	28,729	$	787,988	$	4,486
Acquisitions of leasehold acreage		128,635		52,306		24,462
Total	$	157,364	$	840,294	$	28,948

     In March 2007, Encore Operating and OLLC acquired oil and natural gas properties in the Big Horn Basin, including properties in the Elk Basin and the Gooseberry fields for approximately $393.6 million. In April 2007, we acquired oil and natural gas properties in the Williston Basin for approximately $392.1 million.

     During 2008, our capital expenditures for leasehold acreage costs totaled $128.6 million, $45.2 million of which related to the exercise of preferential rights in the Haynesville area and the remainder of which related to the acquisition of unproved acreage in various areas. During 2007, our capital expenditures for leasehold acreage costs totaled $52.3 million, $16.1 million of which related to the Williston Basin asset acquisition and the remainder of which related to the acquisition of unproved acreage in various areas. During 2006, our capital expenditures for leasehold acreage costs totaled $24.5 million, all of which related to the acquisition of unproved acreage in various areas.

     Funding of necessary working capital. As of December 31, 2008 and 2007, our working capital (defined as total current assets less total current liabilities) was $188.7 million and negative $16.2 million, respectively. The increase in 2008 as compared to 2007 was primarily attributable to a decrease in commodity prices at December 31, 2008 as compared to December 31, 2007, which positively impacted the fair value of our outstanding commodity derivative contracts.

     For 2009, we expect working capital to remain positive, primarily due to the fair value of our outstanding derivative contracts. We anticipate cash reserves to be close to zero because we intend to use any excess cash to fund capital obligations and reduce outstanding borrowings and related interest expense under our revolving credit facility. However, we have availability under our revolving credit facility to fund our obligations as they become due. We do not plan to pay cash dividends in the foreseeable future. Our production volumes, commodity prices, and differentials for oil and natural gas will be the largest variables affecting working capital. Our operating cash flow is determined in large part by production volumes and commodity prices. Given our current commodity derivative contracts, assuming constant or increasing production volumes, our operating cash flow should remain positive in 2009.

     The Board approved a capital budget of $310 million for 2009, excluding proved property acquisitions. The level of these and other future expenditures are largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects, and market conditions. We plan to finance our ongoing expenditures using internally generated cash flow and borrowings under our revolving credit facility.

     Off-balance sheet arrangements. We have no investments in unconsolidated entities or persons that could materially affect our liquidity or the availability of capital resources. We have no off-balance sheet arrangements that are material to our financial position or results of operations.

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     Contractual obligations. The following table illustrates our contractual obligations and commitments at December 31, 2008:

Contractual Obligations			Payments Due by Period
and Commitments	Maturity Date		Total		2009		2010 - 2011		2012 - 2013		Thereafter
			(in thousands)
6.25% Notes (a)		4/15/2014	$	201,563	$	9,375	$	18,750	$	18,750	$	154,688
6.0% Notes (a)		7/15/2015		426,000		18,000		36,000		36,000		336,000
7.25% Notes (a)		12/1/2017		247,875		10,875		21,750		21,750		193,500
Revolving credit facilities (a)		3/7/2012		789,626		19,885		39,770		729,971		—
Commodity derivative contracts (b)				—		—		—		—		—
Interest rate swaps				4,342		1,269		3,071		2		—
Capital lease obligations				1,747		466		932		349		—
Development commitments (c)				134,860		134,860		—		—		—
Operating leases and commitments (d)				17,493		3,952		7,577		5,964		—
Asset retirement obligations (e)				178,889		1,511		3,022		3,022		171,334
Total			$	2,002,395	$	200,193	$	130,872	$	815,808	$	855,522

(a)	Includes principal and projected interest payments. Please read Note 8 of our Recast Financial Statements for additional information regarding our long-term debt.
(b)	At December 31, 2008, our commodity derivative contracts were in a net asset position. With the exception of $67.6 million of deferred premiums on commodity derivative contracts, the ultimate settlement amounts of our commodity derivative contracts are unknown because they are subject to continuing market risk. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” included in our 2008 Annual Report and Notes 13 and 14 of our Recast Financial Statements for additional information regarding our commodity derivative contracts.
(c)	Development commitments include: authorized purchases for work in process of $116.7 million and future minimum payments for drilling rig operations of $18.1 million. Also at December 31, 2008, we had $178.2 million of authorized purchases not placed to vendors (authorized AFEs), which were not accrued and are excluded from the above table but are budgeted for and are expected to be made unless circumstances change.
(d)	Operating leases and commitments include office space and equipment obligations that have non-cancelable lease terms in excess of one year of $16.8 million and future minimum payments for other operating commitments of $0.7 million. Please read Note 4 of our Recast Financial Statements for additional information regarding our operating leases.
(e)	Asset retirement obligations represent the undiscounted future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal at the end of field life. Please read Note 5 of our Recast Financial Statements for additional information regarding our asset retirement obligations.

     Other contingencies and commitments. In order to facilitate ongoing sales of our oil production in the CCA, we ship a portion of our production in pipelines downstream and sell to purchasers at major market hubs. From time to time, shipping delays, purchaser stipulations, or other conditions may require that we sell our oil production in periods subsequent to the period in which it is produced. In such case, the deferred sale would have an adverse effect in the period of production on reported production volumes, oil and natural gas revenues, and costs as measured on a unit-of-production basis.

     The marketing of our CCA oil production is mainly dependent on transportation through the Bridger, Poplar, and Butte pipelines to markets in the Guernsey, Wyoming area. Alternative transportation routes and markets have been developed by moving a portion of the crude oil production through the Enbridge Pipeline to the Clearbrook, Minnesota hub. To a lesser extent, our production also depends on transportation through the Platte Pipeline to Wood River, Illinois as well as other pipelines connected to the Guernsey, Wyoming area. While shipments on the Platte Pipeline are oversubscribed and have been subject to apportionment since December 2005, we were allocated sufficient pipeline capacity to move our crude oil production effective January 1, 2007. Enbridge completed an expansion, which moved the total Rockies area pipeline takeaway closer to a balancing point with increasing production volumes and thereby provided greater stability to oil differentials in the area. In spite of the increase in capacity, the Enbridge Pipeline continues to run at full capacity and is scheduled to complete an additional expansion by the beginning of 2010. However, further restrictions on available capacity to transport oil through any of the above-mentioned pipelines, any other pipelines, or any refinery upsets could have a material adverse effect on our production volumes and the prices we receive for our production.

     The difference between NYMEX market prices and the price received at the wellhead for oil and natural gas production is commonly referred to as a differential. In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have affected this differential. We cannot accurately predict future crude oil and natural gas differentials. Increases in the percentage differential between the NYMEX price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial position, and cash flows. The following table illustrates the relationship between oil and natural gas wellhead prices as a percentage of average NYMEX prices by quarter for 2008, as well as our expected differentials for the first quarter of 2009:

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	Actual												Forecast
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			First Quarter
	of 2008			of 2008			of 2008			of 2008			of 2009
Oil wellhead to NYMEX percentage		91	%		94	%		91	%		80	%		78	%
Natural gas wellhead to NYMEX percentage		103	%		102	%		93	%		86	%		103	%

     Capital resources

     Cash flows from operating activities. Cash provided by operating activities increased $343.5 million from $319.7 million in 2007 to $663.2 million in 2008, primarily due to an increase in our production margin, partially offset by increased settlements on our commodity derivative contracts as a result of higher commodity prices in the first half of 2008.

     Cash provided by operating activities increased $22.4 million from $297.3 million in 2006 to $319.7 million in 2007, primarily due to an increase in our production margin, partially offset by increased settlements on our commodity derivative contracts as a result of increases in oil prices and an increase in accounts receivable as a result of increased oil and natural gas production.

     Cash flows from investing activities. Cash used in investing activities decreased $201.3 million from $929.6 million in 2007 to $728.3 million in 2008, primarily due to a $706.0 million decrease in amounts paid for acquisitions of oil and natural gas properties and a $283.7 million decrease in proceeds received for the disposition of assets, partially offset by a $225.1 million increase in development of oil and natural gas properties. In 2007, we paid approximately $393.6 million in conjunction with the Big Horn Basin asset acquisition and approximately $392.1 million in conjunction with the Williston Basin asset acquisition. In 2007, we also completed the sale of certain oil and natural gas properties in the Mid-Continent for net proceeds of approximately $294.8 million. During 2008, we advanced $24.8 million (net of collections) to ExxonMobil for their portion of costs incurred drilling wells under the joint development agreement as compared to advancements of $29.5 million (net of collections) in 2007.

     Cash used in investing activities increased $532.2 million from $397.4 million in 2006 to $929.6 million in 2007, primarily due to a $818.4 million increase in amounts paid for acquisitions of oil and natural gas properties, primarily our Big Horn Basin and Williston Basin asset acquisitions, partially offset by a $286.4 million increase in proceeds received for the disposition of assets, primarily our Mid-Continent asset disposition. During 2007, we advanced $29.5 million (net of collections) to ExxonMobil for their portion of costs incurred drilling the commitment wells under the joint development agreement as compared to advancements of $22.4 million (net of collections) in 2006.

     Cash flows from financing activities. Our cash flows from financing activities consist primarily of proceeds from and payments on long-term debt and repurchases of our common stock. We periodically draw on our revolving credit facility to fund acquisitions and other capital commitments.

     During 2008, we received net cash of $65.4 million from financing activities, including net borrowings on our revolving credit facilities of $199 million, which resulted in an increase in outstanding borrowings under our revolving credit facilities from $526 million at December 31, 2007 to $725 million at December 31, 2008.

     In December 2007, we announced that the Board approved a share repurchase program authorizing us to repurchase up to $50 million of our common stock. During 2008, we completed the share repurchase program by repurchasing and retiring 1,397,721 shares of our outstanding common stock at an average price of approximately $35.77 per share.

     In October 2008, we announced that the Board authorized a new share repurchase program of up to $40 million of our common stock. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions, and may be suspended or discontinued at any time. The share repurchase program will be funded using our available cash. As of December 31, 2008, we had repurchased and retired 620,265 shares of our outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the new share repurchase program.

     During 2007, we received net cash of $610.8 million from financing activities, including net borrowings on our revolving credit facilities of $444.8 million and net proceeds of $193.5 million from ENP’s issuance of common units. Net borrowings on our revolving credit facilities were primarily due to borrowings used to finance our Big Horn Basin and Williston Basin asset acquisitions, which were partially offset by repayments from the net proceeds received from the Mid-Continent asset disposition and ENP’s issuance of common units.

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     During 2006, we received net cash of $99.2 million from financing activities. In April 2006, we received net proceeds of $127.1 million from a public offering of 4,000,000 shares of our common stock, which were used to (1) reduce outstanding borrowings under our revolving credit facility, (2) invest in oil and natural gas activities, and (3) pay general corporate expenses.

     Liquidity. Our primary sources of liquidity are internally generated cash flows and the borrowing capacity under our revolving credit facility. We also have the ability to adjust our capital expenditures. We may use other sources of capital, including the issuance of additional debt or equity securities, to fund acquisitions or maintain our financial flexibility. We believe that our internally generated cash flows and availability under our revolving credit facility will be sufficient to fund our planned capital expenditures for the foreseeable future. However, should commodity prices continue to decline or the capital markets remain tight, the borrowing capacity under our revolving credit facilities could be adversely affected. We are currently in a process of redetermining the borrowing base under our revolving credit facilities. We expect that the banks will reaffirm our current borrowing base but we recognize that this process could result in a reduction. In the event of a reduction in the borrowing base under our revolving credit facilities, we do not believe it will result in any required prepayments of indebtedness given our relatively low levels of borrowings under those facilities in relation to the existing borrowing base.

     Internally generated cash flows. Our internally generated cash flows, results of operations, and financing for our operations are largely dependent on oil and natural gas prices. During 2008, our average realized oil and natural gas prices increased by 51 percent and 38 percent, respectively, as compared to 2007. Realized oil and natural gas prices fluctuate widely in response to changing market forces. In 2008, approximately 70 percent of our production was oil. As previously discussed, our oil wellhead differentials during 2008 improved as compared to 2007, favorably impacting the prices we received for our oil production. To the extent oil and natural gas prices continue to decline from levels in mid. February 2009 or we experience a significant widening of our differentials, earnings, cash flows from operations, and availability under our revolving credit facility may be adversely impacted. Prolonged periods of low oil and natural gas prices or sustained wider differentials could cause us to not be in compliance with financial covenants under our revolving credit facility and thereby affect our liquidity. However, we have protected a significant portion of our forecasted production for 2009 against declining commodity prices. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” included in our 2008 Annual Report and Notes 13 and 14 of our Recast Financial Statements for additional information regarding our commodity derivative contracts.

     Revolving credit facilities. Our principal source of short-term liquidity is our revolving credit facility. The syndicate of lenders underwriting our facility includes 30 banking and other financial institutions, and the syndicate of lenders underwriting ENP’s facility includes 13 banking and other financial institutions, both after taking into consideration recent mergers and acquisitions within the financial services industry. None of the lenders are underwriting more than eight percent of the respective total commitments. We believe the large number of lenders, the relatively small percentage participation of each, and the relatively high level of availability under each facility provides adequate diversity and flexibility should further consolidation occur within the financial services industry.

     Certain of the lenders underwriting our facility are also counterparties to our commodity derivative contracts. At December 31, 2008, we had committed greater than 10 percent of either our outstanding oil or natural gas commodity derivative contracts to the following counterparties:

	Percentage of			Percentage of
	Oil Derivative			Natural Gas Derivative
	Contracts			Contracts
Counterparty	Committed			Committed
BNP Paribas		22	%		24	%
Calyon		15	%		31	%
Fortis		11	%		—
UBS		16	%		—
Wachovia		11	%		38	%

     Encore Acquisition Company Senior Secured Credit Agreement

     In March 2007, we entered into a five-year amended and restated credit agreement (as amended, the “EAC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The EAC Credit Agreement matures on March 7, 2012. Effective February 7, 2008, we amended the EAC Credit Agreement to, among other things, provide that certain negative covenants in the EAC Credit Agreement restricting hedge transactions do not apply to any oil and natural gas hedge transaction that is a floor or put

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transaction not requiring any future payments or delivery by us or any of our restricted subsidiaries. Effective May 22, 2008, we amended the EAC Credit Agreement to, among other things, increase the interest rate margins applicable to loans made under the EAC Credit Agreement, as set forth in the table below, and increase the borrowing base to $1.1 billion. The EAC Credit Agreement provides for revolving credit loans to be made to us from time to time and letters of credit to be issued from time to time for our account or the account of any of our restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the EAC Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. On December 5, 2008, the borrowing base under the EAC Credit Agreement was redetermined with no change. As of December 31, 2008, the borrowing base was $1.1 billion. We are currently in a process of redetermining the borrowing base under the EAC Credit Agreement which could result in a reduction to the borrowing base.

     Our obligations under the EAC Credit Agreement are secured by a first-priority security interest in our restricted subsidiaries’ proved oil and natural gas reserves and in our equity interests in our restricted subsidiaries. In addition, our obligations under the EAC Credit Agreement are guaranteed by our restricted subsidiaries.

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

	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.250	%		0.000	%
Greater than or equal to .50 to 1 but less than .75 to 1		1.500	%		0.250	%
Greater than or equal to .75 to 1 but less than .90 to 1		1.750	%		0.500	%
Greater than or equal to .90 to 1		2.000	%		0.750	%

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by us) is the rate per year equal to LIBOR, as published by Reuters or another source designated by Bank of America, N.A., for deposits in dollars for a similar interest period. The “base rate” is calculated as the higher of (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 percent.

     Any outstanding letters of credit reduce the availability under the EAC Credit Agreement. Borrowings under the EAC Credit Agreement may be repaid from time to time without penalty.

     The EAC 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 our and our restricted subsidiaries’ assets, subject to permitted exceptions;

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

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

• a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

• a requirement that we maintain a ratio of consolidated current assets (as defined in the EAC Credit Agreement) to consolidated current liabilities (as defined in the EAC Credit Agreement) of not less than 1.0 to 1.0; and

• a requirement that we maintain a ratio of consolidated EBITDA (as defined in the EAC 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 EAC 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 EAC Credit Agreement to be immediately due and payable.

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

	Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .50 to 1		0.250	%
Greater than or equal to .50 to 1 but less than .75 to 1		0.300	%
Greater than or equal to .75 to 1		0.375	%

     On December 31, 2008, there were $575 million of outstanding borrowings and $525 million of borrowing capacity under the EAC Credit Agreement. On February 18, 2009, there were $543 million of outstanding borrowings and $557 million of borrowing capacity under the EAC Credit Agreement.

     Encore Energy Partners Operating LLC Credit Agreement

     OLLC is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “OLLC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The OLLC Credit Agreement matures on March 7, 2012. On August 22, 2007, OLLC amended its credit agreement to revise certain financial covenants. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. On December 5, 2008, the borrowing base under the OLLC Credit Agreement was redetermined with no change. As of December 31, 2008, the borrowing base was $240 million. We are currently in a process of redetermining the borrowing base under the OLLC Credit Agreement which could result in a reduction to the borrowing base.

     OLLC’s obligations under the OLLC Credit Agreement are secured by a first-priority security interest in OLLC’s 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 ENP and OLLC’s restricted subsidiaries. We consolidate the debt of ENP with that of our own; however, obligations under the OLLC Credit Agreement are non-recourse to us and our restricted subsidiaries.

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

	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.000	%		0.000	%
Greater than or equal to .50 to 1 but less than .75 to 1		1.250	%		0.000	%
Greater than or equal to .75 to 1 but less than .90 to 1		1.500	%		0.250	%
Greater than or equal to .90 to 1		1.750	%		0.500	%

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by us) is the rate per year equal to LIBOR, as published by Reuters or another source designated by Bank of America, N.A., for deposits in dollars for a similar interest period. The “base rate” is calculated as the higher of (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 percent.

     Any outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.

     The OLLC Credit Agreement contains covenants that include, among others:

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

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• a prohibition against purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;

• a restriction on creating liens on the assets of ENP, OLLC and 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 ENP and OLLC maintain a ratio of consolidated current assets (as defined in the OLLC Credit Agreement) to consolidated current liabilities (as defined in the OLLC Credit Agreement) of not less than 1.0 to 1.0;

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC Credit Agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 1.5 to 1.0;

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC Credit Agreement) to consolidated senior interest expense of not less than 2.5 to 1.0; and

• a requirement that ENP and 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.

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

	Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .50 to 1		0.250	%
Greater than or equal to .50 to 1 but less than .75 to 1		0.300	%
Greater than or equal to .75 to 1		0.375	%

     On December 31, 2008, there were $150 million of outstanding borrowings and $90 million of borrowing capacity under the OLLC Credit Agreement. On February 18, 2009, there were $201 million of outstanding borrowings and $39 million of borrowing capacity under the OLLC Credit Agreement.

     Please read Note 8 of our Recast Financial Statements for additional information regarding our long-term debt.

     Indentures governing our senior subordinated notes. We and our restricted subsidiaries are subject to certain negative and financial covenants under the indentures governing the 6.25% Notes, the 6.0% Notes, and the 7.25% Notes (collectively, the “Notes”). The provisions of the indentures limit our and our restricted subsidiaries’ ability to, among other things:

• incur additional indebtedness;

• pay dividends on our capital stock or redeem, repurchase, or retire our capital stock or subordinated indebtedness;

• make investments;

• incur liens;

• create any consensual limitation on the ability of our restricted subsidiaries to pay dividends, make loans, or transfer property to us;

• engage in transactions with our affiliates;

• sell assets, including capital stock of our subsidiaries;

• consolidate, merge, or transfer assets;

• a requirement that we maintain a current ratio (as defined in the indentures) of not less than 1.0 to 1.0; and

• a requirement that we maintain a ratio of consolidated EBITDA (as defined in the indentures) to consolidated interest expense of not less than 2.5 to 1.0.

     If we experience a change of control (as defined in the indentures), subject to certain conditions, we must give holders of the Notes the opportunity to sell to us their Notes at 101 percent of the principal amount, plus accrued and unpaid interest.

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     Debt covenants. At December 31, 2008, we and ENP were in compliance with all debt covenants.

     Capitalization. At December 31, 2008, we had total assets of $3.6 billion and total capitalization of $2.6 billion, of which 50 percent was represented by stockholders’ equity and 50 percent by long-term debt. At December 31, 2007, we had total assets of $2.8 billion and total capitalization of $2.1 billion, of which 46 percent was represented by stockholders’ equity and 54 percent by long-term debt. The percentages of our capitalization represented by stockholders’ equity and long-term debt could vary in the future if debt or equity is used to finance capital projects or acquisitions.

Changes in Prices

     Our oil and natural gas revenues, the value of our assets, and our ability to obtain bank loans or additional capital on attractive terms are affected by changes in oil and natural gas prices, which fluctuate significantly. The following table illustrates our average oil and natural gas prices for the periods presented. Our average realized prices for 2008, 2007, and 2006 were decreased by $0.20, $3.96, and $5.37 per BOE, respectively, as a result of commodity derivative contracts, which were previously designated as hedges.

	Year Ended December 31,
	2008		2007		2006
Average realized prices:
Oil ($/Bbl)	$	89.30	$	58.96	$	47.30
Natural gas ($/Mcf)		8.63		6.26		6.24
Combined ($/BOE)		77.87		52.66		43.87
Average wellhead prices:
Oil ($/Bbl)	$	89.58	$	63.50	$	54.42
Natural gas ($/Mcf)		8.63		6.69		6.59
Combined ($/BOE)		78.07		56.62		49.24

     Increases in oil and natural gas prices may be accompanied by or result in: (1) increased development costs, as the demand for drilling operations increases; (2) increased severance taxes, as we are subject to higher severance taxes due to the increased value of oil and natural gas extracted from our wells; (3) increased LOE, as the demand for services related to the operation of our wells increases; and (4) increased electricity costs. Decreases in oil and natural gas prices may be accompanied by or result in: (1) decreased development costs, as the demand for drilling operations decreases; (2) decreased severance taxes, as we are subject to lower severance taxes due to the decreased value of oil and natural gas extracted from our wells; (3) decreased LOE, as the demand for services related to the operation of our wells decreases; (4) decreased electricity costs; (5) impairment of oil and natural gas properties; and (6) decreased revenues and cash flows. We believe our risk management program and available borrowing capacity under our revolving credit facility provide means for us to manage commodity price risks.

Critical Accounting Policies and Estimates

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

Oil and Natural Gas Properties

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

     If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs would be expensed in the period in which the determination is made. If an exploratory well finds reserves but they cannot be classified as proved, we continue to capitalize the associated cost as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the

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reserves and the operating viability of the project. If subsequently it is determined that these conditions do not continue to exist, all previously capitalized costs associated with the exploratory well would be expensed in the period in which the determination is made. Re-drilling or directional drilling in a previously abandoned well is classified as development or exploratory based on whether it is in a proved or unproved reservoir. Costs for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Costs to recomplete a well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the costs would be charged to expense.

     DD&A expense is directly affected by our reserve estimates. Significant revisions to reserve estimates can be and are made by our reserve engineers each year. Mostly these are the result of changes in price, but as reserve quantities are estimates, they can also change as more or better information is collected, especially in the case of estimates in newer fields. Downward revisions have the effect of increasing our DD&A rate, while upward revisions have the effect of decreasing our DD&A rate. Assuming no other changes, such as an increase in depreciable base, as our reserves increase, the amount of DD&A expense in a given period decreases and vice versa. DD&A expense associated with lease and well equipment and intangible drilling costs is based upon proved developed reserves, while DD&A expense for capitalized leasehold costs is based upon total proved reserves. As a result, changes in the classification of our reserves could have a material impact on our DD&A expense.

     Miller & Lents estimates our reserves annually at December 31. This results in a new DD&A rate which we use for the preceding fourth quarter after adjusting for fourth quarter production. We internally estimate reserve additions and reclassifications of reserves from proved undeveloped to proved developed at the end of the first, second, and third quarters for use in determining a DD&A rate for the respective quarter.

     Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Internal costs directly associated with the development of proved properties are capitalized as a cost of the property and are classified accordingly in our consolidated financial statements. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable. Natural gas volumes are converted to BOE at the rate of six Mcf of natural gas to one Bbl of oil.

     The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to accumulated DD&A.

     In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), we assess the need for an impairment of long-lived assets to be held and used, including proved oil and natural gas properties, whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then an impairment charge is recognized to the extent that the asset’s carrying value exceeds its fair value. Expected future net cash flows are based on existing proved reserves (and appropriately risk-adjusted probable reserves), forecasted production information, and management’s outlook of future commodity prices. Any impairment charge incurred is expensed and reduces our net basis in the asset. Management aggregates proved property for impairment testing the same way as for calculating DD&A. The price assumptions used to calculate undiscounted cash flows is based on judgment. We use prices consistent with the prices 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. During 2008, events and circumstances indicated that a portion of our oil and natural gas properties, primarily four wells in the Tuscaloosa Marine Shale, might be impaired. As a result, we completed an impairment assessment and recorded a $59.5 million impairment charge. Our estimates of undiscounted cash flows indicated that the remaining carrying amounts of our oil and natural gas properties are expected to be recovered. Nonetheless, if oil and natural gas prices continue to decline, it is reasonably possible that our estimates of undiscounted cash flows may change in the near term resulting in the need to record an additional write down of our oil and natural gas properties to fair value.

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

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proved reserves have been found in the past. Since the wells drilled on unproved acreage are inherently exploratory in nature, actual results could vary from estimates especially in newer areas in which we do not have a long history of drilling.

     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 & Lents prepares a reserve and economic evaluation of all of our properties on a well-by-well basis. Assumptions used by Miller & Lents in calculating reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. The accuracy of reserve estimates is a function of the:

• quality and quantity of available data;

• interpretation of that data;

• accuracy of various mandated economic assumptions; and

• judgment of the independent reserve engineer.

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

     Asset retirement obligations. In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” we recognize the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas property is acquired or a new well is drilled. An amount equal to and offsetting the liability is capitalized as part of the carrying amount of our oil and natural gas properties. The liability is recorded at its discounted fair value and then accreted each period until it is settled or the asset is sold, at which time the liability is reversed.

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

Goodwill and Other Intangible Assets

     We account for goodwill and other intangible assets under the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill and other intangible assets with indefinite useful lives are assessed for impairment annually on December 31 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level. We have determined that we have two reporting units: EAC Standalone and ENP. If indicators of impairment are determined to exist, an impairment charge would be recognized for the amount by which the carrying value of an indefinite lived intangible asset exceeds its implied fair value.

     We utilize both a market capitalization and an income approach to determine the fair value of our reporting units. The primary component of the income approach is the estimated discounted future net cash flows expected to be recovered from the reporting unit’s oil and natural gas properties. Our analysis concluded that there was no impairment of goodwill as of December 31, 2008. Prices for oil and natural gas have deteriorated sharply in recent months and significant uncertainty remains on how prices for these commodities will behave in the future. Any additional decreases in the prices of oil and natural gas or any negative reserve adjustments from the December 31, 2008 assessment could change our estimates of the fair value of our reporting units and could result in an impairment charge.

     Intangible assets with definite useful lives are amortized over their estimated useful lives. In accordance with SFAS 144, we evaluate the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.

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     We allocate the purchase price paid for the acquisition of a business to the assets and liabilities acquired based on the estimated fair values of those assets and liabilities. Estimates of fair value are based upon, among other things, reserve estimates, anticipated future prices and costs, and expected net cash flows to be generated. These estimates are often highly subjective and may have a material impact on the amounts recorded for acquired assets and liabilities.

Net Profits Interests

     A major portion of our acreage position in the CCA is subject to net profits interests ranging from one percent to 50 percent. The holders of these net profits interests are entitled to receive a fixed percentage of the cash flow remaining after specified costs have been subtracted from net revenue. The net profits calculations are contractually defined. In general, net profits are determined after considering costs associated with production, overhead, interest, and development. The amounts of reserves and production attributable to net profits interests are deducted from our reserves and production data, and our revenues are reported net of net profits interests. The reserves and production attributed to the net profits interests are calculated by dividing estimated future net profits interests (in the case of reserves) or prior period actual net profits interests (in the case of production) by commodity prices at the determination date. Fluctuations in commodity prices and the levels of development activities in the CCA from period to period will impact the reserves and production attributed to the net profits interests and will have an inverse effect on our oil and natural gas revenues, production, reserves, and net income.

Oil and Natural Gas Revenue Recognition

     Oil and natural gas revenues are recognized as oil and natural gas is produced and sold, net of royalties and net profits interests. Royalties, net profits interests, and severance taxes are incurred 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 prices for those properties are estimated and recorded. Natural gas revenues are reduced by any processing and other fees incurred except for transportation costs paid to third parties, which are recorded as expense. Natural gas revenues are recorded using the sales method of accounting whereby revenue is recognized based on actual sales of natural gas rather than our proportionate share of natural gas production. If our overproduced imbalance position (i.e., we have cumulatively been over-allocated production) is greater than our share of remaining reserves, a liability is recorded for the excess at period-end prices unless a different price is specified in the contract in which case that price is used. Revenue is not recognized for the production in tanks, oil marketed on behalf of joint interest owners in our properties, or oil in pipelines that has not been delivered to the purchaser.

Income Taxes

     Our effective tax rate is subject to variability from period to period as a result of factors other than changes in federal and state tax rates and/or changes in tax laws which can affect tax paying companies. Our effective tax rate is affected by changes in the allocation of property, payroll, and revenues between states in which we own property as rates vary from state to state. Our deferred taxes are calculated using rates we expect to be in effect when they reverse. As the mix of property, payroll, and revenues varies by state, our estimated tax rate changes. Due to the size of our gross deferred tax balances, a small change in our estimated future tax rate can have a material effect on earnings.

Derivatives

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

     We apply the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) and its amendments, which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative does not qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, changes in fair value can be recorded in accumulated other comprehensive income until such time as the hedged item is recognized in earnings.

     To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting

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changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically. Cash flow hedges are marked to market through accumulated other comprehensive income each period.

     We have elected to designate our current interest rate swaps as cash flow hedges. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in accumulated other comprehensive income in stockholders’ equity and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized immediately in earnings. While management does not anticipate changing the designation of our interest rate swaps as hedges, factors beyond our control can preclude the use of hedge accounting.

     We have elected to not designate our current portfolio of commodity derivative contracts as hedges and therefore, changes in fair value of these instruments are recognized in earnings each period.

     Please read “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” included in our 2008 Annual Report for discussion regarding our sensitivity analysis for financial instruments.

New Accounting Pronouncements

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

     In September 2006, the FASB issued SFAS 157, which: (1) standardizes the definition of fair value; (2) establishes a framework for measuring fair value in GAAP; and (3) expands disclosures related to the use of fair value measures in financial statements. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value, but does not require any new fair value measurements. SFAS 157 was prospectively effective for financial assets and liabilities for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delayed the effective date of SFAS 157 for one year for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We elected a partial deferral of SFAS 157 for all instruments within the scope of FSP FAS 157-2, including, but not limited to, our asset retirement obligations and indefinite lived assets. The adoption of SFAS 157 on January 1, 2008, as it relates to financial assets and liabilities, did not have a material impact on our results of operations or financial condition. We do not expect the adoption of SFAS 157 on January 1, 2009, as it relates to all instruments within the scope of FSP FAS 157-2, to have a material impact on our results of operations or financial condition.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – including an amendment of FASB Statement No. 115” (“SFAS 159”)

     In February 2007, the FASB issued SFAS 159, which permits entities to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis. SFAS 159 also allows entities an irrevocable option to measure eligible items at fair value at specified election dates, with resulting changes in fair value reported in earnings. SFAS 159 was effective for fiscal years beginning after November 15, 2007. We did not elect the fair value option for eligible instruments and therefore, the adoption of SFAS 159 on January 1, 2008 did not impact our results of operations or financial condition. We will assess the impact of electing the fair value option for any eligible instruments acquired in the future. Electing the fair value option for such instruments could have a material impact on our future results of operations or financial condition.

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

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

SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”)

     In December 2007, the FASB issued SFAS 141R, which replaces SFAS No. 141, “Business Combinations.” SFAS 141R establishes principles and requirements for the reporting entity in a business combination, including: (1) recognition and measurement

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in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. SFAS 141R is prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008, with early application prohibited. We currently do not have any pending acquisitions that would fall within the scope of SFAS 141R. Future acquisitions could have an impact on our results of operations and financial condition.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment to ARB No. 51” (“SFAS 160”)

     In December 2007, the FASB issued SFAS 160, which amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008. SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest and the disclosure of consolidated net income attributable to the parent and to the noncontrolling interest on the face of the consolidated statement of operations and gains and losses on a subsidiaries’ issuance of equity to be accounted for as capital transactions. The adoption of SFAS 160 on January 1, 2009 did not have a material impact on our results of operations and financial condition. The retrospective application of SFAS 160 resulted in the reclassification of approximately $169.1 million and $122.5 million from “Minority interest in consolidated partnership” to “Noncontrolling interest” at December 31, 2008 and 2007, respectively, on our Consolidated Balance Sheets included in our Recast Financial Statements.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (“SFAS 161”)

     In March 2008, the FASB issued SFAS 161, which amends SFAS 133, to require enhanced disclosures about: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for fiscal years beginning on or after November 15, 2008, with early application encouraged. The adoption of SFAS 161 will require additional disclosures regarding our derivative instruments; however, it will not impact our results of operations or financial condition.

SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”)

     In May 2008, the FASB issued SFAS 162, which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. SFAS 162 was effective November 15, 2008. The adoption of SFAS 162 did not impact our results of operations or financial condition.

FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”)

     In June 2008, the FASB issued FSP EITF 03-6-1, which addresses whether instruments granted in equity-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation for computing basic earnings per share (“EPS”) under the two-class method described by SFAS No. 128, “Earnings per Share.” FSP EITF 03-6-1 is retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. The adoption of FSP EITF 03-6-1 on January 1, 2009 did not have a material impact on our results of operations or financial condition. All periods presented in our Recast Financial Statements have been restated to reflect the adoption of FSP EITF 03-6-1. The retrospective application of FSP EITF 03-6-1 reduced our basic earnings per common share by $0.14 and $0.03 for 2008 and 2006 and reduced our diluted earnings per share by $0.06, $0.01, and $0.01 for 2008, 2007, and 2006, respectively. The adoption of FSP EITF 03-6-1 did not have an impact on our basic earnings per share for 2007.

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Exhibit 99.3

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

	Page
Report of Independent Registered Public Accounting Firm		1
Consolidated Balance Sheets as of December 31, 2008 and 2007		2
Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007, and 2006		3
Consolidated Statements of Equity and Comprehensive Income for the Years Ended December 31, 2008, 2007, and 2006		4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007, and 2006		5
Notes to Consolidated Financial Statements		6
Supplementary Information		48

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Encore Acquisition Company:

We have audited the accompanying consolidated balance sheets of Encore Acquisition Company (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Encore Acquisition Company at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 9 to the consolidated financial statements, effective January 1, 2007, the Company adopted Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109.”

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2009 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP  

Fort Worth, Texas
February 24, 2009, except for the matters related to the retrospective adoptions of SFAS No. 160 and FSP EITF 03-6-1 and the reorganization of operating segments described in Notes 2, 11 and 18 as to which the date is January 25, 2010

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ENCORE ACQUISITION COMPANY

CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share amounts)

	December 31,
	2008			2007
ASSETS
Current assets:
Cash and cash equivalents	$	2,039		$	1,704
Accounts receivable, net of allowance for doubtful accounts of $381 and $0, respectively		129,065			134,880
Inventory		24,798			16,257
Derivatives		349,344			9,722
Deferred taxes		—			20,420
Income taxes receivable		29,445			2,661
Other		6,239			2,866
Total current assets		540,930			188,510
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		3,538,459			2,845,776
Unproved properties		124,339			63,352
Accumulated depletion, depreciation, and amortization		(771,564	)		(489,004	)
		2,891,234			2,420,124
Other property and equipment		25,192			21,750
Accumulated depreciation		(12,753	)		(10,733	)
		12,439			11,017
Goodwill		60,606			60,606
Derivatives		38,497			34,579
Long-term receivables, net of allowance for doubtful accounts of $7,643 and $6,045, respectively		60,915			40,945
Other		28,574			28,780
Total assets	$	3,633,195		$	2,784,561
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	10,017		$	21,548
Accrued liabilities:
Lease operating		19,108			15,057
Development capital		79,435			48,359
Interest		11,808			12,795
Production, ad valorem, and severance taxes		25,133			24,694
Marketing		3,594			8,721
Derivatives		63,476			39,337
Oil and natural gas revenues payable		10,821			13,076
Deferred taxes		105,768			—
Other		23,092			21,143
Total current liabilities		352,252			204,730
Derivatives		8,922			47,091
Future abandonment cost, net of current portion		48,058			27,371
Deferred taxes		416,915			312,914
Long-term debt		1,319,811			1,120,236
Other		3,989			1,530
Total liabilities		2,149,947			1,713,872
Commitments and contingencies (see Note 4)
Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par value, 144,000,000 shares authorized, 51,551,937 and 53,303,464 issued and outstanding, respectively		516			534
Additional paid-in capital		525,763			538,620
Treasury stock, at cost, of 4,753 and 17,690 shares, respectively		(101	)		(590	)
Retained earnings		789,698			411,377
Accumulated other comprehensive loss		(1,748	)		(1,786	)
Total EAC stockholders’ equity		1,314,128			948,155
Noncontrolling interest		169,120			122,534
Total equity		1,483,248			1,070,689
Total liabilities and equity	$	3,633,195		$	2,784,561

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

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ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)

	Year Ended December 31,
	2008			2007			2006
Revenues:
Oil	$	897,443		$	562,817		$	346,974
Natural gas		227,479			150,107			146,325
Marketing		10,496			42,021			147,563
Total revenues		1,135,418			754,945			640,862
Expenses:
Production:
Lease operating		175,115			143,426			98,194
Production, ad valorem, and severance taxes		110,644			74,585			49,780
Depletion, depreciation, and amortization		228,252			183,980			113,463
Impairment of long-lived assets		59,526			—			—
Exploration		39,207			27,726			30,519
General and administrative		48,421			39,124			23,194
Marketing		9,570			40,549			148,571
Derivative fair value loss (gain)		(346,236	)		112,483			(24,388	)
Provision for doubtful accounts		1,984			5,816			1,970
Other operating		12,975			17,066			8,053
Total expenses		339,458			644,755			449,356
Operating income		795,960			110,190			191,506
Other income (expenses):
Interest		(73,173	)		(88,704	)		(45,131	)
Other		3,898			2,667			1,429
Total other expenses		(69,275	)		(86,037	)		(43,702	)
Income before income taxes		726,685			24,153			147,804
Income tax provision		(241,621	)		(14,476	)		(55,406	)
Consolidated net income		485,064			9,677			92,398
Less: net loss (income) attributable to noncontrolling interest		(54,252	)		7,478			—
Net income attributable to EAC stockholders	$	430,812		$	17,155		$	92,398
Net income per common share:
Basic	$	8.10		$	0.32		$	1.75
Diluted	$	8.01		$	0.31		$	1.74
Weighted average common shares outstanding:
Basic		52,270			53,170			51,865
Diluted		52,866			53,629			52,356

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

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ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF EQUITY AND COMPREHENSIVE INCOME
(in thousands)

	EAC Stockholders
	Issued																		Accumulated
	Shares of						Additional			Shares of									Other
	Common			Common			Paid-in			Treasury			Treasury			Retained			Comprehensive			Noncontrolling			Total
	Stock			Stock			Capital			Stock			Stock			Earnings			Loss			Interest			Equity
Balance at December 31, 2005		48,785		$	488		$	316,619			(11	)	$	(375	)	$	302,875		$	(72,826	)	$	—		$	546,781
Exercise of stock options and vesting of restricted stock		280			3			3,641			—			—			—			—			—			3,644
Purchase of treasury stock		—			—			—			(25	)		(633	)		—			—			—			(633	)
Cancellation of treasury stock		(18	)		—			(195	)		18			551			(356	)		—			—			—
Issuance of common stock		4,000			40			127,061			—			—			—			—			—			127,101
Non-cash stock-based compensation		—			—			10,075			—			—			—			—			—			10,075
Components of comprehensive income:
Net income		—			—			—			—			—			92,398			—			—			92,398
Change in deferred hedge gain/loss, net of tax of $22,365		—			—			—			—			—			—			37,499			—			37,499
Total comprehensive income																										129,897
Balance at December 31, 2006		53,047			531			457,201			(18	)		(457	)		394,917			(35,327	)		—			816,865
Exercise of stock options and vesting of restricted stock		313			3			1,587			—			—			—			—			—			1,590
Purchase of treasury stock		—			—			—			(39	)		(1,136	)		—			—			—			(1,136	)
Cancellation of treasury stock		(39	)		—			(338	)		39			1,003			(665	)		—			—			—
Non-cash equity-based compensation		—			—			14,632			—			—			—			—			2,627			17,259
ENP issuance of common units, net of offering costs		—			—			(12,088	)		—			—			—			—			205,549			193,461
ENP cash distributions to noncontrolling interests		—			—			—			—			—			(30	)		—			(538	)		(568	)
Adjustment to reflect gain on ENP issuance of common units		—			—			77,626			—			—			—			—			(77,626	)		—
Components of comprehensive income:
Net income		—			—			—			—			—			17,155			—			(7,478	)		9,677
Amortization of deferred hedge losses, net of tax of $20,047		—			—			—			—			—			—			33,541			—			33,541
Total comprehensive income																										43,218
Balance at December 31, 2007		53,321			534			538,620			(18	)		(590	)		411,377			(1,786	)		122,534			1,070,689
Exercise of stock options and vesting of restricted stock		300			2			2,620			—			—			—			—			—			2,622
Repurchase and retirement of common stock		(2,018	)		(20	)		(19,279	)		—			—			(47,871	)		—			—			(67,170	)
Purchase of treasury stock		—			—			—			(33	)		(1,055	)		—			—			—			(1,055	)
Cancellation of treasury stock		(46	)		—			(465	)		46			1,544			(1,079	)		—			—			—
Non-cash equity-based compensation		—			—			14,505			—			—			—			—			1,697			16,202
ENP issuance of common units		—			—			—			—			—			—			—			5,748			5,748
ENP cash distributions to noncontrolling interests		—			—			—			—			—			(3,541	)		—			(24,004	)		(27,545	)
Adjustment to reflect gain on ENP issuance of common units		—			—			3,458			—			—			—			—			(3,458	)		—
Economic uniformity adjustment related to conversion of management incentive units		—			—			(13,920	)		—			—			—			—			13,920			—
Other		—			—			224			—			—			—			—			—			224
Components of comprehensive income:
Net income		—			—			—			—			—			430,812			—			54,252			485,064
Change in deferred hedge loss on interest rate swaps, net of tax of $957		—			—			—			—			—			—			(1,748	)		(1,569	)		(3,317	)
Amortization of deferred loss on commodity derivative contracts, net of tax of $1,071		—			—			—			—			—			—			1,786			—			1,786
Total comprehensive income																										483,533
Balance at December 31, 2008		51,557		$	516		$	525,763			(5	)	$	(101	)	$	789,698		$	(1,748	)	$	169,120		$	1,483,248

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

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ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

	Year Ended December 31,
	2008			2007			2006
Cash flows from operating activities:
Consolidated net income	$	485,064		$	9,677		$	92,398
Adjustments to reconcile consolidated net income to net cash provided by operating activities:
Depletion, depreciation, and amortization		228,252			183,980			113,463
Impairment of long-lived assets		59,526			—			—
Non-cash exploration expense		34,874			25,487			28,128
Deferred taxes		232,614			12,588			51,220
Non-cash equity-based compensation expense		14,115			15,997			8,980
Non-cash derivative loss (gain)		(299,914	)		130,910			(10,434	)
Loss (gain) on disposition of assets		(3,623	)		7,409			(297	)
Provision for doubtful accounts		1,984			5,816			1,970
Other		6,479			10,182			7,577
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		(8,488	)		(48,647	)		(2,275	)
Current derivatives		(13,681	)		(17,430	)		—
Other current assets		(35,495	)		3,108			(4,945	)
Long-term derivatives		(8,601	)		(35,750	)		—
Other assets		(2,174	)		(1,214	)		(365	)
Accounts payable		(11,468	)		4,461			1,833
Other current liabilities		(14,351	)		14,788			10,080
Other noncurrent liabilities		(1,876	)		(1,655	)		—
Net cash provided by operating activities		663,237			319,707			297,333
Cash flows from investing activities:
Proceeds from disposition of assets		4,235			287,928			1,522
Purchases of other property and equipment		(4,208	)		(3,519	)		(4,290	)
Acquisition of oil and natural gas properties		(142,559	)		(848,545	)		(30,119	)
Development of oil and natural gas properties		(560,997	)		(335,897	)		(340,582	)
Net advances to working interest partners		(24,817	)		(29,523	)		(22,425	)
Other		—			—			(1,536	)
Net cash used in investing activities		(728,346	)		(929,556	)		(397,430	)
Cash flows from financing activities:
Proceeds from issuance of common stock, net of issuance costs		—			—			127,101
Proceeds from issuance of ENP common units, net of issuance costs		—			193,461			—
Repurchase and retirement of common stock		(67,170	)		—			—
Exercise of stock options and vesting of restricted stock, net of treasury stock purchases		1,567			454			3,011
Proceeds from long-term debt, net of issuance costs		1,370,339			1,479,259			281,853
Payments on long-term debt		(1,172,500	)		(1,034,428	)		(294,000	)
Payment of commodity derivative contract premiums		(39,184	)		(26,195	)		(7,848	)
ENP cash distributions to noncontrolling interests		(27,545	)		(568	)		—
Change in cash overdrafts		(63	)		(1,193	)		(10,911	)
Net cash provided by financing activities		65,444			610,790			99,206
Increase (decrease) in cash and cash equivalents		335			941			(891	)
Cash and cash equivalents, beginning of period		1,704			763			1,654
Cash and cash equivalents, end of period	$	2,039		$	1,704		$	763

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

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ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Description of Business

     Encore Acquisition Company (together with its subsidiaries, “EAC”), a Delaware corporation, is engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States. Since 1998, EAC has acquired producing properties with proven reserves and leasehold acreage and grown the production and proven reserves by drilling, exploring, and reengineering or expanding existing waterflood projects. EAC’s properties and oil and natural gas reserves are located in four core areas:

• the Cedar Creek Anticline (“CCA”) in the Williston Basin in Montana and North Dakota;

• the Permian Basin in West Texas and southeastern New Mexico;

• the Rockies, which includes non-CCA assets in the Williston, Big Horn, and Powder River Basins in Wyoming, Montana, and North Dakota, and the Paradox Basin in southeastern Utah; and

• the Mid-Continent area, which includes the Arkoma and Anadarko Basins in Oklahoma, the North Louisiana Salt Basin, the East Texas Basin, and the Mississippi Salt Basin.

Note 2. Summary of Significant Accounting Policies

Recast of Consolidated Financial Statements and Notes to Consolidated Financial Statements

     On January 1, 2009, EAC adopted new guidance issued by the Financial Accounting Standards Board (the “FASB”) on the accounting for noncontrolling interests and new guidance relating to the treatment of equity-based payment transactions in the calculation of earnings per share. The retrospective application of the new guidance on noncontrolling interests resulted in the reclassification of approximately $169.1 million and $122.5 million from “Minority interest in consolidated partnership” to “Noncontrolling interest” at December 31, 2008 and 2007, respectively, on the accompanying Consolidated Balance Sheets. The retrospective application of the new guidance on earnings per share reduced EAC’s basic earnings per common share by $0.14 and $0.03 for the years ended December 31, 2008 and 2006 and reduced EAC’s diluted earnings per share by $0.06, $0.01, and $0.01 for the years ended December 31, 2008, 2007, and 2006, respectively. The adoption of the revised guidance on earnings per share did not have an impact on EAC’s basic earnings per share for the year ended December 31, 2007.

     In August 2009, Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly owned guarantor subsidiary of EAC, sold certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota (the “Rockies and Permian Basin Assets”) to Encore Energy Partners LP (together with its subsidiaries, “ENP”), a publicly traded Delaware limited partnership, for approximately $186.8 million in cash. In June 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Williston Basin in North Dakota and Montana (the “Williston Basin Assets”) to ENP for approximately $25.2 million in cash. In January 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”), to ENP for approximately $46.4 million in cash. Because these assets were sold to an affiliate, the dispositions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby ENP recorded the assets and liabilities of the acquired properties at Encore Operating’s carrying value and ENP’s historical financial information was recast to include the acquired properties for all periods presented. Accordingly, EAC’s segment information for ENP in these notes to consolidated financial statements reflect the historical results of ENP combined with those of the Arkoma Basin Assets, the Williston Basin Assets, and the Rockies and Permian Basin Assets for all periods presented.

     As a result of the above noted transactions, the consolidated financial statements, notes to consolidated financial statements (including Notes 2, 9, 11, 16, and 18), and unaudited supplementary information have been revised.

Principles of Consolidation

     EAC’s consolidated financial statements include the accounts of its wholly owned and majority-owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.

     In February 2007, EAC formed ENP to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. In September 2007, ENP completed its initial public offering (“IPO”). As of December 31, 2008 and 2007, EAC owned approximately 63 percent and 58 percent, respectively, of ENP’s common units, as well as all of the interests of Encore Energy Partners GP LLC (“GP LLC”), a Delaware limited liability company and ENP’s general partner, which is an indirect wholly owned non-guarantor subsidiary of EAC. Considering the presumption of control of GP LLC in accordance with Emerging Issues Task Force (“EITF”) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” the financial position, results of operations,

6

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

and cash flows of ENP are consolidated with those of EAC. EAC elected to account for gains on ENP’s issuance of common units as capital transactions as permitted by Staff Accounting Bulletin (“SAB”) Topic 5H, “Accounting for Sales of Stock by a Subsidiary.” Please read “Note 10. Stockholders’ Equity” for additional discussion.

     As presented in the accompanying Consolidated Balance Sheets, “Noncontrolling interest” as of December 31, 2008 and 2007 of $169.1 million and $122.5 million, respectively, represents third-party ownership interests in ENP. As presented in the accompanying Consolidated Statements of Operations, “Net income attributable to noncontrolling interest” for 2008 of $54.3 million and “Net loss attributable to noncontrolling interest” for 2007 of $7.5 million represents ENP’s results of operations attributable to third-party owners.

     The following table summarizes the effects of changes in EAC’s partnership interest in ENP on EAC’s equity for the periods indicated:

	Year Ended December 31,
	2008		2007
	(in thousands)
Net income attributable to EAC stockholders	$	430,812	$	17,155
Transfer from (to) noncontrolling interest:
Increase in EAC’s paid-in capital for ENP’s issuance of 10,148,400 common units in public offering		—		77,626
Increase in EAC’s paid-in capital for ENP’s issuance of 283,700 common units in connection with acquisition of net profits interest in certain Crockett County properties		3,458		—
Net transfer from noncontrolling interest		3,458		77,626
Change from net income attributable to EAC stockholders and transfers from (to) noncontrolling interest	$	434,270	$	94,781

Use of Estimates

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

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

Cash and Cash Equivalents

     Cash and cash equivalents include cash in banks, money market accounts, and all highly liquid investments with an original maturity of three months or less. On a bank-by-bank basis and considering legal right of offset, cash accounts that are overdrawn are reclassified to current liabilities and any change in cash overdrafts is shown as “Change in cash overdrafts” in the “Financing activities” section of EAC’s Consolidated Statements of Cash Flows.

Supplemental Disclosures of Cash Flow Information

     The following table sets forth supplemental disclosures of cash flow information for the periods indicated:

7

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

	Year ended December 31,
	2008		2007		2006
	(In thousands)
Cash paid during the period for:
Interest	$	67,519	$	82,649	$	46,389
Income taxes		33,110		260		464
Non-cash investing and financing activities:
Deferred premiums on commodity derivative contracts		53,387		20,341		30,319
ENP’s issuance of common units in connection with acquisition of net profits interest in certain Crockett County properties		5,748		—		—

Accounts Receivable

     Trade accounts receivable, which are primarily from oil and natural gas sales, are recorded at the invoiced amount and do not bear interest with the exception of the current portion of balances due from ExxonMobil Corporation (“ExxonMobil”) in connection with EAC’s joint development agreement. Please read “Note 4. Commitments and Contingencies” for additional discussion of this agreement. EAC routinely reviews outstanding accounts receivable balances and assesses the financial strength of its customers and records a reserve for amounts not expected to be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. The following table summarizes the changes in allowance for doubtful accounts for the periods indicated:

	Year Ended December 31,
	2008			2007
	(in thousands)
Allowance for doubtful accounts at January 1	$	6,045		$	2,329
Bad debt expense		1,984			5,816
Write off		(5	)		(2,100	)
Allowance for doubtful accounts at December 31	$	8,024		$	6,045

     Of the $8.0 million in allowance for doubtful accounts at December 31, 2008, $0.4 million is short-term and $7.6 million is long-term.

Inventory

     Inventory includes materials and supplies and oil in pipelines, which are stated at the lower of cost (determined on an average basis) or market. Oil produced at the lease which resides unsold in pipelines is carried at an amount equal to its operating costs to produce. Oil in pipelines purchased from third parties is carried at average purchase price. Inventory consisted of the following as of the dates indicated:

	December 31,
	2008		2007
	(in thousands)
Materials and supplies	$	15,933	$	11,030
Oil in pipelines		8,865		5,227
Total inventory	$	24,798	$	16,257

Properties and Equipment

     Oil and Natural Gas Properties. EAC uses the successful efforts method of accounting for its 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.

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ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

     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 EAC’s Consolidated Statements of Operations and shown as a non-cash adjustment to net income in the “Operating activities” section of EAC’s Consolidated Statements of Cash Flows in the period in which the determination was made. If an exploratory well finds reserves but they cannot be classified as proved, EAC continues to capitalize the associated cost as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the reserves and the operating viability of the project. If subsequently it is determined that these conditions do not continue to exist, 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 EAC’s Consolidated Statements of Cash Flows in the period in which the determination is made. Re-drilling or directional drilling in a previously abandoned well is classified as development or exploratory based on whether it is in a proved or unproved reservoir. Costs for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Costs to recomplete a well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the costs would be charged to expense. All capitalized costs associated with both development and exploratory wells are shown as “Development of oil and natural gas properties” in the “Investing activities” section of EAC’s Consolidated Statements of Cash Flows.

     Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Internal costs directly associated with the development of proved properties are capitalized as a cost of the property and are classified accordingly in EAC’s consolidated financial statements. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable. Natural gas volumes are converted to barrels of oil equivalent (“BOE”) at the rate of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of oil.

     The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to accumulated DD&A.

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

     In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), EAC assesses the need for an impairment of long-lived assets to be held and used, including proved oil and natural gas properties, whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then an impairment charge is recognized to the extent that the asset’s carrying value exceeds its fair value. Expected future net cash flows are based on existing proved reserves (and appropriately risk-adjusted probable reserves), forecasted production information, and management’s outlook of future commodity prices. Any impairment charge incurred is expensed and reduces the net basis in the asset. Management aggregates proved property for impairment testing the same way as for calculating DD&A. The price assumptions used to calculate undiscounted cash flows is based on judgment. EAC uses 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.

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

     Amounts shown in the accompanying Consolidated Balance Sheets as “Proved properties, including wells and related equipment” consisted of the following as of the dates indicated:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

	December 31,
	2008		2007
	(in thousands)
Proved leasehold costs	$	1,421,859	$	1,346,516
Wells and related equipment — Completed		1,943,275		1,408,512
Wells and related equipment — In process		173,325		90,748
Total proved properties	$	3,538,459	$	2,845,776

     Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is recognized on a straight-line basis over estimated useful lives, which range from three to seven years. Leasehold improvements are capitalized and depreciated over the remaining term of the lease, which is through 2013 for EAC’s corporate headquarters. Gains or losses from the disposal of other property and equipment are recognized in the period realized and included in “Other operating expense” of EAC’s Consolidated Statements of Operations.

Goodwill and Other Intangible Assets

     EAC accounts for goodwill and other intangible assets under the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill and other intangible assets with indefinite useful lives are tested for impairment annually on December 31 or whenever indicators of impairment exist. If indicators of impairment are determined to exist, an impairment charge would be recognized for the amount by which the carrying value of the asset exceeds its implied fair value. The goodwill test is performed at the reporting unit level. EAC has determined that it has two reporting units: EAC Standalone and ENP. ENP has been allocated $2.6 million of goodwill and the remainder has been allocated to the EAC Standalone segment.

     EAC utilizes both a market capitalization and an income approach to determine the fair value of its reporting units. The primary component of the income approach is the estimated discounted future net cash flows expected to be recovered from the reporting unit’s oil and natural gas properties. EAC’s analysis concluded that there was no impairment of goodwill as of December 31, 2008. Prices for oil and natural gas have deteriorated sharply in recent months and significant uncertainty remains on how prices for these commodities will behave in the future. Any additional decreases in the prices of oil and natural gas or any negative reserve adjustments from the December 31, 2008 assessment could change EAC’s estimates of the fair value of its reporting units and could result in an impairment charge.

     Intangible assets with definite useful lives are amortized over their estimated useful lives. In accordance with SFAS 144, EAC evaluates the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.

     ENP is a party to a contract allowing it to purchase a certain amount of natural gas at a below market price for use as field fuel. The fair value of this contract, net of related amortization, is included in “Other noncurrent assets” on the accompanying Consolidated Balance Sheets. The gross carrying amount of this contract is $4.2 million and as of December 31, 2008 and 2007, accumulated amortization was $0.6 million and $0.3 million, respectively. During each of 2008 and 2007, ENP recorded $0.3 million of amortization expense related to this contract. The net carrying amount is being amortized on a straight-line basis through July 2019. ENP expects to recognize $0.3 million of amortization expense during each of the next five years related to this contract.

Asset Retirement Obligations

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

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ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Equity-Based Compensation

     EAC accounts for equity-based compensation according to the provisions of SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”), which requires the recognition of compensation expense for equity-based awards over the requisite service period in an amount equal to the grant date fair value of the awards. EAC utilizes a standard option pricing model (i.e., Black-Scholes) to measure the fair value of employee stock options under SFAS 123R. Please read “Note 12. Employee Benefit Plans” for additional discussion of EAC’s employee benefit plans.

     SFAS 123R also requires that the benefits associated with the tax deductions in excess of recognized compensation cost be reported as a financing cash flow. This requirement reduces net operating cash flows and increases net financing cash flows. EAC recognizes compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards. Compensation expense associated with awards to employees who are eligible for retirement is fully expensed on the date of grant.

Segment Reporting

     EAC operates in only one industry: the oil and natural gas exploration and production industry in the United States. However, EAC is organizationally structured along two reportable segments: EAC Standalone and ENP. EAC’s segments are components of its business for which separate financial information related to operating and development costs are available and regularly evaluated by the chief operating decision maker in deciding how to allocate capital resources to projects and in assessing performance. Please read “Note 18. Segment Information” for additional discussion. Prior to the fourth quarter of 2007, segment reporting was not applicable to EAC.

Major Customers/Concentration of Credit Risk

     The following purchasers accounted for 10 percent or greater of the sales of production for the period indicated:

	Percentage of Total Sales of
	Production for the Year Ended
	December 31,
	2008			2007			2006
Consolidated EAC
Eight-Eight Oil		14	%		14	%		(a	)
Tesoro Refining & Marketing Co		12	%		(a	)		(a	)
Shell Trading Company		(a	)		(a	)		15	%
ConocoPhillips		(a	)		(a	)		12	%
ENP
Marathon Oil Corporation		19	%		24	%		(a	)
ConocoPhillips		17	%		10	%		(a	)
Chevron Corporation		(a	)		(a	)		21	%
Sid Richardson Energy		(a	)		(a	)		13	%
Tesoro Refining & Marketing Co		15	%		17	%		(a	)
Trammo Petroleum, Inc.		(a	)		(a	)		14	%
Navajo Refining & Crude Marketing		(a	)		(a	)		16	%
EAC Standalone
Shell Trading Company		(a	)		(a	)		15	%
ConocoPhillips		(a	)		(a	)		10	%
Eight-Eight Oil		23	%		29	%		(a	)
Tesoro Refining & Marketing Co		13	%		(a	)		(a	)

(a) Less than 10 percent for the period indicated.

Income Taxes

     Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between financial

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

statement carrying amounts of existing assets and liabilities and their respective tax bases. Valuation allowances are established when necessary to reduce net deferred tax assets to amounts expected to be realized. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.

Oil and Natural Gas Revenue Recognition

     Oil and natural gas revenues are recognized as oil and natural gas is produced and sold, net of royalties and net profits interests. Royalties, net profits interests, and severance taxes are incurred 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 prices for those properties are estimated and recorded as “Accounts receivable, net” in the accompanying Consolidated Balance Sheets. Natural gas revenues are reduced by any processing and other fees incurred except for transportation costs paid to third parties, which are recorded in “Other operating expense” in the accompanying Consolidated Statements of Operations. Natural gas revenues are recorded using the sales method of accounting whereby revenue is recognized based on actual sales of natural gas rather than EAC’s proportionate share of natural gas production. If EAC’s overproduced imbalance position (i.e., EAC has cumulatively been over-allocated production) is greater than EAC’s share of remaining reserves, a liability is recorded for the excess at period-end prices unless a different price is specified in the contract in which case that price is used. Revenue is not recognized for the production in tanks, oil marketed on behalf of joint owners in EAC’s properties, or oil in pipelines that has not been delivered to the purchaser.

     EAC’s net oil inventories in pipelines were 173,119 Bbls and 124,410 Bbls at December 31, 2008 and 2007, respectively. Natural gas imbalances at December 31, 2008 and 2007, were 28,717 million British thermal units (“MMBtu”) and 128,856 MMBtu under-delivered to EAC, respectively.

Marketing Revenues and Expenses

     Marketing revenues include the sales of natural gas purchased from third parties as well as pipeline tariffs charged for transportation volumes through EAC’s pipelines. Marketing revenues derived from sales of oil and natural gas purchased from third parties are recognized when persuasive evidence of a sales arrangement exists, delivery has occurred, the sales price is fixed or determinable, and collectibility is reasonably assured. Marketing expenses include the cost of oil and natural gas volumes purchased from third parties, pipeline tariffs, storage, truck facility fees, and tank bottom costs used to support the sale of oil production. As EAC takes title to the oil and natural gas and has risks and rewards of ownership, these transactions are presented gross in the Consolidated Statements of Operations, unless they meet the criteria for netting as outlined in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.”

Shipping Costs

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

Derivatives

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

     EAC applies the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) and its amendments, which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative does not qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, changes in fair value can be recognized in accumulated other comprehensive income until such time as the hedged item is recognized in earnings.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

     To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically. Cash flow hedges are marked to market through accumulated other comprehensive income each period.

     EAC has elected to designate its current interest rate swaps as cash flow hedges. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in “Accumulated other comprehensive income” on the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized in earnings immediately as “Derivative fair value loss (gain)” in the Consolidated Statements of Operations.

     EAC has elected to not designate its current portfolio of commodity derivative contracts as hedges and therefore, changes in fair value of these instruments are recognized in earnings as “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.

Comprehensive Income

     EAC has elected to show comprehensive income as part of its Consolidated Statements of Stockholders’ Equity and Comprehensive Income rather than in its Consolidated Statements of Operations.

Reclassifications

     Certain amounts in prior periods have been reclassified to conform to the current period presentation. In particular, “Income taxes receivable” has been presented separately on the accompanying Consolidated Balance Sheets.

New Accounting Pronouncements

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

     In September 2006, the FASB issued SFAS 157, which: (1) standardizes the definition of fair value; (2) establishes a framework for measuring fair value in GAAP; and (3) expands disclosures related to the use of fair value measures in financial statements. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value, but does not require any new fair value measurements. SFAS 157 was prospectively effective for financial assets and liabilities for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delayed the effective date of SFAS 157 for one year for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). EAC elected a partial deferral of SFAS 157 for all instruments within the scope of FSP FAS 157-2, including, but not limited to, its asset retirement obligations and indefinite lived assets. EAC will continue to evaluate the impact of SFAS 157 on these instruments during the deferral period. The adoption of SFAS 157 on January 1, 2008, as it relates to financial assets and liabilities, did not have a material impact on EAC’s results of operations or financial condition. EAC does not expect the adoption of SFAS 157 on January 1, 2009, as it relates to all instruments within the scope of FSP FAS 157-2, to have a material impact on its results of operations or financial condition. Please read “Note 14. Fair Value Measurements” for additional discussion.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FASB Statement No. 115” (“SFAS 159”)

     In February 2007, the FASB issued SFAS 159, which permits entities to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis. SFAS 159 also allows entities an irrevocable option to measure eligible items at fair value at specified election dates, with resulting changes in fair value reported in earnings. SFAS 159 was effective for fiscal years beginning after November 15, 2007. EAC did not elect the fair value option for eligible instruments and therefore, the adoption of SFAS 159 on January 1, 2008 did not impact EAC’s results of operations or financial condition. EAC will assess the impact of electing the fair value option for any eligible instruments acquired in the future. Electing the fair value option for such instruments could have a material impact on EAC’s future results of operations or financial condition.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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

SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”)

     In December 2007, the FASB issued SFAS 141R, which replaces SFAS No. 141, “Business Combinations.” SFAS 141R establishes principles and requirements for the reporting entity in a business combination, including: (1) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. SFAS 141R is prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008, with early application prohibited. EAC currently does not have any pending acquisitions that would fall within the scope of SFAS 141R. Future acquisitions could impact EAC’s results of operations and financial condition and the reporting in the consolidated financial statements.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment to ARB No. 51” (“SFAS 160”)

     In December 2007, the FASB issued SFAS 160, which amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 was effective for financial statements issued for fiscal years beginning on or after December 15, 2008, except for the presentation and disclosure requirements which were retrospectively effective. SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest and the disclosure of consolidated net income attributable to the parent and to the noncontrolling interest on the face of the consolidated statement of operations and gains and losses on a subsidiaries’ issuance of equity to be accounted for as capital transactions. The adoption of SFAS 160 on January 1, 2009 did not have a material impact on EAC’s results of operations and financial condition. As previously discussed, the retrospective application of SFAS 160 resulted in the reclassification of approximately $169.1 million and $122.5 million from “Minority interest in consolidated partnership” to “Noncontrolling interest” at December 31, 2008 and 2007, respectively, on the accompanying Consolidated Balance Sheets.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161”)

     In March 2008, the FASB issued SFAS 161, which amends SFAS 133, to require enhanced disclosures about: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for fiscal years beginning on or after November 15, 2008, with early application encouraged. The adoption of SFAS 161 will require additional disclosures regarding EAC’s derivative instruments; however, it will not impact EAC’s results of operations or financial condition.

SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”)

     In May 2008, the FASB issued SFAS 162, which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. SFAS 162 was effective November 15, 2008. The adoption of SFAS 162 did not impact EAC’s results of operations or financial condition.

FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”)

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ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

     In June 2008, the FASB issued FSP EITF 03-6-1, which addresses whether instruments granted in equity-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation for computing basic earnings per share (“EPS”) under the two-class method described by SFAS No. 128, “Earnings per Share” (“SFAS 128”). FSP EITF 03-6-1 was retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. The adoption of FSP EITF 03-6-1 on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition. All periods presented in the accompanying Consolidated Financial Statements have been restated to reflect the adoption of FSP EITF 03-6-1. As previously discussed, the retrospective application of FSP EITF 03-6-1 reduced EAC’s basic earnings per common share by $0.14 and $0.03 for the years ended December 31, 2008 and 2006 and reduced EAC’s diluted earnings per share by $0.06, $0.01, and $0.01 for the years ended December 31, 2008, 2007, and 2006, respectively. The adoption of FSP EITF 03-6-1 did not have an impact on EAC’s basic earnings per share for the year ended December 31, 2007. Please read “Note 11. EPS” for additional discussion.

Note 3. Acquisitions and Dispositions

Acquisitions

     In January 2007, EAC entered into a purchase and sale agreement with certain subsidiaries of Anadarko Petroleum Corporation (“Anadarko”) to acquire oil and natural gas properties and related assets in the Williston Basin of Montana and North Dakota. The closing of the Williston Basin acquisition occurred in April 2007. The Williston Basin acquisition was treated as a reverse like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended, (the “Code”) and I.R.S. Revenue Procedure 2000-37 with the Mid-Continent disposition discussed below. The total purchase price for the Williston Basin assets was approximately $392.1 million, including transaction costs of approximately $1.3 million.

     Also in January 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 and related assets in the Gooseberry field in Park County, Wyoming. Prior to closing, EAC assigned the rights and duties under the purchase and sale agreement relating to the Elk Basin assets to Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly owned subsidiary of ENP, and the rights and duties under the purchase and sale agreement relating to the Gooseberry assets to Encore Operating. The closing of the Big Horn Basin acquisition occurred in March 2007. The total purchase price for the Big Horn Basin assets was approximately $393.6 million, including transaction costs of approximately $1.3 million.

     EAC financed the acquisitions of the Gooseberry assets and Williston Basin assets through borrowings under its revolving credit facility. ENP financed the acquisition of the Elk Basin assets through a $93.7 million contribution from EAC, $120 million of borrowings under a subordinated credit agreement with EAP Operating, LLC, a Delaware limited liability company and direct wholly owned guarantor subsidiary of EAC, and borrowings under OLLC’s revolving credit facility. Please read “Note 8. Long-Term Debt” for additional discussion of EAC’s long-term debt.

Dispositions

     In June 2007, EAC completed the sale of certain oil and natural gas properties in the Mid-Continent area, and in July 2007, additional Mid-Continent properties that were subject to preferential rights were sold. EAC received total net proceeds of approximately $294.8 million, after deducting transaction costs of approximately $3.6 million, and recorded a loss on sale of approximately $7.4 million. The disposed properties included certain properties in the Anadarko and Arkoma Basins of Oklahoma. EAC retained material oil and natural gas interests in other properties in these basins and remains active in those areas. Proceeds from the Mid-Continent asset disposition were used to reduce outstanding borrowings under EAC’s revolving credit facility.

Pro Formas

     The following unaudited pro forma condensed financial data was derived from the historical financial statements of EAC and from the accounting records of Anadarko to give effect to the Big Horn Basin and Williston Basin asset acquisitions and the Mid-Continent asset disposition as if they had each occurred on January 1, 2006. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Big

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ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Horn Basin and Williston Basin asset acquisitions and the Mid-Continent asset disposition taken place on January 1, 2006 and is not intended to be a projection of future results.

	Year Ended December 31,
	2007		2006
	(in thousands, except per share amounts)
Pro forma total revenues	$	749,659	$	785,281
Pro forma net income attributable to EAC stockholders	$	20,685	$	100,702
Pro forma net income per common share:
Basic	$	0.38	$	1.91
Diluted	$	0.38	$	1.89

Note 4. Commitments and Contingencies

Litigation

     EAC 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 EAC’s business, financial position, results of operations, or liquidity.

Leases

     EAC leases office space and equipment that have remaining non-cancelable lease terms in excess of one year. The following table summarizes by year the remaining non-cancelable future payments under these operating leases as of December 31, 2008 (in thousands):

2009	$	3,603
2010		3,609
2011		3,598
2012		3,358
2013		2,607
Thereafter		—
	$	16,775

     EAC’s operating lease rental expense was approximately $5.8 million, $5.5 million, and $4.6 million in 2008, 2007, and 2006, respectively.

ExxonMobil

     In March 2006, EAC entered into a joint development agreement with ExxonMobil to develop legacy natural gas fields in West Texas. Under the terms of the agreement, EAC has the opportunity to develop approximately 100,000 gross acres and earns 30 percent of ExxonMobil’s working interest and 22.5 percent of ExxonMobil’s net revenue interest in each well drilled. EAC operates each well during the drilling and completion phase, after which ExxonMobil assumes operational control of the well.

     In July 2008, EAC earned the right to participate in all fields by drilling the final well of the 24-well commitment program and is entitled to a 30 percent working interest in future drilling locations. EAC has the right to propose and drill wells for as long as it is engaged in continuous drilling operations.

     During 2008 and 2007, EAC advanced $38.0 million and $37.7 million, respectively, to ExxonMobil for its portion of costs incurred drilling wells under the joint development agreement. At December 31, 2008, EAC had a net receivable from ExxonMobil of $79.0 million, of which $11.2 million was included in “Accounts receivable, net” and $67.8 million was included in “Long-term receivables” on the accompanying Consolidated Balance Sheet based on when EAC expects repayment. At December 31, 2007, EAC

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had a net receivable from ExxonMobil of $51.7 million, of which $12.3 million was included in “Accounts receivable, net” and $39.4 million was included in “Long-term receivables, net” on the accompanying Consolidated Balance Sheet.

Note 5. Asset Retirement Obligations

     Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. As of December 31, 2008 and 2007, EAC had $9.2 million and $6.7 million, respectively, held in escrow from which funds are released only for reimbursement of plugging and abandonment expenses on its Bell Creek properties, which is included in other long-term assets in the accompanying Consolidated Balance Sheets. The following table summarizes the changes in EAC’s asset retirement obligations for the periods indicated:

	Year Ended December 31,
	2008			2007
	(in thousands)
Future abandonment liability at January 1	$	28,079		$	19,841
Wells drilled		498			145
Acquisition of properties		111			8,251
Disposition of properties		—			(959	)
Accretion of discount		1,361			1,145
Plugging and abandonment costs incurred		(1,756	)		(1,655	)
Revision of previous estimates		21,276			1,311
Future abandonment liability at December 31	$	49,569		$	28,079

     As of December 31, 2008, $48.1 million of EAC’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $1.5 million were current and included in “Other current liabilities” on the accompanying Consolidated Balance Sheets. Approximately $4.4 million of the future abandonment liability as of December 31, 2008 represents the estimated cost for decommissioning ENP’s Elk Basin natural gas processing plant. ENP expects to continue reserving additional amounts based on the estimated timing to cease operations of the natural gas processing plant.

Note 6. Capitalization of Exploratory Well Costs

     EAC follows FSP No. 19-1 “Accounting for Suspended Well Costs” (“FSP 19-1”), which permits the continued capitalization of exploratory well costs if the well found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The following table reflects the net changes in capitalized exploratory well costs during the periods indicated, and does not include amounts that were capitalized and subsequently expensed in the same period.

	Year Ended December 31,
	2008			2007			2006
	(in thousands)
Beginning balance at January 1	$	19,479		$	13,048		$	6,560
Additions to capitalized exploratory well costs pending the determination of proved reserves		28,757			19,479			13,048
Reclassification to proved property and equipment based on the determination of proved reserves		(19,229	)		(9,390	)		(1,457	)
Capitalized exploratory well costs charged to expense		(250	)		(3,658	)		(5,103	)
Total	$	28,757		$	19,479		$	13,048

     All capitalized exploratory well costs have been capitalized for less than one year.

Note 7. Other Current Liabilities

     Other current liabilities consisted of the following as of the dates indicated:

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	December 31,
	2008		2007
	(in thousands)
Net profits interests payable	$	995	$	3,996
Income taxes payable		940		2,789
Accrued compensation		16,216		8,431
Current portion of future abandonment liability		1,511		708
Other		3,430		5,219
Total	$	23,092	$	21,143

Note 8. Long-Term Debt

     Long-term debt consisted of the following as of the dates indicated:

	Maturity		December 31,
	Date		2008		2007
			(in thousands)
Revolving credit facilities		3/7/2012	$	725,000	$	526,000
6.25% Senior Subordinated Notes		4/15/2014		150,000		150,000
6.0% Senior Subordinated Notes, net of unamortized discount of $3,960 and $4,440, respectively		7/15/2015		296,040		295,560
7.25% Senior Subordinated Notes, net of unamortized discount of $1,229 and $1,324, respectively		12/1/2017		148,771		148,676
Total			$	1,319,811	$	1,120,236

Senior Subordinated Notes

     As of December 31, 2008 certain of EAC’s subsidiaries were subsidiary guarantors of EAC’s senior subordinated notes. The subsidiary guarantors may without restriction transfer funds to EAC in the form of cash dividends, loans, and advances. Please read “Note 16. Financial Statements of Subsidiary Guarantors” for additional discussion.

     The indentures governing EAC’s senior subordinated notes contain certain affirmative, negative, and financial covenants, which include:

• limitations on incurrence of additional debt, restrictions on asset dispositions, and restricted payments;

• a requirement that EAC maintain a current ratio (as defined in the indentures) of not less than 1.0 to 1.0; and

• a requirement that EAC maintain a ratio of consolidated EBITDA (as defined in the indentures) to consolidated interest expense of not less than 2.5 to 1.0.

As of December 31, 2008, EAC was in compliance with all covenants of its senior subordinated notes.

     If EAC experiences a change of control (as defined in the indentures), subject to certain conditions, it must give holders of its senior subordinated notes the opportunity to sell them to EAC at 101 percent of the principal amount, plus accrued and unpaid interest.

Revolving Credit Facilities

     Encore Acquisition Company Senior Secured Credit Agreement

     In March 2007, EAC entered into a five-year amended and restated credit agreement (as amended, the “EAC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The EAC Credit Agreement matures on March 7, 2012. Effective February 7, 2008, EAC amended the EAC Credit Agreement to, among other things, provide that certain negative covenants in the EAC Credit Agreement restricting hedge transactions do not apply to any oil and natural gas hedge transaction that is a floor or put transaction not requiring any future payments or delivery by EAC or any of its restricted subsidiaries. Effective May 22, 2008, EAC amended the EAC Credit Agreement to, among other things, increase interest rate margins applicable to loans made under the EAC Credit Agreement, as set forth in the table below, and increase the borrowing base to $1.1 billion. The EAC Credit Agreement

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provides for revolving credit loans to be made to EAC from time to time and letters of credit to be issued from time to time for the account of EAC or the account of any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the EAC Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. On December 5, 2008, the borrowing base under the EAC Credit Agreement was redetermined with no change. As of December 31, 2008, the borrowing base was $1.1 billion.

     EAC’s obligations under the EAC Credit Agreement are secured by a first-priority security interest in EAC’s restricted subsidiaries’ proved oil and natural gas reserves and in EAC’s equity interests in its restricted subsidiaries. In addition, EAC’s obligations under the EAC Credit Agreement are guaranteed by its restricted subsidiaries.

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

	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.250	%		0.000	%
Greater than or equal to .50 to 1 but less than .75 to 1		1.500	%		0.250	%
Greater than or equal to .75 to 1 but less than .90 to 1		1.750	%		0.500	%
Greater than or equal to .90 to 1		2.000	%		0.750	%

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by EAC) is the rate per year equal to LIBOR, as published by Reuters or another source designated by Bank of America, N.A., for deposits in dollars for a similar interest period. The “base rate” is calculated as the higher of (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 percent.

     Any outstanding letters of credit reduce the availability under the EAC Credit Agreement. Borrowings under the EAC Credit Agreement may be repaid from time to time without penalty.

     The EAC 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 EAC’s and its restricted subsidiaries’ assets, subject to permitted exceptions;

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

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

• a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

• a requirement that we maintain a ratio of consolidated current assets (as defined in the EAC Credit Agreement) to consolidated current liabilities (as defined in the EAC Credit Agreement) of not less than 1.0 to 1.0; and

• a requirement that we maintain a ratio of consolidated EBITDA (as defined in the EAC 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 EAC 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 EAC Credit Agreement to be immediately due and payable.

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

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	Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .50 to 1		0.250	%
Greater than or equal to .50 to 1 but less than .75 to 1		0.300	%
Greater than or equal to .75 to 1		0.375	%

     On December 31, 2008, there were $575 million of outstanding borrowings and $525 million of borrowing capacity under the EAC Credit Agreement. As of December 31, 2008, EAC was in compliance with all covenants of the EAC Credit Agreement.

     Encore Energy Partners Operating LLC Credit Agreement

     OLLC is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “OLLC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The OLLC Credit Agreement matures on March 7, 2012. On August 22, 2007, OLLC amended its credit agreement to revise certain financial covenants. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. On December 5, 2008, the borrowing base under the OLLC Credit Agreement was redetermined with no change. As of December 31, 2008, the borrowing base was $240 million.

     OLLC’s obligations under the OLLC Credit Agreement are secured by a first-priority security interest in OLLC’s proved oil and natural gas reserves and in the equity interests in OLLC and its restricted subsidiaries. In addition, OLLC’s obligations under the OLLC Credit Agreement are guaranteed by ENP and OLLC’s restricted subsidiaries. EAC consolidates the debt of ENP with that of its own; however, obligations under the OLLC Credit Agreement are non-recourse to EAC and its restricted subsidiaries.

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

	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.000	%		0.000	%
Greater than or equal to .50 to 1 but less than .75 to 1		1.250	%		0.000	%
Greater than or equal to .75 to 1 but less than .90 to 1		1.500	%		0.250	%
Greater than or equal to .90 to 1		1.750	%		0.500	%

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate per year equal to LIBOR, as published by Reuters or another source designated by Bank of America, N.A., for deposits in dollars for a similar interest period. The “base rate” is calculated as the higher of (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 percent.

     Any outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.

     The OLLC Credit Agreement contains covenants that include, among others:

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

• a prohibition against purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;

• a restriction on creating liens on the assets of ENP, 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;

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• a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

• a requirement that ENP and OLLC maintain a ratio of consolidated current assets (as defined in the OLLC Credit Agreement) to consolidated current liabilities (as defined in the OLLC Credit Agreement) of not less than 1.0 to 1.0;

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC Credit Agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 1.5 to 1.0;

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC Credit Agreement) to consolidated senior interest expense of not less than 2.5 to 1.0; and

• a requirement that ENP and 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.

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

	Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .50 to 1		0.250	%
Greater than or equal to .50 to 1 but less than .75 to 1		0.300	%
Greater than or equal to .75 to 1		0.375	%

     On December 31, 2008, there were $150 million of outstanding borrowings and $90 million of borrowing capacity under the OLLC Credit Agreement. As of December 31, 2008, OLLC was in compliance with all covenants of the OLLC Credit Agreement.

Long-Term Debt Maturities

     The following table illustrates EAC’s long-term debt maturities as of December 31, 2008:

	Payments Due by Period
	Total		2009		2010		2011		2012		2013		Thereafter
	(in thousands)
6.25% Notes	$	150,000	$	—	$	—	$	—	$	—	$	—	$	150,000
6.0% Notes		300,000		—		—		—		—		—		300,000
7.25% Notes		150,000		—		—		—		—		—		150,000
Revolving credit facilities		725,000		—		—		—		725,000		—		—
Total	$	1,325,000	$	—	$	—	$	—	$	725,000	$	—	$	600,000

     During 2008, 2007, and 2006, the weighted average interest rate for total indebtedness was 5.6 percent, 6.9 percent, and 6.1 percent, respectively.

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Note 9. Taxes

Income Taxes

     The components of income tax provision were as follows for the periods indicated:

	Year Ended December 31,
	2008			2007			2006
	(in thousands)
Federal:
Current	$	(7,626	)	$	(1,888	)	$	(3,785	)
Deferred		(222,651	)		(11,229	)		(48,327	)
Total federal		(230,277	)		(13,117	)		(52,112	)
State, net of federal benefit:
Current		(1,381	)		—			(401	)
Deferred		(9,963	)		(1,359	)		(2,893	)
Total state		(11,344	)		(1,359	)		(3,294	)
Income tax provision (a)	$	(241,621	)	$	(14,476	)	$	(55,406	)

(a) Excludes an excess tax benefit related to stock option exercises and vesting of restricted stock, which was recorded directly to additional paid-in capital, of $2.1 million and $1.3 million during 2008 and 2006, respectively. During 2007, EAC did not recognize an excess tax benefit related to stock option exercises and vesting of restricted stock.

     The following table reconciles income tax provision with income tax at the Federal statutory rate for the periods indicated:

	Year Ended December 31,
	2008			2007			2006
	(in thousands)
Income before income taxes	$	726,685		$	24,153		$	147,804
Income taxes at the Federal statutory rate	$	(254,340	)	$	(8,454	)	$	(51,731	)
State income taxes, net of federal benefit		(12,861	)		(716	)		(3,440	)
Enactment of the Texas margin tax		—			—			(1,062	)
Change in estimated future state tax rate		2,113			(495	)		1,208
Nondeductible deferred compensation expense		(1,124	)		(1,963	)		—
Tax on income attributable to noncontrolling interest		18,988			(2,617	)		—
Permanent and other		5,603			(231	)		(381	)
Income tax provision	$	(241,621	)	$	(14,476	)	$	(55,406	)

     A Texas franchise tax reform measure signed into law in May 2006 caused the Texas franchise tax to be applicable to numerous types of entities that previously were not subject to the tax, including several of EAC’s subsidiaries. EAC adjusted its net deferred tax balances using the new higher marginal tax rate it expects to be effective when those deferred taxes reverse resulting in a charge of $1.1 million during 2006.

     The major components of net current deferred taxes and net long-term deferred taxes were as follows as of the dates indicated:

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	December 31,
	2008			2007
	(in thousands)
Current:
Assets:
Unrealized hedge loss in accumulated other comprehensive loss	$	222		$	1,071
Derivative fair value loss		—			15,442
Other		2,422			3,907
Total current deferred tax assets		2,644			20,420
Liabilities:
Derivative fair value gain		(108,412	)		—
Total current deferred tax liabilities		(108,412	)		—
Net current deferred tax asset (liability)	$	(105,768	)	$	20,420
Long-term:
Assets:
Alternative minimum tax credits	$	2,300		$	2,676
Unrealized hedge loss in accumulated other comprehensive loss		735			—
Derivative fair value loss		—			10,775
Section 43 credits		8,889			13,227
Net operating loss carryforward		1,439			23,806
Change in accounting method		5,583			—
Asset retirement obligations		17,842			11,266
Deferred equity-based compensation		6,757			6,599
Other		1,556			—
Total long-term deferred tax assets		45,101			68,349
Liabilities:
Derivative fair value gain		(2,711	)		—
Other		—			(11,076	)
Book basis of oil and natural gas properties in excess of tax basis		(459,305	)		(370,187	)
Total current deferred tax liabilities		(462,016	)		(381,263	)
Net long-term deferred tax liability	$	(416,915	)	$	(312,914	)

     At December 31, 2008, EAC had state net operating loss (“NOL”) carryforwards, which are available to offset future regular state taxable income, if any. At December 31, 2008, EAC also had federal alternative minimum tax (“AMT”) credits, which are available to reduce future federal regular tax liabilities in excess of AMT. EAC believes it is more likely than not that the NOL carryforwards will offset future taxable income prior to their expiration. The AMT credits have no expiration. Therefore, a valuation allowance against these deferred tax assets is not considered necessary. If unused, these carryforwards and credits will expire as follows:

	Federal		State
Expiration Date	AMT Credits		NOL
	(in thousands)
2012	$	—	$	41
2014		—		299
2024		—		196
2025		—		656
2026		—		152
2027		—		95
Indefinite		2,300		—
	$	2,300	$	1,439

     On January 1, 2007, EAC adopted the provisions of FIN No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold

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and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. EAC and its subsidiaries file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, EAC is no longer subject to U.S. federal, state, and local income tax examinations for years prior to 2003.

     EAC performs a periodic evaluation of tax positions to review the appropriate recognition threshold for each tax position recognized in EAC’s financial statements, including, but not limited to:

• a review of documentation of tax positions taken on previous returns including an assessment of whether EAC followed industry practice or the applicable requirements under the tax code;

• a review of open tax returns (on a jurisdiction by jurisdiction basis) as well as supporting documentation used to support those tax returns;

• a review of the results of past tax examinations;

• a review of whether tax returns have been filed in all appropriate jurisdictions;

• a review of existing permanent and temporary differences; and

• consideration of any tax planning strategies that may have been used to support realization of deferred tax assets.

     On the date of adoption of FIN 48 and as of December 31, 2008 and 2007, all of EAC’s tax positions met the “more-likely-than-not” threshold prescribed by FIN 48. As a result, no additional tax expense, interest, or penalties have been accrued. EAC includes interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its Consolidated Statements of Operations. For 2008, 2007, and 2006, EAC recorded only a nominal amount of interest and penalties on certain tax positions.

Taxes Other than Income Taxes

     Taxes other than income taxes included the following for the periods indicated:

	Year Ended December 31,
	2008		2007		2006
	(in thousands)
Production and severance taxes	$	96,468	$	65,145	$	43,458
Ad valorem taxes		14,176		9,440		6,322
Franchise, payroll, and other taxes		2,479		2,263		1,745
Total	$	113,123	$	76,848	$	51,525

Note 10. Stockholders’ Equity

Public Offering of Common Stock

     In April 2006, EAC issued 4,000,000 shares of its common stock at a price of $32.00 per share. The net proceeds of approximately $127.1 million were used to (1) reduce outstanding borrowings under EAC’s revolving credit facility, (2) invest in oil and natural gas activities, and (3) pay general corporate expenses.

Stock Option Exercises and Restricted Stock Vestings

     During 2008, 2007, and 2006, employees of EAC exercised 45,616 options, 128,709 options, and 178,174 options, respectively, for which EAC received proceeds of $0.6 million, $1.6 million, and $2.3 million in 2008, 2007, and 2006, respectively. During 2008, 2007, and 2006, employees elected to satisfy minimum tax withholding obligations related to the vesting of restricted stock by directing EAC to withhold 32,946 shares, 38,978 shares, and 24,362 shares of common stock, respectively, which are accounted for as treasury stock until they are formally retired.

Preferred Stock

     EAC’s authorized capital stock includes 5,000,000 shares of preferred stock, none of which were issued and outstanding at

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December 31, 2008 or 2007. EAC does not plan to issue any shares of preferred stock.

Stock Repurchase Programs

     In December 2007, EAC announced that the Board approved a share repurchase program authorizing EAC to repurchase up to $50 million of its common stock. During 2008, EAC completed the share repurchase program by repurchasing and retiring 1,397,721 shares of its outstanding common stock at an average price of approximately $35.77 per share.

     In October 2008, EAC announced that the Board approved a new share repurchase program authorizing EAC to repurchase up to $40 million of its common stock. As of December 31, 2008, EAC had repurchased and retired 620,265 shares of its outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the new share repurchase program.

Issuance of ENP Common Units

     In May 2008, ENP acquired an existing net profits interest in certain of its properties in the Permian Basin of West Texas in exchange for 283,700 common units which were valued at $5.8 million at the time of the acquisition. As a result, EAC’s percentage ownership in ENP went from approximately 67 percent to approximately 66 percent. Additionally, EAC reclassified $3.5 million from “Noncontrolling interest” to “Additional paid-in capital” on the accompanying Consolidated Balance Sheets to recognize gains on the issuance of ENP’s common units.

     In December 2008, as a result of the conversion of ENP’s management incentive units into ENP common units, EAC recorded a $13.9 million economic uniformity adjustment by reducing “Additional paid-in capital” and increasing “Noncontrolling interest” in the accompanying Consolidated Balance Sheets.

     In September 2007, ENP completed its IPO of 9,000,000 common units at a price to the public of $21.00 per unit, and in October 2007, the underwriters exercised their over-allotment option to purchase an additional 1,148,400 common units. As a result, EAC’s percentage ownership in ENP went from 100 percent to approximately 58 percent. Additionally, EAC reclassified $77.6 million from “Noncontrolling interest” to “Additional paid-in capital” on the accompanying Consolidated Balance Sheets to recognize gains on the issuance of ENP’s common units.

Rights Plan

     In October 2008, the Board declared a dividend of one right for each outstanding share of EAC’s common stock to stockholders of record at the close of business on November 7, 2008. Each right entitles the registered holder to purchase from EAC a unit consisting of one one-hundredth of a share of Series A Junior Participating Preferred Stock, par value $0.01 per share, at a purchase price of $120 per fractional share, subject to adjustment.

     The rights will separate from the common stock and a “Distribution Date” will occur, with certain exceptions, upon the earlier of (1) ten days following a public announcement that a person or group of affiliated or associated persons (an “Acquiring Person”) has acquired, or obtained the right to acquire, beneficial ownership of more than 10 percent of EAC’s then-outstanding shares of common stock, or (2) ten business days following the commencement of a tender offer or exchange offer that would result in a person’s becoming an Acquiring Person. In certain circumstances, the Distribution Date may be deferred by the Board. The rights are not exercisable until the Distribution Date and will expire at the close of business on October 28, 2011, unless earlier redeemed or exchanged by EAC.

Note 11. EPS

     As discussed in “Note 2. Summary of Significant Accounting Policies,” EAC adopted FSP EITF 03-6-1 on January 1, 2009, and all periods presented have been restated to calculate EPS in accordance with this pronouncement. Under the two-class method of calculating EPS, earnings are allocated to participating securities as if all the earnings for the period had been distributed. A participating security is any security that contains nonforfeitable rights to dividends or dividend equivalents paid to common stockholders. For purposes of calculating EPS, unvested restricted stock awards are considered participating securities. EPS is calculated by dividing the common stockholders’ interest in net income, after deducting the interests of participating securities, by the weighted average shares outstanding. For 2008 and 2006, basic EPS decreased by $0.14 and $0.03, respectively, per common share for the adoption of FSP EITF 03-6-1. For 2007, basic EPS was unaffected by the adoption of FSP EITF 03-6-1. For 2008, 2007, and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

2006, diluted EPS decreased by $0.06, $0.01, and $0.01, respectively, per common share for the adoption of FSP EITF 03-6-1.

     The following table reflects the allocation of net income to EAC’s common stockholders and EPS computations for the periods indicated:

	Year Ended December 31,
	2008			2007			2006
	(in thousands, except per share amounts)
Basic Earnings Per Share
Numerator:
Undistributed net income — attributable to EAC	$	430,812		$	17,155		$	92,398
Less: participation rights of unvested restricted stock in undistributed earnings		(7,595	)		(291	)		(1,454	)
Basic undistributed net income — attributable to EAC common shares	$	423,217		$	16,864		$	90,944
Denominator:
Basic weighted average shares outstanding		52,270			53,170			51,865
Basic EPS — attributable to EAC common shares	$	8.10		$	0.32		$	1.75
Diluted Earnings Per Share
Numerator:
Undistributed net income — attributable to EAC common shares	$	430,812		$	17,155		$	92,398
Less: participation rights of unvested restricted stock in undistributed earnings		(7,511	)		(289	)		(1,440	)
Diluted undistributed net income — attributable to EAC common shares	$	423,301		$	16,866		$	90,958
Denominator:
Basic weighted average shares outstanding		52,270			53,170			51,865
Effect of dilutive options (a)		596			459			491
Diluted weighted average shares outstanding		52,866			53,629			52,356
Diluted EPS — attributable to EAC common shares	$	8.01		$	0.31		$	1.74

(a) For 2008, 2007, and 2006, options to purchase 157,614, 121,651, and 103,856 shares of common stock, respectively, were outstanding but excluded from the diluted EPS calculations because their effect would have been antidilutive.

Note 12. Employee Benefit Plans

401(k) Plan

     EAC made contributions to its 401(k) plan, which is a voluntary and contributory plan for eligible employees based on a percentage of employee contributions, of $3.6 million, $2.2 million, and $1.1 million during 2008, 2007, and 2006, respectively. EAC’s 401(k) plan does not allow employees to invest in securities of EAC.

Incentive Stock Plans

     In May 2008, EAC’s stockholders approved the 2008 Incentive Stock Plan (the “2008 Plan”). No additional awards will be granted under EAC’s 2000 Incentive Stock Plan (the “2000 Plan”) and any previously granted awards outstanding under the 2000 Plan will remain outstanding in accordance with their terms. The purpose of the 2008 Plan is to attract, motivate, and retain selected employees of EAC and to provide EAC with the ability to provide incentives more directly linked to the profitability of the business and increases in shareholder value. All directors and full-time regular employees of EAC and its subsidiaries and affiliates are eligible to be granted awards under the 2008 Plan. The total number of shares of common stock reserved for issuance pursuant to the 2008 Plan is 2,400,000. No more than 1,600,000 shares of EAC’s common stock will be available for grants of “full value” stock awards, such as restricted stock or stock units. As of December 31, 2008, there were 2,389,000 shares available for issuance under the 2008 Plan. Shares delivered or withheld for payment of the exercise price of an option, shares withheld for payment of tax withholding, shares subject to options or other awards that expire or are forfeited, and restricted shares that are forfeited will again become available for issuance under the 2008 Plan. The 2008 Plan provides for the granting of cash awards, incentive stock options, non-qualified stock options, restricted stock, and stock appreciation rights at the discretion of the Compensation Committee of the Board. The Board also has a Restricted Stock Award Committee whose sole member is Jon S. Brumley, EAC’s Chief Executive Officer and President. The Restricted Stock Award Committee may grant up to 25,000 shares of restricted stock on an annual basis to non-executive employees at its discretion.

     The 2008 Plan contains the following individual limits:

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• an employee may not be granted awards covering or relating to more than 300,000 shares of common stock during any calendar year;

• a non-employee director may not be granted awards covering or relating to more than 20,000 shares of common stock during any calendar year; and

• an employee may not receive awards consisting of cash (including cash awards that are granted as performance awards) in respect of any calendar year having a value determined on the grant date in excess of $5.0 million.

     In May 2008, the Board approved certain amendments to the 2000 Plan to ensure compliance with Section 409A of the Code. In particular, the 2000 Plan was amended to allow for the exemption of options from the requirements of Section 409A of the Code by requiring that, upon a change-in-control, options granted or that vest on or after January 1, 2005 be valued at their fair market value as of the date they are cashed out, rather than the highest price per share paid in the 60 days prior to the change-in-control. The amendments to the 2000 Plan did not require stockholder approval under its terms, applicable laws, or the rules of the New York Stock Exchange.

     During 2008, 2007, and 2006, EAC recorded non-cash stock-based compensation expense related to its incentive stock plans in the accompanying Consolidated Statements of Operations of $9.0 million, $9.2 million, and $9.0 respectively, and recognized income tax benefits related thereto of $3.4 million, $3.4 million, and $3.2 million, respectively. During 2008, 2007, and 2006, EAC also capitalized $2.3 million, $1.3 million, and $1.1 million, respectively, of non-cash stock-based compensation cost as a component of “Properties and equipment” in the accompanying Consolidated Balance Sheets. Non-cash stock-based compensation expense has been allocated to LOE and general and administrative (“G&A”) expense based on the allocation of the respective employees’ cash compensation.

     Please read “Note 17. ENP” for a discussion of ENP’s equity-based compensation plan.

     Stock Options. All options have a strike price equal to the fair market value of EAC’s common stock on the grant date, have a ten-year life, and vest over a three-year period. The fair value of options granted was estimated on the grant date using a Black-Scholes option valuation model based on the assumptions noted in the following table. The expected volatility was based on the historical volatility of EAC’s common stock for a period of time commensurate with the expected term of the options. For options granted prior to January 1, 2008, EAC used the “simplified” method prescribed by Staff Accounting Bulletin No. 107, “Valuation of Share-Based Payment Arrangements for Public Companies” to estimate the expected term of the options, which was calculated as the average midpoint between each vesting date and the life of the option. For options granted subsequent to December 31, 2007, EAC determined the expected life of the options based on an analysis of historical exercise and forfeiture behavior as well as expectations about future behavior. The risk-free interest rate is based on the U.S Treasury yield curve in effect at the grant date for a period of time commensurate with the expected term of the options.

	Year Ended December 31,
	2008			2007			2006
Expected volatility		33.7	%		35.7	%		42.8	%
Expected dividend yield		0.0	%		0.0	%		0.0	%
Expected term (in years)		6.25			6.0			6.0
Risk-free interest rate		3.0	%		4.8	%		4.6	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

     The following table summarizes the changes in EAC’s outstanding options for the periods indicated:

	Year Ended December 31,
	2008									2007					2006
						Weighted
						Average
				Weighted		Remaining		Aggregate					Weighted					Weighted
	Number of			Average		Contractual		Intrinsic		Number of			Average		Number of			Average
	Options			Strike Price		Term		Value		Options			Strike Price		Options			Strike Price
								(in thousands)
Outstanding at beginning of year		1,381,782		$	16.03						1,337,118		$	14.44		1,440,812		$	13.20
Granted		176,170			33.76						200,059			25.73		122,890			31.10
Forfeited or expired		(14,923	)		30.83						(26,686	)		27.15		(48,410	)		24.65
Exercised		(45,616	)		14.11						(128,709	)		12.34		(178,174	)		13.14
Outstanding at end of year		1,497,413			18.02		5.1	$	13,224		1,381,782			16.03		1,337,118			14.44
Exercisable at end of year		1,177,015			14.65		4.2		13,224		1,103,018			13.25		1,076,815			11.90

     The weighted average fair value per share of options granted during 2008, 2007, and 2006 was $13.15, $11.16, and $14.96, respectively. The total intrinsic value of options exercised during 2008, 2007, and 2006 was $1.6 million, $2.3 million, and $2.4 million, respectively. During 2008, 2007, and 2006, EAC received proceeds from the exercise of stock options of $0.5 million, $1.6 million, and $2.3 million, respectively. During 2008 and 2006, EAC recognized income tax benefits related to stock options of $0.5 million and $0.9 million, respectively. During 2007, EAC did not recognize any income tax benefits related to stock options. At December 31, 2008, EAC had $1.1 million of total unrecognized compensation cost related to unvested stock options, which is expected to be recognized over a weighted average period of 1.9 years.

     Additional information about options outstanding and exercisable at December 31, 2008 is as follows:

			Weighted				Weighted
	Range of		Number of		Average		Average		Number of
	Strike Prices		Options		Life		Strike		Options
Year of Grant	Per Share		Outstanding		(Years)		Price		Exercisable
2001	$8.33 to $9.33			409,486		2.5	$	8.85		409,486
2002	$8.50 to $12.40			284,085		3.8		11.94		284,085
2003	$11.49 to $13.61			35,965		4.5		12.28		35,965
2004	$17.17 to $19.77			259,075		5.1		17.55		259,075
2005	$	26.55		68,105		6.1		26.55		68,105
2006	$	31.10		92,823		7.1		31.10		61,716
2007	$	25.73		181,174		8.1		25.73		58,583
2008	$	33.76		166,700		9.1		33.76		—
				1,497,413						1,177,015

     Restricted Stock. Restricted stock awards vest over varying periods from one to five years, subject to performance-based vesting for certain members of senior management. During 2008, 2007, and 2006, EAC recognized expense related to restricted stock of $7.6 million, $7.6 million, and $7.3 million, respectively. During 2008 and 2006, EAC recognized income tax benefits related to the vesting of restricted stock of $1.6 million and $0.4 million, respectively. During 2007, EAC did not recognize any income tax benefits related to the vesting of restricted stock. The following table summarizes the changes in the number of EAC’s unvested restricted stock awards and their related weighted average grant date fair value for 2008:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

				Weighted
				Average
	Number of			Grant Date
	Shares			Fair Value
Outstanding at January 1, 2008		918,338		$	27.07
Granted		314,086			37.02
Vested		(256,785	)		25.63
Forfeited		(37,232	)		29.59
Outstanding at December 31, 2008		938,407			30.67

     During 2008, 2007, and 2006, EAC issued 241,515 shares, 169,453 shares, and 277,162 shares, respectively, of restricted stock to employees and members of the Board, the vesting of which is dependent only on the passage of time and continued employment. The following table illustrates outstanding restricted stock at December 31, 2008 the vesting of which is dependent only on the passage of time and continued employment:

	Year of Vesting
Year of Grant	2009		2010		2011		2012		Total
2004		25,119		—		—		—		25,119
2005		71,483		71,483		—		—		142,966
2006		169,408		60,793		—		—		230,201
2007		75,014		79,183		79,184		4,167		237,548
2008		52,827		52,832		76,836		52,839		235,334
Total		393,851		264,291		156,020		57,006		871,168

     During 2008, 2007, and 2006, EAC issued 72,571 shares, 175,180 shares, and 151,447 shares of restricted stock to certain members of senior management, the vesting of which is dependent not only on the passage of time and continued employment, but also on the achievement of certain performance measures. The performance measures related to the 2007 and 2006 awards were met and therefore, vesting depends only on the passage of time and continued employment. The following table illustrates outstanding restricted stock at December 31, 2008 the vesting of which is dependent not only on the passage of time and continued employment, but also on the achievement of certain performance measures:

	Year of Vesting
Year of Grant	2009		2010		2011		2012		Total
2008		16,810		16,810		16,810		16,809		67,239

     As of December 31, 2008, EAC had $8.2 million of total unrecognized compensation cost related to unvested restricted stock, which is expected to be recognized over a weighted average period of 2.7 years. None of EAC’s unvested restricted stock is subject to variable accounting. During 2008, 2007, and 2006, there were 256,785 shares, 184,867 shares, and 101,377 shares, respectively, of restricted stock that vested for which certain employees elected to satisfy minimum tax withholding obligations related thereto by directing EAC to withhold 32,946 shares, 38,978 shares, and 24,362 shares of common stock, respectively. EAC accounts for these shares as treasury stock until they are formally retired and have been reflected as such in the accompanying consolidated financial statements. The total fair value of restricted stock that vested during 2008, 2007, and 2006 was $8.7 million, $5.3 million, and $2.6 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 13. Financial Instruments

     The following table sets forth EAC’s book value and estimated fair value of financial instrument assets (liabilities) as of the dates indicated:

	December 31,
	2008						2007
	Book			Fair			Book			Fair
	Value			Value			Value			Value
				(in thousands)
Cash and cash equivalents	$	2,039		$	2,039		$	1,704		$	1,704
Accounts receivable, net		129,065			129,065			134,880			134,880
Plugging bond		824			1,202			777			921
Bell Creek escrow		9,229			9,241			6,701			6,728
Accounts payable		10,017			10,017			(21,548	)		(21,548	)
6.25% Notes		(150,000	)		(101,250	)		(150,000	)		(138,375	)
6.0% Notes		(296,040	)		(194,250	)		(295,560	)		(264,750	)
7.25% Notes		(148,771	)		(94,500	)		(148,676	)		(143,813	)
Revolving credit facilities		(725,000	)		(725,000	)		(526,000	)		(526,000	)
Commodity derivative contracts		387,612			387,612			9,798			9,798
Deferred premiums on commodity derivative contracts		(67,610	)		(67,610	)		(51,926	)		(51,926	)
Interest rate swaps		(4,559	)		(4,559	)		—			—

     The book value of cash and cash equivalents, accounts receivable, net, and accounts payable approximate fair value due to the short-term nature of these instruments. The fair values of the Notes were determined using open market quotes. The difference between book value and fair value represents the premium or discount on that date. The book value of the revolving credit facilities approximates fair value as the interest rate is variable. The plugging bond and Bell Creek escrow are included in “Other assets” on the accompanying Consolidated Balance Sheets and are classified as “held to maturity” and therefore, are recorded at amortized cost, which was less than fair value. The fair values of the plugging bond and Bell Creek escrow were determined using open market quotes. Commodity derivative contracts and interest rate swaps are marked-to-market each quarter.

Derivative Financial Instruments

     Commodity Derivative Contracts. EAC manages commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of sales volumes. Put contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collars provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price.

     As of December 31, 2008, EAC had $67.6 million of deferred premiums payable of which $5.4 million was long-term and included in “Derivatives” in the non-current liabilities section of the accompanying Consolidated Balance Sheet and $62.2 million was current and included in “Derivatives” in the current liabilities section of the accompanying Consolidated Balance Sheet. The premiums relate to various oil and natural gas floor contracts and are payable on a monthly basis from January 2009 to January 2010. EAC recorded these premiums at their net present value at the time the contract was entered into and accretes that value to the eventual settlement price by recording interest expense each period.

     From time to time, EAC sells floors with a strike price below the strike price of the purchased floors in order to partially finance the premiums paid on the purchased floors. Together the two floors, known as a floor spread or put spread, have a lower premium cost than a traditional floor contract but provide price protection only down to the strike price of the short floor. As with EAC’s other commodity derivative contracts, these are marked-to-market each quarter through “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations. In the following tables, the purchased floor component of these floor spreads are shown net and included with EAC’s other floor contracts.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

     The following tables summarize EAC’s open commodity derivative contracts as of December 31, 2008:

Oil Derivative Contracts

	Average		Weighted		Average			Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily			Average		Daily		Average		Daily		Average		Asset
	Floor		Floor		Short Floor			Short Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume			Price		Volume		Price		Volume		Price		Value
	(Bbl)		(per Bbl)		(Bbl)			(per Bbl)		(Bbl)		(per Bbl)		(Bbl)		(per Bbl)		(in thousands)
2009 (a)																		$	342,063
		11,630	$	110.00		—		$	—		—	$	—		2,000	$	90.46
		8,000		80.00		—			—		440		97.75		500		89.39
		—		—		(5,000	)		50.00		—		—		1,000		68.70
2010																			17,618
		880		80.00		—			—		440		93.80		—		—
		2,000		75.00		—			—		1,000		77.23		—		—
2011																			15,112
		1,880		80.00		—			—		1,440		95.41		—		—
		1,000		70.00		—			—		—		—		—		—
																		$	374,793

(a) In addition, ENP has a floor contract for 1,000 Bbls/D at $63.00 per Bbl and a short floor contract for 1,000 Bbls/D at $65.00 per Bbl.

Natural Gas Derivative Contracts

	Average		Weighted		Average	Weighted	Average		Weighted		Average		Weighted
	Daily		Average		Daily	Average	Daily		Average		Daily		Average		Asset
	Floor		Floor		Short Floor	Short Floor	Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume	Price	Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)	(per Mcf)	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(in thousands)
2009															$	7,281
		3,800	$	8.20	—	$ —		3,800	$	9.83		—	$	—
		3,800		7.20	—	—		—		—		—		—
		1,800		6.76	—	—		—		—		—		—
2010																4,690
		3,800		8.20	—	—		3,800		9.58		902		6.30
		4,698		7.26	—	—		—		—		—		—
2011																424
		898		6.76	—	—		—		—		902		6.70
2012																424
		898		6.76	—	—		—		—		902		6.66
															$	12,819

     Interest Rate Swaps. ENP manages interest rate risk with interest rate swaps whereby it swaps floating rate debt under the OLLC Credit Agreement with a weighted average fixed rate. These interest rate swaps were designated as cash flow hedges. The following table summarizes ENP’s open interest rate swaps as of December 31, 2008:

	Notional		Fixed			Floating
Term	Amount		Rate			Rate
	(in thousands)
Jan. 2009 - Jan. 2011	$	50,000		3.1610	%	1-month LIBOR
Jan. 2009 - Jan. 2011		25,000		2.9650	%	1-month LIBOR
Jan. 2009 - Jan. 2011		25,000		2.9613	%	1-month LIBOR
Jan. 2009 - Mar. 2012		50,000		2.4200	%	1-month LIBOR

     As of December 31, 2008, the fair market value of ENP’s interest rate swaps was a net liability of $4.6 million of which, $1.3 million was current and included in the current liabilities line “Derivatives” and $3.3 million was long-term and included in the other

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

liabilities line “Derivatives” in the accompanying Consolidated Balance Sheets. During 2008, settlements of interest rate swaps increased EAC’s consolidated interest expense by approximately $0.2 million.

     Current Period Impact. As a result of commodity derivative contracts which were previously designated as hedges, EAC recognized a pre-tax reduction in oil and natural gas revenues of approximately $2.9 million, $53.6 million, and $60.3 million in 2008, 2007, and 2006, respectively. EAC also recognized derivative fair value gains and losses related to: (1) ineffectiveness on designated derivative contracts; (2) changes in the market value of derivative contracts; (3) settlements on commodity derivative contracts; and (4) premium amortization. The following table summarizes the components of “Derivative fair value loss (gain)” for the periods indicated:

	Year Ended December 31,
	2008			2007		2006
	(in thousands)
Ineffectiveness on designated derivative contracts	$	372		$	—	$	1,748
Mark-to-market loss (gain) derivative contracts		(365,495	)		36,272		(31,205	)
Premium amortization		62,352			41,051		13,926
Settlements on commodity derivative contracts		(43,465	)		35,160		(8,857	)
Total derivative fair value loss (gain)	$	(346,236	)	$	112,483	$	(24,388	)

     Counterparty Risk. At December 31, 2008, EAC had committed greater than 10 percent of either its oil or natural gas commodity derivative contracts to the following counterparties:

	Percentage of			Percentage of
	Oil Derivative			Natural Gas Derivative
	Contracts			Contracts
Counterparty	Committed			Committed
BNP Paribas		22	%		24	%
Calyon		15	%		31	%
Fortis		11	%		—
UBS		16	%		—
Wachovia		11	%		38	%

     In order to mitigate the credit risk of financial instruments, EAC enters into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and EAC. Instead of treating separately each derivative financial transaction between the counterparty and EAC, the master netting agreement enables the counterparty and EAC to aggregate all financial trades and treat them as a single agreement. This arrangement benefits EAC in three ways: (1) the netting of the value of all trades reduces the likelihood of counterparties requiring daily collateral posting by EAC; (2) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (3) netting of settlement amounts reduces EAC’s credit exposure to a given counterparty in the event of close-out.

     Accumulated Other Comprehensive Loss. At December 31, 2008, accumulated other comprehensive loss consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps that are designated as hedges of $1.7 million. At December 31, 2007, accumulated other comprehensive loss consisted entirely of deferred losses, net of tax, on commodity derivative contracts that were previously designated as hedges of $1.8 million.

     EAC expects to reclassify $1.3 million of deferred losses associated with ENP’s interest rate swaps from accumulated other comprehensive loss to interest expense during 2009. EAC also expects to reclassify $0.2 million of income taxes associated with ENP’s interest rate swaps from accumulated other comprehensive loss to income tax benefit during 2009.

Note 14. Fair Value Measurements

     As discussed in “Note 2. Summary of Significant Accounting Policies,” EAC adopted SFAS 157 on January 1, 2008, as it relates to financial assets and liabilities. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

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• Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities.

• Level 2 — Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.

• Level 3 — Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.

     EAC’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the financial assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions are used to estimate the fair values of EAC’s financial assets and liabilities that are accounted for at fair value on a recurring basis:

• Level 2 — Fair values of oil and natural gas swaps were estimated using a combined income and market-based valuation methodology based upon forward commodity price curves obtained from independent pricing services reflecting broker market quotes. Fair values of interest rate swaps were estimated using a combined income and market-based valuation methodology based upon credit ratings and forward interest rate yield curves obtained from independent pricing services reflecting broker market quotes.

• Level 3 — Fair values of oil and natural gas floors and caps were estimated using pricing models and discounted cash flow methodologies based on inputs that are not readily available in public markets.

     The following table sets forth EAC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2008:

				Fair Value Measurements at Reporting Date Using
				Quoted Prices in
				Active Markets for		Significant Other			Significant
				Identical Assets		Observable Inputs			Unobservable Inputs
Description	December 31, 2008			(Level 1)		(Level 2)			(Level 3)
	(in thousands)
Oil derivative contracts — swaps	$	37,458		$	—	$	37,458		$	—
Oil derivative contracts — floors and caps		337,335			—		—			337,335
Natural gas derivative contracts — swaps		78			—		78			—
Natural gas derivative contracts — floors and caps		12,741			—		—			12,741
Interest rate swaps		(4,559	)		—		(4,559	)		—
Total	$	383,053		$	—	$	32,977		$	350,076

     The following table summarizes the changes in the fair value of EAC’s Level 3 financial assets and liabilities for 2008:

	Fair Value Measurements Using Significant
	Unobservable Inputs (Level 3)
	Oil Derivative			Natural Gas
	Contracts —			Derivative Contracts —
	Floors and Caps			Floors and Caps		Total
	(in thousands)
Balance at January 1, 2008	$	16,647		$	7,081	$	23,728
Total gains (losses):
Included in earnings		350,584			5,104		355,688
Purchases, issuances, and settlements		(29,896	)		556		(29,340	)
Balance at December 31, 2008	$	337,335		$	12,741	$	350,076
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	350,584		$	5,104	$	355,688

33

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

     Since EAC does not use hedge accounting for its commodity derivative contracts, all gains and losses on its Level 3 financial assets and liabilities are included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations. All fair values reflected in the table above and in the accompanying Consolidated Balance Sheet have been adjusted for non-performance risk, resulting in a reduction of the net asset of approximately $3.4 million as of December 31, 2008.

Note 15. Related Party Transactions

     During 2008, 2007, and 2006, EAC received approximately $160.5 million, $85.3 million, and $7.4 million, respectively, from affiliates of Tesoro Corporation (“Tesoro”) related to gross oil and natural gas production sold from wells operated by Encore Operating. Mr. John V. Genova, a member of the Board, served as an employee of Tesoro until May 2008.

     Please read “Note 17. ENP” for a discussion of related party transactions with ENP.

Note 16. Financial Statements of Subsidiary Guarantors

     In February 2007, EAC formed certain non-guarantor subsidiaries in connection with the formation of ENP. Please read “Note 17. ENP” for additional discussion of ENP’s formation and other matters. As of December 31, 2008 and 2007, certain of EAC’s wholly owned subsidiaries were subsidiary guarantors of EAC’s senior subordinated notes. The subsidiary guarantees are full and unconditional, and joint and several. The subsidiary guarantors may, without restriction, transfer funds to EAC in the form of cash dividends, loans, and advances. In accordance with SEC rules, EAC has prepared condensed consolidating financial statements in order to quantify the financial position, results of operations, and cash flows of the subsidiary guarantors. The following Condensed Consolidating Balance Sheets as of December 31, 2008 and 2007 and Condensed Consolidating Statements of Operations and Comprehensive Income (Loss) and Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2008 and 2007 present consolidating financial information for Encore Acquisition Company (“Parent”) on a stand alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries. As of December 31, 2008, EAC’s guarantor subsidiaries were:

• EAP Properties, Inc.;

• EAP Operating, LLC;

• Encore Operating; and

• Encore Operating Louisiana, LLC.

As of December 31, 2008, EAC’s non-guarantor subsidiaries were:

• ENP;

• OLLC;

• GP LLC;

• Encore Partners GP Holdings LLC;

• Encore Partners LP Holdings LLC;

• Encore Energy Partners Finance Corporation; and

• Encore Clear Fork Pipeline LLC.

     All intercompany investments in, loans due to/from, subsidiary equity, and revenues and expenses between the Parent, guarantor subsidiaries, and non-guarantor subsidiaries are shown prior to consolidation with the Parent and then eliminated to arrive at consolidated totals per the accompanying consolidated financial statements of EAC. Prior to February 2007, all of EAC’s subsidiaries were subsidiary guarantors of EAC’s senior subordinated notes. Therefore, a Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) and a Condensed Consolidating Statement of Cash Flows are not presented for 2006.

34

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2008
(in thousands)

			Guarantor			Non-Guarantor						Consolidated
	Parent		Subsidiaries			Subsidiaries			Eliminations			Total
ASSETS
Current assets:
Cash and cash equivalents	$	607	$	813		$	619		$	—		$	2,039
Other current assets		29,004		421,392			90,797			(2,302	)		538,891
Total current assets		29,611		422,205			91,416			(2,302	)		540,930
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		—		3,016,937			521,522			—			3,538,459
Unproved properties		—		124,272			67			—			124,339
Accumulated depletion, depreciation, and amortization		—		(670,991	)		(100,573	)		—			(771,564	)
		—		2,470,218			421,016			—			2,891,234
Other property and equipment, net		—		11,877			562			—			12,439
Other assets, net		12,846		129,482			46,264			—			188,592
Investment in subsidiaries		2,976,208		(12,865	)		—			(2,963,343	)		—
Total assets	$	3,018,665	$	3,020,917		$	559,258		$	(2,965,645	)	$	3,633,195
LIABILITIES AND EQUITY
Current liabilities	$	118,089	$	215,640		$	20,825		$	(2,302	)	$	352,252
Deferred taxes		416,637		—			278			—			416,915
Long-term debt		1,169,811		—			150,000			—			1,319,811
Other liabilities		—		48,000			12,969			—			60,969
Total liabilities		1,704,537		263,640			184,072			(2,302	)		2,149,947
Commitments and contingencies (see Note 4)
Total equity		1,314,128		2,757,277			375,186			(2,963,343	)		1,483,248
Total liabilities and equity	$	3,018,665	$	3,020,917		$	559,258		$	(2,965,645	)	$	3,633,195

35

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2007
(in thousands)

			Guarantor			Non-Guarantor						Consolidated
	Parent		Subsidiaries			Subsidiaries			Eliminations			Total
ASSETS
Current assets:
Cash and cash equivalents	$	1	$	1,700		$	3		$	—		$	1,704
Other current assets		535,221		437,852			21,053			(807,320	)		186,806
Total current assets		535,222		439,552			21,056			(807,320	)		188,510
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		—		2,467,606			378,170			—			2,845,776
Unproved properties		—		63,352			—			—			63,352
Accumulated depletion, depreciation, and amortization		—		(451,343	)		(37,661	)		—			(489,004	)
		—		2,079,615			340,509			—			2,420,124
Other property and equipment, net		—		10,610			407			—			11,017
Other assets, net		14,899		121,904			28,107			—			164,910
Investment in subsidiaries		2,090,471		20,611			—			(2,111,082	)		—
Total assets	$	2,640,592	$	2,672,292		$	390,079		$	(2,918,402	)	$	2,784,561
LIABILITIES AND EQUITY
Current liabilities	$	306,787	$	687,351		$	17,885		$	(807,293	)	$	204,730
Deferred taxes		312,914		—			—			—			312,914
Long-term debt		1,072,736		—			47,500			—			1,120,236
Other liabilities		—		49,461			26,531			—			75,992
Total liabilities		1,692,437		736,812			91,916			(807,293	)		1,713,872
Commitments and contingencies (see Note 4)
Total equity		948,155		1,935,480			298,163			(2,111,109	)		1,070,689
Total liabilities and equity	$	2,640,592	$	2,672,292		$	390,079		$	(2,918,402	)	$	2,784,561

36

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME
For the Year Ended December 31, 2008
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	749,864		$	147,579		$	—		$	897,443
Natural gas		—			192,942			34,537			—			227,479
Marketing		—			5,172			5,324			—			10,496
Total revenues		—			947,978			187,440			—			1,135,418
Expenses:
Production:
Lease operating		—			146,460			28,655			—			175,115
Production, ad valorem, and severance taxes		—			91,809			18,835			—			110,644
Depletion, depreciation, and amortization		—			190,548			37,704			—			228,252
Impairment of long-lived assets		—			59,526			—			—			59,526
Exploration		—			39,026			181			—			39,207
General and administrative		15,801			24,751			12,135			(4,266	)		48,421
Marketing		—			4,104			5,466			—			9,570
Derivative fair value gain		—			(249,356	)		(96,880	)		—			(346,236	)
Provision for doubtful accounts		—			1,984			—			—			1,984
Other operating		165			11,485			1,325			—			12,975
Total expenses		15,966			320,337			7,421			(4,266	)		339,458
Operating income (loss)		(15,966	)		627,641			180,019			4,266			795,960
Other income (expenses):
Interest		(66,204	)		—			(6,969	)		—			(73,173	)
Equity income from subsidiaries		736,408			51,468			—			(787,876	)		—
Other		98			7,967			99			(4,266	)		3,898
Total other expenses		670,302			59,435			(6,870	)		(792,142	)		(69,275	)
Income before income taxes		654,336			687,076			173,149			(787,876	)		726,685
Income tax provision		(240,986	)		—			(635	)		—			(241,621	)
Consolidated net income		413,350			687,076			172,514			(787,876	)		485,064
Amortization of deferred loss on commodity
derivative contracts, net of tax		(1,071	)		2,857			—			—			1,786
Change in deferred hedge gain on interest rate swaps, net of tax		(625	)		—			(2,692	)		—			(3,317	)
Comprehensive income	$	411,654		$	689,933		$	169,822		$	(787,876	)	$	483,533

37

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
For the Year Ended December 31, 2007
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Revenues:
Oil	$	—		$	503,981		$	58,836		$	—		$	562,817
Natural gas		—			137,838			12,269			—			150,107
Marketing		—			33,439			8,582			—			42,021
Total revenues		—			675,258			79,687			—			754,945
Expenses:
Production:
Lease operating		—			129,506			13,920			—			143,426
Production, ad valorem, and severance taxes		—			66,014			8,571			—			74,585
Depletion, depreciation, and amortization		—			157,982			25,998			—			183,980
Exploration		—			27,726			—			—			27,726
General and administrative		15,107			15,354			10,707			(2,044	)		39,124
Marketing		—			33,876			6,673			—			40,549
Derivative fair value loss		—			86,182			26,301			—			112,483
Provision for doubtful accounts		—			5,816			—			—			5,816
Other operating		221			16,083			762			—			17,066
Total expenses		15,328			538,539			92,932			(2,044	)		644,755
Operating income (loss)		(15,328	)		136,719			(13,245	)		2,044			110,190
Other income (expenses):
Interest		(82,825	)		(6,415	)		(12,294	)		12,830			(88,704	)
Equity income (loss) from subsidiaries		123,381			(3,205	)		—			(120,176	)		—
Other		6,405			10,940			196			(14,874	)		2,667
Total other expenses		46,961			1,320			(12,098	)		(122,220	)		(86,037	)
Income (loss) before income taxes		31,633			138,039			(25,343	)		(120,176	)		24,153
Income tax benefit (provision)		(14,478	)		—			2			—			(14,476	)
Consolidated net income (loss)		17,155			138,039			(25,341	)		(120,176	)		9,677
Amortization of deferred loss on commodity derivative contracts, net of tax		(20,047	)		53,588			—			—			33,541
Comprehensive income (loss)	$	(2,892	)	$	191,627		$	(25,341	)	$	(120,176	)	$	43,218

38

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2008
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	629,345		$	(81,882	)	$	115,774		$	—		$	663,237
Cash flows from investing activities:
Acquisition of oil and natural gas properties		—			(142,471	)		(88	)		—			(142,559	)
Development of oil and natural gas properties		—			(543,399	)		(17,598	)		—			(560,997	)
Investments in subsidiaries		(681,766	)		—			—			681,766			—
Other		—			(24,475	)		(315	)		—			(24,790	)
Net cash used in investing activities		(681,766	)		(710,345	)		(18,001	)		681,766			(728,346	)
Cash flows from financing activities:
Repurchase of common stock		(67,170	)		—			—			—			(67,170	)
Proceeds from long-term debt, net of issuance costs		1,127,029			—			243,310			—			1,370,339
Payments on long-term debt		(1,031,500	)		—			(141,000	)		—			(1,172,500	)
Net equity distributions		—			806,460			(124,694	)		(681,766	)		—
Other		24,668			(15,120	)		(74,773	)		—			(65,225	)
Net cash provided by (used in) financing activities		53,027			791,340			(97,157	)		(681,766	)		65,444
Increase (decrease) in cash and cash equivalents		606			(887	)		616			—			335
Cash and cash equivalents, beginning of period		1			1,700			3			—			1,704
Cash and cash equivalents, end of period	$	607		$	813		$	619		$	—		$	2,039

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2007
(in thousands)

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(305,868	)	$	615,484		$	10,091		$	—		$	319,707
Cash flows from investing activities:
Proceeds from disposition of assets		—			287,928			—			—			287,928
Acquisition of oil and natural gas properties		—			(518,251	)		(330,294	)		—			(848,545	)
Development of oil and natural gas properties		—			(329,252	)		(6,645	)		—			(335,897	)
Investments in subsidiaries		(93,658	)		—			—			93,658			—
Other		—			(32,585	)		(457	)		—			(33,042	)
Net cash used in investing activities		(93,658	)		(592,160	)		(337,396	)		93,658			(929,556	)
Cash flows from financing activities:
Proceeds from issuance of ENP common units, net of issuance costs		—			—			193,461			—			193,461
Proceeds from long-term debt, net of issuance costs		1,208,501			—			270,758			—			1,479,259
Payments on long-term debt		(809,428	)		—			(225,000	)		—			(1,034,428	)
Net equity contributions		—			—			93,658			(93,658	)		—
Other		454			(22,387	)		(5,569	)		—			(27,502	)
Net cash provided by (used in) financing activities		399,527			(22,387	)		327,308			(93,658	)		610,790
Increase in cash and cash equivalents		1			937			3			—			941
Cash and cash equivalents, beginning of period		—			763			—			—			763
Cash and cash equivalents, end of period	$	1		$	1,700		$	3		$	—		$	1,704

39

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 17. ENP

     In September 2007, ENP completed its IPO of 9,000,000 common units at a price to the public of $21.00 per unit. In October 2007, the underwriters exercised their over-allotment option to purchase an additional 1,148,400 common units of ENP. The net proceeds of approximately $193.5 million, after deducting the underwriters’ discount and a structuring fee of approximately $14.9 million, in the aggregate, and offering expenses of approximately $4.7 million, were used to repay in full the $126.4 million of outstanding indebtedness under OLLC’s subordinated credit agreement with EAP Operating, LLC, and reduce outstanding borrowings under the OLLC Credit Agreement.

     In connection with the closing of ENP’s IPO, EAC, ENP, and certain of their respective subsidiaries entered into a contribution, conveyance and assumption agreement (the “Contribution Agreement”) and an amended and restated administrative services agreement (the “Administrative Services Agreement”), each as more fully described below. In addition, prior to ENP’s IPO, GP LLC approved the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “ENP Plan”), as more fully described below.

Contribution, Conveyance and Assumption Agreement

     At the closing of ENP’s IPO, the following transactions, among others, occurred pursuant to the Contribution Agreement:

• Encore Operating transferred certain oil and natural gas properties and related assets in the Permian Basin to ENP in exchange for 4,043,478 common units; and

• EAC agreed to indemnify ENP for certain environmental liabilities, tax liabilities, and title defects, as well as defects relating to retained assets and liabilities, occurring or existing before the closing.

     These transfers and distributions were made in a series of steps outlined in the Contribution Agreement. In connection with the issuance of the common units by ENP in exchange for the Permian Basin assets, ENP’s IPO, and the exercise of the underwriters’ over-allotment option to purchase additional common units, GP LLC exchanged such number of common units for general partner units as was necessary to enable it to maintain its two percent general partner interest in ENP. GP LLC received the common units through capital contributions from EAC and its subsidiaries of common units they owned.

Administrative Services Agreement

     ENP does not have any employees. The employees supporting ENP’s operations are employees of EAC. Accordingly, EAC recognizes all employee-related expenses and liabilities in its consolidated financial statements. Encore Operating performs administrative services for ENP, such as accounting, corporate development, finance, land, legal, and engineering, pursuant to the Administrative Services Agreement. In addition, Encore Operating provides all personnel and any facilities, goods, and equipment necessary to perform these services and not otherwise provided by ENP. Encore Operating initially received an administrative fee of $1.75 per BOE of ENP’s production for such services. Effective April 1, 2008, the administrative fee increased to $1.88 per BOE of ENP’s production as a result of the COPAS Wage Index Adjustment. Encore Operating also charges ENP for reimbursement of actual third-party expenses incurred on ENP’s behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on ENP’s behalf. In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator of a well. Encore Operating is not liable to ENP for its performance of, or failure to perform, services under the Administrative Services Agreement unless its acts or omissions constitute gross negligence or willful misconduct.

     ENP also reimburses EAC for any state income, franchise, or similar tax incurred by EAC resulting from the inclusion of ENP and its subsidiaries in consolidated tax returns with EAC and its subsidiaries as required by applicable law. The amount of any such reimbursement is limited to the tax that ENP and its subsidiaries would have incurred had it not been included in a combined group with EAC.

Purchase and Investment Agreement

     In December 2007, OLLC entered into a purchase and investment agreement with Encore Operating pursuant to which OLLC agreed to acquire certain oil and natural gas properties and related assets in the Permian and Williston Basins from Encore Operating. The transaction closed in February 2008, but was effective as of January 1, 2008. The consideration for the acquisition consisted of approximately $125.3 million in cash, including post-closing adjustments, and 6,884,776 common units representing limited partner

40

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

interests in ENP. ENP funded the cash portion of the purchase price with borrowings under the OLLC Credit Agreement. EAC used the proceeds from the sale to reduce outstanding borrowings under the EAC Credit Agreement.

Long-Term Incentive Plan

     In September 2007, GP LLC approved the ENP Plan, which provides for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other equity-based awards, and unit awards. All employees, consultants, and directors of EAC, GP LLC, and any of their subsidiaries and affiliates who perform services for ENP and its subsidiaries and affiliates are eligible to be granted awards under the ENP Plan. The total number of common units reserved for issuance pursuant to the ENP Plan is 1,150,000. As of December 31, 2008, there were 1,100,000 common units available for issuance under the ENP Plan. The ENP Plan is administered by the board of directors of GP LLC or a committee thereof, referred to as the plan administrator. To satisfy common unit awards under the ENP Plan, ENP may issue new common units, acquire common units in the open market, or use common units owned by EAC and its affiliates.

     Phantom Units. From time to time, ENP issues phantom units to members of GP LLC’s board of directors pursuant to the ENP Plan. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the plan administrator, cash equivalent to the value of a common unit. ENP intends to settle the phantom units at vesting by issuing common units; therefore, these phantom units are classified as equity instruments. Phantom units vest in four equal annual installments. The holders of phantom units are also entitled to receive distribution equivalent rights prior to vesting, which entitle them to receive cash equal to the amount of any cash distributions made by ENP with respect to a common unit during the period the right is outstanding. During 2008 and 2007, ENP recognized non-cash equity-based compensation expense for the phantom units of approximately $0.3 million and $31,000, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations.

     The following table summarizes the changes in the number of ENP’s unvested phantom units and their related weighted average grant date fair value for 2008:

				Weighted
				Average
	Number of			Grant Date
	Shares			Fair Value
Outstanding at January 1, 2008		20,000		$	20.21
Granted		30,000			17.91
Vested		(6,250	)		19.93
Forfeited		—			—
Outstanding at December 31, 2008		43,750			18.67

     During 2008 and 2007, ENP issued 30,000 and 20,000, respectively, phantom units to members of GP LLC’s board of directors pursuant to the ENP Plan the vesting of which is dependent only on the passage of time and continuation as a board member. The following table illustrates by year of grant the vesting of outstanding phantom units at December 31, 2008:

	Year of Vesting
Year of Grant	2009		2010		2011		2012		Total
2007		5,000		5,000		5,000		—		15,000
2008		7,500		7,500		7,500		6,250		28,750
Total		12,500		12,500		12,500		6,250		43,750

     As of December 31, 2008, ENP had $0.6 million of total unrecognized compensation cost related to unvested phantom units, which is expected to be recognized over a weighted average period of 1.5 years. During 2008, there were 6,250 phantom units that vested, the total fair value of which was $0.1 million.

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ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Management Incentive Units

     In May 2007, the board of directors of GP LLC issued 550,000 management incentive units to certain executive officers of GP LLC. A management incentive unit is a limited partner interest in ENP that entitles the holder to quarterly distributions to the extent paid to ENP’s common unitholders and to increasing distributions upon the achievement of 10 percent compounding increases in ENP’s distribution rate to common unitholders. On November 14, 2008 the management incentive units became convertible into ENP common, at the option of the holder, units at a ratio of one management incentive unit to approximately 3.1186 ENP common units. During the fourth quarter of 2008, all 550,000 management incentive units were converted into 1,715,205 ENP common units.

     The fair value of the management incentive units granted in 2007 was estimated on the date of grant using a discounted dividend model. During 2008 and 2007, ENP recognized total non-cash equity-based compensation expense for the management incentive units of $4.8 million and $6.8 million, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. As of December 31, 2008, there have been no additional issuances of management incentive units.

Distributions

     During 2008 and 2007, ENP paid cash distributions to unitholders of $74.4 million and $1.3 million, respectively, of which $46.9 million and $0.8 million was paid to EAC and its subsidiaries and had no impact on EAC’s consolidated cash.

Note 18. Segment Information

     The following tables provides EAC’s operating segment information required by SFAS No. 131, “Disclosure about Segments of an Enterprise and Related Information” as well as the results of operations from oil and natural gas producing activities required by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.” As discussed in Note 2. Summary of Significant Accounting Policies-Recast of Consolidated Financial Statements and Notes to Consolidated Financial Statements, the financial information for all periods presented has been recast to include the financial position and results of operations of assets purchased by ENP from Encore Operating subsequent to December 31, 2008 in ENP’s financial information rather than in EAC Standalone’s financial information. The consolidated totals for all periods did not change from amounts previously presented.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

	For the Year Ended December 31, 2008
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	670,830		$	226,613		$	—		$	897,443
Natural gas		173,535			53,944			—			227,479
Marketing		5,172			5,324			—			10,496
Total revenues		849,537			285,881			—			1,135,418
Expenses:
Production:
Lease operating		130,363			44,752			—			175,115
Production, ad valorem, and severance taxes		82,497			28,147			—			110,644
Depletion, depreciation, and amortization		170,715			57,537			—			228,252
Impairment of long-lived assets		59,526			—			—			59,526
Exploration		39,011			196			—			39,207
General and administrative		36,082			16,605			(4,266	)		48,421
Marketing		4,104			5,466			—			9,570
Derivative fair value gain		(249,356	)		(96,880	)		—			(346,236	)
Provision for doubtful accounts		1,984			—			—			1,984
Other operating		11,305			1,670			—			12,975
Total expenses		286,231			57,493			(4,266	)		339,458
Operating income		563,306			228,388			4,266			795,960
Other income (expenses):
Interest		(66,204	)		(6,969	)		—			(73,173	)
Other		8,065			99			(4,266	)		3,898
Total other expenses		(58,139	)		(6,870	)		(4,266	)		(69,275	)
Income before income taxes		505,167			221,518			—			726,685
Income tax provision		(240,859	)		(762	)		—			(241,621	)
Consolidated net income		264,308			220,756			—			485,064
Amortization of deferred loss on commodity derivative contracts, net of tax		1,786			—			—			1,786
Change in deferred hedge gain on interest rate swaps, net of tax		941			(4,258	)		—			(3,317	)
Comprehensive income	$	267,035		$	216,498		$	—		$	483,533
Costs incurred related to oil and natural gas properties	$	730,908		$	45,613		$	—		$	776,521
Segment assets (as of December 31, 2008)	$	2,823,778		$	813,313		$	(3,896	)	$	3,633,195
Segment liabilities (as of December 31, 2008)	$	1,961,453		$	193,962		$	(5,468	)	$	2,149,947

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ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

	For the Year Ended December 31, 2007
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(in thousands)
Revenues:
Oil	$	427,271		$	135,546		$	—		$	562,817
Natural gas		110,988			39,119			—			150,107
Marketing		33,439			8,582			—			42,021
Total revenues		571,698			183,247			—			754,945
Expenses:
Production:
Lease operating		109,446			33,980			—			143,426
Production, ad valorem, and severance taxes		56,873			17,712			—			74,585
Depletion, depreciation, and amortization		136,486			47,494			—			183,980
Exploration		27,600			126			—			27,726
General and administrative		25,923			15,245			(2,044	)		39,124
Marketing		33,876			6,673			—			40,549
Derivative fair value loss		86,182			26,301			—			112,483
Provision for doubtful accounts		5,816			—			—			5,816
Other operating		15,640			1,426			—			17,066
Total expenses		497,842			148,957			(2,044	)		644,755
Operating income		73,856			34,290			2,044			110,190
Other income (expenses):
Interest		(82,417	)		(12,702	)		6,415			(88,704	)
Other		10,930			196			(8,459	)		2,667
Total other expenses		(71,487	)		(12,506	)		(2,044	)		(86,037	)
Income before income taxes		2,369			21,784			—			24,153
Income tax provision		(14,398	)		(78	)		—			(14,476	)
Consolidated net income (loss)		(12,029	)		21,706			—			9,677
Amortization of deferred loss on commodity derivative contracts, net of tax		33,541			—			—			33,541
Comprehensive income	$	21,512		$	21,706		$	—		$	43,218
Costs incurred related to oil and natural gas properties	$	792,157		$	424,002		$	—		$	1,216,159
Segment assets (as of December 31, 2007)	$	2,038,707		$	749,144		$	(3,290	)	$	2,784,561
Segment liabilities (as of December 31, 2007)	$	1,611,503		$	109,078		$	(6,709	)	$	1,713,872

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ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

	For the Year Ended December 31, 2006
	EAC								Consolidated
	Standalone			ENP			Eliminations		Total
	(in thousands)
Revenues:
Oil	$	306,074		$	40,900		$	—	$	346,974
Natural gas		105,864			40,461			—		146,325
Marketing		147,563			—			—		147,563
Total revenues		559,501			81,361			—		640,862
Expenses:
Production:
Lease operating		84,100			14,094			—		98,194
Production, ad valorem, and severance taxes		42,754			7,026			—		49,780
Depletion, depreciation, and amortization		98,766			14,697			—		113,463
Exploration		30,497			22			—		30,519
General and administrative		19,723			3,471			—		23,194
Marketing		148,571			—			—		148,571
Derivative fair value gain		(24,388	)		—			—		(24,388	)
Provision for doubtful accounts		1,970			—			—		1,970
Other operating		6,735			1,318			—		8,053
Total expenses		408,728			40,628			—		449,356
Operating income		150,773			40,733			—		191,506
Other income (expenses):
Interest		(45,131	)		—			—		(45,131	)
Other		1,429			—			—		1,429
Total other expenses		(43,702	)		—			—		(43,702	)
Income before income taxes		107,071			40,733			—		147,804
Income tax provision		(55,146	)		(260	)		—		(55,406	)
Consolidated net income		51,925			40,473			—		92,398
Amortization of deferred loss on commodity derivative contracts, net of tax		37,499			—			—		37,499
Comprehensive income	$	89,424		$	40,473		$	—	$	129,897
Costs incurred related to oil and natural gas properties	$	369,223		$	9,346		$	—	$	378,569

Note 19. Impairment of Long-Lived Assets

     During 2008, circumstances indicated that the carrying amounts of certain oil and natural gas properties, primarily four wells in the Tuscaloosa Marine Shale, may not be recoverable. EAC compared the assets’ carrying amounts to the undiscounted expected future net cash flows, which indicated the need for an impairment charge. EAC then compared the net carrying amounts of the impaired assets to their estimated fair value, which resulted in a pretax write-down of the value of proved oil and natural gas properties of $59.5 million. Fair value was determined using estimates of future production volumes and estimates of future prices EAC might receive for these volumes, discounted to a present value. EAC’s estimates of undiscounted cash flows indicated that the remaining carrying amounts of its oil and natural gas properties are expected to be recovered. Nonetheless, if oil and natural gas prices decline, it is reasonably possible that EAC’s estimates of undiscounted cash flows may change in the near term resulting in the need to record an additional write down of oil and natural gas properties to fair value.

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ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 20. Subsequent Events

     Commodity Derivative Contracts

     Subsequent to December 31, 2008, EAC entered into additional commodity derivative contracts. The following tables summarize EAC’s open commodity derivative contracts as of February 18, 2009:

     Oil Derivative Contracts

	Average		Weighted		Average			Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily			Average		Daily		Average		Daily		Average
	Floor		Floor		Short Floor			Short Floor		Cap		Cap		Swap		Swap
Period	Volume		Price		Volume			Price		Volume		Price		Volume		Price
	(Bbl)		(per Bbl)		(Bbl)			(per Bbl)		(Bbl)		(per Bbl)		(Bbl)		(per Bbl)
Feb. - Dec. 2009
		11,630	$	110.00		—		$	—		440	$	97.75		2,000	$	90.46
		8,000		80.00		—			—		—		—		500		89.39
		—		—		—			—		—		—		1,000		68.70
		—		—		(5,000	)		50.00		—		—		—		—
2010
		880		80.00		—			—		440		93.80		—		—
		2,000		75.00		—			—		1,500		75.48		—		—
		3,000		60.00		—			—		500		65.60		—		—
		1,000		56.00		—			—		—		—		2,000		60.48
2011
		1,880		80.00		—			—		1,440		95.41		—		—
		1,000		70.00		—			—		—		—		—		—

     Natural Gas Derivative Contracts

	Average		Weighted		Average	Weighted	Average		Weighted		Average		Weighted
	Daily		Average		Daily	Average	Daily		Average		Daily		Average
	Floor		Floor		Short Floor	Short Floor	Cap		Cap		Swap		Swap
Period	Volume		Price		Volume	Price	Volume		Price		Volume		Price
	(Mcf)		(per Mcf)		(Mcf)	(per Mcf)	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)
Feb 2009 - Dec 2009
		3,800	$	8.20	—	$ —		3,800	$	9.83		—	$	—
		3,800		7.20	—	—		5,000		7.45		—		—
		6,800		6.57	—	—		15,000		6.63		—		—
		15,000		5.64	—	—						—		—
2010
		3,800		8.20	—	—		3,800		9.58		—		—
		4,698		7.26	—	—		—		—		902		6.30
2011
		898		6.76	—	—		—		—		902		6.70
2012
		898		6.76	—	—		—		—		902		6.66

     As of February 18, 2009, EAC’s total deferred commodity derivative premiums were $58.4 million, $15.7 million, and $0.9 million for the remainder of 2009, 2010, and, 2011, respectively.

     Purchase and Sale Agreement

     On December 5, 2008, EAC entered into a purchase and sale agreement, with OLLC, pursuant to which OLLC acquired certain oil and natural gas producing properties and related assets in the Arkoma Basin and royalty interest properties in Oklahoma as well as 10,300 unleased mineral acres from EAC. The transaction closed on January 2, 2009, but was effective as of November 1, 2008. The

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ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

purchase price was $49 million in cash, subject to customary adjustments (including a reduction in the purchase price for acquisition-related commodity derivative premiums of approximately $3 million), which OLLC financed through borrowings under the OLLC Credit Agreement.

     Other Events

     Subsequent to December 31, 2008, EAC granted 269,417 stock options and 378,537 shares of restricted stock to employees as part of its annual incentive program and 144,695 stock options and 376,717 shares of restricted stock vested. Subsequent to December 31, 2008, it was determined that the performance measures related to certain awards granted in 2008 were met and therefore, vesting now depends only on the passage of time and continued employment.

     On January 26, 2009, ENP announced a distribution for the fourth quarter of 2008 to unitholders of record as of the close of business on February 6, 2009 at a rate of $0.50 per unit. Approximately $16.8 million was paid on February 13, 2009, $10.7 million of which was paid to EAC and its subsidiaries and had no impact on EAC’s consolidated cash.

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ENCORE ACQUISITION COMPANY

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,
	2008			2007
	(in thousands)
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment	$	3,538,459		$	2,845,776
Unproved properties		124,339			63,352
Accumulated depletion, depreciation, and amortization		(771,564	)		(489,004	)
	$	2,891,234		$	2,420,124

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

	Year Ended December 31,
	2008		2007		2006
	(in thousands)
Acquisitions:
Proved properties	$	28,729	$	787,988	$	4,486
Unproved properties		128,635		52,306		24,462
Asset retirement obligations		111		8,251		785
Total acquisitions		157,475		848,545		29,733
Development:
Drilling and exploitation		362,111		270,016		253,484
Asset retirement obligations		498		145		147
Total development		362,609		270,161		253,631
Exploration:
Drilling and exploitation		252,104		95,221		92,839
Geological and seismic		2,851		1,456		1,720
Delay rentals		1,482		776		646
Total exploration		256,437		97,453		95,205
Total costs incurred	$	776,521	$	1,216,159	$	378,569

Oil & Natural Gas Producing Activities — Unaudited

     The estimates of EAC’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 EAC’s properties and the representative value thereof are made using oil and natural gas prices in effect as of the dates of such estimates and are held constant throughout the life of the properties. Year-end prices used in estimating net cash flows were as follows as of the dates indicated:

	December 31,
	2008		2007		2006
Oil (per Bbl)	$	44.60	$	96.01	$	61.06
Natural gas (per Mcf)	$	5.62	$	7.47	$	5.48

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ENCORE ACQUISITION COMPANY

SUPPLEMENTARY INFORMATION — (Continued)

     EAC’s reserve and production quantities from its CCA properties have been reduced by the amounts attributable to the net profits interest. The net profits interest on EAC’s CCA properties has also been deducted from future cash inflows in the calculation of Standardized Measure. In addition, net future cash inflows have not been adjusted for commodity derivative contracts outstanding at the end of the year. The future net cash flows are reduced by estimated production and development costs, which are based on year-end economic conditions and held constant throughout the life of the properties, and by the estimated effect of future income taxes. Future income taxes are based on statutory income tax rates in effect at year-end, EAC’s tax basis in its proved oil and natural gas properties, and the effect of NOL carryforwards and AMT credits.

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

     EAC’s estimated net quantities of proved oil and natural gas reserves were as follows as of the dates indicated:

	December 31,
	2008		2007		2006
Proved reserves:
Oil (MBbl)		134,452		188,587		153,434
Natural gas (MMcf)		307,520		256,447		306,764
Combined (MBOE)		185,705		231,328		204,561
Proved developed reserves:
Oil (MBbl)		110,014		125,213		94,246
Natural gas (MMcf)		232,715		191,072		235,049
Combined (MBOE)		148,800		157,058		133,421

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ENCORE ACQUISITION COMPANY

SUPPLEMENTARY INFORMATION — (Continued)

     The changes in EAC’s proved reserves were as follows for the periods indicated:

				Natural			Oil
	Oil			Gas			Equivalent
	(MBbl)			(MMcf)			(MBOE)
Balance, December 31, 2005		148,387			283,865			195,698
Purchases of minerals-in-place		25			235			64
Extensions and discoveries		3,269			78,861			16,412
Improved recovery		10,935			941			11,092
Revisions of previous estimates		(1,847	)		(33,682	)		(7,461	)
Production		(7,335	)		(23,456	)		(11,244	)
Balance, December 31, 2006		153,434			306,764			204,561
Purchases of minerals-in-place		40,534			15,667			43,146
Sales of minerals-in-place		(1,845	)		(107,249	)		(19,719	)
Extensions and discoveries		4,362			65,639			15,302
Improved recovery		666			90			681
Revisions of previous estimates		981			(501	)		896
Production		(9,545	)		(23,963	)		(13,539	)
Balance, December 31, 2007		188,587			256,447			231,328
Purchases of minerals-in-place		266			6,220			1,303
Extensions and discoveries		7,411			73,527			19,665
Improved recovery		287			—			287
Revisions of previous estimates		(52,049	)		(2,300	)		(52,432	)
Production		(10,050	)		(26,374	)		(14,446	)
Balance, December 31, 2008 (a)		134,452			307,520			185,705

(a) Includes reserves of 27.3 MMBbls of oil and 78.0 Bcf of natural gas (40.3 MMBOE) attributable to ENP in which there was a 36 percent noncontrolling interest as of December 31, 2008.

     EAC’s Standardized Measure of discounted estimated future net cash flows was as follows as of the dates indicated:

	December 31,
	2008			2007			2006
	(in thousands)
Future cash inflows	$	6,754,431		$	17,394,468		$	9,291,007
Future production costs		(3,082,814	)		(5,721,804	)		(3,668,897	)
Future development costs		(497,197	)		(469,034	)		(371,396	)
Future abandonment costs, net of salvage		(96,480	)		(75,172	)		(134,103	)
Future income tax expense		(555,370	)		(3,236,356	)		(1,499,290	)
Future net cash flows		2,522,570			7,892,102			3,617,321
10% annual discount		(1,302,616	)		(4,600,393	)		(2,155,514	)
Standardized measure of discounted estimated future net cash flows (a)	$	1,219,954		$	3,291,709		$	1,461,807

(a) Includes $326.6 million attributable to ENP in which there was a 36 percent noncontrolling interest as of December 31, 2008.

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ENCORE ACQUISITION COMPANY

SUPPLEMENTARY INFORMATION — (Continued)

     The changes in EAC’s Standardized Measure of discounted estimated future net cash flows were as follows for the periods indicated:

	Year Ended December 31,
	2008			2007			2006
	(in thousands)
Net change in prices and production costs	$	(2,848,387	)	$	1,718,818		$	(634,033	)
Purchases of minerals-in-place		14,155			1,249,008			539
Sales of minerals-in-place		—			(300,727	)		—
Extensions, discoveries, and improved recovery		171,509			282,163			141,211
Revisions of previous quantity estimates		(474,926	)		21,887			(62,615	)
Production, net of production costs		(321,935	)		(710,134	)		(340,036	)
Development costs incurred during the period		148,569			270,016			253,484
Accretion of discount		329,171			146,181			191,847
Change in estimated future development costs		(176,732	)		(235,005	)		(185,212	)
Net change in income taxes		991,368			(672,807	)		248,491
Change in timing and other		95,453			60,502			(70,340	)
Net change in standardized measure		(2,071,755	)		1,829,902			(456,664	)
Standardized measure, beginning of year		3,291,709			1,461,807			1,918,471
Standardized measure, end of year	$	1,219,954		$	3,291,709		$	1,461,807

Selected Quarterly Financial Data — Unaudited

     The following table provides selected quarterly financial data for the periods indicated:

	Quarter
	First			Second			Third		Fourth
	(in thousands, except per share data)
2008
Revenues	$	272,902		$	357,334		$	337,478	$	167,704
Operating income (loss)	$	68,956		$	(55,925	)	$	375,148	$	407,781
Net income (loss) attributable to EAC stockholders	$	31,220		$	(35,720	)	$	206,307	$	229,005
Net income (loss) per common share:
Basic	$	0.58		$	(0.68	)	$	3.88	$	4.35
Diluted	$	0.58		$	(0.68	)	$	3.77	$	4.32
2007
Revenues	$	130,542		$	189,643		$	195,016	$	239,744
Operating income (loss)	$	(29,592	)	$	50,914		$	41,059	$	47,809
Net income (loss) attributable to EAC stockholders	$	(29,429	)	$	15,171		$	11,985	$	19,428
Net income (loss) per common share:
Basic	$	(0.55	)	$	0.28		$	0.22	$	0.36
Diluted	$	(0.55	)	$	0.28		$	0.22	$	0.36

     As discussed in “Note 2. Summary of Significant Accounting Policies” and “Note 10. Earnings Per Share,” EAC adopted FSP EITF 03-6-1 on January 1, 2009 and all periods presented have been restated to calculate EPS in accordance therewith.

51

EX-99.6

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 1, 2010

ENCORE ACQUISITION COMPANY

(Exact name of registrant as specified in its charter)

Delaware	001-16295	75-2759650
(State or other jurisdiction	(Commission	(IRS Employer
of incorporation)	File Number)	Identification No.)

777 Main Street, Suite 1400, Fort Worth, Texas	76102
(Address of principal executive offices)	(Zip Code)

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

Not applicable

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

þ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02 Results of Operations and Financial Condition

     On February 1, 2010, Encore Acquisition Company (“EAC”) issued a press release providing, among other things, (1) estimated proved oil and natural gas reserves as of December 31, 2009 and (2) certain fourth quarter operating results. A copy of the press release is furnished as Exhibit 99.1 to this Form 8-K.

     The information being furnished pursuant to Item 2.02 of this Form 8-K and in Exhibit 99.1 shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 (the “Exchange Act”) or otherwise subject to the liabilities of that section, nor shall it be incorporated by reference into a filing under the Securities Act of 1933, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.

Item 8.01 Other Events.

     EAC’s total proved oil and natural gas reserves as of December 31, 2009 were 220.3 million barrels of oil equivalent (“MMBOE”), consisting of 147.1 million barrels of crude oil, condensate, and natural gas liquids and 439.1 billion cubic feet of natural gas. EAC produced 15.7 MMBOE during 2009, averaging 45,143 barrels of oil equivalent per day during the fourth quarter of 2009.

     At December 31, 2009, oil reserves accounted for 67 percent of EAC’s total proved reserves, and 80 percent of EAC’s total proved reserves are developed.

     The following table summarizes the changes in proved reserves during 2009 (in thousands of barrels of oil equivalent):

Reserves at December 31, 2008	185,705
Purchases of minerals-in-place	24,078
Sales of minerals-in-place	(117	)
Extensions and discoveries	21,502
Revisions	4,774
Production	(15,669	)
Reserves at December 31, 2009	220,273

     Based on the average NYMEX oil price of $75.98 per barrel for the fourth quarter of 2009, EAC’s wellhead differential was negative $8.04 per barrel for the quarter. Based on the average NYMEX natural gas price of $4.17 per thousand cubic feet (“Mcf”) for the fourth quarter of 2009, EAC’s wellhead differential was positive $0.49 per Mcf for the quarter.

     In the press release, EAC uses the financial measure of PV-10 Value. PV-10 Value is the present value of estimated future revenues expected to be generated from the production of proved reserves, net of estimated future production and development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to commodity derivative activities, non-property related expenses such as general and administrative expenses, debt service, depletion, depreciation, and amortization, and income taxes, discounted at an annual rate of 10 percent.

     EAC’s oil and natural gas reserves and related PV-10 Value are derived from the reports of Miller and Lents, Ltd., an independent petroleum engineering firm.

Item 9.01 Financial Statements and Exhibits

     (d) Exhibits

99.1	Press Release dated February 1, 2010 (furnished pursuant to Item 2.02 of this Form 8-K).
99.2	Consent of Miller and Lents, Ltd.

SIGNATURE

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	ENCORE ACQUISITION COMPANY
Date: February 1, 2010	By:	/s/ Andrea Hunter
	Andrea Hunter
	Vice President, Controller, and Principal Accounting Officer

EXHIBIT INDEX

Exhibit No.	Description
99.1	Press Release dated February 1, 2010.
99.2	Consent of Miller and Lents, Ltd.

Exhibit 99.1

Encore Acquisition Company Announces Year-End Proved
Reserves and Certain Fourth Quarter 2009 Operating Results

FORT WORTH, Texas – (BUSINESS WIRE) – February 1, 2010 — Encore Acquisition Company (NYSE: EAC) (“Encore” or the “Company”) today announced year-end 2009 reserves and certain fourth quarter 2009 operating results.

Proved Reserves

Total proved oil and natural gas reserves at December 31, 2009 were 220.3 million barrels of oil equivalent (“BOE”), consisting of 147.1 million barrels of crude oil, condensate, and natural gas liquids and 439.1 billion cubic feet of natural gas. Proved reserves were calculated utilizing twelve month average prices during 2009, or $61.18 per Bbl of oil and $3.83 per Mcf of natural gas. Prior year proved reserves were calculated based on year-end 2008 spot market prices of $44.60 per Bbl of oil and $5.62 per Mcf of natural gas.

Using 2009 average prices, the estimated discounted net present value of Encore’s proved oil and natural gas reserves, before projected income taxes and net abandonment costs, using a 10 percent per annum discount rate (“PV-10 Value”) was approximately $2.1 billion at December 31, 2009, as compared to a PV-10 value of approximately $1.4 billion at December 31, 2008 using unescalated year-end 2008 prices.

At December 31, 2009, oil reserves accounted for 67 percent of total proved reserves, and 80 percent of total proved reserves are developed. The following table summarizes the changes in proved reserves:

	MBOE
Reserves at December 31, 2008		185,705
Purchases of minerals-in-place		24,078
Sales of minerals-in-place		(117	)
Extensions and discoveries		21,502
Revisions of previous estimates		4,774
Production		(15,669	)
Reserves at December 31, 2009		220,273

Encore’s proved reserve estimates for 100 percent of its properties were prepared by independent petroleum engineers.

Fourth Quarter Operating Results

Encore’s fourth quarter production averaged 45,143 BOE per day, consisting of 27,913 Bbls of oil per day and 103,382 Mcf of natural gas per day. This represents an increase of eight percent over the 41,824 BOE per day produced in the fourth quarter of 2008.

NYMEX oil prices averaged $75.98 per Bbl for the fourth quarter of 2009, and Encore’s wellhead differential was a negative $8.04 per Bbl for the quarter. This represents a tightening in the differential of $3.85 per Bbl from the $11.89 per Bbl differential in the fourth quarter of 2008.

NYMEX natural gas prices averaged $4.17 per Mcf for the fourth quarter of 2009, and the Company’s wellhead differential was a positive $0.49 per Mcf for the quarter as compared to a negative $0.99 per Mcf in the fourth quarter of 2008.

Costs Incurred

During 2009, the Company completed 120 gross wells (48.9 net). The following table summarizes Encore’s costs incurred related to oil and natural gas properties for the periods indicated:

	Year Ended December 31,
	2009		2008
	(in thousands)
Acquisitions:
Proved properties	$	402,457	$	28,840
Unproved properties		17,087		128,635
Total acquisitions		419,544		157,475
Development:
Drilling and exploitation		121,259		362,609
Total development		121,259		362,609
Exploration:
Drilling		163,887		252,104
Geological and seismic		1,022		2,851
Delay rentals		774		1,482
Total exploration		165,683		256,437
Total costs incurred	$	706,486	$	776,521

The amounts provided in this press release are subject to change after review and audit of the Company’s financial statements.

About the Company

Encore Acquisition Company is engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States. Since 1998, Encore has acquired producing properties with proven reserves and leasehold acreage and grown the production and proven reserves by drilling, exploring, reengineering or expanding existing waterflood projects, and applying tertiary recovery techniques.

Additional Information

As previously announced on November 1, 2009, Encore entered into a definitive merger

Page 2 of 3

agreement with Denbury Resources Inc. (“Denbury”) pursuant to which Denbury will acquire Encore (the “transaction”). The combined company will continue to be known as Denbury Resources Inc. and will be headquartered in Plano, Texas. The Boards of Directors of both companies have unanimously approved the merger agreement, and each has recommended approval of the transaction to its respective stockholders. Completion of the transaction is subject to the approval of both Denbury and Encore stockholders, regulatory approvals, and other customary conditions. The transaction is expected to close in the first quarter of 2010.

In connection with the transaction, Denbury and Encore will file a joint proxy statement/prospectus and other documents with the Securities and Exchange Commission (“SEC”). Investors and security holders are urged to carefully read the definitive joint proxy statement/prospectus when it becomes available because it will contain important information regarding Denbury, Encore, and the transaction.

A definitive joint proxy statement/prospectus will be sent to stockholders of Denbury and Encore seeking their approval of the transaction. Investors and security holders may obtain a free copy of the definitive joint proxy statement/prospectus (when available) and other documents filed by Denbury and Encore with the SEC at the SEC’s website, www.sec.gov. The definitive joint proxy statement/prospectus (when available) and such other documents relating to Denbury may also be obtained free-of-charge by directing a request to Denbury, Attn: Investor Relations, 5100 Tennyson Parkway, Suite 1200, Plano, Texas 75024, or from Denbury’s website, www.denbury.com. The definitive joint proxy statement/prospectus (when available) and such other documents relating to Encore may also be obtained free-of-charge by directing a request to Encore, Attn: Bob Reeves, 777 Main Street, Suite 1400, Fort Worth, Texas 76102, or from Encore’s website, www.encoreacq.com.

Denbury, Encore, and their respective directors and executive officers may, under the rules of the SEC, be deemed to be “participants” in the solicitation of proxies in connection with the proposed transaction. Information concerning the interests of the persons who may be “participants” in the solicitation will be set forth in the joint proxy statement/prospectus when it becomes available.

Contacts
Encore Acquisition Company, Fort Worth, TX

Bob Reeves, Chief Financial Officer	Kim Weimer, Investor Relations
817-339-0918	817-339-0886
rcreeves@encoreacq.com	kweimer@encoreacq.com

Page 3 of 3

Exhibit 99.2

Consent of Independent Petroleum Engineers

     The firm of Miller and Lents, Ltd. hereby consents to the use of its name, and to the reference to its report dated January 20, 2010 regarding Encore Acquisition Company’s Reserves and Future Net Revenues as of December 31, 2009, in Encore Acquisition Company’s Current Report dated February 1, 2010 filed on Form 8-K with the United States Securities and Exchange Commission.

     The Current Report contains references to certain reports prepared by Miller and Lents, Ltd. for the exclusive use of Encore Acquisition Company. The analysis, conclusions, and methods contained in the reports are based upon information that was in existence at the time the reports were rendered and Miller and Lents, Ltd. has not updated and undertakes no duty to update anything contained in the reports. While the reports may be used as a descriptive resource, investors are advised that Miller and Lents, Ltd. has not verified information provided by others except as specifically noted in the reports, and Miller and Lents, Ltd. makes no representation or warranty as to the accuracy of such information. Moreover, the conclusions contained in such reports are based on assumptions that Miller and Lents, Ltd. believed were reasonable at the time of their preparation and that are described in such reports in reasonable detail. However, there are a wide range on uncertainties and risks that are outside of the control of Miller and Lents, Ltd. which may impact these assumptions, including but not limited to unforeseen market changes, actions of governments or individuals, natural events, economic changes, and changes of laws and regulations or interpretation of laws and regulations.

MILLER AND LENTS, LTD. Texas Registered Engineering Firm No. F-1442
By:	/s/ Carl D. Richard
Carl D. Richard
Senior Vice President, P. E.

Houston, Texas
February 1, 2010