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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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 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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ENCORE ACQUISITION COMPANY

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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ENCORE ACQUISITION COMPANY

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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ENCORE ACQUISITION COMPANY

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

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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.

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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

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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.

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