Exhibit 99.1

ENCORE ACQUISITION COMPANY

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, reengineering, or expanding existing waterflood projects, and applying tertiary recovery techniques. Our properties and oil and natural gas reserves are located in four core areas:

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

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

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

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

In August 2009, we acquired certain oil and natural gas properties and related assets in the Mid-Continent and East Texas from EXCO Resources, Inc. (together with its affiliates, “EXCO”) for approximately $357.4 million in cash, substantially all of which are proved producing.

Merger with Denbury.  On October 31, 2009, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Denbury Resources Inc. (“Denbury”) pursuant to which we have agreed to merge with and into Denbury, with Denbury as the surviving entity (the “Merger”). The Merger Agreement, which was unanimously approved by our Board of Directors (the “Board”) and by Denbury’s Board of Directors, provides for Denbury’s acquisition of all of our issued and outstanding shares of common stock, par value $.01 per share, in a transaction valued at approximately $4.5 billion, including the assumption of debt and the value of our interest in ENP. We expect to complete the Merger during the first quarter of 2010, although completion by any particular date cannot be assured.

Proved Reserves.  Our estimated total proved reserves at December 31, 2009 were 147.1 MMBbls of oil and 439.1 Bcf of natural gas, based on 2009 average market prices of $61.18 per Bbl for oil and $3.83 per Mcf for natural gas. On a BOE basis, our proved reserves were 220.3 MMBOE at December 31, 2009, of which 67 percent was oil, 80 percent was proved developed, and 20 percent was proved undeveloped.

Most Valuable Asset.  The CCA represented approximately 32 percent of our total proved reserves as of December 31, 2009 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.

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Drilling.  In 2009, we drilled 34 gross (27.5 net) operated productive wells and participated in drilling 78 gross (14.8 net) non-operated productive wells for a total of 112 gross (42.3 net) productive wells. In 2009, we drilled six gross (5.9 net) operated dry holes and participated in drilling another two gross (0.6 net) dry holes for a total of eight gross (6.6 net) dry holes. This represents a success rate of over 93 percent during 2009. We invested $286.9 million in development, exploitation, and exploration activities in 2009, of which $25.4 million related to dry holes.

ENP.  As of February 17, 2010, we owned 20,924,055 of ENP’s outstanding common units, representing an approximate 45.7 percent limited partner interest. Through our indirect ownership of ENP’s general partner, we also hold all 504,851 general partner units, representing a 1.1 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 properties and related assets in the Permian Basin in West Texas and in the Williston Basin in North Dakota to ENP for approximately $125.0 million in cash and 6,884,776 ENP common units. In determining the total sales price, the common units were valued at $125.0 million. In January 2009, we sold certain oil and natural gas properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”), to ENP for approximately $46.4 million in cash. In June 2009, we sold certain oil and natural gas properties and related assets in the Williston Basin in North Dakota and Montana (the “Williston Basin Assets”) to ENP for approximately $25.2 million in cash. In August 2009, we sold certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota (the “Rockies and Permian Basin Assets”) to ENP for approximately $179.6 million in cash.

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 16 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

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, 2009, 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 for which we are required to pay our share of production, exploitation, and development costs. Please read “— Properties — Nature of Our Ownership Interests.” During 2009, 2008, and 2007, our development costs on non-operated properties were approximately 39 percent, 22 percent, and 40 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.

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Natural Gas Gathering

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

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

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

•  control compression costs and fuel use;

•  maintain system integrity;

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

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

Seasonal Nature of Business

Oil and natural 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.

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Production and Price History

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

	Year Ended December 31,
	2009			2008			2007
Total Production Volumes:
Oil (MBbls)		10,016			10,050			9,545
Natural gas (MMcf)		33,919			26,374			23,963
Combined (MBOE)		15,669			14,446			13,539
Average Daily Production Volumes:
Oil (Bbls/D)		27,441			27,459			26,152
Natural gas (Mcf/D)		92,928			72,060			65,651
Combined (BOE/D)		42,929			39,470			37,094
Average Realized Prices:
Oil (per Bbl)	$	54.85		$	89.30		$	58.96
Natural gas (per Mcf)		3.87			8.63			6.26
Combined (per BOE)		43.43			77.87			52.66
Average Costs per BOE:
Lease operating	$	10.53		$	12.12		$	10.59
Production, ad valorem, and severance taxes		4.44			7.66			5.51
Depletion, depreciation, and amortization		18.56			15.80			13.59
Impairment of long-lived assets		0.64			4.12			—
Exploration		3.35			2.71			2.05
Derivative fair value loss (gain)		3.80			(23.97	)		8.31
General and administrative		3.45			3.35			2.89
Provision for doubtful accounts		0.49			0.14			0.43
Other operating		1.64			0.90			1.26
Marketing, net of revenues		(0.05	)		(0.06	)		(0.11	)

Productive Wells

The following table sets forth information relating to productive wells in which we owned a working interest at December 31, 2009. Wells are classified as oil or natural gas wells according to their predominant production stream. 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		729		645.2		89	%		23		6.3		27	%
Permian Basin		1,969		772.2		39	%		692		353.5		51	%
Rockies		1,476		851.7		58	%		42		29.7		71	%
Mid-Continent		484		282.6		58	%		1,355		569.7		42	%
Total		4,658		2,551.7		55	%		2,112		959.2		45	%

(a) Our total wells include 3,810 operated wells and 2,960 non-operated wells. At December 31, 2009, 62 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, 2009. 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, 2009, our undeveloped acreage in the Rockies represented approximately 40 percent of our total net undeveloped acreage. A portion of our oil and natural gas leases are held by production, which means that for as long as our wells continue to produce oil or natural gas, we will continue to own the lease. Leases which are not held by production expire at various dates between 2010 and 2020, with leases representing $28.9 million of cost set to expire in 2010 if not developed.

	Gross		Net
	Acreage		Acreage
CCA:
Developed		93,563		94,607
Undeveloped		159,264		133,107
		252,827		227,714
Permian Basin:
Developed		81,248		53,788
Undeveloped		25,242		23,449
		106,490		77,237
Rockies:
Developed		235,535		160,024
Undeveloped		375,704		245,170
		611,239		405,194
Mid-Continent:
Developed		189,778		101,900
Undeveloped		292,504		205,703
		482,282		307,603
Total:
Developed		600,124		410,319
Undeveloped		852,714		607,429
		1,452,838		1,017,748

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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,
	2009				2008				2007
	Gross		Net		Gross		Net		Gross		Net
Development Wells:
Productive		57		25.9		186		73.4		165		61.7
Dry holes		1		1.0		5		3.1		5		3.3
		58		26.9		191		76.5		170		65.0
Exploratory Wells:
Productive		55		16.4		96		31.4		63		20.9
Dry holes		7		5.6		8		3.8		5		2.6
		62		22.0		104		35.2		68		23.5
Total:
Productive		112		42.3		282		104.8		228		82.6
Dry holes		8		6.6		13		6.9		10		5.9
		120		48.9		295		111.7		238		88.5

Present Activities

As of December 31, 2009, we had 25 gross (10.3 net) wells that had begun drilling and were in varying stages of drilling operations, of which nine gross (1.9 net) were development wells. As of December 31, 2009, we had 15 gross (6.0 net) wells that had reached total depth and were in the process of being completed pending first production, of which six gross (1.2 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 subject to apportionment, we currently believe that we have been allocated sufficient pipeline capacity to move our crude oil production. However, there can be no assurance that we will be allocated sufficient pipeline capacity to move our crude oil production in the future. An expansion of the Enbridge Pipeline was completed in early 2008, which moved the total Rockies area pipeline takeaway closer to increasing production volumes and thereby provided greater stability to oil differentials in the area. An additional expansion of Enbridge Pipeline was completed in early

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2010, bringing additional takeaway capacity to the region, but in spite of these increases in capacity, the Enbridge Pipeline continues to run at full capacity. The Enbridge pipeline is currently presenting a new proposal to further expand the line in anticipation of the continuing expected production increases from the Williston / Bakken region. However, any restrictions on available capacity to transport oil through any of the above-mentioned pipelines, any other pipelines, or any refinery upsets could have a material adverse effect on our production volumes and the prices we receive for our production.

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

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	of 2009			of 2009			of 2009			of 2009
Average oil wellhead to NYMEX percentage		82	%		92	%		89	%		89	%
Average natural gas wellhead to NYMEX percentage		67	%		105	%		109	%		112	%

Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of liquids extracted. Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas in Mcf as production resulting in a price we were paid per Mcf under certain contracts to be higher than the average NYMEX price.

Principal Customers

For 2009, our largest purchaser was Eighty-Eight Oil, which accounted for approximately 18 percent of our total sales of 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 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 production, average wellhead prices, and average LOE per BOE of our properties by principal area of operation for the periods indicated:

	Production									Average
			Natural				Percent			Average Oil		Natural Gas		Lease
	Oil		Gas		Total		of Total			Wellhead		Wellhead		Operating
	(MBbls)		(MMcf)		(MBOE)					(per Bbl)		(per Mcf)		(per BOE)
2009
CCA		3,786		889		3,934		25	%	$	55.41	$	3.87	$	12.64
Permian Basin		1,217		15,182		3,748		24	%		56.73		3.98		8.32
Rockies		4,410		2,035		4,749		30	%		53.46		3.96		12.66
Mid-Continent		603		15,813		3,238		21	%		57.77		3.74		7.43
Total		10,016		33,919		15,669		100	%		54.85		3.87		10.53
2008
CCA		4,146		978		4,309		30	%		88.66		8.35		12.62
Permian Basin		1,246		12,442		3,320		23	%		95.34		8.65		11.96
Rockies		4,256		1,870		4,567		32	%		88.15		9.02		13.80
Mid-Continent		402		11,084		2,250		15	%		96.28		8.55		8.02
Total		10,050		26,374		14,446		100	%		89.58		8.63		12.12
2007
CCA		4,426		1,122		4,614		34	%		62.72		5.31		10.16
Permian Basin		1,214		8,937		2,703		20	%		67.88		7.03		11.97
Rockies		3,434		1,368		3,662		27	%		62.61		6.31		12.15
Mid-Continent		471		12,536		2,560		19	%		65.98		6.62		7.69
Total		9,545		23,963		13,539		100	%		63.50		6.69		10.59

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The following table sets forth the proved reserves of our properties by principal area of operation as of December 31, 2009:

			Natural				Percent
	Oil		Gas		Total		of Total
	(MBbls)		(MMcf)		(MBOE)
Proved Developed:
CCA		60,227		12,708		62,345		36	%
Permian Basin		14,408		127,620		35,678		20	%
Rockies		39,274		15,448		41,849		24	%
Mid-Continent		7,492		166,646		35,266		20	%
Total Proved Developed		121,401		322,422		175,138		100	%
Proved Undeveloped:
CCA		7,777		675		7,890		17	%
Permian Basin		5,641		38,886		12,122		27	%
Rockies		11,469		6,725		12,590		28	%
Mid-Continent		806		70,364		12,533		28	%
Total Proved Undeveloped		25,693		116,650		45,135		100	%
Total Proved:
CCA		68,004		13,383		70,235		32	%
Permian Basin		20,049		166,506		47,800		22	%
Rockies		50,743		22,173		54,439		24	%
Mid-Continent		8,298		237,010		47,799		22	%
Total Proved		147,094		439,072		220,273		100	%

The following table sets forth the PV-10 of our properties by principal area of operation as of December 31, 2009:

	Amount(a)		Percent of Total
	(In thousands)
CCA	$	786,720		37	%
Permian Basin		419,346		20	%
Rockies		671,483		31	%
Mid-Continent		263,488		12	%
Total	$	2,141,037		100	%

(a) Giving effect to commodity derivative contracts, our PV-10 would decrease by $23.4 million at December 31, 2009. Standardized Measure at December 31, 2009 was $1.7 billion. Standardized Measure differs from PV-10 by approximately $414.0 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.

Recent SEC Rule-Making Activity.  In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and natural gas than would have resulted under the previous rules. Use of new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately 8.5 MBOE while the change in definition of proved

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undeveloped reserves increased total proved reserves by 5.7 MMBOE. Therefore, the total impact of the new reserve rules resulted in negative reserves revisions of 2.8 MMBOE. Pursuant to the SEC’s final rule, prior period reserves were not restated.

The SEC’s new rules expanded the technologies that a company can use to establish reserves. The SEC now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.

We used a combination of production and pressure performance, wireline wellbore measurements, simulation studies, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs, and core data to calculate our reserves estimates, including the material additions to the 2009 reserves estimates.

Proved Undeveloped Reserves (“PUDs”).  As of December 31, 2009, our PUDs totaled 25.7 MMBbls of crude oil and 116.7 Bcf of natural gas, for a total of 45.1 MMBOE or about 20.5 percent of our total proved reserves.

All of our PUDs as of December 31, 2009 are associated with drilling or improved recovery development projects that are scheduled to begin drilling or implementation within the next 5 years. Our major development areas include drilling locations in West Texas, Bakken, and Haynesville and PUDs booked for secondary recovery projects in CCA and West Texas. All of the drilling projects will have PUDs convert from undeveloped to developed as these projects begin production. All of the improved recovery projects will convert to proved developed reserves as, and to the extent, these projects achieve production response.

Changes in PUDs that occurred during 2009 were due to:

•  reclassifications of PUDs into proved developed reserves for implementation of drilling projects and response to secondary/tertiary recovery projects;

•  additions of PUDs due to proving up additional drilling locations and changes in PUDs definition under the new SEC rules; and

•  negative revisions in PUDs due to changes in commodity prices.

Drilling Plans.  All PUD drilling locations are scheduled to be drilled prior to the end of 2014. Initial production from these PUDs is expected to begin between 2010 to 2014.

Internal Controls Over Reserves Estimates.  Our policies regarding internal controls over the recording of reserves estimates requires reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles. We engage a third-party petroleum consulting firm, Miller and Lents, to prepare our reserves. Responsibility for compliance in reserves bookings is delegated to the Reserves and Planning Engineering Manager and requires that reserves estimates be made by the regional reservoir engineering staff for our different geographical regions. These reserves estimates are reviewed and approved by regional management and senior engineering staff with final approval by the Reserves and Planning Engineering Manager and the Senior Vice President and Chief Operating Officer and certain members of senior management.

Our Reserves and Planning Engineering Manager is the technical person primarily responsible for overseeing the preparation of our reserves estimates. She has a Bachelor of Science degree in Petroleum Engineering, 15 years of industry experience, and 9 years experience managing our reserves with positions of increasing responsibility in engineering and evaluations. The Reserves and Planning Engineering Manager reports directly to our Senior Vice President and Chief Operating Officer.

The engineers and geologists of Miller and Lents have an average of 30 years of relevant industry experience in the estimation, assessment, and evaluation of oil and natural gas reserves. They have significant industry experience in virtually all petroleum-producing basins in the world and meet the requirements

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regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Miller and Lents is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists; it does not own an interest in our properties and is not employed on a contingent fee basis. Miller and Lents’ report on our reserves and future net revenues as of December 31, 2009, which details specific information regarding the scope of work undertaken and the results thereof, is filed as Exhibit 99.1 to this Report and incorporated herein by reference.

Guidelines established by the SEC 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.

Other Reserve Information.  During 2009, we filed the estimates of our oil and natural gas reserves as of December 31, 2008 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, 2009, 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 decreased 15 percent to 10,360 BOE/D in the fourth quarter of 2009 as compared to 12,153 BOE/D in the fourth quarter of 2008. We invested $18.1 million, $37.3 million, and $41.6 million in capital projects in the CCA during 2009, 2008, and 2007, respectively.

The CCA represents approximately 32 percent of our total proved reserves as of December 31, 2009 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. 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 2009, 2008, and 2007, we reduced oil and natural gas revenues for net profits interests by $31.8 million, $56.5 million, and $32.5 million, respectively.

Permian Basin Properties

West Texas.  Our West Texas properties include 17 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.

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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.

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. We also have the right to propose and drill wells for as long as we are engaged in continuous drilling operations.

We 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 three percent from 8,497 BOE/D in the fourth quarter of 2008 to 8,777 BOE/D in the fourth quarter of 2009. We believe these properties will be an area of growth over the next several years. During 2009, we drilled 21 gross wells and invested approximately $64.3 million of capital to develop these properties.

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 30 percent from 6,732 Mcfe/D in the fourth quarter of 2008 to 4,742 Mcfe/D in the fourth quarter of 2009. During 2009, we drilled two gross wells and invested approximately $3.3 million of capital to develop these properties.

Mid-Continent Properties

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 nearly tripled from 8,159 Mcfe/D in the fourth quarter of 2008 to 24,420 Mcfe/D for the fourth quarter of 2009. The increase in production was primarily due to our acquisition of the Nogre Marchand Unit and other properties in the Anadarko basin from EXCO in 2009. During 2009, we invested $6.7 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 and development in the Stockman, Danville, Gladewater, and Overton fields in east Texas. We purchased interests in the Gladewater and Overton fields from EXCO in 2009. Our interests in the Elm Grove Field in Bossier Parish, Louisiana 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 and was completed with an 11-stage fracture stimulation. Since entering the Haynesville play, we have accumulated over 18,000 gross acres.

During 2009, we drilled four gross wells and invested approximately $93.7 million of capital to develop these properties. Average daily production for these properties increased 30 percent from 36,239 Mcfe/D in the fourth quarter of 2008 to 47,104 Mcfe/D for the fourth quarter of 2009.

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 seven percent from 4,212 BOE/D in the fourth quarter of 2008 to 3,934 BOE/D in the fourth quarter of 2009. During 2009, we invested approximately $1.0 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 2009, we drilled and completed six wells in the Bakken and Sanish. The Almond prospect contains 70,000 net acres and is located near the northeast border of Mountrail County, North Dakota.

Average daily production for these properties increased 11 percent from 6,919 BOE/D in the fourth quarter of 2008 to 7,708 BOE/D in the fourth quarter of 2009. During 2009, we drilled seven gross wells and invested approximately $81.2 million of capital to develop our Rockies properties.

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.

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We invested $12.3 million of capital to develop these properties in 2009. Average daily production from these properties increased nine percent from 890 BOE/D in the fourth quarter of 2008 to 969 BOE/D in the fourth quarter of 2009.

In July 2009, we acquired a private company for $24 million, which procured a CO₂ supply intended to be used for a tertiary oil recovery project in the Bell Creek Field. The initial term of the CO₂ supply contract is 15 years. The CO₂ purchasable is not transportable as capture and compression facilities and a related pipeline need to be built. Until the CO₂ can be transported to the field and the capture, compression, and injection of the CO₂ proves economic, the contract has an unknown useful life. During 2009, we invested approximately $5.0 million of capital related to a pipeline which is intended to be used to transport this CO₂ supply to our Bell Creek field.

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. We believe these properties have additional potential in horizontal redevelopment, secondary development, and tertiary recovery potential.

Average daily production for these properties increased approximately four percent from 631 BOE/D in the fourth quarter of 2008 to 658 BOE/D in the fourth quarter of 2009. During 2009, we invested approximately $3.1 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.

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;

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•  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 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.

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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, 2009, ENP has recorded $4.7 million as future abandonment liability for decommissioning the Elk Basin natural gas processing plant. Due to the significant 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.

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

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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 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

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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 2009, and, as of the date of this Report, we are not aware of any environmental issues or claims that will require material capital expenditures in the future. 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;

•  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

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

Natural Gas Gathering.  Section 1(b) of the Natural Gas Act (“NGA”), exempts natural gas gathering facilities from the jurisdiction of the Federal Energy Regulatory Commission (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. Our gathering operations could be adversely affected should they become subject to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Sales of Natural Gas.  The price at which we buy and sell natural gas 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.

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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 and New Mexico impose 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 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, 2009, we had a staff of 421 persons, including 35 engineers, 18 geologists, and 13 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

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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 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 officer and principal financial officer. 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.

Our 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.

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.

Failure to complete the Merger or delays in completing the Merger could negatively affect our stock price and future business and operations.

There is no assurance that we will be able to consummate the Merger. If the Merger is not completed for any reason, we may be subject to a number of risks, including the following:

•  we will not realize the benefits expected from the Merger, including a potentially enhanced financial and competitive position;

•  the current market price of our common stock may reflect a market assumption that the Merger will occur and a failure to complete the Merger could result in a negative perception by the stock market of us generally and a resulting decline in the market price of our common stock; and

•  certain costs relating to the Merger, including certain investment banking, financing, legal, and accounting fees and expenses, must be paid even if the Merger is not completed, and we may be required to pay substantial fees to Denbury if the Merger Agreement is terminated under specified circumstances.

Delays in completing the Merger could exacerbate uncertainties concerning the effect of the Merger, which may have an adverse effect on the business following the Merger and could defer or detract from the realization of the benefits expected to result from the Merger.

There may be substantial disruption to our business and distraction of our management and employees as a result of the Merger.

There may be substantial disruption to our business and distraction of our management and employees from day-to-day operations because matters related to the Merger may require substantial commitments of time and resources, which could otherwise have been devoted to other opportunities that could have been beneficial to us.

Business uncertainties and contractual restrictions while the Merger is pending may have an adverse effect on us.

Uncertainty about the effect of the Merger on employees, suppliers, partners, regulators, and customers may have an adverse effect on us. These uncertainties may impair our ability to attract, retain, and motivate key personnel until the Merger is consummated and could cause suppliers, customers, and others that deal with us to defer purchases or other decisions concerning us or seek to change existing business relationships with us. In addition, the Merger Agreement restricts us from making certain acquisitions and taking other specified actions without Denbury’s approval. These restrictions could prevent us from pursuing attractive business opportunities that may arise prior to the completion of the Merger.

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

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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.

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 led to an extended worldwide economic slowdown in 2008 and 2009, which is expected to continue into 2010. The slowdown in economic activity has reduced worldwide demand for energy and resulted in lower oil and natural gas prices.

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

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

•  reduce the amount of cash flow available for capital expenditures, 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.

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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 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.

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.

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.

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.

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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 2010. 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 in 2011 and 2012. After 2010, 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, 2009, we were entitled to future payments of approximately $61.0 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.

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, net 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

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on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Developing and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations.

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. 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;

•  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

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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.

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.

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 with proved reserves, our total 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;

•  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 under our revolving credit facility to finance acquisitions;

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

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•  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 oil and natural gas properties, 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 32 percent of our proved reserves as of December 31, 2009 and accounted for 25 percent of our 2009 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.

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

For 2009, our largest purchaser was Eighty-Eight Oil, which accounted for 18 percent of our total sales of production. If customer, or any other significant customer, were to reduce the production purchased from us, our revenue and cash available for distribution will decline to the extent we are not able to find new customers for our production.

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 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

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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 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, 2009, we had total consolidated debt of $1.2 billion and $889.7 million of consolidated available borrowing capacity under our revolving credit facilities. 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;

•  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 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 affect 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

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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 revolving credit facilities have substantial restrictions and financial covenants that may restrict our business and financing activities.

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

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

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

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

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

We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets due to 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 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.

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

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

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

Other companies operated approximately 21 percent of our properties (measured by total reserves) and approximately 44 percent of our wells as of December 31, 2009. 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.

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 “Items 1 and 2. Business and Properties — Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.

Possible regulations related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to the warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of refined oil products and natural gas, are examples of greenhouse gases. The U.S. Congress is considering climate-related legislation to reduce emissions of greenhouse gases. In addition, at least 20 states have developed measures to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissions inventories and/or regional greenhouse gas cap and trade programs. The EPA has adopted regulations requiring reporting of greenhouse gas emissions from certain facilities and is considering additional regulation of greenhouse gases as “air pollutants” under the CAA. Passage of climate change legislation or other regulatory initiatives by

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Congress or various states, or the adoption of regulations by the EPA or analogous state agencies, that regulate or restrict emissions of greenhouse gases (including methane or carbon dioxide) in areas in which we conduct business could have an adverse effect our operations and the demand for oil and natural gas.

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 could be adversely affected.

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 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.

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. We intend to finance these capital expenditures through operating cash flows. However,

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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.

The loss of key personnel could adversely affect our business.

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.

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PART II

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

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

	High		Low
2009
Quarter ended December 31	$	49.00	$	35.64
Quarter ended September 30	$	39.93	$	25.53
Quarter ended June 30	$	39.01	$	22.30
Quarter ended March 31	$	32.11	$	17.04
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

On February 17, 2010, the closing sales price of our common stock as reported by the NYSE was $50.03 per share and we had approximately 418 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, 2009, we had repurchased and retired 620,265 shares of our outstanding common stock for approximately $17.2 million, or an average price of $27.68 per share, under the share repurchase program. During the fourth quarter of 2009, we did not repurchase any shares of our outstanding common stock under the share repurchase program. As of December 31, 2009, approximately $22.8 million of our common stock remained authorized for repurchase.

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 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.

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Stock Performance Graph

The following graph compares our cumulative total stockholder return during the period from January 1, 2005 to December 31, 2009 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, 2005 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, 2005 Among Encore
Acquisition Company, the Standard & Poor’s 500 Index, and the
Independent Oil and Gas Index

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ITEM 6.   SELECTED FINANCIAL DATA

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

	Year Ended December 31,(a)
	2009			2008			2007			2006			2005
	(In thousands, except per share amounts)
Consolidated Statements of Operations Data:
Revenues(b):
Oil	$	549,391		$	897,443		$	562,817		$	346,974		$	307,959
Natural gas		131,185			227,479			150,107			146,325			149,365
Marketing(c)		4,840			10,496			42,021			147,563			—
Total revenues		685,416			1,135,418			754,945			640,862			457,324
Expenses:
Production:
Lease operating(d)		165,062			175,115			143,426			98,194			69,744
Production, ad valorem, and severance taxes		69,539			110,644			74,585			49,780			45,601
Depletion, depreciation, and amortization		290,776			228,252			183,980			113,463			85,627
Impairment of long-lived assets(e)		9,979			59,526			—			—			—
Exploration		52,488			39,207			27,726			30,519			14,443
General and administrative(d)		54,024			48,421			39,124			23,194			17,268
Marketing(c)		3,994			9,570			40,549			148,571			—
Derivative fair value loss (gain)(f)		59,597			(346,236	)		112,483			(24,388	)		5,290
Loss on early redemption of debt(g)		—			—			—			—			19,477
Provision for doubtful accounts		7,686			1,984			5,816			1,970			231
Other operating		25,761			12,975			17,066			8,053			9,254
Total expenses		738,906			339,458			644,755			449,356			266,935
Operating income (loss)		(53,490	)		795,960			110,190			191,506			190,389
Other income (expenses):
Interest		(79,017	)		(73,173	)		(88,704	)		(45,131	)		(34,055	)
Other		2,447			3,898			2,667			1,429			1,039
Total other expenses		(76,570	)		(69,275	)		(86,037	)		(43,702	)		(33,016	)
Income (loss) before income taxes		(130,060	)		726,685			24,153			147,804			157,373
Income tax benefit (provision)		32,173			(241,621	)		(14,476	)		(55,406	)		(53,948	)
Consolidated net income (loss)		(97,887	)		485,064			9,677			92,398			103,425
Less: net loss (income) attributable to noncontrolling interest		16,752			(54,252	)		7,478			—			—
Net income (loss) attributable to EAC stockholders	$	(81,135	)	$	430,812		$	17,155		$	92,398		$	103,425
Net income (loss) per common share:
Basic	$	(1.54	)	$	8.10		$	0.32		$	1.75		$	2.10
Diluted	$	(1.54	)	$	8.01		$	0.31		$	1.74		$	2.07
Weighted average common shares outstanding:
Basic		52,634			52,270			53,170			51,865			48,682
Diluted		52,634			52,866			53,629			52,356			49,303

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	Year Ended December 31,(a)
	2009			2008			2007			2006			2005
	(In thousands, except per unit amounts)
Total Production Volumes:
Oil (Bbls)		10,016			10,050			9,545			7,335			6,871
Natural gas (Mcf)		33,919			26,374			23,963			23,456			21,059
Combined (BOE)		15,669			14,446			13,539			11,244			10,381
Average Realized Prices:
Oil ($/Bbl)	$	54.85		$	89.30		$	58.96		$	47.30		$	44.82
Natural gas ($/Mcf)		3.87			8.63			6.26			6.24			7.09
Combined ($/BOE)		43.43			77.87			52.66			43.87			44.05
Average Costs per BOE:
Lease operating(d)	$	10.53		$	12.12		$	10.59		$	8.73		$	6.72
Production, ad valorem, and severance taxes		4.44			7.66			5.51			4.43			4.39
Depletion, depreciation, and amortization		18.56			15.80			13.59			10.09			8.25
Impairment of long-lived assets(e)		0.64			4.12			—			—			—
Exploration		3.35			2.71			2.05			2.71			1.39
General and administrative(d)		3.45			3.35			2.89			2.06			1.67
Derivative fair value loss (gain)(f)		3.80			(23.97	)		8.31			(2.17	)		0.51
Provision for doubtful accounts		0.49			0.14			0.43			0.18			0.02
Other operating		1.64			0.90			1.26			0.71			0.89
Marketing, net of revenues(c)		(0.05	)		(0.06	)		(0.11	)		0.09			—
Consolidated Statements of Cash Flows Data:
Cash provided by (used in):
Operating activities	$	745,677		$	663,237		$	319,707		$	297,333		$	292,269
Investing activities		(769,430	)		(728,346	)		(929,556	)		(397,430	)		(573,560	)
Financing activities		35,672			65,444			610,790			99,206			281,842

	As of December 31,(a)
	2009			2008		2007			2006			2005
	(In thousands)
Proved Reserves:
Oil (Bbls)		147,094			134,452		188,587			153,434			148,387
Natural gas (Mcf)		439,072			307,520		256,447			306,764			283,865
Combined (BOE)		220,273			185,705		231,328			204,561			195,698
Consolidated Balance Sheets Data:
Working capital	$	(62,854	)	$	188,678	$	(16,220	)	$	(40,745	)	$	(56,838	)
Total assets		3,663,961			3,633,195		2,784,561			2,006,900			1,705,705
Long-term debt		1,214,097			1,319,811		1,120,236			661,696			673,189
Equity		1,630,833			1,483,248		1,070,689			816,865			546,781

(a)

We acquired certain oil and natural gas properties and related assets in the Mid-Continent and east Texas regions in August 2009. We acquired certain oil and natural gas properties and related assets in the Big Horn and Williston Basins in March 2007 and April 2007, respectively. We also acquired Crusader Energy Corporation in October 2005. The operating results of these acquisitions are included in our Consolidated Statements of Operations from the date of acquisition forward. We disposed of certain oil and natural gas properties and related assets in the Mid-Continent in June 2007. The operating results of this disposition are included in our Consolidated Statements of Operations through the date of disposition.

(b)

For 2009, 2008, 2007, 2006, and 2005, we reduced oil and natural gas revenues for net profits interests owned by others by $31.8 million, $56.5 million, $32.5 million, $23.4 million, and $21.2 million, respectively.

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(c)	In 2006, we began purchasing third-party oil Bbls from a counterparty other than to whom the Bbls were sold for aggregation and sale with our own equity production in various markets. These purchases assisted us in marketing our production by decreasing our dependence on individual markets. These activities allowed us to aggregate larger volumes, facilitated our efforts to maximize the prices we received for production, provided for a greater allocation of future pipeline capacity in the event of curtailments, and enabled us to reach other markets. In 2007, we discontinued the purchase of oil from third party companies as market conditions changed and pipeline space was gained. Implementing this change allowed us to focus on the marketing of our own oil production, leveraging newly gained pipeline space, and delivering oil to various newly developed markets in an effort to maximize the value of the oil at the wellhead. In March 2007, ENP acquired a natural gas pipeline as part of the Big Horn Basin asset acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet to the pipeline and resold downstream to various local and off-system markets.
(d)	On January 1, 2006, we adopted the provisions of ASC 718, 505-50, and 260-10-60-1A (formerly SFAS No. 123R, “Share-Based Payment”). Due to the adoption of ASC 718, 505-50, and 260-10-60-1A, non-cash equity-based compensation expense for 2005 has been reclassified to allocate the amount to the same respective income statement lines as the respective employees’ cash compensation. In 2005, this resulted in increases in LOE of $1.3 million ($0.13 per BOE) and in general and administrative (“G&A”) expense of $2.6 million ($0.25 per BOE).
(e)	During 2009 and 2008, circumstances indicated that the carrying value of certain of our oil and natural gas properties in the Tuscaloosa Marine Shale may not be recoverable. For the proved oil and natural gas property costs, we compared the assets’ carrying amounts to the undiscounted expected future net cash flows, which indicated a need for an impairment charge. We then compared the net carrying amounts of the impaired assets to their estimated fair value, which resulted in a pretax write-down of the value of oil and natural gas properties. For the unproved acreage costs, we recorded a valuation allowance to reflect the portion of the property costs that we believe will not be transferred to proved properties over the remaining life of the lease. The impairment of proved oil and natural gas properties and unproved acreage in the Tuscaloosa Marine Shale totaled $10.0 million and $59.5 million during 2009 and 2008, respectively. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes, discounted to a present value.
(f)	During July 2006, we elected to discontinue hedge accounting prospectively for all of our remaining commodity derivative contracts which were previously accounted for as hedges. From that point forward, all mark-to-market gains or losses on all commodity derivative contracts are recorded in “Derivative fair value loss (gain)” while in periods prior to that point, only the ineffective portions of commodity derivative contracts which were designated as hedges were recorded in “Derivative fair value loss (gain).”
(g)	In 2005, we recorded a $19.5 million loss on early redemption of debt related to the redemption premium and the expensing of unamortized debt issuance costs of our 83/8% Senior Subordinated Notes due 2012. We redeemed all $150 million of such notes with proceeds received from the issuance of $300 million of our 6.0% Senior Subordinated Notes due 2015.

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

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

Introduction

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

•  Overview of Business

•  2009 Highlights

•  Results of Operations

— Comparison of 2009 to 2008

— Comparison of 2008 to 2007

•  Capital Commitments, Capital Resources, and Liquidity

•  Changes in Prices

•  Critical Accounting Policies and Estimates

•  New Accounting Pronouncements

•  Information Concerning Forward-Looking Statements

Overview of Business

We are a Delaware corporation engaged in the acquisition, development, exploitation, exploration, and production of oil and natural gas reserves from onshore fields in the United States. Our business strategies include:

•  Maintaining an active development program to maximize existing reserves and production;

•  Utilizing EOR techniques to maximize existing reserves and production;

•  Expanding our reserves, production, and development inventory through a disciplined acquisition program;

•  Exploring for reserves; and

•  Operating in a cost effective, efficient, and safe manner.

As previously discussed, on October 31, 2009, we entered into the Merger Agreement with Denbury pursuant to which we have agreed to merge with and into Denbury, with Denbury as the surviving entity. The Merger Agreement, which was unanimously approved by our Board and by Denbury’s Board of Directors, provides for Denbury’s acquisition of all of our issued and outstanding shares of common stock in a transaction valued at approximately $4.5 billion, including the assumption of debt and the value of our interest

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in ENP. We expect to complete the Merger during the first quarter of 2010, although completion by any particular date cannot be assured.

At December 31, 2009, our oil and natural gas properties had estimated total proved reserves of 147.1 MMBbls of oil and 439.1 Bcf of natural gas, based on 2009 12-month average market prices of $61.18 per Bbl of oil and $3.83 per Mcf of natural gas. On a BOE basis, our proved reserves were 220.3 MMBOE at December 31, 2009, of which approximately 67 percent was oil, approximately 80 percent was proved developed, and approximately 20 proved undeveloped.

Our financial results and ability to generate cash depend upon many factors, particularly the price of oil and natural gas. Average NYMEX prices deteriorated significantly in 2009. Our oil wellhead differentials to NYMEX deteriorated slightly in 2009 as we realized 89 percent of the average NYMEX oil price, as compared to 90 percent in 2008. Our natural gas wellhead differentials to NYMEX improved in 2009 as we realized 97 percent of the average NYMEX natural gas price, as compared to 95 percent in 2008. Commodity prices are influenced by many factors that are outside of our control. We cannot accurately predict future commodity prices. For this reason, we attempt to mitigate the effect of commodity price risk by entering into commodity derivative contracts for a portion of our forecasted production. For a discussion of factors that influence commodity prices and risks associated with our commodity derivative contracts, please read “Item 1A. Risk Factors.”

2009 Highlights

Our financial and operating results for 2009 included the following:

•  Our average daily production volumes increased nine percent to 42,929 BOE/D as compared to 39,470 BOE/D in 2008. Oil represented 64 percent and 70 percent of our total production volumes in 2009 and 2008, respectively.

•  We invested $706.5 million in oil and natural gas activities, of which $286.9 million was invested in development, exploitation, and exploration activities, yielding 112 gross (42.3 net) productive wells, and $419.5 million was invested in acquisitions, primarily related to our EXCO asset acquisition.

•  In September, we issued 2,750,000 shares of our common stock at a price to the public of $37.40 per common share. The net proceeds of approximately $100.6 million were used to reduce outstanding borrowings under our revolving credit facility.

•  In August, we acquired certain oil and natural gas properties and related assets in the Mid-Continent and East Texas from EXCO for approximately $357.4 million in cash (including a deposit of $37.5 million made in June 2009).

•  In August, we sold the Rockies and Permian Basin Assets to ENP for approximately $179.6 million in cash.

•  In June, we sold the Williston Basin Assets to ENP for approximately $25.2 million in cash.

•  In April, we issued $225 million of our 9.5% Senior Subordinated Notes due 2016. We used the net proceeds of approximately $202.4 million to reduce outstanding borrowings under our revolving credit facility.

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

•  In January, we sold the Arkoma Basin Assets to ENP for approximately $46.4 million in cash.

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Results of Operations

Comparison of 2009 to 2008

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

	Year Ended December 31,					Increase/(Decrease)
	2009		2008			$			%
Revenues (in thousands):
Oil wellhead	$	549,391	$	900,300		$	(350,909	)
Oil commodity derivative contracts		—		(2,857	)		2,857
Total oil revenues	$	549,391	$	897,443		$	(348,052	)		(39	)%
Natural gas wellhead	$	131,185	$	227,479		$	(96,294	)		(42	)%
Combined wellhead	$	680,576	$	1,127,779		$	(447,203	)		(40	)%
Combined commodity derivative contracts		—		(2,857	)		2,857
Total combined oil and natural gas revenues	$	680,576	$	1,124,922		$	(444,346	)		(40	)%
Marketing		4,840		10,496			(5,656	)		(54	)%
Total revenues	$	685,416	$	1,135,418		$	(450,002	)		(40	)%
Average realized prices:
Oil wellhead ($/Bbl)	$	54.85	$	89.58		$	(34.73	)
Oil commodity derivative contracts ($/Bbl)		—		(0.28	)		0.28
Total oil revenues ($/Bbl)	$	54.85	$	89.30		$	(34.45	)		(39	)%
Natural gas wellhead ($/Mcf)	$	3.87	$	8.63		$	(4.76	)		(55	)%
Combined wellhead ($/BOE)	$	43.43	$	78.07		$	(34.64	)
Combined commodity derivative contracts ($/BOE)		—		(0.20	)		0.20
Total combined oil and natural gas revenues ($/BOE)	$	43.43	$	77.87		$	(34.44	)		(44	)%
Total production volumes:
Oil (MBbls)		10,016		10,050			(34	)		0	%
Natural gas (MMcf)		33,919		26,374			7,545			29	%
Combined (MBOE)		15,669		14,446			1,223			8	%
Average daily production volumes:
Oil (Bbl/D)		27,441		27,459			(18	)		0	%
Natural gas (Mcf/D)		92,928		72,060			20,868			29	%
Combined (BOE/D)		42,929		39,470			3,459			9	%
Average NYMEX prices:
Oil (per Bbl)	$	61.95	$	99.75		$	(37.80	)		(38	)%
Natural gas (per Mcf)	$	3.99	$	9.04		$	(5.05	)		(56	)%

Oil revenues decreased 39 percent from $897.4 million in 2008 to $549.4 million in 2009 as a result of a $34.73 per Bbl decrease in our average realized oil price and a 34 MBbl decrease in our oil production volumes. Our lower average realized oil price decreased oil revenues by approximately $347.8 million and was primarily due to a lower average NYMEX price, which decreased from $99.75 per Bbl in 2008 to $61.95

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per Bbl in 2009. Our lower oil production volumes decreased oil revenues by approximately $3.1 million. Oil revenues in 2008 were also reduced by approximately $2.9 million, or $0.28 per Bbl, for oil derivative contracts previously designated as hedges. In 2009 and 2008, our average daily production volumes were decreased by 1,721 BOE/D and 1,530 BOE/D, respectively, for net profits interests related to our CCA properties, which reduced our oil wellhead revenues by $31.3 million and $55.3 million, respectively.

Natural gas revenues decreased 42 percent from $227.5 million in 2008 to $131.2 million in 2009 as a result of a $4.76 per Mcf decrease in our average realized natural gas price, partially offset by a 7,545 MMcf increase in natural gas production volumes. Our lower average realized natural gas price decreased natural gas revenues by approximately $161.4 million and was primarily due to a lower average NYMEX price, which decreased from $9.04 per Mcf in 2008 to $3.99 per Mcf in 2009. Our higher natural gas production volumes increased natural gas revenues by approximately $65.1 million was primarily the result of successful development programs in our Permian Basin and Mid-Continent regions and our acquisitions of properties from EXCO in August 2009.

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

	Year Ended December 31,
	2009			2008
Average oil wellhead ($/Bbl)	$	54.85		$	89.58
Average NYMEX ($/Bbl)	$	61.95		$	99.75
Differential to NYMEX	$	(7.10	)	$	(10.17	)
Average oil wellhead to NYMEX percentage		89	%		90	%
Average natural gas wellhead ($/Mcf)	$	3.87		$	8.63
Average NYMEX ($/Mcf)	$	3.99		$	9.04
Differential to NYMEX	$	(0.12	)	$	(0.41	)
Average natural gas wellhead to NYMEX percentage		97	%		95	%

Our average oil wellhead price as a percentage of the average NYMEX price was 89 percent in 2009 as compared to 90 percent in 2008.

Our average natural gas wellhead price as a percentage of the average NYMEX price was 97 percent in 2009 as compared to 95 percent in 2008.

Marketing revenues decreased 54 percent from $10.5 million in 2008 to $4.8 million in 2009 primarily as a result of a reduction in natural gas throughput in our Wildhorse pipeline and the decrease in natural gas prices. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

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Expenses.  The following table provides the components of our expenses for the periods indicated:

	Year Ended December 31,						Increase/(Decrease)
	2009			2008			$			%
Expenses (in thousands):
Production:
Lease operating	$	165,062		$	175,115		$	(10,053	)
Production, ad valorem, and severance taxes		69,539			110,644			(41,105	)
Total production expenses		234,601			285,759			(51,158	)		(18	)%
Other:
Depletion, depreciation, and amortization		290,776			228,252			62,524
Impairment of long-lived assets		9,979			59,526			(49,547	)
Exploration		52,488			39,207			13,281
General and administrative		54,024			48,421			5,603
Marketing		3,994			9,570			(5,576	)
Derivative fair value loss (gain)		59,597			(346,236	)		405,833
Provision for doubtful accounts		7,686			1,984			5,702
Other operating		25,761			12,975			12,786
Total operating		738,906			339,458			399,448			118	%
Interest		79,017			73,173			5,844
Income tax provision (benefit)		(32,173	)		241,621			(273,794	)
Total expenses	$	785,750		$	654,252		$	131,498			20	%
Expenses (per BOE):
Production:
Lease operating	$	10.53		$	12.12		$	(1.59	)
Production, ad valorem, and severance taxes		4.44			7.66			(3.22	)
Total production expenses		14.97			19.78			(4.81	)		(24	)%
Other:
Depletion, depreciation, and amortization		18.56			15.80			2.76
Impairment of long-lived assets		0.64			4.12			(3.48	)
Exploration		3.35			2.71			0.64
General and administrative		3.45			3.35			0.10
Marketing		0.25			0.66			(0.41	)
Derivative fair value loss (gain)		3.80			(23.97	)		27.77
Provision for doubtful accounts		0.49			0.14			0.35
Other operating		1.64			0.90			0.74
Total operating		47.15			23.49			23.66			101	%
Interest		5.04			5.07			(0.03	)
Income tax provision (benefit)		(2.05	)		16.73			(18.78	)
Total expenses	$	50.14		$	45.29		$	4.85			11	%

Production expenses.  Total production expenses decreased 18 percent from $285.8 million in 2008 to $234.6 million in 2009. Our production margin decreased 47 percent from $842.0 million in 2008 to $446.0 million in 2009. Total oil and natural gas wellhead revenues per BOE decreased by 44 percent and

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ENCORE ACQUISITION COMPANY

total production expenses per BOE decreased by 24 percent. On a per BOE basis, our production margin decreased 51 percent to $28.46 per BOE in 2009 as compared to $58.29 per BOE in 2008.

Production expense attributable to LOE decreased $10.1 million from $175.1 million in 2008 to $165.1 million in 2009 as a result of a $1.59 decrease in the average per BOE rate, partially offset by higher production volumes. Our lower average LOE per BOE rate decreased LOE by approximately $24.9 million and was primarily due to decreases in natural gas prices resulting in lower electricity costs and gas plant fuel costs and lower prices paid to oilfield service companies and suppliers. Our higher production volumes increased LOE by approximately $14.8 million.

Production expense attributable to production taxes decreased $41.1 million from $110.6 million in 2008 to $69.5 million in 2009 primarily due to lower wellhead revenues, which exclude the effects of commodity derivative contracts. As a percentage of wellhead revenues, production taxes increased to 10.2 percent in 2009 as compared to 9.8 percent in 2008 primarily due to higher ad valorem taxes, which are based on production volumes as opposed to a percentage of wellhead revenues.

Depletion, depreciation, and amortization (“DD&A”) expense.  DD&A expense increased $62.5 million from $228.3 million in 2008 to $290.8 million in 2009 as a result of a $2.76 increase in the per BOE rate and higher production volumes. Our higher average DD&A per BOE rate increased DD&A expense by approximately $43.2 million and was primarily due to the decrease in our proved reserves at the beginning of 2009 as a result of lower average commodity prices, partially offset by reserves added during 2009 through our EXCO asset acquisition. Our higher production volumes increased DD&A expense by approximately $19.3 million.

Impairment of long-lived assets.  During 2009 and 2008, circumstances indicated that the carrying value of certain of our oil and natural gas properties in the Tuscaloosa Marine Shale may not be recoverable. For the proved oil and natural gas property costs, we compared the assets’ carrying value to the undiscounted expected future net cash flows, which indicated a need for an impairment charge. We then compared the net book value of the impaired assets to their estimated discounted value, which resulted in a pretax write-down of the value of oil and natural gas properties. For the unproved acreage costs, we recorded a valuation allowance to reflect the portion of the property costs that we believe will not be transferred to proved properties over the remaining life of the lease. The impairment of proved oil and natural gas properties and unproved acreage in the Tuscaloosa Marine Shale totaled of $10.0 million and $59.5 million during 2009 and 2008, respectively. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes, discounted to a present value.

As of December 31, 2009, we do not have any unproved oil and natural gas properties in the Tuscaloosa Marine Shale whose carrying value has not been written down to zero.

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ENCORE ACQUISITION COMPANY

Exploration expense.  Exploration expense increased $13.3 million from $39.2 million in 2008 to $52.5 million in 2009. During 2009, we expensed 5.6 net exploratory dry holes totaling $25.4 million. During 2008, we expensed 3.8 net exploratory dry holes totaling $14.7 million. Impairment of unproved acreage increased $5.1 million from $20.2 million in 2008 to $25.3 million in 2009, primarily due to our larger unproved property base, as well as the impairment of certain acreage through the normal course of evaluation. The following table provides the components of exploration expenses for the periods indicated:

	Year Ended December 31,				Increase
	2009		2008		(Decrease)
	(In thousands)
Dry holes	$	25,407	$	14,683	$	10,724
Geological and seismic		1,022		2,851		(1,829	)
Delay rentals		773		1,482		(709	)
Impairment of unproved acreage		25,286		20,191		5,095
Total	$	52,488	$	39,207	$	13,281

G&A expense.  G&A expense increased $5.6 million from $48.4 million in 2008 to $54.0 million in 2009 primarily due to retention bonuses paid in August 2009 related to our 2008 strategic alternatives process and the expensing of transaction costs related to our EXCO asset acquisition.

Marketing expense.  Marketing expense decreased $5.6 million from $9.6 million in 2008 to $4.0 million in 2009 as a result of a reduction in natural gas throughput in our Wildhorse pipeline and the decrease in natural gas prices. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

Derivative fair value loss (gain).  During 2009, we recorded a $59.6 million derivative fair value loss as compared to a $346.2 million derivative fair value gain in 2008, the components of which were as follows:

	Year Ended December 31,						Increase/
	2009			2008			(Decrease)
	(In thousands)
Ineffectiveness	$	2		$	372		$	(370	)
Mark-to-market loss (gain)		350,365			(365,495	)		715,860
Premium amortization		98,395			62,352			36,043
Settlements		(389,165	)		(43,465	)		(345,700	)
Total derivative fair value loss (gain)	$	59,597		$	(346,236	)	$	405,833

Provision for doubtful accounts.  In 2009 and 2008, we recorded a provision for doubtful accounts of $7.7 million and $2.0 million, respectively, primarily for the payout allowance related to the ExxonMobil joint development agreement.

Other operating expense.  Other operating expense increased $12.8 million from $13.0 million in 2008 to $25.8 million in 2009, primarily due to a $6.5 million adjustment to the carrying value of pipe and other tubular inventory whose market value had declined below cost and higher gathering and transportation fees.

Interest expense.  Interest expense increased $5.8 million from $73.2 million in 2008 to $79.0 million in 2009 primarily due to the issuance of our 9.5% Notes in April 2009. The weighted average interest rate for all long-term debt for 2009 was 5.8 percent as compared to 5.6 percent for 2008.

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ENCORE ACQUISITION COMPANY

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

	Year Ended December 31,				Increase/
	2009		2008		(Decrease)
	(In thousands)
6.25% Senior Subordinated Notes	$	9,751	$	9,727	$	24
6.0% Senior Subordinated Notes		18,585		18,550		35
9.5% Senior Subordinated Notes		15,999		—		15,999
7.25% Senior Subordinated Notes		11,005		10,996		9
Revolving credit facilities		18,253		31,038		(12,785	)
Other		5,424		2,862		2,562
Total	$	79,017	$	73,173	$	5,844

Income taxes.  In 2009, we recorded an income tax benefit of $32.2 million as compared to an income tax provision of $241.6 million in 2008. In 2009, we had a loss before income taxes of $130.1 million as compared to income before income taxes of $726.7 million in 2008. Our effective tax rate decreased to 24.7 percent in 2009 as compared to 33.2 percent in 2008 primarily due to the 2008 provision to return difference for the production activities deduction estimated at the end of 2008 due to a change in tax planning as a result of the monetization of hedges in the first quarter of 2009 and an increase in the effective state income tax rate due to changes in apportionment associated with our 2009 acquisitions.

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ENCORE ACQUISITION COMPANY

Comparison of 2008 to 2007

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

							Increase/
	Year Ended December 31,						(Decrease)
	2008			2007			$			%
Revenues (in thousands):
Oil wellhead	$	900,300		$	606,112		$	294,188
Oil commodity derivative contracts		(2,857	)		(43,295	)		40,438
Total oil revenues	$	897,443		$	562,817		$	334,626			59	%
Natural gas wellhead	$	227,479		$	160,399		$	67,080
Natural gas commodity derivative contracts		—			(10,292	)		10,292
Total natural gas revenues	$	227,479		$	150,107		$	77,372			52	%
Combined wellhead	$	1,127,779		$	766,511		$	361,268
Combined commodity derivative contracts		(2,857	)		(53,587	)		50,730
Total combined oil and natural gas revenues		1,124,922			712,924			411,998			58	%
Marketing		10,496			42,021			(31,525	)		(75	)%
Total revenues	$	1,135,418		$	754,945		$	380,473			50	%
Average realized prices:
Oil wellhead ($/Bbl)	$	89.58		$	63.50		$	26.08
Oil commodity derivative contracts ($/Bbl)		(0.28	)		(4.54	)		4.26
Total oil revenues ($/Bbl)	$	89.30		$	58.96		$	30.34			51	%
Natural gas wellhead ($/Mcf)	$	8.63		$	6.69		$	1.94
Natural gas commodity derivative contracts ($/Mcf)		—			(0.43	)		0.43
Total natural gas revenues ($/Mcf)	$	8.63		$	6.26		$	2.37			38	%
Combined wellhead ($/BOE)	$	78.07		$	56.62		$	21.45
Combined commodity derivative contracts ($/BOE)		(0.20	)		(3.96	)		3.76
Total combined oil and natural gas revenues ($/BOE)	$	77.87		$	52.66		$	25.21			48	%
Total production volumes:
Oil (MBbls)		10,050			9,545			505			5	%
Natural gas (MMcf)		26,374			23,963			2,411			10	%
Combined (MBOE)		14,446			13,539			907			7	%
Average daily production volumes:
Oil (Bbl/D)		27,459			26,152			1,307			5	%
Natural gas (Mcf/D)		72,060			65,651			6,409			10	%
Combined (BOE/D)		39,470			37,094			2,376			6	%
Average NYMEX prices:
Oil (per Bbl)	$	99.75		$	72.45		$	27.30			38	%
Natural gas (per Mcf)	$	9.04		$	6.86		$	2.18			32	%

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ENCORE ACQUISITION COMPANY

Oil revenues increased 59 percent from $562.8 million in 2007 to $897.4 million in 2008 as a result of an increase in our average realized oil price and an increase in oil production volumes of 505 MBbls. The increase in oil production volumes contributed approximately $32.1 million in additional oil revenues and was primarily the result of a full year of production from our Big Horn Basin acquisition in March 2007 and our Williston Basin acquisition in April 2007, as well as our development program in the Bakken.

Our average realized oil price increased $30.34 per Bbl from 2007 to 2008 primarily as a result of an increase in our average realized oil wellhead price, which increased oil revenues by approximately $262.1 million, or $26.08 per Bbl. Our average realized oil wellhead price increased primarily as a result of the increase in the average NYMEX price from $72.45 per Bbl in 2007 to $99.75 per Bbl in 2008.

During July 2006, we elected to discontinue hedge accounting prospectively for all remaining commodity derivative contracts which were previously accounted for as hedges. While this change had no effect on our cash flows, results of operations are affected by mark-to-market gains and losses, which fluctuate with the changes in oil and natural gas prices. As a result, oil revenues for 2008 included amortization of net losses on certain commodity derivative contracts that were previously designated as hedges of approximately $2.9 million, or $0.28 per Bbl, while 2007 included approximately $43.3 million, or $4.54 per Bbl, of net losses.

Our average daily production volumes were decreased by 1,530 BOE/D and 1,466 BOE/D in 2008 and 2007, respectively, for net profits interests related to our CCA properties, which reduced our oil wellhead revenues by $55.3 million and $31.9 million in 2008 and 2007, respectively.

Natural gas revenues increased 52 percent from $150.1 million in 2007 to $227.5 million in 2008 as a result of an increase in our average realized natural gas price and an increase in natural gas production volumes of 2,411 MMcf. The increase in natural gas production volumes contributed approximately $16.1 million in additional natural gas revenues and was primarily the result of our development program in our Permian Basin and Mid-Continent regions.

Our average realized natural gas price increased $2.37 per Mcf from 2007 to 2008 primarily as a result of an increase in our average realized natural gas wellhead price, which increased natural gas revenues by approximately $50.9 million, or $1.94 per Mcf. Our average realized natural gas wellhead price increased primarily as a result of the increase in the average NYMEX price from $6.86 per Mcf in 2007 to $9.04 per Mcf in 2008. In addition, as a result of our discontinuance of hedge accounting in July 2006, natural gas revenues for 2007 included amortization of net losses on certain commodity derivative contracts that were previously designated as hedges of approximately $10.3 million, or $0.43 per Mcf.

The table below shows the relationship between our oil and natural gas wellhead prices as a percentage of average NYMEX prices for the periods indicated:

	Year Ended December 31,
	2008			2007
Average oil wellhead ($/Bbl)	$	89.58		$	63.50
Average NYMEX ($/Bbl)	$	99.75		$	72.45
Differential to NYMEX	$	(10.17	)	$	(8.95	)
Average oil wellhead to NYMEX percentage		90	%		88	%
Average natural gas wellhead ($/Mcf)	$	8.63		$	6.69
Average NYMEX ($/Mcf)	$	9.04		$	6.86
Differential to NYMEX	$	(0.41	)	$	(0.17	)
Average natural gas wellhead to NYMEX percentage		95	%		98	%

Our average oil wellhead price as a percentage of the average NYMEX price was 90 percent in 2008 as compared to 88 percent in 2007. Our average natural gas wellhead price as a percentage of the average NYMEX price was 95 percent in 2008 as compared to 98 percent in 2007.

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ENCORE ACQUISITION COMPANY

Marketing revenues decreased 75 percent from $42.0 million in 2007 to $10.5 million in 2008 primarily as a result of discontinuing the purchase of oil from third party companies as market conditions changed and historical pipeline space was realized. Implementing this change allowed us to focus on the marketing of our own production, leveraging newly gained pipeline space, and delivering oil to various newly developed markets in an effort to maximize the value of the oil at the wellhead. In March 2007, ENP acquired a natural gas pipeline from Anadarko as part of the Big Horn Basin asset acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet to the pipeline and resold downstream to various local and off-system markets.

Expenses.  The following table provides the components of our expenses for the periods indicated:

						Increase/
	Year Ended December 31,					(Decrease)
	2008			2007		$			%
Expenses (in thousands):
Production:
Lease operating	$	175,115		$	143,426	$	31,689
Production, ad valorem, and severance taxes		110,644			74,585		36,059
Total production expenses		285,759			218,011		67,748			31	%
Other:
Depletion, depreciation, and amortization		228,252			183,980		44,272
Impairment of long-lived assets		59,526			—		59,526
Exploration		39,207			27,726		11,481
General and administrative		48,421			39,124		9,297
Marketing		9,570			40,549		(30,979	)
Derivative fair value loss (gain)		(346,236	)		112,483		(458,719	)
Provision for doubtful accounts		1,984			5,816		(3,832	)
Other operating		12,975			17,066		(4,091	)
Total operating		339,458			644,755		(305,297	)		(47	)%
Interest		73,173			88,704		(15,531	)
Income tax provision		241,621			14,476		227,145
Total expenses	$	654,252		$	747,935	$	(93,683	)		(13	)%
Expenses (per BOE):
Production:
Lease operating	$	12.12		$	10.59	$	1.53
Production, ad valorem, and severance taxes		7.66			5.51		2.15
Total production expenses		19.78			16.10		3.68			23	%
Other:
Depletion, depreciation, and amortization		15.80			13.59		2.21
Impairment of long-lived assets		4.12			—		4.12
Exploration		2.71			2.05		0.66
General and administrative		3.35			2.89		0.46
Marketing		0.66			2.99		(2.33	)
Derivative fair value loss (gain)		(23.97	)		8.31		(32.28	)
Provision for doubtful accounts		0.14			0.43		(0.29	)
Other operating		0.90			1.26		(0.36	)
Total operating		23.49			47.62		(24.13	)		(51	)%
Interest		5.07			6.55		(1.48	)
Income tax provision		16.73			1.07		15.66
Total expenses	$	45.29		$	55.24	$	(9.95	)		(18	)%

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ENCORE ACQUISITION COMPANY

Production expenses.  Total production expenses increased 31 percent from $218.0 million in 2007 to $285.8 million in 2008. Our production margin increased 54 percent to $842.0 million as compared to $548.5 million in 2007. Total oil and natural gas wellhead revenues per BOE increased by 38 percent while total production expenses per BOE increased by 23 percent. On a per BOE basis, our production margin increased 44 percent to $58.29 per BOE as compared to $40.52 per BOE for 2007.

Production expense attributable to LOE increased $31.7 million from $143.4 million in 2007 to $175.1 million in 2008 as a result of a $1.53 increase in the average per BOE rate, which contributed approximately $22.1 million of additional LOE, and an increase in production volumes, which contributed approximately $9.6 million of additional LOE. The increase in our average LOE per BOE rate was attributable to:

•  increases in prices paid to oilfield service companies and suppliers;

•  increases in natural gas prices resulting in higher electricity costs and gas plant fuel costs;

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

•  an increase of approximately $4.7 million ($0.32 per BOE) for retention bonuses paid in August 2008 and approximately $4.1 million ($0.28 per BOE) for retention bonuses paid in August 2009, related to our strategic alternatives process.

Production expense attributable to production taxes increased $36.1 million from $74.6 million in 2007 to $110.6 million in 2008 primarily due to higher wellhead revenues, which exclude the effects of commodity derivative contracts. As a percentage of wellhead revenues, production taxes remained approximately constant at 9.8 percent in 2008 as compared to 9.7 percent in 2007.

DD&A expense.  DD&A expense increased $44.3 million from $184.0 million in 2007 to $228.3 million in 2008 as a result of a $2.21 increase in the per BOE rate, which contributed approximately $32.0 million of additional DD&A expense, and an increase in production volumes, which contributed approximately $12.3 million of additional DD&A expense. The increase in our average DD&A per BOE rate was attributable to higher costs incurred resulting from increases in rig rates, pipe costs, and acquisition costs and the decrease in our total proved reserves to 185.7 MMBOE as of December 31, 2008 as compared to 231.3 MMBOE as of December 31, 2007.

Impairment of long-lived assets.  During 2008, circumstances indicated that the carrying value of certain wells we drilled in the Tuscaloosa Marine Shale may not be recoverable. We compared the assets’ carrying value to the undiscounted expected future net cash flows, which indicated a need for an impairment charge. We then compared the net book value of the impaired assets to their estimated discounted value, which resulted in a pretax write-down of the value of proved oil and natural gas properties of $59.5 million. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes, discounted to a present value.

Exploration expense.  Exploration expense increased $11.5 million from $27.7 million in 2007 to $39.2 million in 2008. During 2008, we expensed 3.8 net exploratory dry holes totaling $14.7 million. During 2007, we expensed 2.6 net exploratory dry holes totaling $14.7 million. Impairment of unproved acreage increased $9.4 million from $10.8 million in 2007 to $20.2 million in 2008, primarily due to our larger

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unproved property base, as well as the impairment of certain acreage through the normal course of evaluation. The following table provides the components of exploration expenses for the periods indicated:

	Year Ended December 31,
	2008		2007		Increase
	(In thousands)
Dry holes	$	14,683	$	14,673	$	10
Geological and seismic		2,851		1,455		1,396
Delay rentals		1,482		784		698
Impairment of unproved acreage		20,191		10,814		9,377
Total	$	39,207	$	27,726	$	11,481

G&A expense.  G&A expense increased $9.3 million from $39.1 million in 2007 to $48.4 million in 2008, primarily due to:

•  a full year of ENP public entity expenses;

•  higher activity levels;

•  increased personnel costs due to intense competition for human resources within the industry; and

•  an increase of approximately $2.9 million for retention bonuses paid in August 2008 and approximately $2.8 million for retention bonuses paid in August 2009, related to our strategic alternatives process;

•  partially offset by a $3.1 million decrease in non-cash equity-based compensation.

Marketing expense.  Marketing expense decreased $31.0 million from $40.5 million in 2007 to $9.6 million in 2008 primarily as a result of discontinuing purchasing oil from third party companies as market conditions changed and historical pipeline space was realized. Implementing this change allowed us to focus on the marketing of our own production, leveraging newly gained pipeline space, and delivering oil to various newly developed markets in an effort to maximize the value of the oil at the wellhead. In March 2007, ENP acquired a natural gas pipeline from Anadarko as part of the Big Horn Basin asset acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet to the pipeline and resold downstream to various local and off-system markets.

Derivative fair value loss (gain).  During 2008, we recorded a $346.2 million derivative fair value gain as compared to a $112.5 million derivative fair value loss in 2007, the components of which were as follows:

	Year Ended
	December 31,					Increase/
	2008			2007		(Decrease)
	(In thousands)
Ineffectiveness	$	372		$	—	$	372
Mark-to-market loss (gain)		(365,495	)		36,272		(401,767	)
Premium amortization		62,352			41,051		21,301
Settlements		(43,465	)		35,160		(78,625	)
Total derivative fair value loss (gain)	$	(346,236	)	$	112,483	$	(458,719	)

The change in our derivative fair value loss (gain) was a result of the addition of commodity derivative contracts in the first part of 2008 when prices were high and the significant decrease in prices during the end of 2008, which favorably impacted the fair values of those contracts.

Provision for doubtful accounts.  In 2008 and 2007, we recorded a provision for doubtful accounts of $2.0 million and $5.8 million, respectively, primarily for the payout allowance related to the ExxonMobil joint development agreement.

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Other operating expense.  Other operating expense decreased $4.1 million from $17.1 million in 2007 to $13.0 million in 2008, primarily due to a $7.4 million loss on the sale of certain Mid-Continent properties in 2007, partially offset by a $3.4 million increase during 2008 in third-party transportation costs to move our production to markets outside the immediate area of production.

Interest expense.  Interest expense decreased $15.5 million from $88.7 million in 2007 to $73.2 million in 2008, primarily due to (1) the use of net proceeds from our Mid-Continent asset disposition and ENP’s IPO to reduce weighted average outstanding borrowings on our revolving credit facilities, (2) a reduction in LIBOR, and (3) our use of interest rate swaps to fix the rate on a portion of outstanding borrowings on ENP’s revolving credit facility. The weighted average interest rate for all long-term debt for 2008 was 5.6 percent as compared to 6.9 percent for 2007.

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

	Year Ended December 31,				Increase/
	2008		2007		(Decrease)
	(In thousands)
6.25% Senior Subordinated Notes	$	9,727	$	9,705	$	22
6.0% Senior Subordinated Notes		18,550		18,517		33
7.25% Senior Subordinated Notes		10,996		10,988		8
Revolving credit facilities		31,038		46,085		(15,047	)
Other		2,862		3,409		(547	)
Total	$	73,173	$	88,704	$	(15,531	)

Income taxes.  In 2008, we recorded an income tax provision of $241.6 million as compared to $14.5 million in 2007. In 2008, we had income before income taxes of $726.7 million as compared to $24.2 million in 2007. Our effective tax rate decreased to 33.2 percent in 2008 as compared to 59.9 percent in 2007 primarily due to the 2007 recognition of non-deductible deferred compensation.

Capital Commitments, Capital Resources, and Liquidity

Capital commitments.  Our primary uses of cash are:

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

•  Acquisitions of oil and natural gas properties;

•  Funding of working capital; and

•  Contractual obligations.

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

	Year Ended December 31,
	2009		2008		2007
	(In thousands)
Development and exploitation	$	121,259	$	362,609	$	270,161
Exploration		165,683		256,437		97,453
Total	$	286,942	$	619,046	$	367,614

Our development and exploitation expenditures primarily relate to drilling development and infill wells, workovers of existing wells, and field related facilities. Our development and exploitation capital for 2009

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yielded 57 gross (25.9 net) productive wells and one gross (1.0 net) dry holes. Our exploration expenditures primarily relate to drilling exploratory wells, seismic costs, delay rentals, and geological and geophysical costs. Our exploration capital for 2009 yielded 55 gross (16.4 net) productive wells and 7 gross (5.6 net) dry holes. Please read “Items 1 and 2. Business and Properties — Development Results” for a description of the areas in which we drilled wells during 2009.

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

	Year Ended December 31,
	2009		2008		2007
	(In thousands)
Acquisitions of proved property	$	402,457	$	28,840	$	796,239
Acquisitions of leasehold acreage		17,087		128,635		52,306
Total	$	419,544	$	157,475	$	848,545

In August 2009, we acquired certain oil and natural gas properties from EXCO for approximately $357.4 million in cash (including a deposit of $37.5 million made in June 2009). In May 2009, ENP acquired certain natural gas properties in the Vinegarone Field in Val Verde County, Texas from an independent energy company for approximately $27.5 million in cash. In April 2007, we acquired oil and natural gas properties in the Williston Basin for approximately $392.1 million. In March 2007, we and ENP acquired oil and natural gas properties in the Big Horn Basin, including properties in the Elk Basin and the Gooseberry fields, for approximately $393.6 million.

During 2009, our capital expenditures for leasehold acreage related to the acquisition of unproved acreage in various areas. During 2008, $45.2 million of our capital expenditures for leasehold acreage related to the exercise of preferential rights in the Haynesville area and the remainder related to the acquisition of unproved acreage in various areas. During 2007, $16.1 million of our capital expenditures for leasehold acreage related to the Williston Basin asset acquisition and the remainder related to the acquisition of unproved acreage in various areas.

Funding of working capital.  As of December 31, 2009 and 2008, our working capital (defined as total current assets less total current liabilities) was a negative $62.9 million and a positive $188.7 million, respectively. The decrease was primarily due to the monetization of certain of our 2009 oil derivative contracts in March 2009 and higher oil prices at December 31, 2009 as compared to December 31, 2008, which negatively impacted the fair value of our outstanding oil derivative contracts.

For 2010, we expect working capital to remain negative primarily due to the fair value of our outstanding commodity derivative contracts. We anticipate cash reserves to be close to zero because we intend to use any excess cash to fund capital obligations and reduce outstanding borrowings and related interest expense under our revolving credit facility. However, we have availability under our revolving credit facility to fund our obligations as they become due. We do not plan to pay cash dividends in the foreseeable future. Our production volumes, commodity prices, and differentials for oil and natural gas will be the largest variables affecting working capital. Our operating cash flow is determined in large part by production volumes and commodity prices. Given our current commodity derivative contracts, assuming relatively stable commodity prices and constant production volumes, our operating cash flow should remain positive in 2010.

Our capital expenditures are largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects, and market conditions. We plan to finance our ongoing expenditures using internally generated cash flow and borrowings under our revolving credit facility.

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

Contractual obligations.  The following table provides our contractual obligations and commitments at December 31, 2009:

		Payments Due by Period
Contractual Obligations and Commitments	Maturity Date	Total		2010		2011 - 2012		2013 - 2014		Thereafter
	(In thousands)
6.25% Senior Subordinated Notes(a)	4/15/2014	$	192,188	$	9,375	$	18,750	$	164,063	$	—
6.0% Senior Subordinated Notes(a)	7/15/2015		408,000		18,000		36,000		36,000		318,000
9.5% Senior Subordinated Notes(a)	5/1/2016		363,938		21,375		42,750		42,750		257,063
7.25% Senior Subordinated Notes(a)	12/1/2017		237,000		10,875		21,750		21,750		182,625
Revolving credit facilities(a)	3/7/2012		432,824		10,144		422,680		—		—
Commodity derivative contracts(b)			85,029		48,804		36,225		—		—
Interest rate swaps(c)			3,669		3,320		349		—		—
Capital lease obligations			1,281		466		815		—		—
Development commitments(d)			48,026		48,026		—		—		—
Operating leases and commitments(e)			13,568		3,983		6,978		2,607		—
Asset retirement obligations(f)			192,912		1,517		3,034		3,668		184,693
Total		$	1,978,435	$	175,885	$	589,331	$	270,838	$	942,381

(a)	Includes principal and projected interest payments. Please read Note 7 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our long-term debt.
(b)	Represents net liabilities for commodity derivative contracts. With the exception of $48.8 million of deferred premiums on commodity derivative contracts, the ultimate settlement amounts of our commodity derivative contracts are unknown because they are subject to continuing market risk. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” and Note 12 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our commodity derivative contracts.
(c)	Represents net liabilities for interest rate swaps, the ultimate settlement of which are unknown because they are subject to continuing market risk. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” and Note 12 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our interest rate swaps.
(d)	Represents authorized purchases for work in process. Also at December 31, 2009, we had $167.2 million of authorized purchases not placed to vendors (authorized AFEs), which were not accrued and are excluded from the above table but are budgeted for and are expected to be made unless circumstances change.
(e)	Includes office space and equipment obligations that have non-cancelable lease terms in excess of one year of $13.2 million and future minimum payments for other operating commitments of $0.4 million. Please read Note 4 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our operating leases.
(f)	Represents the undiscounted future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal at the end of field life. Please read Note 5 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our asset retirement obligations.

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

The marketing of our CCA oil production is mainly dependent on transportation through the Bridger, Poplar, and Butte pipelines to markets in the Guernsey, Wyoming area. Alternative transportation routes and markets have been developed by moving a portion of the crude oil production through the Enbridge Pipeline to the Clearbrook, Minnesota hub. To a lesser extent, our production also depends on transportation through the Platte Pipeline to Wood River, Illinois as well as other pipelines connected to the Guernsey, Wyoming area. While shipments on the Platte Pipeline are oversubscribed and subject to apportionment, we currently believe that we have been allocated sufficient pipeline capacity to move our crude oil production. However, there can be no assurance that we will be allocated sufficient pipeline capacity to move our crude oil production in the future. An expansion of the Enbridge Pipeline was completed in early 2008, which moved the total Rockies area pipeline takeaway closer to increasing production volumes and thereby provided greater stability to oil differentials in the area. An additional expansion of Enbridge Pipeline was completed in early 2010, bringing additional takeaway capacity to the region, but in spite of these increases in capacity, the Enbridge Pipeline continues to run at full capacity. The Enbridge pipeline is currently presenting a new proposal to further expand the line in anticipation of the continuing expected production increases from the Williston / Bakken region. However, any restrictions on available capacity to transport oil through any of the above-mentioned pipelines, any other pipelines, or any refinery upsets could have a material adverse effect on our production volumes and the prices we receive for our production.

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

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	of 2009			of 2009			of 2009			of 2009
Average oil wellhead to NYMEX percentage		82	%		92	%		89	%		89	%
Average natural gas wellhead to NYMEX percentage		67	%		105	%		109	%		112	%

Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of liquids extracted. Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas in Mcf as production resulting in a price we were paid per Mcf under certain contracts to be higher than the average NYMEX price.

Capital resources

Cash flows from operating activities.  Cash provided by operating activities increased $82.4 million from $663.2 million in 2008 to $745.7 million in 2009, primarily due to the monetization of certain of our 2009 oil derivative contracts in March 2009 and decreased settlements paid under our oil derivative contracts as a result of lower average oil prices in 2009 as compared to 2008, partially offset by a decrease in our production margin.

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Cash provided by operating activities increased $343.5 million from $319.7 million in 2007 to $663.2 million in 2008, primarily due to an increase in our production margin, partially offset by increased settlements on our commodity derivative contracts as a result of higher commodity prices in the first half of 2008.

Cash flows from investing activities.  Cash used in investing activities increased $41.1 million from $728.3 million in 2008 to $769.4 million in 2009, primarily due to a $290.4 million increase in amounts paid to acquire oil and natural gas properties, namely our EXCO asset acquisition, partially offset by a $218.7 million decrease in amounts paid to develop oil and natural gas properties and a $32.2 million decrease in net advancements to working interest partners. During 2009, we collected $7.4 million (net of advancements) from ExxonMobil for their portion of costs incurred by us in drilling wells under the joint development agreement as compared to advancements of $24.8 million (net of collections) in 2007.

Cash used in investing activities decreased $201.3 million from $929.6 million in 2007 to $728.3 million in 2008, primarily due to a $706.0 million decrease in amounts paid for acquisitions of oil and natural gas properties and a $283.7 million decrease in proceeds received for the disposition of assets, partially offset by a $225.1 million increase in development of oil and natural gas properties. In 2007, we paid approximately $393.6 million in conjunction with the Big Horn Basin asset acquisition and approximately $392.1 million in conjunction with the Williston Basin asset acquisition. In 2007, we also completed the sale of certain oil and natural gas properties in the Mid-Continent for net proceeds of approximately $294.8 million. During 2008, we advanced $24.8 million (net of collections) to ExxonMobil for their portion of costs incurred by us in drilling wells under the joint development agreement as compared to advancements of $29.5 million (net of collections) in 2007.

Cash flows from financing activities.  Our cash flows from financing activities consist primarily of proceeds from and payments on long-term debt, issuances of EAC shares of common stock and ENP common units, and ENP distributions to noncontrolling interests. We periodically draw on our revolving credit facility to fund acquisitions and other capital commitments.

During 2009, we received net cash of $35.7 million from financing activities, including $202.4 million of net proceeds from the issuance of our 9.5% Notes, $100.6 million of net proceeds from the issuance of EAC common stock, and $170.1 million of net proceeds from the issuance of ENP common units, partially offset by net repayments on revolving credit facilities of $315 million, payments for deferred commodity derivative contract premiums of $71.4 million, and ENP distributions to noncontrolling interests of $37.7 million. Net repayments decreased the outstanding borrowings under revolving credit facilities from $725 million at December 31, 2008 to $410 million at December 31, 2009.

In December 2007, we announced that the Board approved a share repurchase program authorizing us to repurchase up to $50 million of our common stock. During 2008, we completed the share repurchase program by repurchasing and retiring 1,397,721 shares of our outstanding common stock at an average price of approximately $35.77 per share.

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

During 2008, we received net cash of $65.4 million from financing activities, including net borrowings on our revolving credit facilities of $199 million, which resulted in an increase in outstanding borrowings under our revolving credit facilities from $526 million at December 31, 2007 to $725 million at December 31, 2008.

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During 2007, we received net cash of $610.8 million from financing activities, including net borrowings on our revolving credit facilities of $458 million and net proceeds of $193.5 million from the issuance of ENP common units. Net borrowings on our revolving credit facilities were primarily due to borrowings used to finance our Big Horn Basin and Williston Basin asset acquisitions, which were partially offset by repayments from the net proceeds received from the Mid-Continent asset disposition and ENP’s issuance of common units.

Liquidity

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

Issuance of 9.5% Senior Subordinated Notes Due 2016.  In April 2009, we issued $225 million of our 9.5% Notes at 92.228 percent of par value. We used the net proceeds of approximately $202.4 million to reduce outstanding borrowings under our revolving credit facility. Interest on the 9.5% Notes is due semi-annually on May 1 and November 1, beginning November 1, 2009. The 9.5% Notes mature on May 1, 2016.

Internally generated cash flows.  Our internally generated cash flows, results of operations, and financing for our operations are largely dependent on oil and natural gas prices. During 2009, our average realized oil and natural gas prices decreased by 39 percent and 55 percent, respectively, as compared to 2008. Realized oil and natural gas prices fluctuate widely in response to changing market forces. If oil and natural gas prices decline, or we experience a significant widening of our differentials, then our earnings, cash flows from operations, and borrowing base under our revolving credit facilities may be adversely impacted. Prolonged periods of lower oil and natural gas prices, or sustained wider differentials, could cause us to not be in compliance with financial covenants under our revolving credit facilities and thereby affect our liquidity. However, we have protected a portion of our forecasted production through 2012 against declining commodity prices. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” and Note 12 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our commodity derivative contracts.

Revolving credit facilities.  The syndicate of lenders underwriting our revolving credit facility includes 30 banking and other financial institutions, and the syndicate of lenders underwriting ENP’s revolving credit facility includes 15 banking and other financial institutions. None of the lenders are underwriting more than ten percent of the respective total commitment. We believe the number of lenders, the small percentage participation of each, and the level of availability under each facility provides adequate diversity and flexibility should further consolidation occur within the financial services industry.

Certain of the lenders underwriting our facility are also counterparties to our commodity derivative contracts. Please read “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional discussion.

Encore Acquisition Company Credit Agreement

In March 2007, we entered into a five-year amended and restated credit agreement (as amended, the “EAC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The EAC Credit Agreement matures on March 7, 2012. In March 2009, we amended the EAC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the EAC Credit Agreement.

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The EAC Credit Agreement provides for revolving credit loans to be made to us from time to time and letters of credit to be issued from time to time for the account of us or any of our restricted subsidiaries. The aggregate amount of the commitments of the lenders under the EAC Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. In March 2009, the borrowing base of our revolving credit facility was reaffirmed at $1.1 billion before a reduction of $200 million solely as a result of the monetization of certain of our 2009 oil derivative contracts during the first quarter of 2009. In April 2009, the borrowing base was reduced by $75 million as a result of our issuance of the 9.5% Notes. The reductions in the borrowing base under the EAC Credit Agreement did not result in any required prepayments of indebtedness. In December 2009, we amended the EAC Credit Agreement to, among other things, increase the borrowing base under the EAC Credit Agreement to $925 million. As of December 31, 2009, the borrowing base was $925 million.

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

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

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

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

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

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

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

The EAC Credit Agreement contains covenants including, among others, the following:

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

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

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•  a restriction on creating liens on our and our restricted subsidiaries’ assets, subject to permitted exceptions;

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

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

•  a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

•  a requirement that we maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0; and

•  a requirement that we maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0.

The EAC Credit Agreement contains customary events of default, which would permit the lenders to accelerate the debt if not cured within applicable grace periods. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the EAC Credit Agreement to be immediately due and payable.

On December 31, 2009 and February 17, 2010, there were $155 million of outstanding borrowings, $0.3 million of outstanding letters of credit, and $769.7 million of borrowing capacity under the EAC Credit Agreement.

Encore Energy Partners Operating LLC Credit Agreement

In March 2007, OLLC entered into a five-year credit agreement (as amended, the “OLLC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The OLLC Credit Agreement matures on March 7, 2012. In March 2009, OLLC amended the OLLC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. In August 2009, OLLC amended the OLLC Credit Agreement to, among other things, (1) increase the borrowing base from $240 million to $375 million, (2) increase the aggregate commitments of the lenders from $300 million to $475 million, and (3) increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. In November 2009, OLLC amended the OLLC Credit Agreement, which will be effective upon the closing of the Merger, to, among other things, permit the consummation of the Merger from being a “Change of Control” under the OLLC Credit Agreement.

The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries. The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $475 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. As of December 31, 2009, the borrowing base was $375 million.

OLLC incurs a commitment fee of 0.5 percent on the unused portion of the OLLC Credit Agreement.

Obligations under the OLLC Credit Agreement are secured by a first-priority security interest in substantially all of OLLC’s proved oil and natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition, obligations under the OLLC Credit Agreement are guaranteed by ENP and OLLC’s restricted subsidiaries. We consolidate the debt of ENP with that of our own; however, obligations under the OLLC Credit Agreement are non-recourse to us and our restricted subsidiaries.

Loans under the OLLC Credit Agreement are subject to varying rates of interest based on (1) outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan.

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

	Applicable Margin for			Applicable Margin for
Ratio of Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		2.250	%		1.250	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.500	%		1.500	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.750	%		1.750	%
Greater than or equal to .90 to 1		3.000	%		2.000	%

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

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

The OLLC Credit Agreement contains covenants including, among others, the following:

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

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

•  a restriction on creating liens on the assets of ENP, OLLC, and OLLC’s restricted subsidiaries, subject to permitted exceptions;

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

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

•  a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

•  a requirement that ENP and OLLC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0 (the “ENP Current Ratio”);

•  a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0 (the “ENP Interest Coverage Ratio”); and

•  a requirement that ENP and OLLC maintain a ratio of consolidated funded debt to consolidated adjusted EBITDA of not more than 3.5 to 1.0 (the “ENP Leverage Ratio”).

In order to show ENP’s and OLLC’s compliance with the covenants of the OLLC Credit Agreement, the use of non-GAAP financial measures is required. The presentation of these non-GAAP financial measures provides useful information to investors as they allow readers to understand how much cushion there is between the required ratios and the actual ratios. These non-GAAP financial measures should not be considered an alternative to any measure of financial performance presented in accordance with GAAP.

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As of December 31, 2009, ENP and OLLC were in compliance with all covenants in the OLLC Credit Agreement, including the following financial covenants:

		Actual Ratio as of
Financial Covenant	Required Ratio	December 31, 2009
ENP Current Ratio	Minimum 1.0 to 1.0	5.1 to 1.0
ENP Interest Coverage Ratio	Minimum 2.5 to 1.0	10.7 to 1.0
ENP Leverage Ratio	Maximum 3.5 to 1.0	2.0 to 1.0

The following table shows the calculation of the ENP Current Ratio as of December 31, 2009 ($ in thousands):

ENP current assets	$	48,248
Availability under the OLLC Credit Agreement		120,000
ENP consolidated current assets	$	168,248
Divided by: ENP consolidated current liabilities	$	32,690
ENP Current Ratio		5.1

The following table shows the calculation of the ENP Interest Coverage Ratio for the twelve months ended December 31, 2009 ($ in thousands):

ENP Consolidated EBITDA(a)	$	116,732
Divided by: ENP consolidated net interest expense and letter of credit fees	$	10,928
ENP Interest Coverage Ratio		10.7

(a) ENP Consolidated EBITDA is defined in the OLLC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense. ENP Consolidated EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.

The following table shows the calculation of the ENP Leverage Ratio for the twelve months ended December 31, 2009 ($ in thousands):

ENP consolidated funded debt	$	255,000
Divided by: ENP Consolidated Adjusted EBITDA(a)	$	127,719
ENP Leverage Ratio		2.0

(a) ENP Consolidated Adjusted EBITDA is defined in the OLLC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense, after giving pro forma effect to one or more acquisitions or dispositions in excess of $20 million in the aggregate. ENP Consolidated Adjusted EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.

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The following table presents a calculation of ENP Consolidated EBITDA and ENP Consolidated Adjusted EBITDA for the twelve months ended December 31, 2009 (in thousands) as required under the OLLC Credit Agreement, together with a reconciliation of such amounts to their most directly comparable financial measures calculated and presented in accordance with GAAP. These EBITDA measures should not be considered an alternative to net income (loss), operating income (loss), cash flow from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. These EBITDA measures may not be comparable to similarly titled measures of another company because all companies may not calculate these measures in the same manner.

ENP consolidated net income	$	(40,507	)
ENP unrealized non-cash hedge gain		94,441
ENP consolidated net interest expense		10,928
ENP income and franchise taxes		14
ENP depletion, depreciation, amortization, and exploration expense		50,040
ENP non-cash unit-based compensation		565
ENP other non-cash		1,251
ENP Consolidated EBITDA		116,732
Pro forma effect of acquisitions		10,987
ENP Consolidated Adjusted EBITDA	$	127,719

The OLLC Credit Agreement contains customary events of default, which would permit the lenders to accelerate the debt if not cured within applicable grace periods. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately due and payable.

On December 31, 2009, there were $255 million of outstanding borrowings and $120 million of borrowing capacity under the OLLC Credit Agreement. On February 17, 2010, there were $260 million of outstanding borrowings and $115 million of borrowing capacity under the OLLC Credit Agreement.

Indentures governing our senior subordinated notes.  We and our restricted subsidiaries are subject to certain negative and financial covenants under the indentures governing the 9.5% Notes, the 6.25% Notes, the 6.0% Notes, and the 7.25% Notes (collectively, the “Notes”). The provisions of the indentures limit our and our restricted subsidiaries’ ability to, among other things:

•  incur additional indebtedness;

•  pay dividends on our capital stock or redeem, repurchase, or retire our capital stock or subordinated indebtedness;

•  make investments;

•  incur liens;

•  create any consensual limitation on the ability of our restricted subsidiaries to pay dividends, make loans, or transfer property to us;

•  engage in transactions with our affiliates;

•  sell assets, including capital stock of our subsidiaries;

•  consolidate, merge, or transfer assets;

•  a requirement that we maintain a current ratio (as defined in the indentures) of not less than 1.0 to 1.0; and

•  a requirement that we maintain a ratio of consolidated EBITDA (as defined in the indentures) to consolidated interest expense of not less than 2.5 to 1.0.

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If we experience a change of control (as defined in the indentures), subject to certain conditions, we must give holders of the Notes the opportunity to sell to us their Notes at 101 percent of the principal amount, plus accrued and unpaid interest.

Capitalization.  At December 31, 2009, we had total assets of $3.7 billion and total capitalization of $2.8 billion, of which 57 percent was represented by equity and 43 percent by long-term debt. At December 31, 2008, we had total assets of $3.6 billion and total capitalization of $2.8 billion, of which 53 percent was represented by equity and 47 percent by long-term debt. The percentages of our capitalization represented by equity and long-term debt could vary in the future if debt or equity is used to finance capital projects or acquisitions.

Changes in Prices

Our oil and natural gas revenues, the value of our assets, and our ability to obtain bank loans or additional capital on attractive terms are affected by changes in oil and natural gas prices, which fluctuate significantly. The following table provides our average oil and natural gas prices for the periods indicated. Our average realized prices for 2008 and 2007 were decreased by $0.20 and $3.96 per BOE, respectively, as a result of commodity derivative contracts, which were previously designated as hedges.

	Year Ended December 31,
	2009		2008		2007
Average realized prices:
Oil ($/Bbl)	$	54.85	$	89.30	$	58.96
Natural gas ($/Mcf)		3.87		8.63		6.26
Combined ($/BOE)		43.43		77.87		52.66
Average wellhead prices:
Oil ($/Bbl)	$	54.85	$	89.58	$	63.50
Natural gas ($/Mcf)		3.87		8.63		6.69
Combined ($/BOE)		43.43		78.07		56.62

Increases in oil and natural gas prices may be accompanied by or result in: (1) increased development costs, as the demand for drilling operations increases; (2) increased severance taxes, as we are subject to higher severance taxes due to the increased value of oil and natural gas extracted from our wells; (3) increased LOE, as the demand for services related to the operation of our wells increases; and (4) increased electricity costs. Decreases in oil and natural gas prices may be accompanied by or result in: (1) decreased development costs, as the demand for drilling operations decreases; (2) decreased severance taxes, as we are subject to lower severance taxes due to the decreased value of oil and natural gas extracted from our wells; (3) decreased LOE, as the demand for services related to the operation of our wells decreases; (4) decreased electricity costs; (5) impairment of oil and natural gas properties; and (6) decreased revenues and cash flows. We believe our risk management program and available borrowing capacity under our revolving credit facility provide means for us to manage commodity price risks.

Critical Accounting Policies and Estimates

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

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Oil and Natural Gas Properties

Successful efforts method.  We use the successful efforts method of accounting for oil and natural gas properties under ASC 932 (formerly SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”). Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive.

If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs are expensed in the period in which the determination is made. If an exploratory well finds reserves but they cannot be classified as proved, we continue to capitalize the associated cost as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress in assessing the reserves and the operating viability of the project. If subsequently it is determined that these conditions do not continue to exist, all previously capitalized costs associated with the exploratory well are expensed in the period in which the determination was made. Re-drilling or directional drilling in a previously abandoned well is classified as development or exploratory based on whether it is in a proved or unproved reservoir. Costs for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Costs to recomplete a well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is unsuccessful, the costs are charged to expense.

DD&A expense is directly affected by our reserve estimates. Significant revisions to reserve estimates can be and are made by our reserve engineers each year. Mostly these are the result of changes in price, but as reserve quantities are estimates, they can also change as more or better information is collected, especially in the case of estimates in newer fields. Downward revisions have the effect of increasing our DD&A rate, while upward revisions have the effect of decreasing our DD&A rate. Assuming no other changes, such as an increase in depreciable base, as our reserves increase, the amount of DD&A expense in a given period decreases and vice versa. DD&A expense associated with lease and well equipment and intangible drilling costs is based upon proved developed reserves, while DD&A expense for capitalized leasehold costs is based upon total proved reserves. As a result, changes in the classification of our reserves could have a material impact on our DD&A expense.

Miller and Lents estimates our reserves annually at December 31. This results in a new DD&A rate which we use for the preceding fourth quarter after adjusting for fourth quarter production. We internally estimate reserve additions and reclassifications of reserves from proved undeveloped to proved developed at the end of the first, second, and third quarters for use in determining a DD&A rate for the respective quarter.

Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Internal costs directly associated with the development of proved properties are capitalized as a cost of the property and are classified accordingly in our consolidated financial statements. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable. Natural gas volumes are converted to BOE at the rate of six Mcf of natural gas to one Bbl of oil.

The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to accumulated DD&A.

In accordance with ASC 360-10, 205, 840, 958, and 855-10-60-1 (formerly SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”), we assess the need for an impairment of long-lived assets to be held and used, including proved oil and natural gas properties, whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then an

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impairment charge is recognized to the extent the asset’s carrying value exceeds its fair value. Expected future net cash flows are based on existing proved reserves (and appropriately risk-adjusted probable reserves), forecasted production information, and management’s outlook of future commodity prices. Any impairment charge incurred is expensed and reduces our net basis in the asset. Management aggregates proved property for impairment testing the same way as for calculating DD&A. The price assumptions used to calculate undiscounted cash flows is based on judgment. We use prices consistent with the prices we believe a market participant would use in bidding on acquisitions and/or assessing capital projects. These price assumptions are critical to the impairment analysis as lower prices could trigger impairment.

Unproved properties, the majority of which relate to the acquisition of leasehold interests, are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of the unproved properties’ costs which we believe will not be transferred to proved properties over the life of the lease. One of the primary factors in determining what portion will not be transferred to proved properties is the relative proportion of the unproved properties on which proved reserves have been found in the past. Since the wells drilled on unproved acreage are inherently exploratory in nature, actual results could vary from estimates especially in newer areas in which we do not have a long history of drilling.

Oil and natural gas reserves.  Our estimates of proved reserves are based on the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing conditions and operating methods. Miller and Lents prepares a reserve and economic evaluation of all of our properties on a well-by-well basis. Assumptions used by Miller and Lents in calculating reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. The accuracy of reserve estimates is a function of the:

•  quality and quantity of available data;

•  interpretation of that data;

•  accuracy of various mandated economic assumptions; and

•  judgment of the independent reserve engineer.

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

Asset retirement obligations.  In accordance with ASC 410-20, 450-20, 835-20, 360-10-35, 840-10, and 980-410 (formerly SFAS No. 143, “Accounting for Asset Retirement Obligations”), we recognize the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas property is acquired or a new well is drilled. An amount equal to and offsetting the liability is capitalized as part of the carrying amount of our oil and natural gas properties. The liability is recorded at its discounted risk adjusted fair value and then accreted each period until it is settled or the asset is sold, at which time the liability is reversed.

The fair value of the liability associated with the asset retirement obligation is determined using significant assumptions, including current estimates of the plugging and abandonment costs, annual expected

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

Goodwill and Other Intangible Assets

We account for goodwill and other intangible assets under the provisions of ASC 350, 730-10-60-3, 323-10-35-13, 205-20-60-4, and 280-10-60-2 (formerly SFAS No. 142, “Goodwill and Other Intangible Assets”). Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is assessed for impairment annually on December 31 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level. We have determined that we have two reporting units: EAC Standalone and ENP. If indicators of impairment are determined to exist, an impairment charge is recognized for the amount by which the carrying value of goodwill exceeds its implied fair value.

We utilize both a market capitalization and an income approach to determine the fair value of our reporting units. The primary component of the income approach is the estimated discounted future net cash flows expected to be recovered from the reporting unit’s oil and natural gas properties. Our analysis concluded that there was no impairment of goodwill as of December 31, 2009. Significant decreases in the prices of oil and natural gas or significant negative reserve adjustments from the December 31, 2009 assessment could change our estimates of the fair value of our reporting units and could result in an impairment charge.

Intangible assets with definite useful lives are amortized over their estimated useful lives. In accordance with ASC 360-10, 205, 840, 958, and 855-10-60-1, we evaluate the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.

We allocate the purchase price paid for the acquisition of a business to the assets and liabilities acquired based on the estimated fair values of those assets and liabilities. Estimates of fair value are based upon, among other things, reserve estimates, anticipated future prices and costs, and expected net cash flows to be generated. These estimates are often highly subjective and may have a material impact on the amounts recorded for acquired assets and liabilities.

Net Profits Interests

A major portion of our acreage position in the CCA is subject to net profits interests ranging from one percent to 50 percent. The holders of these net profits interests are entitled to receive a fixed percentage of the cash flow remaining after specified costs have been subtracted from net revenue. The net profits calculations are contractually defined. In general, net profits are determined after considering costs associated with production, overhead, interest, and development. The amounts of reserves and production attributable to net profits interests are deducted from our reserves and production data, and our revenues are reported net of net profits interests. The reserves and production attributed to the net profits interests are calculated by dividing estimated future net profits interests (in the case of reserves) or prior period actual net profits interests (in the case of production) by commodity prices at the determination date. Fluctuations in commodity prices and the levels of development activities in the CCA from period to period will impact the reserves and production attributed to the net profits interests and will have an inverse effect on our oil and natural gas revenues, production, reserves, and net income.

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Oil and Natural Gas Revenue Recognition

Oil and natural gas revenues are recognized as oil and natural gas is produced and sold, net of royalties and net profits interests. Royalties, net profits interests, and severance taxes are incurred based upon the actual price received from the sales. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. Natural gas revenues are reduced by any processing and other fees incurred except for transportation costs paid to third parties, which are recorded as expense. Natural gas revenues are recorded using the sales method of accounting whereby revenue is recognized based on actual sales of natural gas rather than our proportionate share of natural gas production. If our overproduced imbalance position (i.e., we have cumulatively been over-allocated production) is greater than our share of remaining reserves, a liability is recorded for the excess at period-end prices unless a different price is specified in the contract in which case that price is used. Revenue is not recognized for production in tanks, oil marketed on behalf of joint interest owners in our properties, or oil in pipelines that has not been delivered to the purchaser.

Income Taxes

Our effective tax rate is subject to variability from period to period as a result of factors other than changes in federal and state tax rates and/or changes in tax laws which can affect taxpaying companies. Our effective tax rate is affected by changes in the allocation of property, payroll, and revenues between states in which we own property as rates vary from state to state. Our deferred taxes are calculated using rates we expect to be in effect when they reverse. As the mix of property, payroll, and revenues varies by state, our estimated tax rate changes. Due to the size of our gross deferred tax balances, a small change in our estimated future tax rate can have a material effect on earnings.

Derivatives

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

We apply the provisions of ASC 815 (formerly SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”), which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, the effective portion of changes in fair value can be recognized in accumulated other comprehensive income or loss until such time as the hedged item is recognized in earnings. In order to qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically.

We have elected to designate our outstanding interest rate swaps as cash flow hedges. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in accumulated other comprehensive income or loss in equity and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized immediately in earnings. While management does not anticipate changing the designation of our interest rate swaps as hedges, factors beyond our control can preclude the use of hedge accounting.

We have not elected to designate our current portfolio of commodity derivative contracts as hedges. Therefore, changes in fair value of these derivative instruments are recognized in earnings each period.

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

New Accounting Pronouncements

FASB Launches Accounting Standards Codification

In June 2009, the FASB issued ASC 105-10 (formerly SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles”). ASC 105-10 establishes the FASB Accounting Standards Codification as the sole source of authoritative accounting principles recognized by the FASB to be applied by all nongovernmental entities in the preparation of financial statements in conformity with GAAP. ASC 105-10 was prospectively effective for financial statements issued for fiscal years ending on or after September 15, 2009, and interim periods within those fiscal years. The adoption of ASC 105-10 on July 1, 2009 did not impact our results of operations or financial condition.

Following the Codification, the FASB does not issue new standards in the form of Statements, FASB Staff Positions (“FSP”), or EITF Abstracts. Instead, it issues Accounting Standards Updates (“ASU”), which update the Codification, provide background information about the guidance, and provide the basis for conclusions on the changes to the Codification.

The Codification did not change GAAP; however, it did change the way GAAP is organized and presented. As a result, these changes impact how companies, including us, reference GAAP in their financial statements and in their significant accounting policies.

ASC 820-10 (formerly FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157”)

In February 2008, the FASB issued ASC 820-10, which delayed the effective date of ASC 820-10 for one year for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). ASC 820-10 was prospectively effective for financial statements issued for fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. We elected a partial deferral of ASC 820-10 for all instruments within the scope of ASC 820-10, including, but not limited to, our asset retirement obligations and indefinite lived assets. The adoption of ASC 820-10 on January 1, 2009 as it relates to nonfinancial assets and liabilities did not have a material impact on our results of operations or financial condition.

ASC 805 (formerly SFAS No. 141 (revised 2007), “Business Combinations”)

In December 2007, the FASB issued ASC 805, which establishes principles and requirements for the reporting entity in a business combination, including: (1) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. In April 2009, the FASB issued ASC 805-20 (formerly FSP No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arises from Contingencies”), which amends and clarifies ASC 805 to address application issues, including: (1) initial recognition and measurement; (2) subsequent measurement and accounting; and (3) disclosure of assets and liabilities arising from contingencies in a business combination. ASC 805 and ASC 805-20 were prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008. The application of ASC 805 and ASC 805-20 to the acquisition of certain oil and natural gas properties and related assets in the Mid-Continent and East Texas resulted in the expensing of approximately $1.5 million of transaction costs.

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ASC 810-10-65-1 (formerly SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment to ARB No. 51)

In December 2007, the FASB issued ASC 810-10-65-1, which establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. ASC 810-10-65-1 was prospectively effective for financial statements issued for fiscal years beginning on or after December 15, 2008, except for the presentation and disclosure requirements which were retrospectively effective. ASC 810-10-65-1 clarifies that a noncontrolling interest in a subsidiary, which was often referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, ASC 810-10-65-1 requires consolidated net income to be reported for the amounts attributable to both the parent and the noncontrolling interest on the face of the consolidated statement of operations and gains or losses on a subsidiaries’ issuance of equity to be accounted for as capital transactions. The adoption of ASC 810-10-65-1 on January 1, 2009 did not have a material impact on our results of operations or financial condition. The retrospective application of ASC 810-10-65-1 resulted in the reclassification of approximately $169.1 million from “Minority interest in consolidated partnership” to “Noncontrolling interest” at December 31, 2008 on our consolidated balance sheet.

ASC 815-10 (formerly SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133”)

In March 2008, the FASB issued ASC 815-10, which requires enhanced disclosures: including (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under ASC 815; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. ASC 815-10 was prospectively effective for financial statements issued for fiscal years beginning on or after November 15, 2008, and interim periods within those fiscal years. The adoption of ASC 815-10 on January 1, 2009 required additional disclosures regarding our derivative instruments; however, it did not impact our results of operations or financial condition.

ASC 260-10 (formerly FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”)

In June 2008, the FASB issued ASC 260-10, which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation for computing basic earnings per share under the two-class method. ASC 260-10 was retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. In this Report, periods prior to the adoption of ASC 260-10 have been restated to calculate earnings per share in accordance with this pronouncement. The retrospective application of ASC 260-10 reduced our basic earnings per share by $0.14 for 2008 and reduced our diluted earnings per share by $0.06 and $0.01 for 2008 and 2007, respectively. The adoption of ASC 260-10 did not have an impact on our basic earnings per share for 2007.

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

In December 2008, the SEC issued Release 33-8995, which amends oil and natural gas reporting requirements under Regulations S-K and S-X. Release 33-8995 also adds a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being phased out. Release 33-8995 permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. Release 33-8995 will also allow companies to disclose their probable and possible reserves to investors at the company’s option. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor; (2) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (3) report oil and gas reserves using an average price based upon

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the prior 12-month period rather than a year-end price, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. Release 33-8995 was prospectively effective for financial statements issued for fiscal years ending on or after December 31, 2009.

ASC 855-10 (formerly SFAS No. 165, “Subsequent Events”)

In June 2009, the FASB issued ASC 855-10 to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or available to be issued. In particular, ASC 855-10 sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. ASC 855-10 was prospectively effective for financial statements issued for interim or annual periods ending after June 15, 2009. The adoption of ASC 855-10 on June 30, 2009 did not impact our results of operations or financial condition.

ASU No. 2009-05, “Fair Value Measurement and Disclosure: Measuring Liabilities at Fair Value” (“ASU 2009-05”)

In August 2009, the FASB issued ASU 2009-05 to provide clarification on measuring liabilities at fair value when a quoted price in an active market is not available. In particular, ASU 2009-05 specifies that a valuation technique should be applied that used either the quote of the liability when traded as an asset, the quoted prices for similar liabilities or similar liabilities when traded as assets, or another valuation technique consistent with existing fair value measurement guidance. ASU 2009-05 was prospectively effective for financial statements issued for interim or annual periods ending after October 1, 2009. The adoption of ASU 2009-05 on December 31, 2009 did not impact our results of operations or financial condition.

ASU No. 2010-03, “Oil and Gas Reserve Estimation and Disclosure” (“ASU 2010-03”)

In January 2010, the FASB issued ASU 2010-03 to align the oil and natural gas reserve estimation and disclosure requirements of Extractive Activities — Oil and Gas (ASC 932) with the requirements in the SEC’s final rule, “Modernization of the Oil and Gas Reporting.” ASU 2010-03 was prospectively effective for financial statements issued for annual periods ending on or after December 31, 2009.

ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements” (“ASU 2010-06”)

In January 2010, the FASB issued ASU 2010-06 to require additional information to be disclosed principally in respect of level 3 fair value measurements and transfers to and from Level 1 and Level 2 measurements; in addition, enhanced disclosure is required concerning inputs and valuation techniques used to determine Level 2 and Level 3 fair value measurements. ASU 2010-06 was generally effective for interim and annual reporting periods beginning after December 15, 2009; however, the requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years) with early adoption allowed. The adoption of ASU 2010-06 on December 31, 2009 did not impact our results of operations or financial condition.

Information Concerning Forward-Looking Statements

This Report contains forward-looking statements, which give our current expectations or forecasts of future events. Forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts. These statements may include words such as “may,” “will,” “could,” “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “predict,” “potential,” “pursue,” “target,”

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“continue,” and other words and terms of similar meaning. In particular, forward-looking statements included in this Report relate to, among other things, the following:

•  the occurrence of any event, change, or other circumstance that could affect the consummation of the Merger or give rise to the termination of the Merger Agreement in connection with the Merger;

•  the inability to complete the Merger due to the failure to satisfy any conditions required to consummate the Merger;

•  items of income and expense (including, without limitation, LOE, production taxes, DD&A, G&A, and effective income tax rates);

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

•  areas of future growth;

•  our development and exploitation programs;

•  future secondary development and tertiary recovery potential;

•  anticipated prices for oil and natural gas and expectations regarding differentials between wellhead prices and benchmark prices (including, without limitation, the effects of the worldwide economic recession);

•  projected results of operations;

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

•  availability of pipeline capacity;

•  expected commodity derivative positions and payments related thereto (including the ability of counterparties to fulfill obligations);

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

•  projected borrowings under our revolving credit facility (and the ability of lenders to fund their commitments); and

•  the marketing of our oil and natural gas production.

You are cautioned not to place undue reliance on such forward-looking statements, which speak only as of the date of this Report. Our actual results may differ significantly from the results discussed in the forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, the matters discussed in “Item 1A. Risk Factors” and elsewhere in this Report and in our other filings with the SEC. If one or more of these risks or uncertainties materialize (or the consequences of such a development changes), or should underlying assumptions prove incorrect, actual outcomes may vary materially from those forecasted or expected. We undertake no responsibility to update forward-looking statements for changes related to these or any other factors that may occur subsequent to this filing for any reason.

Except for our obligations to disclose material information under United States federal securities laws, we undertake no obligation to release publicly any revision to any forward-looking statement, to report events or circumstances after the date of this Report, or to report the occurrence of unanticipated events.

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

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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 and reduce 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, 2009, we had committed 10 percent or greater (in terms of fair market value) of either our oil or natural gas derivative contracts in asset positions to the following counterparties:

	Fair Market Value of			Fair Market Value of
	Oil Derivative			Natural Gas Derivative
Counterparty	Contracts Committed			Contracts Committed
	(In thousands)
BNP Paribas	$	22,570		$	7,496
Calyon		(a	)		8,550
JP Morgan		10,272			(a	)
Royal Bank of Canada		14,059			(a	)
Wachovia		8,302			3,844

(a) Less than 10 percent.

In order to mitigate the credit risk of financial instruments, we enter into master netting agreements with certain counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating each derivative financial transaction between the counterparty and us separately, the master netting agreement enables the counterparty and us to aggregate all financial trades and treat them as a single agreement. This arrangement is intended to benefit us in three ways: (1) the netting of the value of all trades reduces the likelihood of counterparties requiring daily collateral posting by us; (2) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (3) netting of settlement amounts reduces 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 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 enter into floor spreads. In a floor spread, we purchase puts at a specified price (a “purchased put”) and also sells a put at a lower price (a “short put”). This strategy enables us to achieve some downside protection for a portion of our production, while funding the cost of such protection by selling a put at a lower price. If the price of the commodity falls below the strike price of the purchased put, then we have protection against additional commodity price decreases for the covered production down to the strike price of the short put. At commodity prices below the strike price of the short put, the benefit from the purchased put is generally offset by the expense associated with the short put. For example, in 2007, we purchased oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. As NYMEX prices increased in 2008, we wanted to protect downside price exposure at the higher price. In order to do this, we purchased oil put options for 2,000 Bbls/D in 2010 at $75 per Bbl and simultaneously sold oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. Thus, after these transactions were completed, we had purchased two oil put options for 2,000 Bbls/D in 2010 (one

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at $65 per Bbl and one at $75 per Bbl) and sold one oil put option for 2,000 Bbls/D in 2010 at $65 per Bbl. However, the net effect resulted in us owning one oil put option for 2,000 Bbls/D at $75 per Bbl. In the following tables, the purchased floor component of these floor spreads are shown net and included with our other floor contracts.

The counterparties to our commodity derivative contracts are a diverse group of six institutions, all of which are currently rated A+ or better by Standard & Poor’s and/or Fitch. As of December 31, 2009, the fair market value of our oil derivative contracts was a net liability of approximately $18.2 million and the fair market value of our natural gas derivative contracts was a net asset of approximately $19.0 million. These amounts exclude deferred premiums of $48.8 million that are not subject to changes in commodity prices. Based on our open commodity derivative positions at December 31, 2009, a 10 percent increase in the respective NYMEX prices for oil and natural gas would decrease our net commodity derivative asset by approximately $82.8 million, while a 10 percent decrease in the respective NYMEX prices for oil and natural gas would increase our net commodity derivative asset by approximately $85.4 million.

The following tables summarize our open commodity derivative contracts as of December 31, 2009:

Oil Derivative Contracts

													Asset/
	Average		Weighted		Average		Weighted		Average		Weighted		(Liability)
	Daily		Average		Daily		Average		Daily		Average		Fair
	Floor		Floor		Cap		Cap		Swap		Swap		Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(In thousands)
2010													$	(30,760	)
		880	$	80.00		2,940	$	90.57		—	$	—
		5,500		73.47		3,000		74.13		3,885		77.79
		8,385		62.83		500		65.60		1,750		64.08
		1,000		56.00		—		—		1,000		59.70
2011														17,720
		4,880		80.00		2,940		94.44		325		80.00
		2,500		70.00		—		—		1,060		78.42
		4,385		65.00		—		—		250		69.65
2012														(5,120	)
		750		70.00		500		82.05		835		81.19
		2,135		65.00		250		79.25		1,300		76.54
													$	(18,160	)

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Natural Gas Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted		Asset
	Daily		Average		Daily		Average		Daily		Average		Fair
	Floor		Floor		Cap		Cap		Swap		Swap		Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(In thousands)
Jan. — June 2010													$	5,949
		3,800	$	8.20		3,800	$	9.58		25,452	$	6.46
		4,698		7.26		—		—		20,550		5.23
July — Dec. 2010														6,644
		3,800		8.20		3,800		9.58		—		—
		4,698		7.26		10,000		6.25		25,452		6.46
		10,000		5.13		—		—		550		5.86
2011														4,677
		3,398		6.31		—		—		27,952		6.48
		—		—		—		—		550		5.86
2012														1,755
		898		6.76		—		—		25,452		6.47
		—		—		—		—		550		5.86
													$	19,025

Interest rate sensitivity.  At December 31, 2009, we had total long-term debt of $1.2 billion, net of discount of $20.9 million. Of this amount, $150 million bears interest at a fixed rate of 6.25 percent, $300 million bears interest at a fixed rate of 6.0 percent, $225 million bears interest at a fixed rate of 9.5 percent, and $150 million bears interest at a fixed rate of 7.25 percent. The remaining long-term debt balance of $410 million as of December 31, 2009 consisted of outstanding borrowings under revolving credit facilities, which are subject to floating market rates of interest that are linked to the Eurodollar rate.

At this level of floating rate debt, if the Eurodollar rate increased by 10 percent, we would incur an additional $1.0 million of interest expense per year on our revolving credit facilities, and if the Eurodollar rate decreased by 10 percent, we would incur 1.0 million less. Additionally, if the discount or premium rates on our senior subordinated notes increased by 10 percent, the fair value of our fixed rate debt at December 31, 2009 would increase from approximately $828.8 million to approximately $829.8 million, and if the discount or premium rates decreased by 10 percent, the fair value would decrease to approximately $827.7 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, 2009, the fair market value of ENP’s interest rate swaps was a net liability of approximately $3.7 million. If the Eurodollar rate increased by 10 percent, the fair value would decrease to approximately $3.4 million, and if the Eurodollar rate decreased by 10 percent, the fair value would increase to approximately $3.9 million.

The following table summarizes ENP’s open interest rate swaps as of December 31, 2009:

	Notional		Fixed			Floating
Term	Amount		Rate			Rate
	(In thousands)
Jan. 2010 — Jan. 2011	$	50,000		3.1610	%		1-month LIBOR
Jan. 2010 — Jan. 2011		25,000		2.9650	%		1-month LIBOR
Jan. 2010 — Jan. 2011		25,000		2.9613	%		1-month LIBOR
Jan. 2010 — Mar. 2012		50,000		2.4200	%		1-month LIBOR

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ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

	Page
Report of Independent Registered Public Accounting Firm		77
Consolidated Balance Sheets as of December 31, 2009 and 2008		78
Consolidated Statements of Operations for the Years Ended December 31, 2009, 2008, and 2007		79
Consolidated Statements of Equity and Comprehensive Income (Loss) for the Years Ended December 31, 2009, 2008, and 2007		80
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008, and 2007		81
Notes to Consolidated Financial Statements		82
Supplementary Information		139

76

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Encore Acquisition Company:

We have audited the accompanying consolidated balance sheets of Encore Acquisition Company (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Encore Acquisition Company at December 31, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 2 to the consolidated financial statements, effective January 1, 2009, the Company retroactively changed its method for the presentation of noncontrolling interests in consolidated subsidiaries with the adoption of the guidance originally issued in FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment to ARB No. 51 (codified in FASB ASC Topic 810, Consolidation) and retroactively changed its method of calculating basic and diluted earnings per share with the adoption of the guidance originally issued in FSP No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (codified in FASB ASC Topic 260, Earnings Per Share). Additionally, as discussed in Note 2 to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements resulting from Accounting Standards Update No. 2010-03, Oil and Gas Reserve Estimation and Disclosures, effective for annual reporting periods ended on or after December 31, 2009.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Encore Acquisition Company’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2010 expressed an unqualified opinion thereon.

/s/  Ernst & Young LLP

Fort Worth, Texas

February 24, 2010

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ENCORE ACQUISITION COMPANY

CONSOLIDATED BALANCE SHEETS

	December 31,
	2009			2008
	(In thousands, except
	share and par value
	amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	13,958		$	2,039
Accounts receivable, net of allowance for doubtful accounts of $434 and $381, respectively		114,872			117,995
Current portion of long-term receivables		10,581			11,070
Inventory		26,674			24,798
Derivatives		25,825			349,344
Income taxes		1,712			29,445
Other		3,897			6,239
Total current assets		197,519			540,930
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		4,204,622			3,538,459
Unproved properties		95,601			124,339
Accumulated depletion, depreciation, and amortization		(1,058,267	)		(771,564	)
		3,241,956			2,891,234
Other property and equipment		32,649			25,192
Accumulated depreciation		(17,187	)		(12,753	)
		15,462			12,439
Goodwill		60,606			60,606
Derivatives		35,206			38,497
Long-term receivables, net of allowance for doubtful accounts of $13,645 and $7,643, respectively		55,358			60,915
Other		57,854			28,574
Total assets	$	3,663,961		$	3,633,195
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	7,138		$	10,017
Accrued liabilities:
Lease operating		15,862			19,108
Development capital		47,892			79,435
Interest		15,836			11,808
Production, ad valorem, and severance taxes		29,735			25,133
Compensation		12,991			16,216
Derivatives		69,958			63,476
Oil and natural gas revenues payable		18,415			10,821
Deferred taxes		18,689			105,768
Other		23,857			10,470
Total current liabilities		260,373			352,252
Derivatives		42,698			8,922
Future abandonment cost, net of current portion		52,367			48,058
Deferred taxes		453,110			416,915
Long-term debt		1,214,097			1,319,811
Other		10,483			3,989
Total liabilities		2,033,128			2,149,947
Commitments and contingencies (see Note 4)
Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par value, 144,000,000 shares authorized, 54,621,701 and 51,551,937 issued and outstanding, respectively		546			516
Additional paid-in capital		669,717			525,763
Treasury stock, at cost, of none and 4,753 shares, respectively		—			(101	)
Retained earnings		706,694			789,698
Accumulated other comprehensive loss		(1,038	)		(1,748	)
Total EAC stockholders’ equity		1,375,919			1,314,128
Noncontrolling interest		254,914			169,120
Total equity		1,630,833			1,483,248
Total liabilities and equity	$	3,663,961		$	3,633,195

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

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CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2009			2008			2007
	(In thousands, except per share amounts)
Revenues:
Oil	$	549,391		$	897,443		$	562,817
Natural gas		131,185			227,479			150,107
Marketing		4,840			10,496			42,021
Total revenues		685,416			1,135,418			754,945
Expenses:
Production:
Lease operating		165,062			175,115			143,426
Production, ad valorem, and severance taxes		69,539			110,644			74,585
Depletion, depreciation, and amortization		290,776			228,252			183,980
Impairment of long-lived assets		9,979			59,526			—
Exploration		52,488			39,207			27,726
General and administrative		54,024			48,421			39,124
Marketing		3,994			9,570			40,549
Derivative fair value loss (gain)		59,597			(346,236	)		112,483
Provision for doubtful accounts		7,686			1,984			5,816
Other operating		25,761			12,975			17,066
Total expenses		738,906			339,458			644,755
Operating income (loss)		(53,490	)		795,960			110,190
Other income (expenses):
Interest		(79,017	)		(73,173	)		(88,704	)
Other		2,447			3,898			2,667
Total other expenses		(76,570	)		(69,275	)		(86,037	)
Income (loss) before income taxes		(130,060	)		726,685			24,153
Income tax benefit (provision)		32,173			(241,621	)		(14,476	)
Consolidated net income (loss)		(97,887	)		485,064			9,677
Less: net loss (income) attributable to noncontrolling interest		16,752			(54,252	)		7,478
Net income (loss) attributable to EAC stockholders	$	(81,135	)	$	430,812		$	17,155
Net income (loss) per common share:
Basic	$	(1.54	)	$	8.10		$	0.32
Diluted	$	(1.54	)	$	8.01		$	0.31
Weighted average common shares outstanding:
Basic		52,634			52,270			53,170
Diluted		52,634			52,866			53,629

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

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CONSOLIDATED STATEMENTS OF EQUITY AND COMPREHENSIVE INCOME (LOSS)

	EAC Stockholders
	Issued																		Accumulated			Total
	Shares of						Additional			Shares of									Other			EAC
	Common			Common			Paid-in			Treasury			Treasury			Retained			Comprehensive			Stockholders			Noncontrolling			Total
	Stock			Stock			Capital			Stock			Stock			Earnings			Loss			Equity			Interest			Equity
	(In thousands)
Balance at December 31, 2006		53,047		$	531		$	457,201			(18	)	$	(457	)	$	394,917		$	(35,327	)	$	816,865		$	—		$	816,865
Exercise of stock options and vesting of restricted stock		313			3			1,587			—			—			—			—			1,590			—			1,590
Purchase of treasury stock		—			—			—			(39	)		(1,136	)		—			—			(1,136	)		—			(1,136	)
Cancellation of treasury stock		(39	)		—			(338	)		39			1,003			(665	)		—			—			—			—
Non-cash equity-based compensation		—			—			14,632			—			—			—			—			14,632			2,627			17,259
ENP cash distributions to noncontrolling interest		—			—			—			—			—			—			—			—			(538	)		(538	)
ENP cash distributions to holders of management incentive units		—			—			—			—			—			(30	)		—			(30	)		—			(30	)
Net proceeds from ENP issuance of common units		—			—			(12,088	)		—			—			—			—			(12,088	)		205,549			193,461
Adjustment to reflect gain on ENP issuance of common units		—			—			77,626			—			—			—			—			77,626			(77,626	)		—
Components of comprehensive income:
Consolidated net income		—			—			—			—			—			17,155			—			17,155			(7,478	)		9,677
Amortization of deferred hedge losses, net of tax of $20,047		—			—			—			—			—			—			33,541			33,541			—			33,541
Total comprehensive income																							50,696			(7,478	)		43,218
Balance at December 31, 2007		53,321			534			538,620			(18	)		(590	)		411,377			(1,786	)		948,155			122,534			1,070,689
Exercise of stock options and vesting of restricted stock		300			2			2,620			—			—			—			—			2,622			—			2,622
Repurchase and retirement of common stock		(2,018	)		(20	)		(19,279	)		—			—			(47,871	)		—			(67,170	)		—			(67,170	)
Purchase of treasury stock		—			—			—			(33	)		(1,055	)		—			—			(1,055	)		—			(1,055	)
Cancellation of treasury stock		(46	)		—			(465	)		46			1,544			(1,079	)		—			—			—			—
Non-cash equity-based compensation		—			—			14,505			—			—			—			—			14,505			1,697			16,202
ENP cash distributions to noncontrolling interest		—			—			—			—			—			—			—			—			(24,004	)		(24,004	)
ENP cash distributions to holders of management incentive units		—			—			—			—			—			(3,541	)		—			(3,541	)		—			(3,541	)
Net proceeds from ENP issuance of common units		—			—			—			—			—			—			—			—			5,748			5,748
Adjustment to reflect gain on ENP issuance of common units		—			—			3,458			—			—			—			—			3,458			(3,458	)		—
Economic uniformity adjustment related to conversion of management incentive units		—			—			(13,920	)		—			—			—			—			(13,920	)		13,920			—
Other		—			—			224			—			—			—			—			224			—			224
Components of comprehensive income:
Consolidated net income		—			—			—			—			—			430,812			—			430,812			54,252			485,064
Change in deferred hedge loss on interest rate swaps, net of tax of $957		—			—			—			—			—			—			(1,748	)		(1,748	)		(1,569	)		(3,317	)
Amortization of deferred loss on commodity derivative contracts, net of tax of $1,071		—			—			—			—			—			—			1,786			1,786			—			1,786
Total comprehensive income																							430,850			52,683			483,533
Balance at December 31, 2008		51,557			516			525,763			(5	)		(101	)		789,698			(1,748	)		1,314,128			169,120			1,483,248
Exercise of stock options and vesting of restricted stock		431			3			29			—			—			—			—			32			—			32
Net proceeds from issuance of EAC common stock		2,750			27			100,581			—			—			—			—			100,608			—			100,608
Purchase of treasury stock		—			—			—			(111	)		(2,961	)		—			—			(2,961	)		—			(2,961	)
Cancellation of treasury stock		(116	)		—			(1,193	)		116			3,062			(1,869	)		—			—			—			—
Non-cash equity-based compensation		—			—			14,843			—			—			—			—			14,843			172			15,015
ENP cash distributions to noncontrolling interest		—			—			—			—			—			—			—			—			(37,723	)		(37,723	)
Net proceeds from issuance of ENP common units		—			—			—			—			—			—			—			—			169,806			169,806
Adjustment to reflect gain on ENP issuance of common units		—			—			29,577			—			—			—			—			29,577			(29,577	)		—
Economic uniformity adjustment related to conversion of management incentive units		—			—			(78	)		—			—			—			—			(78	)		78			—
Other		—			—			195			—			—			—			—			195			—			195
Components of comprehensive loss:
Consolidated net loss		—			—			—			—			—			(81,135	)		—			(81,135	)		(16,752	)		(97,887	)
Change in deferred hedge loss on interest rate swaps, net of tax of $344		—			—			—			—			—			—			710			710			(210	)		500
Total comprehensive loss																							(80,425	)		(16,962	)		(97,387	)
Balance at December 31, 2009		54,622		$	546		$	669,717			—		$	—		$	706,694		$	(1,038	)	$	1,375,919		$	254,914		$	1,630,833

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2009			2008			2007
	(In thousands)
Cash flows from operating activities:
Consolidated net income (loss)	$	(97,887	)	$	485,064		$	9,677
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization		290,776			228,252			183,980
Impairment of long-lived assets		9,979			59,526			—
Non-cash exploration expense		50,693			34,874			25,487
Deferred taxes		(51,280	)		232,614			12,588
Non-cash equity-based compensation expense		12,731			14,115			15,997
Non-cash derivative loss (gain)		181,409			(299,914	)		130,910
Inventory valuation		6,473			—			—
Loss (gain) on disposition of assets		(2,145	)		(3,623	)		7,409
Provision for doubtful accounts		7,686			1,984			5,816
Other		10,118			6,479			10,182
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		25,022			(8,488	)		(48,647	)
Current derivatives		256,261			(13,681	)		(17,430	)
Other current assets		19,621			(35,495	)		3,108
Long-term derivatives		—			(8,601	)		(35,750	)
Other assets		(396	)		(2,174	)		(1,214	)
Accounts payable		2,283			(11,468	)		4,461
Other current liabilities		25,907			(14,351	)		14,788
Other noncurrent liabilities		(1,574	)		(1,876	)		(1,655	)
Net cash provided by operating activities		745,677			663,237			319,707
Cash flows from investing activities:
Proceeds from disposition of assets		6,032			4,235			287,928
Purchases of other property and equipment		(7,627	)		(4,208	)		(3,519	)
Acquisition of oil and natural gas properties		(432,957	)		(142,559	)		(848,545	)
Development of oil and natural gas properties		(342,298	)		(560,997	)		(335,897	)
Net collections from (advances to) working interest partners		7,420			(24,817	)		(29,523	)
Net cash used in investing activities		(769,430	)		(728,346	)		(929,556	)
Cash flows from financing activities:
Repurchase and retirement of common stock		—			(67,170	)		—
Exercise of stock options and vesting of restricted stock, net of treasury stock purchases		(2,929	)		1,567			454
Proceeds from long-term debt, net of issuance costs		632,166			1,370,339			1,479,259
Payments on long-term debt		(750,000	)		(1,172,500	)		(1,034,428	)
Proceeds from issuance of EAC common stock, net of offering costs		100,608			—			—
Proceeds from issuance of ENP common units, net of offering costs		170,088			—			193,461
ENP cash distributions to noncontrolling interest and holders of management incentive units		(37,723	)		(27,545	)		(568	)
Payments of deferred commodity derivative contract premiums		(71,376	)		(39,184	)		(26,195	)
Change in cash overdrafts		(5,162	)		(63	)		(1,193	)
Net cash provided by financing activities		35,672			65,444			610,790
Increase in cash and cash equivalents		11,919			335			941
Cash and cash equivalents, beginning of period		2,039			1,704			763
Cash and cash equivalents, end of period	$	13,958		$	2,039		$	1,704

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.   Description of Business

Encore Acquisition Company (together with its subsidiaries, “EAC”), a Delaware corporation, is engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States. Since 1998, EAC has acquired producing properties with proven reserves and leasehold acreage and grown the production and proven reserves by drilling, exploring, reengineering, or expanding existing waterflood projects, and applying tertiary recovery techniques. EAC’s properties and oil and natural gas reserves are located in four core areas:

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

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

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

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

Merger with Denbury

On October 31, 2009, EAC entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Denbury Resources Inc. (“Denbury”) pursuant to which EAC has agreed to merge with and into Denbury, with Denbury as the surviving entity (the “Merger”). The Merger Agreement, which was unanimously approved by EAC’s Board of Directors (the “Board”) and by Denbury’s Board of Directors, provides for Denbury’s acquisition of all of the issued and outstanding shares of EAC common stock, par value $.01 per share, in a transaction valued at approximately $4.5 billion, including the assumption of debt and the value of EAC’s interest in Encore Energy Partners LP (together with its subsidiaries, “ENP”), a publicly traded Delaware limited partnership. Completion of the Merger is conditioned upon, among other things, approval by the stockholders of both EAC and Denbury.

Note 2.   Summary of Significant Accounting Policies

Principles of Consolidation

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

Noncontrolling Interest

In February 2007, EAC formed ENP to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. In September 2007, ENP completed its initial public offering (“IPO”). As of December 31, 2009 and 2008, EAC owned approximately 46 percent and 63 percent, respectively, of ENP’s common units. EAC also owns 100 percent of Encore Energy Partners GP LLC (“GP LLC”), a Delaware limited liability company and indirect wholly owned non-guarantor subsidiary of EAC, which is ENP’s general partner. Considering the presumption of control of GP LLC in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 810-20 (formerly Emerging Issues Task Force (“EITF”) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights”), the financial position, results of operations, and cash flows of ENP are fully consolidated with those of EAC.

As presented in the accompanying Consolidated Balance Sheets, “Noncontrolling interest” as of December 31, 2009 and 2008 of $254.9 million and $169.1 million, respectively, represents third-party ownership interests in ENP. As presented in the accompanying Consolidated Statements of Operations, “Net

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loss attributable to noncontrolling interest” for 2009 and 2007 of $16.8 million and $7.5 million, respectively, and “Net income attributable to noncontrolling interest” for 2008 of $54.3 million, represents ENP’s results of operations attributable to third-party owners.

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

	Year Ended December 31,
	2009			2008		2007
	(In thousands)
Net income (loss) attributable to EAC stockholders	$	(81,135	)	$	430,812	$	17,155
Transfer from (to) noncontrolling interest:
Increase in EAC’s paid-in capital for ENP’s issuance of 10,148,400 common units in public offering		—			—		77,626
Increase in EAC’s paid-in capital for ENP’s issuance of 283,700 common units in connection with acquisition of net profits interest in certain Crockett County properties		—			3,458		—
Increase in EAC’s paid-in capital for ENP’s issuance of 2,760,000 common units in public offering		9,312			—		—
Increase in EAC’s paid-in capital for ENP’s issuance of 9,430,000 common units in public offering		20,265			—		—
Net transfer from noncontrolling interest		29,577			3,458		77,626
Change from net income (loss) attributable to EAC stockholders and transfers from (to) noncontrolling interest	$	(51,558	)	$	434,270	$	94,781

Use of Estimates

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

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

Cash and Cash Equivalents

Cash and cash equivalents include cash in banks, money market accounts, and all highly liquid investments with an original maturity of three months or less. On a bank-by-bank basis and considering legal right of offset, cash accounts that are overdrawn are reclassified to current liabilities and any change in cash overdrafts is shown as “Change in cash overdrafts” in the “Financing activities” section of EAC’s Consolidated Statements of Cash Flows.

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

	Year Ended December 31,
	2009		2008		2007
	(In thousands)
Cash paid during the period for:
Interest	$	66,952	$	67,519	$	82,649
Income taxes		9,075		33,110		260
Non-cash investing and financing activities:
Deferred premiums on commodity derivative contracts		50,972		53,387		20,341
ENP’s issuance of common units in connection with acquisition of net profits interest in certain Crockett County properties		—		5,748		—

Accounts Receivable

Trade accounts receivable, which are primarily from oil and natural gas sales, are recorded at the invoiced amount and do not bear interest with the exception of balances due from ExxonMobil Corporation (“ExxonMobil”) in connection with EAC’s joint development agreement. EAC routinely reviews outstanding accounts receivable balances and assesses the financial strength of its customers and records a reserve for amounts not expected to be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted.

During 2009 and 2008, EAC recorded an allowance for doubtful accounts of approximately $7.7 million and $2.0 million, respectively, primarily related to balances due from ExxonMobil in connection with EAC’s joint development agreement, which are included in “Provision for doubtful accounts” in the accompanying Consolidated Statements of Operations. The following table summarizes the changes in EAC’s allowance for doubtful accounts for the periods indicated:

	Year Ended December 31,
	2009			2008
	(In thousands)
Allowance for doubtful accounts at January 1	$	8,024		$	6,045
Bad debt expense		7,686			1,984
Write off		(1,631	)		(5	)
Allowance for doubtful accounts at December 31	$	14,079		$	8,024

As of December 31, 2009, $0.4 million of EAC’s allowance for doubtful accounts was current and $13.6 million was long-term.

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Inventory

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

	December 31,
	2009		2008
	(In thousands)
Materials and supplies	$	17,931	$	15,933
Oil in pipelines		8,743		8,865
Total inventory	$	26,674	$	24,798

During 2009, EAC recorded a lower of cost or market adjustment of approximately $6.5 million to the carrying value of pipe and other tubular inventory whose market value had declined below cost, which is included in “Other operating expense” in the accompanying Consolidated Statements of Operations.

Properties and Equipment

Oil and Natural Gas Properties.  EAC uses the successful efforts method of accounting for its oil and natural gas properties under ASC 932 (formerly Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”). Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive.

If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs are expensed in EAC’s Consolidated Statements of Operations and shown as an adjustment to net income (loss) in the “Operating activities” section of EAC’s Consolidated Statements of Cash Flows in the period in which the determination was made. If an exploratory well finds reserves but they cannot be classified as proved, EAC continues to capitalize the associated cost as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and EAC is making sufficient progress in assessing the reserves and the operating viability of the project. If subsequently it is determined that these conditions do not continue to exist, all previously capitalized costs associated with the exploratory well are expensed and shown as an adjustment to net income (loss) in the “Operating activities” section of EAC’s Consolidated Statements of Cash Flows in the period in which the determination is made. Re-drilling or directional drilling in a previously abandoned well is classified as development or exploratory based on whether it is in a proved or unproved reservoir. Costs for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Costs to recomplete a well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is unsuccessful, the costs are charged to expense. All capitalized costs associated with both development and exploratory wells are shown as “Development of oil and natural gas properties” in the “Investing activities” section of EAC’s Consolidated Statements of Cash Flows.

Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Internal costs directly associated with the development of proved properties are capitalized as a cost of the property and are classified accordingly in EAC’s consolidated financial statements. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total

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proved reserves, as applicable. Natural gas volumes are converted to barrels of oil equivalent (“BOE”) at the rate of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of oil.

The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to accumulated DD&A.

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

In accordance with ASC 360-10, 205, 840, 958, and 855-10-60-1 (formerly SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”), EAC assesses the need for an impairment of long-lived assets to be held and used, including proved oil and natural gas properties, whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then an impairment charge is recognized to the extent the asset’s carrying value exceeds its fair value. Expected future net cash flows are based on existing proved reserves (and appropriately risk-adjusted probable reserves), forecasted production information, and management’s outlook of future commodity prices. Any impairment charge incurred is expensed and reduces the net basis in the asset. Management aggregates proved property for impairment testing the same way as for calculating DD&A. The price assumptions used to calculate undiscounted cash flows is based on judgment. EAC uses prices consistent with the prices it believes a market participant would use in bidding on acquisitions and/or assessing capital projects. These price assumptions are critical to the impairment analysis as lower prices could trigger impairment.

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

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

	December 31,
	2009		2008
	(In thousands)
Proved leasehold costs	$	1,782,042	$	1,421,859
Wells and related equipment — Completed		2,408,662		1,943,275
Wells and related equipment — In process		13,918		173,325
Total proved properties	$	4,204,622	$	3,538,459

Other Property and Equipment.  Other property and equipment is carried at cost. Depreciation is expensed on a straight-line basis over estimated useful lives, which range from three to seven years. Leasehold improvements are capitalized and depreciated over the remaining term of the lease, which is through 2013 for EAC’s corporate headquarters. Gains or losses from the disposal of other property and equipment are

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recognized in the period realized and included in “Other operating expense” in the accompanying Consolidated Statements of Operations.

Goodwill and Other Intangible Assets

EAC accounts for goodwill and other intangible assets under the provisions of ASC 350, 730-10-60-3, 323-10-35-13, 205-20-60-4, and 280-10-60-2 (formerly SFAS No. 142, “Goodwill and Other Intangible Assets”). Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is tested for impairment annually on December 31 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level. EAC has determined that it has two reporting units: EAC Standalone and ENP. As of December 31, 2009, ENP has been allocated $9.3 million of goodwill and the remainder has been allocated to the EAC Standalone segment. If indicators of impairment are determined to exist, an impairment charge is recognized for the amount by which the carrying value of goodwill exceeds its implied fair value.

EAC utilizes both a market capitalization and an income approach to determine the fair value of its reporting units. The primary component of the income approach is the estimated discounted future net cash flows expected to be recovered from the reporting unit’s oil and natural gas properties. EAC’s analysis concluded that there was no impairment of goodwill as of December 31, 2009. Significant decreases in the prices of oil and natural gas or significant negative reserve adjustments from the December 31, 2009 assessment could change EAC’s estimates of the fair value of its reporting units and could result in an impairment charge.

Intangible assets with definite useful lives are amortized over their estimated useful lives. In accordance with ASC 410-20, 450-20, 835-20, 360-10-35, 840-10, and 980-410, EAC evaluates the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.

ENP is a party to a contract allowing it to purchase a certain amount of natural gas at a below market price for use as field fuel. As of December 31, 2009, the gross carrying value of this contact was $4.2 million and accumulated amortization was $0.9 million. During each of 2009, 2008, and 2007, ENP recorded approximately $0.3 million of amortization expense related to this contract. The net carrying value is included in “Other noncurrent assets” on the accompanying Consolidated Balance Sheets and is being amortized on a straight-line basis through November 2020. ENP expects to recognize $0.3 million of amortization expense during each of the next five years related to this contract.

In July 2009, EAC acquired a private company for $24 million in cash, which procured a carbon dioxide (“CO₂”) supply intended to be used for a tertiary oil recovery project in EAC’s Bell Creek Field. The CO₂ purchasable is not transportable as capture and compression facilities and a related pipeline need to be built. Until the CO₂ can be transported to the field and the capture, compression, and injection of the CO₂ proves economic, the contract has an unknown useful life. This contract is included in “Other noncurrent assets” on the accompanying Consolidated Balance Sheet.

Asset Retirement Obligations

In accordance with ASC 410-20, 450-20, 835-20, 360-10-35, 840-10, and 980-410 (formerly SFAS No. 143, “Accounting for Asset Retirement Obligations”), EAC recognizes the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which the property is acquired or a new well is drilled. An amount equal to and offsetting the liability is capitalized as part of the carrying amount of EAC’s oil and natural gas properties.

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The liability is recorded at its risk adjusted discounted fair value and then accreted each period until it is settled or the asset is sold, at which time the liability is reversed. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining field life based on reserve estimates. Please read “Note 5. Asset Retirement Obligations” for additional information.

Equity-Based Compensation

EAC accounts for equity-based compensation according to the provisions of ASC 718, 505-50, and 260-10-60-1A formerly SFAS No. 123 (revised 2004), “Share-Based Payment”), which requires the recognition of compensation expense for equity-based awards over the requisite service period in an amount equal to the grant date fair value of the awards. EAC utilizes a standard option pricing model (i.e., Black-Scholes) to measure the fair value of employee stock options under ASC 718, 505-50, and 260-10-60-1A. Please read “Note 11. Employee Benefit Plans” for additional discussion of EAC’s employee benefit plans.

ASC 718, 505-50, and 260-10-60-1A also requires that the benefits associated with the tax deductions in excess of recognized compensation cost be reported as a financing cash flow. This requirement reduces net operating cash flows and increases net financing cash flows. EAC recognizes compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards. Compensation expense associated with awards to employees who are eligible for retirement is fully expensed on the date of grant.

Segment Reporting

EAC operates in only one industry: the oil and natural gas exploration and production industry in the United States. However, EAC is organizationally structured along two reportable segments: EAC Standalone and ENP. EAC’s segments are components of its business for which separate financial information related to operating and development costs are available and regularly evaluated by the chief operating decision maker in deciding how to allocate capital resources to projects and in assessing performance. Please read “Note 16. Segment Information” for additional discussion.

Major Customers/Concentration of Credit Risk

The following purchasers accounted for 10 percent or greater of the sales of production for the period indicated:

	Percentage of Total Sales of Production for the Year Ended December 31,
	2009			2008			2007
Consolidated EAC
Eight-Eight Oil		18	%		14	%		14	%
Tesoro Refining & Marketing Co		(a	)		12	%		(a	)
ENP
Marathon Oil Corporation		42	%		19	%		24	%
ConocoPhillips		(a	)		17	%		10	%
Tesoro Refining & Marketing Co		(a	)		15	%		17	%
EAC Standalone
Eight-Eight Oil		22	%		23	%		29	%
Tesoro Refining & Marketing Co		(a	)		13	%		(a	)

(a) Less than 10 percent for the period indicated.

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Income Taxes

Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Valuation allowances are established when necessary to reduce net deferred tax assets to amounts expected to be realized. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.

EAC accounts for uncertainty in income taxes in accordance with ASC 740, 805-740, and 835-10 (formerly FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109”). ASC 740, 805-740, and 835-10 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. EAC and its subsidiaries file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, EAC is no longer subject to U.S. federal, state, and local income tax examinations for years prior to 2004.

EAC performs a periodic evaluation of tax positions to review the appropriate recognition threshold for each tax position recognized in EAC’s financial statements, including, but not limited to:

•  a review of documentation of tax positions taken on previous returns including an assessment of whether EAC followed industry practice or the applicable requirements under the tax code;

•  a review of open tax returns (on a jurisdiction by jurisdiction basis) as well as supporting documentation used to support those tax returns;

•  a review of the results of past tax examinations;

•  a review of whether tax returns have been filed in all appropriate jurisdictions;

•  a review of existing permanent and temporary differences; and

•  consideration of any tax planning strategies that may have been used to support realization of deferred tax assets.

As of December 31, 2009 and 2008, all of EAC’s tax positions met the “more-likely-than-not” threshold prescribed by ASC 740, 805-740, and 835-10. As a result, no additional tax expense, interest, or penalties have been accrued. EAC includes interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its Consolidated Statements of Operations. For 2009, 2008, and 2007, EAC recorded only a nominal amount of interest and penalties on certain tax positions.

Oil and Natural Gas Revenue Recognition

Oil and natural gas revenues are recognized as oil and natural gas is produced and sold, net of royalties and net profits interests. Royalties, net profits interests, and severance taxes are incurred based upon the actual price received from the sales. To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Accounts receivable, net” in the accompanying Consolidated Balance Sheets. Natural gas revenues are reduced by any processing and other fees incurred except for transportation costs paid to third parties, which are recorded in “Other operating expense” in the accompanying Consolidated Statements of Operations. Natural gas revenues are recorded using the sales method of accounting whereby revenue is recognized based on actual sales of natural gas rather than EAC’s proportionate share of natural gas production. If EAC’s overproduced imbalance position (i.e., EAC has cumulatively been over-allocated production) is greater than EAC’s share of remaining reserves, a liability is recorded for the excess at period-end prices unless a different price is specified in the contract in which case

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that price is used. Revenue is not recognized for the production in tanks, oil marketed on behalf of joint owners in EAC’s properties, or oil in pipelines that has not been delivered to the purchaser.

EAC’s net oil inventories in pipelines were 117,363 Bbls and 173,119 Bbls at December 31, 2009 and 2008, respectively. Natural gas imbalances at December 31, 2009 were 456,912 million British thermal units (“MMBtu”) over-delivered to EAC, the value of which was approximately $2.3 million. Natural gas imbalances at December 31, 2008, were 28,717 MMBtu under-delivered to EAC the value of which was approximately $0.1 million.

Marketing Revenues and Expenses

In March 2007, ENP acquired a crude oil pipeline and a natural gas pipeline as part of the Elk Basin acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets. In addition, pipeline tariffs are collected for transportation through the crude oil pipeline.

Marketing revenues include the sales of oil and natural gas purchased from third parties as well as pipeline tariffs charged for transportation volumes through EAC’s pipelines. Marketing revenues derived from sales of oil and natural gas purchased from third parties are recognized when persuasive evidence of a sales arrangement exists, delivery has occurred, the sales price is fixed or determinable, and collectibility is reasonably assured. As EAC takes title to the oil and natural gas and has risks and rewards of ownership, these transactions are presented gross in the accompanying Consolidated Statements of Operations, unless they meet the criteria for netting as outlined in ASC 845-10 (formerly EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”).

Shipping Costs

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

Derivatives

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

EAC applies the provisions of ASC 815 (formerly SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”), which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, the effective portion of changes in fair value can be recognized in accumulated other comprehensive income or loss until such time as the hedged item is recognized in earnings. In order to qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically.

EAC has elected to designate its outstanding interest rate swaps as cash flow hedges. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in “Accumulated other

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comprehensive loss” on the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized in earnings and included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.

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

Earnings Per Share

For purposes of calculating earnings per share, EAC allocates net income (loss) to its shareholders and participating securities each quarter under the provisions of ASC 260-10 (formerly EITF Issue No. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128”). Under the two-class method of calculating earnings per share as prescribed by ASC 260-10, earnings are allocated to participating securities as if all the earnings for the period had been distributed. A participating security is any security that may participate in distributions with common shares. For purposes of calculating earnings per share, unvested restricted stock awards are considered participating securities. Net income (loss) per common share is calculated by dividing the shareholders’ interest in net income (loss), after deducting the interests of participating securities, by the weighted average common shares outstanding. Please read “New Accounting Pronouncements” below and “Note 10. Earnings Per Share” for additional discussion.

Comprehensive Income (Loss)

EAC has elected to show comprehensive income (loss) as part of its Consolidated Statements of Equity and Comprehensive Income (Loss) rather than in its Consolidated Statements of Operations or as a separate statement.

FASB Launches Accounting Standards Codification

In June 2009, the FASB issued ASC 105-10 (formerly SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles”). ASC 105-10 establishes the Codification as the sole source of authoritative accounting principles recognized by the FASB to be applied by all nongovernmental entities in the preparation of financial statements in conformity with GAAP. ASC 105-10 was prospectively effective for financial statements issued for fiscal years ending on or after September 15, 2009, and interim periods within those fiscal years. The adoption of ASC 105-10 on July 1, 2009 did not impact EAC’s results of operations or financial condition.

Following the Codification, the FASB does not issue new standards in the form of Statements, FASB Staff Positions (“FSP”), or EITF Abstracts. Instead, it issues Accounting Standards Updates (“ASU”), which update the Codification, provide background information about the guidance, and provide the basis for conclusions on the changes to the Codification.

The Codification did not change GAAP; however, it did change the way GAAP is organized and presented. As a result, these changes impact how companies, including EAC, reference GAAP in their financial statements and in their significant accounting policies.

New Accounting Pronouncements

ASC 820-10 (formerly FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157”)

In February 2008, the FASB issued ASC 820-10, which delayed the effective date of ASC 820-10 for one year for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the

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financial statements on a recurring basis (at least annually). ASC 820-10 was prospectively effective for financial statements issued for fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. EAC elected a partial deferral of ASC 820-10 for all instruments within the scope of ASC 820-10, including, but not limited to, its asset retirement obligations and indefinite lived assets. The adoption of ASC 820-10 on January 1, 2009 as it relates to nonfinancial assets and liabilities did not have a material impact on EAC’s results of operations or financial condition. Please read “Note 12. Fair Value Measurements” for additional discussion.

ASC 805 (formerly SFAS No. 141 (revised 2007), “Business Combinations”)

In December 2007, the FASB issued ASC 805, which establishes principles and requirements for the reporting entity in a business combination, including: (1) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. In April 2009, the FASB issued ASC 805-20 (formerly FSP No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arises from Contingencies”), which amends and clarifies ASC 805 to address application issues, including: (1) initial recognition and measurement; (2) subsequent measurement and accounting; and (3) disclosure of assets and liabilities arising from contingencies in a business combination. ASC 805 and ASC 805-20 were prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008. The application of ASC 805 and ASC 805-20 to the acquisition of certain oil and natural gas properties and related assets in the Mid-Continent and East Texas resulted in the expensing of approximately $1.5 million of transaction costs. Please read “Note 3. Acquisitions and Dispositions” for additional discussion.

ASC 810-10-65-1 (formerly SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment to ARB No. 51)

In December 2007, the FASB issued ASC 810-10-65-1, which establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. ASC 810-10-65-1 was prospectively effective for financial statements issued for fiscal years beginning on or after December 15, 2008, except for the presentation and disclosure requirements which were retrospectively effective. ASC 810-10-65-1 clarifies that a noncontrolling interest in a subsidiary, which was often referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, ASC 810-10-65-1 requires consolidated net income to be reported for the amounts attributable to both the parent and the noncontrolling interest on the face of the consolidated statement of operations and gains or losses on a subsidiaries’ issuance of equity to be accounted for as capital transactions. The adoption of ASC 810-10-65-1 on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition. The retrospective application of ASC 810-10-65-1 resulted in the reclassification of approximately $169.1 million from “Minority interest in consolidated partnership” to “Noncontrolling interest” at December 31, 2008 on the accompanying Consolidated Balance Sheets.

ASC 815-10 (formerly SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133”)

In March 2008, the FASB issued ASC 815-10, which requires enhanced disclosures: including (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under ASC 815; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. ASC 815-10 was prospectively effective for financial

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statements issued for fiscal years beginning on or after November 15, 2008, and interim periods within those fiscal years. The adoption of ASC 815-10 on January 1, 2009 required additional disclosures regarding EAC’s derivative instruments; however, it did not impact EAC’s results of operations or financial condition. Please read “Note 12. Fair Value Measurements” for additional discussion.

ASC 260-10 (formerly FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”)

In June 2008, the FASB issued ASC 260-10, which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation for computing basic earnings per share under the two-class method. ASC 260-10 was retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. In the accompanying Consolidated Financial Statements, periods prior to the adoption of ASC 260-10 have been restated to calculate earnings per share in accordance with this pronouncement. The retrospective application of ASC 260-10 reduced EAC’s basic earnings per share by $0.14 for the year ended December 31, 2008 and reduced EAC’s diluted earnings per share by $0.06 and $0.01 for the years ended December 31, 2008 and 2007, respectively. The adoption of ASC 260-10 did not have an impact on EAC’s basic earnings per share for the year ended December 31, 2007. Please read “Note 10. Earnings Per Unit” for additional discussion.

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

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

ASC 855-10 (formerly SFAS No. 165, “Subsequent Events”)

In June 2009, the FASB issued ASC 855-10 to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or available to be issued. In particular, ASC 855-10 sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. ASC 855-10 was prospectively effective for financial statements issued for interim or annual periods ending after June 15, 2009. The adoption of ASC 855-10 on June 30, 2009 did not impact EAC’s results of operations or financial condition.

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ASU No. 2009-05, “Fair Value Measurement and Disclosure: Measuring Liabilities at Fair Value” (“ASU 2009-05”)

In August 2009, the FASB issued ASU 2009-05 to provide clarification on measuring liabilities at fair value when a quoted price in an active market is not available. In particular, ASU 2009-05 specifies that a valuation technique should be applied that used either the quote of the liability when traded as an asset, the quoted prices for similar liabilities or similar liabilities when traded as assets, or another valuation technique consistent with existing fair value measurement guidance. ASU 2009-05 was prospectively effective for financial statements issued for interim or annual periods ending after October 1, 2009. The adoption of ASU 2009-05 on December 31, 2009 did not impact EAC’s results of operations or financial condition.

ASU No. 2010-03, “Oil and Gas Reserve Estimation and Disclosure” (“ASU 2010-03”)

In January 2010, the FASB issued ASU 2010-03 to align the oil and natural gas reserve estimation and disclosure requirements of Extractive Activities — Oil and Gas (ASC 932) with the requirements in the SEC’s final rule, “Modernization of the Oil and Gas Reporting.” ASU 2010-03 was prospectively effective for financial statements issued for annual periods ending on or after December 31, 2009.

ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements” (“ASU 2010-06”)

In January 2010, the FASB issued ASU 2010-06 to require additional information to be disclosed principally in respect of level 3 fair value measurements and transfers to and from Level 1 and Level 2 measurements; in addition, enhanced disclosure is required concerning inputs and valuation techniques used to determine Level 2 and Level 3 fair value measurements. ASU 2010-06 was generally effective for interim and annual reporting periods beginning after December 15, 2009; however, the requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years) with early adoption allowed. The adoption of ASU 2010-06 on December 31, 2009 did not impact EAC’s results of operations or financial condition.

Note 3.   Acquisitions and Dispositions

Acquisitions

EXCO.  In August 2009, EAC acquired certain oil and natural gas properties and related assets in the Mid-Continent and East Texas from EXCO Resources, Inc. (together with its affiliates, “EXCO”) for approximately $357.4 million in cash, substantially all of which are proved producing. The operations of these properties have been included with those of EAC from the date of acquisition forward. EAC financed the acquisitions through borrowings under its revolving credit facility and proceeds from the issuance of ENP common units to the public.

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The allocation of the purchase price to the fair value of the assets acquired and liabilities assumed from EXCO were as follows (in thousands):

Proved properties, including wells and related equipment	$	367,341
Accounts receivable		6,191
Other property and equipment		435
Total assets acquired		373,967
Current liabilities		4,791
Future abandonment cost		11,764
Total liabilities assumed		16,555
Fair value of net assets acquired	$	357,412

Vinegarone.  In May 2009, ENP acquired certain natural gas properties in the Vinegarone Field in Val Verde County, Texas (the “Vinegarone Assets”) from an independent energy company for approximately $27.5 million in cash, which was financed through proceeds from the issuance of ENP common units to the public. The results of operations of the Vinegarone Assets are included with those of EAC from the date of acquisition forward.

Anadarko.  In April 2007, EAC acquired certain oil and natural gas properties and related assets in the Williston Basin of Montana and North Dakota from certain subsidiaries of Anadarko Petroleum Corporation (“Anadarko”) for approximately $392.1 million in cash. The operations of these properties have been included with those of EAC from the date of acquisition forward. EAC financed the acquisition through borrowings under its revolving credit facility.

In March 2007, EAC acquired certain oil and natural gas properties and related assets in the Big Horn Basin of Wyoming and Montana, which included oil and natural gas properties and related assets in or near the Elk Basin field in Park County, Wyoming and Carbon County, Montana and oil and natural gas properties and related assets in the Gooseberry field in Park County, Wyoming, from Anadarko for approximately $393.6 million in cash. Prior to closing, EAC assigned the rights and duties under the purchase and sale agreement relating to the Elk Basin assets to Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly owned subsidiary of ENP, and the rights and duties under the purchase and sale agreement relating to the Gooseberry assets to Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly owned guarantor subsidiary of EAC. The operations of these properties have been included with those of EAC from the date of acquisition forward. EAC financed the acquisitions of the Gooseberry assets and Williston Basin assets through borrowings under its revolving credit facility. ENP financed the acquisition of the Elk Basin assets through a $93.7 million contribution from EAC, $120 million of borrowings under a subordinated credit agreement with EAP Operating, LLC, a Delaware limited liability company and direct wholly owned guarantor subsidiary of EAC, and borrowings under OLLC’s revolving credit facility.

Dispositions

Mid-Continent.  In June 2007, EAC completed the sale of certain oil and natural gas properties in the Mid-Continent area, and in July 2007, additional Mid-Continent properties that were subject to preferential rights were sold. EAC received total net proceeds of approximately $294.8 million, after deducting transaction costs of approximately $3.6 million, and recorded a loss on sale of approximately $7.4 million. The disposed properties included certain properties in the Anadarko and Arkoma Basins of Oklahoma. EAC retained material oil and natural gas interests in other properties in these basins and remains active in those areas.

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Proceeds from the Mid-Continent asset disposition were used to reduce outstanding borrowings under EAC’s revolving credit facility.

Pro Formas

The following unaudited pro forma condensed financial data was derived from the historical financial statements of EAC and from the accounting records of Anadarko and EXCO to give effect to the Anadarko asset acquisitions, the EXCO asset acquisitions, and the Mid-Continent asset disposition as if they had each occurred on January 1, 2007. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Anadarko asset acquisitions, the EXCO asset acquisitions, and the Mid-Continent asset disposition taken place on January 1, 2007 and is not intended to be a projection of future results.

	Year Ended December 31,
	2009			2008		2007
	(In thousands, except per share amounts)
Pro forma total revenues	$	727,343		$	1,294,513	$	854,388
Pro forma net income (loss) attributable to EAC stockholders	$	(77,741	)	$	483,231	$	48,004
Pro forma net income (loss) per common share:
Basic	$	(1.48	)	$	9.14	$	0.90
Diluted	$	(1.48	)	$	9.04	$	0.89

Note 4.   Commitments and Contingencies

Litigation

EAC is a party to ongoing legal proceedings in the ordinary course of business. Management does not believe the result of these proceedings will have a material adverse effect on EAC’s business, financial position, results of operations, or liquidity.

Three shareholder lawsuits styled as class actions have been filed against EAC and the Board related to the Merger. The lawsuits are entitled:

(1) Sanjay Israni, Individually and On Behalf of All Others Similarly Situated vs. Encore Acquisition Company et al. (filed November 4, 2009 in the District Court of Tarrant County, Texas);

(2) Teamsters Allied Benefit Funds, Individually and On Behalf of All Others Similarly Situated vs. Encore Acquisition Company et al. (filed November 5, 2009 in the Court of Chancery in the State of Delaware); and

(3) Thomas W. Scott, Jr., individually and on behalf of all others similarly situated v. Encore Acquisition Company et al. (filed November 6, 2009 in the District Court of Tarrant County, Texas).

The Teamsters and Scott lawsuits also name Denbury as a defendant. The complaints generally allege that (1) EAC’s directors breached their fiduciary duties in negotiating and approving the Merger and by administering a sale process that failed to maximize shareholder value and (2) EAC, and, in the case of the Teamsters and Scott complaints, Denbury aided and abetted EAC’s directors in breaching their fiduciary duties. The Teamsters complaint also alleges that EAC’s directors and executives stand to receive substantial financial benefits if the Merger is consummated on its current terms. The plaintiffs in these lawsuits seek, among other things, to enjoin the Merger and to rescind the Merger Agreement. EAC and Denbury have entered into a Memorandum of Understanding with the plaintiffs in these lawsuits agreeing in principle to the settlement of the lawsuits based upon inclusion in the joint proxy statement/prospectus of additional disclosures requested

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by the plaintiffs, and agreeing that the parties to the lawsuits will use best efforts to enter into a definitive settlement agreement and seek court approval for the settlement which would be binding on all EAC shareholders who do not opt-out of the settlement.

Leases

EAC leases office space and equipment that have non-cancelable lease terms in excess of one year. The following table summarizes by year the remaining non-cancelable future payments under these operating leases as of December 31, 2009 (in thousands):

2010	$	3,635
2011		3,597
2012		3,358
2013		2,607
2014		—
Thereafter		—
	$	13,197

EAC’s operating lease rental expense was approximately $4.9 million, $5.8 million, and $5.5 million in 2009, 2008, and 2007, respectively.

Note 5.   Asset Retirement Obligations

Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in EAC’s asset retirement obligations for the periods indicated:

	Year Ended December 31,
	2009			2008
	(In thousands)
Future abandonment liability at January 1	$	49,569		$	28,079
Wells drilled		300			498
Acquisition of properties		3,666			111
Disposition of properties		(220	)		—
Accretion of discount		2,400			1,361
Plugging and abandonment costs incurred		(1,576	)		(1,756	)
Revision of previous estimates		(255	)		21,276
Future abandonment liability at December 31	$	53,884		$	49,569

As of December 31, 2009, $52.4 million of EAC’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $1.5 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheets. Approximately $4.7 million of the long-term future abandonment liability represents the estimated cost for decommissioning ENP’s Elk Basin natural gas processing plant.

As of December 31, 2009 and 2008, EAC held $9.3 million and $9.2 million, respectively, in escrow, which is to be released only for reimbursement of actual plugging and abandonment costs incurred on its Bell Creek properties. These amounts are included in “Other assets” in the accompanying Consolidated Balance Sheets.

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Note 6.   Capitalization of Exploratory Well Costs

EAC continues the capitalization of exploratory well costs if the well found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The following table reflects the net changes in capitalized exploratory well costs during the periods indicated, and does not include amounts that were capitalized and subsequently expensed in the same period:

	Year Ended December 31,
	2009			2008			2007
	(In thousands)
Beginning balance at January 1	$	28,757		$	19,479		$	13,048
Additions to capitalized exploratory well costs
pending the determination of proved reserves		8,241			28,757			19,479
Reclassification to proved property and equipment
based on the determination of proved reserves		(15,054	)		(19,229	)		(9,390	)
Previously capitalized exploratory well costs charged to expense		(13,703	)		(250	)		(3,658	)
Ending balance at December 31	$	8,241		$	28,757		$	19,479

All capitalized exploratory well costs have been capitalized for less than one year.

Note 7.   Long-Term Debt

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

	Maturity		December 31,
	Date		2009		2008
			(In thousands)
Revolving credit facilities		3/7/2012	$	410,000	$	725,000
6.25% Senior Subordinated Notes		4/15/2014		150,000		150,000
6.0% Senior Subordinated Notes, net of unamortized discount of $3,449 and $3,960, respectively		7/15/2015		296,551		296,040
9.5% Senior Subordinated Notes, net of unamortized discount of $16,327 and zero, respectively		5/1/2016		208,673		—
7.25% Senior Subordinated Notes, net of unamortized discount of $1,127 and $1,229, respectively		12/1/2017		148,873		148,771
Total			$	1,214,097	$	1,319,811

Senior Subordinated Notes

In April 2009, EAC issued $225 million of its 9.5% Senior Subordinated Notes due 2016 (the “9.5% Notes”) at 92.228 percent of par value. EAC used the net proceeds of approximately $202.4 million, after deducting the underwriters’ discounts and commissions of $4.5 million, in the aggregate, and offering expenses of approximately $0.6 million to reduce outstanding borrowings under its revolving credit facility. Interest on the 9.5% Notes is due semi-annually on May 1 and November 1, beginning November 1, 2009. The 9.5% Notes mature on May 1, 2016.

As of December 31, 2009, certain of EAC’s subsidiaries were subsidiary guarantors of EAC’s senior subordinated notes. The subsidiary guarantors may without restriction transfer funds to EAC in the form of

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cash dividends, loans, and advances. Please read “Note 14. Financial Statements of Subsidiary Guarantors” for additional discussion.

The indentures governing EAC’s senior subordinated notes contain certain affirmative, negative, and financial covenants, which include:

•  limitations on incurrence of additional debt, restrictions on asset dispositions, and restricted payments;

•  a requirement that EAC maintain a current ratio (as defined in the indentures) of not less than 1.0 to 1.0; and

•  a requirement that EAC maintain a ratio of consolidated EBITDA (as defined in the indentures) to consolidated interest expense of not less than 2.5 to 1.0.

As of December 31, 2009, EAC was in compliance with all covenants of its senior subordinated notes.

If EAC experiences a change of control (as defined in the indentures), subject to certain conditions, it must give holders of its senior subordinated notes the opportunity to sell them to EAC at 101 percent of the principal amount, plus accrued and unpaid interest.

Revolving Credit Facilities

Encore Acquisition Company Credit Agreement

EAC is a party to a five-year amended and restated credit agreement dated March 7, 2007 (as amended, the “EAC Credit Agreement”). The EAC Credit Agreement matures on March 7, 2012. In March 2009, EAC amended the EAC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the EAC Credit Agreement.

The EAC Credit Agreement provides for revolving credit loans to be made to EAC from time to time and letters of credit to be issued from time to time for the account of EAC or any of its restricted subsidiaries. The aggregate amount of the commitments of the lenders under the EAC Credit Agreement is $1.25 billion. Availability under the EAC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. In March 2009, the borrowing base of the EAC Credit Agreement was reaffirmed at $1.1 billion before a reduction of $200 million solely as a result of the monetization of certain of EAC’s 2009 oil derivative contracts during the first quarter of 2009. In April 2009, the borrowing base of the EAC Credit Agreement was reduced by $75 million as a result of EAC’s issuance of the 9.5% Notes. The reductions in the borrowing base under the EAC Credit Agreement did not result in any required prepayments of indebtedness. In December 2009, EAC amended the EAC Credit Agreement to, among other things, increase the borrowing base under the EAC Credit Agreement to $925 million. As of December 31, 2009, the borrowing base was $925 million and there were $155 million of outstanding borrowings, $0.3 million of outstanding letters of credit, and $769.7 million of borrowing capacity under the EAC Credit Agreement.

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

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

Obligations under the EAC Credit Agreement are secured by a first-priority security interest in substantially all of EAC’s restricted subsidiaries’ proved oil and natural gas reserves and in EAC’s equity

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interests in its restricted subsidiaries. In addition, obligations under the EAC Credit Agreement are guaranteed by EAC’s restricted subsidiaries.

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

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

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

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

The EAC Credit Agreement contains covenants including, among others, the following:

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

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

•  a restriction on creating liens on the assets of EAC and its restricted subsidiaries, subject to permitted exceptions;

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

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

•  a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

•  a requirement that EAC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0; and

•  a requirement that EAC maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0.

As of December 31, 2009, EAC was in compliance with all covenants of the EAC Credit Agreement.

The EAC Credit Agreement contains customary events of default including, among others, the following:

•  failure to pay principal on any loan when due;

•  failure to pay accrued interest on any loan or fees when due and such failure continues for more than three days;

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•  failure to observe or perform covenants and agreements contained in the EAC Credit Agreement, subject in some cases to a 30-day grace period after discovery or notice of such failure;

•  failure to make a payment when due on any other debt in a principal amount equal to or greater than $15 million or any other event or condition occurs which results in the acceleration of such debt or entitles the holder of such debt to accelerate the maturity of such debt;

•  the commencement of liquidation, reorganization, or similar proceedings with respect to EAC or any guarantor under bankruptcy or insolvency law, or the failure of EAC or any guarantor generally to pay its debts as they become due;

•  the entry of one or more judgments in excess of $15 million (to the extent not covered by insurance) and such judgment(s) remain unsatisfied and unstayed for 30 days;

•  the occurrence of certain ERISA events involving an amount in excess of $15 million;

•  there cease to exist liens covering at least 80 percent of the borrowing base properties; or

•  the occurrence of a change in control.

If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the EAC Credit Agreement to be immediately due and payable.

Encore Energy Partners Operating LLC Credit Agreement

OLLC is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “OLLC Credit Agreement”). The OLLC Credit Agreement matures on March 7, 2012. In March 2009, OLLC amended the OLLC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. In August 2009, OLLC amended the OLLC Credit Agreement to, among other things, (1) increase the borrowing base from $240 million to $375 million, (2) increase the aggregate commitments of the lenders from $300 million to $475 million, and (3) increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. In November 2009, OLLC amended the OLLC Credit Agreement, which will be effective upon the closing of the Merger, to, among other things, (1) permit the consummation of the Merger from being a “Change of Control” under the OLLC Credit Agreement.

The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries. The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $475 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. As of December 31, 2009, the borrowing base was $375 million and there were $255 million of outstanding borrowings and $120 million of borrowing capacity under the OLLC Credit Agreement.

OLLC incurs a commitment fee of 0.5 percent on the unused portion of the OLLC Credit Agreement.

Obligations under the OLLC Credit Agreement are secured by a first-priority security interest in substantially all of OLLC’s proved oil and natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition, obligations under the OLLC Credit Agreement are guaranteed by ENP and OLLC’s restricted subsidiaries. EAC consolidates the debt of ENP with that of its own; however, obligations under the OLLC Credit Agreement are non-recourse to EAC and its restricted subsidiaries.

Loans under the OLLC Credit Agreement are subject to varying rates of interest based on (1) amount outstanding in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan.

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

	Applicable Margin for			Applicable Margin for
Ratio of Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		2.250	%		1.250	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.500	%		1.500	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.750	%		1.750	%
Greater than or equal to .90 to 1		3.000	%		2.000	%

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

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

The OLLC Credit Agreement contains covenants including, among others, the following:

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

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

•  a restriction on creating liens on the assets of ENP, OLLC, and OLLC’s restricted subsidiaries, subject to permitted exceptions;

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

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

•  a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

•  a requirement that ENP and OLLC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0;

•  a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0; and

•  a requirement that ENP and OLLC maintain a ratio of consolidated funded debt to consolidated adjusted EBITDA of not more than 3.5 to 1.0.

As of December 31, 2009, ENP and OLLC were in compliance with all covenants of the OLLC Credit Agreement.

The OLLC Credit Agreement contains customary events of default including, among others, the following:

•  failure to pay principal on any loan when due;

•  failure to pay accrued interest on any loan or fees when due and such failure continues for more than three days;

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•  failure to observe or perform covenants and agreements contained in the OLLC Credit Agreement, subject in some cases to a 30-day grace period after discovery or notice of such failure;

•  failure to make a payment when due on any other debt in a principal amount equal to or greater than $3 million or any other event or condition occurs which results in the acceleration of such debt or entitles the holder of such debt to accelerate the maturity of such debt;

•  the commencement of liquidation, reorganization, or similar proceedings with respect to OLLC or any guarantor under bankruptcy or insolvency law, or the failure of OLLC or any guarantor generally to pay its debts as they become due;

•  the entry of one or more judgments in excess of $3 million (to the extent not covered by insurance) and such judgment(s) remain unsatisfied and unstayed for 30 days;

•  the occurrence of certain ERISA events involving an amount in excess of $3 million;

•  there cease to exist liens covering at least 80 percent of the borrowing base properties; or

•  the occurrence of a change in control.

If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately due and payable.

Long-Term Debt Maturities

The following table shows EAC’s long-term debt maturities as of December 31, 2009:

	Payments Due by Period
	Total		2010		2011		2012		2013		2014		Thereafter
	(In thousands)
6.25% Notes	$	150,000	$	—	$	—	$	—	$	—	$	150,000	$	—
6.0% Notes		300,000		—		—		—		—		—		300,000
9.5% Notes		225,000		—		—		—		—		—		225,000
7.25% Notes		150,000		—		—		—		—		—		150,000
Revolving credit facilities		410,000		—		—		410,000		—		—		—
Total	$	1,235,000	$	—	$	—	$	410,000	$	—	$	150,000	$	675,000

During 2009, 2008, and 2007, the weighted average interest rate for total indebtedness was 5.8 percent, 5.6 percent, and 6.9 percent, respectively.

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Note 8.   Taxes

Income Taxes

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

	Year Ended December 31,
	2009			2008			2007
	(In thousands)
Federal:
Current	$	(14,638	)	$	(7,626	)	$	(1,888	)
Deferred		55,149			(222,651	)		(11,229	)
Total federal		40,511			(230,277	)		(13,117	)
State, net of federal benefit:
Current		(4,469	)		(1,381	)		—
Deferred		(3,869	)		(9,963	)		(1,359	)
Total state		(8,338	)		(11,344	)		(1,359	)
Income tax benefit (provision)(a)	$	32,173		$	(241,621	)	$	(14,476	)

(a) Excludes an excess tax benefit related to stock option exercises and vesting of restricted stock, which was recorded directly to additional paid-in capital, of $0.3 million and $2.1 million during 2009 and 2008, respectively. During 2007, EAC did not recognize an excess tax benefit related to stock option exercises and vesting of restricted stock.

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

	Year Ended December 31,
	2009			2008			2007
	(In thousands)
Income (loss) before income taxes	$	(113,308	)	$	672,433		$	31,631
Noncontrolling interest		(16,752	)		54,252			(7,478	)
Income (loss) before income taxes and noncontrolling interest	$	(130,060	)	$	726,685		$	24,153
Income taxes at the Federal statutory rate	$	45,521		$	(254,340	)	$	(8,454	)
State income taxes, net of federal benefit		2,943			(12,861	)		(716	)
Change in estimated future state tax rate		(9,075	)		2,113			(495	)
Tax on income attributable to noncontrolling interest		(5,863	)		18,988			(2,617	)
Provision to return adjustment		(1,910	)		246			11
Nondeductible deferred compensation expense		—			(1,124	)		(1,963	)
Permanent and other		557			5,357			(242	)
Income tax benefit (provision)	$	32,173		$	(241,621	)	$	(14,476	)

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The major components of net current deferred taxes and net long-term deferred taxes were as follows as of the dates indicated:

	December 31,
	2009			2008
	(In thousands)
Current:
Assets:
Unrealized hedge loss in accumulated other comprehensive loss	$	—		$	222
Net operating loss carryforward		1,312			—
Other		5,473			2,422
Total current deferred tax assets		6,785			2,644
Liabilities:
Prepaid insurance		(415	)		—
Unrealized hedge gain in accumulated other comprehensive loss		(136	)		—
Derivative fair value gain		(24,923	)		(108,412	)
Total current deferred tax liabilities		(25,474	)		(108,412	)
Net current deferred tax liability	$	(18,689	)	$	(105,768	)
Long-term:
Assets:
Alternative minimum tax credits	$	2,262		$	2,300
Unrealized hedge loss in accumulated other comprehensive loss		757			735
Derivative fair value loss		40,064			—
Tertiary recovery credits		3,385			8,889
Net operating loss carryforward		—			1,439
Change in accounting method		—			5,583
Asset retirement obligations		17,575			17,842
Deferred equity-based compensation		9,153			6,757
Acquisition cost capitalized		875			—
Other		211			1,556
Total long-term deferred tax assets		74,282			45,101
Liabilities:
Derivative fair value gain		—			(2,711	)
Book basis of oil and natural gas properties in excess of tax basis		(527,392	)		(459,305	)
Total long-term deferred tax liabilities		(527,392	)		(462,016	)
Net long-term deferred tax liability	$	(453,110	)	$	(416,915	)

At December 31, 2009, EAC had state net operating loss (“NOL”) carryforwards, which are available to offset future regular state taxable income, if any. At December 31, 2009, EAC also had federal alternative minimum tax (“AMT”) credits, which are available to reduce future federal regular tax liabilities in excess of AMT. EAC believes it is more likely than not that the NOL carryforwards will offset future taxable income prior to their expiration. The AMT credits have no expiration. Therefore, a valuation allowance against these

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deferred tax assets is not considered necessary. If unused, these carryforwards and credits will expire as follows:

	Federal		State
Expiration Date	AMT Credits		NOL
	(In thousands)
2012	$	—	$	51
2025		—		226
2026		—		152
2027		—		603
2028		—		420
Indefinite		2,262		—
	$	2,262	$	1,452

Note 9.   Equity

As discussed in “Note 1. Description of Business,” on October 31, 2009, EAC entered into the Merger Agreement with Denbury pursuant to which EAC will merge with and into Denbury, with Denbury as the surviving entity. The Merger Agreement provides for Denbury’s acquisition of all of the issued and outstanding shares of EAC common stock, par value $.01 per share, in a transaction valued at approximately $4.5 billion, including the assumption of debt and the value of the noncontrolling interest in ENP.

Stock Repurchase Programs

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

In December 2007, EAC announced that the Board approved a share repurchase program authorizing EAC to repurchase up to $50 million of its common stock. During 2008, EAC completed the share repurchase program by repurchasing and retiring 1,397,721 shares of its outstanding common stock at an average price of approximately $35.77 per share.

Stock Option Exercises and Restricted Stock Vestings

During 2009, 2008, and 2007, certain employees exercised 23,105 options, 45,616 options, and 128,709 options, respectively, for which EAC received proceeds of $0.5 million, $0.5 million, and $1.6 million, respectively. During 2009, 2008, and 2007, certain employees elected to satisfy minimum tax withholding obligations in conjunction with the vesting of restricted stock by directing EAC to withhold 111,819 shares, 32,946 shares, and 38,978 shares of common stock, respectively, which are accounted for as treasury stock until they are formally retired. Please read “Note 11. Employee Benefit Plans” for additional discussion of EAC’s stock option exercises and restricted stock vestings.

Preferred Stock

EAC’s authorized capital stock includes 5,000,000 shares of preferred stock, none of which were issued and outstanding at December 31, 2009 or 2008. EAC does not plan to issue any shares of preferred stock.

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Issuance of EAC Common Stock

In September 2009, EAC issued 2,750,000 shares of common stock under its shelf registration statement at a price to the public of $37.40 per common share. EAC used the net proceeds of approximately $100.6 million, after deducting the underwriters’ discounts and commissions of $2.0 million, in the aggregate, and offering costs of approximately $0.2 million, to reduce outstanding borrowings under the EAC Credit Agreement.

Issuances of ENP Common Units

In July 2009, ENP issued 9,430,000 common units under its shelf registration statement at a price to the public of $14.30 per common unit. As a result, EAC’s ownership of ENP’s common units decreased from approximately 58 percent to approximately 46 percent. Additionally, EAC increased “Noncontrolling interest” and “Additional paid-in capital” on the accompanying Consolidated Balance Sheets by $20.3 million to recognize gains on the issuance of ENP’s common units.

In May 2009, ENP issued 2,760,000 common units at a price to the public of $15.60 per common unit. As a result, EAC’s ownership of ENP’s common units decreased from approximately 63 percent to approximately 58 percent. Additionally, EAC increased “Noncontrolling interest” and “Additional paid-in capital” on the accompanying Consolidated Balance Sheets by $9.3 million to recognize gains on the issuance of ENP’s common units.

In May 2008, ENP acquired an existing net profits interest in certain of its properties in the Permian Basin of West Texas in exchange for 283,700 common units which were valued at $5.8 million at the time of the acquisition. As a result, EAC’s ownership of ENP’s common units decreased from approximately 67 percent to approximately 66 percent. Additionally, EAC increased “Noncontrolling interest” and “Additional paid-in capital” on the accompanying Consolidated Balance Sheets by $3.5 million to recognize gains on the issuance of ENP’s common units.

In December 2008, as a result of the conversion of ENP’s management incentive units into ENP common units, EAC recorded a $13.9 million economic uniformity adjustment by reducing “Additional paid-in capital” and increasing “Noncontrolling interest” in the accompanying Consolidated Balance Sheets.

In September 2007, ENP completed its IPO of 9,000,000 common units at a price to the public of $21.00 per unit, and in October 2007, the underwriters exercised their over-allotment option to purchase an additional 1,148,400 common units. As a result, EAC’s ownership of ENP’s common units decreased from 100 percent to approximately 58 percent. Additionally, EAC increased “Noncontrolling interest” and “Additional paid-in capital” on the accompanying Consolidated Balance Sheets by $77.6 million to recognize gains on the issuance of ENP’s common units.

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The following table summarizes EAC’s change of ownership in ENP since December 31, 2007:

	ENP Common Units Owned						EAC% of ENP			ENP GP Units		EAC % of
Date	EAC		Others		Total		Common Units			Owned by EAC		All ENP Units
12/31/2007		14,039,279		10,148,400		24,187,679		58.0	%		504,851		58.9	%
Issuance of common units in acquisition of Permian and Williston Basin Assets		6,884,776		—		6,884,776
2/7/2008		20,924,055		10,148,400		31,072,455		67.3	%		504,851		67.9	%
Issuance of common units in acquisition of net profits interest		—		283,700		283,700
5/1/2008		20,924,055		10,432,100		31,356,155		66.7	%		504,851		67.3	%
Vesting of phantom units		—		6,250		6,250
10/31/2008		20,924,055		10,438,350		31,362,405		66.7	%		504,851		67.2	%
Conversion of management incentive units		—		1,715,205		1,715,205
12/31/2008		20,924,055		12,153,555		33,077,610		63.3	%		504,851		63.8	%
Common unit offering		—		2,760,000		2,760,000
5/22/2009		20,924,055		14,913,555		35,837,610		58.4	%		504,851		59.0	%
Common unit offering		—		9,430,000		9,430,000
7/22/2009		20,924,055		24,343,555		45,267,610		46.2	%		504,851		46.8	%
Vesting of phantom units		—		12,500		12,500
10/30/2009		20,924,055		24,356,055		45,280,110		46.2	%		504,851		46.8	%
Conversion of management incentive units		—		5,237		5,237
12/31/2009		20,924,055		24,361,292		45,285,347		46.2	%		504,851		46.8	%

Rights Plan

In October 2008, the Board declared a dividend of one right for each outstanding share of EAC’s common stock to stockholders of record at the close of business on November 7, 2008. Each right entitles the registered holder to purchase from EAC a unit consisting of one one-hundredth of a share of Series A Junior Participating Preferred Stock, par value $0.01 per share, at a purchase price of $120 per fractional share, subject to adjustment.

The rights will separate from the common stock and a “Distribution Date” will occur, with certain exceptions, upon the earlier of (1) ten days following a public announcement that a person or group of affiliated or associated persons (an “Acquiring Person”) has acquired, or obtained the right to acquire, beneficial ownership of more than 10 percent of EAC’s then-outstanding shares of common stock, or (2) ten business days following the commencement of a tender offer or exchange offer that would result in a person’s becoming an Acquiring Person. In certain circumstances, the Distribution Date may be deferred by the Board. The rights are not exercisable until the Distribution Date and will expire at the close of business on October 28, 2011, unless earlier redeemed or exchanged by EAC.

EAC amended its rights plan in connection with its entrance into the Merger Agreement.

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Note 10.   Earnings Per Share

As discussed in “Note 2. Summary of Significant Accounting Policies,” EAC adopted ASC 260-10 on January 1, 2009, and all periods prior to adoption have been restated to calculate earnings per share in accordance therewith. For 2008, basic earnings per share and diluted earnings per share were decreased by $0.14 and $0.06, respectively, as a result of the adoption of ASC 260-10. For 2007, diluted earnings per share was decreased by $0.01 as a result of the adoption of ASC 260-10. For 2007, basic earnings per share was unaffected by the adoption of ASC 260-10.

The following table reflects the allocation of net income (loss) to EAC’s common stockholders and earnings per share computations for the periods indicated:

	Year Ended December 31,
	2009			2008			2007
	(In thousands, except per share amounts)
Basic Earnings Per Share
Numerator:
Undistributed net income (loss) attributable to EAC	$	(81,135	)	$	430,812		$	17,155
Participation rights of unvested restricted stock in undistributed earnings(a)		—			(7,595	)		(291	)
Basic undistributed net income (loss) attributable to EAC common shares	$	(81,135	)	$	423,217		$	16,864
Denominator:
Basic weighted average shares outstanding		52,634			52,270			53,170
Basic EPS attributable to EAC common shares	$	(1.54	)	$	8.10		$	0.32
Diluted Earnings Per Share
Numerator:
Undistributed net income (loss) attributable to EAC	$	(81,135	)	$	430,812		$	17,155
Participation rights of unvested restricted stock in undistributed earnings(a)		—			(7,511	)		(289	)
Diluted undistributed net income (loss) attributable to EAC common shares	$	(81,135	)	$	423,301		$	16,866
Denominator:
Basic weighted average shares outstanding		52,634			52,270			53,170
Effect of dilutive options(b)		—			596			459
Diluted weighted average shares outstanding		52,634			52,866			53,629
Diluted EPS — attributable to EAC common shares	$	(1.54	)	$	8.01		$	0.31

(a)	Unvested restricted stock has no contractual obligation to absorb losses of EAC. Therefore, for 2009, 920,122 shares of restricted stock were outstanding but were excluded from the earnings per share calculations because their effect would have been antidilutive. Please read “Note 11. Employee Benefit Plans” for additional discussion of restricted stock.
(b)	For 2009, 2008, and 2007, options to purchase 1,729,591, 157,614, and 121,651 shares of common stock, respectively, were outstanding but were excluded from the earnings per share calculations because their effect would have been antidilutive. Please read “Note 11. Employee Benefit Plans” for additional discussion of stock options.

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Note 11.   Employee Benefit Plans

401(k) Plan

EAC made contributions to its 401(k) plan, which is a voluntary and contributory plan for eligible employees based on a percentage of employee contributions, of $4.5 million, $3.6 million, and $2.2 million during 2009, 2008, and 2007, respectively. EAC’s 401(k) plan does not allow employees to invest in securities of EAC.

Incentive Stock Plans

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

The total number of shares of EAC’s common stock reserved for issuance pursuant to the 2008 Plan is 2,400,000, of which 1,600,000 are available for grants of “full value” stock awards, such as restricted stock or stock units. As of December 31, 2009, there were 1,717,787 shares available for issuance under the 2008 Plan, of which 1,182,586 are available for grants of “full value” stock awards. Shares delivered or withheld for payment of the exercise price of an option, shares withheld for payment of tax withholding, shares subject to options or other awards that expire or are forfeited, and restricted shares that are forfeited will again become available for issuance under the 2008 Plan.

The 2008 Plan contains the following individual limits:

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

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

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

During 2009, 2008, and 2007, EAC recorded non-cash stock-based compensation expense related to its incentive stock plans of $12.3 million, $9.0 million, and $9.2 million, respectively, which was allocated to LOE and general and administrative expense in the accompanying Consolidated Statements of Operations based on the allocation of the respective employees’ cash compensation. During 2009, 2008, and 2007, EAC also capitalized $2.4 million, $2.3 million, and $1.3 million, respectively, of non-cash stock-based compensation expense related to its incentive stock plans as a component of “Proved properties, including wells and related equipment” in the accompanying Consolidated Balance Sheets. During 2009, 2008, and 2007, EAC recognized income tax benefits related to its incentive stock plans of $4.6 million, $3.4 million, and $3.4 million, respectively.

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Please read “Note 15. ENP” for a discussion of ENP’s unit-based compensation plans.

Stock Options.  All options have a strike price equal to the fair market value of EAC’s common stock on the grant date, have a ten-year life, and vest over a three-year period. The fair value of options granted during 2009, 2008, and 2007 was estimated on the grant date using a Black-Scholes option valuation model based on the following assumptions:

	Year Ended December 31,
	2009			2008			2007
Expected volatility		51.9	%		33.7	%		35.7	%
Expected dividend yield		0.0	%		0.0	%		0.0	%
Expected term (in years)		6.25			6.25			6.0
Risk-free interest rate		2.1	%		3.0	%		4.8	%
Weighted-average grant-date fair value per share	$	15.81		$	13.15		$	11.16

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

The following table summarizes the changes in EAC’s outstanding options for the periods indicated:

	Year Ended December 31,
	2009									2008					2007
						Weighted
						Average
				Weighted		Remaining		Aggregate					Weighted					Weighted
	Number of			Average		Contractual		Intrinsic		Number of			Average		Number of			Average
	Options			Strike Price		Term		Value		Options			Strike Price		Options			Strike Price
	(In thousands)
Outstanding at beginning of year		1,497,413		$	18.02						1,381,782		$	16.03		1,337,118		$	14.44
Granted		269,417			30.55						176,170			33.76		200,059			25.73
Forfeited or expired		(14,134	)		30.93						(14,923	)		30.83		(26,686	)		27.15
Exercised		(23,105	)		20.17						(45,616	)		14.11		(128,709	)		12.34
Outstanding at end of year		1,729,591			19.84		4.9	$	48,738		1,497,413			18.02		1,381,782			16.03
Exercisable at end of year		1,298,056			16.23		3.6		41,262		1,177,015			14.65		1,103,018			13.25

The total intrinsic value of options exercised during 2009, 2008, and 2007 was $0.3 million, $1.6 million, and $2.3 million, respectively. During 2009, 2008, and 2007, EAC received proceeds from the exercise of stock options of $0.5 million, $0.5 million, and $1.6 million, respectively. During 2009 and 2008, EAC recognized income tax benefits related to stock options of $38 thousand and $0.5 million, respectively. During 2007, EAC did not recognize any income tax benefits related to stock options. At December 31, 2009, EAC had $1.7 million of total unrecognized compensation cost related to unvested stock options, which is expected to be recognized over a weighted average period of 1.9 years.

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Additional information about options outstanding and exercisable at December 31, 2009 is as follows:

		Weighted				Weighted
	Range of	Number of		Average		Average		Number of
	Strike Prices	Options		Life		Strike		Options
Year of Grant	Per Share	Outstanding		(Years)		Price		Exercisable
2001	$8.33 to $9.33		400,236		1.5	$	8.87		400,236
2002	$8.50 to $12.40		283,836		2.8		11.94		283,836
2003	$11.49 to $13.61		35,127		3.5		12.25		35,127
2004	$17.17 to $19.77		259,075		4.1		17.55		259,075
2005	$26.55		66,676		5.1	$	26.55		66,676
2006	$31.10		87,961		6.1	$	31.10		87,961
2007	$25.73		173,997		7.1	$	25.73		115,170
2008	$33.76		157,884		8.1	$	33.76		49,975
2009	$30.55		264,799		9.1	$	30.55		—
			1,729,591						1,298,056

Restricted Stock.  Restricted stock awards vest over varying periods from one to five years, subject to performance-based vesting for certain members of senior management. The weighted-average grant-date fair value of restricted stock awards granted during 2009, 2008, and 2007 was $30.52 per share, $37.02 per share, and $25.95 per share, respectively. During 2009, 2008, and 2007, EAC recognized expense related to restricted stock of $9.5 million, $7.6 million, and $7.6 million, respectively. During 2009, EAC recognized income tax provisions related to the vesting of restricted stock of $0.4 million. During 2008, EAC recognized income tax benefits related to the vesting of restricted stock of $1.6 million. During 2007, EAC did not recognize any income tax benefits related to the vesting of restricted stock. The following table summarizes the changes in EAC’s unvested restricted stock awards for 2009:

				Weighted
				Average
	Number of			Grant Date
	Shares			Fair Value
Outstanding at January 1, 2009		938,407		$	30.67
Granted		412,449			30.52
Vested		(408,478	)		29.25
Forfeited		(22,256	)		30.31
Outstanding at December 31, 2009		920,122			31.20

During 2009, 2008, and 2007, EAC issued 189,109 shares, 241,515 shares, and 169,453 shares, respectively, of restricted stock to employees and members of the Board, the vesting of which is dependent only on the passage of time and continued employment. The following table provides information regarding EAC’s outstanding restricted stock at December 31, 2009 the vesting of which is dependent only on the passage of time and continued employment:

	Year of Vesting
Year of Grant	2010		2011		2012		2013		Total
2005		69,592		—		—		—		69,592
2006		59,377		—		—		—		59,377
2007		77,186		77,143		4,166		—		158,495
2008		67,494		91,417		67,333		—		226,244
2009		46,987		46,889		46,806		46,712		187,394
Total		320,636		215,449		118,305		46,712		701,102

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During 2009, 2008, and 2007, EAC issued 223,340 shares, 72,571 shares, and 175,180 shares of restricted stock to certain members of senior management, the vesting of which is dependent not only on the passage of time and continued employment, but also on the achievement of certain performance measures. The performance measures related to the 2008 and 2007 awards were met and therefore, vesting depends only on the passage of time and continued employment and therefore, are included in the table above. The following table provides information regarding EAC’s outstanding restricted stock at December 31, 2009 the vesting of which is dependent not only on the passage of time and continued employment, but also on the achievement of certain performance measures:

	Year of Vesting
Year of Grant	2010		2011		2012		2013		Total
2009		54,755		54,755		54,755		54,755		219,020

None of EAC’s unvested restricted stock is subject to variable accounting. During 2009, 2008, and 2007, there were 408,478 shares, 256,785 shares, and 184,867 shares, respectively, of restricted stock that vested for which certain employees elected to satisfy minimum tax withholding obligations related thereto by directing EAC to withhold 111,819 shares, 32,946 shares, and 38,978 shares of common stock, respectively. EAC accounts for these shares as treasury stock until they are formally retired and have been reflected as such in the accompanying consolidated financial statements. The total fair value of restricted stock that vested during 2009, 2008, and 2007 was $11.0 million, $8.7 million, and $5.3 million, respectively. As of December 31, 2009, EAC had $8.4 million of total unrecognized compensation cost related to unvested restricted stock, which is expected to be recognized over a weighted average period of 2.7 years.

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Note 12.   Fair Value Measurements

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

	December 31,
	2009				2008
	Book		Fair		Book		Fair
	Value		Value		Value		Value
	(In thousands)
Assets:
Cash and cash equivalents	$	13,958	$	13,958	$	2,039	$	2,039
Accounts receivable, net		114,872		114,872		117,995		117,995
Plugging bond		874		991		824		1,202
Bell Creek escrow		9,263		9,263		9,229		9,241
Commodity derivative contracts		61,031		61,031		387,841		387,841
Long-term receivables, net		65,939		65,939		71,986		71,986
Liabilities:
Accounts payable		7,138		7,138		10,017		10,017
6.25% Senior Subordinated Notes		150,000		146,625		150,000		101,250
6.0% Senior Subordinated Notes		296,551		300,375		296,040		194,250
9.5% Senior Subordinated Notes		208,673		231,750		—		—
7.25% Senior Subordinated Notes		148,873		150,000		148,771		94,500
Revolving credit facilities		410,000		410,000		725,000		725,000
Commodity derivative contracts		60,166		60,166		229		229
Deferred premiums on commodity derivative contracts		48,821		48,821		67,610		67,610
Interest rate swaps		3,669		3,669		4,559		4,559

The book values of cash and cash equivalents, accounts receivable, net, and accounts payable approximate fair value due to the short-term nature of these instruments. The book value of long-term receivables, net, approximates fair value as it is net of amounts deemed to be uncollectible and bears interest at market rates. The plugging bond and Bell Creek escrow are included in “Other assets” in the accompanying Consolidated Balance Sheets and are classified as “held to maturity” and therefore, are recorded at amortized cost. The fair values of the plugging bond, Bell Creek escrow, and senior subordinated notes were determined using open market quotes. The difference between book value and fair value of the senior subordinated notes represents the premium or discount on that date. The book value of the revolving credit facilities approximates fair value as the interest rate is variable. EAC’s and ENP’s credit risk have not changed materially from the date the revolving credit facilities were entered into. Commodity derivative contracts and interest rate swaps are marked-to-market each period and are thus stated at fair value in the accompanying Consolidated Balance Sheets. Deferred premiums on commodity derivative contracts were recorded at their net present value at the time the contracts were entered into and EAC accretes that value to the eventual settlement price by recording interest expense each period.

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

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From time to time, EAC enters into floor spreads. In a floor spread, EAC purchases puts at a specified price (a “purchased put”) and also sells a put at a lower price (a “short put”). This strategy enables EAC to achieve some downside protection for a portion of its production, while funding the cost of such protection by selling a put at a lower price. If the price of the commodity falls below the strike price of the purchased put, then EAC has protection against additional commodity price decreases for the covered production down to the strike price of the short put. At commodity prices below the strike price of the short put, the benefit from the purchased put is generally offset by the expense associated with the short put. For example, in 2007, EAC purchased oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. As NYMEX prices increased in 2008, EAC wanted to protect downside price exposure at the higher price. In order to do this, EAC purchased oil put options for 2,000 Bbls/D in 2010 at $75 per Bbl and simultaneously sold oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. Thus, after these transactions were completed, EAC had purchased two oil put options for 2,000 Bbls/D in 2010 (one at $65 per Bbl and one at $75 per Bbl) and sold one oil put option for 2,000 Bbls/D in 2010 at $65 per Bbl. However, the net effect resulted in EAC owning one oil put option for 2,000 Bbls/D at $75 per Bbl. In the following tables, the purchased floor component of these floor spreads are shown net and included with EAC’s other floor contracts.

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

Oil Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted		Asset /
	Daily		Average		Daily		Average		Daily		Average		(Liability)
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(In thousands)
2010													$	(30,760	)
		880	$	80.00		2,940	$	90.57		—	$	—
		5,500		73.47		3,000		74.13		3,885		77.79
		8,385		62.83		500		65.60		1,750		64.08
		1,000		56.00		—		—		1,000		59.70
2011														17,720
		4,880		80.00		2,940		94.44		325		80.00
		2,500		70.00		—		—		1,060		78.42
		4,385		65.00		—		—		250		69.65
2012														(5,120	)
		750		70.00		500		82.05		835		81.19
		2,135		65.00		250		79.25		1,300		76.54
													$	(18,160	)

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Natural Gas Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Daily		Average		Asset
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(In thousands)
Jan. — June 2010													$	5,949
		3,800	$	8.20		3,800	$	9.58		25,452	$	6.46
		4,698		7.26		—		—		20,550		5.23
July — Dec. 2010														6,644
		3,800		8.20		3,800		9.58		—		—
		4,698		7.26		10,000		6.25		25,452		6.46
		10,000		5.13		—		—		550		5.86
2011														4,677
		3,398		6.31		—		—		27,952		6.48
		—		—		—		—		550		5.86
2012														1,755
		898		6.76		—		—		25,452		6.47
		—		—		—		—		550		5.86
													$	19,025

As of December 31, 2009, EAC had $48.8 million of deferred premiums payable, of which $26.3 million was long-term and included in “Derivatives” in the non-current liabilities section of the accompanying Consolidated Balance Sheet and $22.5 million was current and included in “Derivatives” in the current liabilities section of the accompanying Consolidated Balance Sheet. The premiums relate to various oil and natural gas floor contracts and are payable on a monthly basis from January 2010 to January 2013.

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

	Fair Market Value of			Fair Market Value of
	Oil Derivative			Natural Gas Derivative
Counterparty	Contracts Committed			Contracts Committed
	(In thousands)
BNP Paribas	$	22,570		$	7,496
Calyon		(a	)		8,550
JP Morgan		10,272			(a	)
Royal Bank of Canada		14,059			(a	)
Wachovia		8,302			3,844

(a) Less than 10 percent.

In order to mitigate the credit risk of financial instruments, EAC enters into master netting agreements with certain counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and EAC. Instead of treating each derivative financial transaction between the counterparty and EAC separately, the master netting agreement enables the counterparty and EAC to aggregate all financial trades and treat them as a single agreement. This arrangement is intended to benefit EAC in three ways: (1) the netting of the value of all trades reduces the likelihood of counterparties requiring daily collateral posting by EAC; (2) default by a counterparty under one financial trade can trigger rights to terminate all

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financial trades with such counterparty; and (3) netting of settlement amounts reduces EAC’s credit exposure to a given counterparty in the event of close-out. EAC’s accounting policy is to not offset fair value amounts for derivative instruments.

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

	Notional		Fixed			Floating
Term	Amount		Rate			Rate
	(In thousands)
Jan. 2010 - Jan. 2011	$	50,000		3.1610	%		1-month LIBOR
Jan. 2010 - Jan. 2011		25,000		2.9650	%		1-month LIBOR
Jan. 2010 - Jan. 2011		25,000		2.9613	%		1-month LIBOR
Jan. 2010 - Mar. 2012		50,000		2.4200	%		1-month LIBOR

During 2009 and 2008, settlements of interest rate swaps increased EAC’s consolidated interest expense by approximately $3.8 million and $0.2 million, respectively.

Current Period Impact.  As a result of commodity derivative contracts which were previously designated as hedges, EAC recognized a pre-tax reduction in oil and natural gas revenues of approximately $2.9 million and $53.6 million in 2008 and 2007, respectively. EAC also recognizes derivative fair value gains and losses related to: (1) ineffectiveness on derivative contracts designated as hedges; (2) changes in the fair market value of derivative contracts not designated as hedges; (3) settlements on derivative contracts not designated as hedges; and (4) premium amortization. The following table summarizes the components of “Derivative fair value loss (gain)” for the periods indicated:

	Year Ended December 31,
	2009			2008			2007
	(In thousands)
Ineffectiveness	$	2		$	372		$	—
Mark-to-market loss (gain)		350,365			(365,495	)		36,272
Premium amortization		98,395			62,352			41,051
Settlements		(389,165	)		(43,465	)		35,160
Total derivative fair value loss (gain)	$	59,597		$	(346,236	)	$	112,483

In March 2009, EAC elected to monetize certain of its 2009 oil derivative contracts and received proceeds of approximately $190.4 million from these settlements, which were used to reduce outstanding borrowings the EAC Credit Agreement.

Accumulated Other Comprehensive Loss.  At December 31, 2009 and 2008, “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps of $1.0 million and $1.7 million, respectively. During 2010, EAC expects to reclassify $3.4 million of deferred losses from accumulated other comprehensive loss to interest expense. EAC also expects to reclassify $0.1 million of income taxes from accumulated other comprehensive loss to income tax provision during 2010. The actual gains or losses ENP will realize from its interest rate swaps may vary significantly from the deferred losses recorded in “Accumulated other comprehensive loss” in the accompanying Consolidated Balance Sheet due to the fluctuation of interest rates.

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Tabular Disclosures of Fair Value Measurements

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

	Asset Derivatives						Liability Derivatives
	December 31, 2009			December 31, 2008			December 31, 2009			December 31, 2008
	Balance Sheet	Fair		Balance Sheet	Fair		Balance Sheet			Balance Sheet
	Location	Value		Location	Value		Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments under ASC 815
Commodity derivative contracts	Derivatives - current	$	25,825	Derivatives - current	$	349,344	Derivatives - current	$	43,993	Derivatives - current	$	—
Commodity derivative contracts	Derivatives - noncurrent		35,206	Derivatives -noncurrent		38,497	Derivatives - noncurrent		16,173	Derivatives - noncurrent		229
Total derivatives not designated as hedging instruments underASC 815		$	61,031		$	387,841		$	60,166		$	229
Derivatives designated as hedging instruments under ASC 815
Interest rate swaps	Derivatives - current	$	—	Derivatives - current	$	—	Derivatives - current	$	3,421	Derivatives - current	$	1,297
Interest rate swaps	Derivatives - noncurrent		—	Derivatives -noncurrent		—	Derivatives - noncurrent		248	Derivatives - noncurrent		3,262
Total derivatives designated as hedging instruments under ASC 815		$	—		$	—		$	3,669		$	4,559
Total derivatives		$	61,031		$	387,841		$	63,835		$	4,788

The following table summarizes the effect of derivative instruments not designated as hedges under ASC 815 on the Consolidated Statements of Operations for the periods indicated (in thousands):

				Amount of Loss (Gain) Recognized In Income
Derivatives Not Designated as	Location of Loss (Gain)			Year Ended December 31,
Hedges Under ASC 815	Recognized In Income			2009		2008			2007
Commodity derivative contracts		Derivative fair value loss (gain	)	$	59,595	$	(346,608	)	$	112,483

The following tables summarize the effect of derivative instruments designated as hedges under ASC 815 on the Consolidated Statements of Operations for the periods indicated (in thousands):

	Amount of Loss Recognized in
	Accumulated OCI (Effective Portion)
Derivatives Designated as	Year Ended December 31,
Hedges Under ASC 815	2009		2008		2007
Interest rate swaps	$	3,075	$	3,065	$	—

	Amount of Loss Reclassified from Accumulated
	OCI into Income (Effective Portion)
Location of Loss Reclassified from Accumulated	Year Ended December 31,
OCI into Income (Effective Portion)	2009		2008		2007
Interest expense	$	3,785	$	246	$	—
Oil and natural gas revenues		—		2,857		53,587
	$	3,785	$	3,103	$	53,587

	Amount of Loss Recognized
	In Income as Ineffective
	Year Ended December 31,
Location of Loss Recognized in Income as Ineffective	2009		2008		2007
Derivative fair value loss (gain)	$	2	$	372	$	—

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Fair Value Hierarchy

ASC 820-10 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy defined by ASC 820-10 are as follows:

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

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

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

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

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

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

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

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

				Fair Value Measurements at Reporting Date Using
				Quoted Prices in
				Active Markets for		Significant Other			Significant
	Asset (Liability) at			Identical Assets		Observable Inputs			Unobservable Inputs
Description	December 31, 2009			(Level 1)		(Level 2)			(Level 3)
	(In thousands)
Oil derivative contracts — swaps	$	(38,149	)	$	—	$	(38,149	)	$	—
Oil derivative contracts — floors and caps		19,989			—		—			19,989
Natural gas derivative contracts — swaps		11,026			—		11,026			—
Natural gas derivative contracts — floors and caps		7,999			—		—			7,999
Interest rate swaps		(3,669	)		—		(3,669	)		—
Total	$	(2,804	)	$	—	$	(30,792	)	$	27,988

The following table summarizes the changes in the fair value of EAC’s Level 3 assets and liabilities for 2009:

	Fair Value Measurements Using Significant
	Unobservable Inputs (Level 3)
	Oil Derivative			Natural Gas
	Contracts -			Derivative Contracts -
	Floors and Caps			Floors and Caps			Total
	(In thousands)
Balance at January 1, 2009	$	337,335		$	12,741		$	350,076
Total gains (losses):
Included in earnings		(7,223	)		23,736			16,513
Purchases		9,012			844			9,856
Settlements		(319,135	)		(29,322	)		(348,457	)
Balance at December 31, 2009	$	19,989		$	7,999		$	27,988
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	(7,223	)	$	23,736		$	16,513

Since EAC does not use hedge accounting for its commodity derivative contracts, all gains and losses on its Level 3 assets and liabilities are included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.

All fair values have been adjusted for nonperformance risk resulting in a reduction of the net commodity derivative asset of approximately $0.2 million as of December 31, 2009. For commodity derivative contracts which are in an asset position, EAC uses the counterparty’s credit default swap rating. For commodity derivative contracts which are in a liability position, EAC uses the average credit default swap rating of its peer companies as EAC does not have its own credit default swap rating.

EAC’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the nonfinancial assets and liabilities and their placement within the

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fair value hierarchy levels. The following methods and assumptions were used to estimate the fair values of EAC’s assets and liabilities that are accounted for at fair value on a nonrecurring basis:

•  Level 3 — Fair values of asset retirement obligations are determined using discounted cash flow methodologies based on inputs, such as plugging costs and reserve lives, which are not readily available in public markets. See “Note 5. Asset Retirement Obligations” for additional discussion of EAC’s asset retirement obligations.

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

			Fair Value Measurements Using
			Quoted Prices in
			Active Markets for		Significant Other		Significant
	Liability at		Identical Assets		Observable Inputs		Unobservable Inputs		Total Gains
Description	December 31, 2009		(Level 1)		(Level 2)		(Level 3)		(Losses)
	(In thousands)
Asset retirement obligations	$	3,966	$	—	$	—	$	3,966	$	—

Note 13.   Related Party Transactions

During 2008 and 2007, EAC received approximately $160.5 million and $85.3 million, respectively, from affiliates of Tesoro Corporation (“Tesoro”) related to gross oil and natural gas production sold from wells operated by Encore Operating. Mr. John V. Genova, a member of the Board, served as an employee of Tesoro until May 2008.

Please read “Note 15. ENP” for a discussion of related party transactions with ENP.

Note 14.   Financial Statements of Subsidiary Guarantors

Certain of EAC’s wholly owned subsidiaries are subsidiary guarantors of EAC’s senior subordinated notes. The subsidiary guarantees are full and unconditional, and joint and several. The subsidiary guarantors may, without restriction, transfer funds to EAC in the form of cash dividends, loans, and advances. The following Condensed Consolidating Balance Sheets as of December 31, 2009 and 2008 and Condensed Consolidating Statements of Operations and Comprehensive Income (Loss) and Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2009, 2008, and 2007 present consolidating financial information for Encore Acquisition Company (“Parent”) on a stand alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries. As of December 31, 2009, EAC’s guarantor subsidiaries were:

•  EAP Properties, Inc.;

•  EAP Operating, LLC;

•  Encore Operating, L.P.; and

•  Encore Operating Louisiana, LLC.

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

•  ENP;

•  OLLC;

•  GP LLC;

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•  Encore Partners GP Holdings LLC;

•  Encore Partners LP Holdings LLC;

•  Encore Energy Partners Finance Corporation; and

•  Encore Clear Fork Pipeline LLC.

All intercompany investments in, loans due to/from, subsidiary equity, and revenues and expenses between the Parent, guarantor subsidiaries, and non-guarantor subsidiaries are shown prior to consolidation with the Parent and then eliminated to arrive at consolidated totals per the accompanying consolidated financial statements. Prior periods have not been adjusted for ENP’s acquisitions from EAC. Please read “Note 15. ENP” for a discussion of transactions with ENP.

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CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2009

			Guarantor			Non-Guarantor						Consolidated
	Parent		Subsidiaries			Subsidiaries			Eliminations			Total
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	567	$	11,637		$	1,754		$	—		$	13,958
Other current assets		2,314		145,747			46,494			(10,994	)		183,561
Total current assets		2,881		157,384			48,248			(10,994	)		197,519
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		—		3,352,789			851,833			—			4,204,622
Unproved properties		—		95,546			55			—			95,601
Accumulated depletion, depreciation, and amortization		—		(847,850	)		(210,417	)		—			(1,058,267	)
		—		2,600,485			641,471			—			3,241,956
Other property and equipment, net		—		15,018			444			—			15,462
Other assets, net		16,370		163,290			29,488			(124	)		209,024
Investment in subsidiaries		2,812,831		(8,742	)		—			(2,804,089	)		—
Total assets	$	2,832,082	$	2,927,435		$	719,651		$	(2,815,207	)	$	3,663,961
LIABILITIES AND EQUITY
Current liabilities	$	43,841	$	194,836		$	32,690		$	(10,994	)	$	260,373
Deferred taxes		453,225		9			—			(124	)		453,110
Long-term debt		959,097		—			255,000			—			1,214,097
Other liabilities		—		79,591			25,957			—			105,548
Total liabilities		1,456,163		274,436			313,647			(11,118	)		2,033,128
Commitments and contingencies (see Note 4)
Total equity		1,375,919		2,652,999			406,004			(2,804,089	)		1,630,833
Total liabilities and equity	$	2,832,082	$	2,927,435		$	719,651		$	(2,815,207	)	$	3,663,961

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CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2008

			Guarantor			Non-Guarantor						Consolidated
	Parent		Subsidiaries			Subsidiaries			Eliminations			Total
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	607	$	813		$	619		$	—		$	2,039
Other current assets		29,004		421,392			90,797			(2,302	)		538,891
Total current assets		29,611		422,205			91,416			(2,302	)		540,930
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		—		3,016,937			521,522			—			3,538,459
Unproved properties		—		124,272			67			—			124,339
Accumulated depletion, depreciation, and amortization		—		(670,991	)		(100,573	)		—			(771,564	)
		—		2,470,218			421,016			—			2,891,234
Other property and equipment, net		—		11,877			562			—			12,439
Other assets, net		12,846		129,482			46,264			—			188,592
Investment in subsidiaries		2,976,208		(12,865	)		—			(2,963,343	)		—
Total assets	$	3,018,665	$	3,020,917		$	559,258		$	(2,965,645	)	$	3,633,195
LIABILITIES AND EQUITY
Current liabilities	$	118,089	$	215,640		$	20,825		$	(2,302	)	$	352,252
Deferred taxes		416,637		—			278			—			416,915
Long-term debt		1,169,811		—			150,000			—			1,319,811
Other liabilities		—		48,000			12,969			—			60,969
Total liabilities		1,704,537		263,640			184,072			(2,302	)		2,149,947
Commitments and contingencies (see Note 4)
Total equity		1,314,128		2,757,277			375,186			(2,963,343	)		1,483,248
Total liabilities and equity	$	3,018,665	$	3,020,917		$	559,258		$	(2,965,645	)	$	3,633,195

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CONSOLIDATING STATEMENT OF OPERATIONS AND
COMPREHENSIVE INCOME (LOSS)
For the Year Ended December 31, 2009

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
	(In thousands)
Revenues:
Oil	$	—		$	421,780		$	127,611		$	—		$	549,391
Natural gas		—			108,757			22,428			—			131,185
Marketing		—			4,362			478			—			4,840
Total revenues		—			534,899			150,517			—			685,416
Expenses:
Production:
Lease operating		—			123,386			41,676			—			165,062
Production, ad valorem, and severance taxes		—			53,440			16,099			—			69,539
Depletion, depreciation, and amortization		—			234,019			56,757			—			290,776
Impairment of long-lived assets		—			9,979			—			—			9,979
Exploration		—			49,356			3,132			—			52,488
General and administrative		19,771			28,445			11,378			(5,570	)		54,024
Marketing		—			3,692			302			—			3,994
Derivative fair value loss		—			12,133			47,464			—			59,597
Provision for doubtful accounts		—			7,686			—			—			7,686
Other operating		206			22,456			3,099			—			25,761
Total expenses		19,977			544,592			179,907			(5,570	)		738,906
Operating income (loss)		(19,977	)		(9,693	)		(29,390	)		5,570			(53,490	)
Other income (expenses):
Interest		(68,043	)		—			(10,974	)		—			(79,017	)
Equity income from subsidiaries		(25,035	)		(12,064	)		—			37,099			—
Other		(228	)		8,199			46			(5,570	)		2,447
Total other expenses		(93,306	)		(3,865	)		(10,928	)		31,529			(76,570	)
Income (loss) before income taxes		(113,283	)		(13,558	)		(40,318	)		37,099			(130,060	)
Income tax benefit (provision)		32,070			117			(14	)		—			32,173
Consolidated net income (loss)		(81,213	)		(13,441	)		(40,332	)		37,099			(97,887	)
Change in deferred hedge loss on interest rate swaps, net of tax		(339	)		—			839			—			500
Consolidated comprehensive income (loss)	$	(81,552	)	$	(13,441	)	$	(39,493	)	$	37,099		$	(97,387	)

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CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME
For the Year Ended December 31, 2008

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
	(In thousands)
Revenues:
Oil	$	—		$	749,864		$	147,579		$	—		$	897,443
Natural gas		—			192,942			34,537			—			227,479
Marketing		—			5,172			5,324			—			10,496
Total revenues		—			947,978			187,440			—			1,135,418
Expenses:
Production:
Lease operating		—			146,460			28,655			—			175,115
Production, ad valorem, and severance taxes		—			91,809			18,835			—			110,644
Depletion, depreciation, and amortization		—			190,548			37,704			—			228,252
Impairment of long-lived assets		—			59,526			—			—			59,526
Exploration		—			39,026			181			—			39,207
General and administrative		15,801			24,751			12,135			(4,266	)		48,421
Marketing		—			4,104			5,466			—			9,570
Derivative fair value gain		—			(249,356	)		(96,880	)		—			(346,236	)
Provision for doubtful accounts		—			1,984			—			—			1,984
Other operating		165			11,485			1,325			—			12,975
Total expenses		15,966			320,337			7,421			(4,266	)		339,458
Operating income (loss)		(15,966	)		627,641			180,019			4,266			795,960
Other income (expenses):
Interest		(66,204	)		—			(6,969	)		—			(73,173	)
Equity income from subsidiaries		736,408			51,468			—			(787,876	)		—
Other		98			7,967			99			(4,266	)		3,898
Total other expenses		670,302			59,435			(6,870	)		(792,142	)		(69,275	)
Income before income taxes		654,336			687,076			173,149			(787,876	)		726,685
Income tax provision		(240,986	)		—			(635	)		—			(241,621	)
Consolidated net income		413,350			687,076			172,514			(787,876	)		485,064
Amortization of deferred loss on commodity derivative contracts, net of tax		(1,071	)		2,857			—			—			1,786
Change in deferred hedge gain on interest rate swaps, net of tax		(625	)		—			(2,692	)		—			(3,317	)
Comprehensive income	$	411,654		$	689,933		$	169,822		$	(787,876	)	$	483,533

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CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
For the Year Ended December 31, 2007

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
	(In thousands)
Revenues:
Oil	$	—		$	503,981		$	58,836		$	—		$	562,817
Natural gas		—			137,838			12,269			—			150,107
Marketing		—			33,439			8,582			—			42,021
Total revenues		—			675,258			79,687			—			754,945
Expenses:
Production:
Lease operating		—			129,506			13,920			—			143,426
Production, ad valorem, and severance taxes		—			66,014			8,571			—			74,585
Depletion, depreciation, and amortization		—			157,982			25,998			—			183,980
Exploration		—			27,726			—			—			27,726
General and administrative		15,107			15,354			10,707			(2,044	)		39,124
Marketing		—			33,876			6,673			—			40,549
Derivative fair value loss		—			86,182			26,301			—			112,483
Provision for doubtful accounts		—			5,816			—			—			5,816
Other operating		221			16,083			762			—			17,066
Total expenses		15,328			538,539			92,932			(2,044	)		644,755
Operating income (loss)		(15,328	)		136,719			(13,245	)		2,044			110,190
Other income (expenses):
Interest		(82,825	)		(6,415	)		(12,294	)		12,830			(88,704	)
Equity income (loss) from subsidiaries		123,381			(3,205	)		—			(120,176	)		—
Other		6,405			10,940			196			(14,874	)		2,667
Total other expenses		46,961			1,320			(12,098	)		(122,220	)		(86,037	)
Income (loss) before income taxes		31,633			138,039			(25,343	)		(120,176	)		24,153
Income tax benefit (provision)		(14,478	)		—			2			—			(14,476	)
Consolidated net income (loss)		17,155			138,039			(25,341	)		(120,176	)		9,677
Amortization of deferred loss on commodity derivative contracts, net of tax		(20,047	)		53,588			—			—			33,541
Comprehensive income (loss)	$	(2,892	)	$	191,627		$	(25,341	)	$	(120,176	)	$	43,218

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2009

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(71,908	)	$	702,614		$	114,971		$	—		$	745,677
Cash flows from investing activities:
Acquisition of oil and natural gas properties		—			(400,997	)		(31,960	)		—			(432,957	)
Development of oil and natural gas properties		—			(333,261	)		(9,037	)		—			(342,298	)
Investments in subsidiaries		178,435			—			—			(178,435	)		—
Other		—			5,913			(88	)		—			5,825
Net cash provided by (used in) investing activities		178,435			(728,345	)		(41,085	)		(178,435	)		(769,430	)
Cash flows from financing activities:
Proceeds from long-term debt, net of issuance costs		405,105			—			227,061			—			632,166
Payments on long-term debt		(625,000	)		—			(125,000	)		—			(750,000	)
Proceeds from issuance of EAC common stock, net of offering costs		100,608			—			—			—			100,608
Proceeds from issuance of ENP common units, net of offering costs		—			—			170,088			—			170,088
Net equity contributions (distributions)		—			84,221			(262,656	)		178,435			—
Other		12,720			(47,666	)		(82,244	)		—			(117,190	)
Net cash provided by (used in) financing activities		(106,567	)		36,555			(72,751	)		178,435			35,672
Increase (decrease) in cash and cash equivalents		(40	)		10,824			1,135			—			11,919
Cash and cash equivalents, beginning of period		607			813			619			—			2,039
Cash and cash equivalents, end of period	$	567		$	11,637		$	1,754		$	—		$	13,958

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2008

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	629,345		$	(81,882	)	$	115,774		$	—		$	663,237
Cash flows from investing activities:
Acquisition of oil and natural gas properties		—			(142,471	)		(88	)		—			(142,559	)
Development of oil and natural gas properties		—			(543,399	)		(17,598	)		—			(560,997	)
Investments in subsidiaries		(681,766	)		—			—			681,766			—
Other		—			(24,475	)		(315	)		—			(24,790	)
Net cash used in investing activities		(681,766	)		(710,345	)		(18,001	)		681,766			(728,346	)
Cash flows from financing activities:
Repurchase of common stock		(67,170	)		—			—			—			(67,170	)
Proceeds from long-term debt, net of issuance costs		1,127,029			—			243,310			—			1,370,339
Payments on long-term debt		(1,031,500	)		—			(141,000	)		—			(1,172,500	)
Net equity distributions		—			806,460			(124,694	)		(681,766	)		—
Other		24,668			(15,120	)		(74,773	)		—			(65,225	)
Net cash provided by (used in) financing activities		53,027			791,340			(97,157	)		(681,766	)		65,444
Increase (decrease) in cash and cash equivalents		606			(887	)		616			—			335
Cash and cash equivalents, beginning of period		1			1,700			3			—			1,704
Cash and cash equivalents, end of period	$	607		$	813		$	619		$	—		$	2,039

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2007

				Guarantor			Non-Guarantor						Consolidated
	Parent			Subsidiaries			Subsidiaries			Eliminations			Total
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(305,868	)	$	615,484		$	10,091		$	—		$	319,707
Cash flows from investing activities:
Proceeds from disposition of assets		—			287,928			—			—			287,928
Acquisition of oil and natural gas properties		—			(518,251	)		(330,294	)		—			(848,545	)
Development of oil and natural gas properties		—			(329,252	)		(6,645	)		—			(335,897	)
Investments in subsidiaries		(93,658	)		—			—			93,658			—
Other		—			(32,585	)		(457	)		—			(33,042	)
Net cash used in investing activities		(93,658	)		(592,160	)		(337,396	)		93,658			(929,556	)
Cash flows from financing activities:
Proceeds from issuance of ENP common units, net of issuance costs		—			—			193,461			—			193,461
Proceeds from long-term debt, net of issuance costs		1,208,501			—			270,758			—			1,479,259
Payments on long-term debt		(809,428	)		—			(225,000	)		—			(1,034,428	)
Net equity contributions		—			—			93,658			(93,658	)		—
Other		454			(22,387	)		(5,569	)		—			(27,502	)
Net cash provided by (used in) financing activities		399,527			(22,387	)		327,308			(93,658	)		610,790
Increase in cash and cash equivalents		1			937			3			—			941
Cash and cash equivalents, beginning of period		—			763			—			—			763
Cash and cash equivalents, end of period	$	1		$	1,700		$	3		$	—		$	1,704

Note 15.   ENP

In September 2007, ENP completed its IPO of 9,000,000 common units at a price to the public of $21.00 per unit. In October 2007, the underwriters exercised in full their over-allotment option to purchase an additional 1,148,400 common units of ENP. The net proceeds of approximately $193.5 million, after deducting the underwriters’ discount and a structuring fee of approximately $14.9 million, in the aggregate, and offering expenses of approximately $4.7 million, were used to repay in full $126.4 million of outstanding indebtedness under OLLC’s subordinated credit agreement with EAP Operating, LLC, and reduce outstanding borrowings under the OLLC Credit Agreement.

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In connection with ENP’s IPO, EAC, ENP, and certain of their respective subsidiaries entered into a contribution, conveyance and assumption agreement (the “Contribution Agreement”) and an administrative services agreement (the “Administrative Services Agreement”), each as more fully described below. In addition, the board of directors of GP LLC adopted the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “ENP Plan”), as more fully described below.

Contribution, Conveyance and Assumption Agreement

At the closing of ENP’s IPO, the following transactions, among others, occurred pursuant to the Contribution Agreement:

•  Encore Operating contributed certain oil and natural gas properties and related assets in the Permian Basin in West Texas to ENP in exchange for 4,043,478 common units; and

•  EAC agreed to indemnify ENP for certain environmental liabilities, tax liabilities, and title defects, as well as defects relating to retained assets and liabilities, occurring or existing before the closing.

These transfers and distributions were made in a series of steps outlined in the Contribution Agreement. In connection with the issuance of the common units by ENP in exchange for the Permian Basin assets, ENP’s IPO, and the exercise of the underwriters’ over-allotment option to purchase additional common units, GP LLC exchanged such number of common units for general partner units as was necessary to enable it to maintain its then two percent general partner interest in ENP. GP LLC received the common units through capital contributions from EAC of common units it owned.

Administrative Services Agreement

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

Encore Operating initially received an administrative fee of $1.75 per BOE of ENP’s production for such services. From April 1, 2008 to March 31, 2009, the administration fee was $1.88 per BOE of ENP’s production. Effective April 1, 2009, the administrative fee increased to $2.02 per BOE of ENP’s production. ENP also reimburses Encore Operating for actual third-party expenses incurred on ENP’s behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on ENP’s behalf. In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator.

The administrative fee will increase in the following circumstances:

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

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

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

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

Sales of Assets to ENP

In August 2009, Encore Operating sold certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota (the “Rockies and Permian Basin Assets”) to ENP for approximately $179.6 million in cash, which ENP financed through borrowings under the OLLC Credit Agreement and proceeds from the issuance of ENP common units to the public. EAC used the proceeds from the sale of properties to fund a portion of the purchase price of its acquisitions from EXCO.

In June 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Williston Basin in North Dakota and Montana (the “Williston Basin Assets”) to ENP for approximately $25.2 million in cash, which ENP financed through borrowings under the OLLC Credit Agreement and proceeds from the issuance of ENP common units to the public. EAC used the proceeds from the sale of the properties to reduce outstanding borrowings under the EAC Credit Agreement.

In January 2009, Encore Operating sold certain oil and natural gas producing properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”), to ENP for approximately $46.4 million in cash, which ENP financed through borrowings under the OLLC Credit Agreement. EAC used the proceeds from the sale of the properties to reduce outstanding borrowings under the EAC Credit Agreement.

In February 2008, Encore Operating sold certain oil and natural gas properties and related assets in the Permian Basin in West Texas and in the Williston Basin in North Dakota to ENP for approximately $125.0 million in cash and the issuance of 6,884,776 ENP common units to Encore Operating. In determining the total purchase price, the common units were valued at $125.0 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s carrying value of the properties. ENP financed the cash portion of the purchase price through borrowings under the OLLC Credit Agreement. EAC used the proceeds from the sale of the properties to reduce outstanding borrowings under the EAC Credit Agreement.

Shelf Registration Statement on Form S-3

In November 2008, ENP’s “shelf” registration statement on Form S-3 was declared effective by the SEC. Under the shelf registration statement, ENP may offer common units, senior debt, or subordinated debt in one or more offerings with a total initial offering price of up to $1 billion.

Public Offerings of Common Units

In July 2009, ENP issued 9,430,000 common units under its shelf registration statement at a price to the public of $14.30 per common unit. ENP used the net proceeds of approximately $129.2 million, after deducting the underwriters’ discounts and commissions of $5.4 million, in the aggregate, and offering costs of $0.2 million, to fund a portion of the purchase price of the Rockies and Permian Basin Assets.

In May 2009, ENP issued 2,760,000 common units under its shelf registration statement at a price to the public of $15.60 per common unit. ENP used the net proceeds of approximately $40.9 million, after deducting the underwriters’ discounts and commissions of $1.9 million, in the aggregate, and offering costs of approximately $0.2 million, to fund the acquisition of the Vinegarone Assets and a portion of the purchase price of the Williston Basin Assets.

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Long-Term Incentive Plan

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

The total number of common units reserved for issuance pursuant to the ENP Plan is 1,150,000. As of December 31, 2009, there were 1,075,000 common units available for issuance under the ENP Plan.

Phantom Units.  Each October, ENP issues 5,000 phantom units to each member of GP LLC’s board of directors pursuant to the ENP Plan. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the plan administrator, cash equivalent to the value of a common unit. ENP intends to settle the phantom units at vesting by issuing common units to the grantee; therefore, these phantom units are classified as equity instruments. Phantom units vest equally over a four-year period. The holders of phantom units also receive distribution equivalent rights prior to vesting, which entitle them to receive cash equal to the amount of any cash distributions paid by ENP with respect to a common unit during the period the right is outstanding. During 2009, 2008 and 2007, ENP recognized non-cash equity-based compensation expense for the phantom units of approximately $0.4 million, $0.3 million, and $31,000, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations.

The following table summarizes the changes in ENP’s unvested phantom units for 2009:

				Weighted
				Average
	Number of			Grant Date
	Shares			Fair Value
Outstanding at January 1, 2009		43,750		$	18.67
Granted		25,000			18.13
Vested		(12,500	)		18.83
Forfeited		—			—
Outstanding at December 31, 2009		56,250			18.40

During 2009, 2008, and 2007, ENP issued 25,000, 30,000, and 20,000, respectively, phantom units to members of GP LLC’s board of directors, the vesting of which is dependent only on the passage of time and continuation as a board member. The following table provides information regarding ENP’s outstanding phantom units at December 31, 2009:

	Year of Vesting
Year of Grant	2010		2011		2012		2013		Total
2007		5,000		5,000		—		—		10,000
2008		7,500		7,500		6,250		—		21,250
2009		6,250		6,250		6,250		6,250		25,000
Total		18,750		18,750		12,500		6,250		56,250

As of December 31, 2009, ENP had $0.7 million of total unrecognized compensation cost related to unvested phantom units, which is expected to be recognized over a weighted average period of 2.2 years.

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During 2009 and 2008, there were 12,500 and 6,250, respectively, phantom units that vested, the total fair value of which was $0.2 million and $0.1 million, respectively.

Management Incentive Units

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

The fair value of the management incentive units was estimated on the date of grant using a discounted dividend model. During 2008 and 2007, ENP recognized total non-cash equity-based compensation expense for the management incentive units of $4.8 million and $6.8 million, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. There have been no additional issuances of management incentive units.

Distributions

During 2009, 2008, and 2007, ENP paid cash distributions of approximately $81.7 million, $74.4 million, and $1.3 million, respectively, of which $43.9 million, $46.9 million, and $0.8 million, respectively, was paid to EAC and had no impact on EAC’s consolidated cash.

During 2008 and 2007, ENP paid cash distributions of approximately $3.5 million and $29,000, respectively, to certain executive officers of GP LLC, who serve in the same capacities for EAC, based on their ownership of management incentive units.

Note 16.   Segment Information

The following tables provide EAC’s operating segment information required by ASC 280-10 (formerly SFAS No. 131, “Disclosure about Segments of an Enterprise and Related Information”) as well as the results of operations from oil and natural gas producing activities required by ASC 932-235 (formerly SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.”

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	For the Year Ended December 31, 2009
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(In thousands)
Revenues:
Oil	$	421,780		$	127,611		$	—		$	549,391
Natural gas		108,757			22,428			—			131,185
Marketing		4,362			478			—			4,840
Total revenues		534,899			150,517			—			685,416
Expenses:
Production:
Lease operating		123,386			41,676			—			165,062
Production, ad valorem, and severance taxes		53,440			16,099			—			69,539
Depletion, depreciation, and amortization		234,019			56,757			—			290,776
Impairment of long-lived assets		9,979			—			—			9,979
Exploration		49,356			3,132			—			52,488
General and administrative		48,219			11,375			(5,570	)		54,024
Marketing		3,692			302			—			3,994
Derivative fair value loss		12,133			47,464			—			59,597
Other operating		30,348			3,099			—			33,447
Total expenses		564,572			179,904			(5,570	)		738,906
Operating income (loss)		(29,673	)		(29,387	)		5,570			(53,490	)
Other income (expenses):
Interest		(68,043	)		(10,974	)		—			(79,017	)
Other		7,971			46			(5,570	)		2,447
Total other expenses		(60,072	)		(10,928	)		(5,570	)		(76,570	)
Income (loss) before income taxes		(89,745	)		(40,315	)		—			(130,060	)
Income tax benefit (provision)		32,187			(14	)		—			32,173
Consolidated net loss		(57,558	)		(40,329	)		—			(97,887	)
Change in deferred hedge loss on interest rate swaps, net of tax		(339	)		839			—			500
Consolidated comprehensive loss	$	(57,897	)	$	(39,490	)	$	—		$	(97,387	)
Costs incurred related to oil and natural gas properties	$	665,800		$	40,686		$	—		$	706,486

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	For the Year Ended December 31, 2008
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(In thousands)
Revenues:
Oil	$	670,830		$	226,613		$	—		$	897,443
Natural gas		173,535			53,944			—			227,479
Marketing		5,172			5,324			—			10,496
Total revenues		849,537			285,881			—			1,135,418
Expenses:
Production:
Lease operating		130,363			44,752			—			175,115
Production, ad valorem, and severance taxes		82,497			28,147			—			110,644
Depletion, depreciation, and amortization		170,715			57,537			—			228,252
Impairment of long-lived assets		59,526			—			—			59,526
Exploration		39,011			196			—			39,207
General and administrative		36,082			16,605			(4,266	)		48,421
Marketing		4,104			5,466			—			9,570
Derivative fair value gain		(249,356	)		(96,880	)		—			(346,236	)
Other operating		13,289			1,670			—			14,959
Total expenses		286,231			57,493			(4,266	)		339,458
Operating income		563,306			228,388			4,266			795,960
Other income (expenses):
Interest		(66,204	)		(6,969	)		—			(73,173	)
Other		8,065			99			(4,266	)		3,898
Total other expenses		(58,139	)		(6,870	)		(4,266	)		(69,275	)
Income before income taxes		505,167			221,518			—			726,685
Income tax provision		(240,859	)		(762	)		—			(241,621	)
Consolidated net income		264,308			220,756			—			485,064
Amortization of deferred loss on commodity derivative contracts, net of tax		1,786			—			—			1,786
Change in deferred hedge loss on interest rate swaps, net of tax		941			(4,258	)		—			(3,317	)
Consolidated comprehensive income	$	267,035		$	216,498		$	—		$	483,533
Costs incurred related to oil and natural gas properties	$	730,908		$	45,613		$	—		$	776,521

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	For the Year Ended December 31, 2007
	EAC									Consolidated
	Standalone			ENP			Eliminations			Total
	(In thousands)
Revenues:
Oil	$	427,271		$	135,546		$	—		$	562,817
Natural gas		110,988			39,119			—			150,107
Marketing		33,439			8,582			—			42,021
Total revenues		571,698			183,247			—			754,945
Expenses:
Production:
Lease operating		109,446			33,980			—			143,426
Production, ad valorem, and severance taxes		56,873			17,712			—			74,585
Depletion, depreciation, and amortization		136,486			47,494			—			183,980
Exploration		27,600			126			—			27,726
General and administrative		25,923			15,245			(2,044	)		39,124
Marketing		33,876			6,673			—			40,549
Derivative fair value loss		86,182			26,301			—			112,483
Other operating		21,456			1,426			—			22,882
Total expenses		497,842			148,957			(2,044	)		644,755
Operating income		73,856			34,290			2,044			110,190
Other income (expenses):
Interest		(82,417	)		(12,702	)		6,415			(88,704	)
Other		10,930			196			(8,459	)		2,667
Total other expenses		(71,487	)		(12,506	)		(2,044	)		(86,037	)
Income before income taxes		2,369			21,784			—			24,153
Income tax provision		(14,398	)		(78	)		—			(14,476	)
Consolidated net income (loss)		(12,029	)		21,706			—			9,677
Amortization of deferred loss on commodity derivative contracts, net of tax		33,541			—			—			33,541
Consolidated comprehensive income	$	21,512		$	21,706		$	—		$	43,218
Costs incurred related to oil and natural gas properties	$	686,720		$	529,439		$	—		$	1,216,159

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table provides EAC’s balance sheet segment information as of the dates indicated:

	December 31,
	2009			2008
	(In thousands)
Segment assets:
EAC Standalone	$	2,952,523		$	2,823,778
ENP		719,651			813,313
Eliminations		(8,213	)		(3,896	)
Total consolidated assets	$	3,663,961		$	3,633,195
Segment liabilities:
EAC Standalone	$	1,722,261		$	1,961,453
ENP		313,647			193,962
Eliminations		(2,780	)		(5,468	)
Total consolidated liabilities	$	2,033,128		$	2,149,947

Note 17.   Impairment of Long-Lived Assets

During 2009 and 2008, circumstances indicated that the carrying value of certain of EAC’s oil and natural gas properties in the Tuscaloosa Marine Shale may not be recoverable. For the proved oil and natural gas property costs, EAC compared the assets’ carrying value to the undiscounted expected future net cash flows, which indicated the need for an impairment charge. EAC then compared the net book value of the impaired assets to their estimated discounted value, which resulted in a pretax write-down of the value of oil and natural gas properties. For the unproved acreage costs, EAC recorded a valuation allowance to reflect the portion of the property costs that it believes will not be transferred to proved properties over the remaining life of the lease. The impairment of proved oil and natural gas properties and unproved acreage in the Tuscaloosa Marine Shale totaled $10.0 million and $59.5 million, during 2009 and 2008, respectively. Fair value was determined using estimates of future production volumes and estimates of future prices EAC might receive for these volumes, discounted to a present value. EAC’s estimates of undiscounted cash flows indicated that the remaining carrying amounts of its oil and natural gas properties are expected to be recovered. Nonetheless, if oil and natural gas prices decline, it is reasonably possible that EAC’s estimates of undiscounted cash flows may change in the near term resulting in the need to record an additional write down of oil and natural gas properties to fair value.

As of December 31, 2009, EAC does not have any unproved oil and natural gas properties in the Tuscaloosa Marine Shale whose carrying value has not been written down to zero.

Note 18.   Subsequent Events

Subsequent events were evaluated through February 24, 2010, which is the date the financial statements were issued.

Subsequent to December 31, 2009, EAC granted 546,086 shares of restricted stock to employees as part of its annual incentive program and 202,365 of previously granted stock options and 334,317 shares of previously granted of restricted stock vested. Subsequent to December 31, 2009, it was determined that the performance measures related to certain awards granted in February 2009 were met and, therefore, vesting now depends only on the passage of time and continued employment.

On January 25, 2010, ENP announced that the board of directors of GP LLC declared an ENP cash distribution for the fourth quarter of 2009 to unitholders of record as of the close of business on February 8, 2010 at a rate of $0.5375 per unit. Approximately $24.6 million was paid to unitholders on February 12, 2010.

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SUPPLEMENTARY INFORMATION

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

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

	December 31,
	2009			2008
	(In thousands)
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment	$	4,204,622		$	3,538,459
Unproved properties		95,601			124,339
Accumulated depletion, depreciation, and amortization		(1,058,267	)		(771,564	)
	$	3,241,956		$	2,891,234

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

	Year Ended December 31,
	2009		2008		2007
	(In thousands)
Acquisitions:
Proved properties(a)	$	402,457	$	28,840	$	796,239
Unproved properties		17,087		128,635		52,306
Total acquisitions		419,544		157,475		848,545
Development:
Drilling and exploitation(b)		121,259		362,609		270,161
Total development		121,259		362,609		270,161
Exploration:
Drilling and exploitation		163,887		252,104		95,221
Geological and seismic		1,022		2,851		1,456
Delay rentals		774		1,482		776
Total exploration		165,683		256,437		97,453
Total costs incurred	$	706,486	$	776,521	$	1,216,159

(a)	Includes asset retirement obligations incurred for acquisition activities of $3.7 million, $0.1 million, and $8.3 million in 2009, 2008, and 2007, respectively.
(b)	Includes asset retirement obligations incurred for development activities of $0.3 million, $0.5 million, and $0.1 million during 2009, 2008, and 2007, respectively.

Oil & Natural Gas Producing Activities — Unaudited

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

Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods assumed or that prices and costs will remain constant. Actual

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SUPPLEMENTARY INFORMATION — (Continued)

production may not equal the estimated amounts used in the preparation of reserve projections. In accordance with SEC guidelines, 2009 estimates of future net cash flows from EAC’s properties and the representative value thereof are made using an unweighted average of the closing oil and natural gas prices for the applicable commodity on the first day of each month in 2009 and are held constant throughout the life of the properties. In accordance with past SEC guidelines, 2008 and 2007 estimates of future net cash flows from EAC’s properties and the representative value thereof are made using oil and natural gas prices in effect as of the dates of such estimates and are held constant throughout the life of the properties. Prices used in estimating EAC’s future net cash flows were as follows:

	2009		2008		2007
Oil (per Bbl)	$	61.18	$	44.60	$	96.01
Natural gas (per Mcf)	$	3.83	$	5.62	$	7.47

EAC’s proved reserve and production quantities from its CCA properties have been reduced by the amounts attributable to the net profits interest. The net profits interest on EAC’s CCA properties has also been deducted from future cash inflows in the calculation of Standardized Measure. In addition, net future cash inflows have not been adjusted for commodity derivative contracts outstanding at the end of the year. The future net cash flows are reduced by estimated production and development costs, which are based on year-end economic conditions and held constant throughout the life of the properties, and by the estimated effect of future income taxes. Future income taxes are based on statutory income tax rates in effect at year-end, EAC’s tax basis in its proved oil and natural gas properties, and the effect of NOL carryforwards and AMT credits.

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

EAC’s estimated net quantities of proved oil and natural gas reserves were as follows as of the dates indicated:

	December 31,
	2009		2008		2007
Proved developed reserves:
Oil (MBbl)		121,401		110,014		125,213
Natural gas (MMcf)		322,422		232,715		191,072
Combined (MBOE)		175,138		148,800		157,058
Proved undeveloped reserves:
Oil (MBbl)		25,693		24,438		63,374
Natural gas (MMcf)		116,650		74,805		65,375
Combined (MBOE)		45,135		36,905		74,270
Proved reserves:
Oil (MBbl)		147,094		134,452		188,587
Natural gas (MMcf)		439,072		307,520		256,447
Combined (MBOE)		220,273		185,705		231,328

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SUPPLEMENTARY INFORMATION — (Continued)

The changes in EAC’s proved reserves were as follows for the periods indicated:

				Natural			Oil
	Oil			Gas			Equivalent
	(MBbl)			(MMcf)			(MBOE)
Balance, December 31, 2006		153,434			306,764			204,561
Purchases of minerals-in-place		40,534			15,667			43,146
Sales of minerals-in-place		(1,845	)		(107,249	)		(19,719	)
Extensions and discoveries		4,362			65,639			15,302
Improved recovery		666			90			681
Revisions of previous estimates		981			(501	)		896
Production		(9,545	)		(23,963	)		(13,539	)
Balance, December 31, 2007		188,587			256,447			231,328
Purchases of minerals-in-place		266			6,220			1,303
Extensions and discoveries		7,411			73,527			19,665
Improved recovery		287			—			287
Revisions of previous estimates		(52,049	)		(2,300	)		(52,432	)
Production		(10,050	)		(26,374	)		(14,446	)
Balance, December 31, 2008		134,452			307,520			185,705
Purchases of minerals-in-place		6,142			107,614			24,078
Sales of minerals-in-place		(107	)		(64	)		(117	)
Extensions and discoveries		6,902			87,605			21,502
Revisions of previous estimates		9,721			(29,684	)		4,774
Production		(10,016	)		(33,919	)		(15,669	)
Balance, December 31, 2009(a)		147,094			439,072			220,273

(a) Includes proved reserves of 28.9 MMBbls of oil and 84.7 Bcf of natural gas (43.0 MMBOE) attributable to ENP in which there was a 53.2 percent noncontrolling interest as of December 31, 2009.

Recent SEC Rule-Making Activity.  In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and natural gas than would have resulted under the previous rules. Use of new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately 8.5 MMBOE while the change in definition of proved undeveloped reserves increased total proved reserves by 5.7 MMBOE. Therefore, the total impact of the new reserve rules resulted in negative reserves revisions of 2.8 MMBOE. Pursuant to the SEC’s final rule, prior period reserves were not restated.

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ENCORE ACQUISITION COMPANY

SUPPLEMENTARY INFORMATION — (Continued)

EAC’s standardized measure of discounted estimated future net cash flows was as follows as of the dates indicated:

	December 31,
	2009			2008			2007
	(In thousands)
Future cash inflows	$	9,416,040		$	6,754,431		$	17,394,468
Future production costs		(3,960,587	)		(3,082,814	)		(5,721,804	)
Future development costs		(644,323	)		(497,197	)		(469,034	)
Future abandonment costs, net of salvage		(104,394	)		(96,480	)		(75,172	)
Future income tax expense		(1,089,618	)		(555,370	)		(3,236,356	)
Future net cash flows		3,617,118			2,522,570			7,892,102
10% annual discount		(1,890,048	)		(1,302,616	)		(4,600,393	)
Standardized measure of discounted estimated future net cash flows(a)	$	1,727,070		$	1,219,954		$	3,291,709

(a) Includes $494.5 million attributable to ENP in which there was a 53.2 percent noncontrolling interest as of December 31, 2009.

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

	Year Ended December 31,
	2009			2008			2007
	(In thousands)
Net change in prices and production costs	$	539,118		$	(2,848,387	)	$	1,718,818
Purchases of minerals-in-place		191,573			14,155			1,249,008
Sales of minerals-in-place		448			—			(300,727	)
Extensions, discoveries, and improved recovery		113,043			171,509			282,163
Revisions of previous quantity estimates		133,485			(474,926	)		21,887
Production, net of production costs		(433,874	)		(321,935	)		(710,134	)
Previously estimated development costs incurred
during the period		120,959			148,569			270,016
Accretion of discount		121,995			329,171			146,181
Change in estimated future development costs		(44,806	)		(176,732	)		(235,005	)
Net change in income taxes		(223,560	)		991,368			(672,807	)
Change in timing and other		(11,265	)		95,453			60,502
Net change in standardized measure		507,116			(2,071,755	)		1,829,902
Standardized measure, beginning of year		1,219,954			3,291,709			1,461,807
Standardized measure, end of year	$	1,727,070		$	1,219,954		$	3,291,709

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ENCORE ACQUISITION COMPANY

SUPPLEMENTARY INFORMATION — (Continued)

Selected Quarterly Financial Data — Unaudited

The following table provides selected quarterly financial data for the periods indicated:

	Quarter
	First			Second			Third			Fourth
	(In thousands, except per share data)
2009
Revenues	$	114,349		$	163,478		$	186,004		$	221,585
Operating income (loss)	$	4,621		$	(74,609	)	$	30,733		$	(14,235	)
Net loss attributable to EAC stockholders	$	(7,556	)	$	(46,975	)	$	(4,999	)	$	(21,605	)
Net loss per common share:
Basic	$	(0.15	)	$	(0.91	)	$	(0.10	)	$	(0.40	)
Diluted	$	(0.15	)	$	(0.91	)	$	(0.10	)	$	(0.40	)
2008
Revenues	$	272,902		$	357,334		$	337,478		$	167,704
Operating income (loss)	$	68,956		$	(55,925	)	$	375,148		$	407,781
Net income (loss) attributable to EAC stockholders	$	31,220		$	(35,720	)	$	206,307		$	229,005
Net income (loss) per common share:
Basic	$	0.58		$	(0.68	)	$	3.88		$	4.35
Diluted	$	0.58		$	(0.68	)	$	3.77		$	4.32

As discussed in “Note 2. Summary of Significant Accounting Policies” and “Note 10. Earnings Per Share,” EAC adopted ASC 260-10 on January 1, 2009 and all periods have been restated to calculate earnings per share in accordance therewith.

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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 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, 2009 to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control Over Financial Reporting

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

As of December 31, 2009, management assessed the effectiveness of our 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 we maintained effective internal control over financial reporting as of December 31, 2009, based on those criteria.

Ernst & Young LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this Report, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2009. The report, which expresses an unqualified opinion on the effectiveness of our internal control over financial reporting as of December 31, 2009, 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, 2009, 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, 2009, 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, 2009 and 2008, and the related consolidated statements of operations, equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2009 and our report dated February 24, 2010 expressed an unqualified opinion thereon.

/s/  Ernst & Young LLP

Fort Worth, Texas
February 24, 2010

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Changes in Internal Control over Financial Reporting

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

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