Table of Contents

(Mark One)
þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2006
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from           to

Delaware		75-2759650
State or other jurisdiction of incorporation or organization		(I.R.S. Employer Identification No.)
777 Main Street, Suite 1400, Fort Worth, Texas		76102
(Address of principal executive offices)		(Zip Code)

Title of each class		Name of each exchange on which registered
Common Stock		New York Stock Exchange

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity of the Registrant was last sold as of June 30, 2006 (the last business day of Registrant’s most recently completed second fiscal quarter)		$1,324,038,526
Number of shares of Common Stock, $0.01 par value, outstanding as of February 20, 2007		53,113,534

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				Page
PART I
Items 1 and 2.		Business and Properties			1
Item 1A.		Risk Factors			20
Item 1B.		Unresolved Staff Comments			29
Item 3.		Legal Proceedings			29
Item 4.		Submission of Matters to a Vote of Security Holders			29
PART II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			30
Item 6.		Selected Financial Data			32
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operation			34
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk			65
Item 8.		Financial Statements and Supplementary Data			68
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			105
Item 9A.		Controls and Procedures			105
Item 9B.		Other Information			107
PART III
Item 10.		Directors, Executive Officers and Corporate Governance			107
Item 11.		Executive Compensation			107
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			107
Item 13.		Certain Relationships and Related Transactions, and Director Independence			108
Item 14.		Principal Accounting Fees and Services			108
PART IV
Item 15.		Exhibits, Financial Statement Schedules			108
Statement Showing Computation of Ratio of Earnings to Fixed Charges
Subsidiaries of the Company
Consent of Ernst & Young LLP
Consent of Miller and Lents, Ltd.
Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer)
Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer)
Section 1350 Certification (Principal Executive Officer)
Section 1350 Certification (Principal Financial Officer)

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	•	Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
	•	Bcf. One billion cubic feet of natural gas.
	•	Bbl/ D. One Bbl per day.
	•	BOE. One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf to one Bbl of oil.
	•	BOE/ D. One BOE per day.
	•	Completion. The installation of permanent equipment for the production of oil or natural gas.
	•	Delay Rentals. Fees paid to the lessor of the oil and natural gas lease during the primary term of the lease prior to the commencement of production from a well.
	•	Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.
	•	Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
	•	Drill-to-Earn. The acquisition of an ownership interest in the reserves and production found and developed on properties in which no ownership interest exists prior to the onset of drilling.
	•	Encore or the Company. Encore Acquisition Company, a Delaware corporation, together with its subsidiaries.
	•	Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.
	•	Farm-out. Transfer of all or part of the operating rights from the working interest owner to an assignee, who assumes all or some of the burden of development, in return for an interest in the property.
	•	Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we have a working interest.
	•	High-Pressure Air Injection (“HPAI”). HPAI involves utilizing compressors to inject air into previously produced oil and natural gas formations in order to displace remaining resident hydrocarbons and force them under pressure to a common lifting point for production.
	•	Horizontal Drilling. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation usually yields a well which has the ability to produce higher volumes than a vertical well drilled in the same formation.
	•	Lease Operations Expense (“LOE”). All direct and allocated indirect costs of producing oil and natural gas after completion of drilling and before removal of production from the property. Such costs include labor, superintendence, supplies, repairs, maintenance, and direct overhead charges.
	•	LIBOR. London Interbank Offered Rate.
	•	MBbl. One thousand Bbls.
	•	MBOE. One thousand BOE.

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	•	MBOE/ D. One thousand BOE per day.
	•	Mcf. One thousand cubic feet of natural gas.
	•	Mcf/ D. One Mcf per day.
	•	Mcfe. One Mcf equivalent, calculated by converting oil to natural gas equivalent at a ratio of one Bbl of oil to six Mcf.
	•	Mcfe/ D. One Mcfe per day.
	•	MMBbl. One million Bbls.
	•	MMBOE. One million BOE.
	•	MMBtu. One million British thermal units. One British thermal unit is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit.
	•	MMcf. One million Mcf.
	•	MMcf/ D. One MMcf per day.
	•	Net Acres or Net Wells. Gross acres or wells, as the case may be, multiplied by the percentage working interest owned by us.
	•	Net Production. Production that is owned by us less royalties and production due others.
	•	NYMEX. New York Mercantile Exchange.
	•	Oil. Crude oil or condensate.
	•	Operating Income. Gross oil and natural gas revenue less applicable production, ad valorem, and severance taxes and LOE.
	•	Operator. The individual or company responsible for the exploration, exploitation, and production of an oil or natural gas well or lease.
	•	Present Value of Future Net Revenues or Present Value or PV-10. The pretax present value of estimated future revenues to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depletion, depreciation, and amortization, and discounted using an annual discount rate of 10 percent.
	•	Productive Well. A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.
	•	Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
	•	Proved Reserves. The estimated quantities of oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions.
	•	Proved Undeveloped Reserves. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on acreage yet to be drilled for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production. Proved undeveloped reserves include unrealized production response from fluid injection and other improved recovery techniques, such as high-pressure air injection, where such techniques have been proved effective by actual tests in the area and in the same reservoir.

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	•	Reserve-To-Production Index (“R/ P Index”). An estimate expressed in years of the total estimated proved reserves attributable to a producing property divided by production from the property for the 12 months preceding the date as of which the proved reserves were estimated.
	•	Royalty. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
	•	SEC. The United States Securities and Exchange Commission.
	•	Standardized Measure. Future cash inflows from proved oil and natural gas reserves, less future development and production costs and future income tax expenses, discounted at 10 percent per annum to reflect the timing of future cash flows. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes.
	•	Tertiary Recovery. An enhanced recovery operation that normally occurs after waterflooding in which chemicals or natural gasses are used as the injectant. HPAI is a form of tertiary recovery.
	•	Unit. A specifically defined area within which acreage is treated as a single consolidated lease for operations and for allocations of costs and benefits without regard to ownership of the acreage. Units are established for the purpose of recovering oil and natural gas from specified zones or formations.
	•	Waterflood. A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.
	•	Working Interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

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ITEMS 1 and 2.	BUSINESS AND PROPERTIES

	•	the Cedar Creek Anticline (“CCA”) in the Williston Basin of Montana and North Dakota;
	•	the Permian Basin of west Texas and southeastern New Mexico;
	•	the Rockies, which includes non-CCA assets in the Williston and Powder River Basins of Montana and North Dakota and the Paradox Basin of southeastern Utah; and
	•	the Mid-Continent area, which includes the Arkoma and Anadarko Basins of Oklahoma, the North Louisiana Salt Basin, the East Texas Basin, and the Barnett Shale of northern Texas.

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					Year Ended December 31,
																	Three-Year
					2006				2005				2004				Average
					(In MBOE, except percentages)
Acquisition Reserve Replacement Ratio
	Changes in Proved Reserves:
		Acquisitions of minerals-in-place				64				14,796				22,239				12,366
	Divided by:
		Production				11,244				10,381				9,027				10,217
	Acquisition reserve replacement ratio					1	%			142	%			246	%			121	%
Development Reserve Replacement Ratio
	Changes in Proved Reserves:
		Extensions, discoveries, and improved recovery				27,504				19,158				20,580				22,414
		Revisions of estimates				(7,461	)			(928	)			(1,629	)			(3,339	)
			Total development program			20,043				18,230				18,951				19,075
	Divided by:
		Production				11,244				10,381				9,027				10,217
	Development reserve replacement ratio					178	%			176	%			210	%			187	%
Total Reserve Replacement Ratio
	Changes in Proved Reserves:
		Acquisitions of minerals-in-place				64				14,796				22,239				12,366
		Extensions, discoveries, and improved recovery				27,504				19,158				20,580				22,414
		Revisions of estimates				(7,461	)			(928	)			(1,629	)			(3,339	)
			Total reserve additions			20,107				33,026				41,190				31,441
	Divided by:
		Production				11,244				10,381				9,027				10,217
	Total reserve replacement ratio					179	%			318	%			456	%			308	%

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	Agreement to Acquire Big Horn Basin Assets

	Agreement to Acquire Williston Basin Assets

	Intention to Form a Master Limited Partnership

	Potential Divestiture of Mid-Continent Assets

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	•	Maintain an active development program. Our technological expertise, combined with our proficient field operations and reservoir engineering, has allowed us to increase production and reserves on our properties through infill, offset, and re-entry drilling, workovers, and recompletions. Our plan is to maintain an inventory of exploitation and development projects that provide a good source of future production. We also budget a portion of internally generated cash flow to secondary and tertiary recovery projects that are longer- term in nature, the benefit from which is not seen until some point in the future.
	•	Maximize existing reserves and production through HPAI. In addition to conventional development programs, we utilize HPAI techniques on the CCA properties to enhance our growth. HPAI involves using compressors to inject air into producing oil and natural gas formations in order to displace remaining resident hydrocarbons and force them under pressure to a common lifting point for production.
	•	Utilize other improved recovery techniques to maximize existing reserves and production. In addition to our HPAI programs, we use secondary and other tertiary recovery techniques to increase production and proved reserves on existing properties. Throughout our CCA properties and Permian Basin properties, we have successfully used waterflood enhancement programs to increase production. Waterflood enhancement is a secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells. On certain non-operated properties in the Rockies, a similar tertiary recovery technique that uses carbon dioxide instead of water is being used successfully. We believe that these other improved recovery projects, including carbon dioxide injection, will continue to be a source of reserve and production growth.
	•	Expand our reserves, production, and drilling inventory through a disciplined acquisition program. Using our experience, we have developed and refined an acquisition program designed to increase our reserves and complement our core properties. We have a staff of engineering and geoscience professionals who manage our core properties and use their experience and expertise to target and evaluate attractive acquisition opportunities. Following an acquisition, our technical professionals seek to enhance the value of the new assets through a proven development and exploitation program. We will continue to evaluate acquisition opportunities with the same disciplined commitment to acquire assets that fit our portfolio and create value for our shareholders.
	•	Explore for reserves. With the current commodity price environment, we believe exploration programs can provide a rate of return comparable to property acquisitions in certain areas. We seek to acquire undeveloped acreage and/or enter into drilling arrangements to explore in areas that complement our portfolio of properties. In keeping with our exploitation focus, the exploration projects expand existing fields or could set up multi-well exploitation projects if successful.
	•	Operate in a cost effective, efficient, and safe manner. As of December 31, 2006, we operated properties representing approximately 84 percent of our proved reserves, which allows us to control capital allocation, operate in a safe manner, and control timing of investments.

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			Year Ended December 31,
			2006				2005				2004
Production:
	Oil (MBbls)			7,335				6,871				6,679
	Natural gas (MMcf)			23,456				21,059				14,089
	Combined (MBOE)			11,244				10,381				9,027
Average Daily Production:
	Oil (Bbls/D)			20,096				18,826				18,249
	Natural gas (Mcf/D)			64,262				57,696				38,493
	Combined (BOE/D)			30,807				28,442				24,665
Average Prices:
	Oil (per Bbl)		$	47.30			$	44.82			$	33.04
	Natural gas (per Mcf)			6.24				7.09				5.53
	Combined (per BOE)			43.87				44.05				33.07
Average Costs per BOE:
	Lease operations expense		$	8.73			$	6.72			$	5.30
	Production, ad valorem, and severance taxes			4.43				4.39				3.36
	Depletion, depreciation, and amortization			10.09				8.25				5.38
	Exploration			2.71				1.39				0.44
	Derivative fair value (gain) loss			(2.17	)			0.51				0.56
	General and administrative			2.06				1.67				1.33
	Other operating expense			0.89				0.91				0.56
	Oil marketing, net			0.09				—				—

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			Oil Wells												Natural Gas Wells
											Average												Average
			Gross				Net				Working				Gross				Net				Working
			Wells(a)				Wells				Interest				Wells(a)				Wells				Interest
CCA				759				675				89	%			18				5				31	%
Permian Basin				1,991				780				39	%			523				240				46	%
Rockies				607				315				52	%			19				16				82	%
Mid-Continent				388				177				46	%			1,470				357				24	%
	Total			3,745				1,947				52	%			2,030				618				30	%

(a)	Our total wells include 2,587 operated wells and 3,188 non-operated wells. At December 31, 2006, 61 of our wells have multiple completions.

			Gross				Net
			Acreage				Acreage
CCA:
	Developed			110,083				104,135
	Undeveloped			62,465				50,956
				172,548				155,091
Permian:
	Developed			66,132				40,350
	Undeveloped			15,007				13,795
				81,139				54,145
Rockies:
	Developed			64,848				39,626
	Undeveloped			491,613				384,899
				556,461				424,525
Mid-Continent:
	Developed			390,869				101,023
	Undeveloped			169,867				79,902
				560,736				180,925
Total:
	Developed			631,932				285,134
	Undeveloped			738,952				529,552
				1,370,884				814,686

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			Year Ended December 31,
			2006								2005								2004
			Gross				Net				Gross				Net				Gross				Net
Development Wells:
	Productive			182				72				242				145				203				135
	Dry holes			4				3				4				2				1				1
				186				75				246				147				204				136
Exploratory Wells:
	Productive			71				19				34				22				32				30
	Dry holes			14				8				47				42				4				4
				85				27				81				64				36				34
Total:
	Productive			253				91				276				167				235				165
	Dry holes			18				11				51				44				5				5
				271				102				327				211				240				170

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	•	require the acquisition of various permits before drilling commences;
	•	require the installation of expensive pollution control equipment;
	•	enjoin some or all of the operations of facilities deemed in non-compliance with permits;
	•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production, and transportation activities;
	•	restrict the way in which wastes are handled and disposed;
	•	limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, areas inhabited by threatened of endangered species, and other protected areas;

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	•	require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells;
	•	impose substantial liabilities for pollution resulting from operations; and
	•	require preparation of a Resource Management Plan, Environmental Assessment and/or an Environmental Impact Statement for operations affecting federal lands or leases.

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	•	the location of wells;
	•	the method of drilling and casing wells;
	•	the surface use and restoration of properties upon which wells are drilled;
	•	the plugging and abandoning of wells; and
	•	notice to surface owners and other third parties.

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	Nature of Our Ownership Interests

																			Proved Reserve Quantities												PV-10
			2006 Net Production																at December 31, 2006												at December 31, 2006
							Natural																Natural
			Oil				Gas				Total				Percent				Oil				Gas				Total				Amount(a)				Percent
			(MBbls)				(MMcf)				(MBOE)								(MBbls)				(MMcf)				(MBOE)				(in thousands)
CCA				4,851				1,330				5,073				45%				117,868				15,750				120,493			$	1,113,352				57%
Permian Basin				1,277				5,841				2,250				20%				23,105				106,693				40,887				302,669				15%
Rockies				732				360				792				7%				8,716				2,895				9,198				426,160				22%
Mid-Continent				475				15,925				3,129				28%				3,745				181,426				33,983				119,035				6%
	Total			7,335				23,456				11,244				100%				153,434				306,764				204,561			$	1,961,216				100%

(a)

Calculated as the pretax present value of estimated future revenues to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities and non-property related expenses such as general and administrative expenses, debt service, and depletion, depreciation, and amortization; and discounted using an annual discount rate of 10 percent. Giving effect to hedging transactions, our PV-10 value would have been decreased by $21.7 million at December 31, 2006.

The Standardized Measure at December 31, 2006 is $1.5 billion. Standardized Measure differs from PV-10 by $499.4 million because Standardized Measure includes the effect of 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 feel PV-10 provides the best method for assessing relative value of each of our areas.

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	CCA Properties — Montana and North Dakota

	•	acquisition of additional interests;
	•	effective management of the existing wellbores;

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	•	the addition of strategically positioned new horizontal and vertical wellbores;
	•	re-entry horizontal drilling using existing wellbores;
	•	waterflood enhancements; and
	•	implementation of our HPAI program.

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	Permian Basin Properties — West Texas and New Mexico

	West Texas

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	New Mexico

	•	Entering into joint ventures;
	•	Agreements with major oil and gas companies;
	•	Drill to earn agreements;
	•	Farm-outs of close-in exploitation opportunities; and
	•	Establish built-in partnerships with other independent exploration companies.

	Mid-Continent Properties — Oklahoma, Arkansas, East Texas, North Texas, Kansas, and North Louisiana

	Oklahoma, Arkansas, North Texas, and Kansas

	North Louisiana Salt Basin and East Texas Basin

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	Rocky Mountain Properties — North Dakota, Montana, and Utah

	Williston Basin — North Dakota and Montana

	Bell Creek — Montana

	Paradox Basin — Utah

	•	royalties, overriding royalties, NPIs, and other burdens under oil and natural gas leases;
	•	contractual obligations, including, in some cases, development obligations arising under operating agreements, farmout agreements, production sales contracts, and other agreements that may affect the properties or their titles;
	•	liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors, and contractual liens under operating agreements;

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	•	pooling, unitization and communitization agreements, declarations, and orders; and
	•	easements, restrictions, rights-of-way, and other matters that commonly affect property.

	Oil and natural gas prices are volatile and sustained periods of low prices could materially and adversely affect our financial condition, results of operations, and cash flows.

	•	domestic and foreign supply of and demand for oil and natural gas;
	•	weather conditions;
	•	overall domestic and global economic conditions;
	•	political and economic conditions in oil and natural gas producing countries, including those in the Middle East and South America;
	•	actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;
	•	impact of the U.S. dollar exchange rates on oil and natural gas prices;
	•	technological advances affecting energy consumption;
	•	armed conflict in oil and natural gas producing countries;
	•	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; and
	•	the price and availability of alternative fuels.

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	•	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 and repayment of indebtedness;
	•	limit our ability to borrow money or raise additional capital; and
	•	impair our ability to pay distributions.

	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.

	•	future oil and natural gas prices;
	•	production levels;
	•	capital expenditures;
	•	operating and development costs;
	•	the effects of regulation; and
	•	availability of funds.

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	•	the actual prices we receive for oil and natural gas;
	•	our actual operating costs in producing oil and natural gas;
	•	the amount and timing of actual production;
	•	the amount and timing of our capital expenditures;
	•	supply of and demand for oil and natural gas; and
	•	changes in governmental regulations or taxation.

	The failure to replace our reserves could adversely affect our financial condition.

	The results of HPAI techniques are uncertain.

	We may be required to write down our asset carrying values.

	•	oil and natural gas prices decrease;
	•	we make substantial downward adjustments to our estimated proved reserves;
	•	our operating expenses or development costs increase substantially; or
	•	we experience poor performance from our development and exploitation activities.

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	If we do not make acquisitions on economically acceptable terms, our future growth may be limited.

	•	unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
	•	unable to obtain financing for these acquisitions on economically acceptable terms;
	•	outbid by competitors; or
	•	unable to obtain necessary regulatory approvals.

	•	expected revenues;
	•	the level of recoverable reserves and production;
	•	future oil and natural gas prices;
	•	operating costs; and
	•	the nature and amount of potential environmental and other liabilities.

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	The failure to properly manage growth through acquisitions could adversely affect our results of operations.

	•	diversion of management attention from existing operations;
	•	unexpected losses of key employees, customers, and suppliers of the acquired business;
	•	conforming the financial, technological, and management standards, processes, procedures, and controls of the acquired business with those of our existing operations; and
	•	increasing the scope, geographic diversity, and complexity of our operations.

	A substantial portion of our producing properties is located in one geographic area.

	Derivative instruments expose us to risks of financial loss in a variety of circumstances.

	•	a counterparty may not perform its obligation under the applicable derivative instrument; and
	•	there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received resulting in either a drop in the price we receive for production that is not offset by an increase in cash inflows from the derivative or vice versa.

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

	Drilling for 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.

	•	high costs, shortages or delivery delays of drilling rigs, equipment, labor, or other services;
	•	unexpected operational events and drilling conditions;
	•	reductions in oil and natural gas prices;
	•	limitations in the market for oil and natural gas;
	•	adverse weather conditions;
	•	facility or equipment malfunctions;
	•	equipment failures or accidents;
	•	title problems;
	•	pipe or cement failures;
	•	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 drilling and service tools;
	•	unusual or unexpected geological formations;
	•	loss of drilling fluid circulation;
	•	pressure or irregularities in formations;
	•	fires;
	•	natural disasters;
	•	blowouts, surface craterings and explosions; and
	•	uncontrollable flows of oil, natural gas or well fluids.

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

	Terrorist activities and the potential for military and other actions could adversely affect our business.

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

	The loss of key personnel could adversely affect our business.

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	Our business depends 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.

	Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial, technological, and other resources than we do.

	•	acquiring desirable producing properties or new leases for future exploration;
	•	marketing our oil and natural gas production;
	•	integrating new technologies; and
	•	acquiring the equipment and expertise necessary to develop and operate our properties.

	We are subject to complex federal, state, and local laws and regulations that could adversely affect our business.

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

	•	we may have difficulties borrowing money in the future for acquisitions, to meet our operating expenses, or for other purposes;
	•	the amount of our interest expense may increase because certain of our borrowings are at variable rates of interest, which, if interest rates increase, could result in higher interest expense;
	•	we will need to use a portion of the money we earn to pay principal and interest on our debt, which will reduce the amount of money we have to finance our operations and other business activities;
	•	we may be more vulnerable to economic downturns and adverse developments in our industry; and
	•	our debt level could limit our flexibility in planning for, or reacting to, changes in our business and industry.

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ITEM 1B.	UNRESOLVED STAFF COMMENTS

ITEM 3.	LEGAL PROCEEDINGS

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

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

		High				Low
2006
Quarter ended December 31		$	27.62			$	22.45
Quarter ended September 30			30.97				22.63
Quarter ended June 30			32.59				22.75
Quarter ended March 31			36.84				28.16
2005
Quarter ended December 31		$	39.37			$	29.69
Quarter ended September 30			39.48				28.63
Quarter ended June 30			29.63				22.12
Quarter ended March 31			30.48				21.44

											Total Number of				Maximum Number
											Shares Purchased				of Shares That May
			Total Number								as Part of Publicly				Yet Be Purchased
			of Shares				Average Price				Announced Plans				Under the Plans or
Month			Purchased				Paid per Share				or Programs				Programs
October				—			$	—				—				NA
November(a)				17,809			$	25.69				—				NA
December				—			$	—				—				NA
	Total			17,809			$	25.69				—				NA

(a)	We do not have a formal common stock repurchase program. During the fourth quarter of 2006, certain employees surrendered shares of common stock to pay income tax withholding obligations in conjunction with vesting of restricted shares under our 2000 Incentive Stock Plan.

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				Year Ended December 31,(h)
				2006				2005				2004				2003				2002
				(In thousands, except per share and per unit data)
Consolidated Statements of Operations Data:
	Revenues(a):
		Oil		$	346,974			$	307,959			$	220,649			$	176,351			$	134,854
		Natural gas			146,325				149,365				77,884				43,745				25,838
		Oil marketing(e)			147,563				—				—				—				—
	Total revenues			$	640,862			$	457,324			$	298,533			$	220,096			$	160,692
	Net income			$	92,398			$	103,425	(b)		$	82,147			$	63,641	(c)		$	37,685
	Net income per common share(d):
		Basic		$	1.78			$	2.12			$	1.74			$	1.41			$	0.84
		Diluted			1.75				2.09				1.72				1.40				0.83
	Weighted average number of common shares outstanding(d):
		Basic			51,865				48,682				47,090				45,153				45,047
		Diluted			52,736				49,522				47,738				45,500				45,242
Consolidated Statements of Cash Flows Data:
	Cash provided by (used in):
		Operating activities		$	297,333			$	292,269			$	171,821			$	123,818			$	91,509
		Investing activities			(397,430	)			(573,560	)			(433,470	)			(153,747	)			(159,316	)
		Financing activities			99,206				281,842				262,321				17,303				80,749
Production:
	Oil (Bbls)				7,335				6,871				6,679				6,601				6,037
	Natural gas (Mcf)				23,456				21,059				14,089				9,051				8,175
	Combined (BOE)				11,244				10,381				9,027				8,110				7,399
Average Sales Price:
	Oil ($/Bbl)			$	47.30			$	44.82			$	33.04			$	26.72			$	22.34
	Natural gas ($/Mcf)				6.24				7.09				5.53				4.83				3.16
	Combined ($/BOE)				43.87				44.05				33.07				27.14				21.72
Average Costs per BOE:
	Lease operations(f)			$	8.73			$	6.72			$	5.30			$	4.70			$	4.15
	Production, ad valorem, and severance taxes				4.43				4.39				3.36				2.71				2.12
	Depletion, depreciation, and amortization				10.09				8.25				5.38				4.13				4.67
	Exploration(f)				2.71				1.39				0.44				—				—
	General and administrative(f)				2.06				1.67				1.33				1.12				0.83
	Derivative fair value (gain) loss(g)				(2.17	)			0.51				0.56				(0.11	)			(0.12	)
	Other operating expense				0.89				0.91				0.56				0.43				0.28
	Oil marketing, net(e)				0.09				—				—				—				—

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			Year Ended December 31,(h)
			2006				2005				2004				2003				2002
			(In thousands, except per share and per unit data)
Reserves:
	Oil (Bbls)			153,434				148,387				134,048				117,732				111,674
	Natural gas (Mcf)			306,764				283,865				234,030				138,950				99,818
	Combined (BOE)			204,561				195,698				173,053				140,890				128,310

			As of December 31,
			2006				2005				2004				2003				2002
			(In thousands)
Consolidated Balance Sheets Data:
	Working capital		$	(40,745	)		$	(56,838	)		$	(15,566	)		$	(52	)		$	12,489
	Total assets			2,006,900				1,705,705				1,123,400				672,138				549,896
	Total debt			661,696				673,189				379,000				179,000				166,000
	Stockholders’ equity			816,865				546,781				473,575				358,975				296,266

(a)		For the years ended December 31, 2006, 2005, 2004, 2003, and 2002 we reduced revenue for NPI payments by $23.4 million, $21.2 million, $12.6 million, $5.8 million, and $2.0 million, respectively.
(b)		Net income for the year ended December 31, 2005 includes an after-tax loss on early redemption of debt of $12.2 million, which affects its comparability with other periods presented.
(c)		Net income for the year ended December 31, 2003 includes $0.9 million income from the cumulative effect of accounting change, net of tax, which affects its comparability with other periods presented.
(d)		Net income per common share and the weighted-average number of common shares outstanding have been revised for years prior to 2005 for the effects of the 3-for-2 stock split in July 2005.
(e)		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.
(f)		On January 1, 2006, we adopted the provisions of SFAS No. 123R, “Share-Based Payment” (“SFAS 123R”). Due to the adoption of SFAS 123R, non-cash stock-based compensation expense in all prior periods presented has been reclassified to allocate the amount to the same respective income statement lines as the employees’ salary, cash bonus, and benefits. This resulted in increases in LOE of $1.3 million, $0.7 million, and $0.2 million during 2005, 2004, and 2003, respectively, increases in general and administrative (“G&A”) expense of $2.6 million, $1.1 million, and $0.4 million during 2005, 2004, and 2003, respectively, and increases in exploration expense of $41 thousand and $29 thousand during 2005 and 2004, respectively.
(g)		During July 2006, we elected to discontinue hedge accounting prospectively for all commodity derivatives which were previously accounted for as hedges. From that point forward, all mark-to-market gains or losses on these derivative instruments are recorded in “Derivative fair value (gain) loss” while in periods prior to that point, only the ineffective portions of hedges were recorded in “Derivative fair value (gain) loss”.
(h)		We acquired Crusader Energy Corporation (“Crusader”) in October 2005 and Cortez Oil & Gas, Inc. (“Cortez”) in April 2004. The operating results or these entities are included in our Consolidated Statements of Operations from the date of acquisition forward.

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

	•	Overview of Business
	•	2006 Highlights
	•	2007 Outlook
	•	Results of Operations

	—	Comparison of 2006 to 2005
	—	Comparison of 2005 to 2004

	•	Capital Resources
	•	Capital Commitments
	•	Liquidity
	•	Off-Balance Sheet Arrangements
	•	Inflation and Changes in Prices
	•	Critical Accounting Policies and Estimates
	•	New Accounting Pronouncements
	•	Information Concerning Forward-Looking Statements

	•	Maintaining an active development program;
	•	Maximizing existing reserves and production through HPAI;
	•	Utilizing other improved recovery techniques to maximize existing reserves and production;
	•	Expanding our reserves, production, and drilling inventory through a disciplined acquisition program;

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	•	Exploring for reserves; and
	•	Operating in a cost effective, efficient, and safe manner.

	•	Oil and natural gas reserves increased five percent to 205 MMBOE. During 2006, we added 20.1 MMBOE, replacing 179 percent of the 11.2 MMBOE produced in 2006. Please read “Items 1 and 2. Business and Properties — General — Oil and Natural Gas Production and Reserves” for the calculation of our reserve replacement ratios. At December 31, 2006, oil reserves accounted for 75 percent of total proved reserves, and 65 percent of proved reserves are developed. However, primarily as a result of a decline in natural gas prices, the estimated pretax present value of our reserves decreased by 27 percent to $2.0 billion (using a 10 percent discount rate and constant year end prices of $61.06 for oil and $5.48 for natural gas). The Standardized Measure at December 31, 2006 was $1.5 billion. Standardized Measure differs from PV-10 by $499.4 million, because Standardized Measure includes the effect of future income taxes.
	•	During 2006, we had oil and natural gas revenues of $493.3 million. This represents an eight percent increase over the $457.3 million of oil and natural gas revenues reported in 2005.

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	•	Our realized average oil price for 2006, including the effects of hedging, increased $2.48 per Bbl to $47.30 per Bbl as compared to $44.82 per Bbl in 2005. Average oil differentials more than doubled in 2006 to $11.80 per Bbl as compared to $5.50 per Bbl in 2005, which somewhat offset higher production volumes and higher wellhead prices. Our realized average natural gas price for 2006, including the effects of hedging, decreased $0.85 per Mcf to $6.24 per Mcf as compared to $7.09 per Mcf in 2005.
	•	Production volumes for 2006 increased eight percent to 30,807 BOE/ D (11.2 MMBOE), compared with 2005 production volumes of 28,442 BOE/ D (10.4 MMBOE). The rise in production volumes was attributable to our drilling program, HPAI uplift, and acquisitions completed in the second half of 2005. Oil represented 65 percent and 66 percent of our total production volumes in 2006 and 2005, respectively.
	•	During 2006, we generated cash flows from operating activities of $297.3 million. This represents a five percent increase over the $292.3 million of cash flows from operating activities we reported for 2005.
	•	On April 4, 2006, we closed a public offering of 4.0 million shares of common stock at a price of $32.00 per share. The net proceeds of the offering, after deducting underwriting discounts and commissions and the expenses of the offering, were $127.1 million. We used the net proceeds to reduce the amounts outstanding under our revolving credit facility, invest in oil and natural gas activities, and to pay general corporate expenses.
	•	We reported net income of $92.4 million, or $1.75 per diluted share, in 2006, as compared to $103.4 million, or $2.09 per diluted share, for 2005. In addition to the increase in the effective tax rate that decreased net income by $4.7 million, the decrease in net income was primarily due to the following pretax items:

	—	Our natural gas wellhead price was $1.28 per Mcf less in 2006 than 2005 which negatively impacted revenues and margins;
	—	Increased service costs, expensing of stock options, high operating costs in the Mid-Continent area, and expensing of HPAI costs for LOE in 2006 resulted in an increase of $28.5 million, or $2.01 per BOE;
	—	DD&A per BOE increased to $10.09 per BOE as compared to $8.25 per BOE in 2005 as a result of higher than historical finding and development costs, which added $27.8 million to total DD&A;
	—	Exploration expense was $16.1 million higher due to a larger exploration program in 2006 than 2005; and
	—	Interest expense increased by $11.1 million in 2006 as compared to 2005 as a result of higher average debt levels due to financing acquisitions and our capital program.

	Partially offsetting the above items, the change in net income was positively impacted by the following pretax items:

	—	Derivative fair value gain increased $29.8 million, primarily as a result of our discontinuance of hedge accounting in July 2006; and
	—	The recognition of a $19.5 million loss on the early redemption of debt in 2005.

	Diluted earnings per share were lower as a result of the above items and the aforementioned public offering of common stock in April.

	•	We entered into a joint development agreement with ExxonMobil to develop seven natural gas fields in West Texas. Under the terms of the agreement, we have the opportunity to develop

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		approximately 100,000 gross acres and will earn 30 percent of ExxonMobil’s working interest in each well drilled. We will operate each well during the drilling and completion phase, after which ExxonMobil will assume operational control of the well. In 2006, we drilled 24 wells, 12 of which were commitment wells, with an investment of $29.5 million under the joint development agreement. At December 31, 2006, we had advanced $22.4 million to ExxonMobil for its portion of drilling these commitment wells.
	•	We invested $377.6 million in oil and natural gas activities during 2006 (excluding asset retirement obligations of $0.9 million). Of this amount, we invested $348.7 million in development, exploitation, HPAI expansion, and exploration activities, which yielded 253 gross (91.6 net) productive wells, and $28.9 million on acquisitions primarily of undeveloped leases. We operated between 9 and 12 rigs during 2006, including 4 rigs related to our west Texas joint development agreement.

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	•	Invest an amount equal to or less than our cash flows from operations;
	•	Evaluate the potential divestiture of certain Oklahoma natural gas properties; and
	•	Raise capital through an initial public offering of limited partnership interests in the MLP.

Development and exploitation			$	202,000
Exploration				71,000
Acquisitions of leasehold acreage				11,000
Other				1,000
	Total		$	285,000

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				Year Ended December 31,
												Increase/
				2006				2005				(Decrease)
				(In thousands, except per unit and
				per day amounts)
Revenues:
	Oil wellhead			$	399,180			$	350,837			$	48,343
	Oil hedges				(52,206	)			(42,878	)			(9,328	)
		Total oil revenues		$	346,974			$	307,959			$	39,015				13%
	Natural gas wellhead			$	154,458			$	165,794			$	(11,336	)
	Natural gas hedges				(8,133	)			(16,429	)			8,296
		Total natural gas revenues		$	146,325			$	149,365			$	(3,040	)			(2	)%
	Combined wellhead			$	553,638			$	516,631			$	37,007
	Combined hedges				(60,339	)			(59,307	)			(1,032	)
		Total combined oil and natural gas revenues			493,299				457,324				35,975				8%
		Oil marketing revenues			147,563				—				147,563
		Total revenues		$	640,862			$	457,324			$	183,538
Revenues ($/Unit):
	Oil wellhead			$	54.42			$	51.06			$	3.36
	Oil hedges				(7.12	)			(6.24	)			(0.88	)
		Total oil revenues		$	47.30			$	44.82			$	2.48				6%
	Natural gas wellhead			$	6.59			$	7.87			$	(1.28	)
	Natural gas hedges				(0.35	)			(0.78	)			0.43
		Total natural gas revenues		$	6.24			$	7.09			$	(0.85	)			(12	)%
	Combined wellhead			$	49.24			$	49.76			$	(0.52	)
	Combined hedges				(5.37	)			(5.71	)			0.34
		Total combined oil and natural gas revenues		$	43.87			$	44.05			$	(0.18	)			0%
Total production volumes:
	Oil (Bbls)				7,335				6,871				464				7%
	Natural gas (Mcf)				23,456				21,059				2,397				11%
	Combined (BOE)				11,244				10,381				863				8%
Daily production volumes:
	Oil (Bbl/ D)				20,096				18,826				1,270				7%
	Natural gas (Mcf/ D)				64,262				57,696				6,566				11%
	Combined (BOE/ D)				30,807				28,442				2,365				8%
Average NYMEX prices:
	Oil (per Bbl)			$	66.22			$	56.56			$	9.66				17%
	Natural gas (per Mcf)			$	6.99			$	8.96			$	(1.97	)			(22	)%

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			Year Ended
			December 31,
			2006				2005
Oil wellhead ($/Bbl)			$	54.42			$	51.06
Average NYMEX ($/Bbl)			$	66.22			$	56.56
	Differential to NYMEX		$	(11.80	)		$	(5.50	)
	Oil wellhead to NYMEX percentage			82	%			90	%
Natural gas wellhead ($/Mcf)			$	6.59			$	7.87
Average NYMEX ($/Mcf)			$	6.99			$	8.96
	Differential to NYMEX		$	(0.40	)		$	(1.09	)
	Natural gas wellhead to NYMEX percentage			94	%			88	%

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Oil marketing revenues			$	147,563
Oil marketing expenses				(148,571	)
	Oil marketing, net		$	(1,008	)
Oil marketing revenues per BOE			$	13.12
Oil marketing expenses per BOE				(13.21	)
	Oil marketing, net per BOE		$	(0.09	)

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				Year Ended December 31,
												Increase/
				2006				2005				(Decrease)
Expenses (in thousands):
	Production:
		Lease operations		$	98,194			$	69,744			$	28,450
		Production, ad valorem, and severance taxes			49,780				45,601				4,179
	Total production expenses				147,974				115,345				32,629				28%
	Other:
		Depletion, depreciation, and amortization			113,463				85,627				27,836
		Exploration			30,519				14,443				16,076
		General and administrative			23,194				17,268				5,926
		Oil marketing			148,571				—				148,571
		Derivative fair value (gain) loss			(24,388	)			5,290				(29,678	)
		Loss on early redemption of debt			—				19,477				(19,477	)
		Other operating			10,023				9,485				538
	Total operating				449,356				266,935				182,421				68%
	Interest				45,131				34,055				11,076
	Current and deferred income tax provision				55,406				53,948				1,458
Total expenses				$	549,893			$	354,938			$	194,955				55%
Expenses (per BOE):
	Production:
		Lease operations		$	8.73			$	6.72			$	2.01
		Production, ad valorem, and severance taxes			4.43				4.39				0.04
	Total production expenses				13.16				11.11				2.05				18%
	Other:
		Depletion, depreciation, and amortization			10.09				8.25				1.84
		Exploration			2.71				1.39				1.32
		General and administrative			2.06				1.67				0.39
		Derivative fair value (gain) loss			(2.17	)			0.51				(2.68	)
		Loss on early redemption of debt			—				1.88				(1.88	)
		Other operating			0.89				0.91				(0.02	)
	Total operating				26.74				25.72				1.02				4%
	Interest				4.01				3.28				0.73
	Current and deferred income tax provision				4.93				5.20				(0.27	)
Total expenses				$	35.68			$	34.20			$	1.48				4%

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	•	increases in prices paid to oilfield service companies and suppliers due to a current higher price environment;
	•	increased operational activity to maximize production;
	•	the operation of higher operating cost wells (which have offered acceptable rates of return due to increases in oil and natural gas prices);
	•	higher than expected operating costs in the Anadarko Basin and Arkoma Basin of Oklahoma and the North Louisiana Salt Basin;
	•	higher salary levels for engineers and other technical professionals;
	•	expensing HPAI costs associated with the Little Beaver Phase 2 program; and
	•	increased stock-based compensation expense attributable to equity instruments granted to employees under the Plan.

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			Year Ended
			December 31,
											Increase/
			2006				2005				(Decrease)
			(In thousands)
Dry holes			$	17,257			$	8,632			$	8,625
Geological and seismic				1,720				3,137				(1,417	)
Delay rentals				670				635				35
Impairment of unproved acreage				10,872				2,039				8,833
	Total		$	30,519			$	14,443			$	16,076

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					Year Ended
					December 31,
													Increase/
					2006				2005				(Decrease)
					(In thousands)
Designated cash flow hedges:
	Ineffectiveness — Derivative commodity contracts				$	1,748			$	8,371			$	(6,623	)
Undesignated derivative contracts:
	Mark-to-market loss (gain):
		Interest rate swap				—				462				(462	)
		Commodity contracts				(17,279	)			(2,050	)			(15,229	)
	Settlements:
		Interest rate swap				—				(312	)			312
		Commodity contracts				(8,857	)			(1,181	)			(7,676	)
			Total derivative fair value (gain) loss		$	(24,388	)		$	5,290			$	(29,678	)

			Year Ended
			December 31,
											Increase/
			2006				2005				(Decrease)
			(In thousands)
83/8% Notes			$	—			$	7,852			$	(7,852	)
61/4% Notes				9,684				9,375				309
6% Notes				18,418				8,437				9,981
71/4% Notes				10,984				1,145				9,839
Revolving credit facility				3,609				4,554				(945	)
Other				2,436				2,692				(256	)
	Total		$	45,131			$	34,055			$	11,076

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				Year Ended
				December 31,
												Increase/
				2005				2004				(Decrease)
				(In thousands, except per unit and
				per day amounts)
Revenues:
	Oil wellhead			$	350,837			$	255,394			$	95,443
	Oil hedges				(42,878	)			(34,745	)			(8,133	)
		Total oil revenues		$	307,959			$	220,649			$	87,310				40	%
	Natural gas wellhead			$	165,794			$	81,112			$	84,682
	Natural gas hedges				(16,429	)			(3,228	)			(13,201	)
		Total natural gas revenues		$	149,365			$	77,884			$	71,481				92	%
	Combined wellhead			$	516,631			$	336,506			$	180,125
	Combined hedges				(59,307	)			(37,973	)			(21,334	)
		Total combined oil and natural gas revenues		$	457,324			$	298,533			$	158,791				53	%
Revenues ($/Unit):
	Oil wellhead			$	51.06			$	38.24			$	12.82
	Oil hedges				(6.24	)			(5.20	)			(1.04	)
		Total oil revenues		$	44.82			$	33.04			$	11.78				36	%
	Natural gas wellhead			$	7.87			$	5.76			$	2.11
	Natural gas hedges				(0.78	)			(0.23	)			(0.55	)
		Total natural gas revenues		$	7.09			$	5.53			$	1.56				28	%
	Combined wellhead			$	49.76			$	37.28			$	12.48
	Combined hedges				(5.71	)			(4.21	)			(1.50	)
		Total combined oil and natural gas revenues		$	44.05			$	33.07			$	10.98				33	%

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			Year Ended
			December 31,
											Increase/
			2005				2004				(Decrease)
			(In thousands, except per unit and
			per day amounts)
Total production volumes:
	Oil (Bbls)			6,871				6,679				192				3	%
	Natural gas (Mcf)			21,059				14,089				6,970				49	%
	Combined (BOE)			10,381				9,027				1,354				15	%
Daily production volumes:
	Oil (Bbl/ D)			18,826				18,249				577				3	%
	Natural gas (Mcf/ D)			57,696				38,493				19,203				50	%
	Combined (BOE/ D)			28,442				24,665				3,777				15	%
Average NYMEX prices:
	Oil (per Bbl)		$	56.56			$	41.26			$	15.30				37	%
	Natural gas (per Mcf)		$	8.96			$	6.11			$	2.85				47	%

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			Year Ended
			December 31,
			2005				2004
Oil wellhead ($/Bbl)			$	51.06			$	38.24
Average NYMEX ($/Bbl)			$	56.56			$	41.26
	Differential to NYMEX		$	(5.50	)		$	(3.02	)
	Oil wellhead to NYMEX percentage			90	%			93	%
Natural gas wellhead ($/Mcf)			$	7.87			$	5.76
Average NYMEX ($/Mcf)			$	8.96			$	6.11
	Differential to NYMEX		$	(1.09	)		$	(0.35	)
	Natural gas wellhead to NYMEX percentage			88	%			94	%

				Year Ended
				December 31,
												Increase/
				2005				2004				(Decrease)
Expenses (in thousands):
	Production:
		Lease operations		$	69,744			$	47,807			$	21,937
		Production, ad valorem, and severance taxes			45,601				30,313				15,288
	Total production expenses				115,345				78,120				37,225				48	%
	Other:
		Depletion, depreciation, and amortization			85,627				48,522				37,105
		Exploration			14,443				3,935				10,508
		General and administrative			17,268				12,059				5,209
		Derivative fair value loss			5,290				5,011				279
		Loss on early redemption of debt			19,477				—				19,477
		Other operating			9,485				5,028				4,457
	Total operating				266,935				152,675				114,260				75	%
	Interest				34,055				23,459				10,596
	Current and deferred income tax provision				53,948				40,492				13,456
Total expenses				$	354,938			$	216,626			$	138,312				64	%

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				Year Ended
				December 31,
												Increase/
				2005				2004				(Decrease)
Expenses (per BOE):
	Production:
		Lease operations		$	6.72			$	5.30			$	1.42
		Production, ad valorem, and severance taxes			4.39				3.36				1.03
	Total production expenses				11.11				8.66				2.45				28	%
	Other:
		Depletion, depreciation, and amortization			8.25				5.38				2.87
		Exploration			1.39				0.44				0.95
		General and administrative			1.67				1.33				0.34
		Derivative fair value loss			0.51				0.56				(0.05	)
		Loss on early redemption of debt			1.88				—				1.88
		Other operating			0.91				0.56				0.35
	Total operating				25.72				16.93				8.79				52	%
	Interest				3.28				2.60				0.68
	Current and deferred income tax provision				5.20				4.49				0.71
Total expenses				$	34.20			$	24.02			$	10.18				42	%

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			Year Ended
			December 31,
											Increase/
			2005				2004				(Decrease)
			(In thousands)
Dry holes			$	8,632			$	2,050			$	6,582
Geological and seismic				3,137				1,006				2,131
Delay rentals				635				204				431
Impairment of unproved acreage				2,039				675				1,364
	Total		$	14,443			$	3,935			$	10,508

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				Year Ended
				December 31,
												Increase/
				2005				2004				(Decrease)
				(In thousands)
Designated cash flow hedges:
	Ineffectiveness — Commodity contracts			$	8,371			$	5,018			$	3,353
Undesignated derivative contracts:
	Mark-to-market loss — Interest rate swap				150				272				(122	)
	Mark-to-market gain — Commodity contracts				(3,231	)			(279	)			(2,952	)
		Total derivative fair value loss		$	5,290			$	5,011			$	279

			Year Ended
			December 31,
											Increase/
			2005				2004				(Decrease)
			(In thousands)
83/8% Notes			$	7,852			$	12,563			$	(4,711	)
61/4% Notes				9,375				7,005				2,370
6% Notes				8,437				—				8,437
71/4% Notes				1,145				—				1,145
Revolving credit facility				4,554				1,565				2,989
Other				2,692				2,326				366
	Total		$	34,055			$	23,459			$	10,596

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	Capital Resources

	•	Cash flows from operating activities;
	•	Cash flows from financing activities; and
	•	Current capitalization.

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	Capital Commitments

	•	Development, exploitation, and exploration of our existing oil and natural gas properties;
	•	Acquisitions of oil and natural gas properties and leasehold acreage;
	•	Other general property and equipment;
	•	Funding of necessary working capital; and
	•	Payment of contractual obligations.

			Year Ended December 31,
			2006				2005				2004
			(In thousands)
Development and exploitation			$	228,014			$	236,467			$	117,464
Exploration				95,205				57,046				30,546
HPAI				25,470				32,053				39,628
	Total		$	348,689			$	325,566			$	187,638

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			Year Ended December 31,
			2006				2005				2004
			(In thousands)
Acquisitions of proved property			$	4,486			$	224,469			$	204,907
Acquisitions of leasehold acreage				24,462				21,205				33,926
	Total		$	28,948			$	245,674			$	238,833

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			Payments Due by Period
Contractual Obligations and Commitments			Total				2007				2008-2009				2010-2011				Thereafter
			(In thousands)
61/4% Notes(a)			$	220,313			$	9,375			$	18,750			$	18,750			$	173,438
6% Notes(a)				462,000				18,000				36,000				36,000				372,000
71/4% Notes(a)				269,625				10,875				21,750				21,750				215,250
Revolving credit facility(a)				80,212				3,053				6,106				71,053				—
Derivative obligations(b)				77,524				53,804				22,880				840				—
Development commitments(c)				199,092				135,779				62,942				371				—
Operating leases(d)				14,218				1,818				4,304				4,199				3,897
Asset retirement obligations(e)				134,103				636				1,273				1,273				130,921
	Total		$	1,457,087			$	233,340			$	174,005			$	154,236			$	895,506

(a)	Amounts included in the table above include both principal and projected interest payments. Please read Note 8 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our long-term debt.

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(b)	Derivative obligations represent net liabilities for derivatives that were valued as of December 31, 2006. With the exception of $54.7 million of deferred premiums on derivative contracts, the ultimate settlement amounts of the remaining portions of our derivative obligations are unknown because they are subject to continuing market risk. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” and Note 13 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our derivative obligations.
(c)	Development commitments include authorized purchases for work in process of $46.7 million which is accrued at December 31, 2006, future minimum payments for electricity, seismic data analysis, and drilling rig operations of $140.4 million, and $12.0 million for minimum capital obligations associated with the remaining commitment wells to be drilled under the ExxonMobil joint development agreement. Also at December 31, 2006, we had $132.3 million of authorized purchases not placed to vendors (authorized AFEs), which were not accrued and are excluded from the above table but are budgeted for and expected to be made unless circumstances change.
(d)	Operating leases represent office space and equipment obligations that have non-cancelable lease terms in excess of one year. 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.
(e)	Asset retirement obligations represent the undiscounted future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal at the completion of field life. Please read Note 5 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our AROs.

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Ratio of Total Outstandings to Borrowing Base		Eurodollar Loans(a)				Base Rate Loans(b)
Less than .40 to 1			LIBOR + 1.000	%			Base Rate + 0.000	%
From .40 to 1 but less than .75 to 1			LIBOR + 1.250	%			Base Rate + 0.000	%
From .75 to 1 but less than .90 to 1			LIBOR + 1.500	%			Base Rate + 0.250	%
.90 to 1 or greater			LIBOR + 1.750	%			Base Rate + 0.500	%

(a)	The LIBOR rate is equal to the rate determined by Bank of America, N.A. to be the average British Bankers Association Interest Settlement Rate for deposits in dollars for a similar interest period (either one, two, three, or six months, or such other period that is twelve months or less as selected by us and consented to by each lender).

(b)		The Base Rate is calculated as the higher of (i) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (ii) the federal funds effective rate plus 0.5 percent.

	•	incur additional indebtedness;
	•	pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;
	•	make investments;

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	•	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; and
	•	consolidate, merge or transfer assets.

	Off-Balance Sheet Arrangements

	Inflation and Changes in Prices

			Year Ended December 31,
			2006				2005				2004
Net Price Realization with Hedges:
	Oil ($/Bbl)		$	47.30			$	44.82			$	33.04
	Natural gas ($/Mcf)			6.24				7.09				5.53
	Combined ($/BOE)			43.87				44.05				33.07
Average Wellhead Price:
	Oil ($/Bbl)		$	54.42			$	51.06			$	38.24
	Natural gas ($/Mcf)			6.59				7.87				5.76
	Combined ($/BOE)			49.24				49.76				37.28

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	Critical Accounting Policies and Estimates

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	Hedging and Related Activities

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	New Accounting Pronouncements

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

	FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”)

	•	expected capital expenditures and the focus of our capital program;
	•	areas of future growth;
	•	our drilling program;
	•	future horizontal development, secondary development, and tertiary recovery potential;
	•	the implementation of our HPAI program, the ability to expand the program to other parts of the CCA and the effects thereof;
	•	the completion of current HPAI projects and the effects thereof;
	•	anticipated prices for oil and natural gas and expectations regarding differentials between wellhead prices received and benchmark prices (including, without limitation, the effects of increased Canadian oil production and refinery turnarounds);
	•	projected revenues, lifting costs, LOE; production taxes, DD&A expense, G&A expenses, other operating expenses, and taxes;
	•	timing and amount of future production of oil and natural gas;
	•	the benefits to be derived from acquisitions and divestitures;

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	•	availability of pipeline capacity;
	•	expected hedging positions and payments related to hedging contracts;
	•	expectations regarding working capital, cash flow, and anticipated liquidity;
	•	projected borrowings under our revolving credit facility and expectations regarding a new revolving credit facility;
	•	plans regarding an MLP;
	•	expected reductions in our debt levels and the steps taken to reduce our debt; and
	•	marketing of oil and natural gas.

ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

		Percentage of				Percentage of
		Hedged Oil				Hedged Natural Gas
Counterparty		Production Committed				Production Committed
BNP Paribas			7.6	%			66.6	%
Calyon			17.0	%			14.3	%
Deutsche Bank			34.9	%			—
J. Aron & Company			3.8	%			19.0	%
Wachovia			22.6	%			—

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	Oil Derivative Instruments

		Daily				Average				Daily				Average				Daily				Average
		Floor				Floor				Short Floor				Short Floor				Swap				Swap				Fair Market
Period		Volume				Price				Volume				Price				Volume				Price				Value
		(Bbl)				(Per Bbl)				(Bbl)				(Per Bbl)				(Bbl)				(Per Bbl)				(In thousands)
Jan. – Dec. 2007			8,000			$	53.75				—			$	—				3,000			$	36.75			$	(26,347	)
Jan. – June 2008			12,000				64.17				(4,000	)			50.00				1,000				58.59				9,536
July – Dec. 2008			8,000				66.25				(4,000	)			50.00				—				—				8,471
Jan. – Dec. 2009			5,000				70.00				(5,000	)			50.00				—				—				11,972
																										$	3,632

	Natural Gas Derivative Instruments

		Daily				Average				Daily				Average				Daily				Average
		Floor				Floor				Short Floor				Short Floor				Swap				Swap				Fair Market
Period		Volume				Price				Volume				Price				Volume				Price				Value
		(Mcf)				(Per Mcf)				(Mcf)				(Per Mcf)				(Mcf)				(Per Mcf)				(In thousands)
Jan. – Dec. 2007			32,500			$	6.74				—			$	—				10,000			$	4.99			$	7,567
Jan. – Dec. 2008			10,000				6.25				—				—				—				—				2,400
																										$	9,967

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

		Page
Report of Independent Registered Public Accounting Firm			69
Consolidated Balance Sheets as of December 31, 2006 and 2005			70
Consolidated Statements of Operations for the Years Ended December 31, 2006, 2005, and 2004			71
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2006, 2005, and 2004			72
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005, and 2004			73
Notes to Consolidated Financial Statements			74
Supplementary Information			101

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	/s/ Ernst & Young LLP

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					December 31,
					2006				2005
					(In thousands, except
					share and per share
					amounts)
ASSETS
Current assets:
	Cash and cash equivalents				$	763			$	1,654
	Accounts receivable					81,470				76,960
	Inventory					18,170				11,231
	Derivatives					17,349				8,826
	Deferred taxes					24,978				29,030
	Prepaid expenses					2,988				5,656
		Total current assets				145,718				133,357
Properties and equipment, at cost — successful efforts method:
	Proved properties					2,033,914				1,691,175
	Unproved properties					47,548				37,646
	Accumulated depletion, depreciation, and amortization					(364,780	)			(255,564	)
						1,716,682				1,473,257
	Other property and equipment					18,231				15,894
	Accumulated depreciation					(7,791	)			(5,366	)
						10,440				10,528
Goodwill						60,606				59,046
Derivatives						40,715				17,316
Other						32,739				12,201
		Total assets			$	2,006,900			$	1,705,705
			LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable				$	18,204			$	27,281
	Accrued lease operations expense					8,582				6,633
	Accrued development capital					44,492				38,899
	Interest payable					11,273				12,531
	Production, ad valorem, and severance taxes payable					10,915				12,566
	Accrued oil purchases					11,191				—
	Derivatives					60,448				76,515
	Other					21,358				15,770
		Total current liabilities				186,463				190,195
Derivatives						38,688				66,563
Future abandonment cost						19,205				14,430
Deferred taxes						282,825				213,268
Long-term debt						661,696				673,189
Other						1,158				1,279
		Total liabilities				1,190,035				1,158,924
Commitments and contingencies (see Note 4)						—				—
Stockholders’ 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, 53,046,675 and 48,784,846 issued and outstanding, respectively					531				488
	Additional paid-in capital					457,201				316,619
	Treasury stock, at cost, of 17,809 and 11,169 shares, respectively					(457	)			(375	)
	Retained earnings					394,917				302,875
	Accumulated other comprehensive loss					(35,327	)			(72,826	)
		Total stockholders’ equity				816,865				546,781
		Total liabilities and stockholders’ equity			$	2,006,900			$	1,705,705

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				Year Ended December 31,
				2006				2005				2004
				(In thousands, except per share
				amounts)
Revenues:
	Oil			$	346,974			$	307,959			$	220,649
	Natural gas				146,325				149,365				77,884
	Oil marketing				147,563				—				—
Total revenues					640,862				457,324				298,533
Expenses:
	Production:
		Lease operations			98,194				69,744				47,807
		Production, ad valorem, and severance taxes			49,780				45,601				30,313
	Depletion, depreciation, and amortization				113,463				85,627				48,522
	Exploration				30,519				14,443				3,935
	General and administrative				23,194				17,268				12,059
	Oil marketing				148,571				—				—
	Derivative fair value (gain) loss				(24,388	)			5,290				5,011
	Loss on early redemption of debt				—				19,477				—
	Other operating				10,023				9,485				5,028
Total expenses					449,356				266,935				152,675
Operating income					191,506				190,389				145,858
Other income (expenses):
	Interest				(45,131	)			(34,055	)			(23,459	)
	Other				1,429				1,039				240
Total other income (expenses)					(43,702	)			(33,016	)			(23,219	)
Income before income taxes					147,804				157,373				122,639
Income tax provision					(55,406	)			(53,948	)			(40,492	)
Net income				$	92,398			$	103,425			$	82,147
Net income per common share:
		Basic		$	1.78			$	2.12			$	1.74
		Diluted			1.75				2.09				1.72
Weighted average common shares outstanding:
		Basic			51,865				48,682				47,090
		Diluted			52,736				49,522				47,738

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																												Accumulated
				Shares of								Additional				Shares of												Other				Total
				Common				Common				Paid-In				Treasury				Treasury				Retained				Comprehensive				Stockholders’
				Stock				Stock				Capital				Stock				Stock				Earnings				Loss				Equity
				(In thousands)
Balance at December 31, 2003					45,351			$	454			$	251,186				—			$	—			$	117,365			$	(10,030	)		$	358,975
	Exercise of stock options				303				3				4,118				—				—				—				—				4,121
	Issuance of common stock				3,000				30				52,899				—				—				—				—				52,929
	Non-cash stock-based compensation				—				—				1,770				—				—				—				—				1,770
	Components of comprehensive income:
		Net income			—				—				—				—				—				82,147				—				82,147
		Change in deferred hedge gain/loss, net of tax of $15,757			—				—				—				—				—				—				(26,367	)			(26,367	)
	Total comprehensive income																																55,780
Balance at December 31, 2004					48,654				487				309,973				—				—				199,512				(36,397	)			473,575
	Exercise of stock options and vesting of restricted stock				138				1				2,817				—				—				—				—				2,818
	Purchase of treasury stock				—				—				—				(18	)			(570	)			—				—				(570	)
	Cancellation of treasury stock				(7	)			—				(133	)			7				195				(62	)			—				—
	Non-cash stock-based compensation				—				—				3,962				—				—				—				—				3,962
	Components of comprehensive income:
		Net income			—				—				—				—				—				103,425				—				103,425
		Change in deferred hedge gain/loss, net of tax of $21,701			—				—				—				—				—				—				(36,429	)			(36,429	)
	Total comprehensive income																																66,996
Balance at December 31, 2005					48,785				488				316,619				(11	)			(375	)			302,875				(72,826	)			546,781
	Exercise of stock options and vesting of restricted stock				280				3				3,641				—				—				—				—				3,644
	Purchase of treasury stock				—				—				—				(25	)			(633	)			—				—				(633	)
	Cancellation of treasury stock				(18	)			—				(195	)			18				551				(356	)			—				—
	Issuance of common stock				4,000				40				127,061				—				—				—				—				127,101
	Non-cash stock-based compensation				—				—				10,075				—				—				—				—				10,075
	Components of comprehensive income:
		Net income			—				—				—				—				—				92,398				—				92,398
		Change in deferred hedge gain/loss, net of tax of $22,365			—				—				—				—				—				—				37,499				37,499
	Total comprehensive income																																129,897
Balance at December 31, 2006					53,047			$	531			$	457,201				(18	)		$	(457	)		$	394,917			$	(35,327	)		$	816,865

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					Year Ended December 31,
					2006				2005				2004
					(In thousands)
Cash flows from operating activities:
	Net income				$	92,398			$	103,425			$	82,147
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depletion, depreciation, and amortization				113,463				85,627				48,522
		Non-cash exploration expense				28,128				10,706				2,761
		Deferred taxes				51,220				56,032				38,579
		Non-cash stock-based compensation expense				8,980				3,962				1,770
		Non-cash derivative fair value				(10,434	)			12,637				12,449
		Loss on early redemption of debt				—				19,477				—
		Other non-cash expense				7,577				1,912				781
		(Gain) loss on disposition of assets				(297	)			352				271
		Changes in operating assets and liabilities:
			Accounts receivable			(305	)			(30,192	)			(10,719	)
			Other current assets			(4,945	)			(6,096	)			(7,220	)
			Other assets			(365	)			(4,798	)			(5,568	)
			Accounts payable			1,833				(444	)			(1,128	)
			Other current liabilities			10,080				39,669				9,176
Net cash provided by operating activities						297,333				292,269				171,821
Cash flows from investing activities:
	Proceeds from disposition of assets					1,522				753				703
	Purchases of other property and equipment					(4,290	)			(6,767	)			(7,594	)
	Acquisition of oil and natural gas properties					(30,119	)			(154,615	)			(116,316	)
	Acquisition of Cortez Oil & Gas, Inc., net of cash acquired					—				—				(123,808	)
	Acquisition of Crusader Energy Corp., net of cash acquired					—				(91,095	)			—
	Development of oil and natural gas properties					(340,582	)			(321,836	)			(186,455	)
	Advances to working interest partners					(22,425	)			—				—
	Other					(1,536	)			—				—
Net cash used in investing activities						(397,430	)			(573,560	)			(433,470	)
Cash flows from financing activities:
	Proceeds from issuance of common stock					128,000				—				53,900
	Offering costs paid					(899	)			—				(971	)
	Purchase of treasury stock					(633	)			(570	)			—
	Payment of debt issuance costs					(147	)			(534	)			(4,808	)
	Exercise of stock options					3,644				1,468				2,756
	Proceeds from long-term debt					282,000				997,980				478,500
	Payments on long-term debt					(294,000	)			(719,852	)			(278,500	)
	Payments of deferred commodity premiums					(7,848	)			—				—
	Change in cash overdrafts					(10,911	)			3,350				11,444
Net cash provided by financing activities						99,206				281,842				262,321
Increase (decrease) in cash and cash equivalents						(891	)			551				672
Cash and cash equivalents, beginning of period						1,654				1,103				431
Cash and cash equivalents, end of period					$	763			$	1,654			$	1,103

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Note 1.	Formation of the Company and Basis of Presentation

Note 2.	Summary of Significant Accounting Policies

	Principles of Consolidation

	Cash and Cash Equivalents

	Inventories

			December 31,
			2006				2005
			(In thousands)
Warehouse inventory			$	11,784			$	9,019
Oil in pipelines				6,386				2,212
	Total		$	18,170			$	11,231

	Properties and Equipment

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	Goodwill

	Asset Retirement Obligations

	Stock-based Compensation

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			Year Ended
			December 31,
			2005				2004
			(In thousands, except
			per share amounts)
As Reported:
	Non-cash stock-based compensation, net of tax		$	2,483			$	1,108
	Net income			103,425				82,147
	Basic net income per share			2.12				1.74
	Diluted net income per share			2.09				1.72
Pro Forma:
	Non-cash stock-based compensation, net of tax			3,091				2,289
	Net income			102,817				80,966
	Basic net income per share			2.11				1.72
	Diluted net income per share			2.08				1.70

	Segment Reporting

	Major Customers

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	Income Taxes

	Revenue Recognition

	Oil Marketing Revenues and Expenses and Buy/ Sell Transactions

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	Shipping Costs

	Hedging and Related Activities

	Comprehensive Income

	Use of Estimates

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	New Accounting Standards

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

	FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”)

	2005 Acquisitions

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Calculation of total purchase price:
	Cash paid to Crusader’s former owners			$	79,142
	Crusader debt repaid				29,732
	Transaction costs				707
		Total purchase price		$	109,581
Allocation of purchase price to the fair value of assets acquired:
	Cash			$	18,592
	Other current assets				3,362
	Deferred taxes				1,997
	Proved oil and natural gas properties				85,388
	Unproved oil and natural gas properties				6,863
	Goodwill				22,698
		Total assets acquired			138,900
	Current liabilities				(10,267	)
	Non-current liabilities				(1,190	)
	Deferred taxes				(17,862	)
		Total liabilities assumed			(29,319	)
		Fair value of net assets acquired		$	109,581

	2004 Acquisitions

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Calculation of total purchase price:
	Cash paid to Cortez’s former owners			$	85,805
	Cortez debt repaid				39,449
	Transaction costs				1,760
		Total purchase price		$	127,014
Allocation of purchase price to the fair value of assets acquired:
	Cash			$	3,206
	Other current assets				5,946
	Proved oil and natural gas properties				120,503
	Unproved oil and natural gas properties				3,011
	Goodwill				37,908
		Total assets acquired			170,574
	Current liabilities				(5,673	)
	Non-current liabilities				(996	)
	Deferred taxes				(36,891	)
		Total liabilities assumed			(43,560	)
		Fair value of net assets acquired		$	127,014

Note 4.	Commitments and Contingencies

	Litigation

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	Leases

2007		$	1,818
2008			2,210
2009			2,094
2010			2,105
2011			2,094
Thereafter			3,897
		$	14,218

	ExxonMobil

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Note 5.	AROs

			Year Ended
			December 31,
			2006				2005
			(In thousands)
Future abandonment liability at January 1			$	14,430			$	6,601
	Acquisition of properties			785				2,221
	Wells drilled			147				954
	Accretion expense			743				515
	Plugging and abandonment costs incurred			(1,466	)			(745	)
	Revision of estimates			5,202				4,884
Future abandonment liability at December 31			$	19,841			$	14,430

			Year Ended December 31,
			2006				2005				2004
			(In thousands)
Beginning balance at January 1			$	6,560			$	3,242			$	—
Additions to capitalized exploratory well costs pending the determination of proved reserves				13,048				6,560				3,242
Reclassification to proved property and equipment based on the determination of proved reserves				(1,457	)			(996	)			—
Capitalized exploratory well costs charged to expense				(5,103	)			(2,246	)			—
	Total		$	13,048			$	6,560			$	3,242

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			December 31,
			2006				2005
			(In thousands)
Oil and natural gas revenues payable			$	8,612			$	4,544
Net profits payable				1,178				1,634
Acquired gas imbalances				3,173				408
Accrued bonus				5,665				5,299
Other				2,730				3,885
	Total		$	21,358			$	15,770

			December 31,
			2006				2005
			(In thousands)
Revolving credit facility			$	68,000			$	80,000
61/4% Notes				150,000				150,000
6% Notes, net of unamortized discount of $4,892 and $5,317, respectively				295,108				294,683
71/4% Notes, net of unamortized discount of $1,412 and $1,494, respectively				148,588				148,506
	Total		$	661,696			$	673,189

	Senior Subordinated Notes

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	Revolving Credit Facility

Ratio of Total Outstandings to Borrowing Base		Eurodollar Loans(a)				Base Rate Loans(b)
Less than .40 to 1			LIBOR + 1.000%				Base Rate + 0.000%
From .40 to 1 but less than .75 to 1			LIBOR + 1.250%				Base Rate + 0.000%
From .75 to 1 but less than .90 to 1			LIBOR + 1.500%				Base Rate + 0.250%
.90 to 1 or greater			LIBOR + 1.750%				Base Rate + 0.500%

(a)	The London Interbank Offered Rate (“LIBOR”) is equal to the rate determined by Bank of America, N.A. to be the average British Bankers Association Interest Settlement Rate for deposits in dollars for a similar interest period (either one, two, three, or six months, or such other period that is twelve months of less as selected by Encore and consented to by each lender).
(b)	The Base Rate is calculated as the higher of (i) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (ii) the federal funds effective rate plus 0.5 percent.

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		Commitment
Ratio of Total Outstandings to Borrowing Base		Fee Percentage
Less than .40 to 1			0.250%
From .40 to 1 but less than .90 to 1			0.375%
.90 to 1 or greater			0.500%

	Letters of Credit

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	Long-Term Debt Maturities

			Payments Due by Period
			Total				2007				2008-2009				2010-2011				Thereafter
			(In thousands)
61/4% Notes			$	150,000			$	—			$	—			$	—			$	150,000
6% Notes				300,000				—				—				—				300,000
71/4% Notes				150,000				—				—				—				150,000
Revolving credit facility				68,000				—				—				68,000				—
	Total		$	668,000			$	—			$	—			$	68,000			$	600,000

	Income Taxes

					Year Ended December 31,
					2006				2005				2004
					(In thousands)
Federal:
	Current				$	3,785			$	(2,084	)		$	1,788
	Deferred					48,327				53,147				35,470
		Total federal				52,112				51,063				37,258
State (net of federal benefit):
	Current					401				—				125
	Deferred					2,893				2,885				3,109
		Total state				3,294				2,885				3,234
			Income tax provision(a)		$	55,406			$	53,948			$	40,492

(a)	These amounts do not include the Company’s excess tax benefit related to stock option exercises and vesting of restricted stock, which was recorded directly to additional paid-in capital, of $1.3 million, $1.4 million, and $1.3 million during 2006, 2005, and 2004, respectively.

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			Year Ended December 31,
			2006				2005				2004
			(In thousands)
Income before income taxes			$	147,804			$	157,373			$	122,639
Tax at statutory rate			$	51,731			$	55,081			$	42,923
State income taxes, net of federal benefit				3,294				2,885				3,234
Section 43 credits				—				(3,227	)			(3,816	)
Permanent and other				381				(791	)			(1,849	)
	Income tax provision		$	55,406			$	53,948			$	40,492

					December 31,
					2006				2005
					(In thousands)
Current:
	Assets:
		Unrealized hedge loss in other comprehensive income			$	20,049			$	26,427
		Derivative fair value loss				4,062				2,603
		Other				867				—
			Total current deferred tax assets		$	24,978			$	29,030

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					December 31,
					2006				2005
					(In thousands)
Long-term:
	Assets:
		Alternative minimum tax carryforward			$	2,394			$	2,073
		Unrealized hedge loss in other comprehensive income				1,069				16,964
		Derivative fair value loss				2,606				1,424
		Section 43 credits				13,227				13,227
		Other				5,615				3,004
			Total long-term deferred tax assets			24,911				36,692
	Liabilities:
		Book basis of oil and natural gas properties in excess of tax basis				(307,736	)			(249,960	)
	Net long-term deferred tax liability				$	(282,825	)		$	(213,268	)

	Taxes Other than Income Taxes

			Year Ended December 31,
			2006				2005				2004
			(In thousands)
Production and severance taxes			$	43,458			$	41,195			$	27,491
Property and ad valorem taxes				6,322				4,406				2,822
Franchise, payroll, and other taxes				1,745				1,246				868
	Total		$	51,525			$	46,847			$	31,181

	Public Offerings of Common Stock

	Shelf Registration Statement on Form S-3

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	Stock Split

	Common Stock Option Exercises

	Preferred Stock

				Year Ended December 31,
				2006				2005				2004
				(In thousands, except per share data)
Numerator:
	Net income			$	92,398			$	103,425			$	82,147
Denominator:
	Denominator for basic EPS:
		Weighted average shares outstanding			51,865				48,682				47,090
		Effect of dilutive options and diluted restricted stock(a)			871				840				648
	Denominator for diluted EPS				52,736				49,522				47,738
Net income per common share:
	Basic			$	1.78			$	2.12			$	1.74
	Diluted			$	1.75			$	2.09			$	1.72

(a)	Options to purchase 190,406 shares of common stock were outstanding but not included in the above calculation of 2006 EPS because their effect would be antidilutive. There were no antidilutive options or shares of restricted stock for 2005 or 2004.

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	401(k) Plan

	Incentive Stock Plans

	•	an employee may not be granted awards covering or relating to more than 225,000 shares of common stock in any calendar year;
	•	a non-employee director may not be granted awards covering or relating to more than 15,000 shares of common stock in any calendar year; and
	•	an employee may not receive awards consisting of cash (including cash awards that are granted as performance awards) in respect of any calendar year having a value determined on the grant date in excess of $1.0 million.

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		December 31, 2005
		As Originally
		Reported				As Restated
		(In thousands)
Shares of common stock outstanding			49,368				48,785
Common stock		$	494			$	488
Additional paid-in capital		$	325,620			$	316,619
Deferred compensation		$	(9,007	)		$	—
Total stockholders’ equity		$	546,781			$	546,781

		Year Ended
		December 31,
		2006				2005				2004
Expected volatility			42.8	%			46.0	%			34.8	%
Expected dividend yield			0.0	%			0.0	%			0.0	%
Expected term (in years)			6.0				6.0				6.0
Risk-free interest rate			4.6	%			3.7	%			3.2	%

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			Year Ended December 31,
			2006																2005								2004
											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				1,440,812			$	13.20												1,520,586			$	12.00				1,444,431			$	9.91
	Granted(a)			122,890				31.10												115,255				26.55				389,784				17.42
	Forfeited			(48,410	)			24.65												(57,616	)			17.94				(9,764	)			10.49
	Exercised			(178,174	)			13.14												(137,413	)			9.07				(303,865	)			9.07
Outstanding at end of year				1,337,118				14.44				6.0			$	14,353				1,440,812				13.20				1,520,586				12.00
Exercisable at end of year				1,076,815				11.90				5.5				13,662				1,089,677				11.04				948,771				9.77

(a)	During 2004, there were 37,500 stock options granted to non-employee directors.

						Weighted								Weighted
						Number of				Average				Average				Number of
		Range of Strike				Options				Life				Strike				Options
Year of Grant		Prices Per Share				Outstanding				(Years)				Price				Exercisable
2001			$8.33 to $9.33				482,325				4.5			$	8.92				482,325
2002			$8.50 to $12.40				332,903				5.7				11.65				332,903
2003			$11.49 to $13.61				41,289				6.6				12.46				41,289
2004			$17.17 to $19.77				290,195				7.1				17.51				191,807
2005			$26.55				84,931				8.1				26.55				28,491
2006			$31.10				105,475				9.1				31.10				—
							1,337,118				6.0				14.44				1,076,815

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							Weighted
							Average
			Number of				Grant Date
			Shares				Fair Value
Outstanding at January 1, 2006				583,274			$	20.53
	Granted			428,609				31.17
	Vested			(101,377	)			15.49
	Forfeited			(81,887	)			25.37
Outstanding at December 31, 2006				828,619				26.17

		Year of Vesting
Year of Grant		2007				2008				2009				2010				Total
2002			48,275				—				—				—				48,275
2003			19,080				19,080				—				—				38,160
2004			55,039				26,582				26,582				—				108,203
2005			5,508				82,206				76,698				76,698				241,110
2006			34,935				34,935				153,338				34,935				258,143
Total			162,837				162,803				256,618				111,633				693,891

			Year of Vesting
Year of Grant			2007				2008				2009				2010				Total
2006				33,682				33,682				33,682				33,682				134,728
	Total			33,682				33,682				33,682				33,682				134,728

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		December 31,
		2006								2005
		Book Value				Fair Value				Book Value				Fair Value
		(In thousands)
Cash and cash equivalents		$	763			$	763			$	1,654			$	1,654
Accounts receivable			81,470				81,470				76,960				76,960
Plugging bond			732				838				690				843
Bell Creek escrow			4,887				4,902				3,982				3,986
Accounts payable			(18,204	)			(18,204	)			(27,281	)			(27,281	)
61/4% Notes			(150,000	)			(140,625	)			(150,000	)			(145,500	)
6% Notes			(295,108	)			(275,250	)			(294,683	)			(279,000	)
71/4% Notes			(148,588	)			(145,500	)			(148,506	)			(150,000	)
Revolving credit facility			(68,000	)			(68,000	)			(80,000	)			(80,000	)
Commodity derivative contracts			13,599				13,599				(86,794	)			(86,794	)
Deferred premiums on derivative contracts			(54,671	)			(54,671	)			(30,141	)			(30,141	)

	Derivative Financial Instruments

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	Oil Derivative Instruments

		Daily				Average				Daily				Average				Daily				Average
		Floor				Floor				Short Floor				Short Floor				Swap				Swap				Fair
Period		Volume				Price				Volume				Price				Volume				Price				Market Value
		(Bbl)				(Per Bbl)				(Bbl)				(Per Bbl)				(Bbl)				(Per Bbl)				(In thousands)
Jan. — Dec. 2007			8,000			$	53.75				—			$	—				3,000			$	36.75			$	(26,347	)
Jan. — June 2008			12,000				64.17				(4,000	)			50.00				1,000				58.59				9,536
July — Dec. 2008			8,000				66.25				(4,000	)			50.00				—				—				8,471
Jan. — Dec. 2009			5,000				70.00				(5,000	)			50.00				—				—				11,972
																										$	3,632

	Natural Gas Derivative Instruments

		Daily				Average				Daily				Average				Daily				Average
		Floor				Floor				Short Floor				Short Floor				Swap				Swap				Fair
Period		Volume				Price				Volume				Price				Volume				Price				Market Value
		(Mcf)				(Per Mcf)				(Mcf)				(Per Mcf)				(Mcf)				(Per Mcf)				(In thousands)
Jan. — Dec. 2007			32,500			$	6.74				—			$	—				10,000			$	4.99			$	7,567
Jan. — Dec. 2008			10,000				6.25				—				—				—				—				2,400
																										$	9,967

	•	When the NYMEX oil price is greater than $70 per Bbl, the Company pays the net purchased floor premium cost per Bbl.

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	•	When the NYMEX oil price is greater than $50 per Bbl but less than $70 per Bbl, the Company receives settlements of $70 per Bbl less the NYMEX oil price and pays the net purchased floor premium cost per Bbl.
	•	When the NYMEX oil price is below $50 per Bbl, the Company receives $20 per Bbl less the net purchased floor premium cost per Bbl.

					Year Ended December 31,
					2006				2005				2004
					(In thousands)
Designated cash flow hedges:
	Ineffectiveness — Derivative commodity contracts				$	1,748			$	8,371			$	5,018
Undesignated derivative contracts:
	Mark-to-market loss (gain):
		Interest rate swap				—				462				1,958
		Commodity contracts				(17,279	)			(2,050	)			646
	Settlements:
		Interest rate swap				—				(312	)			(1,686	)
		Commodity contracts				(8,857	)			(1,181	)			(925	)
			Total derivative fair value loss (gain)		$	(24,388	)		$	5,290			$	5,011

			December 31,
			2006				2005
			(In thousands)
Deferred loss on commodity derivatives, net of tax			$	(35,327	)		$	(72,918	)
Deferred gain on interest rate swap, net of tax				—				92
	Accumulated other comprehensive loss		$	(35,327	)		$	(72,826	)

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		Percentage of				Percentage of
		Hedged Oil				Hedged Natural Gas
Counterparty		Production Committed				Production Committed
BNP Paribas			7.6%				66.6%
Calyon			17.0%				14.3%
Deutsche Bank			34.9%				—
J. Aron & Company			3.8%				19.0%
Wachovia			22.6%				—

	Acquisitions

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	Master Limited Partnership (“MLP”)

	Revolving Credit Facility

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			December 31,
			2006				2005
			(In thousands)
Properties and equipment, at cost — successful efforts method:
	Proved properties		$	2,033,914			$	1,691,175
	Unproved properties			47,548				37,646
	Accumulated depletion, depreciation, and amortization			(364,780	)			(255,564	)
			$	1,716,682			$	1,473,257

				Year Ended December 31,
				2006				2005				2004
				(In thousands)
Acquisitions:
	Proved properties			$	4,486			$	224,469			$	204,907
	Unproved properties				24,462				21,205				33,926
	Asset retirement obligations				785				2,221				1,165
		Total acquisitions			29,733				247,895				239,998
Development:
	Drilling and exploitation				253,484				268,520				157,092
	Asset retirement obligations				147				954				467
Total development					253,631				269,474				157,559
Exploration:
	Drilling and exploitation				92,839				53,316				29,363
	Geological and seismic				1,720				3,095				979
	Delay rentals				646				635				204
Total exploration					95,205				57,046				30,546
		Total costs incurred		$	378,569			$	574,415			$	428,103

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		December 31,
		2006				2005				2004
Oil (per Bbl)		$	61.06			$	61.04			$	43.46
Natural gas (per Mcf)			5.48				9.44				6.19

			December 31,
			2006				2005				2004
Proved reserves:
	Oil (MBbl)			153,434				148,387				134,048
	Natural gas (MMcf)			306,764				283,865				234,030
	Combined (MBOE)			204,561				195,698				173,053
Proved developed reserves:
	Oil (MBbl)			94,246				101,505				97,114
	Natural gas (MMcf)			235,049				229,950				156,919
	Combined (MBOE)			133,421				139,830				123,267

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							Natural				Oil
			Oil				Gas				Equivalent
			(MBbl)				(MMcf)				(MBOE)
Balance, December 31, 2003				117,732				138,950				140,890
	Acquisitions of minerals-in-place			7,853				86,314				22,239
	Extensions and discoveries			4,226				27,248				8,768
	Improved recovery			11,826				(80	)			11,812
	Revisions of estimates			(910	)			(4,313	)			(1,629	)
	Production			(6,679	)			(14,089	)			(9,027	)
Balance, December 31, 2004				134,048				234,030				173,053
	Acquisitions of minerals-in-place			8,333				38,781				14,796
	Extensions and discoveries			2,780				28,073				7,459
	Improved recovery			11,510				1,132				11,699
	Revisions of estimates			(1,413	)			2,908				(928	)
	Production			(6,871	)			(21,059	)			(10,381	)
Balance, December 31, 2005				148,387				283,865				195,698
	Acquisitions of minerals-in-place			25				235				64
	Extensions and discoveries			3,269				78,861				16,412
	Improved recovery			10,935				941				11,092
	Revisions of estimates			(1,847	)			(33,682	)			(7,461	)
	Production			(7,335	)			(23,456	)			(11,244	)
Balance, December 31, 2006				153,434				306,764				204,561

		December 31,
		2006				2005				2004
		(In thousands)
Net future cash inflows		$	9,291,007			$	10,414,091			$	6,651,858
Future production costs			(3,668,897	)			(3,690,974	)			(2,389,359	)
Future development costs			(371,396	)			(250,554	)			(194,746	)
Future abandonment costs			(134,103	)			(121,553	)			(49,859	)
Future income tax expense			(1,499,290	)			(1,934,504	)			(1,221,933	)
Future net cash flows			3,617,321				4,416,506				2,795,961
10% annual discount			(2,155,514	)			(2,498,035	)			(1,630,342	)
Standardized measure of discounted estimated future net cash flows		$	1,461,807			$	1,918,471			$	1,165,619

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			Year Ended December 31,
			2006				2005				2004
			(In thousands)
Standardized measure, beginning of year			$	1,918,471			$	1,165,619			$	736,939
	Net change in sales price and production costs			(634,033	)			531,793				430,310
	Acquisitions of mineral-in-place			539				256,257				242,855
	Extensions, discoveries, and improved recovery			141,211				229,929				150,112
	Revisions of quantity estimates			(62,615	)			(15,455	)			(15,217	)
	Sales, net of production costs			(340,036	)			(357,028	)			(222,995	)
	Development costs incurred during the year			253,484				268,520				157,092
	Accretion of discount			191,847				116,562				73,694
	Change in estimated future development costs			(185,212	)			(199,158	)			(276,027	)
	Net change in income taxes			248,491				(247,937	)			(145,042	)
	Change in timing and other			(70,340	)			169,369				33,898
Standardized measure, end of year			$	1,461,807			$	1,918,471			$	1,165,619

			Quarter
			First				Second				Third				Fourth
			(In thousands, except per share data)
2006
Revenues, as reported			$	116,216			$	133,471			$	177,697			$	157,710
	Plus: change in marketing presentation			31,746				24,022				—				—
	Revenues, as restated		$	147,962			$	157,493			$	177,697			$	157,710
Operating income			$	40,846			$	47,594			$	78,002			$	25,064
Net income			$	17,936			$	22,235			$	42,135			$	10,092
Basic income per common share			$	0.37			$	0.42			$	0.80			$	0.19
Diluted income per common share			$	0.36			$	0.42			$	0.78			$	0.19
2005
Revenues			$	91,581			$	99,717			$	127,572			$	138,454
Operating income			$	39,917			$	43,401			$	38,911			$	68,160
Net income			$	21,784			$	23,668			$	20,854			$	37,119
Basic income per common share			$	0.45			$	0.49			$	0.43			$	0.76
Diluted income per common share			$	0.44			$	0.48			$	0.42			$	0.75

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

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	/s/ Ernst & Young LLP

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ITEM 9B.	OTHER INFORMATION

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

ITEM 11.	EXECUTIVE COMPENSATION

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

(a)

(b)

(c)

Number of Securities

Remaining Available

Number of

for Future Issuance

Securities to Be

Under Equity

Issued upon Exercise

Weighted-Average

Compensation Plans

of Outstanding

Exercise Price of

(Excluding

Options, Warrants

Outstanding Options,

Securities Reflected

and Rights(2)

Warrants and Rights

in Column(a))

Equity compensation plans approved by security holders(1)

1,337,118

$

14.44

1,307,467

Equity compensation plans not approved by security holders

—

—

—

Total

1,337,118

$

14.44

1,307,467

(1)	The 2000 Incentive Stock Plan is the Company’s only equity compensation plan.
(2)	Excludes 828,919 shares of restricted stock.

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ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

	1. Financial Statements:

		Page
Report of Independent Registered Public Accounting Firm			69
Consolidated Balance Sheets as of December 31, 2006 and 2005			70
Consolidated Statements of Operations for the Years Ended December 31, 2006, 2005, and 2004			71
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2006, 2005, and 2004			72
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005, and 2004			73
Notes to Consolidated Financial Statements			74

	2. Financial Statement Schedules:

	All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes to the consolidated financial statements.

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Exhibit
No.				Description
	2	.1		Purchase and Sale Agreement dated January 16, 2007 among Clear Fork Pipeline Company, Howell Petroleum Corporation, Kerr-McGee Oil & Gas Onshore LP, and the Company (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K, filed with the SEC on January 17, 2007).
	2	.2		Purchase and Sale Agreement dated January 23, 2007 among Howell Petroleum Corporation and Kerr-McGee Oil & Gas Onshore LP, as Sellers, and the Company, as Purchaser (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K, filed with the SEC on January 26, 2007).
	3	.1		Second Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2001, filed with the SEC on November 7, 2001).
	3	.1.2		Certificate of Amendment to Second Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2005, filed with the SEC on May 5, 2005).
	3	.2		Second Amended and Restated Bylaws of the Company (incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2001, filed with the SEC on November 7, 2001).
	4	.1		Specimen certificate of the Company (incorporated by referenced to Exhibit 4.1 to Registration Statement on Form S-1, Registration No. 333-47540, filed with the SEC on December 15, 2000).
	4	.2.1		Indenture, dated as of April 2, 2004, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, with respect to the 6.25% Senior Subordinated Notes due 2014 (incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-4 (Registration No. 333-117025) filed with the SEC on June 30, 2004).
	4	.2.2		Form of 6.25% Senior Subordinated Note to Cede & Co. or its registered assigns (included as Exhibit A to Exhibit 4.2.1 above).
	4	.3.1		Indenture, dated as of July 13, 2005, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, with respect to the 6% Senior Subordinated Notes due 2015 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, filed with the SEC on July 14, 2005).
	4	.3.2		Form of 6% Senior Subordinated Note due 2015 (included as Exhibit A to Exhibit 4.3.1 above).
	4	.4.1		Indenture, dated as of November 16, 2005, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association with respect to Subordinated Debt Securities (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, filed with the SEC on November 23, 2005).
	4	.4.2		First Supplemental Indenture, dated as of November 16, 2005, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, with respect to the 71/4% Senior Subordinated Notes due 2017 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, filed with the SEC on November 23, 2005).
	4	.4.3		Form of 71/4% Senior Subordinated Note due 2017 (included as Exhibit A to Exhibit 4.4.2 above).
	10	.1+		2000 Incentive Stock Plan (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-8 (File No. 333-120422), filed with the SEC on November 12, 2004).

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Exhibit
No.				Description
	10	.2+		Employee Severance Protection Plan (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2003, filed with the SEC on May 8, 2003).
	10	.3+		Form of Restricted Stock Award — Executive (incorporated by reference to Exhibit 10.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005).
	10	.4+		Form of Stock Option Agreement (Nonqualified) (incorporated by reference to Exhibit 10.4 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005).
	10	.5+		Form of Stock Option Agreement (Incentive) (incorporated by reference to Exhibit 10.5 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005).
	10	.6+		Form of Indemnification Agreement for directors and executive officers (incorporated by reference to Exhibit 10.6 of the Company’s 2004 Annual Report on Form 10-K for the year ended December 31, 2004).
	10	.7		Description of Compensation Payable to Non-Management Directors (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed with the SEC on February 22, 2006).
	10	.8		Amended and Restated Credit Agreement, dated August 19, 2004, among the Company, Encore Operating, L.P., Bank of America, N.A., as Administrative Agent, Fotis Capital Corp. and Wachovia Bank, N.A., as Co-Syndication Agents, BNP Paribas and Citibank, N.A., as Co-Documentary Agents and the financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the SEC on August 25, 2004).
	10	.9		First Amendment to Credit Agreement, dated April 29, 2005 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed with the SEC on May 4, 2005).
	10	.10		Second Amendment to Credit Agreement, dated November 14, 2005 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed with the SEC on November 18, 2005).
	10	.11		Third Amendment to Credit Agreement, dated December 29, 2005 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed with the SEC on January 5, 2006).
	10	.12		Registration Rights Agreement, dated August 18, 1998, by and among the Company and the other parties thereto (incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-1 (File No. 333-47540), filed with the SEC on October 6, 2000).
	12	.1*		Statement showing computation of ratios of earnings to fixed charges.
	21	.1*		Subsidiaries of the Company as of February 1, 2007.
	23	.1*		Consent of Ernst & Young LLP.
	23	.2*		Consent of Miller and Lents, Ltd.
	24	.1*		Power of Attorney (included on the signature page of this report).
	31	.1*		Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer).
	31	.2*		Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer).
	32	.1*		Section 1350 Certification (Principal Executive Officer).
	32	.2*		Section 1350 Certification (Principal Financial Officer).

*	Filed herewith

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	Encore Acquisition Company

Date: February 28, 2007		By: /s/ Jon S. Brumley   Jon S. Brumley Chief Executive Officer

Signature				Title or Capacity		Date
/s/ I. Jon Brumley   I. Jon Brumley				Chairman of the Board and Director		February 28, 2007
/s/ Jon S. Brumley   Jon S. Brumley				Chief Executive Officer, President, and Director (Principal Executive Officer)		February 28, 2007
/s/ Robert C. Reeves   Robert C. Reeves				Senior Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer and Principal Accounting Officer)		February 28, 2007
/s/ John A. Bailey   John A. Bailey				Director		February 28, 2007
/s/ Martin C. Bowen   Martin C. Bowen				Director		February 28, 2007
/s/ Ted Collins, Jr.   Ted Collins, Jr.				Director		February 28, 2007
/s/ Ted A. Gardner   Ted A. Gardner				Director		February 28, 2007

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Signature				Title or Capacity		Date
/s/ John V. Genova   John V. Genova				Director		February 28, 2007
/s/ James A. Winne III   James A. Winne III				Director		February 28, 2007

112