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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Form 10-K

Encore Acquisition Company

Registrant’s telephone number, including area code:

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

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

      Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     o

      Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2)     Yes þ          No o

DOCUMENTS INCORPORATED BY REFERENCE

      Parts of the definitive proxy statement for the Registrant’s annual meeting of stockholders to be held on April 29, 2004 are incorporated by reference into Part III of this report on Form 10-K.

ENCORE ACQUISITION COMPANY

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      This annual report on Form 10-K (the “Report”) contains forward-looking statements, which give our current expectations and forecasts of future events. The Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for forward-looking statements made by or on behalf of Encore Acquisition Company or its subsidiaries. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a description of various factors that could materially affect the ability of Encore Acquisition Company to achieve the anticipated results described in the forward looking statements. Certain terms commonly used in the oil and natural gas industry and in this Report are defined at the end of Item 7A, beginning on page 45, under the caption “Glossary of Oil and Natural Gas Terms.” In addition, all production and reserve volumes disclosed in this Report represent amounts net to Encore Acquisition Company.

PART I

Items 1 and 2.  Business and Properties

General

      Our Business. We are a growing independent energy company engaged in the acquisition, development, exploitation, and production of onshore North American oil and natural gas reserves. Since our inception in 1998, we have sought to acquire high quality assets with potential for upside through low-risk development drilling projects. Our properties are currently located in the Williston Basin of Montana and North Dakota, the Permian Basin of Texas and New Mexico, the Anadarko Basin of Oklahoma, the Powder River Basin of Montana, the Paradox Basin of Utah, and the North Louisiana Salt Basin of Louisiana. During the three years ended December 31, 2003, we invested $134.8 million in acquiring producing oil and natural gas properties and we have invested another $266.5 million on development and exploitation of these properties.

      Most Valuable Asset. The Cedar Creek Anticline (“CCA”), in the Williston Basin of Montana and North Dakota, represented 73% of our total proved reserves as of December 31, 2003. The CCA is our most valuable asset today and in the foreseeable future. A large portion of our future success revolves around future exploitation of and production from this property through primary, secondary, and tertiary recovery techniques.

      Recent Acquisitions. On March 2, 2004, we entered into a stock purchase agreement to acquire all of the outstanding common stock of Cortez Oil & Gas, Inc., a privately held, independent oil and gas company (“Cortez”), for total consideration of approximately $123.0 million. We intend to fund the acquisition initially with bank debt under our existing credit facility. The oil and natural gas assets to be acquired from Cortez are in the same areas as our producing properties located in the CCA of Montana, the Permian Basin of West Texas and Southeastern New Mexico, and in our Mid Continent area, including the Anadarko and Arkoma Basins of Oklahoma and the Barnett Shale north of Fort Worth, Texas. We expect to close the transaction in the second quarter of 2004.

      On July 31, 2003, we completed an acquisition of interests in natural gas properties in North Louisiana for $52.5 million before purchase price adjustments. Subsequent to the initial acquisition, we have purchased additional interests in the properties. The properties are located in the Elm Grove Field in Bossier Parish, Louisiana and are non-operated working interests ranging from 2% to 38% across 1,800 net acres in 15 sections. The properties are substantially all natural gas. For the fourth quarter of 2003, the properties’ average daily production was 8,255 Mcfe.

      Drilling. In 2003, we drilled 105 gross operated wells and participated in drilling another 33 gross non-operated wells for a total of 138 gross wells for the year. On a net basis, we drilled 95.7 operated wells and participated in 7.9 non-operated wells in 2003.

      Oil and Natural Gas Reserves. In 2003, our reserve growth was achieved through acquisitions, high pressure air injection (“HPAI”) and organically through the drill bit by developing a portion of our inventory of drilling projects that we expect will extend over the next several years. We continue to pursue

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      The following table sets forth our total proved reserves, average daily production and reserve-to-production ratio, or R/ P index, in our principal areas of operation as of December 31, 2003 and for the year then ended.

(1)	Our CCA properties, which produce mainly from porous dolomites drilled on 40 to 80 acre spacing intervals, have longer reserve lives than our other properties because the low permeability level encountered within those producing intervals require a longer time to produce the reserves in place. This results in a lower production decline rate.
(2)	Permian Basin includes the Central Permian, Indian Basin and Crockett properties.
(3)	Rockies includes the Paradox Basin, Lodgepole and Bell Creek properties.
(4)	Mid Continent includes the Elm Grove and Verden properties. The Elm Grove properties were acquired on July 31, 2003, and the R/ P index shown in the table is calculated by annualizing our production since the acquisition.

      Public Offering. On November 13, 2003, we priced a public offering of 8.0 million shares of our common stock at a price to the public of $20.25 per share. The underwriters also exercised their over-allotment option for an additional 1.06 million shares of common stock, at a price of $20.25 per share, on December 2, 2003, for a total of 9.06 million shares. We used all of the net proceeds to repurchase 6,866,643 shares of our common stock from J.P. Morgan Partners (SBIC), LLC (“J.P. Morgan”) and 2,193,357 shares from Warburg, Pincus Equity Partners L.P. (“Warburg Pincus”) at a price of $19.3775 per share. The 9.06 million shares we purchased were retired upon repurchase. Our total shares outstanding did not change as a result of this offering. Net proceeds from the original offering and the over-allotment option totaled approximately $175.6 million, after deducting underwriting discounts and commissions and the estimated expenses of the offering. After giving effect to the repurchase, J.P. Morgan no longer beneficially owns any of our common stock and Warburg Pincus beneficially owns 24.5% of our common stock.

Business Strategies

      Our primary business objective is to maximize internally generated cash flow and shareholder value by executing the following strategies:

	•	Maintain an Active Low-Risk Development Drilling Program. Our technological expertise, combined with our proficient field operations and reservoir engineering, have allowed us to increase production and reserves on our properties through development drilling, workovers, waterflood enhancements, tertiary projects, and recompletions. Our plan is to maintain an inventory of low-risk

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		exploitation and development projects that provide us ongoing drilling activity. Each year, we budget a portion of internally generated cash flow to secondary and tertiary recovery projects whose results will not be seen until future years. Our conventional development budget for 2004, exclusive of spending on high pressure air injection, is $93 million.
	•	Maximize Existing Reserves and Production Through High-Pressure Air Injections. In addition to conventional development drilling, we utilize high-pressure air injection techniques on certain properties to enhance our growth. High-pressure air injection 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. We believe that the HPAI programs on our CCA properties will generate a higher rate of return than other tertiary processes and can be applied throughout our CCA properties. The zone of our initial focus for HPAI, the Red River U4 zone, is the same zone where HPAI has been successfully implemented by other operators in adjacent areas and on our Pennel unit of the CCA. Response from HPAI investments is not expected until ten to eighteen months from the time of first injection. Our high-pressure air injection budget for 2004 is $34 million.
	•	Expand Our Reserves, Production, and Drilling Inventory Through a Disciplined Acquisition Program. We will continue to pursue acquisitions of properties with similar upside potential to our current producing properties portfolio. Using the experience of our management team, we have developed and refined an acquisition program designed to increase our reserves and to complement our core properties, while providing upside potential. We have a staff of engineering and geoscience professionals who manage our core properties and use their experience and expertise to target 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. For the year ended 2003, we evaluated over $1 billion of potential acquisitions. We will continue to aggressively evaluate acquisition opportunities in 2004 with the same disciplined commitment to acquire assets that fit our portfolio and continue to create value for our shareholders.
	•	Focus on Cost Control Through Efficient and Safe Operations. As of December 31, 2003, we operated properties representing approximately 84% of our proved reserves, which allows us to control capital allocation and expenses. Not only do we strive to efficiently operate our properties but we strive to safely operate our properties. The total recordable incident rate (“TRIR”) averaged 2.5 per 200,000 man hours for the industry in 2003. We are very proud to have a perfect TRIR of zero for our employees in 2003.

      Challenges to Implementing Our Strategy. We face a number of challenges to implementing our strategy and achieving our goals. Our primary challenge is to generate superior rates of return on our investments in a volatile commodity pricing environment, while replenishing our drilling inventory. Changing commodity prices affect the rate of return on a property acquisition, internally generated cash flow, and, in turn, can affect our capital budget. In addition to the changing commodity price risk, we face strong competition from independents and major oil companies. For more information on the challenges to implementing our strategy and achieving our goals, please read “Factors That May Affect Future Results and Financial Condition” beginning on page 37.

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Business Activities

      The following table sets forth the net production, proved reserves quantities, and PV-10 values of our properties:

Properties — Principal Areas of Operations

(1)	Our CCA properties, which produce mainly from porous dolomites drilled on 40 to 80 acre spacing intervals, have longer reserve lives than our other properties because the low permeability level encountered within those producing intervals require a longer time to produce the reserves in place. This results in a lower production decline rate.
(2)	Permian Basin includes the Central Permian, Indian Basin and Crockett properties.
(3)	Rockies includes the Paradox Basin, Lodgepole and Bell Creek properties.
(4)	Mid Continent includes the Elm Grove and Verden Properties.
(5)	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%. Giving effect to hedging transactions based on prices current at such dates, our PV-10 value would have been decreased by $23.8 million at December 31, 2003. The Standardized Measure at December 31, 2003 is $736.9 million. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes.

Operations

      We act as operator of properties representing approximately 84% of our proved reserves at December 31, 2003. As operator, we are able to better control expenses, capital allocation, and the timing of exploitation and development activities of these properties. Our remaining properties are operated by third parties, and, as working interest owners in those properties, we are required to pay our share of the costs of operating, exploiting, and developing them. See “— Properties — Nature of Our Ownership Interests” on page 11. During the years ended December 31, 2003, 2002, and 2001 our approximate costs for development activities on non-operated properties were $5.4 million, $3.4 million, and $9.3 million, respectively. Because the properties purchased in our North Louisiana acquisition in 2003 are all non-operated, we expect our capital costs related to non-operated activities to increase in 2004.

Proved Reserves

      Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on acreage yet to be drilled for which

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      The following table sets forth estimated period-end proved reserves for the periods indicated as estimated by Miller and Lents, Ltd., independent petroleum engineers (in thousands except per Bbl and per Mcf amounts):

(1)	Volumetric reserves attributed to the net profits interests in our CCA properties were 20,623 MBOE, 16,262 MBOE, and 11,062 MBOE, respectively, at December 31, 2003, 2002, and 2001. See “— Properties — Net Profits Interests” on page 13. The volumes attributed to the net profits interests, which reduce our reserves on a BOE for BOE basis, will fluctuate from period to period primarily based on commodity prices and the level of planned development expenditures.
(2)	The pretax present value of estimated future revenues to be generated from the production of proved reserves net of estimated future 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%. Giving effect to hedging transactions based on prices current at such dates, our PV-10 value would have been $997.2 million at December 31, 2003, $860.6 million at December 31, 2002, and $364.4 million at December 31, 2001.

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(3)	Estimated future cash inflows to be generated from the production and sale of proved oil and natural gas reserves, net of estimated future production and development costs, and future income tax expenses discounted at 10% 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.

      There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of exploitation expenditures. The data in the above table represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly, and estimates of other engineers might differ materially from those shown above. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Results of drilling, testing, and production, after the date of the estimate, may justify revisions. Accordingly, reserve estimates may vary significantly from the quantities of oil and natural gas that are ultimately recovered.

      Future prices received for production and future costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The PV-10 reserve value shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is mandated by the Securities and Exchange Commission (“SEC”), is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate. For properties that we operate, future production expenses exclude our share of contractual overhead charges. In addition, the calculation of estimated future costs does not take into account the effect of various cash outlays, including, among other things, general and administrative costs and interest expense.

      During the calendar year 2003, we filed estimates of oil and natural gas reserves at December 31, 2002 with the U.S. Department of Energy on Form EIA-23. As required for the EIA-23, this filing reflects only production that comes from our operated wells at year end, and is reported on a gross basis. These estimates come directly from our reserve report that is prepared by Miller and Lents, Ltd., who are independent petroleum engineers.

Production and Price History

      The following table sets forth information regarding net production of oil and natural gas, certain price information, and average cost per BOE for each of the periods indicated:

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Producing Wells

      The following table sets forth information at December 31, 2003 relating to the producing wells in which we owned a working interest as of that date. We also held royalty interests in 2,546 producing wells as of that date. Wells are classified as oil or natural gas wells according to their predominant production stream. Gross wells are the total number of producing wells in which we have an interest, and net wells are determined by multiplying gross wells by our average working interest.