##### Table of Contents









UNITED STATES SECURITIES AND EXCHANGE
COMMISSION

Washington, D.C. 20549


Form 10-K

|                                                |  |                                                                                         
|----------------------------------------------- |  | ----------------------------------------------------------------------------------------
|þ                                               |  | ANNUAL REPORT PURSUANT TO SECTION 13 OR
    15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|                                               
|For the fiscal year ended December 31,
    2003

Encore Acquisition Company

(Exact name of registrant as specified in its
charter)


|                                                                                                 |  |                              |  |                                      
|------------------------------------------------------------------------------------------------ |  | ---------------------------- |  | -------------------------------------
|Delaware                                                                                         |  | 001-16295                    |  | 75-2759650                           
|(State or other jurisdiction
    of incorporation)                                               |  | (Commission
    File Number) |  | (IRS Employer
    Identification No.)
|                                                                                                
|777 Main Street
    Suite 1400
    Fort Worth, Texas(Address of principal executive
    offices) |  |                              |  | 76102(Zip Code)                      

Registrants telephone number, including
area code:

(817) 877-9955


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

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

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

None


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

|                                                                                                                                                                                                                               |  |   |             | 
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ |  | - | ----------- | 
|Aggregate market value of the voting and
    non-voting common stock held by non-affiliates of the Registrant
    as of June 30, 2003 (the last business day of
    Registrants most recently completed second fiscal quarter |  | $ | 222,980,532 | 
|Number of shares of Common Stock, $0.01 par
    value, outstanding as of February 27, 2004                                                                                                                                     |  |   | 30,403,189  | 

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.



---






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ENCORE ACQUISITION COMPANY

2003 ANNUAL REPORT ON FORM 10-K


TABLE OF CONTENTS

|                                                 |  |                                                                                                        |  |      |    |  |  | 
|------------------------------------------------ |  | ------------------------------------------------------------------------------------------------------ |  | ---- | -- |  |  | 
|                                                 |  |                                                                                                        |  | Page
|                                                 |  |                                                                                                        |  |     
|PART I                                          
|Items 1 and 2.                                   |  | Business and Properties                                                                                |  |      | 2  | 
|Item 3.                                          |  | Legal Proceedings                                                                                      |  |      | 16 | 
|Item 4.                                          |  | Submission of Matters to a
    Vote of Security Holders                                                |  |      | 16 | 
|                                                
|PART II                                         
|Item 5.                                          |  | Market for Registrants
    Common Equity and Related Stockholder Matters                              |  |      | 17 | 
|Item 6.                                          |  | Selected Financial Data                                                                                |  |      | 18 | 
|Item 7.                                          |  | Managements Discussion
    and Analysis of Financial Condition and Results of Operations              |  |      | 19 | 
|Item 7A.                                         |  | Quantitative and Qualitative
    Disclosures About Market Risk                                         |  |      | 43 | 
|Item 8.                                          |  | Financial Statements and
    Supplementary Data                                                        |  |      | 48 | 
|Item 9.                                          |  | Changes in and Disagreements
    with Accountants on Accounting and Financial Disclosure               |  |      | 79 | 
|Item 9A.                                         |  | Controls and Procedures                                                                                |  |      | 79 | 
|                                                
|PART III                                        
|Item 10.                                         |  | Directors and Executive
    Officers of the Registrant                                                 |  |      | 79 | 
|Item 11.                                         |  | Executive Compensation                                                                                 |  |      | 80 | 
|Item 12.                                         |  | Security Ownership of
    Certain Beneficial Owners and Management and Related Stockholder
    Matters |  |      | 80 | 
|Item 13.                                         |  | Certain Relationships and
    Related Transactions                                                     |  |      | 80 | 
|Item 14.                                         |  | Principal Accountant Fees
    and Services                                                             |  |      | 80 | 
|                                                
|PART IV                                         
|Item 15.                                         |  | Exhibits, Financial
    Statement Schedules, and Reports on Form 8-K                                   |  |      | 81 | 
|First Amendment to Credit Agreement             
|Second Amendment to Credit Agreement            
|Severance Agreement with Morris B. Smith        
|Stock Purchase Agreement                        
|Subsidiaries of the Company                     
|Consent of Ernst & Young LLP                    
|Consent of Miller and Lents, Ltd.               
|Rule 13a-14(a)/15d-14(a) Certification          
|Rule 13a-14(a)/15d-14(a) Certification          
|Certification Pursuant to 18 U.S.C. Section 1350
|Certification Pursuant to 18 U.S.C. Section 1350





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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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high-quality assets and to replenish our drilling
inventory through acquisitions. During 2003, we added
20.7 MMBOE of oil and natural gas reserves for finding,
development, and acquisition, or FD&A, replacement costs of
$7.42 per BOE, which replaced 255% of the 8.1 MMBOE we
produced in 2003. Including downward revisions of
3.5 MMBOE, the development program added 14.4 MMBOE
(178% of our production) at an average FD&A cost of
$6.86 per BOE. Included in our reserve additions are
12.5 MMBOE of HPAI in the CCA of Montana and North Dakota.
Our three year average FD&A cost, including revisions, is
$5.60 per BOE, with a reserve replacement ratio of 329%.


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.

|                         |       |                    |         |         |  |                |    |         |   |       |        |        |  |  |    |     |   |  |      |      | 
|------------------------ | ----- | ------------------ | ------- | ------- |  | -------------- | -- | ------- | - | ----- | ------ | ------ |  |  | -- | --- | - |  | ---- | ---- | 
|                         |       | Proved Reserves at |         |         |  | Average Daily  |    |         |   |      
|                         |       | December 31,       |         | Percent |  | Production for |    | Percent |   |      
|                         |       | 2003               |         | of      |  | 2003           |    | of      |   | R/P  
|                         |       | (MBOE)             |         | Total   |  | (BOE/d)        |    | Total   |   | Index
|                         |       |                    |         |         |  |                |    |         |   |      
|Cedar Creek Anticline(1) |       |                    | 103,601 |         |  |                | 73 | %       |   |       | 13,490 |        |  |  | 61 | %   |   |  | 21.0 |     
|Permian Basin(2)         |       |                    | 22,424  |         |  |                | 16 | %       |   |       | 4,554  |        |  |  | 20 | %   |   |  | 13.5 |     
|Rockies(3)               |       |                    | 6,620   |         |  |                | 5  | %       |   |       | 2,935  |        |  |  | 13 | %   |   |  | 6.2  |     
|Mid Continent(4)         |       |                    | 8,245   |         |  |                | 6  | %       |   |       | 1,239  |        |  |  | 6  | %   |   |  | 11.2 |     
|                         |       |                    |         |         |  |                |    |         |   |       |        |        |  |  |    |     |   |  |      |     
|                         | Total |                    |         | 140,890 |  |                |    | 100     | % |       |        | 22,218 |  |  |    | 100 | % |  |      | 17.4 | 
|                         |       |                    |         |         |  |                |    |         |   |       |        |        |  |  |    |     |   |  |      |     



---



|    |                                                                                                                                                                                                                                                                                                                                                                                
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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

|                         |       |                     |       |                           |  |                      |       |         |  |         |       |        |  |        |    |                |   |         |         |         |  |  |        |         |  |  |         |         |  |   |         |           |  |  |    |     |  
|------------------------ | ----- | ------------------- | ----- | ------------------------- |  | -------------------- | ----- | ------- |  | ------- | ----- | ------ |  | ------ | -- | -------------- | - | ------- | ------- | ------- |  |  | ------ | ------- |  |  | ------- | ------- |  | - | ------- | --------- |  |  | -- | --- | -
|                         |       |                     |       |                           |  |                      |       |         |  |         |       |       
|                         |       |                     |       | Proved Reserve Quantities |  | PV-10               
|                         |       | Net Production 2003 |       | at December 31, 2003      |  | at December 31, 2003
|                         |       |                     |       |                           |  |                     
|                         |       |                     |       | Natural                   |  |                      |       |         |  | Natural |       |        |  |       
|                         |       | Oil                 |       | Gas                       |  | Total                |       |         |  | Oil     |       | Gas    |  | Total  |    |               
|                         |       | (MBbls)             |       | (MMcf)                    |  | (MBOE)               |       | Percent |  | (MBbls) |       | (MMcf) |  | (MBOE) |    | Amount(5)      |   | Percent
|                         |       |                     |       |                           |  |                      |       |         |  |         |       |        |  |        |    |                |   |        
|                         |       |                     |       |                           |  |                      |       |         |  |         |       |        |  |        |    | (In thousands) |   |        
|Cedar Creek Anticline(1) |       |                     | 4,723 |                           |  |                      | 1,206 |         |  |         | 4,924 |        |  |        | 61 | %              |   |         | 100,387 |         |  |  | 19,286 |         |  |  | 103,601 |         |  | $ | 614,428 |           |  |  | 60 | %  
|Permian Basin(2)         |       |                     | 853   |                           |  |                      | 4,857 |         |  |         | 1,662 |        |  |        | 20 | %              |   |         | 11,067  |         |  |  | 68,138 |         |  |  | 22,424  |         |  |   | 230,223 |           |  |  | 23 | %  
|Rockies(3)               |       |                     | 990   |                           |  |                      | 490   |         |  |         | 1,071 |        |  |        | 13 | %              |   |         | 6,123   |         |  |  | 2,983  |         |  |  | 6,620   |         |  |   | 62,263  |           |  |  | 6  | %  
|Mid Continent(4)         |       |                     | 35    |                           |  |                      | 2,498 |         |  |         | 453   |        |  |        | 6  | %              |   |         | 155     |         |  |  | 48,543 |         |  |  | 8,245   |         |  |   | 114,160 |           |  |  | 11 | %  
|                         |       |                     |       |                           |  |                      |       |         |  |         |       |        |  |        |    |                |   |         |         |         |  |  |        |         |  |  |         |         |  |   |         |           |  |  |    |    
|                         | Total |                     |       | 6,601                     |  |                      |       | 9,051   |  |         |       | 8,110  |  |        |    | 100            | % |         |         | 117,732 |  |  |        | 138,950 |  |  |         | 140,890 |  |   | $       | 1,021,074 |  |  |    | 100 | %
|                         |       |                     |       |                           |  |                      |       |         |  |         |       |        |  |        |    |                |   |         |         |         |  |  |        |         |  |  |         |         |  |   |         |           |  |  |    |    



---



|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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 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 where such techniques have been
proved effective by actual tests in the area and in the same
reservoir.


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):

|                            |                     |                    |         |         |           |      |         |         |         |   |         |         |         | 
|--------------------------- | ------------------- | ------------------ | ------- | ------- | --------- | ---- | ------- | ------- | ------- | - | ------- | ------- | ------- | 
|                            |                     |                   
|                            |                     | As of December 31,
|                            |                     |                   
|                            |                     | 2003               |         | 2002    |           | 2001
|                            |                     |                    |         |         |           |     
|Oil (Bbls)                  |                     |                    |         |         |           |      |         |         |         |   |         |        
|                            | Developed           |                    |         | 92,377  |           |      |         | 93,945  |         |   |         | 71,639  |        
|                            | Undeveloped         |                    |         | 25,355  |           |      |         | 17,729  |         |   |         | 19,730  |        
|                            |                     |                    |         |         |           |      |         |         |         |   |         |        
|                            |                     | Total              |         |         | 117,732   |      |         |         | 111,674 |   |         |         | 91,369  | 
|                            |                     |                    |         |         |           |      |         |         |         |   |         |        
|Natural Gas (Mcf)           |                     |                    |         |         |           |      |         |         |         |   |         |        
|                            | Developed           |                    |         | 104,767 |           |      |         | 82,217  |         |   |         | 69,941  |        
|                            | Undeveloped         |                    |         | 34,183  |           |      |         | 17,601  |         |   |         | 5,746   |        
|                            |                     |                    |         |         |           |      |         |         |         |   |         |        
|                            |                     | Total              |         |         | 138,950   |      |         |         | 99,818  |   |         |         | 75,687  | 
|                            |                     |                    |         |         |           |      |         |         |         |   |         |        
|Combined (BOE)              |                     |                    |         |         |           |      |         |         |         |   |         |        
|                            | Developed           |                    |         | 109,838 |           |      |         | 107,648 |         |   |         | 83,296  |        
|                            | Undeveloped         |                    |         | 31,052  |           |      |         | 20,662  |         |   |         | 20,687  |        
|                            |                     |                    |         |         |           |      |         |         |         |   |         |        
|                            |                     | Total(1)           |         |         | 140,890   |      |         |         | 128,310 |   |         |         | 103,983 | 
|                            |                     |                    |         |         |           |      |         |         |         |   |         |        
|PV-10(2)                    |                     |                    |         |         |           |      |         |         |         |   |         |        
|                            | Developed           |                    | $       | 844,873 |           |      | $       | 732,823 |         |   | $       | 299,383 |        
|                            | Undeveloped         |                    |         | 176,201 |           |      |         | 132,281 |         |   |         | 60,979  |        
|                            |                     |                    |         |         |           |      |         |         |         |   |         |        
|                            |                     | Total              |         | $       | 1,021,074 |      |         | $       | 865,104 |   |         | $       | 360,362 | 
|                            |                     |                    |         |         |           |      |         |         |         |   |         |        
|Standardized
    Measure(3) |                     | $                  | 736,939 |         |           | $    | 624,718 |         |         | $ | 284,309 |        
|                            |                     |                    |         |         |           |      |         |         |         |   |         |        
|Reserve price assumptions   |                     |                    |         |         |           |      |         |         |         |   |         |        
|                            | Oil ($/Bbl)         |                    | $       | 32.55   |           |      | $       | 31.20   |         |   | $       | 19.84   |        
|                            | Natural gas ($/Mcf) |                    |         | 5.83    |           |      |         | 4.79    |         |   |         | 2.57    |        



---



|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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:

|                          |                       |                         |   |        |  |      |   |        |  |  |   |        | 
|------------------------- | --------------------- | ----------------------- | - | ------ |  | ---- | - | ------ |  |  | - | ------ | 
|                          |                       |                        
|                          |                       | Year Ended December 31,
|                          |                       |                        
|                          |                       | 2003                    |   | 2002   |  | 2001
|                          |                       |                         |   |        |  |     
|Production:               |                       |                         |   |        |  |      |   |        |  |  |   |       
|                          | Oil (MBbls)           |                         |   | 6,601  |  |      |   | 6,037  |  |  |   | 4,935  | 
|                          | Natural gas (MMcf)    |                         |   | 9,051  |  |      |   | 8,175  |  |  |   | 8,078  | 
|                          | Combined (MBOE)       |                         |   | 8,110  |  |      |   | 7,399  |  |  |   | 6,281  | 
|Average Daily Production: |                       |                         |   |        |  |      |   |        |  |  |   |       
|                          | Oil (Bbls/d)          |                         |   | 18,085 |  |      |   | 16,540 |  |  |   | 13,519 | 
|                          | Natural gas (Mcf/d)   |                         |   | 24,798 |  |      |   | 22,397 |  |  |   | 22,130 | 
|                          | Combined (BOE/d)      |                         |   | 22,218 |  |      |   | 20,273 |  |  |   | 17,208 | 
|Average Prices:           |                       |                         |   |        |  |      |   |        |  |  |   |       
|                          | Oil (per Bbl)         |                         | $ | 26.72  |  |      | $ | 22.34  |  |  | $ | 21.43  | 
|                          | Natural gas (per Mcf) |                         |   | 4.83   |  |      |   | 3.16   |  |  |   | 3.73   | 
|                          | Combined (per BOE)    |                         |   | 27.14  |  |      |   | 21.72  |  |  |   | 21.64  | 

7



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|                       |                                                                              |                         |   |      |  |      |   |      |  |  |   |      | 
|---------------------- | ---------------------------------------------------------------------------- | ----------------------- | - | ---- |  | ---- | - | ---- |  |  | - | ---- | 
|                       |                                                                              |                        
|                       |                                                                              | Year Ended December 31,
|                       |                                                                              |                        
|                       |                                                                              | 2003                    |   | 2002 |  | 2001
|                       |                                                                              |                         |   |      |  |     
|Average Costs per BOE: |                                                                              |                         |   |      |  |      |   |      |  |  |   |     
|                       | Lease operations expense                                                     |                         | $ | 4.67 |  |      | $ | 4.15 |  |  | $ | 4.00 | 
|                       | Production, ad valorem, and severance taxes                                  |                         |   | 2.71 |  |      |   | 2.12 |  |  |   | 2.20 | 
|                       | General and administrative (excluding non-cash
    stock based compensation) |                         |   | 1.07 |  |      |   | 0.83 |  |  |   | 0.80 | 
|                       | Depletion, depreciation, and amortization                                    |                         |   | 4.13 |  |      |   | 4.67 |  |  |   | 5.05 | 

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.

|                      |       |           |       |                   |     |          |     |         |  |       |     |          |  |  |     |     |     |  |     |     |  |  |     |     | 
|--------------------- | ----- | --------- | ----- | ----------------- | --- | -------- | --- | ------- |  | ----- | --- | -------- |  |  | --- | --- | --- |  | --- | --- |  |  | --- | --- | 
|                      |       |           |       |                  
|                      |       | Oil Wells |       | Natural Gas Wells
|                      |       |           |       |                  
|                      |       |           |       | Average           |     |          |     | Average
|                      |       | Gross     |       | Net               |     | Working  |     | Gross   |  | Net   |     | Working 
|                      |       | Wells     |       | Wells             |     | Interest |     | Wells   |  | Wells |     | Interest
|                      |       |           |       |                   |     |          |     |         |  |       |     |         
|Cedar Creek Anticline |       |           | 565   |                   |     |          | 492 |         |  |       | 87% |          |  |  | 31  |     |     |  | 8   |     |  |  | 25% |    
|Permian Basin         |       |           | 1,171 |                   |     |          | 213 |         |  |       | 18% |          |  |  | 367 |     |     |  | 143 |     |  |  | 39% |    
|Rockies               |       |           | 309   |                   |     |          | 77  |         |  |       | 25% |          |  |  |    |     |     |  |    |     |  |  |    |    
|Mid Continent         |       |           | 65    |                   |     |          | 3   |         |  |       | 5%  |          |  |  | 222 |     |     |  | 39  |     |  |  | 18% |    
|                      |       |           |       |                   |     |          |     |         |  |       |     |          |  |  |     |     |     |  |     |     |  |  |     |    
|                      | Total |           |       | 2,110             | (1) |          |     | 785     |  |       |     | 37%      |  |  |     | 620 | (1) |  |     | 190 |  |  |     | 31% | 
|                      |       |           |       |                   |     |          |     |         |  |       |     |          |  |  |     |     |     |  |     |     |  |  |     |    



---



|    |                                                                             
|--- | ----------------------------------------------------------------------------
|(1) | Our total wells include 906 operated wells and
    1,824 non-operated wells.

Acreage

The following table sets forth information at
December 31, 2003 relating to acreage held by us. Developed
acreage is assigned to producing wells. Undeveloped acreage is
acreage held under lease, permit, contract, or option that is
not in a spacing unit for a producing well, including leasehold
interests identified for exploitation or exploratory drilling.
Our undeveloped acreage is concentrated in our CCA, Bell Creek,
and Verden properties, which represent 75%, 7%, and 7% of our
total undeveloped acreage, respectively. These leases expire at
various dates ranging from January 2004 to July 2012, with
leases representing $403,000 of cost set to expire in 2004 if
not developed.

|                    |       |         |         |         |  |  |         |         | 
|------------------- | ----- | ------- | ------- | ------- |  |  | ------- | ------- | 
|                    |       | Gross   |         | Net    
|                    |       | Acreage |         | Acreage
|                    |       |         |         |        
|Developed acreage   |       |         | 211,219 |         |  |  | 138,981 |        
|Undeveloped acreage |       |         | 73,896  |         |  |  | 56,903  |        
|                    |       |         |         |         |  |  |         |        
|                    | Total |         |         | 285,115 |  |  |         | 195,884 | 
|                    |       |         |         |         |  |  |         |        

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##### Table of Contents



Drilling Results

The following table sets forth information with
respect to wells drilled during the periods indicated. The
information should not be considered indicative of future
performance, nor should a correlation be assumed between the
number of productive wells drilled, quantities of reserves
found, or economic value. We should continue to have good
results from drilling because most of our exposure is to infill
drilling. Productive wells are those that produce commercial
quantities of hydrocarbons, exclusive of their capacity to
produce a reasonable rate of return.

|                  |       |                         |  |       |  |      |  |       |  |  |  |       | 
|----------------- | ----- | ----------------------- |  | ----- |  | ---- |  | ----- |  |  |  | ----- | 
|                  |       |                        
|                  |       | Year Ended December 31,
|                  |       |                        
|Development Wells |       | 2003                    |  | 2002  |  | 2001
|                  |       |                         |  |       |  |     
|Productive        |       |                         |  |       |  |      |  |       |  |  |  |      
|                  | Gross |                         |  | 137.0 |  |      |  | 109.0 |  |  |  | 142.0 | 
|                  | Net   |                         |  | 103.0 |  |      |  | 95.3  |  |  |  | 105.6 | 
|Dry               |       |                         |  |       |  |      |  |       |  |  |  |      
|                  | Gross |                         |  | 1.0   |  |      |  | 0.0   |  |  |  | 1.0   | 
|                  | Net   |                         |  | 0.7   |  |      |  | 0.0   |  |  |  | 1.0   | 

Present Activities

As of December 31, 2003, we had a total of
3 gross (2.9 net) wells that had been spudded and were
in varying stages of drilling operations. Also, there were
10 gross (9.8 net) wells that had reached total depth
and were in varying stages of completion pending first
production.

As of December 31, 2003, we are in the
process of expanding the HPAI program to the entire north end of
the Pennel Unit. Full field design has been completed and we are
ordering necessary tubular, electrical, and compression
equipment for the project.

We are in the process of completing the first
phase of HPAI in the Little Beaver area on CCA. First injection
began in the Little Beaver phase one during December 2003 and
phase one and phase two should be completed during 2004.

Delivery Commitments and Marketing

Our oil and natural gas production is principally
sold to end users, marketers, refiners, and other purchasers
having access to nearby pipeline facilities consistent with
industry practices. In areas where there is no practical access
to pipelines, oil is trucked to storage facilities. Our
marketing of oil and natural gas can be affected by factors
beyond our control, the potential effects of which cannot be
accurately predicted. For the fiscal year 2003, our largest
purchasers included ConocoPhillips, Shell, and Eighty-Eight Oil,
which respectively accounted for 28%, 26%, and 11% of total oil
and natural gas sales. Management is of the opinion that the
loss of any one purchaser would not have a material adverse
effect on our ability to market our oil and natural gas
production. The sale of approximately 50% of CCA oil is
dependant on transportation to markets through the Butte
pipeline to Guernsey, Wyoming. Any restrictions on the available
capacity for us to transport oil in this pipeline could have a
material adverse effect on our price we receive and our oil
revenues.

Competition

We compete with major and independent oil and
natural gas companies. Some of our competitors have
substantially greater financial and other resources than we do.
In addition, larger competitors may be able to absorb the burden
of any changes in federal, state, provincial, and local laws and
regulations more easily than we can, adversely affecting our
competitive position. Our competitors may be able to pay more
for productive oil and natural gas properties and may be able to
define, evaluate, bid for, and purchase a greater number of
properties and prospects than we can. Further, these companies
may enjoy technological advantages and may be able to implement
new technologies more rapidly than we can. Our ability to

9



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acquire additional properties in the future will
depend upon our ability to conduct efficient operations,
evaluate and select suitable properties, implement advanced
technologies, and consummate transactions in this highly
competitive environment.


Federal and State Regulations

Compliance with applicable federal and state
regulations is often difficult and costly, and non-compliance
may result in substantial penalties. The following are some
specific regulations that may affect us. We cannot predict the
impact of these or future legislative or regulatory initiatives.

Federal Regulation of Natural
Gas.The interstate transportation and
sale for resale of natural gas is subject to federal regulation,
including transportation rates and various other matters, by the
Federal Energy Regulatory Commission (FERC). Federal
wellhead price controls on all domestic natural gas were
terminated on January 1, 1992 and none of our natural gas
sales are currently subject to FERC regulation. We cannot
predict the impact of future government regulation on any
natural gas operations.

Although FERCs regulations should generally
facilitate the transportation of natural gas produced from our
properties and the direct access to end-user markets, the future
impact of these regulations on marketing our production or on
our natural gas transportation business cannot be predicted. We
do not believe, however, that we will be affected differently
than competing producers and marketers.

Federal Regulation of
Oil.Sales of crude oil, condensate
and natural gas liquids are not currently regulated and are made
at market prices. The net price received from the sale of these
products is affected by market transportation costs. A
significant part of our oil production is transported by
pipeline. Under rules adopted by FERC effective January 1995,
interstate oil pipelines can change rates based on an inflation
index, though other rate mechanisms may be used in specific
circumstances. The United States Court of Appeals upheld
FERCs orders in 1996. These rules have had little effect
on our oil transportation cost.

State Regulation.Oil and natural gas operations are subject to various types of
regulation at the state and local levels. Such regulation
includes requirements for drilling permits, the method of
developing new fields, the spacing and operations of wells and
waste prevention. The production rate may be regulated and the
maximum daily production allowable from oil and natural gas
wells may be established on a market demand or conservation
basis. These regulations may limit production by well and the
number of wells that can be drilled.

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

Environmental
Regulations.Various federal, state
and local laws regulating the discharge of materials into the
environment, or otherwise relating to the protection of the
environment, directly impact oil and natural gas exploration,
development and production operations, and consequently may
impact our operations and costs. Management believes that we are
in substantial compliance with applicable environmental laws and
regulations. To date, we have not expended any material amounts
to comply with such regulations, and we do not currently
anticipate that future compliance will have a materially adverse
effect on our consolidated financial position or results of
operations.

Operating Hazards and Insurance

The oil and natural gas business involves a
variety of operating risks, including fires, explosions,
blowouts, environmental hazards, and other potential events that
can adversely affect our operations. Any of these problems could
adversely affect our ability to conduct operations and cause us
to incur substantial losses. Such losses could reduce or
eliminate the funds available for exploration, exploitation, or
leasehold acquisitions or result in loss of properties.

10



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

Employees

We had 119 employees as of December 31,
2003, 50 of which are field personnel. None of the employees are
represented by any union. We consider our relations with our
employees to be good.

Principal Executive Office

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

Available Information

We make available electronically, free of charge
through our website (www.encoreacq.com), our annual reports on
Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K and other items filed with the SEC
pursuant to Section 13(a) of the Securities Exchange Act of
1934 as soon as reasonably practicable after we electronically
file such material with the SEC. In addition, the public may
read and copy any materials that we file with the SEC at the
SECs Public Reference Room at 450 Fifth Street, NW,
Washington, DC 20549. The public may obtain information on the
operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330. The SEC maintains a website (www.sec.gov) that
contains reports, proxy and information statements and other
information regarding issuers, like us, that file electronically
with the SEC.

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

The charters of our board of director committees
are available on our website. Copies of the code of business
conduct and ethics and board committee charters are also
available in print upon written request to the Corporate
Secretary, Encore Acquisition Company, 777 Main Street,
Suite 1400, Fort Worth, Texas 76102.

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

Properties



| |                                      
| | -------------------------------------
| | Nature of Our
    Ownership Interests

We own interests in oil and natural gas
properties located in Montana, North Dakota, Texas, New Mexico,
Oklahoma, Utah, and Louisiana. Substantially all of our PV-10
reserve value at December 31, 2003 was attributable to
working interests in oil and natural gas properties. A working
interest in an oil and natural gas lease requires us to pay our
proportionate share of the costs of drilling and production. The
map on the following page depicts the location of our
significant properties and the properties we plan to acquire
from Cortez. For information on the pending acquisition of
Cortez, see General  Recent Acquisitions
and Note 14. Subsequent Events (unaudited) to
the consolidated financial statements.

11



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##### Table of Contents



MAP



| |                                                                
| | ---------------------------------------------------------------
| | Cedar Creek Anticline
    Properties  Montana and North Dakota

The CCA was purchased on June 1, 1999, and
we have subsequently acquired additional working interests from
various owners. Presently, we operate approximately 99.5% of the
CCA properties with an average working interest of approximately
87%.

The CCA is a major structural feature of the
Williston Basin in southeastern Montana and northwestern North
Dakota. Our acreage is concentrated on the crest of
the CCA, giving us access to the greatest accumulation of oil in
the structure. Our holdings extend for approximately 70
continuous miles across five counties in two states. The gross
producing interval on the CCA is approximately 2,000 feet
thick, and ranges in depth from approximately 7,000 feet to
9,000 feet.

Since taking over operations, along with
subsequent additional acquired interests, we have increased
production by 75% on the CCA from 7,807 BOE per day (average for
June 1999) to 13,655 BOE per day (average for the fourth quarter
2003). We have accomplished ongoing production growth through a
combination of:



| |   |                                                                                             
| | - | --------------------------------------------------------------------------------------------
| |  | additional acquisition of interests;                                                        
|
| |  | detailed attention to the existing wellbores;                                               
|
| |  | the addition of strategically positioned new
    horizontal and vertical wellbores;         
|
| |  | the highly successful application of horizontal
    re-entry drilling in existing wellbores;
|
| |  | waterflood enhancements;                                                                    
|
| |  | and implementation of our high-pressure air
    injection program.                          

In 2003, we drilled 78 gross wells on the
CCA, of which 46 were horizontal re-entry wells that both
reestablished production from non-producing wells, added
additional barrels from existing producing wells and serve as
injection wells for secondary and tertiary recovery projects.
Including our HPAI project, we incurred $77.6 million of
capital projects on the CCA during 2003. The average daily
production from the CCA was 13,490 BOE per day for 2003.

12



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Our outlook for sustained production growth on
the CCA remains strong. We plan to continue the development of
the reserve base through currently identified opportunities and
future opportunities resulting from knowledge gained through
continued study and the drilling and exploitation efforts
ongoing on these properties. We believe that HPAI continues to
be our most significant source of sustained production growth on
the CCA.

The CCA represents 73% of our total proved
reserves as of December 31, 2003. The CCA represents our
most valuable asset today and in the foreseeable future. A large
portion of our future success revolves around future
exploitation and production from these properties.

High-Pressure Air
Injection.High-pressure air injection
is a tertiary recovery technique that involves utilizing
compressors to inject air into oil and natural gas formations in
order to displace remaining resident hydrocarbons and force them
under pressure to a common lifting point for production.

In 2002 we initiated a HPAI pilot program that
injects air into the Red River U4 zone in the Pennel area of the
CCA. The Red River U4 zone is the same zone where high-pressure
air injection has been successfully implemented by other
operators in adjacent areas on the CCA. We have seen positive
results from this pilot high-pressure air injection project at
Pennel. Based on these results, we are in the process of
expanding high pressure air injection to other areas in the CCA.
We believe that high-pressure air injection technology can be
applied throughout the CCA and that it may yield significant new
reserves. We believe that the high-pressure air injection will
generate a higher rate of return than other tertiary processes
on the CCA.

The pilot project at Pennel continues to perform
well with production uplift on target with our original
projection. During the second half of 2003 we approved a
$25 million project to expand HPAI to the entire north end
of the Pennel Unit (Pennel Phase Two). Full field
design has been completed and we are ordering necessary tubular,
electrical, and compression equipment. The Pennel Phase Two
expansion should be complete in early 2005.

In the Little Beaver area of the CCA we were able
to arrange to purchase our high-pressure air compression
services from an offset operator during 2003. This allowed us to
implement a HPAI project in Little Beaver, on the south end of
the CCA, in less than one year. First injection began in Little
Beaver phase one during December 2003 and phase one and phase
two should be completed during 2004. Our independent reserve
engineers, Miller and Lents, Ltd., booked 12.2 million
barrels of proved undeveloped oil reserves associated with high
pressure air at year end 2003 related to the Little Beaver unit
project. High-pressure air injection contributed to our FD&A
cost during 2003.

We believe that much of our acreage in the CCA
has potential opportunities for utilizing HPAI recovery
techniques at economic rates of return. We continue to evaluate
and perform engineering studies on these projects. Over the next
several years we plan to implement these development projects
initially in the Red River U4 zone of the CCA. Additionally, we
have other zones in the CCA that currently produce oil and may
provide additional HPAI opportunities. We believe these zones
can be most economically evaluated for HPAI opportunities after
initiating HPAI in the Red River U4 zone.

Net Profits
Interests.A major portion of our
acreage position in the CCA is subject to net profits interests
(NPI) ranging from 1% to 50%. The holders of these
net profits interests are entitled to receive a fixed percentage
of the cash flow remaining after specified costs have been
subtracted from net revenue. The net profits calculations are
contractually defined, but in general, net profits are
determined after considering operating expense, overhead
expense, interest expense, and drilling costs. The amounts of
reserves and production calculated to be attributable to these
net profits interests are deducted from our reserves and
production data, and our revenues are reported net of NPI
payments. The reserves and production that are attributed to the
NPIs are calculated by dividing estimated future NPI payments
(in the case of reserves) or prior period actual NPI payments
(in the case of production) by the commodity prices current at
the determination date. Fluctuations in commodity prices and the
levels of development activities in the CCA from period to
period will impact the reserves and production attributed to the
NPIs and will have an inverse effect on our reported reserves
and production. For the years ended December 31,

13



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##### Table of Contents



2003, 2002, and 2001, we reduced revenue for the
payments of the net profits interests by $5.8 million,
$2.0 million, and $2.8 million, respectively.




| |                                                    
| | ---------------------------------------------------
| | Permian Basin Properties  Texas
    and New Mexico



| |                                                                   
| | ------------------------------------------------------------------
| | Central
    Permian Andrews, Ector,
    and Pecos Counties, Texas

The Central Permian properties were purchased
from Conoco on January 4, 2002. These properties are
located in the Permian Basin near Midland, Texas, and include
two major operated fields: East Cowden Grayburg Unit and
Fuhrman-Nix; and two non-operated fields: North Cowden and
Yates. The properties are 94% oil. Production from the Central
Permian comes from multiple reservoirs including the
San Andres, Grayburg, Glorieta, and Pennsylvanian zones at
depths ranging from approximately 4,000 feet to
10,000 feet. We invested $12.2 million in the
development drilling of 18 gross wells on the properties in
2003. Average daily production from the Central Permian
properties was 2,410 BOE per day in 2003. We see these
properties as an area of growth over the next several years.



| |                                     
| | ------------------------------------
| | Crockett
    Crockett County, Texas

The Crockett properties were purchased on
March 30, 2000. We have acquired small additional working
interests subsequent to the initial acquisition. The properties,
located in the southern portion of the Permian Basin of West
Texas consist primarily of three field groupings located near
the town of Ozona, Texas. We operate approximately 34% of the
Crockett properties, and we own a large interest in a
significant number of the properties that we do not operate.

Production comes mainly from the Canyon and
Strawn Formations. Both formations contain multiple pay
intervals, and continued development opportunities remain on
these properties. In 2003, an active development drilling
program took place on our non-operated properties. In 2003, we
invested approximately $3.7 million of development capital
on the Crockett properties. Since acquiring these properties, we
have increased production 18% from 8,700 Mcfe per day
(average daily production for 2000) to 10,288 Mcfe per day
(average daily production for 2003). We see these properties as
an area of growth over the next couple of years.



| |                                              
| | ---------------------------------------------
| | Indian
    Basin Eddy County, New
    Mexico

The Indian Basin properties were purchased on
August 24, 2000. We own varied non-operated working
interests in these properties (primary area operators are
Marathon and ChevronTexaco), whose production is 96% natural
gas. Located in the western portion of the Permian Basin in
southeastern New Mexico, these properties produce from multiple
zones in the Pennsylvanian Formation. In 2003, we invested an
insignificant amount of capital in the Indian Basin properties.
The average daily production from the Indian Basin properties
was 2,573 Mcfe per day for 2003.



| |                                                                
| | ---------------------------------------------------------------
| | Rocky Mountain Properties  North
    Dakota, Montana, and Utah



| |                                      
| | -------------------------------------
| | Lodgepole Stark County, North Dakota

The Lodgepole properties were purchased on
March 31, 2000. The properties consist of working and
overriding royalty interests in several geographically
concentrated fields. Approximately 95% of our interests are
non-operated; the largest of which is the Eland Unit in which we
own a 26% working interest.

The Lodgepole properties are located in the
Williston Basin in western North Dakota near the town of
Dickinson, approximately 120 miles from our CCA properties.
The Lodgepole properties produce exclusively from the
Mississippian-aged Lodgepole Formation, and the Eland Unit is
the largest accumulation in the trend. The average production
from the Lodgepole properties was 1,817 BOE per day for 2003. In
2003, we invested an insignificant amount of capital in the
Lodgepole properties.

The Lodgepole properties produce from reefs with
high permeability and thick oil columns. The prolific nature of
these reservoirs makes future engineering estimates related to
ultimate recovery of

14



---



##### Table of Contents



reserves inherently difficult to determine. If
the properties performance varies significantly from the
Miller and Lents, Ltd. estimates of reserves, then our future
cash flows could be affected in 2004 and a few years beyond.




| |                                                              
| | -------------------------------------------------------------
| | Bell
    Creek Powder River and
    Carter Counties, Montana

The Bell Creek properties, located in the Powder
River Basin of southeastern-most Montana, were purchased on
November 29, 2000. We operate the seven production units
that comprise the Bell Creek properties, each with a 100%
working interest. The shallow (less than 5,000 feet)
Cretaceous-aged Muddy Sandstone reservoir produces 100% oil. We
invested $0.5 million of capital in these properties in
2003. The average daily production from the Bell Creek
properties was 314 BOE per day for 2003.



| |                                             
| | --------------------------------------------
| | Paradox
    Basin San Juan
    County, Utah

The Paradox Basin properties, located in
southeast Utahs Paradox Basin, were purchased on
August 29, 2002. The properties are divided between two
prolific oil producing units: the Ratherford Unit operated by
ExxonMobil and the Aneth Unit operated by ChevronTexaco. The
working interest and net revenue interest in the Ratherford Unit
are 11.1% and 9.7%, respectively, and the working interest and
the net revenue interest in the Aneth Unit are 13.4% and 11.4%,
respectively. The average net production to us was approximately
804 BOE per day. We believe these properties have horizontal
redevelopment, secondary development, and tertiary recovery
potential. Our development capital was $0.5 million for
2003.



| |                                                      
| | -----------------------------------------------------
| | Mid Continent Properties 
    Oklahoma and Louisiana



| |                                             
| | --------------------------------------------
| | Elm
    Grove Bossier Parish,
    Louisiana

The Elm Grove properties were purchased on
July 31, 2003 for $52.5 million before purchase price
adjustments. Subsequent to the initial acquisition, we have
purchased additional interests in the properties. The interests
in the natural gas properties are located in the Elm Grove Field
in Bossier Parish, Louisiana. The acquired properties include
non-operated working interests ranging from 2% to 38% across
1,800 net acres in 15 sections. We did not own the
properties for an entire year; but the properties averaged
8,255 Mcfe per day in the fourth quarter of 2003. At
December 31, 2003, there were two wells currently being
drilled and five wells waiting on completion. In 2003, we
invested approximately $2.8 million of development capital
on the Elm Grove properties. We believe these properties are an
area of growth for us.



| |                                               
| | ----------------------------------------------
| | Verden
    Caddo and Grady Counties, Oklahoma

The Verden properties were purchased on
August 24, 2000. We own various operated and non-operated
interests in these properties. Located in the Anadarko Basin of
central Oklahoma, production is primarily natural gas from the
deep (below 15,000 feet) prolific Springer Sands. The
development of these properties is driven primarily by other
operators where we have a working interest in the properties and
share our proportional drilling costs. Therefore, we do not
control the timing of future development of the properties.
During 2003, we invested $1.6 million of capital in the
properties. The average daily production from the Verden
properties was 4,088 Mcfe per day for 2003.

Title To Properties

We believe that our title to our oil and natural
gas properties is good and defensible in accordance with
standards generally accepted in the oil and natural gas industry.

15



---



##### Table of Contents



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



| |   |                                                                                                                                                                                                                                                
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | royalties, overriding royalties, net profit
    interests, 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;                                  
|
| |  | pooling, unitization and communitization
    agreements, declarations, and orders; and                                                                                                                                                         
|
| |  | easements, restrictions, rights-of-way, and other
    matters that commonly affect property.                                                                                                                                                   

We believe that the burdens and obligations
affecting our properties do not in the aggregate materially
interfere with the use of the properties. As indicated under
Net Profits Interests above, a major portion of our
acreage position in the CCA, our primary asset, is subject to
net profits interests.






|        |                  
|------- | -----------------
|Item 3. | Legal Proceedings

We are not currently a party to any material
legal proceeding of which we are aware.






|        |                                                        
|------- | -------------------------------------------------------
|Item 4. | Submission of Matters to a Vote of Security
    Holders

There were no matters submitted to stockholders
during the quarter ended December 31, 2003.

16



---



##### Table of Contents





PART II







|        |                                                                          
|------- | -------------------------------------------------------------------------
|Item 5. | Market for Registrants Common Equity
    and Related Stockholder Matters

Our common stock, $0.01 par value, is listed
on the New York Stock Exchange under the symbol
EAC. The following table sets forth quarterly high
and low sales prices of our common stock for each quarterly
period of 2003 and 2002:

|                           |  |      |       |     |  |   |       | 
|-------------------------- |  | ---- | ----- | --- |  | - | ----- | 
|                           |  | High |       | Low
|                           |  |      |       |    
|2003                       |  |      |       |     |  |   |       | 
|Quarter ended December 31  |  | $    | 25.28 |     |  | $ | 19.60 | 
|Quarter ended September 30 |  |      | 22.15 |     |  |   | 17.80 | 
|Quarter ended June 30      |  |      | 20.01 |     |  |   | 17.00 | 
|Quarter ended March 31     |  |      | 19.35 |     |  |   | 16.63 | 
|2002                       |  |      |       |     |  |   |       | 
|Quarter ended December 31  |  | $    | 20.40 |     |  | $ | 13.51 | 
|Quarter ended September 30 |  |      | 17.55 |     |  |   | 15.00 | 
|Quarter ended June 30      |  |      | 17.35 |     |  |   | 14.60 | 
|Quarter ended March 31     |  |      | 15.00 |     |  |   | 12.40 | 

On February 27, 2004, we had approximately
202 shareholders of record.

Recent Sale and Repurchase of
Securities

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 and 2,193,357 shares from 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.

Dividends

No dividends have been declared or paid on our
common stock. We anticipate that we will retain all future
earnings and other cash resources for the future operation and
development of our business. Accordingly, we do not intend to
declare or pay any cash dividends in the foreseeable future.
Payment of any future dividends will be at the discretion of our
Board of Directors after taking into account many factors,
including our operating results, financial condition, current
and anticipated cash needs, and plans for expansion. The
declaration and payment of dividends is restricted by our
existing credit agreement, the indenture governing our
8 3/8% notes, and any future dividends may also be
restricted by future agreements with our lenders.

17



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##### Table of Contents








|        |                        
|------- | -----------------------
|Item 6. | Selected Financial Data

The following selected consolidated financial
data should be read in conjunction with Item 7.
Managements Discussion and Analysis of Financial Condition
and Results of Operations and Item 8. Financial
Statements and Supplementary Data (in thousands except per
share and per unit data):

|                                                          |                                                                              |                         |         |          |   |      |         |          |   |      |         |         |   |   |         |         |   |   |        |          |  
|--------------------------------------------------------- | ---------------------------------------------------------------------------- | ----------------------- | ------- | -------- | - | ---- | ------- | -------- | - | ---- | ------- | ------- | - | - | ------- | ------- | - | - | ------ | -------- | -
|                                                          |                                                                              |                        
|                                                          |                                                                              | Year Ended December 31,
|                                                          |                                                                              |                        
|                                                          |                                                                              | 2003                    |         | 2002     |   | 2001 |         | 2000     |   | 1999
|                                                          |                                                                              |                         |         |          |   |      |         |          |   |     
|Consolidated Statements of Operations
    Data:           |                                                                              |                         |         |          |   |      |         |          |   |      |         |         |   |   |         |         |   |   |        |         
|Revenues(1):                                              |                                                                              |                         |         |          |   |      |         |          |   |      |         |         |   |   |         |         |   |   |        |         
|                                                          | Oil                                                                          |                         | $       | 176,351  |   |      | $       | 134,854  |   |      | $       | 105,768 |   |   | $       | 92,441  |   |   | $      | 30,454   |  
|                                                          | Natural gas                                                                  |                         |         | 43,745   |   |      |         | 25,838   |   |      |         | 30,149  |   |   |         | 16,509  |   |   |        | 810      |  
|                                                          |                                                                              |                         |         |          |   |      |         |          |   |      |         |         |   |   |         |         |   |   |        |         
|Total revenues                                            |                                                                              | $                       | 220,096 |          |   | $    | 160,692 |          |   | $    | 135,917 |         |   | $ | 108,950 |         |   | $ | 31,264 |         
|                                                          |                                                                              |                         |         |          |   |      |         |          |   |      |         |         |   |   |         |         |   |   |        |         
|Net income (loss)                                         |                                                                              | $                       | 63,641  | (2)      |   | $    | 37,685  |          |   | $    | 16,179  | (3)     |   | $ | (2,135  | )(4)    |   | $ | 3,005  |         
|                                                          |                                                                              |                         |         |          |   |      |         |          |   |      |         |         |   |   |         |         |   |   |        |         
|Net income (loss) per common share:                       |                                                                              |                         |         |          |   |      |         |          |   |      |         |         |   |   |         |         |   |   |        |         
|                                                          | Basic                                                                        |                         | $       | 2.11     |   |      | $       | 1.25     |   |      | $       | 0.56    |   |   | $       | (0.09   | ) |   | $      | 0.13     |  
|                                                          | Diluted                                                                      |                         |         | 2.10     |   |      |         | 1.25     |   |      |         | 0.56    |   |   |         | (0.09   | ) |   |        | 0.13     |  
|Weighted average number of common shares
    outstanding: |                                                                              |                         |         |          |   |      |         |          |   |      |         |         |   |   |         |         |   |   |        |         
|                                                          | Basic                                                                        |                         |         | 30,102   |   |      |         | 30,031   |   |      |         | 28,718  |   |   |         | 22,806  |   |   |        | 22,687   |  
|                                                          | Diluted                                                                      |                         |         | 30,333   |   |      |         | 30,161   |   |      |         | 28,723  |   |   |         | 22,806  |   |   |        | 22,687   |  
|Consolidated Statements of Cash Flows
    Data:           |                                                                              |                         |         |          |   |      |         |          |   |      |         |         |   |   |         |         |   |   |        |         
|Cash provided by (used by):                               |                                                                              |                         |         |          |   |      |         |          |   |      |         |         |   |   |         |         |   |   |        |         
|                                                          | Operating activities                                                         |                         | $       | 123,818  |   |      | $       | 91,509   |   |      | $       | 80,212  |   |   | $       | 44,508  |   |   | $      | 9,759    |  
|                                                          | Investing activities                                                         |                         |         | (153,747 | ) |      |         | (159,316 | ) |      |         | (89,583 | ) |   |         | (99,236 | ) |   |        | (201,701 | )
|                                                          | Financing activities                                                         |                         |         | 17,303   |   |      |         | 80,749   |   |      |         | 8,610   |   |   |         | 49,107  |   |   |        | 194,972  |  
|Production:                                               |                                                                              |                         |         |          |   |      |         |          |   |      |         |         |   |   |         |         |   |   |        |         
|                                                          | Oil (Bbls)                                                                   |                         |         | 6,601    |   |      |         | 6,037    |   |      |         | 4,935   |   |   |         | 3,961   |   |   |        | 1,796    |  
|                                                          | Natural gas (Mcf)                                                            |                         |         | 9,051    |   |      |         | 8,175    |   |      |         | 8,078   |   |   |         | 4,303   |   |   |        | 180      |  
|                                                          | Combined (BOE)                                                               |                         |         | 8,110    |   |      |         | 7,399    |   |      |         | 6,281   |   |   |         | 4,678   |   |   |        | 1,826    |  
|Average Sales Price:                                      |                                                                              |                         |         |          |   |      |         |          |   |      |         |         |   |   |         |         |   |   |        |         
|                                                          | Oil ($/Bbl)                                                                  |                         | $       | 26.72    |   |      | $       | 22.34    |   |      | $       | 21.43   |   |   | $       | 23.34   |   |   | $      | 16.96    |  
|                                                          | Natural gas ($/Mcf)                                                          |                         |         | 4.83     |   |      |         | 3.16     |   |      |         | 3.73    |   |   |         | 3.84    |   |   |        | 4.50     |  
|                                                          | Combined ($/BOE)                                                             |                         |         | 27.14    |   |      |         | 21.72    |   |      |         | 21.64   |   |   |         | 23.29   |   |   |        | 17.12    |  
|Costs per BOE:                                            |                                                                              |                         |         |          |   |      |         |          |   |      |         |         |   |   |         |         |   |   |        |         
|                                                          | Lease operations                                                             |                         | $       | 4.67     |   |      | $       | 4.15     |   |      | $       | 4.00    |   |   | $       | 3.99    |   |   | $      | 4.60     |  
|                                                          | Production and severance taxes                                               |                         |         | 2.71     |   |      |         | 2.12     |   |      |         | 2.20    |   |   |         | 3.24    |   |   |        | 2.97     |  
|                                                          | General and administrative (excluding non-cash
    stock based compensation) |                         |         | 1.07     |   |      |         | 0.83     |   |      |         | 0.80    |   |   |         | 0.93    |   |   |        | 2.22     |  
|                                                          | Depletion, depreciation, and amortization                                    |                         |         | 4.13     |   |      |         | 4.67     |   |      |         | 5.05    |   |   |         | 4.72    |   |   |        | 2.89     |  
|Reserves:                                                 |                                                                              |                         |         |          |   |      |         |          |   |      |         |         |   |   |         |         |   |   |        |         
|                                                          | Oil (Bbls)                                                                   |                         |         | 117,732  |   |      |         | 111,674  |   |      |         | 91,369  |   |   |         | 78,910  |   |   |        | 69,299   |  
|                                                          | Natural gas (Mcf)                                                            |                         |         | 138,950  |   |      |         | 99,818   |   |      |         | 75,687  |   |   |         | 72,970  |   |   |        | 10,940   |  
|                                                          | Combined (BOE)                                                               |                         |         | 140,890  |   |      |         | 128,310  |   |      |         | 103,983 |   |   |         | 91,072  |   |   |        | 71,122   |  

18



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##### Table of Contents



|                                 |  |                    |         |      |  |      |         |      |  |      |         |  |  |   |         |   |  |   |         | 
|-------------------------------- |  | ------------------ | ------- | ---- |  | ---- | ------- | ---- |  | ---- | ------- |  |  | - | ------- | - |  | - | ------- | 
|                                 |  |                   
|                                 |  | As of December 31,
|                                 |  |                   
|                                 |  | 2003               |         | 2002 |  | 2001 |         | 2000 |  | 1999
|                                 |  |                    |         |      |  |      |         |      |  |     
|Consolidated Balance Sheet Data: |  |                    |         |      |  |      |         |      |  |      |         |  |  |   |         |   |  |   |         | 
|Working capital                  |  | $                  | (52     | )    |  | $    | 12,489  |      |  | $    | 1,107   |  |  | $ | (15,275 | ) |  | $ | 5,126   | 
|Total assets                     |  |                    | 672,138 |      |  |      | 549,896 |      |  |      | 402,000 |  |  |   | 343,756 |   |  |   | 215,571 | 
|Total debt                       |  |                    | 179,000 |      |  |      | 166,000 |      |  |      | 79,107  |  |  |   | 162,045 |   |  |   | 99,250  | 
|Stockholders equity             |  |                    | 358,975 |      |  |      | 296,266 |      |  |      | 269,302 |  |  |   | 147,811 |   |  |   | 102,422 | 



---



|    |                                                                                                                                                                                                                                                                                                                                                                             
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | For the years ended December 31, 2003, 2002,
    2001, 2000, and 1999 we reduced revenue for the payments of the
    net profits interests by $5.8 million, $2.0 million,
    $2.8 million, $11.5 million, and $4.4 million,
    respectively.                                                                                                                              
|   
|(2) | Net income for the year ended December 31,
    2003 includes a $0.9 million cumulative effect of
    accounting change, which affects its comparability with other
    periods presented. See pro forma amounts presented in
    Note 2. Summary of Significant Account
    Policies  New Accounting Standards to the
    accompanying consolidated financial statements.
|   
|(3) | Net income for the year ended December 31,
    2001 includes $9.6 million of non-cash compensation
    expense, $4.3 million of bad debt expense,
    $1.6 million of impairment of oil and natural gas
    properties, and a $(0.9) million cumulative effect of
    accounting change, which affects its comparability with other
    periods presented.                  
|   
|(4) | Net income for the year ended December 31,
    2000 includes $26.0 million of non-cash compensation
    expense, which affects its comparability with other periods
    presented.                                                                                                                                                                                          






|        |                                                                                          
|------- | -----------------------------------------------------------------------------------------
|Item 7. | Managements Discussion and Analysis
    of Financial Condition and Results of Operations

The following discussion and analysis of the
consolidated financial condition and results of operations of
Encore Acquisition Company should be read in conjunction with
the historical financial information provided in the
consolidated financial statements and accompanying notes, as
well as the business and properties descriptions in Items 1
and 2 of this Report.

Overview

We engage in the acquisition, development,
exploitation and production of onshore North American oil and
natural gas reserves. We remain determined to execute our
business strategy of maintaining an active low-risk development
drilling program, maximizing existing reserves and production
through high-pressure air injection projects, expanding our
reserves and production through a disciplined acquisition
program, and cost control through efficient and safe operations.

Our financial results and ability to generate
cash depend upon many factors, particularly the price of oil and
natural gas. Oil prices remained strong in 2003. The average oil
price for the NYMEX futures market was $31.04 and
$26.08 per barrel for 2003 and 2002, respectively. The
average natural gas price for the NYMEX futures market was $5.50
and $3.36 per MMBTU for 2003 and 2002, respectively.
Commodity prices are impacted by many factors that are outside
of our control. It is very difficult for us to predict future
commodity prices. For this reason, we attempt to mitigate the
effect of commodity price risk by hedging.

In 2003, we were able to expand our Mid Continent
area by acquiring a non-operated interest in natural gas
properties in North Louisiana. We are optimistic both about how
well this particular asset, Elm Grove, fits in our portfolio,
and by the possibilities of additional acquisitions in the
region. Elm Grove complements our existing asset base in many
ways. We believe it contains a solid, predictable production
base along with a large number of low risk infill drilling
opportunities that are currently being exploited.

Also in 2003, we continued to see positive
results from our initial high-pressure air injection project at
our Pennel unit of the CCA, and have approved expanding it to
other areas in the CCA. We began phase one of our second HPAI
project in Little Beaver during December 2003 and phase one and
phase two

19



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##### Table of Contents



should be completed during 2004. Our independent
reserve engineers, Miller and Lents, Ltd., booked
12.2 million barrels of proved undeveloped oil reserves
associated with high pressure air at year end 2003 related to
the Little Beaver unit project. High pressure air injection
contributed to our FD&A cost of $7.42 per BOE during
2003. For the long term, we believe that high-pressure air
injection technology can be applied throughout the Cedar Creek
Anticline.


2003 Highlights

Our financial and operating results for the year
ended December 31, 2003 included the following highlights:



| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | Oil and natural gas reserves increased 10% to
    140,890 MBOE. During 2003, we added 20.7 MMBOE at a
    FD&A cost of $7.42 per BOE, replacing 255% of the
    8.1 MMBOE produced in 2003. Including revisions, the
    development program added 14.4 MMBOE (178% of our
    production) at a cost of $6.86 per BOE. Included in our
    reserve additions are 12.5 MMBOE of high-pressure air
    volumes. The 12.5 MMBOE represents the first reserves
    related to our high-pressure air injection program in the Cedar
    Creek Anticline of Montana and North Dakota. Our three year
    FD&A costs, including revisions, are $5.60 per BOE with
    a reserve replacement ratio of 329%. Oil reserves accounted for
    84% of total proved reserves, and 78% of proved reserves are
    proved developed. Our reserve-to-production ratio is
    17 years for total proved reserves and 14 years for
    proved developed reserves.                                                                                                                                                                                                                           
|
| |  | Production volumes for the year increased 10% to
    8.1 MMBOE (22,218 BOE per day), compared with 2002
    production of 7.4 MMBOE (20,273 BOE per day). Oil
    represented 81% and 82% of our total BOE production in 2003 and
    2002, respectively. The increase in production is due to our
    continued successful development and exploitation program as
    well as the Elm Grove acquisition.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|
| |  | Net income for the full year of 2003 increased
    69% to $63.6 million, or $2.10 per diluted share, on
    revenues of $220.1 million. Net income for the year ended
    December 31, 2003 includes a $0.9 million
    ($0.03 per diluted share) cumulative effect of accounting
    change resulting from the adoption of Statement of Financial
    Accounting Standards No. 143 Accounting for Asset
    Retirement Obligations on January 1, 2003. This
    compares to full year 2002 net income of
    $37.7 million, or $1.25 per diluted share, on revenues
    of $160.7 million. For 2003, cash flow from operations
    increased 35% to $123.8 million from $91.5 million for
    2002. The increase in net income and cash flow from operations
    from 2002 was primarily a result of higher production and higher
    commodity prices throughout the year.                                                                                                                                                                                                                                                                                            
|
| |  | We improved our financial flexibility and
    liquidity by negotiating an increased borrowing base under the
    existing credit facility from $220 million to
    $270 million. At December 31, 2003, we had
    $29 million outstanding on the borrowing base and
    $241 million available for funding of future capital
    requirements.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|
| |  | We improved our ability to access capital markets
    with the filing of a $400 million universal shelf
    registration statement on Form S-3. We currently have
    $216 million availability remaining under the registration
    statement.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|
| |  | We expanded the liquidity and public ownership of
    our common stock by facilitating the sale of common stock by
    J.P. Morgan and Warburg Pincus. 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 and 2,193,357 shares from 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

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| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |   | no longer beneficially owns any of our common
    stock and Warburg Pincus beneficially owns 24.5% of our common
    stock.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|
| |  | High-pressure air injection was implemented in a
    second area on the CCA properties in the Little Beaver area. We
    were able to negotiate the purchase of high-pressure air
    compression services from an offset operator. This allowed us to
    implement a project in Little Beaver unit, on the south end of
    the Cedar Creek Anticline, in less than one year. First
    injection began in Little Beaver phase one during December 2003
    and phase one and phase two should be completed during 2004. Our
    independent reserve engineers, Miller and Lents, Ltd., booked
    12.2 million barrels of oil reserves associated with high
    pressure air at year end 2003 at Little Beaver. High pressure
    air injection contributed to our FD&A cost during 2003.

Results of Operations

Comparison of 2003 to 2002

Set forth below is our comparison of operations
during the year ended December 31, 2003 with the year ended
December 31, 2002.

Revenues and
Production.For the year ended
December 31, 2003, revenues increased $59.4 million.
The following table illustrates the primary components of oil
and natural gas revenue for the years ended December 31,
2003 and 2002, as well as each years respective oil and
natural gas volumes (dollars in thousands except per unit
amounts):

|                     |                            |                         |         |         |  |            |       |        |  |         |         |         |  |   |       |       |  |   |         |        |  |   |       |      | 
|-------------------- | -------------------------- | ----------------------- | ------- | ------- |  | ---------- | ----- | ------ |  | ------- | ------- | ------- |  | - | ----- | ----- |  | - | ------- | ------ |  | - | ----- | ---- | 
|                     |                            |                         |         |         |  |           
|                     |                            | Year Ended December 31, |         |         |  |           
|                     |                            |                         |         |         |  |           
|                     |                            |                         |         |         |  |           
|                     |                            | 2003                    |         | 2002    |  | Difference
|                     |                            |                         |         |         |  |           
|                     |                            | Revenue                 |         | $/Unit  |  | Revenue    |       | $/Unit |  | Revenue |         | $/Unit 
|                     |                            |                         |         |         |  |            |       |        |  |         |         |        
|Revenues:            |                            |                         |         |         |  |            |       |        |  |         |         |         |  |   |       |       |  |   |         |        |  |   |       |     
|Oil wellhead         |                            | $                       | 190,203 |         |  | $          | 28.82 |        |  | $       | 141,119 |         |  | $ | 23.38 |       |  | $ | 49,084  |        |  | $ | 5.44  |     
|Oil hedges           |                            |                         | (13,852 | )       |  |            | (2.10 | )      |  |         | (6,265  | )       |  |   | (1.04 | )     |  |   | (7,587  | )      |  |   | (1.06 | )   
|                     |                            |                         |         |         |  |            |       |        |  |         |         |         |  |   |       |       |  |   |         |        |  |   |       |     
|                     | Total Oil Revenues         |                         | $       | 176,351 |  |            | $     | 26.72  |  |         | $       | 134,854 |  |   | $     | 22.34 |  |   | $       | 41,497 |  |   | $     | 4.38 | 
|                     |                            |                         |         |         |  |            |       |        |  |         |         |         |  |   |       |       |  |   |         |        |  |   |       |     
|Natural gas wellhead |                            | $                       | 45,218  |         |  | $          | 5.00  |        |  | $       | 24,803  |         |  | $ | 3.03  |       |  | $ | 20,415  |        |  | $ | 1.97  |     
|Natural gas hedges   |                            |                         | (1,473  | )       |  |            | (0.17 | )      |  |         | 1,035   |         |  |   | 0.13  |       |  |   | (2,508  | )      |  |   | (0.30 | )   
|                     |                            |                         |         |         |  |            |       |        |  |         |         |         |  |   |       |       |  |   |         |        |  |   |       |     
|                     | Total Natural Gas Revenues |                         | $       | 43,745  |  |            | $     | 4.83   |  |         | $       | 25,838  |  |   | $     | 3.16  |  |   | $       | 17,907 |  |   | $     | 1.67 | 
|                     |                            |                         |         |         |  |            |       |        |  |         |         |         |  |   |       |       |  |   |         |        |  |   |       |     
|Combined wellhead    |                            | $                       | 235,421 |         |  | $          | 29.03 |        |  | $       | 165,922 |         |  | $ | 22.42 |       |  | $ | 69,499  |        |  | $ | 6.61  |     
|Combined hedges      |                            |                         | (15,325 | )       |  |            | (1.89 | )      |  |         | (5,230  | )       |  |   | (0.70 | )     |  |   | (10,095 | )      |  |   | (1.19 | )   
|                     |                            |                         |         |         |  |            |       |        |  |         |         |         |  |   |       |       |  |   |         |        |  |   |       |     
|                     | Total Combined Revenues    |                         | $       | 220,096 |  |            | $     | 27.14  |  |         | $       | 160,692 |  |   | $     | 21.72 |  |   | $       | 59,404 |  |   | $     | 5.42 | 
|                     |                            |                         |         |         |  |            |       |        |  |         |         |         |  |   |       |       |  |   |         |        |  |   |       |     

|                   |  |            |       |         |  |            |       |         |  |            |       |         |  |   |       |  |  |  |     |  |  |   |      | 
|------------------ |  | ---------- | ----- | ------- |  | ---------- | ----- | ------- |  | ---------- | ----- | ------- |  | - | ----- |  |  |  | --- |  |  | - | ---- | 
|                   |  |            |       | Average |  |            |       | Average |  |            |       | Average
|                   |  |            |       | NYMEX   |  |            |       | NYMEX   |  |            |       | NYMEX  
|                   |  | Production |       | $/Unit  |  | Production |       | $/Unit  |  | Production |       | $/Unit 
|                   |  |            |       |         |  |            |       |         |  |            |       |        
|Other data:        |  |            |       |         |  |            |       |         |  |            |       |         |  |   |       |  |  |  |     |  |  |   |      | 
|Oil (MBbls)        |  |            | 6,601 |         |  | $          | 31.04 |         |  |            | 6,037 |         |  | $ | 26.08 |  |  |  | 564 |  |  | $ | 4.96 | 
|Natural Gas (MMcf) |  |            | 9,051 |         |  |            | 5.50  |         |  |            | 8,175 |         |  |   | 3.36  |  |  |  | 876 |  |  |   | 2.14 | 
|Combined (MBOE)    |  |            | 8,110 |         |  |            |       |         |  |            | 7,399 |         |  |   |       |  |  |  | 711 |  |  |   |      | 

Oil revenues increased $41.5 million in 2003
over 2002 as production increased 564 MBbls and our average
realized price increased $4.38 per Bbl. The increase in
production resulted from our successful development drilling
program and uplift from the HPAI program. Oil revenues were
reduced by $13.9 million in 2003 due to our hedging
program. The hedging per Bbl reduction to our wellhead oil price
of $2.10 represented a $1.06 per Bbl greater reduction than
in 2002. This compares favorably with the

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$4.96 increase in the average NYMEX price from
2002 to 2003 as we were able to realize additional upside due to
a higher average ceiling on our 2003 hedges compared to NYMEX
than in 2002. In addition, our oil wellhead revenue was reduced
by $5.6 million and $2.0 million in 2003 and 2002,
respectively, for the net profits interests payments made to
others related to our CCA properties.


Natural gas revenues increased in 2003 by
$17.9 million due to a 65% increase in the net wellhead
price received along with increased production of 876 MMcf.
The increase in net wellhead price received of $1.97 per
Mcf resulted as the average NYMEX price increased $2.14 per
Mcf over the same period. The natural gas production increase
resulted from the Elm Grove acquisition during 2003. Averaging
7,984 Mcfe per day since its acquisition on July 31,
2003, the Elm Grove properties added 3,345 Mcfe per day to
our average daily production for the full year.

For 2004, we anticipate increased production
related to our budgeted $93 million capital drilling
program and $34 million in HPAI projects. We also have an
additional $13 million budgeted for leasehold and other
general capital expenditures. The total capital budget for 2004
is $140 million.

Prices received for oil and natural gas
production are largely based on current market prices, which are
beyond our control. We have based our 2004 forecasts on the
assumptions of $23.50 per Bbl and $3.75 per Mcf NYMEX
prices. For comparability and accountability, we take a constant
approach to budgeting commodity prices. We presently analyze our
inventory of capital projects on $23.50 per Bbl and
$3.75 per Mcf NYMEX prices to ensure a good rate of return
to our shareholders without the benefit of escalating future
commodity prices. If NYMEX prices trend downward below our base
deck, we may reevaluate our capital projects. At these assumed
prices, we have forecasted net hedge contract payments of
approximately $0.9 million for oil and net receipts of
$4.5 million for natural gas. However, these amounts will
change directly with any change in the market price of oil and
natural gas and with any change in our outstanding hedge
positions. Additionally, we have anticipated net profits
interests payments of $1.7 million for oil and
$0.03 million for natural gas. These payments are highly
dependent on the level of drilling in the CCA and commodity
prices, and thus, any change in the level of drilling or market
fluctuation in commodity prices will have a direct impact on the
amount of payments we are required to make. If commodity prices
are significantly lower than our forecasted prices of $23.50 for
oil and $3.75 for natural gas, we will not have sufficient
internally generated cash flow to fund the budgeted
$93 million drilling program, $34 million in HPAI
projects, and $13 million leasehold and other capital for
2004. In this case, we would have to borrow money under our
existing revolving credit facility, seek capital markets, or
curtail the capital program. If drilling is curtailed or ended,
future cash flows could be materially negatively impacted.

Lease Operations
Expense.Lease operations expense for
the year ended December 31, 2003 increased by
$7.2 million as compared to 2002. The increase in total
lease operations expense resulted from the increase in volumes
as a result of our 2003 drilling program, the Elm Grove
acquisition and HPAI program. See  Revenues and
Production above. On a per BOE basis, lease operations
expense increased $0.52 primarily due to (1) full year
results of our Paradox Basin properties, which had higher
average per BOE lease operations expense of $9.04 for 2003
compared to our average of $4.67 per BOE, (2) the HPAI
project on the CCA properties, and (3) lower production
volumes from our Lodgepole properties, which have low operating
costs.

For 2004, we anticipate an increase in total
lease operations expense, as well as on a per BOE basis. We
anticipate this increase due to a full year of production at our
North Louisiana properties, as well as further implementation of
the high-pressure air injection program. Also, the continued
production decline of our Lodgepole properties, which have low
per BOE operating costs, will continue to raise our lease
operations expense on a per BOE basis. We have projected total
lease operations expenses of approximately $46.5 million,
or $5.56 per BOE, for 2004.

Production, Ad Valorem, and Severance
Taxes.Production, ad valorem, and
severance taxes for the year ended December 31, 2003
increased as compared to 2002 by approximately
$6.4 million. The increase is a direct result of the
increase in wellhead revenue. See  Revenues and
Production above. As a

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percentage of oil and natural gas revenues
(excluding the effects of net profits and hedges), production,
ad valorem, and severance taxes increased slightly from 9.3% to
9.4% from 2002 to 2003.


For 2004, total production, ad valorem, and
severance taxes will depend in a large part on prevailing oil
and natural gas prices. However, the production, ad valorem, and
severance tax rate should remain relatively constant at an
estimated 9.1% of wellhead revenues. However, if NYMEX prices
continue to stay above $30 per barrel, we will temporarily
lose production and severance tax incentives in Montana and
North Dakota, which would cause our tax rates to increase in
2004.

Depletion, Depreciation, and Amortization
(DD&A) Expense.Despite an increase in production, DD&A expense decreased by
approximately $1.0 million in 2003. This decrease was due
to the adoption of SFAS 143 on January 1, 2003, which
resulted in a lower per BOE rate. As a result of the adoption of
SFAS 143, we can no longer assume proceeds received for the
salvage value of our equipment will offset plugging and
abandonment costs, and thus are now required to deduct salvage
value from the book value of equipment in calculating our
depreciable base. This was the primary driver of the decrease in
the average DD&A rate from $4.67 per BOE of production
during 2002 to $4.13 per BOE in 2003.

We anticipate the total DD&A expense in 2004
will increase due to increased production resulting from the Elm
Grove acquisition and our planned 2004 capital expenditures of
$140 million. Assuming capital expenditures do not differ
significantly from our budgeted amount, we expect our DD&A
rate for 2004 to be approximately $4.60 per BOE. This per
BOE increase from 2003 is primarily attributable to higher than
historical FD&A costs for 2003. This rate could vary
significantly based on actual capital expenditures, production
rates, net profits interests, and any acquisition that closes in
2004. Additionally, changes in the market price for oil and
natural gas could affect the level of our reserves. As the level
of reserves change, the DD&A rate is inversely affected.

General and Administrative
(G&A) Expense.G&A
expense increased $2.5 million ($0.24 per BOE) to
$8.7 million in 2003 (excluding non-cash stock based
compensation of $0.6 million in 2003). The increase in
G&A expense was a result of increased staffing levels used
to manage our growing asset base and outside consulting services
used in the evaluation of potential acquisitions.

We have forecast approximately $9.8 million
for general and administrative expenses in 2004. This represents
an increase of approximately $1.1 million from 2003. The
increase is expected to result from the continued implementation
of the HPAI projects, increased staffing, additional expenses
related to compliance with the Sarbanes-Oxley Act of 2002 and
the changes in listing requirements of The New York Stock
Exchange.

Non-Cash Stock Based Compensation
Expense.Non-cash stock based
compensation expense increased from zero in 2002 to
$0.6 million in 2003. This expense represents the
amortization of deferred compensation, recorded in equity
related to restricted stock granted under the 2000 Incentive
Stock Plan. This amount is being amortized to expense over the
vesting period of the restricted stock.

During 2002 and 2003, we issued 129,328 and
45,461 shares, respectively, of restricted stock to
employees. Of these, 77,901 shares issued in 2002 and
45,461 shares issued in 2003 vest in equal installments on
the third, fourth, and fifth anniversary of the date of the
grant and depend only on continued employment for future
issuance. These represent a fixed award per APB 25 and
compensation expense will be recorded over the related service
period. Of the remaining 51,427 shares issued in 2002,
34,464 remain outstanding at December 31, 2003. These were
issued to two members of senior management and also vest in
equal installments on the third, fourth, and fifth anniversary
of the date of the grant. However, these shares not only depend
on the passage of time and continued employment, but on certain
performance measures for their future issuance. These represent
a variable award under APB 25 and, thus, the full amount of
compensation expense to be recorded for these shares will not be
known until their eventual issuance.

Other Operating
Expense.Other operating expense for
the year ended December 31, 2003 increased as compared to
2002 by approximately $1.4 million. This amount primarily
consists of 2003 severance payment obligations to former
employees. The remaining amount relates to the inclusion of
accretion

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expense on our SFAS 143 future abandonment
liability; and the abandonment in undeveloped leasehold costs.


For 2004, we anticipate other operating expense
to be approximately $2.9 million.

Interest Expense.Interest expense for the year ended December 31, 2003
increased $3.8 million over 2002 due primarily to an
increase in our weighted average interest rate from period to
period, as well as an increase in debt outstanding related to
our credit facility. We incurred additional debt in 2003 to fund
the North Louisiana acquisition. The weighted average interest
rate, net of hedges, for 2003 was 9.6% compared to 8.2% for
2002. This higher weighted average interest rate is the result
of the issuance of $150 million aggregate principal amount
of 8 3/8% senior subordinated notes in June 2002,
which was the primary component of our total indebtedness during
2003, while the revolving credit facility with a lower floating
rate was the primary component during the first half of 2002. In
conjunction with the issuance of 8 3/8% notes in June
2002, we entered into an interest rate swap, which swaps fixed
rates to floating, with the intent of lowering our effective
interest payments. As this transaction does not qualify for
hedge accounting, changes in its fair market value, as well as
settlements, are not recorded in interest expense, but in
Derivative fair value (gain) loss on the
Consolidated Statements of Operations. During 2003, a gain of
$1.5 million related to this interest rate swap was
recorded in Derivative fair value (gain) loss. See
Note 11 to the accompanying consolidated financial
statements.

The following table illustrates the components of
interest expense for 2003 and 2002 (in thousands):

|                                 |       |      |        |        |  |            |       |        |  |   |        |       | 
|-------------------------------- | ----- | ---- | ------ | ------ |  | ---------- | ----- | ------ |  | - | ------ | ----- | 
|                                 |       | 2003 |        | 2002   |  | Difference
|                                 |       |      |        |        |  |           
|8 3/8% senior subordinated notes |       | $    | 12,563 |        |  | $          | 6,488 |        |  | $ | 6,075  |      
|Revolving credit facility        |       |      | 453    |        |  |            | 2,260 |        |  |   | (1,807 | )    
|Hedge settlements                |       |      |       |        |  |            | 1,249 |        |  |   | (1,249 | )    
|Hedge loss amortization          |       |      | 1,910  |        |  |            | 1,619 |        |  |   | 291    |      
|Debt issuance cost amortization  |       |      | 714    |        |  |            | 314   |        |  |   | 400    |      
|Fees and other                   |       |      | 511    |        |  |            | 376   |        |  |   | 135    |      
|                                 |       |      |        |        |  |            |       |        |  |   |        |      
|                                 | Total |      | $      | 16,151 |  |            | $     | 12,306 |  |   | $      | 3,845 | 
|                                 |       |      |        |        |  |            |       |        |  |   |        |      

Derivative Fair Value
Gain/Loss.The derivative fair value
gain of $0.9 million in 2003 represents the ineffective
portion of the mark-to-market loss on our derivative hedging
instruments, settlements received on our fixed to floating
interest rate swap, any commodity derivatives not designated as
hedges, and changes in the mark-to-market value of our fixed to
floating interest rate swap.

Currently, this line item on the Statement of
Operations is primarily dependent on the futures price of oil,
natural gas and LIBOR interest rates. This is due to the fact
that the main components are the mark-to-market movement of and
any settlements on our commodity derivative contracts not
designated as hedges and our fixed to floating interest rate
swap.

Income Tax Expense.Income tax expense for 2003 increased $13.5 million over
2002. This increase is due primarily to the $38.6 million
increase in Income before Income Taxes from 2002 to 2003. Our
effective income tax rate, prior to adjusting for
Section 43 credits, remained at a constant 38% for both
2002 and 2003. However, during 2003, we generated
$2.1 million in Section 43 credits, as compared to
$1.1 million of Section 43 credits generated in 2002.
This increase resulted in an effective income tax rate of 36.5%
in 2003, a decrease of 1% from our 2002 effective rate
of 37.5%.

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Comparison of 2002 to 2001

Set forth below is our comparison of operations
during the year ended December 31, 2002 with the year ended
December 31, 2001.

Revenues and
Production.For the year ended
December 31, 2002, revenues increased $24.8 million.
The following table illustrates the primary components of oil
and natural gas revenue for the years ended December 31,
2002 and 2001, as well as each years respective oil and
natural gas volumes (dollars in thousands except per unit
amounts):

|                     |                            |                         |         |         |  |            |       |        |  |         |         |         |  |   |       |       |  |   |        |        |   |   |       |       |  
|-------------------- | -------------------------- | ----------------------- | ------- | ------- |  | ---------- | ----- | ------ |  | ------- | ------- | ------- |  | - | ----- | ----- |  | - | ------ | ------ | - | - | ----- | ----- | -
|                     |                            |                         |         |         |  |           
|                     |                            | Year Ended December 31, |         |         |  |           
|                     |                            |                         |         |         |  |           
|                     |                            |                         |         |         |  |           
|                     |                            | 2002                    |         | 2001    |  | Difference
|                     |                            |                         |         |         |  |           
|                     |                            | Revenue                 |         | $/Unit  |  | Revenue    |       | $/Unit |  | Revenue |         | $/Unit 
|                     |                            |                         |         |         |  |            |       |        |  |         |         |        
|Revenues:            |                            |                         |         |         |  |            |       |        |  |         |         |         |  |   |       |       |  |   |        |        |   |   |       |      
|Oil wellhead         |                            | $                       | 141,119 |         |  | $          | 23.38 |        |  | $       | 114,723 |         |  | $ | 23.25 |       |  | $ | 26,396 |        |   | $ | 0.13  |      
|Oil hedges           |                            |                         | (6,265  | )       |  |            | (1.04 | )      |  |         | (8,955  | )       |  |   | (1.82 | )     |  |   | 2,690  |        |   |   | 0.78  |      
|                     |                            |                         |         |         |  |            |       |        |  |         |         |         |  |   |       |       |  |   |        |        |   |   |       |      
|                     | Total Oil Revenues         |                         | $       | 134,854 |  |            | $     | 22.34  |  |         | $       | 105,768 |  |   | $     | 21.43 |  |   | $      | 29,086 |   |   | $     | 0.91  |  
|                     |                            |                         |         |         |  |            |       |        |  |         |         |         |  |   |       |       |  |   |        |        |   |   |       |      
|Natural gas wellhead |                            | $                       | 24,803  |         |  | $          | 3.03  |        |  | $       | 34,014  |         |  | $ | 4.21  |       |  | $ | (9,211 | )      |   | $ | (1.18 | )    
|Natural gas hedges   |                            |                         | 1,035   |         |  |            | 0.13  |        |  |         | (3,865  | )       |  |   | (0.48 | )     |  |   | 4,900  |        |   |   | 0.61  |      
|                     |                            |                         |         |         |  |            |       |        |  |         |         |         |  |   |       |       |  |   |        |        |   |   |       |      
|                     | Total Natural Gas Revenues |                         | $       | 25,838  |  |            | $     | 3.16   |  |         | $       | 30,149  |  |   | $     | 3.73  |  |   | $      | (4,311 | ) |   | $     | (0.57 | )
|                     |                            |                         |         |         |  |            |       |        |  |         |         |         |  |   |       |       |  |   |        |        |   |   |       |      

|                |  |            |       |         |  |            |       |         |  |            |       |         |  |   |       |  |  |  |       |  |  |   |       |  
|--------------- |  | ---------- | ----- | ------- |  | ---------- | ----- | ------- |  | ---------- | ----- | ------- |  | - | ----- |  |  |  | ----- |  |  | - | ----- | -
|                |  |            |       | Average |  |            |       | Average |  |            |       | Average
|                |  |            |       | NYMEX   |  |            |       | NYMEX   |  |            |       | NYMEX  
|                |  | Production |       | $/Unit  |  | Production |       | $/Unit  |  | Production |       | $/Unit 
|                |  |            |       |         |  |            |       |         |  |            |       |        
|Other data:     |  |            |       |         |  |            |       |         |  |            |       |         |  |   |       |  |  |  |       |  |  |   |       |  
|Oil (MBbls)     |  |            | 6,037 |         |  | $          | 26.08 |         |  |            | 4,935 |         |  | $ | 25.92 |  |  |  | 1,102 |  |  | $ | 0.16  |  
|Gas (MMcf)      |  |            | 8,175 |         |  |            | 3.36  |         |  |            | 8,078 |         |  |   | 4.06  |  |  |  | 97    |  |  |   | (0.70 | )
|Combined (MBOE) |  |            | 7,399 |         |  |            |       |         |  |            | 6,281 |         |  |   |       |  |  |  | 1,118 |  |  |   |       |  

Oil revenues increased $29.1 million in 2002
over 2001 primarily due to an increase in oil volumes, while the
net wellhead price received remained relatively flat. Oil
volumes increased 1,102 MBbls from 2001 to 2002 due to the
Central Permian and Paradox Basin acquisitions, as well as
increased production from our successful development drilling
program. Wellhead oil revenues were reduced by $2.0 million
and $2.7 million in 2002 and 2001, respectively, for the
net profits interests payments held by others in the CCA. Total
oil revenues were further increased by a decrease in hedge
payments, which were $2.7 million lower.

Natural gas revenues decreased in 2002 by
$4.3 million due to a 28% decrease in the net wellhead
price received, from $4.21 in 2001 to $3.03 in 2002, with
essentially flat production. This price decline is consistent
with the NYMEX decline from $4.06 to $3.36 over the same period.
We recovered a portion of the natural gas price decline through
our hedges, which generated net receipts of $1.0 million in
2002 versus net payments of $3.9 million in 2001. These
hedging receipts are a direct result of the decrease in the
average NYMEX price for natural gas.

Lease Operations
Expense.Lease operations expense for
the year ended December 31, 2002 increased as compared to
2001 by $5.5 million. The increase in lease operations
expenses resulted from the increase in volumes as a result of
our 2002 Central Permian and Paradox Basin acquisitions and our
successful drilling program. See  Revenues and
Production above. On a per BOE basis, lease operations
expenses increased from $4.00 in 2001 to $4.15 in 2002 primarily
due to higher per BOE lifting costs for our 2002 acquisitions.

Production, Ad Valorem, and Severance
Taxes.Production, ad valorem, and
severance taxes for the year ended December 31, 2002
increased as compared to 2001 by approximately
$1.8 million. The increase is a direct result of the
increase in wellhead revenue. See  Revenues and
Production above. As a

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percentage of oil and natural gas revenues
(excluding the effects of net profits and hedges), production,
ad valorem, and severance taxes increased slightly from 9.1% to
9.3% from 2001 to 2002.


Depletion, Depreciation, and Amortization
(DD&A) Expense.DD&A expense increased by approximately $2.8 million in
2002. This increase was due to a 1.1 MMBOE increase in
production volumes, partially offset by a decrease in the
DD&A rate per BOE. See  Revenues and
Production above. The average DD&A rate decreased from
$5.05 per BOE of production during 2001 to $4.67 per
BOE in 2002. The increase in volumes caused a $5.6 million
increase in related DD&A expense, while the decrease in the
DD&A rate caused a $2.8 million decrease. The decrease
is attributable to upward reserve revisions due to higher prices.

General and Administrative
(G&A) Expense.G&A
expense increased $1.1 million in 2002 (excluding non-cash
stock based compensation of $9.6 million in 2001). The
increase in G&A resulted from the additional staff necessary
after the Permian and Paradox Basin acquisitions to manage,
expand, and exploit our growing asset base. On a per BOE basis,
G&A expense remained relatively flat at $0.83 during 2002 as
compared to $0.80 during 2001.

Other Operating
Expense.Other operating expense for
the year ended December 31, 2002 increased as compared to
2001 by approximately $1.1 million. This amount primarily
consists of 2001 severance payment obligations to former
employees, as well as transportation costs, namely pipeline fees
paid to third parties, geological and geophysical expenses, and
delay rentals. The increase is due to higher transportation
costs and geological and geophysical expenses in 2002, which
more than offset the lack of severance payments in 2002.

Interest Expense.Interest expense for the year ended December 31, 2002
increased $6.3 million over 2001. The increase in interest
expense is primarily due to increased levels of debt,
amortization of hedge loss (see below), and a higher weighted
average interest rate in 2002 as compared to 2001. On
June 25, 2002, we issued $150.0 million in
8 3/8% senior subordinated notes, and used most of the
proceeds to repay all amounts outstanding under the previous
credit facility and entered into a new revolving credit
facility. See  Capital Commitments, Capital
Resources and Liquidity on page 31. For 2002, the
weighted average debt balance was $149.7 million, compared
with $89.3 million for 2001. Additionally, the weighted
average interest rate, including hedges, in 2002 was 8.2%, while
it was 6.8% in 2001. The higher weighted average interest rate
is due to a higher fixed rate on the 8 3/8% notes as
compared to the floating rate debt outstanding previously.

At the time the previous credit facility was
terminated, we had three interest rate swaps outstanding, with a
notional amount of $30.0 million each, which swapped
LIBOR-based floating rates for fixed rates. According to the
provisions of SFAS 133, these no longer qualified for hedge
accounting. The unrealized loss of $3.8 million at
June 25, 2002, which was recognized in accumulated other
comprehensive income, is being amortized to interest expense
over the original life of the swaps. We amortized
$1.6 million of this loss to interest expense during 2002.

The following table illustrates the components of
interest expense for 2002 and 2001 (in thousands):

|                                 |       |      |       |        |  |            |       |       |  |   |        |       | 
|-------------------------------- | ----- | ---- | ----- | ------ |  | ---------- | ----- | ----- |  | - | ------ | ----- | 
|                                 |       | 2002 |       | 2001   |  | Difference
|                                 |       |      |       |        |  |           
|8 3/8% senior subordinated notes |       | $    | 6,488 |        |  | $          |      |       |  | $ | 6,488  |      
|Revolving credit facility        |       |      | 2,260 |        |  |            | 4,596 |       |  |   | (2,336 | )    
|Burlington note                  |       |      |      |        |  |            | 389   |       |  |   | (389   | )    
|Hedge settlements                |       |      | 1,249 |        |  |            | 717   |       |  |   | 532    |      
|Hedge loss amortization          |       |      | 1,619 |        |  |            |      |       |  |   | 1,619  |      
|Debt issuance cost               |       |      | 314   |        |  |            | 120   |       |  |   | 194    |      
|Fees and other                   |       |      | 376   |        |  |            | 219   |       |  |   | 157    |      
|                                 |       |      |       |        |  |            |       |       |  |   |        |      
|                                 | Total |      | $     | 12,306 |  |            | $     | 6,041 |  |   | $      | 6,265 | 
|                                 |       |      |       |        |  |            |       |       |  |   |        |      

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Non-Cash Stock Based Compensation
Expense.Non-cash stock based
compensation expense decreased from $9.6 million for 2001
to zero in 2002. This non-cash stock based compensation expense
is associated with the purchase by our management stockholders
of Class A common stock under our management stock plan
adopted in August 1998 and was recorded as compensation in
accordance with variable plan accounting under Accounting
Principles Board Opinion No. 25, Accounting for Stock
Issued to Employees (APB 25). The
$9.6 million of non-cash compensation expense recorded in
the first quarter of 2001 represents the final amount of expense
to be recorded related to the Class A common stock.

Derivative Fair Value
Gain/Loss.The derivative fair value
gain of $0.9 million in 2002 represents the ineffective
portion of the mark-to-market loss on our derivative hedging
instruments, as well as the mark-to-market loss on our two short
puts outstanding at December 31, 2002 and our interest rate
swap settlements subsequent to the issuance of the senior
subordinated notes on June 25, 2002.

Bad Debt Expense.On
December 2, 2001, Enron Corp. and certain subsidiaries,
including Enron North America Corp. (Enron), each
filed voluntary petitions for relief under Chapter 11 of
Title 11 of the United States Bankruptcy Code. Prior to
this date, we had entered into oil and natural gas hedging
contracts with Enron, many of which were set to expire at
December 31, 2001; however, others related to 2002 and
2003. As a result of the Chapter 11 bankruptcy declaration
and pursuant to the terms of our contract with Enron, we
terminated all outstanding oil and natural gas derivative
contracts with Enron as of December 12, 2001. According to
the terms of the contract, Enron is liable to us for the
mark-to-market value of all contracts outstanding on that date,
which totaled $6.6 million. Additionally, Enron failed to
make timely payment of $0.4 million in 2001 hedge
settlements. Both of these amounts remained outstanding as of
December 31, 2001. Due to the uncertainty of future
collection of any or all of the amounts owed to us by Enron, for
the year ended December 31, 2001, we have recorded a charge
to bad debt expense for the full amount of the receivable,
$7.0 million, and recorded a related allowance on the
receivable of $7.0 million.

At the time of termination, the market price of
our commodity contracts with Enron exceeded their amortized cost
on our balance sheet, giving rise to a gain. In accordance with
the provisions of SFAS 133, this gain was recorded in other
comprehensive income until such time as the original hedged
production affected income. As a result, at December 31,
2001, we had $4.8 million in gross unrecognized gains in
other comprehensive income that were reversed into earnings
during 2002 and 2003. The following table illustrates the
amortization of this amount to revenue (in thousands):

|       |  |     |       |     |  |       |       |  |  |   |       | 
|------ |  | --- | ----- | --- |  | ----- | ----- |  |  | - | ----- | 
|Period |  | Oil |       | Gas |  | Total
|       |  |     |       |     |  |      
|2002   |  | $   | 2,822 |     |  | $     | 1,594 |  |  | $ | 4,416 | 
|2003   |  |     | 401   |     |  |       | 18    |  |  |   | 419   | 
|       |  |     |       |     |  |       |       |  |  |   |       | 
|Total  |  | $   | 3,223 |     |  | $     | 1,612 |  |  | $ | 4,835 | 
|       |  |     |       |     |  |       |       |  |  |   |       | 

Impairment of Oil and Natural Gas
Properties.Throughout 2001, futures
prices for oil and natural gas continued to decline from their
December 31, 2000 levels. The SEC price case used for our
2000 reserve estimate was $26.80 per Bbl and $9.77 per
Mcf dropping to $19.84 per Bbl and $2.57 per Mcf for
the 2001 estimate. Although the SEC price case does not
necessarily coincide with managements estimates of future
prices, this indicated the need to assess our oil and natural
gas properties for any possible impairment. Thus, we compared
the undiscounted future cash flows for each of our oil and
natural gas properties to their net book value, which indicated
the need for an impairment charge on certain properties. We then
compared the net book value of the impaired assets to their
estimated fair value, which resulted in a write-down of the
value of proved oil and natural gas properties of
$2.6 million. Fair value was determined using estimates of
future production volumes and estimates of future prices we
might receive for these volumes discounted back to a present
value using a rate commensurate with the risks inherent in the
industry.

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We performed a similar review at
December 31, 2002 and determined no impairment charge was
necessary.

Description of Critical Accounting
Estimates



| |                                   
| | ----------------------------------
| | Oil and Natural Gas
    Properties

Successful Efforts
Method.We utilize the successful
efforts method of accounting for our oil and natural gas
properties as opposed to the full cost method. In general, we
believe that the successful efforts method of accounting for oil
and natural gas would not result in materially different
operating results as we do not currently maintain an active
exploratory drilling program. Under the successful efforts
method, all development and acquisition costs of proved
properties are capitalized and amortized on a unit-of-production
basis over the remaining life of proved developed reserves or
proved reserves, as applicable. Exploration expenses, including
geological and geophysical expenses and delay rentals, are
charged to expense as incurred. Costs of drilling exploratory
wells are initially capitalized, but charged to expense if and
when the well is determined to be unsuccessful. To date, our
exploration efforts have been minimal. Expenditures for repairs
and maintenance to sustain or increase production from the
existing producing reservoir are charged to expense as incurred.
Expenditures to recomplete a current well in a different or
additional proven or unproven reservoir are capitalized pending
determination that economic reserves have been added. If the
recompletion is not successful, the expenditures are charged to
expense. Expenditures for redrilling or directional drilling in
a previously abandoned well are classified as drilling costs to
a proven or unproven reservoir for determination of capital or
expense. Significant tangible equipment added or replaced is
capitalized. Expenditures to construct facilities or increase
the productive capacity from existing reserves are capitalized.
Internal costs directly associated with the development and
exploitation of properties are capitalized as a cost of the
property and are classified accordingly in our consolidated
financial statements.

Oil and Natural Gas
Reserves.Assumptions used by the
independent reserve engineers in calculating reserves or
regarding the future cash flows or fair value of our properties
are subject to change in the future. Future prices received for
production and future production costs may vary, perhaps
significantly, from the prices and costs assumed for purposes of
calculating reserve estimates. We may not be able to develop
proved reserves within the periods estimated. Furthermore,
prices and costs will not remain constant. Actual production may
not equal the estimated amounts used in the preparation of
reserve projections. As these estimates change, the amount of
calculated reserves change. Any change in reserves directly
impacts our estimate of future cash flows from the property, as
well as the propertys fair value.

Impairment.Impairments of proved oil and natural gas properties are
directly affected by our reserve estimates. We are required to
assess the need for an impairment of capitalized costs of oil
and natural gas properties and other long-lived assets whenever
events or circumstances indicate that the carrying value of
those assets may not be recoverable. If impairment is indicated
based on a comparison of the assets carrying value to its
undiscounted expected future net cash flows, then it is
recognized to the extent that the carrying value exceeds fair
value. Each part of this calculation is subject to a large
degree of management judgment, including the determination of
propertys reserves, amount and timing of future cash
flows, and fair value.

Depletion, Depreciation, and Amortization
(DD&A).DD&A
expense is directly affected by our reserve estimates. Any
change in reserves directly impacts the amount of DD&A
expense that we recognize in a given period. Assuming no other
changes, such as an increase in depreciable base, as our
reserves increase, the amount of DD&A expense in a given
period decreases and vice versa. Changes in future commodity
prices would likely result in increases or decreases in
estimated recoverable reserves. Additionally, the
Miller & Lents, Ltd., our independent reserve engineers
estimate our reserves once a year at December 31.

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| |                      
| | ---------------------
| | Net Profits Interests

A major portion of our acreage position in the
Cedar Creek Anticline is subject to net profits interests
(NPI) ranging from 1% to 50%. The holders of these
net profits interests are entitled to receive a fixed percentage
of the cash flow remaining after specified costs have been
deducted from net revenues. The net profits calculations are
contractually defined, but in general, net profits are
determined after considering operating expense, overhead
expense, interest expense, and drilling costs. The amounts of
reserves and production calculated to be attributable to these
net profits interests are deducted from our reserves and
production data, and our revenues are reported net of NPI
payments. The reserves and production that are attributed to the
NPIs are calculated by dividing estimated future NPI payments
(in the case of reserves) or prior period actual NPI payments
(in the case of production) by the commodity prices current at
the determination date. Fluctuations in commodity prices and the
levels of development activities in the CCA from period to
period will impact the reserves and production attributed to the
NPIs and will have an inverse effect on our reported reserves
and production. Based largely on higher commodity prices, we
expect the net profit interest to be higher in the year 2004 and
possibly beyond, which directly impacts our revenues,
production, reserves, and earnings.



| |                    
| | -------------------
| | Revenue Recognition

Revenues are recognized for our share of jointly
owned properties as oil and natural gas is produced and sold,
net of royalties and net profits interest payments. Natural gas
revenues are also reduced by any processing and other fees paid
except for transportation costs paid to third parties which are
recorded as expense. Revenues are recorded using the sales
method of accounting whereby revenue is recognized as natural
gas is sold by us rather than as our working interest share of
production. Royalties, net profits interests, and severance
taxes are paid based upon the actual price received from the
sales. To the extent actual quantities and values of oil and
natural gas are unavailable for a given reporting period because
of timing or information not received from third parties, we
estimate and record the expected sales volumes and values for
those properties. We also do not recognize revenue for the
production in tanks or pipelines that has not been delivered to
the purchaser yet. Our net oil inventories in pipelines were
46,622 Bbls and 104,954 Bbls at December 31, 2003
and 2002, respectively. Natural gas imbalances under-delivered
to us at December 31, 2003 and December 31, 2002, were
446,000 MMBTU and 510,000 MMBTU, respectively.



| |             
| | ------------
| | Income Taxes

Section 43
Credits.Section 43 of the
Internal Revenue Code (Code) allows a
15 percent tax credit for certain enhanced oil recovery
project costs incurred in the United States. We believe project
costs incurred related to our HPAI tertiary recovery project on
the CCA qualify under the provisions of the Code and, therefore,
we have reduced income tax expense by 15 percent of project
costs incurred to date. The tax basis for the properties (and
related intangible drilling cost deductions and future
depreciation deductions) is reduced by the amount of the
enhanced oil recovery tax credit. In order to qualify for the
credits a project must meet all of the following requirements:



| |                                                                                                                                                                                                                                                      
| | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | 1. The project involves the application of
    one or more qualified tertiary recovery methods that is
    reasonably expected to result in more than an insignificant
    increase in the amount of crude oil that ultimately will be
    recovered;
|
| | 2. The project is located within the United
    States;                                                                                                                                                                                              
|
| | 3. The first injection of liquids, gases, or
    other matter for the project occurs after December 31,
    1990; and                                                                                                                                
|
| | 4. The project is certified by a petroleum
    engineer.                                                                                                                                                                                             

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According to the Code, the costs that will
qualify for the credit when paid or incurred in connection with
a qualifying enhanced oil recovery project include:



| |                                                                                                                                                                                                      
| | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | 1.Tangible Property. Any amount paid
    for tangible property that is an integral part of a qualified
    enhanced oil recovery project, and with respect to which
    depreciation is allowable.   
|
| | 2.Intangible Drilling and Development
    Costs. Intangible drilling cost with respect to which the
    taxpayer may make an intangible drilling costs deduction
    election under Code Sec. 263(c).
|
| | 3.Qualified Tertiary Injectant
    Expenses. Any qualified tertiary injectant expenses for
    which a deduction is allowable under any Code section.                                                

If our federal income tax returns are reviewed by
the Internal Revenue Service (the IRS), the IRS
could disagree with our decision and disallow a portion of the
credit. While we believe our HPAI project qualifies for the tax
credit and that our accounting and tracking of the costs related
to project are accurate, should the IRS disagree with our
position, we would be required to record additional income tax
expense to the extent tax credits have been previously
recognized.



| |                         
| | ------------------------
| | Stock-based Compensation

Employee stock options and restricted stock
awards are accounted for under the provisions of Accounting
Principles Board Opinion No. 25 (APB 25),
Accounting for Stock Issued to Employees.
Accordingly, no compensation is recorded for stock options that
are granted to employees or non-employee directors with an
exercise price equal to or above the common stock price on the
grant date. If compensation expense for the stock based awards
had been determined using the provisions of SFAS 123, our
net income and net income per share would have been adjusted to
the pro forma amounts indicated below (in thousands, except per
share amounts):

|             |                                                      |                         |   |        |  |      |   |        |  |  |   |        | 
|------------ | ---------------------------------------------------- | ----------------------- | - | ------ |  | ---- | - | ------ |  |  | - | ------ | 
|             |                                                      |                        
|             |                                                      | Year Ended December 31,
|             |                                                      |                        
|             |                                                      |                         |   |       
|             |                                                      | 2003                    |   | 2002   |  | 2001
|             |                                                      |                         |   |        |  |     
|As Reported: |                                                      |                         |   |        |  |      |   |        |  |  |   |       
|             | Net income                                           |                         | $ | 63,641 |  |      | $ | 37,685 |  |  | $ | 16,179 | 
|             | Non-cash stock based compensation
    (net of taxes) |                         |   | 381    |  |      |   |       |  |  |   | 9,587  | 
|             | Diluted net income per share                         |                         |   | 2.10   |  |      |   | 1.25   |  |  |   | 0.56   | 
|Pro Forma:   |                                                      |                         |   |        |  |      |   |        |  |  |   |       
|             | Net income                                           |                         | $ | 62,093 |  |      | $ | 36,408 |  |  | $ | 15,475 | 
|             | Non-cash stock based compensation
    (net of taxes) |                         |   | 1,929  |  |      |   | 1,277  |  |  |   | 10,291 | 
|             | Diluted net income per share                         |                         |   | 2.05   |  |      |   | 1.21   |  |  |   | 0.54   | 



| |                                   
| | ----------------------------------
| | Hedging and Related
    Activities

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

Effective January 1, 2001, we adopted
Statement of Financial Accounting Standards No. 133
(SFAS 133), Accounting for Derivative
Instruments and Hedging Activities. This standard requires
us to recognize all of our derivative and hedging instruments in
our statements of financial position as either assets or
liabilities and measure them at fair value. If a derivative does
not qualify for hedge accounting, it must be adjusted to fair
value through earnings. However, if a derivative does qualify
for hedge accounting, depending on the nature of the hedge,
changes in fair value can be offset against the

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change in fair value of the hedged item through
earnings or recognized in other comprehensive income until such
time as the hedged item is recognized in earnings.


To qualify for cash flow hedge accounting, the
cash flows from the hedging instrument must be highly effective
in offsetting changes in cash flows due to changes in the
underlying items being hedged. In addition, all hedging
relationships must be designated, documented, and reassessed
periodically. Most of our derivative financial instruments
qualify for hedge accounting. In accordance with the provisions
of SFAS 133, cash flow hedges are marked-to-market through
comprehensive income each quarter.

Currently, all of our derivative financial
instruments that are designated as hedges are designated as cash
flow hedges. These instruments hedge the exposure of variability
in expected future cash flows that is attributable to a
particular risk. The effective portion of the gain or loss on
these derivative instruments is recorded in Other
Comprehensive Income in Stockholders Equity and
reclassified into earnings in the same period in which the
hedged transaction affects earnings. Any ineffective portion of
the gain or loss is recognized as Derivative fair value
(gain) loss in the Consolidated Statements of Operations
immediately. While management does not anticipate changing the
designation of any of our current derivative contracts as
hedges, factors beyond our control can preclude the use of hedge
accounting. One example would be variability in the NYMEX price
for oil or natural gas, upon which many of our commodity
derivative contracts are based, that does not coincide with
changes in the spot price for oil and natural gas that we are
paid. Another example would be if the counterparty to a
derivative contract was deemed no longer creditworthy and
non-performance under the terms of the contract was likely. To
the extent our derivative contracts are not designated as
hedges, high earnings volatility can result, as any future
changes in the market value of the contract would then be
marked-to-market through earnings.

Capital Commitments, Capital Resources and
Liquidity

Capital Commitments.Our primary needs for cash are as follows:



| |   |                                                                                
| | - | -------------------------------------------------------------------------------
| |  | Development and exploitation of our existing oil
    and natural gas properties
|
| |  | High-pressure air injection programs on our CCA
    properties                 
|
| |  | Acquisitions of oil and natural gas properties                                 
|
| |  | Leasehold and acreage costs                                                    
|
| |  | Other general property and equipment                                           
|
| |  | Funding of necessary working capital                                           
|
| |  | Payment of contractual obligations                                             

Development and
Exploitation.Our capital expenditures
for conventional development and exploitation during the years
ended December 31, 2003 and 2002 totaled $86.1 million
and $73.7 million, respectively.

For 2004, we expect to invest $93 million in
development and exploitation. We have based our 2004 forecasts
on the assumptions of $23.50 per Bbl and $3.75 per Mcf
NYMEX prices. For comparability and accountability, we take a
constant approach to budgeting commodity prices. We analyze our
inventory of capital projects based on $23.50 per Bbl and
$3.75 per Mcf NYMEX prices to ensure a rate of return to
our shareholders without the benefit of escalating future
commodity prices. If NYMEX prices trend downward below our base
deck, we may reevaluate capital projects and may adjust the
capital budgeted for development and exploitation investments
accordingly.

High-Pressure Air
Injection.Our capital expenditures
for high-pressure air injection during the years ended
December 31, 2003 and 2002 totaled $12.9 million and
$6.6 million, respectively. In 2003, we began implementing
our second HPAI program in the Little Beaver unit of the CCA and
began injecting air in the reservoir in December 2003. We expect
to have the Little Beaver unit fully implemented by the first
quarter of 2004. The Little Beaver unit project was taken from
concept to implementation in less than

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9 months. We successfully negotiated a
contract from a third party to supply the air compression
services to Little Beaver, which reduced the up front capital
requirements for the Little Beaver unit project. In 2002, we
began a pilot program to begin injecting air into the Red River
U4 reservoir in a portion of the Pennel Unit of the CCA. Because
of positive results, we are planning to expand the project in
the Pennel unit of the CCA with a $25.2 million expansion
of the project which we expect to complete by early 2005. We
believe that the HPAI program will generate a higher rate of
return than other tertiary processes and can be applied
throughout the CCA. The zone of our initial focus, the Red River
U4 zone, is the same zone where HPAI has been successfully
implemented by other operators in adjacent areas and on the
Pennel unit of the CCA. Response from HPAI investments is not
expected until ten to eighteen months from the time of first
injection.


For 2004, we expect to invest $34 million in
high-pressure air injection. We have based our 2004 forecasts on
the assumptions of $23.50 per Bbl and $3.75 per Mcf
NYMEX prices. See  Development and
Exploitation above regarding our approach to budgeting
commodity prices.

Acquisitions.Our
capital expenditures for oil and natural gas acquisitions during
the years ended December 31, 2003 and 2002 totaled
$54.6 million and $78.5 million, respectively. In
2003, we completed an acquisition of interests in natural gas
properties in North Louisiana. 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 production and reserves
of the properties are substantially all natural gas. On
January 1, 2002, we completed the Central Permian
acquisition from Conoco for approximately $50.1 million.
During the second quarter of 2002, we closed a second, follow-on
acquisition of additional working interest for
$8.3 million. The Central Permian properties increased our
operational presence in West Texas. On August 29, 2002 we
acquired an interest in oil and natural gas properties in
southeast Utahs Paradox Basin.

We will continue to pursue acquisitions of
properties with similar upside potential to our current
producing properties portfolio. For the year ended 2003, we
evaluated over $1 billion of potential acquisitions. We do
not budget for acquisitions but we will continue to evaluate
acquisition opportunities as they arise in 2004 with the same
disciplined commitment to acquire assets that fit our portfolio
and continue to create value.

Our current $140 million capital budget for
2004 does not include any funds for the development and
exploitation of oil and natural gas properties that we may
acquire during 2004. Our practice is to review our capital
budget following a significant acquisition. We are currently
undertaking such a review in connection with the Cortez
transaction.

Leasehold and Acreage
Costs.Our capital expenditures for
leasehold and acreage costs during the years ended
December 31, 2003 and 2002 totaled $0.1 million and
$0.4 million, respectively.

For 2004, we expect to invest $12 million
for leasehold and acreage costs. Compared to historical
expenditures for leasehold and acreage, 2004 will be a
significant increase in capital expenditures. We plan to
actively pursue leases and acreage in our core areas that we are
currently operating oil and natural gas properties. These
investments are not expected to result in oil and natural gas
production in 2004.

Other General Property and
Equipment.Our capital expenditures
for other general property and equipment during the years ended
December 31, 2003 and 2002 totaled $1.5 million and
$0.7 million, respectively. Capital expenditures for other
general property and equipment include corporate leasehold
improvements, computers, software, telecommunications equipment,
field trucks, and field rental equipment.

For 2004, we expect to invest $0.8 million
in other general property and equipment.

Working Capital.At
December 31, 2003, our working capital was
$(0.1) million while at December 31, 2002 working
capital was $12.5 million, a decrease of
$12.6 million. The decrease is primarily attributable to
cash and cash equivalents. Excluding the decrease in cash of
$12.6 million, working capital was essentially flat from
2002 to 2003. In order to minimize our interest expense, we use

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excess cash reserves to pay down any amounts
outstanding under our revolving credit facility. However, at the
end of 2002, due to the margin maintenance requirements with our
commodity derivative counterparties and the high commodity price
environment, we maintained cash reserves on hand to satisfy any
margin calls as they arose. Thus, we held a much higher cash and
cash equivalents balance at December 31, 2002 than would
otherwise be held. This resulted in the decrease in working
capital from December 31, 2002 to December 31, 2003.
Currently, as of March 3, 2004, we have $4.5 million
posted related to our derivatives margin account.


For 2004, we expect working capital to remain
relatively flat to 2003. We anticipate cash reserves to be close
to zero as we use any excess cash to fund capital obligations
and any additional excess cash would be used to pay down our
existing credit facility. We do not plan to pay cash dividends
in the foreseeable future. The overall 2004 commodity prices for
oil and natural gas will be the largest variable driving the
different components of working capital. Our operating cash flow
is determined in a large part by commodity prices. Assuming
moderate to high commodity prices, our operating cash flow
should remain positive for the foreseeable future. We have
budgeted capital expenditures of approximately
$140.0 million for 2004. The level of these and other
future expenditures is largely discretionary, and the amount of
funds devoted to any particular activity may increase or
decrease significantly, depending on available opportunities and
market conditions. We plan to finance our ongoing expenditures
using internally generated cash flow, available cash, and our
existing credit agreement.

Contractual
Obligations.The following table
illustrates our contractual obligations and commercial
commitments outstanding at December 31, 2003
(in thousands):

|                             |  |                        |         |      |  |           |        |           |  |            |        |  |  |   |        |  |  |   |         | 
|---------------------------- |  | ---------------------- | ------- | ---- |  | --------- | ------ | --------- |  | ---------- | ------ |  |  | - | ------ |  |  | - | ------- | 
|                             |  |                       
|                             |  | Payments Due by Period
|Contractual Obligations and  |  |                       
|Commercial Commitments       |  | Total                  |         | 2004 |  | 2005-2006 |        | 2007-2008 |  | Thereafter
|                             |  |                        |         |      |  |           |        |           |  |           
|8 3/8% Notes(1)              |  | $                      | 256,782 |      |  | $         | 12,563 |           |  | $          | 25,125 |  |  | $ | 25,125 |  |  | $ | 193,969 | 
|Revolving Credit Facility(2) |  |                        | 28,593  |      |  |           | 637    |           |  |            | 27,956 |  |  |   |       |  |  |   |        | 
|Derivative Obligations(3)    |  |                        | 8,204   |      |  |           | 4,903  |           |  |            | 2,272  |  |  |   | 1,029  |  |  |   |        | 
|Development Commitments(4)   |  |                        | 50,793  |      |  |           | 48,923 |           |  |            | 1,270  |  |  |   | 600    |  |  |   |        | 
|Operating Leases(5)          |  |                        | 2,843   |      |  |           | 951    |           |  |            | 1,507  |  |  |   | 342    |  |  |   | 43      | 
|                             |  |                        |         |      |  |           |        |           |  |            |        |  |  |   |        |  |  |   |         | 
|Totals                       |  | $                      | 347,215 |      |  | $         | 67,977 |           |  | $          | 58,130 |  |  | $ | 27,096 |  |  | $ | 194,012 | 
|                             |  |                        |         |      |  |           |        |           |  |            |        |  |  |   |        |  |  |   |         | 



---



|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Amounts included in the table above include both
    principal and projected interest payments. See information
    presented in Note 6. Indebtedness to the
    accompanying consolidated financial statements for additional
    information regarding our long-term debt.                                                                                                                                                                                                                                                      
|   
|(2) | Amounts included in the table above include both
    principal and projected interest payments. See
    Note 6. Indebtedness to the accompanying
    consolidated financial statements for additional information
    regarding our long-term debt. Giving effect to the Cortez
    acquisition, the pro-forma amount outstanding under our
    revolving credit facility as of December 31, 2003 would be
    approximately $152.0 million.                                                                                      
|   
|(3) | Derivative obligations represent liabilities for
    derivatives that were valued as of December 31, 2003. The
    ultimate settlement amounts of the remaining portions of our
    derivative obligations are unknown because they are subject to
    continuing market risk. See Item 7A. Quantitative and
    Qualitative Disclosures About Market Risk and
    Note 11. Financial Investments to the
    accompanying consolidated financial statements for additional
    information regarding our derivative obligations.
|   
|(4) | Development commitments represent authorized
    purchases not placed to vendors, thus not accrued at year-end.
    These purchases are authorized and expected to be made during
    2004 unless circumstances change. Above amounts also include
    minimum transmission payments for electricity.                                                                                                                                                                                                                               
|   
|(5) | Operating leases represent office space and
    equipment obligations that have remaining non-cancelable lease
    terms in excess of one year. See Note 4. Commitments
    and Contingencies to the accompanying consolidated
    financial statements for additional information regarding our
    operating leases.                                                                                                                                                                                                            

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Investing
Activities.Cash used by investing
activities decreased by $5.6 million from 2002 to 2003.
This was due to offsetting changes in its two primary
components: acquisition of oil and natural gas properties, which
decreased by $23.9 million; and development of oil and
natural gas properties, which increased $18.7 million. Cash
used for the acquisition of oil and natural gas properties
varies year to year based on our success in acquiring oil and
natural gas properties. Our bid price is a price we feel
provides a certain level of return based on our expectation of
future oil and natural gas prices, while providing potential for
some upside realization. Success in the acquisition market is
largely driven by competition in the marketplace and in the
availability of properties for sale. During 2002, we were
successful in completing two major property acquisitions, one
comprised of properties in the Paradox Basin of Utah and one
comprised of properties in the Permian Basin of West Texas at a
combined cost of $78.6 million, while in 2003 we were
successful in completing one major property acquisition of
properties in the North Louisiana Salt Basin of Louisiana at a
cost of $54.6 million. The increase in cash used in the
development of oil and natural gas properties of $18.7 was the
result of drilling 29 more gross wells (8.3 net) and the
expansion of the HPAI project into the Little Beaver area of
the CCA.

Capital Resources.Our primary capital resources are net cash provided by operating
activities, and proceeds from financing activities which are
used to fund our capital commitments. Our primary needs for cash
include our high-pressure air injection program in the CCA,
acquisitions of oil and natural gas properties, development and
exploitation of our existing oil and natural gas properties,
leasehold and acreage cost, funding of necessary working
capital, and payment of contractual obligations.

Operating
Activities.For 2003, cash provided by
operating activities increased by $32.3 million. This
increase resulted from the $26.0 increase in net income coupled
with an increase in deferred taxes of $11.8 million, offset
by decrease in changes in operating assets and liabilities from
2002 to 2003 of $6.4 million. The increase in net income
was primarily due to increased production volumes and higher
commodity prices compared to 2002.

Financing
Activities.During 2003 proceeds from
financing activities was $17.3 million, while it was
$80.7 million in 2002. In 2003, we were able to close the
initial Elm Grove acquisition and subsequent interests for
$54.6 million and fund our $99.0 million capital
drilling program with only a modest $13.0 million increase
in our revolving credit facility. During 2002, however, we
increased our debt by $88.0 million to fund two property
acquisitions, Central Permian and Paradox Basin, and fund
$80.3 million in development expenditures.

Additionally during 2003, 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 and 2,193,357 shares
from 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.

This compares to 2002 when on June 25, 2002,
we sold $150 million of 8 3/8% Senior
Subordinated Notes maturing on June 15, 2012 in a private
placement pursuant to Rule 144A. We received net proceeds
of $145.6 million from the sale of the
8 3/8% notes, after deducting debt issuance costs. The
proceeds were used to repay and retire our prior credit facility
($143.0 million), to pay the fees and expenses related to
the new revolving credit facility ($1.5 million), and to
hold in reserve for the Paradox Basin acquisition
($1.1 million).

Liquidity.Our
principal source of short-term liquidity is our revolving credit
facility. We entered into the current revolving credit facility
on June 25, 2002. Borrowings under the facility are secured
by a first priority lien on our proved oil and natural gas
reserves. Availability under the facility is determined

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through semi-annual borrowing base determinations
and may be increased or decreased. The amount available under
our credit facility increased in 2003 by $50.0 million to
$270.0 million, with $29.0 million outstanding as of
December 31, 2003. We expect the pending acquisition of
Cortez will reduce the availability by $123.0 million. The
maturity date of the new facility is June 25, 2006.


Amounts outstanding under the facility are
subject to varying rates of interest based on the amount
outstanding and our borrowing base. Based on our current
$270.0 million borrowing base, our applicable interest
rates are calculated as follows:

|                             |  |      |                | 
|---------------------------- |  | ---- | -------------- | 
|Amount Outstanding           |  | Rate
|                             |  |     
|$0 to $55,000,000            |  |      | LIBOR + 1.000% | 
|$55,000,001 to $110,000,000  |  |      | LIBOR + 1.125% | 
|$110,000,001 to $165,000,000 |  |      | LIBOR + 1.250% | 
|$165,000,001 to $198,000,000 |  |      | LIBOR + 1.500% | 
|$198,000,001 to $270,000,000 |  |      | LIBOR + 1.750% | 

Our revolving credit facility and the indenture
related to the 8 3/8% notes contain financial and
other restrictive covenants that limit our ability to engage in
activities that may be in our long-term best interests. The
covenants under our revolving credit facility are similar but
generally more restrictive than the covenants under the
indenture. Our ability to borrow under our revolving credit
facility is subject to financial covenants, including leverage,
interest and fixed charge coverage ratios. Our revolving credit
facility limits our ability to effect mergers, asset sales, and
change of control events. These covenants also contain
restrictions regarding our ability to incur additional
indebtedness in the future. In some cases, our subsidiaries are
subject to similar restrictions that may restrict their ability
to make distributions to us. The indenture related to our
8 3/8% notes also contains limitations on our ability
to effect mergers and change of control events, incur additional
indebtedness, sell assets, declare and pay dividends or make
other restricted payments, enter into transactions with
affiliates and subject our assets to liens.

Based on current commodity conditions, we believe
that our capital resources are adequate to meet the requirements
of our business through 2005 and the foreseeable future. Based
on our anticipated capital programs, we expect to invest our
internally generated cash flow to replace production and enhance
our development programs. During 2004, we have planned total
capital expenditures of approximately $140 million,
although we may need additional capital to pursue acquisitions
or other capital projects. Our current capital budget does not
include any funds for development and exploitation of oil and
natural gas properties that we may acquire during 2004. Our
practice is to review our capital budget following a significant
transaction. We are currently undertaking such review in
connection with the Cortez transaction.

Substantially all of our capital expenditures are
discretionary and will be undertaken only if funds are available
and the projected rates of return are satisfactory. Future cash
flows are subject to a number of variables including the level
of oil and natural gas production and prices. Operations and
other capital resources may not provide cash in sufficient
amounts to maintain planned levels of capital expenditures.
Additionally, we are required to maintain margin amounts and/or
letters of credits with the counterparties to our outstanding
hedges if the mark-to-market value of our hedges reach a certain
negative value. Although we did not have any margin deposits
with our counterparties as of December 31, 2003, if
commodity prices were to rise substantially, we would be
required to post margin with one or more counterparties for
expected future hedging settlements. Currently, as of
March 3, 2004, we have $4.5 million posted related to
our derivatives margin account.

Book Capitalization.At December 31, 2003, we had total assets of
$672.1 million. Total capitalization was
$538.0 million, of which 66.7% was represented by
stockholders equity and 33.3% by senior debt.

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Inflation and Changes in Prices

While the general level of inflation affects
certain of our costs, factors unique to the petroleum industry
result in independent price fluctuations. Historically,
significant fluctuations have occurred in oil and natural gas
prices. In addition, changing prices often cause costs of
equipment and supplies to vary as industry activity levels
increase and decrease to reflect perceptions of future price
levels. Although it is difficult to estimate future prices of
oil and natural gas, price fluctuations have had, and will
continue to have, a material effect on us.

The following table indicates the average oil and
natural gas prices received for the years ended
December 31, 2003, 2002, and 2001. Average equivalent
prices for 2003, 2002, and 2001 were decreased by $1.89, $0.70,
and $2.04 per BOE, respectively, as a result of our hedging
activities. Average prices per equivalent barrel indicate the
composite impact of changes in oil and natural gas prices.
Natural gas production is converted to oil equivalents at the
conversion rate of six Mcf per Bbl.

|                                  |  |         |       |             |  |          |      |  |  |   |       | 
|--------------------------------- |  | ------- | ----- | ----------- |  | -------- | ---- |  |  | - | ----- | 
|                                  |  | Oil     |       | Natural Gas |  | Combined
|                                  |  | ($/Bbl) |       | ($/Mcf)     |  | ($/BOE) 
|                                  |  |         |       |             |  |         
|Net Price Realization with Hedges |  |         |       |             |  |          |      |  |  |   |       | 
|Year ended December 31, 2003      |  | $       | 26.72 |             |  | $        | 4.83 |  |  | $ | 27.14 | 
|Year ended December 31, 2002      |  |         | 22.34 |             |  |          | 3.16 |  |  |   | 21.72 | 
|Year ended December 31, 2001      |  |         | 21.43 |             |  |          | 3.73 |  |  |   | 21.64 | 
|Average Wellhead Price            |  |         |       |             |  |          |      |  |  |   |       | 
|Year ended December 31, 2003      |  | $       | 28.82 |             |  | $        | 5.00 |  |  | $ | 29.03 | 
|Year ended December 31, 2002      |  |         | 23.38 |             |  |          | 3.03 |  |  |   | 22.42 | 
|Year ended December 31, 2001      |  |         | 23.25 |             |  |          | 4.21 |  |  |   | 23.68 | 

SPECIAL NOTE REGARDING FORWARD-LOOKING
STATEMENTS

Our disclosure and analysis in this Report
contains some forward-looking statements. Forward-looking
statements give our current expectations or forecasts of future
events. You can identify these statements by the fact that they
do not relate strictly to historical or current facts. These
statements may include words such as anticipate,
estimate, expect, project,
intend, plan, believe,
should, and other words and terms of similar meaning
in connection with any discussion of future operating or
financial performance. In particular, these include, among other
things, statements relating to:



| |   |                                                                                                                                                                                        
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | 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 High-Pressure Air
    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;                                                                                                                                            
|
| |  | projected revenues; FD&A costs; lifting
    costs; lease operations expenses; production, ad valorem and
    severance taxes; general and administrative expenses; taxes; and
    DD&A;
|
| |  | timing and amount of future production of oil and
    natural gas;                                                                                                                     
|
| |  | expected hedging positions and payments related
    to hedging contracts;                                                                                                              
|
| |  | expectations regarding working capital, cash flow
    and anticipated liquidity;                                                                                                       

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| |   |                                                                                    
| | - | -----------------------------------------------------------------------------------
| |  | the closing of the Cortez transaction and the
    benefits to be derived therefrom;
|
| |  | projected borrowings under our credit
    facility; and                            
|
| |  | marketing of oil and natural gas.                                                  

Our actual results may differ significantly from
the results discussed in the forward-looking statements. Such
statements involve risks and uncertainties, including, but not
limited to, the matters discussed in the subsection entitled
Factors That May Affect Future Results and Financial
Condition below and elsewhere in this Report and our other
filings with the Securities and Exchange Commission. If one or
more of these risks or uncertainties materialize, or should
underlying assumptions prove incorrect, actual outcomes may vary
materially from those indicated. We undertake no responsibility
to update for changes related to these or any other factors that
may occur subsequent to this filing for any reason.

FACTORS THAT MAY AFFECT FUTURE RESULTS AND
FINANCIAL CONDITION

You should read carefully the following
factors and all other information contained in this Report. If
any of the risks and uncertainties described below or elsewhere
in this Report actually occur, our business, financial condition
or results of operations could be materially adversely affected.
In that case, the trading price of our common stock could
decline, and an investor may lose all or part of his
investment.

Risks Related to Our Business



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

Historically, the markets for oil and natural gas
have been volatile, and these markets are likely to continue to
be volatile in the future. Our revenues, profitability and
future growth depend substantially on prevailing oil and natural
gas prices. Lower oil and natural gas prices may reduce the
amount of oil and natural gas that we can economically produce.
Prevailing oil and natural gas prices also affect the amount of
internally generated cash flow available for repayment of
indebtedness and capital expenditures. In addition, the amount
we can borrow under our revolving credit facility is subject to
periodic redetermination based in part on changing expectations
of future oil and natural gas prices.

The factors that can cause oil and natural gas
price volatility include:



| |   |                                                                                                                                                 
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------
| |  | the supply of domestic and foreign oil and
    natural gas;                                                                                     
|
| |  | the ability of members of the Organization of
    Petroleum Exporting Countries to agree upon and maintain oil
    prices and production levels;
|
| |  | political instability or armed conflict in oil or
    natural gas producing regions;                                                            
|
| |  | the level of consumer demand;                                                                                                                   
|
| |  | weather conditions;                                                                                                                             
|
| |  | the price and availability of alternative fuels;                                                                                                
|
| |  | domestic and foreign governmental regulations and
    taxes;                                                                                    
|
| |  | domestic political developments; and                                                                                                            
|
| |  | worldwide economic conditions.                                                                                                                  

The volatile nature of markets for oil and
natural gas makes it difficult to reliably estimate future
prices. Any decline in oil and natural gas prices adversely
affects our financial condition. If oil or natural gas prices
decline significantly for a sustained period of time, we may,
among other things, be unable to meet our financial obligations,
make planned expenditures or raise additional capital.

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| |                                                                                                                                                                                                                                                              
| | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | Reserve estimates depend on many
    assumptions that may prove to be inaccurate. Any material
    inaccuracies in our reserve estimates or underlying assumptions
    could cause the quantities and net present value of our reserves
    to be overstated.

Estimating quantities of proved oil and natural
gas reserves is a complex process that requires interpretations
of available technical data and numerous assumptions, including
certain economic assumptions. Any significant inaccuracies in
these interpretations or assumptions or changes in conditions
could cause the quantities and net present value of our reserves
to be overstated.

To prepare estimates of economically recoverable
oil and natural gas reserves and future net cash flows, we must
analyze many variable factors, such as historical production
from the area compared with production rates from other
producing areas. We must also analyze available geological,
geophysical, production and engineering data, and the extent,
quality and reliability of this data can vary. The process also
involves economic assumptions relating to commodity prices,
production costs, severance and excise taxes, capital
expenditures and workover and remedial costs. Actual results
most likely will vary from our estimates. Any significant
variance could reduce the estimated quantities and present value
of our reserves.

You should not assume that the present value of
future net cash flows from our proved reserves referred to in
this Report is the current market value of our estimated oil and
natural gas reserves. In accordance with SEC requirements, we
base the estimated discounted future net cash flows from our
proved reserves on prices and costs in effect on the date of the
estimate, holding the prices and costs constant throughout the
life of the properties. Actual future prices and costs may
differ materially from those used in the net present value
estimate, and future net present value estimates using then
current prices and costs may be significantly less than the
current estimate.



| |                                                                         
| | ------------------------------------------------------------------------
| | The results of high pressure air injection
    techniques are uncertain.

We utilize high pressure air injection, or HPAI,
techniques on some of our properties and plan to use the
techniques in the future on a substantial portion of our
properties, including our CCA properties. The additional
production and reserves attributable to our use of the
techniques, if any, are inherently difficult to predict. If our
HPAI programs do not allow for the extraction of residual
hydrocarbons in the manner or to the extent that we anticipate,
our future results of operations and financial condition could
be materially adversely affected.



| |                                                                                    
| | -----------------------------------------------------------------------------------
| | If oil and natural gas prices decrease, we
    may be required to take write downs.

We may be required to write down the carrying
value of our oil and natural gas properties when future
estimated oil and gas prices are low or if we have substantial
downward adjustments to our estimated proved reserves or
increases in our estimates of operating expenses or development
costs. We capitalize the costs to acquire, find and develop our
oil and natural gas properties under the successful efforts
accounting method. The net capitalized costs of our oil and
natural gas properties may not exceed their estimated fair
value. If net capitalized costs of our oil and natural gas
properties exceed their fair value, we must charge the amount of
the excess to earnings. We review the carrying value of our
properties quarterly, based on changes in expectations of future
oil and natural gas prices, expenses and tax rates. Once
incurred, a write down of oil and natural gas properties is not
reversible at a later date even if oil or gas prices increase.



| |                                                                                                                      
| | ---------------------------------------------------------------------------------------------------------------------
| | Our acquisition strategy subjects us to
    numerous risks that could adversely affect our results of
    operations.

Acquisitions are an essential part of our growth
strategy, and our ability to acquire additional properties on
favorable terms is important to our long-term growth. Depending
on conditions in the acquisition market, it may be difficult or
impossible for us to identify properties for acquisition or we
may not be able to make acquisitions on terms that we consider
economically acceptable. Even if we are able to identify
suitable acquisition opportunities, our acquisition strategy
depends upon, among other things, our ability to obtain debt and
equity financing and, in some cases, regulatory approvals.

38



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The successful acquisition of producing
properties requires an assessment of several factors, including:



| |   |                                               
| | - | ----------------------------------------------
| |  | recoverable reserves;                         
|
| |  | future oil and natural gas prices;            
|
| |  | operating costs; and                          
|
| |  | potential environmental and other liabilities.

The accuracy of these assessments is inherently
uncertain. In connection with these assessments, we perform a
review of the subject properties that we believe to be generally
consistent with industry practices. Our review will not reveal
all existing or potential problems nor will it permit us to
become sufficiently familiar with the properties to fully assess
their deficiencies and capabilities. Inspections may not always
be performed on every well, and structural and environmental
problems are not necessarily observable even when an inspection
is undertaken. Even when problems are identified, the seller may
be unwilling or unable to provide effective contractual
protection against all or part of the problems. We are often not
entitled to contractual indemnification for environmental
liabilities and acquire properties on an as is basis.

Possible future acquisitions could result in our
incurring additional debt, contingent liabilities and expenses,
all of which could have a material adverse effect on our
financial condition and operating results. Furthermore, our
financial position and results of operations may fluctuate
significantly from period to period based on whether significant
acquisitions are completed in particular periods. Competition
for acquisitions is intense and may increase the cost of, or
cause us to refrain from, completing acquisitions.



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

Growing through acquisitions and managing that
growth will require us to continue to invest in operational,
financial and management information systems and to attract,
retain, motivate and effectively manage our employees. Pursuing
and integrating acquisitions involves a number of risks,
including:



| |   |                                                                                                                                                                                 
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | 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.                                                                                                

The process of integrating acquired operations
into our existing operations may result in unforeseen operating
difficulties and may require significant management attention
and financial resources that would otherwise be available for
the ongoing development or expansion of existing operations.



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

We have extensive operations in the Williston
Basin of Montana and North Dakota. As of December 31, 2003,
our CCA properties in the Williston Basin represented
approximately 73% of our proved reserves and 61% of our 2003
production. Any circumstance or event that negatively impacts
production or marketing of oil and natural gas in the Williston
Basin could materially reduce our earnings and cash flow.

39



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

We use derivative instruments in an effort to
reduce our exposure to fluctuations in the prices of oil and
natural gas and to reduce our cash outflows related to interest.
Our derivative instruments expose us to risks of financial loss
in a variety of circumstances, including when:



| |   |                                                                                                                                                                         
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | a counterparty to our derivative instruments is
    unable to satisfy its obligations;                                                                                  
|
| |  | production is less than expected; or                                                                                                                                    
|
| |  | there is an adverse change in the expected
    differential between the underlying price in the derivative
    instrument and actual prices received for our production.

Derivative instruments may limit our ability to
realize increased revenue from increases in the prices for oil
and natural gas.

We adopted Statement of Financial Accounting
Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities
(SFAS 133), on January 1, 2001.
SFAS 133 generally requires us to record each hedging
transaction as an asset or liability measured at its fair value.
Each quarter we must record changes in the fair value of our
hedges, which could result in significant fluctuations in net
income and stockholders equity from period to period.



| |                                                                
| | ---------------------------------------------------------------
| | Drilling oil and natural gas wells is a
    high-risk activity.

Drilling oil and natural gas wells, including
development wells, involves numerous risks, including the risk
that no commercially productive oil or natural gas reservoirs
will be discovered. We often are uncertain as to the future cost
or timing of drilling, completing and producing wells. We may
not recover all or any portion of our investment in drilling oil
and natural gas wells.

Our drilling operations may be curtailed, delayed
or canceled as a result of a variety of factors, including
unexpected drilling conditions or miscalculations, title
problems, pressure or irregularities in formations, equipment
failures or accidents, adverse weather conditions, compliance
with environmental and other governmental requirements and cost
of, or shortages or delays in the availability of, drilling rigs
and equipment.



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

Our future success depends upon our ability to
find, develop or acquire additional oil and natural gas reserves
that are economically recoverable. Our proved reserves generally
decline when reserves are produced, unless we conduct successful
exploitation or development activities or acquire properties
containing proved reserves, or both. We may not be able to find,
develop or acquire additional reserves on an economic basis.

Substantial capital is required to replace and
grow reserves. If lower oil and natural gas prices or operating
difficulties result in our cash flow from operations being less
than expected or limit on our ability to borrow under our
revolving credit facility, we may be unable to expend the
capital necessary to find, develop or acquire new oil and
natural gas reserves.



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

Other companies operate some of the properties in
which we have an interest. We have limited ability to influence
or control the operation or future development of these
non-operated properties or the amount of capital expenditures
that we are required to fund with respect to them. Our
dependence on the operator and other working interest owners for
these projects and our limited ability to influence or control
the operation and future development of these properties could
materially adversely affect the realization of our targeted
returns on capital in drilling or acquisition activities and
lead to unexpected future costs.

40



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##### Table of Contents





| |                                                                                                                                                                    
| | -------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | Our business involves many operating risks
    that can cause substantial losses; insurance may be unavailable
    or inadequate to protect us against these risks.

Our operations are subject to hazards and risks
inherent in drilling for, producing and transporting oil and
natural gas, such as fires; natural disasters; explosions;
formations with abnormal pressures; blowouts; collapses of
wellbore, casing or other tubulars; failure of oilfield drilling
and service tools; uncontrollable flows of oil, natural gas,
formation water or drilling fluids; pressure forcing oil or
natural gas out of the wellbore at a dangerous velocity coupled
with the potential for fire or explosion; changes in
below-ground pressure in a formation that cause surface collapse
or cratering; pipeline ruptures or cement failures;
environmental hazards, such as oil spills, natural gas leaks and
discharges of toxic gases; and weather. If any of these events
occur, we could incur substantial losses as a result of injury
or loss of life; damage to and destruction of property, natural
resources and equipment; pollution and other environmental
damage; regulatory investigations and penalties; suspension of
our operations; and repair and remediation costs.

We do not maintain insurance against the loss of
oil or natural gas reserves as a result of operating hazards,
nor do we maintain business interruption insurance. In addition,
pollution and environmental risks generally are not fully
insurable. We may experience losses for uninsurable or uninsured
risks or losses in amounts in excess of existing insurance
coverage. The occurrence of an event that is not fully covered
by insurance could harm our financial condition and results of
operations.



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

The threat of terrorism and the impact of
military and other action have caused instability in world
financial markets and could lead to increased volatility in
prices for oil and natural gas, all of which could adversely
affect the markets for our operations. Future acts of terrorism
could be directed against companies operating in the United
States. The U.S. government has issued public warnings that
indicate that energy assets might be specific targets of
terrorist organizations. These developments have subjected our
operations to increased risk and, depending on their ultimate
magnitude, could have a material adverse effect on our business.



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

We make and will continue to make substantial
capital expenditures in development and exploitation projects.
We intend to finance these capital expenditures through a
combination of cash flow from operations and external financing
arrangements. Additional financing sources may be required in
the future to fund our capital expenditures. Financing may not
continue to be available under existing or new financing
arrangements, or on acceptable terms, if at all. If additional
capital resources are not available, we may be forced to curtail
our drilling and other activities or be forced to sell some of
our assets on an untimely or unfavorable basis.



| |                                                                   
| | ------------------------------------------------------------------
| | The loss of key personnel could adversely
    affect our business.

We depend to a large extent on the efforts and
continued employment of I. Jon Brumley, our Chairman of the
Board and Chief Executive Officer, Jon S. Brumley, our
President, and other key personnel. The loss of the services of
Mr. I. Jon Brumley or Mr. Jon S. Brumley or other
key personnel could adversely affect our business, and we do not
have employment agreements with, and do not maintain key man
insurance on the lives of, any of these persons. Our drilling
success and the success of other activities integral to our
operations will depend, in part, on our ability to attract and
retain experienced geologists, engineers and other
professionals. Competition for experienced geologists, engineers
and some other professionals is extremely intense. If we cannot
retain our technical personnel or attract additional experienced
technical personnel, our ability to compete could be harmed.

41



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##### Table of Contents





| |                                                                                                                                           
| | ------------------------------------------------------------------------------------------------------------------------------------------
| | The marketability of our oil and natural
    gas production is dependent upon transportation facilities over
    which we have no control.

The marketability of our oil and natural gas
production depends in part upon the availability, proximity and
capacity of pipelines, oil and natural gas gathering systems and
processing facilities. Any significant change in market factors
affecting these infrastructure facilities could harm our
business. We deliver oil and natural gas through gathering
systems and pipelines that we do not own. These facilities may
not be available to us in the future.



| |                                                                                                                                                                          
| | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | 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.

We operate in the highly competitive areas of oil
and natural gas acquisition, development, exploitation and
production. The oil and natural gas industry is characterized by
rapid and significant technological advancements and
introductions of new products and services using new
technologies. We face intense competition from independent,
technology-driven companies as well as from both major and other
independent oil and natural gas companies in each of the
following areas:



| |   |                                                                                           
| | - | ------------------------------------------------------------------------------------------
| |  | 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.

Many of our competitors have financial,
technological and other resources substantially greater than
ours, which may adversely affect our ability to compete with
these companies. These companies may be able to pay more for
development prospects and productive oil and natural gas
properties and may be able to define, evaluate, bid for and
purchase a greater number of properties and prospects than our
financial or human resources permit. Further, these companies
may enjoy technological advantages and may be able to implement
new technologies more rapidly than we can. Our ability to
develop and exploit our oil and natural gas properties and to
acquire additional properties in the future will depend upon our
ability to successfully conduct operations, implement advanced
technologies, evaluate and select suitable properties and
consummate transactions in this highly competitive environment.



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

Exploration, development, production and sale of
oil and natural gas in North America are subject to extensive
federal, state, provincial and local laws and regulations,
including complex tax and environmental laws and regulations. We
may be required to make large expenditures to comply with
applicable laws and regulations, which could adversely affect
our results of operations and financial condition. Matters
subject to regulation include discharge permits for drilling
operations, drilling bonds, spacing of wells, unitization and
pooling of properties, environmental protection, reports
concerning operations and taxation. Under these laws and
regulations, we could be liable for personal injuries, property
damage, oil spills, discharge of hazardous materials,
reclamation costs, remediation and clean-up costs and other
environmental damages.

We do not believe that full insurance coverage
for all potential environmental damages is available at a
reasonable cost, and we may need to expend significant financial
and managerial resources to comply with environmental
regulations and permitting requirements. We could incur
substantial additional costs and liabilities in our oil and
natural gas operations as a result of stricter environmental
laws, regulations and enforcement policies.

Failure to comply with these laws and regulations
also may result in the suspension or termination of our
operations and subject us to administrative, civil and criminal
penalties. Further, these laws and regulations could change in
ways that substantially increase our costs. Any of these
liabilities, penalties,

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##### Table of Contents



suspensions, terminations or regulatory changes
could make it more expensive for us to conduct our business or
cause us to limit or curtail some of our operations.







|         |                                                               
|-------- | --------------------------------------------------------------
|Item 7A. | Quantitative and Qualitative Disclosures
    About Market Risk

Hedging Policy.We
have adopted a formal hedging policy. The purpose of our hedging
program is to mitigate the negative effects of declining
commodity prices on our business. The hedging policy is set by
the President with input from the Chief Executive Officer and
the Chief Financial Officer. We plan to continue in the normal
course of business to hedge our exposure to fluctuating
commodity prices. The volumes we have capped or swapped will not
exceed 75% of our anticipated production from proved producing
reserves. Under our hedging policy, we do not enter into
derivatives for speculative purposes. However, not all of our
derivatives qualify for hedge accounting and in some instances
management has determined it is more cost effective not to
designate certain derivatives as hedges.

Counterparties.Our
counterparties to hedging contracts include: BNP Paribas;
Deutsche Bank; Koch; Morgan Stanley; Mitsui & Co; Shell
Trading; Credit Lyonnais; J. Aron & Company, a
wholly-owned subsidiary of Goldman, Sachs & Co. At
December 31, 2003 approximately 35%, 23%, 20%, and 16% of
estimated oil production hedged is committed to Morgan
Stanley, J. Aron & Company, Deutsche Bank, and
Credit Lyonnais, respectively. Approximately 42%, 33%, and 25%
of our hedged gas production is contracted with BNP Paribas,
J. Aron & Company, and Morgan Stanley,
respectively. Performance on all of J. Aron &
Companys contracts with us is guaranteed by their parent,
Goldman, Sachs & Co. We feel the credit-worthiness of
our current counterparties is sound and we do not anticipate any
non-performance of contractual obligations. As long as each
counterparty maintains an investment grade credit rating,
pursuant to our hedging contracts, no collateral is required.

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

Commodity Price
Sensitivity.The tables in this
section provide information about derivative financial
instruments to which we were a party as of December 31,
2003 that are sensitive to changes in oil and natural gas
commodity prices.

We hedge commodity price risk with swap
contracts, put contracts, and collar contracts. Swap contracts
provide a fixed price for a notional amount of sales volumes.
Put contracts provide a fixed floor price on a notional amount
of sales volumes while allowing full price participation if the
relevant index price closes above the floor price. Collar
contracts provide a floor price on a notional amount of sales
volumes while allowing some additional price participation if
the relevant index price closes above the floor price.
Additionally, we occasionally we sell short put contracts with a
strike price well below the floor price of the collar. These
short put contracts do not qualify for hedge accounting under
SFAS 133, and accordingly, the mark-to-market change in the
value of these contracts is recorded as fair value gain/loss in
the statements of operations. Thus, not all of our derivatives
qualify for hedge accounting and in some instances management
has determined it is more cost effective not to designate
certain derivatives as hedges. The unrealized mark-to-market
loss on our outstanding commodity derivatives at
December 31, 2003 was approximately $(16.0) million.
The fair market value of our oil derivative contracts was
$(7.1) million and the fair market value of our natural gas
derivative contracts was $(0.6) million.

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| |                                                  
| | -------------------------------------------------
| | Oil Derivative Contracts at
    December 31, 2003

|                 |  |              |        |           |  |            |       |           |  |             |       |           |  |   |       |  |  |  |       |  |  |   |       | 
|---------------- |  | ------------ | ------ | --------- |  | ---------- | ----- | --------- |  | ----------- | ----- | --------- |  | - | ----- |  |  |  | ----- |  |  | - | ----- | 
|                 |  | Daily        |        | Floor     |  | Daily      |       | Cap       |  | Daily       |       | Swap     
|                 |  | Floor Volume |        | Price     |  | Cap Volume |       | Price     |  | Swap Volume |       | Price    
|Period           |  | (Bbls)       |        | (per Bbl) |  | (Bbls)     |       | (per Bbl) |  | (Bbls)      |       | (per Bbl)
|                 |  |              |        |           |  |            |       |           |  |             |       |          
|Jan. - June 2004 |  |              | 17,000 |           |  | $          | 23.16 |           |  |             | 7,000 |           |  | $ | 29.06 |  |  |  | 500   |  |  | $ | 26.48 | 
|July - Dec. 2004 |  |              | 17,000 |           |  |            | 23.91 |           |  |             | 5,000 |           |  |   | 28.33 |  |  |  | 500   |  |  |   | 26.48 | 
|Jan. - June 2005 |  |              | 2,500  |           |  |            | 23.00 |           |  |             | 2,000 |           |  |   | 30.41 |  |  |  | 1,000 |  |  |   | 25.12 | 
|July - Dec. 2005 |  |              | 1,500  |           |  |            | 23.00 |           |  |             | 1,500 |           |  |   | 30.18 |  |  |  | 1,000 |  |  |   | 25.12 | 
|Jan. - Dec. 2006 |  |              |       |           |  |            |      |           |  |             |      |           |  |   |      |  |  |  | 2,000 |  |  |   | 25.03 | 
|Jan. - Dec. 2007 |  |              |       |           |  |            |      |           |  |             |      |           |  |   |      |  |  |  | 2,000 |  |  |   | 25.11 | 



| |                                                          
| | ---------------------------------------------------------
| | Natural Gas Derivative Contracts at
    December 31, 2003

|                 |  |              |        |           |  |            |      |           |  |             |       |           |  |   |      |  |  |  |       |  |  |   |      | 
|---------------- |  | ------------ | ------ | --------- |  | ---------- | ---- | --------- |  | ----------- | ----- | --------- |  | - | ---- |  |  |  | ----- |  |  | - | ---- | 
|                 |  | Daily        |        | Floor     |  | Daily      |      | Cap       |  | Daily       |       | Swap     
|                 |  | Floor Volume |        | Price     |  | Cap Volume |      | Price     |  | Swap Volume |       | Price    
|Period           |  | (Mcf)        |        | (per Mcf) |  | (Mcf)      |      | (per Mcf) |  | (Mcf)       |       | (per Mcf)
|                 |  |              |        |           |  |            |      |           |  |             |       |          
|Jan. - Dec. 2004 |  |              | 20,000 |           |  | $          | 4.07 |           |  |             | 7,500 |           |  | $ | 6.02 |  |  |  | 5,000 |  |  | $ | 5.01 | 
|Jan. - Dec. 2004 |  |              |       |           |  |            |     |           |  |             |      |           |  |   |     |  |  |  | 5,000 |  |  |   | 4.63 | 

Subsequent to December 31, 2003, we entered into
several additional oil and natural gas derivative contracts. The
tables below summarize the terms of the contracts entered into
from January 1, 2004 through March 4, 2004:



| |                                                         
| | --------------------------------------------------------
| | Additional Oil Derivative Contracts at
    March 4, 2004

|                 |  |              |       |           |  |            |       |           |  |             |       |           |  |   |       |  |  |  |   |  |  |  |   | 
|---------------- |  | ------------ | ----- | --------- |  | ---------- | ----- | --------- |  | ----------- | ----- | --------- |  | - | ----- |  |  |  | - |  |  |  | - | 
|                 |  | Daily        |       | Floor     |  | Daily      |       | Cap       |  | Daily       |       | Swap     
|                 |  | Floor Volume |       | Price     |  | Cap Volume |       | Price     |  | Swap Volume |       | Price    
|Period           |  | (Bbls)       |       | (per Bbl) |  | (Bbls)     |       | (per Bbl) |  | (Bbls)      |       | (per Bbl)
|                 |  |              |       |           |  |            |       |           |  |             |       |          
|July - Dec. 2004 |  |              | 1,000 |           |  | $          | 31.50 |           |  |             | 1,000 |           |  | $ | 34.56 |  |  |  |  |  |  |  |  | 
|Jan. - Dec 2005  |  |              | 1,000 |           |  |            | 28.50 |           |  |             | 1,000 |           |  |   | 32.40 |  |  |  |  |  |  |  |  | 
|Jan. - Dec 2006  |  |              | 1,000 |           |  |            | 27.50 |           |  |             | 1,000 |           |  |   | 29.88 |  |  |  |  |  |  |  |  | 



| |                                                                 
| | ----------------------------------------------------------------
| | Additional Natural Gas Derivative Contracts
    at March 4, 2004

|                 |  |              |       |           |  |            |      |           |  |        |       |           |  |   |      |  |  |  |       |  |  |   |      | 
|---------------- |  | ------------ | ----- | --------- |  | ---------- | ---- | --------- |  | ------ | ----- | --------- |  | - | ---- |  |  |  | ----- |  |  | - | ---- | 
|                 |  |              |       |           |  |            |      |           |  | Daily  |       |          
|                 |  | Daily        |       | Floor     |  | Daily      |      | Cap       |  | Swap   |       | Swap     
|                 |  | Floor Volume |       | Price     |  | Cap Volume |      | Price     |  | Volume |       | Price    
|Period           |  | (Mcf)        |       | (per Mcf) |  | (Mcf)      |      | (per Mcf) |  | (Mcf)  |       | (per Mcf)
|                 |  |              |       |           |  |            |      |           |  |        |       |          
|July - Dec. 2004 |  |              |      |           |  |            |     |           |  |        |      |           |  |   |     |  |  |  | 5,000 |  |  | $ | 5.65 | 
|Jan. - Dec 2005  |  |              | 5,000 |           |  | $          | 5.05 |           |  |        | 5,000 |           |  | $ | 5.97 |  |  |  |      |  |  |   |     | 
|Jan. - Dec. 2006 |  |              | 5,000 |           |  |            | 4.85 |           |  |        | 5,000 |           |  |   | 5.68 |  |  |  |      |  |  |   |     | 

Interest Rate
Sensitivity.At December 31,
2003, we had total long-term debt of $179.0 million. Of
this amount, $150.0 million bears interest at a fixed rate
of 8 3/8%. The remaining outstanding long-term debt balance
of $29.0 million is under our credit agreement and is
subject to floating market rates of interest. Borrowings under
the credit agreement bear interest at a fluctuating rate that is
linked to LIBOR. As of December 31, 2003, we had one
outstanding interest rate swap. This swap does not qualify for
hedge accounting as it swaps fixed interest rate for a floating
interest rate tied to LIBOR. The following table summarizes the
terms of this swap:



| |                                                           
| | ----------------------------------------------------------
| | Interest Rate Derivative Contract at
    December 31, 2003

|                     |  |               |  |               |  |             |               |          |  |                   |        |  |  |   |       | 
|-------------------- |  | ------------- |  | ------------- |  | ----------- | ------------- | -------- |  | ----------------- | ------ |  |  | - | ----- | 
|                     |  |               |  |               |  |             |               |          |  | Fair Market Value
|                     |  |               |  |               |  |             |               | Encore   |  | at December 31,  
|Notional Swap Amount |  | Start Date    |  | End Date      |  | Encore Pays |               | Receives |  | 2003             
|                     |  |               |  |               |  |             |               |          |  |                  
|(In thousands)       |  |               |  |               |  |             |               |          |  | (In thousands)   
|$80,000              |  | June 25, 2002 |  | June 15, 2005 |  |             | LIBOR + 3.89% |          |  |                   | 8.375% |  |  | $ | 2,420 | 

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GLOSSARY OF OIL AND NATURAL GAS
TERMS

The following are abbreviations and definitions
of certain terms commonly used in the oil and natural gas
industry and this Report:

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 at standard atmospheric conditions.

Bbl/ D.One stock
tank barrel of oil or other liquid hydrocarbons 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 barrel
of oil equivalent per day, calculated by converting natural gas
to oil equivalent barrels at a ratio of six Mcf to one Bbl of
oil.

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 or in close proximity to an area of known
production targeting existing reservoirs.

Exploratory Well.A
well drilled to find and produce oil or natural gas in an
unproved area or to find a new reservoir in a field previously
found to be productive of oil or natural gas in another
reservoir.

Finding, Development, and Acquisition
(FD&A) Costs.Capital
costs incurred in the finding, development, acquisition,
exploitation, improved recovery, and revisions of proved oil and
natural gas reserves, excluding non-cash asset retirement
obligations.

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).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.

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.All direct and 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.

MBbl.One thousand
barrels of oil or other liquid hydrocarbons.

MBOE.One thousand
barrels of oil equivalent, calculated by converting gas to oil
equivalent barrels at a ratio of six Mcf to one Bbl of oil.

Mcf.One thousand
cubic feet of natural gas.

Mcf/ D.One thousand
cubic feet of natural gas per day.

Mcfe.One thousand
cubic feet of natural gas equivalent, calculated by converting
oil to natural gas equivalent at a ratio of one Bbl of oil to
six Mcf.

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

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
cubic feet of natural gas.

Net Acres or Net
Wells.Gross acres or wells
multiplied, as the case may be, 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
taxes and lease operating expense.

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%.

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 where such techniques have been proved
effective by actual tests in the area and in the same reservoir.

Reserve-To-Production Index or 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.

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% 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.

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##### Table of Contents



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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##### Table of Contents








|        |                                                
|------- | -----------------------------------------------
|Item 8. | Financial Statements and Supplementary
    Data

|                                                                                                             |  |  |    | 
|------------------------------------------------------------------------------------------------------------ |  |  | -- | 
|Independent Auditors Report                                                                                 |  |  | 49 | 
|Consolidated Balance Sheets as of
    December 31, 2003 and 2002                                             |  |  | 51 | 
|Consolidated Statements of Operations for the
    Years Ended December 31, 2003, 2002, and 2001              |  |  | 52 | 
|Consolidated Statement of Stockholders
    Equity for the Years Ended December 31, 2003, 2002,
    and 2001 |  |  | 53 | 
|Consolidated Statements of Cash Flows for the
    Years Ended December 31, 2003, 2002, and 2001              |  |  | 54 | 
|Notes to Consolidated Financial Statements                                                                   |  |  | 55 | 
|Supplemental Information                                                                                     |  |  | 74 | 

48



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##### Table of Contents



REPORT OF INDEPENDENT AUDITORS

To the Board of Directors and Shareholders of
Encore Acquisition Company:

We have audited the accompanying consolidated
balance sheets of Encore Acquisition Company and subsidiaries
(the Company) as of December 31, 2003 and 2002,
and the related consolidated statements of operations,
stockholders equity, and cash flows for years then ended.
These financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these financial statements based on our audits. The
financial statements of Encore Acquisition Company as of
December 31, 2001, and for the year then ended were audited
by other auditors who have ceased operations. Those auditors
expressed an unqualified opinion on those financial statements
in their report dated March 1, 2002.

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

In our opinion, the consolidated financial
statements referred to above present fairly, in all material
respects, the consolidated financial position of Encore
Acquisition Company and subsidiaries at December 31, 2003
and 2002, and the consolidated results of their operations and
their cash flows for the years then ended, in conformity with
accounting principles generally accepted in the United States.

As explained in Note 2 to the consolidated
financial statements, effective January 1, 2003, the
Company adopted Statement of Financial Accounting Standards
No. 143, Accounting for Asset Retirement
Obligations.



| |                      
| | ---------------------
| | /s/ ERNST & YOUNG LLP

Fort Worth, Texas

February 6, 2004


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REPORT OF INDEPENDENT PUBLIC
ACCOUNTANTS

To the Shareholders of Encore Acquisition Company:

We have audited the accompanying consolidated
balance sheets of Encore Acquisition Company (a Delaware
corporation) and subsidiaries as of December 31, 2001 and
2000, and the related consolidated statements of operations,
stockholders equity, and cash flows for each of the three
years in the period ended December 31, 2001. These
financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred
to above present fairly, in all material respects, the financial
position of Encore Acquisition Company and subsidiaries as of
December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 2001, in conformity with
accounting principles generally accepted in the United States.

As explained in Note 2 to the financial
statements, effective January 1, 2001, the Company changed
its method of accounting for derivatives.



| |                    
| | -------------------
| | ARTHUR ANDERSEN LLP

Dallas, Texas

March 1, 2002


Subsequent to the completion of the audit of the
Companys 2001 financial statements, Arthur Andersen LLP
was convicted of obstruction of justice charges relating to a
federal investigation of Enron Corporation and ceased operations
as a public accounting firm. Accordingly, the report of
independent public accountants included above is a copy of a
report previously issued by Arthur Andersen. Arthur Andersen has
not reissued its report for inclusion in this document.

50



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##### Table of Contents



ENCORE ACQUISITION COMPANY



CONSOLIDATED BALANCE SHEETS


|                                                                   |                                                                                                                      |                                            |         |          |         |  |         |         |         | 
|------------------------------------------------------------------ | -------------------------------------------------------------------------------------------------------------------- | ------------------------------------------ | ------- | -------- | ------- |  | ------- | ------- | ------- | 
|                                                                   |                                                                                                                      |                                           
|                                                                   |                                                                                                                      | December 31,                              
|                                                                   |                                                                                                                      |                                           
|                                                                   |                                                                                                                      | 2003                                       |         | 2002    
|                                                                   |                                                                                                                      |                                            |         |         
|                                                                   |                                                                                                                      |                                           
|                                                                   |                                                                                                                      | (In thousands                             
|                                                                   |                                                                                                                      | except share data)                        
|ASSETS                                                            
|Current assets:                                                    |                                                                                                                      |                                            |         |          |         |  |         |        
|                                                                   | Cash and cash equivalents                                                                                            |                                            | $       | 431      |         |  | $       | 13,057  |        
|                                                                   | Accounts receivable (net of allowance of $0 and
    $7.0 million, respectively)                                      |                                            |         | 27,640   |         |  |         | 21,981  |        
|                                                                   | Inventory                                                                                                            |                                            |         | 6,019    |         |  |         | 5,032   |        
|                                                                   | Derivative assets                                                                                                    |                                            |         | 5,588    |         |  |         | 3,245   |        
|                                                                   | Deferred tax asset                                                                                                   |                                            |         | 3,592    |         |  |         | 4,833   |        
|                                                                   | Other current assets                                                                                                 |                                            |         | 1,673    |         |  |         | 1,317   |        
|                                                                   |                                                                                                                      |                                            |         |          |         |  |         |        
|                                                                   |                                                                                                                      | Total current assets                       |         |          | 44,943  |  |         |         | 49,465  | 
|                                                                   |                                                                                                                      |                                            |         |          |         |  |         |        
|Properties and equipment, at cost 
    successful efforts method: |                                                                                                                      |                                            |         |          |         |  |         |        
|                                                                   | Producing properties                                                                                                 |                                            |         | 739,288  |         |  |         | 581,012 |        
|                                                                   | Undeveloped properties                                                                                               |                                            |         | 921      |         |  |         | 1,168   |        
|                                                                   | Accumulated depletion, depreciation, and
    amortization                                                            |                                            |         | (124,646 | )       |  |         | (94,356 | )      
|                                                                   |                                                                                                                      |                                            |         |          |         |  |         |        
|                                                                   |                                                                                                                      |                                            | 615,563 |          |         |  | 487,824 |        
|                                                                   |                                                                                                                      |                                            |         |          |         |  |         |        
|                                                                   | Other property and equipment                                                                                         |                                            |         | 3,831    |         |  |         | 3,680   |        
|                                                                   | Accumulated depreciation                                                                                             |                                            |         | (2,586   | )       |  |         | (1,917  | )      
|                                                                   |                                                                                                                      |                                            |         |          |         |  |         |        
|                                                                   |                                                                                                                      |                                            | 1,245   |          |         |  | 1,763   |        
|                                                                   |                                                                                                                      |                                            |         |          |         |  |         |        
|Other assets                                                       |                                                                                                                      |                                            | 10,387  |          |         |  | 10,844  |        
|                                                                   |                                                                                                                      |                                            |         |          |         |  |         |        
|                                                                   |                                                                                                                      | Total assets                               |         | $        | 672,138 |  |         | $       | 549,896 | 
|                                                                   |                                                                                                                      |                                            |         |          |         |  |         |        
|                                                                  
|LIABILITIES AND STOCKHOLDERS
    EQUITY                          
|Current liabilities:                                               |                                                                                                                      |                                            |         |          |         |  |         |        
|                                                                   | Accounts payable                                                                                                     |                                            | $       | 10,668   |         |  | $       | 9,650   |        
|                                                                   | Accrued lease operations expense                                                                                     |                                            |         | 2,507    |         |  |         | 2,373   |        
|                                                                   | Accrued development capital                                                                                          |                                            |         | 9,302    |         |  |         | 4,500   |        
|                                                                   | Derivative liabilities                                                                                               |                                            |         | 8,026    |         |  |         | 8,558   |        
|                                                                   | Production and severance taxes payable                                                                               |                                            |         | 5,365    |         |  |         | 4,822   |        
|                                                                   | Other current liabilities                                                                                            |                                            |         | 9,127    |         |  |         | 7,073   |        
|                                                                   |                                                                                                                      |                                            |         |          |         |  |         |        
|                                                                   |                                                                                                                      | Total current liabilities                  |         |          | 44,995  |  |         |         | 36,976  | 
|                                                                   |                                                                                                                      |                                            |         |          |         |  |         |        
|Derivative liabilities                                             |                                                                                                                      |                                            | 3,514   |          |         |  | 2,998   |        
|Future abandonment cost                                            |                                                                                                                      |                                            | 5,341   |          |         |  |        |        
|Deferred tax liability                                             |                                                                                                                      |                                            | 80,313  |          |         |  | 47,656  |        
|Long-term debt                                                     |                                                                                                                      |                                            | 179,000 |          |         |  | 166,000 |        
|                                                                   |                                                                                                                      |                                            |         |          |         |  |         |        
|                                                                   |                                                                                                                      | Total liabilities                          |         |          | 313,163 |  |         |         | 253,630 | 
|                                                                   |                                                                                                                      |                                            |         |          |         |  |         |        
|Commitments and contingencies                                      |                                                                                                                      |                                            |        |          |         |  |        |        
|Stockholders equity:                                              |                                                                                                                      |                                            |         |          |         |  |         |        
|                                                                   | Preferred stock, $.01 par value,
    5,000,000 shares authorized, none issued and outstanding                        |                                            |         |         |         |  |         |        |        
|                                                                   | Common stock, $.01 par value,
    60,000,000 shares authorized, 30,335,693 and 30,162,955
    issued and outstanding |                                            |         | 303      |         |  |         | 302     |        
|                                                                   | Additional paid-in capital                                                                                           |                                            |         | 253,865  |         |  |         | 251,231 |        
|                                                                   | Deferred compensation                                                                                                |                                            |         | (2,528   | )       |  |         | (2,396  | )      
|                                                                   | Retained earnings                                                                                                    |                                            |         | 117,365  |         |  |         | 53,724  |        
|                                                                   | Accumulated other comprehensive income                                                                               |                                            |         | (10,030  | )       |  |         | (6,595  | )      
|                                                                   |                                                                                                                      |                                            |         |          |         |  |         |        
|                                                                   |                                                                                                                      | Total stockholders equity                 |         |          | 358,975 |  |         |         | 296,266 | 
|                                                                   |                                                                                                                      |                                            |         |          |         |  |         |        
|                                                                   |                                                                                                                      | Total liabilities and stockholders equity |         | $        | 672,138 |  |         | $       | 549,896 | 
|                                                                   |                                                                                                                      |                                            |         |          |         |  |         |        

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

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ENCORE ACQUISITION COMPANY



CONSOLIDATED STATEMENTS OF
OPERATIONS


|                                                                           |                                                                              |                                             |         |         |        |      |         |         |        |   |         |         |        | 
|-------------------------------------------------------------------------- | ---------------------------------------------------------------------------- | ------------------------------------------- | ------- | ------- | ------ | ---- | ------- | ------- | ------ | - | ------- | ------- | ------ | 
|                                                                           |                                                                              |                                            
|                                                                           |                                                                              | Year Ended December 31,                    
|                                                                           |                                                                              |                                            
|                                                                           |                                                                              | 2003                                        |         | 2002    |        | 2001
|                                                                           |                                                                              |                                             |         |         |        |     
|                                                                           |                                                                              |                                            
|                                                                           |                                                                              | (In thousands except per share data)       
|Revenues:                                                                  |                                                                              |                                             |         |         |        |      |         |         |        |   |         |        
|                                                                           | Oil                                                                          |                                             | $       | 176,351 |        |      | $       | 134,854 |        |   | $       | 105,768 |       
|                                                                           | Natural gas                                                                  |                                             |         | 43,745  |        |      |         | 25,838  |        |   |         | 30,149  |       
|                                                                           |                                                                              |                                             |         |         |        |      |         |         |        |   |         |        
|Total revenues                                                             |                                                                              |                                             | 220,096 |         |        |      | 160,692 |         |        |   | 135,917 |        
|                                                                           |                                                                              |                                             |         |         |        |      |         |         |        |   |         |        
|Expenses:                                                                  |                                                                              |                                             |         |         |        |      |         |         |        |   |         |        
|                                                                           | Production                                                                  |                                             |         |         |        |      |         |         |        |   |         |         |       
|                                                                           |                                                                              | Lease operations                            |         |         | 37,846 |      |         |         | 30,678 |   |         |         | 25,139 | 
|                                                                           |                                                                              | Production, ad valorem, and severance taxes |         |         | 22,013 |      |         |         | 15,653 |   |         |         | 13,809 | 
|                                                                           | Depletion, depreciation, and amortization                                    |                                             |         | 33,530  |        |      |         | 34,550  |        |   |         | 31,721  |       
|                                                                           | General and administrative (excluding non-cash
    stock based compensation) |                                             |         | 8,680   |        |      |         | 6,150   |        |   |         | 5,053   |       
|                                                                           | Non-cash stock based compensation                                            |                                             |         | 614     |        |      |         |        |        |   |         | 9,587   |       
|                                                                           | Derivative fair value (gain) loss                                            |                                             |         | (885    | )      |      |         | (900    | )      |   |         | 680     |       
|                                                                           | Bad debt expense                                                             |                                             |         |        |        |      |         |        |        |   |         | 7,005   |       
|                                                                           | Impairment of oil and natural gas properties                                 |                                             |         |        |        |      |         |        |        |   |         | 2,598   |       
|                                                                           | Other operating expense                                                      |                                             |         | 3,481   |        |      |         | 2,045   |        |   |         | 934     |       
|                                                                           |                                                                              |                                             |         |         |        |      |         |         |        |   |         |        
|Total expenses                                                             |                                                                              |                                             | 105,279 |         |        |      | 88,176  |         |        |   | 96,526  |        
|                                                                           |                                                                              |                                             |         |         |        |      |         |         |        |   |         |        
|Operating income                                                           |                                                                              |                                             | 114,817 |         |        |      | 72,516  |         |        |   | 39,391  |        
|                                                                           |                                                                              |                                             |         |         |        |      |         |         |        |   |         |        
|Other income (expenses):                                                   |                                                                              |                                             |         |         |        |      |         |         |        |   |         |        
|                                                                           | Interest                                                                     |                                             |         | (16,151 | )      |      |         | (12,306 | )      |   |         | (6,041  | )     
|                                                                           | Other                                                                        |                                             |         | 214     |        |      |         | 91      |        |   |         | 46      |       
|                                                                           |                                                                              |                                             |         |         |        |      |         |         |        |   |         |        
|Total other income (expenses)                                              |                                                                              |                                             | (15,937 | )       |        |      | (12,215 | )       |        |   | (5,995  | )      
|                                                                           |                                                                              |                                             |         |         |        |      |         |         |        |   |         |        
|Income before income taxes and cumulative effect
    of accounting change  |                                                                              |                                             | 98,880  |         |        |      | 60,301  |         |        |   | 33,396  |        
|Current income tax benefit (provision)                                     |                                                                              |                                             | (991    | )       |        |      | 745     |         |        |   | (1,919  | )      
|Deferred income tax provision                                              |                                                                              |                                             | (35,111 | )       |        |      | (23,361 | )       |        |   | (14,414 | )      
|                                                                           |                                                                              |                                             |         |         |        |      |         |         |        |   |         |        
|Income before cumulative effect of accounting
    change                   |                                                                              |                                             | 62,778  |         |        |      | 37,685  |         |        |   | 17,063  |        
|Cumulative effect of accounting change, net of
    income taxes            |                                                                              |                                             | 863     |         |        |      |        |         |        |   | (884    | )      
|                                                                           |                                                                              |                                             |         |         |        |      |         |         |        |   |         |        
|Net income                                                                 |                                                                              | $                                           | 63,641  |         |        | $    | 37,685  |         |        | $ | 16,179  |        
|                                                                           |                                                                              |                                             |         |         |        |      |         |         |        |   |         |        
|Income before cumulative effect of accounting
    change per common share: |                                                                              |                                             |         |         |        |      |         |         |        |   |         |        
|                                                                           | Basic                                                                        |                                             | $       | 2.09    |        |      | $       | 1.25    |        |   | $       | 0.59    |       
|                                                                           | Diluted                                                                      |                                             |         | 2.07    |        |      |         | 1.25    |        |   |         | 0.59    |       
|Net income per common share:                                               |                                                                              |                                             |         |         |        |      |         |         |        |   |         |        
|                                                                           | Basic                                                                        |                                             | $       | 2.11    |        |      | $       | 1.25    |        |   | $       | 0.56    |       
|                                                                           | Diluted                                                                      |                                             |         | 2.10    |        |      |         | 1.25    |        |   |         | 0.56    |       
|Weighted average common shares outstanding:                                |                                                                              |                                             |         |         |        |      |         |         |        |   |         |        
|                                                                           | Basic                                                                        |                                             |         | 30,102  |        |      |         | 30,031  |        |   |         | 28,718  |       
|                                                                           | Diluted                                                                      |                                             |         | 30,333  |        |      |         | 30,161  |        |   |         | 28,723  |       

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

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ENCORE ACQUISITION COMPANY



CONSOLIDATED STATEMENT OF STOCKHOLDERS
EQUITY


|                                                                            |                                                                            |                                  |    |         |  |        |    |            |  |            |     |          |  |              |          |           |   |               |     |               |  |   |          |   |  |   |        |      |   |   |         |        |  |   |         |         |   |   |          |         |  
|--------------------------------------------------------------------------- | -------------------------------------------------------------------------- | -------------------------------- | -- | ------- |  | ------ | -- | ---------- |  | ---------- | --- | -------- |  | ------------ | -------- | --------- | - | ------------- | --- | ------------- |  | - | -------- | - |  | - | ------ | ---- | - | - | ------- | ------ |  | - | ------- | ------- | - | - | -------- | ------- | -
|                                                                            |                                                                            |                                  |    |         |  |        |    |            |  | Notes      |     |          |  |              |          |           |   | Accumulated   |     |              
|                                                                            |                                                                            | Class A                          |    | Class B |  |        |    | Additional |  | Receivable |     |          |  |              |          | Retained  |   | Other         |     | Total        
|                                                                            |                                                                            | Common                           |    | Common  |  | Common |    | Paid-In    |  | Officers/  |     | Treasury |  | Deferred     |          | Earnings  |   | Comprehensive |     | Stockholders
|                                                                            |                                                                            | Stock                            |    | Stock   |  | Stock  |    | Capital    |  | Employees  |     | Stock    |  | Compensation |          | (Deficit) |   | Income        |     | Equity       
|                                                                            |                                                                            |                                  |    |         |  |        |    |            |  |            |     |          |  |              |          |           |   |               |     |              
|                                                                            |                                                                            |                                 
|                                                                            |                                                                            | (In thousands except share data)
|Balance at December 31, 2000                                                |                                                                            | $                                | 1  |         |  | $      | 3  |            |  | $          |    |          |  | $            | 147,968  |           |   | $             | (21 | )             |  | $ |         |   |  | $ |       |      |   | $ | (140    | )      |  | $ |        |         |   | $ | 147,811  |        
|Proceeds from initial public offering (net of
    offering costs of $1,568) |                                                                            |                                  |   |         |  |        |   |            |  |            | 71  |          |  |              | 91,456   |           |   |               |    |               |  |   |         |   |  |   |       |      |   |   |        |        |  |   |        |         |   |   | 91,527   |        
|Non-cash stock based compensation                                           |                                                                            |                                  |   |         |  |        |   |            |  |            |    |          |  |              | 9,587    |           |   |               |    |               |  |   |         |   |  |   |       |      |   |   |        |        |  |   |        |         |   |   | 9,587    |        
|Recapitalization                                                            |                                                                            |                                  | (1 | )       |  |        | (3 | )          |  |            | 229 |          |  |              | (225     | )         |   |               |    |               |  |   |         |   |  |   |       |      |   |   |        |        |  |   |        |         |   |   |         |        
|Repayment of notes receivable 
    officers and employees                  |                                                                            |                                  |   |         |  |        |   |            |  |            |    |          |  |              |         |           |   |               | 21  |               |  |   |         |   |  |   |       |      |   |   |        |        |  |   |        |         |   |   | 21       |        
|Components of comprehensive income:                                         |                                                                            |                                  |    |         |  |        |    |            |  |            |     |          |  |              |          |           |   |               |     |               |  |   |          |   |  |   |        |      |   |   |         |        |  |   |         |         |   |   |          |        
|                                                                            | Net income                                                                 |                                  |    |        |  |        |    |           |  |            |     |         |  |              |          |          |   |               |     |              |  |   |          |  |  |   |        |     |   |   |         | 16,179 |  |   |         |        |   |   |          | 16,179  |  
|                                                                            | Change in deferred hedge gain/loss (net of income
    taxes of $12,226)    |                                  |    |        |  |        |    |           |  |            |     |         |  |              |          |          |   |               |     |              |  |   |          |  |  |   |        |     |   |   |         |       |  |   |         | 19,058  |   |   |          | 19,058  |  
|                                                                            | Cumulative effect of accounting change (net of
    income taxes of $9,121) |                                  |    |        |  |        |    |           |  |            |     |         |  |              |          |          |   |               |     |              |  |   |          |  |  |   |        |     |   |   |         |       |  |   |         | (14,881 | ) |   |          | (14,881 | )
|                                                                            |                                                                            |                                  |    |         |  |        |    |            |  |            |     |          |  |              |          |           |   |               |     |               |  |   |          |   |  |   |        |      |   |   |         |        |  |   |         |         |   |   |          |        
|Total comprehensive income                                                  |                                                                            |                                  |    |         |  |        |    |            |  |            |     |          |  |              |          |           |   |               |     |               |  |   |          |   |  |   |        |      |   |   |         |        |  |   |         |         |   |   | 20,356   |        
|                                                                            |                                                                            |                                  |    |         |  |        |    |            |  |            |     |          |  |              |          |           |   |               |     |               |  |   |          |   |  |   |        |      |   |   |         |        |  |   |         |         |   |   |          |        
|Balance at December 31, 2001                                                |                                                                            |                                  |   |         |  |        |   |            |  |            | 300 |          |  |              | 248,786  |           |   |               |    |               |  |   |         |   |  |   |       |      |   |   | 16,039  |        |  |   | 4,177   |         |   |   | 269,302  |        
|Exercise of stock options                                                   |                                                                            |                                  |   |         |  |        |   |            |  |            |    |          |  |              | 51       |           |   |               |    |               |  |   |         |   |  |   |       |      |   |   |        |        |  |   |        |         |   |   | 51       |        
|Issuance of restricted stock                                                |                                                                            |                                  |   |         |  |        |   |            |  |            | 2   |          |  |              | 2,394    |           |   |               |    |               |  |   |         |   |  |   | (2,396 | )    |   |   |        |        |  |   |        |         |   |   |         |        
|Components of comprehensive income:                                         |                                                                            |                                  |    |         |  |        |    |            |  |            |     |          |  |              |          |           |   |               |     |               |  |   |          |   |  |   |        |      |   |   |         |        |  |   |         |         |   |   |          |        
|                                                                            | Net income                                                                 |                                  |    |        |  |        |    |           |  |            |     |         |  |              |          |          |   |               |     |              |  |   |          |  |  |   |        |     |   |   |         | 37,685 |  |   |         |        |   |   |          | 37,685  |  
|                                                                            | Change in deferred hedge gain/loss (Net of income
    taxes of $6,602)     |                                  |    |        |  |        |    |           |  |            |     |         |  |              |          |          |   |               |     |              |  |   |          |  |  |   |        |     |   |   |         |       |  |   |         | (10,772 | ) |   |          | (10,772 | )
|                                                                            |                                                                            |                                  |    |         |  |        |    |            |  |            |     |          |  |              |          |           |   |               |     |               |  |   |          |   |  |   |        |      |   |   |         |        |  |   |         |         |   |   |          |        
|Total comprehensive income                                                  |                                                                            |                                  |    |         |  |        |    |            |  |            |     |          |  |              |          |           |   |               |     |               |  |   |          |   |  |   |        |      |   |   |         |        |  |   |         |         |   |   | 26,913   |        
|                                                                            |                                                                            |                                  |    |         |  |        |    |            |  |            |     |          |  |              |          |           |   |               |     |               |  |   |          |   |  |   |        |      |   |   |         |        |  |   |         |         |   |   |          |        
|Balance at December 31, 2002                                                |                                                                            |                                  |   |         |  |        |   |            |  |            | 302 |          |  |              | 251,231  |           |   |               |    |               |  |   |         |   |  |   | (2,396 | )    |   |   | 53,724  |        |  |   | (6,595  | )       |   |   | 296,266  |        
|Exercise of stock options                                                   |                                                                            |                                  |   |         |  |        |   |            |  |            | 1   |          |  |              | 1,974    |           |   |               |    |               |  |   |         |   |  |   |       |      |   |   |        |        |  |   |        |         |   |   | 1,975    |        
|Issuance of Common Stock                                                    |                                                                            |                                  |   |         |  |        |   |            |  |            | 91  |          |  |              | 175,383  |           |   |               |    |               |  |   |         |   |  |   |       |      |   |   |        |        |  |   |        |         |   |   | 175,474  |        
|Purchase of Treasury Stock                                                  |                                                                            |                                  |   |         |  |        |   |            |  |            |    |          |  |              |         |           |   |               |    |               |  |   | (175,560 | ) |  |   |       |      |   |   |        |        |  |   |        |         |   |   | (175,560 | )      
|Cancellation of Treasury Stock                                              |                                                                            |                                  |   |         |  |        |   |            |  |            | (91 | )        |  |              | (175,469 | )         |   |               |    |               |  |   | 175,560  |   |  |   |       |      |   |   |        |        |  |   |        |         |   |   |         |        
|Deferred compensation:                                                      |                                                                            |                                  |    |         |  |        |    |            |  |            |     |          |  |              |          |           |   |               |     |               |  |   |          |   |  |   |        |      |   |   |         |        |  |   |         |         |   |   |          |        
|                                                                            | Issuance of restricted Common Stock                                        |                                  |    |        |  |        |    |           |  |            |     |         |  |              |          | 927       |   |               |     |              |  |   |          |  |  |   |        | (927 | ) |   |         |       |  |   |         |        |   |   |          |        |  
|                                                                            | Amortization of expense                                                    |                                  |    |        |  |        |    |           |  |            |     |         |  |              |          |          |   |               |     |              |  |   |          |  |  |   |        | 614  |   |   |         |       |  |   |         |        |   |   |          | 614     |  
|                                                                            | Other changes                                                              |                                  |    |        |  |        |    |           |  |            |     |         |  |              |          | (181      | ) |               |     |              |  |   |          |  |  |   |        | 181  |   |   |         |       |  |   |         |        |   |   |          |        |  
|Components of comprehensive income:                                         |                                                                            |                                  |    |         |  |        |    |            |  |            |     |          |  |              |          |           |   |               |     |               |  |   |          |   |  |   |        |      |   |   |         |        |  |   |         |         |   |   |          |        
|                                                                            | Net income                                                                 |                                  |    |        |  |        |    |           |  |            |     |         |  |              |          |          |   |               |     |              |  |   |          |  |  |   |        |     |   |   |         | 63,641 |  |   |         |        |   |   |          | 63,641  |  
|                                                                            | Change in deferred hedge gain/loss (Net of income
    taxes of $2,105)     |                                  |    |        |  |        |    |           |  |            |     |         |  |              |          |          |   |               |     |              |  |   |          |  |  |   |        |     |   |   |         |       |  |   |         | (3,435  | ) |   |          | (3,435  | )
|                                                                            |                                                                            |                                  |    |         |  |        |    |            |  |            |     |          |  |              |          |           |   |               |     |               |  |   |          |   |  |   |        |      |   |   |         |        |  |   |         |         |   |   |          |        
|Total comprehensive income                                                  |                                                                            |                                  |    |         |  |        |    |            |  |            |     |          |  |              |          |           |   |               |     |               |  |   |          |   |  |   |        |      |   |   |         |        |  |   |         |         |   |   | 60,206   |        
|                                                                            |                                                                            |                                  |    |         |  |        |    |            |  |            |     |          |  |              |          |           |   |               |     |               |  |   |          |   |  |   |        |      |   |   |         |        |  |   |         |         |   |   |          |        
|Balance at December 31, 2003                                                |                                                                            | $                                |   |         |  | $      |   |            |  | $          | 303 |          |  | $            | 253,865  |           |   | $             |    |               |  | $ |         |   |  | $ | (2,528 | )    |   | $ | 117,365 |        |  | $ | (10,030 | )       |   | $ | 358,975  |        
|                                                                            |                                                                            |                                  |    |         |  |        |    |            |  |            |     |          |  |              |          |           |   |               |     |               |  |   |          |   |  |   |        |      |   |   |         |        |  |   |         |         |   |   |          |        

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

53



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##### Table of Contents



ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF CASH
FLOWS

|                                                                                      |                                                             |                                                |          |          |        |      |          |          |        |   |         |          |        |  
|------------------------------------------------------------------------------------- | ----------------------------------------------------------- | ---------------------------------------------- | -------- | -------- | ------ | ---- | -------- | -------- | ------ | - | ------- | -------- | ------ | -
|                                                                                      |                                                             |                                               
|                                                                                      |                                                             | Year Ended December  31,                      
|                                                                                      |                                                             |                                               
|                                                                                      |                                                             | 2003                                           |          | 2002     |        | 2001
|                                                                                      |                                                             |                                                |          |          |        |     
|                                                                                      |                                                             |                                               
|                                                                                      |                                                             | (In thousands)                                
|Operating activities                                                                  |                                                             |                                                |          |          |        |      |          |          |        |   |         |         
|Net income                                                                            |                                                             | $                                              | 63,641   |          |        | $    | 37,685   |          |        | $ | 16,179  |         
|Adjustments to reconcile net income to net cash
    provided by operating activities: |                                                             |                                                |          |          |        |      |          |          |        |   |         |         
|                                                                                      | Depletion, depreciation, and amortization                   |                                                |          | 33,530   |        |      |          | 34,550   |        |   |         | 31,721   |       
|                                                                                      | Deferred taxes                                              |                                                |          | 35,111   |        |      |          | 23,361   |        |   |         | 13,718   |       
|                                                                                      | Non-cash stock based compensation                           |                                                |          | 614      |        |      |          |         |        |   |         | 9,587    |       
|                                                                                      | Cumulative effect of accounting change                      |                                                |          | (863     | )      |      |          |         |        |   |         | 884      |       
|                                                                                      | Non-cash derivative fair value (gain) loss                  |                                                |          | (165     | )      |      |          | (1,239   | )      |   |         | 680      |       
|                                                                                      | Other non-cash                                              |                                                |          | 1,293    |        |      |          | 177      |        |   |         | 1,718    |       
|                                                                                      | Loss on disposition of assets                               |                                                |          | 322      |        |      |          | 254      |        |   |         | 165      |       
|                                                                                      | Bad debt expense                                            |                                                |          |         |        |      |          |         |        |   |         | 7,005    |       
|                                                                                      | Impairment of oil and natural gas properties                |                                                |          |         |        |      |          |         |        |   |         | 2,598    |       
|                                                                                      | Changes in operating assets and liabilities:                |                                                |          |          |        |      |          |          |        |   |         |          |       
|                                                                                      |                                                             | Accounts receivable                            |          |          | (5,602 | )    |          |          | (5,695 | ) |         |          | 4,564  |  
|                                                                                      |                                                             | Other current assets                           |          |          | (8,592 | )    |          |          | (3,161 | ) |         |          | (2,258 | )
|                                                                                      |                                                             | Other assets                                   |          |          | (2,024 | )    |          |          | 2,177  |   |         |          | (4,605 | )
|                                                                                      |                                                             | Accounts payable and other current liabilities |          |          | 6,553  |      |          |          | 3,400  |   |         |          | (1,744 | )
|                                                                                      |                                                             |                                                |          |          |        |      |          |          |        |   |         |         
|Cash provided by operating activities                                                 |                                                             |                                                | 123,818  |          |        |      | 91,509   |          |        |   | 80,212  |         
|Investing activities                                                                  |                                                             |                                                |          |          |        |      |          |          |        |   |         |         
|                                                                                      | Proceeds from disposition of assets                         |                                                |          | 1,295    |        |      |          | 226      |        |   |         | 310      |       
|                                                                                      | Purchases of other property and equipment                   |                                                |          | (1,464   | )      |      |          | (680     | )      |   |         | (1,091   | )     
|                                                                                      | Acquisition of oil and natural gas properties               |                                                |          | (54,601  | )      |      |          | (78,549  | )      |   |         | (1,622   | )     
|                                                                                      | Development of oil and natural gas properties               |                                                |          | (98,977  | )      |      |          | (80,313  | )      |   |         | (87,180  | )     
|                                                                                      |                                                             |                                                |          |          |        |      |          |          |        |   |         |         
|Cash used by investing activities                                                     |                                                             |                                                | (153,747 | )        |        |      | (159,316 | )        |        |   | (89,583 | )       
|Financing activities                                                                  |                                                             |                                                |          |          |        |      |          |          |        |   |         |         
|                                                                                      | Proceeds from issuance of common stock                      |                                                |          | 176,127  |        |      |          |         |        |   |         | 93,095   |       
|                                                                                      | Purchase of treasury stock                                  |                                                |          | (175,560 | )      |      |          |         |        |   |         |         |       
|                                                                                      | Offering costs paid                                         |                                                |          | (653     | )      |      |          |         |        |   |         | (1,568   | )     
|                                                                                      | Proceeds from issuance of 8 3/8% note                       |                                                |          |         |        |      |          | 150,000  |        |   |         |         |       
|                                                                                      | Payments for debt issuance costs                            |                                                |          | (125     | )      |      |          | (6,195   | )      |   |         |         |       
|                                                                                      | Exercise of stock options                                   |                                                |          | 1,975    |        |      |          | 51       |        |   |         |         |       
|                                                                                      | Proceeds from notes receivable 
    officers and employees |                                                |          |         |        |      |          |         |        |   |         | 21       |       
|                                                                                      | Proceeds from long-term debt                                |                                                |          | 112,500  |        |      |          | 144,000  |        |   |         | 161,000  |       
|                                                                                      | Payments on long-term debt                                  |                                                |          | (99,500  | )      |      |          | (206,000 | )      |   |         | (227,500 | )     
|                                                                                      | Cash overdrafts                                             |                                                |          | 2,539    |        |      |          |         |        |   |         |         |       
|                                                                                      | Payments on note payable                                    |                                                |          |         |        |      |          | (1,107   | )      |   |         | (16,438  | )     
|                                                                                      |                                                             |                                                |          |          |        |      |          |          |        |   |         |         
|Cash provided by financing activities                                                 |                                                             |                                                | 17,303   |          |        |      | 80,749   |          |        |   | 8,610   |         
|Increase (decrease) in cash and cash
    equivalents                                  |                                                             |                                                | (12,626  | )        |        |      | 12,942   |          |        |   | (761    | )       
|Cash and cash equivalents, beginning of period                                        |                                                             |                                                | 13,057   |          |        |      | 115      |          |        |   | 876     |         
|                                                                                      |                                                             |                                                |          |          |        |      |          |          |        |   |         |         
|Cash and cash equivalents, end of period                                              |                                                             | $                                              | 431      |          |        | $    | 13,057   |          |        | $ | 115     |         
|                                                                                      |                                                             |                                                |          |          |        |      |          |          |        |   |         |         

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

54



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##### Table of Contents



ENCORE ACQUISITION COMPANY



NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS




|   |                                                       
|-- | ------------------------------------------------------
|1. | Formation of the Company and Basis of
    Presentation

Encore Acquisition Company (the
Company), a Delaware Corporation, is an independent
(non-integrated) oil and natural gas company in the United
States. We were organized in April 1998 and are engaged in the
acquisition, development, exploitation, and production of North
American oil and natural gas reserves. Our oil and natural gas
reserves are concentrated in fields 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.



|   |                                               
|-- | ----------------------------------------------
|2. | Summary of Significant Accounting
    Policies



| |                            
| | ---------------------------
| | Principles of Consolidation

Our consolidated financial statements include the
accounts of all subsidiaries in which we hold a controlling
interest. All material intercompany balances and transactions
are eliminated.



| |                          
| | -------------------------
| | Cash and Cash Equivalents

Cash and cash equivalents include cash in banks,
money market accounts, and all highly liquid investments with an
original maturity of three months or less. On a bank-by-bank
basis, cash accounts that are overdrawn are reclassified to
current liabilities and any change in cash overdrafts is shown
as a financing activity in the consolidated statements of cash
flows.



| |            
| | -----------
| | Inventories

Inventories are comprised principally of
materials and supplies, which are stated at the lower of cost
(determined on an average basis) or market, and oil in
pipelines. Oil produced at the lease which resides unsold in
pipelines is carried at an amount equal to its operating costs
to produce.



| |                                   
| | ----------------------------------
| | Oil and Natural Gas
    Properties

We utilize the successful efforts method of
accounting for our oil and natural gas properties. Under this
method, all development and acquisition costs of proved
properties are capitalized and amortized on a unit-of-production
basis over the remaining life of proved developed reserves or
proved reserves, as applicable. Exploration expenses, including
geological and geophysical expenses and delay rentals, are
charged to expense as incurred. Costs of drilling exploratory
wells are initially capitalized, but charged to expense if and
when the well is determined to be unsuccessful. Expenditures for
repairs and maintenance to sustain or increase production from
the existing producing reservoir are charged to expense as
incurred. Expenditures to recomplete a current well in a
different or additional proven or unproven reservoir are
capitalized pending determination that economic reserves have
been added. If the recompletion is not successful, the
expenditures are charged to expense. Expenditures for redrilling
or directional drilling in a previously abandoned well are
classified as drilling costs to a proven or unproven reservoir
for determination of capital or expense. Significant tangible
equipment added or replaced is capitalized. Expenditures to
construct facilities or increase the productive capacity from
existing reserves are capitalized. Internal costs directly
associated with the development and exploitation of properties
are capitalized as a cost of the property and are classified
accordingly in the Companys consolidated financial
statements. Natural gas volumes are converted to equivalent
barrels at the rate of six Mcf to one barrel. See Note 2,
New Accounting Standards, on page 58 for a
discussion of Statement of Financial Accounting Standard
No. 143, Accounting for Asset Retirement
Obligations (SFAS 143), which the Company
adopted as of January 1, 2003.

55



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##### Table of Contents



ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)

The Company is required to assess the need for an
impairment of capitalized costs of oil and natural gas
properties and other long-lived assets whenever events or
circumstances indicate that the carrying value of those assets
may not be recoverable. If impairment is indicated based on a
comparison of the assets carrying value to its
undiscounted expected future net cash flows, then it is
recognized to the extent that the carrying value exceeds fair
value. Any impairment charge incurred is expensed reduces our
recorded basis in the asset.

The costs of retired, sold, or abandoned
properties that constitute part of an amortization base are
charged or credited, net of proceeds received, to the
accumulated depletion, depreciation, and amortization reserve.
Gains or losses from the disposal of other properties are
recognized in the current period.

Additionally, the Companys independent
reserve engineers estimate our reserves once a year at
December 31. This results in a new DD&A rate which the
Company uses for the preceding fourth quarter and, to the extent
no other reserve estimates change materially, the subsequent
three quarters of the following year.



| |                         
| | ------------------------
| | Stock-based Compensation

Employee stock options and restricted stock
awards are accounted for under the provisions of Accounting
Principles Board Opinion No. 25, Accounting for Stock
Issued to Employees (APB 25).
Accordingly, no compensation is recorded for stock options that
are granted to employees or non-employee directors with an
exercise price equal to or above the common stock price on the
grant date. However, expense is recorded related to restricted
stock granted to employees. If compensation expense for the
stock based awards had been determined using the provisions of
Statement of Financial Accounting Standard No. 123,
Accounting for Stock-Based Compensation
(SFAS 123), the Companys net income and
net income per share would have been adjusted to the pro forma
amounts indicated below (in thousands, except per share amounts):

|             |                                                  |                         |   |        |  |      |   |        |  |  |   |        | 
|------------ | ------------------------------------------------ | ----------------------- | - | ------ |  | ---- | - | ------ |  |  | - | ------ | 
|             |                                                  |                        
|             |                                                  | Year Ended December 31,
|             |                                                  |                        
|             |                                                  | 2003                    |   | 2002   |  | 2001
|             |                                                  |                         |   |        |  |     
|As Reported: |                                                  |                         |   |        |  |      |   |        |  |  |   |       
|             | Net income                                       |                         | $ | 63,641 |  |      | $ | 37,685 |  |  | $ | 16,179 | 
|             | Non-cash stock based compensation (net of taxes) |                         |   | 381    |  |      |   |       |  |  |   | 9,587  | 
|             | Diluted net income per share                     |                         |   | 2.10   |  |      |   | 1.25   |  |  |   | 0.56   | 
|Pro Forma:   |                                                  |                         |   |        |  |      |   |        |  |  |   |       
|             | Net income                                       |                         | $ | 62,093 |  |      | $ | 36,408 |  |  | $ | 15,475 | 
|             | Non-cash stock based compensation (net of taxes) |                         |   | 1,929  |  |      |   | 1,277  |  |  |   | 10,291 | 
|             | Diluted net income per share                     |                         |   | 2.05   |  |      |   | 1.21   |  |  |   | 0.54   | 



| |                  
| | -----------------
| | Segment Reporting

The Company has only one operating segment, the
development and exploitation of oil and natural gas reserves.
Additionally, all of our assets are located in the United States
and all of our oil and natural gas revenues are derived from
customers located in the United States.

For 2003, 28%, 26%, and 11% of total oil and
natural gas production was sold to ConocoPhillips, Shell, and
Eighty-Eight Oil, respectively. In 2002, ConAgra and Equiva
Trading Company (a joint venture between Shell and Texaco)
accounted for 16% and 10% of total oil and natural gas sales,
respectively. For 2001, 25%, 17%, and 11% of total oil and
natural gas production was sold to ConAgra, Equiva Trading
Company and EOTT Energy Co., respectively.

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ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)



| |             
| | ------------
| | Income Taxes

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



| |                    
| | -------------------
| | Revenue Recognition

Revenues are recognized for Encores share
of jointly owned properties as oil and natural gas is produced
and sold, net of royalties and net profits interest payments.
Revenues are also reduced by any processing and other fees paid
except for transportation costs paid to third parties which are
recorded as expense. Natural gas revenues are recorded using the
sales method of accounting whereby revenue is recognized as
natural gas is sold by the Company rather than as the
Companys working interest share of production. Royalties,
net profits interests, and severance taxes are paid based upon
the actual price received from the sales. To the extent actual
quantities and values of oil and natural gas are unavailable for
a given reporting period because of timing or information not
received from third parties, we estimate and record the expected
sales volumes and values for those properties. The Company also
does not recognize revenue for the production in tanks or
pipelines that has not been delivered to the purchaser yet.
Encores net oil inventories in pipelines were
46,622 Bbls and 104,954 Bbls at December 31, 2003
and 2002, respectively. Natural gas imbalances under-delivered
to Encore at December 31, 2003 and December 31, 2002,
were 446,000 MMBTU and 510,000 MMBTU, respectively.



| |               
| | --------------
| | Shipping Costs

Shipping costs in the form of pipeline fees paid
to third parties are incurred to move oil and natural gas
production from certain properties to a different market
location for ultimate sale. These costs are included in other
operating expense in our statements of operations.



| |                                   
| | ----------------------------------
| | Hedging and Related
    Activities

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

Effective January 1, 2001, the Company
adopted Statement of Financial Accounting Standards No. 133
(SFAS 133), Accounting for Derivative
Instruments and Hedging Activities. This standard requires
us to recognize all of our derivative financial instruments in
our consolidated balance sheets as either assets or liabilities
and measure them at fair value. If a derivative does not qualify
for hedge accounting, it must be adjusted to fair value through
earnings. However, if a derivative does qualify for hedge
accounting, depending on the nature of the hedge, changes in
fair value can be offset against the change in fair value of the
hedged item through earnings or recognized in other
comprehensive income until such time as the hedged item is
recognized in earnings.

To qualify for cash flow hedge accounting, the
cash flows from the hedging instrument must be highly effective
in offsetting changes in cash flows of the hedged item. In
addition, all hedging relationships must be designated,
documented, and reassessed periodically. The impact of adopting
SFAS 133 on January 1, 2001 was to record the fair
value of our derivatives as a reduction in assets of
$1.1 million and as a

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ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)

liability in the amount of $24.4 million.
Additionally, we recorded a reduction in earnings as the
cumulative effect of an accounting change of $0.9 million
(net of taxes of $0.5 million) and a decrease to
stockholders equity for other comprehensive income in the
amount of $14.9 million (net of deferred taxes of
$9.1 million).

Currently, all of our derivative financial
instruments that are designated as hedges are designated as cash
flow hedges. These instruments hedge the exposure of variability
in expected future cash flows that is attributable to a
particular risk. The effective portion of the mark-to-market
gain or loss on these derivative instruments is recorded in
other comprehensive income in stockholders equity and
reclassified into earnings in the same period in which the
hedged transaction affects earnings. Any ineffective portion of
the mark-to-market gain or loss is recognized into earnings
immediately.



| |                     
| | --------------------
| | Comprehensive Income

Comprehensive income includes net income and
other comprehensive income, which includes, effective
January 1, 2001, unrealized gains and losses on derivative
financial instruments. Encore chooses to show yearly
comprehensive income as part of its consolidated statement of
stockholders equity.



| |                 
| | ----------------
| | Use of Estimates

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

Estimates made in preparing these consolidated
financial statements include the Companys estimated proved
oil and natural gas reserve volumes used in calculating
depletion, depreciation, and amortization expense; the estimated
future cash flows and fair value of our properties used in
determining the need for any impairment write-down; and the
timing and amount of future abandonment costs used in
calculating the Companys asset retirement obligations. See
Note 4. Commitments and Contingencies 
Asset Retirement Obligations. Future changes in the
assumptions used could have a significant impact on reported
results in future periods.

New Accounting Standards

Statements of Financial Accounting Standards
No. 141, Business Combinations
(SFAS 141) and No. 142, Goodwill and
Other Intangible Assets (SFAS 142) were
issued in July 2001. SFAS 141 requires that all business
combinations entered into subsequent to June 30, 2001 be
accounted for under the purchase method of accounting and that
certain acquired intangible assets in a business combination be
recognized and reported as assets apart from goodwill.
SFAS 142 requires that amortization of goodwill be replaced
with periodic tests of the goodwills impairment at least
annually in accordance with the provisions of SFAS 142 and
that intangible assets other than goodwill be amortized over
their useful lives.

Currently, the Emerging Issues Task Force staff
are engaged in discussions on the issue of whether SFAS 141
and SFAS 142 which were effective June 30, 2001,
called for mineral rights held under a lease or other
contractual arrangement to be classified on the balance sheet as
intangible assets and accompanied by specific footnote
disclosures. Historically, oil and gas companies, including
Encore, have included these costs with all other oil and natural
gas property costs in Property, Plant, and Equipment on the
consolidated balance sheet.

In the event this interpretation is adopted, a
substantial portion of the acquisition costs of oil and natural
gas properties would be required to be classified on the balance
sheet as an intangible asset. The

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ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)

Company believes this interpretation would not
have a material effect on our results of operations for the
periods presented or in the future as these intangible assets
would be depleted using the units of production method in a
manner consistent with the method currently used to calculate
depletion, depreciation, and amortization expense on these
assets.

At December 31, 2003, the Company had
$0.9 million of undeveloped leasehold costs and
$291.5 million of developed leasehold costs (net of
accumulated depletion) that would be reclassified as
Intangible developed and undeveloped leasehold costs
if the Company were to apply the interpretation as currently
discussed.

In August 2001, the FASB issued SFAS 143,
which the Company adopted as of January 1, 2003. This
statement requires us to record a liability in the period in
which an asset retirement obligation (ARO) is
incurred. Also, upon initial recognition of the liability, we
must capitalize additional asset cost equal to the amount of the
liability. In addition to any obligations that arise after the
effective date of SFAS 143, upon initial adoption we must
recognize (1) a liability for any existing AROs,
(2) capitalized cost related to the liability, and
(3) accumulated depletion, depreciation, and amortization
on that capitalized cost.

The adoption of SFAS 143 resulted in a
January 1, 2003 cumulative effect adjustment to record
(i) a $4.0 million increase in the carrying values of
proved properties, (ii) a $2.1 million decrease in
accumulated depletion, depreciation, and amortization, and
(iii) a $5.2 million increase in other non-current
liabilities, and (iv) a gain of $0.9 million, net of
tax, as a cumulative effect of accounting change on
January 1, 2003. The Company does not include a market risk
premium in its risk estimates as the effect would not be
material.

The following table shows net income and basic
and diluted net income per common share as reported, as well as
pro forma amounts as if the Company had adopted SFAS 143
prior to January 1, 2001 (in thousands, except per common
share amounts):

|             |                                     |                         |   |        |  |      |   |        |  |  |   |        | 
|------------ | ----------------------------------- | ----------------------- | - | ------ |  | ---- | - | ------ |  |  | - | ------ | 
|             |                                     |                        
|             |                                     | Year Ended December 31,
|             |                                     |                        
|             |                                     | 2003                    |   | 2002   |  | 2001
|             |                                     |                         |   |        |  |     
|As Reported: |                                     |                         |   |        |  |      |   |        |  |  |   |       
|             | Net income                          |                         | $ | 63,641 |  |      | $ | 37,685 |  |  | $ | 16,179 | 
|             | Basic net income per common share   |                         |   | 2.11   |  |      |   | 1.25   |  |  |   | 0.56   | 
|             | Diluted net income per common share |                         |   | 2.10   |  |      |   | 1.25   |  |  |   | 0.56   | 
|Pro Forma:   |                                     |                         |   |        |  |      |   |        |  |  |   |       
|             | Net income                          |                         | $ | 62,778 |  |      | $ | 38,035 |  |  | $ | 16,549 | 
|             | Basic net income per common share   |                         |   | 2.09   |  |      |   | 1.27   |  |  |   | 0.58   | 
|             | Diluted net income per common share |                         |   | 2.07   |  |      |   | 1.26   |  |  |   | 0.58   | 

In August 2001, the FASB issued Statement of
Financial Accounting Standards No. 144, Accounting
for the Impairment or Disposal of Long-Lived Assets
(SFAS 144), which is effective for financial
statements issued for fiscal years beginning after
December 15, 2001 and interim periods within those fiscal
years. SFAS 144 requires that long-lived assets to be
disposed of by sale be measured at the lower of the carrying
amount or fair value less cost to sell, whether reported in
continuing operations or in discontinued operations.
SFAS 144 broadens the reporting of discontinued operations
to include all components of an entity with operations that can
be distinguished from the rest of the entity and that will be
eliminated from the ongoing operations of the entity in a
disposal transaction. The Company adopted SFAS No. 144
effective January 1, 2002. The Companys adoption of
this statement has not had a material effect on its financial
position or results of operations.

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ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)

In April 2002, the FASB issued SFAS 145,
Rescission of FASB Statements No. 4, 44, and 64,
Amendment of FASB Statement No. 13, and Technical
Corrections. Under Statement 4, all gains and losses
from extinguishment of debt were required to be aggregated and,
if material, classified as an extraordinary item, net of related
income tax effect. This Statement eliminates Statement 4
and, thus, the exception to applying Opinion 30 to all
gains and losses related to extinguishments of debt. As a
result, gains and losses from extinguishment of debt should be
classified as extraordinary items only if they meet the criteria
in Opinion 30. Applying the provisions of Opinion 30
will distinguish transactions that are part of an entitys
recurring operations from those that are unusual or infrequent
or that meet the criteria for classification as an extraordinary
item. This statement is effective for Encore beginning
January 1, 2003, at which time the extraordinary loss on
extinguishment of debt of $0.9 million recorded in the
second quarter of 2002 was reclassified to operating income.

In December 2002, the FASB issued
SFAS No. 148, Accounting for Stock-Based
Compensation  Transition and Disclosure, an Amendment
of FASB Statement No. 123
(SFAS 148). This Statement amends
SFAS 123, to provide alternative methods of transition for
a voluntary change to the fair value method of accounting for
stock-based employee compensation. In addition, this Statement
amends the disclosure requirements of SFAS 123 to require
prominent disclosures in both annual and interim financial
statements. Certain of the disclosure modifications are required
for fiscal years ending after December 15, 2002.
SFAS 148 has not had any effect on the Companys
financial position or results of operations. See additional
required disclosures at Note 10. Employee Benefit
Plans.



|   |             
|-- | ------------
|3. | Acquisitions



| |                  
| | -----------------
| | 2001 Acquisitions

During 2001, we made small miscellaneous
acquisitions of undeveloped acreage. No material proved property
acquisitions were made.



| |                  
| | -----------------
| | 2002 Acquisitions

On January 4, 2002 we closed the purchase of
our Central Permian properties. These properties were purchased
from Conoco for approximately $50.1 million. The properties
include two major operated fields: East Cowden Grayburg and
Fuhrman-Nix; and two non-operated fields: North Cowden and
Yates. During the second quarter of 2002, we closed a second
follow-on acquisition of additional working interests in the
East Cowden Field for $8.3 million.

On August 29, 2002, we completed an
acquisition of interests in oil and natural gas properties in
southeast Utahs Paradox Basin. The final purchase price
after the exercise of preferential rights was $17.9 million
($16.7 million after closing adjustments). The properties
are divided between two oil producing units: the Ratherford Unit
operated by ExxonMobil and the Aneth Unit operated by Chevron
Texaco.



| |                  
| | -----------------
| | 2003 Acquisitions

On July 31, 2003, we closed the initial
acquisition of the North Louisiana properties. Subsequently, we
have purchased several smaller interests in these properties.
The original purchase was effective June 1, 2003. The
Company purchased interests in natural gas properties in North
Louisiana (the Elm Grove acquisition) from a group
of private sellers at a cost of $54.6 million. Beginning
August 1, 2003, revenues and expenses from these properties
have been included in the Companys Consolidated Statements
of Operations and drilling costs have been included in
Development of oil and natural gas properties in the
Consolidated Statements of Cash Flows. From June 1, 2003 to
July 31, 2003, revenues, expenses, and development capital
of the properties were treated as adjustments to the purchase
price. The properties are

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ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)

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.

These acquisitions have been accounted for as
purchases. The operating results of the acquired properties have
been included in our consolidated financial statements since the
date of acquisition.



|   |                              
|-- | -----------------------------
|4. | Commitments and Contingencies



| |       
| | ------
| | Leases

We lease office space and equipment that have
remaining non-cancelable lease terms in excess of one year. The
following table summarizes by year our remaining non-cancelable
future payments under operating leases as of December 31,
2003 (in thousands):

|           |  |   |     | 
|---------- |  | - | --- | 
|2004       |  | $ | 951 | 
|2005       |  |   | 987 | 
|2006       |  |   | 520 | 
|2007       |  |   | 171 | 
|2008       |  |   | 171 | 
|Thereafter |  |   | 43  | 

Our operating lease rental expense was
approximately $1.5 million, $0.9 million, and
$0.7 million in 2003, 2002, and 2001, respectively.



| |                             
| | ----------------------------
| | Asset Retirement Obligations

The Companys primary asset retirement
obligations relate to future plugging and abandonment expenses
on our oil and natural gas properties and related facilities
disposal. As of December 31, 2003, the Company had
$2.7 million held in an escrow account from which funds are
released only for reimbursement of plugging and abandonment
expenses on our Bell Creek property. This amount is included in
Other assets in the accompanying Consolidated
Balance Sheet. The following table summarizes the changes in the
Companys future abandonment liability recorded in
Future abandonment cost on the Companys
Consolidated Balance Sheet from the liability initially recorded
upon adoption of SFAS 143 on January 1, 2003 through
December 31, 2003 (in thousands):

|                                                      |                                         |              |       |      |  
|----------------------------------------------------- | --------------------------------------- | ------------ | ----- | ---- | -
|                                                      |                                         | Year Ended  
|                                                      |                                         | December 31,
|                                                      |                                         | 2003        
|                                                      |                                         |             
|Future abandonment liability at January 1,
    2003   |                                         | $            | 4,791 |     
|                                                      | Acquisition of Elm Grove properties     |              |       | 337  |  
|                                                      | Wells Drilled                           |              |       | 83   |  
|                                                      | Accretion expense                       |              |       | 272  |  
|                                                      | Plugging and abandonment costs incurred |              |       | (100 | )
|                                                      | Revision of estimates                   |              |       | (42  | )
|                                                      |                                         |              |       |     
|Future abandonment liability at December 31,
    2003 |                                         | $            | 5,341 |     
|                                                      |                                         |              |       |     

The pro-forma asset retirement obligation as of
December 31, 2001 and 2000 would have been
$4.1 million and $4.2 million, respectively, had the
Company adopted SFAS 143 prior to January 1, 2001.

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ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)



|   |                                             
|-- | --------------------------------------------
|5. | Accounts Payable and Accrued
    Liabilities

Other current liabilities were as follows at
December 31 (in thousands):

|                                    |       |      |       |       |  |   |       |       | 
|----------------------------------- | ----- | ---- | ----- | ----- |  | - | ----- | ----- | 
|                                    |       | 2003 |       | 2002 
|                                    |       |      |       |      
|Cash overdrafts                     |       | $    | 2,681 |       |  | $ |      |      
|Oil and natural gas revenue payable |       |      | 1,176 |       |  |   | 4,108 |      
|Net profits payable                 |       |      | 589   |       |  |   | 237   |      
|Interest                            |       |      | 563   |       |  |   | 595   |      
|Other                               |       |      | 4,118 |       |  |   | 2,133 |      
|                                    |       |      |       |       |  |   |       |      
|                                    | Total |      | $     | 9,127 |  |   | $     | 7,073 | 
|                                    |       |      |       |       |  |   |       |      



|   |             
|-- | ------------
|6. | Indebtedness

The following table details the Companys
indebtedness at December 31 (in thousands):

|                          |       |      |         |         |  |   |         |         | 
|------------------------- | ----- | ---- | ------- | ------- |  | - | ------- | ------- | 
|                          |       | 2003 |         | 2002   
|                          |       |      |         |        
|Revolving Credit Facility |       | $    | 29,000  |         |  | $ | 16,000  |        
|8 3/8% Notes              |       |      | 150,000 |         |  |   | 150,000 |        
|                          |       |      |         |         |  |   |         |        
|                          | Total |      | $       | 179,000 |  |   | $       | 166,000 | 
|                          |       |      |         |         |  |   |         |        

Prior to restructuring our debt on June 25,
2002 (see below), the Companys operating subsidiary
maintained a credit agreement with a group of banks that matured
in May 2004. The Company guaranteed the subsidiarys
obligations under the credit agreement and pledged the stock and
other equity interests of its subsidiaries to secure the
guaranty.

On June 25, 2002, the Company sold
$150 million of 8 3/8% Senior Subordinated Notes
maturing on June 15, 2012 (the Notes). The
offering was made through a private placement pursuant to
Rule 144A. Subsequently, the Company filed a registration
statement on Form S-4/ A, which was declared effective on
December 6, 2002. The Company received net proceeds of
$145.6 million from the sale of the Notes, after deducting
debt issuance costs. The proceeds were used to repay and retire
the Companys prior credit facility ($143.0 million),
to pay the fees and expenses related to a new revolving credit
facility ($1.5 million), and to hold in reserve for the
Paradox Basin acquisition ($1.1 million).

All of the Companys subsidiaries are
currently subsidiary guarantors of the Notes. Since
(i) each subsidiary guarantor is 100% owned by the Company,
(ii) the Company has no assets or operations that are
independent of its subsidiaries, (iii) the subsidiary
guarantees are full and unconditional and joint and several and
(iv) all of the Companys subsidiaries are subsidiary
guarantors, the Company has not included the financial
statements of each subsidiary in this report. The subsidiary
guarantors may without restriction transfer funds to the Company
in the form of cash dividends, loans and advances.

Concurrently with the issuance of the Notes, the
Company also entered into a new revolving credit facility (the
Facility) on June 25, 2002. Borrowings under
the Facility are secured by a first priority lien on the
Companys proved oil and natural gas reserves. Availability
under the Facility is determined through semi-annual borrowing
base determinations and may be increased or decreased. The
amount available under the Facility at December 31, 2003
was $270.0 million, with $29.0 million outstanding as
of December 31, 2003. The maturity date of the Facility is
June 25, 2006.

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ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)

Amounts outstanding under the Facility are
subject to varying rates of interest based on the amount
outstanding and the Companys borrowing base. Based on our
current $270.0 million borrowing base, our applicable
interest rates are calculated as follows:

|                             |  |      |                | 
|---------------------------- |  | ---- | -------------- | 
|Amount Outstanding           |  | Rate
|                             |  |     
|$0 to $55,000,000            |  |      | LIBOR + 1.000% | 
|$55,000,001 to $110,000,000  |  |      | LIBOR + 1.125% | 
|$110,000,001 to $165,000,000 |  |      | LIBOR + 1.250% | 
|$165,000,001 to $198,000,000 |  |      | LIBOR + 1.500% | 
|$198,000,001 to $270,000,000 |  |      | LIBOR + 1.750% | 

During 2003 and 2002, the weighted average
interest rate under the Facility was 9.6% and 8.2%, respectively.

Additionally, under the Facility, the Company is
subject to certain affirmative, negative, and financial
covenants. These include limitations on incurrence of additional
debt, restrictions on asset dispositions and restricted
payments, maintenance of a 1.0 to 1.0 current ratio, and
maintenance of an EBITDA, as defined, to interest expense ratio
of at least 2.5 to 1.0. As of December 31, 2003, the
Company was in compliance with all covenants.

The following table illustrates the
Companys long-term debt maturities at December 31,
2003 (in thousands):

|                          |        |                        |         |         |  |             |   |             |  |            |        |        |  |   |   |   |  |   |         |         | 
|------------------------- | ------ | ---------------------- | ------- | ------- |  | ----------- | - | ----------- |  | ---------- | ------ | ------ |  | - | - | - |  | - | ------- | ------- | 
|                          |        |                       
|                          |        | Payments Due by Period
|                          |        |                       
|                          |        | Total                  |         | 2004    |  | 2005 - 2006 |   | 2007 - 2008 |  | Thereafter
|                          |        |                        |         |         |  |             |   |             |  |           
|8 3/8% Notes              |        | $                      | 150,000 |         |  | $           |  |             |  | $          |       |        |  | $ |  |   |  | $ | 150,000 |        
|Revolving credit facility |        |                        | 29,000  |         |  |             |  |             |  |            | 29,000 |        |  |   |  |   |  |   |        |        
|                          |        |                        |         |         |  |             |   |             |  |            |        |        |  |   |   |   |  |   |         |        
|                          | Totals |                        | $       | 179,000 |  |             | $ |            |  |            | $      | 29,000 |  |   | $ |  |  |   | $       | 150,000 | 
|                          |        |                        |         |         |  |             |   |             |  |            |        |        |  |   |   |   |  |   |         |        

Consolidated cash payments for interest were
$16.2 million, $13.2 million, and $6.4 million,
respectively, for 2003, 2002, and 2001.



|   |      
|-- | -----
|7. | Taxes



| |             
| | ------------
| | Income Taxes

The components of the Companys total income
tax expense including amounts related to items shown net of
income taxes on the statements of operations were attributed to
the following items (in thousands):

|                  |                                                          |                         |        |        |  |      |        |        |  |   |        |        | 
|----------------- | -------------------------------------------------------- | ----------------------- | ------ | ------ |  | ---- | ------ | ------ |  | - | ------ | ------ | 
|                  |                                                          |                        
|                  |                                                          | Year Ended December 31,
|                  |                                                          |                        
|                  |                                                          | 2003                    |        | 2002   |  | 2001
|                  |                                                          |                         |        |        |  |     
|Taxes related to: |                                                          |                         |        |        |  |      |        |        |  |   |        |       
|                  | Income before cumulative effect of accounting
    change |                         | $      | 36,102 |  |      | $      | 22,616 |  |   | $      | 16,333 | 
|                  | Cumulative effect of accounting change                   |                         |        | 529    |  |      |        |       |  |   |        | 541    | 
|                  |                                                          |                         |        |        |  |      |        |        |  |   |        |       
|Total tax expense |                                                          | $                       | 36,631 |        |  | $    | 22,616 |        |  | $ | 16,874 |       
|                  |                                                          |                         |        |        |  |      |        |        |  |   |        |       

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##### Table of Contents



ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)

The components of the income tax provision
related to income/ loss before cumulative effect of accounting
change and extraordinary loss are as follows (in thousands):

|                     |          |                         |        |        |        |      |        |        |        |   |        |        |        | 
|-------------------- | -------- | ----------------------- | ------ | ------ | ------ | ---- | ------ | ------ | ------ | - | ------ | ------ | ------ | 
|                     |          |                        
|                     |          | Year Ended December 31,
|                     |          |                        
|                     |          | 2003                    |        | 2002   |        | 2001
|                     |          |                         |        |        |        |     
|Federal:             |          |                         |        |        |        |      |        |        |        |   |        |       
|                     | Current  |                         | $      | 991    |        |      | $      | (745   | )      |   | $      | 1,919  |       
|                     | Deferred |                         |        | 32,145 |        |      |        | 21,552 |        |   |        | 13,125 |       
|                     |          |                         |        |        |        |      |        |        |        |   |        |       
|                     |          | Total federal           |        |        | 33,136 |      |        |        | 20,807 |   |        |        | 15,044 | 
|                     |          |                         |        |        |        |      |        |        |        |   |        |       
|State:               |          |                         |        |        |        |      |        |        |        |   |        |       
|                     | Current  |                         |        |       |        |      |        |       |        |   |        |       |       
|                     | Deferred |                         |        | 2,966  |        |      |        | 1,809  |        |   |        | 1,289  |       
|                     |          |                         |        |        |        |      |        |        |        |   |        |       
|                     |          | Total state             |        |        | 2,966  |      |        |        | 1,809  |   |        |        | 1,289  | 
|                     |          |                         |        |        |        |      |        |        |        |   |        |       
|Income tax provision |          | $                       | 36,102 |        |        | $    | 22,616 |        |        | $ | 16,333 |       
|                     |          |                         |        |        |        |      |        |        |        |   |        |       

Reconciliation of income tax expense with tax at
the Federal statutory rate is as follows (in thousands):

|                                           |                      |                         |        |        |  |      |        |        |  |   |        |        | 
|------------------------------------------ | -------------------- | ----------------------- | ------ | ------ |  | ---- | ------ | ------ |  | - | ------ | ------ | 
|                                           |                      |                        
|                                           |                      | Year Ended December 31,
|                                           |                      |                        
|                                           |                      | 2003                    |        | 2002   |  | 2001
|                                           |                      |                         |        |        |  |     
|Income before income taxes                 |                      | $                       | 98,880 |        |  | $    | 60,301 |        |  | $ | 33,396 |       
|                                           |                      |                         |        |        |  |      |        |        |  |   |        |       
|Tax at statutory rate                      |                      | $                       | 34,608 |        |  | $    | 21,105 |        |  | $ | 11,689 |       
|State income taxes, net of federal benefit |                      |                         | 2,966  |        |  |      | 1,809  |        |  |   | 1,289  |       
|Non-cash stock based compensation          |                      |                         |       |        |  |      |       |        |  |   | 3,355  |       
|Section 29 & 43 credits                    |                      |                         | (1,322 | )      |  |      | (632   | )      |  |   |       |       
|Other                                      |                      |                         | (150   | )      |  |      | 334    |        |  |   |       |       
|                                           |                      |                         |        |        |  |      |        |        |  |   |        |       
|                                           | Income tax provision |                         | $      | 36,102 |  |      | $      | 22,616 |  |   | $      | 16,333 | 
|                                           |                      |                         |        |        |  |      |        |        |  |   |        |       

The major components of the net current deferred
tax asset and net long-term deferred tax liability are as
follows at December 31 (in thousands):

|                               |                                                         |                                        |       |       |        |   |       |       |       |  
|------------------------------ | ------------------------------------------------------- | -------------------------------------- | ----- | ----- | ------ | - | ----- | ----- | ----- | -
|                               |                                                         |                                       
|                               |                                                         | December 31,                          
|                               |                                                         |                                       
|                               |                                                         | 2003                                   |       | 2002 
|                               |                                                         |                                        |       |      
|Current:                       |                                                         |                                        |       |       |        |   |       |      
|Assets:                        |                                                         |                                        |       |       |        |   |       |      
|                               | Allowance for bad debt                                  |                                        | $     |      |        |   | $     | 984   |      
|                               | Unrealized hedge loss in other comprehensive
    income |                                        |       | 4,626 |        |   |       | 3,883 |      
|                               | Other                                                   |                                        |       |      |        |   |       | 65    |      
|                               |                                                         |                                        |       |       |        |   |       |      
|                               |                                                         | Total current deferred tax assets      |       |       | 4,626  |   |       |       | 4,932 |  
|                               |                                                         |                                        |       |       |        |   |       |      
|Liabilities:                   |                                                         |                                        |       |       |        |   |       |      
|                               | Derivative fair value loss                              |                                        |       | (881  | )      |   |       | (99   | )    
|                               | Other                                                   |                                        |       | (153  | )      |   |       |      |      
|                               |                                                         |                                        |       |       |        |   |       |      
|                               |                                                         | Total current deferred tax liabilities |       |       | (1,034 | ) |       |       | (99   | )
|                               |                                                         |                                        |       |       |        |   |       |      
|Net current deferred tax asset |                                                         | $                                      | 3,592 |       |        | $ | 4,833 |      
|                               |                                                         |                                        |       |       |        |   |       |      

64



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##### Table of Contents



ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)

|                                     |                                                                         |                                     |         |         |       |   |         |         |       | 
|------------------------------------ | ----------------------------------------------------------------------- | ----------------------------------- | ------- | ------- | ----- | - | ------- | ------- | ----- | 
|                                     |                                                                         |                                    
|                                     |                                                                         | December 31,                       
|                                     |                                                                         |                                    
|                                     |                                                                         | 2003                                |         | 2002   
|                                     |                                                                         |                                     |         |        
|Long-term:                           |                                                                         |                                     |         |         |       |   |         |        
|Assets:                              |                                                                         |                                     |         |         |       |   |         |        
|                                     | Alternative minimum tax                                                 |                                     | $       | 1,972   |       |   | $       | 1,312   |      
|                                     | Unrealized hedge loss in other comprehensive
    income                 |                                     |         | 1,453   |       |   |         | 159     |      
|Section 43 credits                   |                                                                         |                                     | 1,062   |         |       |   | 1,019   |        
|                                     | Other                                                                   |                                     |         | 251     |       |   |         | 14      |      
|                                     |                                                                         |                                     |         |         |       |   |         |        
|                                     |                                                                         | Total long-term deferred tax assets |         |         | 4,738 |   |         |         | 2,504 | 
|                                     |                                                                         |                                     |         |         |       |   |         |        
|Liabilities:                         |                                                                         |                                     |         |         |       |   |         |        
|                                     | Book basis of oil and natural gas properties in
    excess of tax basis |                                     |         | (85,051 | )     |   |         | (50,160 | )    
|                                     |                                                                         |                                     |         |         |       |   |         |        
|Net long-term deferred tax liability |                                                                         | $                                   | (80,313 | )       |       | $ | (47,656 | )      
|                                     |                                                                         |                                     |         |         |       |   |         |        

Cash income tax payments in the amount of
$1.5 million were made in 2003 and in 2001. No cash income
tax payments were made in 2002.



| |                              
| | -----------------------------
| | Taxes Other than Income Taxes

Taxes other than income taxes were comprised of
the following (in thousands):

|                                   |       |                         |        |        |  |      |        |        |  |   |        |        | 
|---------------------------------- | ----- | ----------------------- | ------ | ------ |  | ---- | ------ | ------ |  | - | ------ | ------ | 
|                                   |       |                        
|                                   |       | Year Ended December 31,
|                                   |       |                        
|                                   |       | 2003                    |        | 2002   |  | 2001
|                                   |       |                         |        |        |  |     
|Production and severance           |       | $                       | 19,999 |        |  | $    | 14,397 |        |  | $ | 13,303 |       
|Property and ad valorem            |       |                         | 2,014  |        |  |      | 1,256  |        |  |   | 506    |       
|Franchise, payroll and other taxes |       |                         | 677    |        |  |      | 383    |        |  |   | 316    |       
|                                   |       |                         |        |        |  |      |        |        |  |   |        |       
|                                   | Total |                         | $      | 22,690 |  |      | $      | 16,036 |  |   | $      | 14,125 | 
|                                   |       |                         |        |        |  |      |        |        |  |   |        |       



|   |                     
|-- | --------------------
|8. | Stockholders Equity



| |                                     
| | ------------------------------------
| | Public Offerings of Common
    Stock

On March 8, 2001, the Company priced its
shares to be issued in its initial public offering
(IPO) and began trading on the New York Stock
Exchange the following day under the ticker symbol
EAC. Immediately prior to Encores IPO, all of
the outstanding shares of Class A and Class B stock
held by management and institutional investors were converted
into 2,630,203 and 20,249,758 shares, respectively, of a
single class of common stock. Through the IPO, the Company sold
an additional 7,150,000 shares of common stock to the
public at the offering price of $14.00 per share, resulting
in total outstanding shares of 30,029,961. The Company received
$91.5 million in net proceeds after deducting the
underwriters discounts and commissions and related
offering expenses. The proceeds received from the IPO were used
to pay down debt outstanding under our credit facility.

On November 13, 2003, the Company priced a
public offering of 8.0 million shares of Encores
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. The Company used all of the
net proceeds to repurchase 6,866,643 shares of
Encores 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 the Company purchased were
retired upon

65



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##### Table of Contents



ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)

repurchase. Encores 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
Encores common stock and Warburg Pincus beneficially owns
24.5% of Encores common stock.



| |                              
| | -----------------------------
| | Common Stock Option Exercises

During the years ended December 31, 2003 and
2002, employees of the Company exercised 145,727 and 3,666
options, respectively. The Company received proceeds from the
option exercises of $2.0 million and $0.1 million in
the years ended December 31, 2003 and 2002, respectively,
related to these option exercises.



| |                
| | ---------------
| | Preferred Stock

The Company has authorized a class of
undesignated preferred stock consisting of
5,000,000 shares, none of which are issued and outstanding.
The Board of Directors has not determined the rights and
privileges of holders of such preferred stock and we have no
current plans to issue any shares of preferred stock.



| |                                                               
| | --------------------------------------------------------------
| | Non-Cash Stock Based Compensation Expense
    on Class A Stock

The Company followed variable plan accounting for
the Class A stock sold to management. Accordingly,
compensation expense was based on the excess of the estimated
fair value of the Class A stock over the amount paid by the
shareholders. Compensation expense was adjusted in each
reporting period based on the most recent fair value estimates
until the measurement date occurred. Compensation expense was
recorded over the expected service period of the Class A
stock, which was based on a vesting schedule. The Class A
stock vested 25% upon issuance and an additional 15% per
year for the following five years. Prior to September 1,
2000, the Company estimated the fair value of our Class A
common stock based on discounted cash flow estimates of our oil
and natural gas properties. Beginning on September 1, 2000,
we estimated the fair value of the Class A stock based on
90% of the estimated offering price in the Companys IPO.
The measurement date occurred on March 8, 2001, the date of
the IPO, as after this date the Class A shareholders were
no longer required to make future capital contributions. Total
compensation expense on the Class A shares using the IPO
price of $14.00 per share was $35.6 million. Based on
the estimated fair values and vesting at the end of each period,
the Company recorded $9.6 million of compensation expense
for 2001 and $26.0 million in 2000. The $9.6 million
recorded in 2001 represented the final compensation expense to
be recorded related to the Class A shares.



|   |                           
|-- | --------------------------
|9. | Earnings Per Share (EPS)

Under Statement of Financial Accounting Standards
No. 128, the Company must report basic EPS, which excludes
the effect of potentially dilutive securities, and diluted EPS,
which includes the effect of all potentially dilutive
securities. EPS for the periods presented is based on weighted
average common shares outstanding for the period.

66



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##### Table of Contents



ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)

The following table reflects EPS data for the
years ended December 31 (in thousands, except per share
data):

|                                                                                   |            |                         |        |        |  |      |        |        |  |   |        |        | 
|---------------------------------------------------------------------------------- | ---------- | ----------------------- | ------ | ------ |  | ---- | ------ | ------ |  | - | ------ | ------ | 
|                                                                                   |            |                        
|                                                                                   |            | Year Ended December 31,
|                                                                                   |            |                        
|                                                                                   |            | 2003                    |        | 2002   |  | 2001
|                                                                                   |            |                         |        |        |  |     
|Numerator:                                                                         |            |                         |        |        |  |      |        |        |  |   |        |       
|Income before cumulative effect of accounting
    change                           |            | $                       | 62,778 |        |  | $    | 37,685 |        |  | $ | 17,063 |       
|Cumulative effect of accounting change                                             |            |                         | 863    |        |  |      |       |        |  |   | (884   | )     
|                                                                                   |            |                         |        |        |  |      |        |        |  |   |        |       
|                                                                                   | Net income |                         | $      | 63,641 |  |      | $      | 37,685 |  |   | $      | 16,179 | 
|                                                                                   |            |                         |        |        |  |      |        |        |  |   |        |       
|Denominator:                                                                       |            |                         |        |        |  |      |        |        |  |   |        |       
|Denominator for basic earnings per
    share  weighted average shares outstanding |            |                         | 30,102 |        |  |      | 30,031 |        |  |   | 28,718 |       
|Effect of dilutive options and dilutive
    restricted stock(a)                    |            |                         | 231    |        |  |      | 130    |        |  |   | 5      |       
|                                                                                   |            |                         |        |        |  |      |        |        |  |   |        |       
|Denominator for diluted earnings per share                                         |            |                         | 30,333 |        |  |      | 30,161 |        |  |   | 28,723 |       
|                                                                                   |            |                         |        |        |  |      |        |        |  |   |        |       
|Basic income per common share before accounting
    change                         |            | $                       | 2.09   |        |  | $    | 1.25   |        |  | $ | 0.59   |       
|Cumulative effect of accounting change, net of tax                                 |            |                         | 0.02   |        |  |      |       |        |  |   | (0.03  | )     
|                                                                                   |            |                         |        |        |  |      |        |        |  |   |        |       
|Basic income per common share after accounting
    change                          |            | $                       | 2.11   |        |  | $    | 1.25   |        |  | $ | 0.56   |       
|Diluted income per common share before accounting
    change                       |            | $                       | 2.07   |        |  | $    | 1.25   |        |  | $ | 0.59   |       
|Cumulative effect of accounting change, net of tax                                 |            |                         | 0.03   |        |  |      |       |        |  |   | (0.03  | )     
|                                                                                   |            |                         |        |        |  |      |        |        |  |   |        |       
|Diluted income per common share after accounting
    change                        |            | $                       | 2.10   |        |  | $    | 1.25   |        |  | $ | 0.56   |       
|                                                                                   |            |                         |        |        |  |      |        |        |  |   |        |       



---



|    |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) |  | There were no antidilutive options or
    antidilutive restricted stock outstanding for the year ended
    December 31, 2003 and December 31, 2001. Options to
    purchase 272,177 shares of common stock were outstanding
    but not included in the above calculation of 2002 diluted
    earnings per share because their effect would be antidilutive.
    Additionally, the Company issued 129,328 shares of
    restricted stock at the end of 2002 which are not included in
    the calculation of 2002 diluted earnings per share because their
    effect on the shares outstanding would be nominal.



|    |                       
|--- | ----------------------
|10. | Employee Benefit Plans



| |            
| | -----------
| | 401(k) plan

We make contributions to the Encore Acquisition
Company 401(k) Plan, which is a voluntary and contributory plan
for eligible employees. Our contributions, which are based on a
percentage of matching employee contributions, totaled
$0.5 million in 2003, $0.5 million in 2002, and
$0.4 million in 2001. The Companys 401(k) plan does
not currently allow employees to invest in securities of the
Company.



| |                      
| | ---------------------
| | Incentive Stock Plans

During 2000, the Companys Board of
Directors approved the 2000 Incentive Stock Plan (the
Plan). The purpose of the Plan is to attract,
motivate, and retain selected employees of the Company and to
provide the Company with the ability to provide incentives more
directly linked to the profitability of the business and
increases in shareholder value. All directors and full-time
regular employees of the Company and its subsidiaries and
affiliates are eligible to be granted awards under the Plan. The
total number of shares of common stock reserved and available
for distribution pursuant to the Plan is 1.8 million. The
Plan provides for the granting of incentive stock options,
non-qualified stock options, and restricted stock at the
discretion of the Companys Board of Directors.

67



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##### Table of Contents



ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)

All options granted under the Plan have a strike
price equal to the market price on the date of grant.
Additionally, all have a ten-year life and vest equally over a
two or three-year period. The following table summarizes the
changes in the number of outstanding options and their related
weighted average strike prices during 2003, 2002, and 2001:

|                                 |            |                         |           |                         |   |                         |       |              |  |           |           |              |   |   |       |       |  |  |         |         |   |   |       |       | 
|-------------------------------- | ---------- | ----------------------- | --------- | ----------------------- | - | ----------------------- | ----- | ------------ |  | --------- | --------- | ------------ | - | - | ----- | ----- |  |  | ------- | ------- | - | - | ----- | ----- | 
|                                 |            |                         |           |                         |   |                        
|                                 |            | Year Ended December 31, |           | Year Ended December 31, |   | Year Ended December 31,
|                                 |            | 2003                    |           | 2002                    |   | 2001                   
|                                 |            |                         |           |                         |   |                        
|                                 |            |                         |           | Weighted                |   |                         |       | Weighted     |  |           |           | Weighted    
|                                 |            | Number of               |           | Average                 |   | Number of               |       | Average      |  | Number of |           | Average     
|                                 |            | Options                 |           | Strike Price            |   | Options                 |       | Strike Price |  | Options   |           | Strike Price
|                                 |            |                         |           |                         |   |                         |       |              |  |           |           |             
|Outstanding at beginning of year |            |                         | 1,178,511 |                         |   | $                       | 14.62 |              |  |           | 847,500   |              |   | $ | 13.44 |       |  |  |        |         |   | $ |      |      
|                                 | Granted(a) |                         |           | 49,792                  |   |                         |       | 19.45        |  |           |           | 378,177      |   |   |       | 17.21 |  |  |         | 940,000 |   |   |       | 13.49 | 
|                                 | Forfeited  |                         |           | (119,622                | ) |                         |       | 16.11        |  |           |           | (43,500      | ) |   |       | 14.24 |  |  |         | (92,500 | ) |   |       | 14.00 | 
|                                 | Exercised  |                         |           | (145,727                | ) |                         |       | 13.43        |  |           |           | (3,666       | ) |   |       | 14.00 |  |  |         |        |   |   |       |      | 
|                                 |            |                         |           |                         |   |                         |       |              |  |           |           |              |   |   |       |       |  |  |         |         |   |   |       |      
|Outstanding at end of year       |            |                         | 962,954   |                         |   |                         | 14.86 |              |  |           | 1,178,511 |              |   |   | 14.62 |       |  |  | 847,500 |         |   |   | 13.44 |      
|                                 |            |                         |           |                         |   |                         |       |              |  |           |           |              |   |   |       |       |  |  |         |         |   |   |       |      
|Exercisable at end of year       |            |                         | 581,610   |                         |   |                         | 13.95 |              |  |           | 324,278   |              |   |   | 13.31 |       |  |  |        |         |   |   |      |      
|                                 |            |                         |           |                         |   |                         |       |              |  |           |           |              |   |   |       |       |  |  |         |         |   |   |       |      



---



|    |  |                                                                                                                                                                                                                                                  
|--- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) |  | During 2003 and 2002, 15,000 and none of the
    options granted, respectively, were granted to non-employee
    directors. The weighted average fair value of individual options
    granted in 2003 and 2002 was $6.38 and $6.91, respectively.

Additional information about common stock options
outstanding and exercisable at December 31, 2003 is as
follows:

|                                 |  |                     |         |              |  |              |     |  |  |   |       | 
|-------------------------------- |  | ------------------- | ------- | ------------ |  | ------------ | --- |  |  | - | ----- | 
|                                 |  |                    
|                                 |  | Options Outstanding
|                                 |  |                    
|                                 |  |                     |         | Weighted     |  | Weighted    
|                                 |  | Number of           |         | Average Life |  | Average     
|Range of Strike Prices per Share |  | Options             |         | (Years)      |  | Strike Price
|                                 |  |                     |         |              |  |             
|$12.49 to $14.00                 |  |                     | 682,667 |              |  |              | 7.5 |  |  | $ | 13.37 | 
|$14.01 to $20.41                 |  |                     | 280,287 |              |  |              | 9.0 |  |  |   | 18.50 | 

Under the Plan during 2003 and 2002, the Company
issued 45,461 and 129,328 shares, respectively, of
restricted common stock to employees. Of these,
45,461 shares issued in 2003 and 77,901 shares issued
in 2002 vest in equal installments over a five year period
evenly in years three, four, and five and depend only on
continued employment for future issuance. These represent a
fixed award per APB 25 and compensation expense is being
recorded over the related five-year service period. Of the
remaining 51,427 shares issued in 2002, only 34,464 remain
outstanding at December 31, 2003. These were issued to two
members of senior management and also vest in equal installments
over a five year period evenly in years three, four, and five.
However, these shares not only depend on the passage of time and
continued employment, but on certain performance measures for
their future issuance. These represent a variable award under
APB 25, and thus, the full amount of compensation expense
to be recorded for these shares will not be known until their
eventual issuance as it is dependent on the price of the
Companys common stock on that date. The closing stock
price on the date of grant in 2002 was $18.60 and was $24.65 on
December 31, 2003.

68



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##### Table of Contents



ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)



| |                     
| | --------------------
| | SFAS 123 disclosures

Under SFAS 123, the fair value of each stock
option grant is estimated on the date of grant using the
Black-Scholes option-pricing model. See Stock-based
Compensation in Note 2. The following amounts
represent weighted average values used in the model to calculate
the fair value of the options granted during 2003, 2002,
and 2001:

|                        |  |              |         |              |  |              |         |  |  |  |         | 
|----------------------- |  | ------------ | ------- | ------------ |  | ------------ | ------- |  |  |  | ------- | 
|                        |  | Year Ended   |         | Year Ended   |  | Year Ended  
|                        |  | December 31, |         | December 31, |  | December 31,
|                        |  | 2003         |         | 2002         |  | 2001        
|                        |  |              |         |              |  |             
|Risk free interest rate |  |              | 3.0%    |              |  |              | 3.4%    |  |  |  | 4.4%    | 
|Expected life           |  |              | 4 years |              |  |              | 4 years |  |  |  | 4 years | 
|Expected volatility     |  |              | 36.5%   |              |  |              | 46.7%   |  |  |  | 28.9%   | 
|Expected dividend yield |  |              | 0.0%    |              |  |              | 0.0%    |  |  |  | 0.0%    | 



|    |                      
|--- | ---------------------
|11. | Financial Instruments

The following table sets forth the book value and
estimated fair value of the Companys financial instruments
(in thousands):

|                               |  |                   |          |                   |  |            |          |            |  |   |          |   |  |   |          |  
|------------------------------ |  | ----------------- | -------- | ----------------- |  | ---------- | -------- | ---------- |  | - | -------- | - |  | - | -------- | -
|                               |  |                   |          |                  
|                               |  | December 31, 2003 |          | December 31, 2002
|                               |  |                   |          |                  
|                               |  | Book Value        |          | Fair Value        |  | Book Value |          | Fair Value
|                               |  |                   |          |                   |  |            |          |           
|Cash and cash equivalents      |  | $                 | 431      |                   |  | $          | 431      |            |  | $ | 13,057   |   |  | $ | 13,057   |  
|Accounts receivable, net       |  |                   | 27,640   |                   |  |            | 27,640   |            |  |   | 21,981   |   |  |   | 21,981   |  
|Accounts payable               |  |                   | (10,668  | )                 |  |            | (10,668  | )          |  |   | (9,650   | ) |  |   | (9,650   | )
|8 3/8% Notes                   |  |                   | (150,000 | )                 |  |            | (162,750 | )          |  |   | (150,000 | ) |  |   | (161,000 | )
|Revolving credit facility      |  |                   | (29,000  | )                 |  |            | (29,000  | )          |  |   | (16,000  | ) |  |   | (16,000  | )
|Commodity derivative contracts |  |                   | (7,768   | )                 |  |            | (7,768   | )          |  |   | (5,047   | ) |  |   | (5,047   | )
|Interest rate swaps            |  |                   | 2,420    |                   |  |            | 2,420    |            |  |   | (1,325   | ) |  |   | (1,325   | )
|Plugging bond                  |  |                   | 589      |                   |  |            | 643      |            |  |   | 554      |   |  |   | 633      |  

The book value of cash and cash equivalents
approximates fair value because of the short maturity of these
instruments. The fair value of our 8 3/8% bonds was
determined using their open market quote as of December 31,
2003. The difference between book value and fair value
represents the premium on that date. The book value of the
Facility approximates the fair value as the interest rate is
variable. The plugging bond is classified as held to maturity
and therefore is recorded at amortized cost, which at
December 31, 2003 is less than fair value. Commodity
contracts and interest rate swaps are marked to market each
quarter in accordance with the provisions of SFAS 133.



| |                      
| | ---------------------
| | Commodity Derivatives

The Company hedges commodity price risk with swap
contracts, put contracts, and collar contracts and hedges
interest rate risk with swap contracts. Swap contracts provide a
fixed price for a notional amount of volume. Put contracts
provide a fixed floor price on a notional amount of volume while
allowing full price participation if the relevant index price
closes above the floor price. Collar contracts provide floor
price for a notional amount of volume while allowing some
additional price participation if the relevant index price
closes above the floor price. Additionally, we occasionally sell
put contracts with a strike price well below the floor price of
the collar. These short put contracts do not qualify for hedge
accounting under SFAS 133, and accordingly, the
mark-to-market change in the value of these contracts is
recorded as fair value gain/loss in the statement of operations.

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ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)

The Company has several oil and natural gas put
contracts in place at December 31, 2003 which the Company
did not designate as cash flow hedges, and thus they are also
marked to market through earnings each quarter. Some instances
management has determined it is more cost effective to not
designate certain derivatives as hedges. At December 31,
2003, we had oil put contracts of 1,500 Bbls per day in the
first half of 2004, 2,500 Bbls of oil put contracts in the
second half of 2004, and natural gas put contracts of
5,000 Mcf per day for 2004 that were not designated as cash
flow hedges. The fair value of these contracts at
December 31, 2003 was $0.9 million.

In order to more effectively hedge the cash flows
received on our oil and natural gas production, the Company
enters into financial instruments whereby we swap certain per
Bbl or per Mcf floating market indices for a fixed amount. These
market indices are a component of the price the Company is paid
on its actual production and by fixing this component of our
marketing price, we are able to realize a net price with a more
consistent differential to NYMEX. Since NYMEX is the basis of
all our derivative oil hedging contracts and some of our natural
gas contracts, a more consistent differential results in more
effective hedges. However, management has elected not to use
hedge accounting for certain of these contracts. Instead, we
mark these contracts to market each quarter through
Derivative fair value (gain) loss in the
Consolidated Statements of Operations. Thus, as these contracts
do not change the Companys overall hedged volumes, average
prices presented in the table below are exclusive of any effect
of these non-hedge instruments. As of December 31, 2003,
the mark-to-market value of these contracts is $0.1 million.

The following tables summarize our open commodity
derivative positions designated as cash flow hedges as of
December 31, 2003:



| |                                    
| | -----------------------------------
| | Oil Hedges at December 31,
    2003

|                 |  |             |        |           |  |           |       |           |  |            |       |           |  |                |       |  |  |  |       |  |  |   |       |  |  |   |        |  
|---------------- |  | ----------- | ------ | --------- |  | --------- | ----- | --------- |  | ---------- | ----- | --------- |  | -------------- | ----- |  |  |  | ----- |  |  | - | ----- |  |  | - | ------ | -
|                 |  | Daily Floor |        | Floor     |  | Daily Cap |       | Cap       |  | Daily Swap |       | Swap      |  | Fair Market   
|                 |  | Volume      |        | Price     |  | Volume    |       | Price     |  | Volume     |       | Price     |  | Value         
|Period           |  | (Bbls)      |        | (per Bbl) |  | (Bbls)    |       | (per Bbl) |  | (Bbls)     |       | (per Bbl) |  | (In thousands)
|                 |  |             |        |           |  |           |       |           |  |            |       |           |  |               
|Jan.  June 2004 |  |             | 15,500 |           |  | $         | 22.98 |           |  |            | 7,000 |           |  | $              | 29.06 |  |  |  | 500   |  |  | $ | 26.48 |  |  | $ | (3,679 | )
|July  Dec. 2004 |  |             | 14,500 |           |  |           | 23.72 |           |  |            | 5,000 |           |  |                | 28.33 |  |  |  | 500   |  |  |   | 26.48 |  |  |   | (1,203 | )
|Jan.  June 2005 |  |             | 2,500  |           |  |           | 23.00 |           |  |            | 2,000 |           |  |                | 30.41 |  |  |  | 1,000 |  |  |   | 25.12 |  |  |   | (421   | )
|July  Dec. 2005 |  |             | 1,500  |           |  |           | 23.00 |           |  |            | 1,500 |           |  |                | 30.18 |  |  |  | 1,000 |  |  |   | 25.12 |  |  |   | (509   | )
|Jan.  Dec. 2006 |  |             |       |           |  |           |      |           |  |            |      |           |  |                |      |  |  |  | 2,000 |  |  |   | 25.03 |  |  |   | (1,139 | )
|Jan.  Dec. 2007 |  |             |       |           |  |           |      |           |  |            |      |           |  |                |      |  |  |  | 2,000 |  |  |   | 25.11 |  |  |   | (1,029 | )



| |                                            
| | -------------------------------------------
| | Natural Gas Hedges at December 31,
    2003

|                 |  |             |        |          |  |           |      |           |  |            |       |           |  |                |      |  |  |  |       |  |  |   |      |  |  |   |      |  
|---------------- |  | ----------- | ------ | -------- |  | --------- | ---- | --------- |  | ---------- | ----- | --------- |  | -------------- | ---- |  |  |  | ----- |  |  | - | ---- |  |  | - | ---- | -
|                 |  | Daily Floor |        | Floor    |  | Daily Cap |      | Cap       |  | Daily Swap |       | Swap      |  | Fair Market   
|                 |  | Volume      |        | Price    |  | Volume    |      | Price     |  | Volume     |       | Price     |  | Value         
|Period           |  | (Mcf)       |        | (per cf) |  | (Mcf)     |      | (per Mcf) |  | (Mcf)      |       | (per Mcf) |  | (In thousands)
|                 |  |             |        |          |  |           |      |           |  |            |       |           |  |               
|Jan.  Dec. 2004 |  |             | 15,000 |          |  | $         | 4.02 |           |  |            | 7,500 |           |  | $              | 6.03 |  |  |  | 5,000 |  |  | $ | 5.01 |  |  | $ | (477 | )
|Jan.  Dec. 2005 |  |             |       |          |  |           |     |           |  |            |      |           |  |                |     |  |  |  | 5,000 |  |  |   | 4.63 |  |  |   | (311 | )

As a result of all of our hedging transactions
for oil and natural gas we recognized a pre-tax reduction in
revenues of approximately $15.3 million, $5.2 million,
and $12.8 million in 2003, 2002, and 2001, respectively.
Based on the fair value of our hedges at December 31, 2003,
our unrealized pre-tax loss recorded in other comprehensive
income related to outstanding hedges is $13.9 million for
oil and $2.1 million for natural gas. Of the total deferred
hedge loss at December 31, 2003 related to commodity
contracts, $12.1 million relates to 2004 contracts, and
$1.7 million, $1.2 million, $1.0 million relate
to 2005, 2006, and 2007 contracts, respectively.

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ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)



| |                          
| | -------------------------
| | Interest Rate Derivatives

As discussed in Note 6.
Indebtedness, in conjunction with the sale of the Notes,
the Company repaid all amounts outstanding under its previous
credit facility on June 25, 2002, and terminated the prior
revolving credit facility on that date. At the time, the Company
had three interest rate swaps outstanding, with a notional
amount of $30 million each, which swapped LIBOR based
floating rates for fixed rates. According to the provisions of
SFAS 133, these no longer qualified for hedge accounting.
Their unrealized loss of $3.8 million through June 25,
2002 was recognized in accumulated other comprehensive income,
and is being amortized to interest expense over the original
life of the swaps as follows (in thousands):

|     |       |             |      |             |  |             |      |             |  |       |      |   |  |   |      |   |  |   |        |        |  
|---- | ----- | ----------- | ---- | ----------- |  | ----------- | ---- | ----------- |  | ----- | ---- | - |  | - | ---- | - |  | - | ------ | ------ | -
|Year |       | 1st Quarter |      | 2nd Quarter |  | 3rd Quarter |      | 4th Quarter |  | Total
|     |       |             |      |             |  |             |      |             |  |      
|2002 |       | $           |     |             |  | $           | (59  | )           |  | $     | (806 | ) |  | $ | (754 | ) |  | $ | (1,619 | )     
|2003 |       |             | (654 | )           |  |             | (544 | )           |  |       | (414 | ) |  |   | (297 | ) |  |   | (1,909 | )     
|2004 |       |             | (212 | )           |  |             | (153 | )           |  |       | (109 | ) |  |   | (72  | ) |  |   | (546   | )     
|2005 |       |             | (40  | )           |  |             | 72   |             |  |       | 85   |   |  |   | 60   |   |  |   | 177    |       
|2006 |       |             | 22   |             |  |             | 24   |             |  |       | 29   |   |  |   | 33   |   |  |   | 108    |       
|2007 |       |             | 38   |             |  |             | 1    |             |  |       |     |   |  |   |     |   |  |   | 39     |       
|     |       |             |      |             |  |             |      |             |  |       |      |   |  |   |      |   |  |   |        |       
|     | Total |             |      |             |  |             |      |             |  |       |      |   |  |   |      |   |  |   | $      | (3,750 | )
|     |       |             |      |             |  |             |      |             |  |       |      |   |  |   |      |   |  |   |        |       

During the third quarter of 2002, the Company
cash settled one of three interest rate swaps discussed above
and during the first quarter of 2003, the Company cash settled
the remaining two. This resulted in a gain of $0.6 million
in 2003 and a loss of $0.4 million in 2002, which was
included in Derivative fair value (gain) loss
in the Statements of Operations.

The following table summarizes the Companys
only remaining interest rate swap contract at December 31,
2003:

|                    |  |                 |            |             |  |          |               |                |  |  |        |  |  |   |       | 
|------------------- |  | --------------- | ---------- | ----------- |  | -------- | ------------- | -------------- |  |  | ------ |  |  | - | ----- | 
|                    |  |                 |            |             |  |          |               | Fair Market   
|                    |  |                 |            |             |  | Encore   |               | Value         
|Contract Expiration |  | Notional Amount |            | Encore Pays |  | Receives |               | (In thousands)
|                    |  |                 |            |             |  |          |               |               
|June 2005           |  | $               | 80,000,000 |             |  |          | LIBOR + 3.89% |                |  |  | 8.375% |  |  | $ | 2,420 | 

As a result of our hedging transactions for
interest, we recognized in interest expense a pre-tax loss of
approximately $1.9 million, $1.6 million, and
$0.7 million in 2003, 2002, and 2001, respectively.
Additionally, $1.5 million gain was recognized in
Derivative fair value (gain) loss in 2003 for
settlements and changes in fair value of our current interest
rate swap, which does not qualify for hedge accounting.

The actual gains or losses we realize from our
derivative transactions may vary significantly from the deferred
loss amount recorded in equity at December 31, 2003 due to
fluctuation of prices in the commodities markets and/or
fluctuations in the floating LIBOR interest rate.



| |                  
| | -----------------
| | Counterparty Risk

The Companys counterparties to hedging
contracts include: Paribas BNP; Deutsche Bank; Koch; Morgan
Stanley; Mitsui & Co; Shell Trading; Credit Lyonnais;
J. Aron & Company, a wholly-owned subsidiary of
Goldman, Sachs & Co. Approximately 35%, 23%, 20%, and
16% of estimated oil production hedged is committed to Morgan
Stanley, J. Aron & Company, Deutsche Bank, and Credit
Lyonnais, respectively. Approximately 42%, 33%, and 25% of our
hedged gas production is contracted with BNP Paribas, J.
Aron & Company, and Morgan Stanley, respectively.
Performance on all of J. Aron & Companys
contracts with the Company is guaranteed by their parent
Goldman, Sachs & Co. We feel the credit-worthiness of
our current counterparties is sound and we do not anticipate any
non-performance of

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ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)

contractual obligations. However, as long as each
counterparty maintains an investment grade credit rating,
pursuant to our hedging contracts, no collateral is required.

In order to mitigate the credit risk of financial
instruments, the Company enters into master netting agreements
with significant counterparties. The master netting agreement is
a standardized, bilateral contract between the Company and a
given counterparty. Instead of treating each financial
transaction between the Company and its counterparty separately,
the master netting agreement enables the Company and its
counterparty to aggregate all financial trades and treat them as
a single agreement. This arrangement benefits the Company in
three ways. First, the netting of the value of all trades
reduces the requirements of daily collateral posting by the
Company. Second, default by a counterparty under one financial
trade can trigger rights for the Company to terminate all
financial trades with such counterparty. Third, netting of
settlement amounts reduces the Companys credit exposure to
a given counterparty in the event of close-out.



|    |                            
|--- | ---------------------------
|12. | Termination of Enron Hedges

On December 2, 2001, Enron Corp. and certain
subsidiaries, including Enron North America Corp.
(Enron), each filed voluntary petitions for relief
under Chapter 11 of Title 11 of the United States
Bankruptcy Code. Prior to this date, the Company had entered
into oil and natural gas hedging contracts with Enron, many of
which were set to expire at December 31, 2001; however,
others related to 2002 and 2003. As a result of the
Chapter 11 bankruptcy declaration and pursuant to the terms
of the Companys contract with Enron, we terminated all
outstanding oil and natural gas derivative contracts with Enron
as of December 12, 2001. According to the terms of the
contract, Enron is liable to the Company for the mark-to-market
value of all contracts outstanding on that date, which totaled
$6.6 million. Additionally, Enron failed to make timely
payment of $0.4 million in 2001 hedge settlements. Both of
these amounts remained outstanding as of December 31, 2001.
Due to the uncertainty of future collection of any or all of the
amounts owed to the Company by Enron, the Company recorded an
allowance for the full amount of the receivable of
$7.0 million.

At the time of termination, the market price of
our commodity contracts with Enron exceeded their amortized cost
on our balance sheet, giving rise to a gain. In accordance with
the provisions of SFAS 133, this gain was recorded in other
comprehensive income and was reversed into earnings during 2003
and 2002. The following table illustrates the amortization of
this amount to revenue by year (in thousands):

|       |       |         |       |             |  |       |       |       |  |   |       |       | 
|------ | ----- | ------- | ----- | ----------- |  | ----- | ----- | ----- |  | - | ----- | ----- | 
|       |       | Oil     |       | Natural Gas |  |      
|Period |       | Revenue |       | Revenue     |  | Total
|       |       |         |       |             |  |      
|2002   |       | $       | 2,822 |             |  | $     | 1,594 |       |  | $ | 4,416 |      
|2003   |       |         | 401   |             |  |       | 18    |       |  |   | 419   |      
|       |       |         |       |             |  |       |       |       |  |   |       |      
|       | Total |         | $     | 3,223       |  |       | $     | 1,612 |  |   | $     | 4,835 | 
|       |       |         |       |             |  |       |       |       |  |   |       |      

During the first quarter of 2003, due to
continued uncertainty of any ultimate collection and continuing
legal fees, the Company sold its entire Enron receivable to a
third party for $0.5 million. As the receivable was fully
reserved, this amount was recorded as a gain in 2003 and
included in Other operating expense in the
Consolidated Statements of Operations. The Company no longer has
any claims outstanding against Enron and accordingly has
eliminated the previously recorded $7.0 million receivable
and related allowance from the accompanying consolidated balance
sheet as of December 31, 2003.

The Company actively evaluates the credit
exposure related to its derivatives and receivables, and
considers its history with the debtor, how long the amount has
been outstanding, potential offsets to the amount owed, and
general economic conditions. Other than the Enron loss, the
Company has not become aware of any conditions which warrant an
allowance or write-off of a receivable or derivative position.

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ENCORE ACQUISITION COMPANY


NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS  (Continued)



|    |                                
|--- | -------------------------------
|13. | Impairment of Long-Lived Assets

Throughout 2001, futures prices for oil and
natural gas continued to decline from their December 31,
2000 levels. The SEC price case used for our 2000 reserve
estimate was $26.80 per Bbl and $9.77 per Mcf dropping
to $19.84 per Bbl and $2.57 per Mcf for the 2001
estimate. Although the SEC price case does not necessarily
coincide with managements estimates of future prices, this
indicated the need to assess our oil and natural gas properties
for any possible impairment. Thus, we compared the undiscounted
future cash flows for each of our oil and natural gas properties
to their net book value, which indicated the need for an
impairment charge on certain properties. We then compared the
net book value of the impaired assets to their estimated fair
value, which resulted in a write-down of the value of proved oil
and natural gas properties of $2.6 million. Fair value was
determined using estimates of future production volumes and
estimates of future prices we might receive for these volumes
discounted back to a present value using a rate commensurate
with the risks inherent in the industry. We performed a similar
review at December 31, 2003 and 2002, and determined no
impairment charge was necessary.



|    |                              
|--- | -----------------------------
|14. | Subsequent Events (unaudited)

On March 2, 2004, the Company 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. The Company intends to fund the acquisition
initially with bank debt under the Companys existing
credit facility. The acquired oil and natural gas assets 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, however,
the closing is subject in some respects to the Companys
due diligence review and other closing conditions, and there can
be no assurance that the closing will occur as expected.

In connection with the Cortez acquisition, we
entered into several oil and natural gas hedges subsequent to
December 31, 2003. The table below shows the terms of these
contracts as of March 4, 2004:



| |                                                         
| | --------------------------------------------------------
| | Additional Oil Derivative Contracts at
    March 4, 2004

|                 |  |             |       |           |  |           |       |           |  |            |       |           |  |   |       |  |  |  |   |  |  |  |   | 
|---------------- |  | ----------- | ----- | --------- |  | --------- | ----- | --------- |  | ---------- | ----- | --------- |  | - | ----- |  |  |  | - |  |  |  | - | 
|                 |  | Daily Floor |       | Floor     |  | Daily Cap |       | Cap       |  | Daily Swap |       | Swap     
|                 |  | Volume      |       | Price     |  | Volume    |       | Price     |  | Volume     |       | Price    
|Period           |  | (Bbls)      |       | (per Bbl) |  | (Bbls)    |       | (per Bbl) |  | (Bbls)     |       | (per Bbl)
|                 |  |             |       |           |  |           |       |           |  |            |       |          
|July  Dec. 2004 |  |             | 1,000 |           |  | $         | 31.50 |           |  |            | 1,000 |           |  | $ | 34.56 |  |  |  |  |  |  |  |  | 
|Jan.  Dec 2005  |  |             | 1,000 |           |  |           | 28.50 |           |  |            | 1,000 |           |  |   | 32.40 |  |  |  |  |  |  |  |  | 
|Jan.  Dec 2006  |  |             | 1,000 |           |  |           | 27.50 |           |  |            | 1,000 |           |  |   | 29.88 |  |  |  |  |  |  |  |  | 



| |                                                                 
| | ----------------------------------------------------------------
| | Additional Natural Gas Derivative Contracts
    at March 4, 2004

|                 |  |             |       |           |  |           |      |           |  |            |       |           |  |   |      |  |  |  |       |  |  |   |      | 
|---------------- |  | ----------- | ----- | --------- |  | --------- | ---- | --------- |  | ---------- | ----- | --------- |  | - | ---- |  |  |  | ----- |  |  | - | ---- | 
|                 |  | Daily Floor |       | Floor     |  | Daily Cap |      |           |  | Daily Swap |       | Swap     
|                 |  | Volume      |       | Price     |  | Volume    |      | Cap Price |  | Volume     |       | Price    
|Period           |  | (Mcf)       |       | (per Mcf) |  | (Mcf)     |      | (per Mcf) |  | (Mcf)      |       | (per Mcf)
|                 |  |             |       |           |  |           |      |           |  |            |       |          
|July  Dec. 2004 |  |             |      |           |  |           |     |           |  |            |      |           |  |   |     |  |  |  | 5,000 |  |  | $ | 5.65 | 
|Jan.  Dec. 2005 |  |             | 5,000 |           |  | $         | 5.05 |           |  |            | 5,000 |           |  | $ | 5.97 |  |  |  |      |  |  |   |     | 
|Jan.  Dec. 2006 |  |             | 5,000 |           |  |           | 4.85 |           |  |            | 5,000 |           |  |   | 5.68 |  |  |  |      |  |  |   |     | 

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SUPPLEMENTAL INFORMATION

Capitalized Costs Relating to Oil and Gas
Producing Activities

The capitalized cost of oil and natural gas
properties at December 31, 2003 and 2002 are as follows (in
thousands):

|                                                                   |                                                           |   |         |          |   |   |         |         |  
|------------------------------------------------------------------ | --------------------------------------------------------- | - | ------- | -------- | - | - | ------- | ------- | -
|                                                                   |                                                           |   |         |         
|Properties and equipment, at cost 
    successful efforts method: |                                                           |   |         |          |   |   |         |        
|                                                                   | Producing properties                                      |   | $       | 739,288  |   |   | $       | 581,012 |  
|                                                                   | Undeveloped properties                                    |   |         | 921      |   |   |         | 1,168   |  
|                                                                   | Accumulated depletion, depreciation, and
    amortization |   |         | (124,646 | ) |   |         | (94,356 | )
|                                                                   |                                                           |   |         |          |   |   |         |        
|                                                                   |                                                           | $ | 615,563 |          |   | $ | 487,824 |        
|                                                                   |                                                           |   |         |          |   |   |         |        

Costs Incurred Relating to Oil and Gas
Producing Activities

The following table summarizes costs incurred
related to oil and natural gas properties:

|             |                                 |                         |   |        |         |      |   |        |         |  |   |        |        | 
|------------ | ------------------------------- | ----------------------- | - | ------ | ------- | ---- | - | ------ | ------- |  | - | ------ | ------ | 
|             |                                 |                        
|             |                                 | Year Ended December 31,
|             |                                 |                        
|             |                                 | 2003                    |   | 2002   |         | 2001
|             |                                 |                         |   |        |         |     
|             |                                 |                        
|             |                                 | (In thousands)         
|Acquisitions |                                 |                         |   |        |         |      |   |        |         |  |   |       
|             | Producing properties            |                         | $ | 54,484 |         |      | $ | 78,158 |         |  | $ | 1,471  |       
|             | Undeveloped properties          |                         |   | 117    |         |      |   | 391    |         |  |   | 151    |       
|             | Asset retirement obligations(1) |                         |   | 337    |         |      |   |       |         |  |   |       |       
|Development  |                                 |                         |   |        |         |      |   |        |         |  |   |       
|             | Drilling and exploitation       |                         |   | 98,977 |         |      |   | 80,313 |         |  |   | 87,180 |       
|             | Asset retirement obligations(1) |                         |   | 83     |         |      |   |       |         |  |   |       |       
|             |                                 |                         |   |        |         |      |   |        |         |  |   |       
|             |                                 | Total                   |   | $      | 153,998 |      |   | $      | 158,862 |  |   | $      | 88,802 | 
|             |                                 |                         |   |        |         |      |   |        |         |  |   |       



---



|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | The Company adopted SFAS 143 on
    January 1, 2003 which requires us to capitalize additional
    asset cost equal to the amount of our discounted asset
    retirement obligation assumed in a property purchase or incurred
    in the drilling of new wells. Had the Company adopted
    SFAS 143 prior to January 1, 2001, the Companys
    acquisition cost incurred on a pro-forma basis would have been
    increased by $0.7 million and zero for the years ended
    December 31, 2002 and 2001, respectively. The effect on the
    Companys development cost incurred on a pro-forma basis
    would have been insignificant.

Oil & Natural Gas Producing
Activities (unaudited)

The estimates of the Companys proved oil
and natural gas reserves, which are located entirely within the
United States, were prepared in accordance with guidelines
established by the Securities and Exchange Commission and the
Financial Accounting Standards Board. Proved oil and natural gas
reserve quantities are based on estimates prepared by Miller and
Lents, Ltd., who are independent petroleum engineers.

Future prices received for production and future
production costs may vary, perhaps significantly, from the
prices and costs assumed for purposes of these estimates. There
can be no assurance that the proved reserves will be developed
within the periods assumed or that prices and costs will remain
constant. Actual production may not equal the estimated amounts
used in the preparation of reserve projections. In accordance
with the Securities and Exchange Commissions guidelines,
the Companys estimates of future net cash flows from the
properties and the representative value thereof are made using
oil and natural gas prices in effect as of the dates of such
estimates and are held constant throughout the life of the
properties. Average prices used in estimating net cash flows at
December 31, 2003, 2002, and 2001 were $32.55, $31.20, and
$19.84 per barrel, respectively, for oil and $5.83, $4.79,
and $2.57 per Mcf, respectively, for natural gas. The net
profits interest on our Cedar Creek Anticline properties has been

74



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deducted from future cash inflows in the
calculation of Standardized Measure. The Companys reserve
and production quantities have been reduced by the amounts
attributable to the net profits interest. In addition, net
future cash inflows have not been adjusted for hedge positions
outstanding at the end of the year. The future cash flows are
reduced by estimated production costs and development costs,
which are based on year-end economic conditions and held
constant throughout the life of the properties, and by the
estimated effect of future income taxes. Future income taxes are
based on statutory income tax rates in effect at year end, the
Companys tax basis in its proved oil and natural gas
properties, and the effect of net operating loss, alternative
minimum tax and Section 43 credits, and other carry
forwards.


There are numerous uncertainties inherent in
estimating quantities of proved reserves and in projecting
future rates of production and timing of development
expenditures. Oil and natural gas reserve engineering is and
must be recognized as a subjective process of estimating
underground accumulations of oil and natural gas that cannot be
measured in any exact way, and estimates of other engineers
might differ materially from those included in this Annual
Report on Form 10-K. The accuracy of any reserve estimate
is a function of the quality of available data and engineering,
and estimates may justify revisions. Accordingly, reserve
estimates are often materially different from the quantities of
oil and natural gas that are ultimately recovered. Reserve
estimates are integral to managements analysis of
impairments of oil and natural gas properties and the
calculation of depletion, depreciation, and amortization on
these properties.

Estimated net quantities of proved oil and
natural gas reserves of the Company were as follows:

|                  |                           |        |  |             |  |                |  |         |  |  |  |         | 
|----------------- | ------------------------- | ------ |  | ----------- |  | -------------- |  | ------- |  |  |  | ------- | 
|                  |                           | Oil    |  | Natural Gas |  | Oil Equivalent
|                  |                           | (MBbl) |  | (MMcf)      |  | (MBOE)        
|                  |                           |        |  |             |  |               
|December 31, 2003 |                           |        |  |             |  |                |  |         |  |  |  |        
|                  | Proved reserves           |        |  | 117,732     |  |                |  | 138,950 |  |  |  | 140,890 | 
|                  | Proved developed reserves |        |  | 92,377      |  |                |  | 104,767 |  |  |  | 109,838 | 
|December 31, 2002 |                           |        |  |             |  |                |  |         |  |  |  |        
|                  | Proved reserves           |        |  | 111,674     |  |                |  | 99,818  |  |  |  | 128,310 | 
|                  | Proved developed reserves |        |  | 93,945      |  |                |  | 82,217  |  |  |  | 107,648 | 
|December 31, 2001 |                           |        |  |             |  |                |  |         |  |  |  |        
|                  | Proved reserves           |        |  | 91,369      |  |                |  | 75,687  |  |  |  | 103,983 | 
|                  | Proved developed reserves |        |  | 71,639      |  |                |  | 69,941  |  |  |  | 83,296  | 

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The change in proved reserves were as follows for
the years ended:

|                                  |  |        |         |             |  |                |         |   |  |  |         |  
|--------------------------------- |  | ------ | ------- | ----------- |  | -------------- | ------- | - |  |  | ------- | -
|                                  |  | Oil    |         | Natural Gas |  | Oil Equivalent
|                                  |  | (MBbl) |         | (MMcf)      |  | (MBOE)        
|                                  |  |        |         |             |  |               
|Balance, December 31, 2000        |  |        | 78,910  |             |  |                | 72,970  |   |  |  | 91,072  |  
|                                  |  |        |         |             |  |                |         |   |  |  |         |  
|Acquisitions of minerals-in-place |  |        |        |             |  |                |        |   |  |  |        |  
|Extensions and discoveries        |  |        | 19,266  |             |  |                | 14,063  |   |  |  | 21,610  |  
|Revisions of estimates            |  |        | (1,872  | )           |  |                | (3,268  | ) |  |  | (2,418  | )
|Production                        |  |        | (4,935  | )           |  |                | (8,078  | ) |  |  | (6,281  | )
|                                  |  |        |         |             |  |                |         |   |  |  |         |  
|Balance, December 31, 2001        |  |        | 91,369  |             |  |                | 75,687  |   |  |  | 103,983 |  
|                                  |  |        |         |             |  |                |         |   |  |  |         |  
|Acquisitions of minerals-in-place |  |        | 14,555  |             |  |                | 5,434   |   |  |  | 15,461  |  
|Extensions and discoveries        |  |        | 9,605   |             |  |                | 23,643  |   |  |  | 13,546  |  
|Revisions of estimates            |  |        | 2,182   |             |  |                | 3,229   |   |  |  | 2,719   |  
|Production                        |  |        | (6,037  | )           |  |                | (8,175  | ) |  |  | (7,399  | )
|                                  |  |        |         |             |  |                |         |   |  |  |         |  
|Balance, December 31, 2002        |  |        | 111,674 |             |  |                | 99,818  |   |  |  | 128,310 |  
|                                  |  |        |         |             |  |                |         |   |  |  |         |  
|Acquisitions of minerals-in-place |  |        | 13      |             |  |                | 37,464  |   |  |  | 6,257   |  
|Extensions and discoveries        |  |        | 3,957   |             |  |                | 7,354   |   |  |  | 5,182   |  
|Improved recovery                 |  |        | 12,773  |             |  |                | (178    | ) |  |  | 12,744  |  
|Revisions of estimates            |  |        | (4,084  | )           |  |                | 3,543   |   |  |  | (3,493  | )
|Production                        |  |        | (6,601  | )           |  |                | (9,051  | ) |  |  | (8,110  | )
|                                  |  |        |         |             |  |                |         |   |  |  |         |  
|Balance, December 31, 2003        |  |        | 117,732 |             |  |                | 138,950 |   |  |  | 140,890 |  
|                                  |  |        |         |             |  |                |         |   |  |  |         |  

The Standardized Measure of discounted estimated
future net cash flows and changes therein related to proved oil
and natural gas reserves (in thousands) is as follows at:

|                                                                       |  |              |            |      |  |      |            |   |  |   |           |  
|---------------------------------------------------------------------- |  | ------------ | ---------- | ---- |  | ---- | ---------- | - |  | - | --------- | -
|                                                                       |  |             
|                                                                       |  | December 31,
|                                                                       |  |             
|                                                                       |  | 2003         |            | 2002 |  | 2001
|                                                                       |  |              |            |      |  |     
|Net future cash inflows                                                |  | $            | 4,245,574  |      |  | $    | 3,648,515  |   |  | $ | 1,770,384 |  
|Future production costs                                                |  |              | (1,683,810 | )    |  |      | (1,448,110 | ) |  |   | (794,139  | )
|Future development costs                                               |  |              | (81,076    | )    |  |      | (63,194    | ) |  |   | (67,652   | )
|Future income tax expense                                              |  |              | (716,869   | )    |  |      | (623,987   | ) |  |   | (215,568  | )
|                                                                       |  |              |            |      |  |      |            |   |  |   |           |  
|Future net cash flows                                                  |  |              | 1,763,819  |      |  |      | 1,513,224  |   |  |   | 693,025   |  
|10% annual discount                                                    |  |              | (1,026,880 | )    |  |      | (888,506   | ) |  |   | (408,716  | )
|                                                                       |  |              |            |      |  |      |            |   |  |   |           |  
|Standardized measure of discounted estimated
    future net cash flows |  | $            | 736,939    |      |  | $    | 624,718    |   |  | $ | 284,309   |  
|                                                                       |  |              |            |      |  |      |            |   |  |   |           |  

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Primary changes in the Standardized Measure of
discounted estimated future net cash flows (in thousands) are as
follows for the year ended:

|                                        |                                                 |                         |         |          |   |      |         |          |   |   |         |          |  
|--------------------------------------- | ----------------------------------------------- | ----------------------- | ------- | -------- | - | ---- | ------- | -------- | - | - | ------- | -------- | -
|                                        |                                                 |                        
|                                        |                                                 | Year Ended December 31,
|                                        |                                                 |                        
|                                        |                                                 | 2003                    |         | 2002     |   | 2001
|                                        |                                                 |                         |         |          |   |     
|Standardized measure, beginning of year |                                                 | $                       | 624,718 |          |   | $    | 284,309 |          |   | $ | 599,276 |         
|                                        | Net change in sales prices and production costs |                         |         | 81,964   |   |      |         | 305,097  |   |   |         | (334,809 | )
|                                        | Acquisitions of minerals-in-place               |                         |         | 91,654   |   |      |         | 131,370  |   |   |         |         |  
|                                        | Extensions, discoveries, and improved recovery  |                         |         | 103,780  |   |      |         | 135,897  |   |   |         | 71,090   |  
|                                        | Revisions of quantity estimates                 |                         |         | (25,650  | ) |      |         | 18,216   |   |   |         | (18,244  | )
|                                        | Sales, net of production costs                  |                         |         | (151,955 | ) |      |         | (114,361 | ) |   |         | (96,969  | )
|                                        | Development costs incurred during the year      |                         |         | 98,977   |   |      |         | 80,313   |   |   |         | 87,179   |  
|                                        | Accretion of discount                           |                         |         | 86,511   |   |      |         | 36,036   |   |   |         | 70,636   |  
|                                        | Change in estimated future development costs    |                         |         | (116,859 | ) |      |         | (44,285  | ) |   |         | (51,238  | )
|                                        | Net change in income taxes                      |                         |         | (52,992  | ) |      |         | (164,334 | ) |   |         | 31,028   |  
|                                        | Change in timing and other                      |                         |         | (3,209   | ) |      |         | (43,540  | ) |   |         | (73,640  | )
|                                        |                                                 |                         |         |          |   |      |         |          |   |   |         |         
|Standardized measure, end of year       |                                                 | $                       | 736,939 |          |   | $    | 624,718 |          |   | $ | 284,309 |         
|                                        |                                                 |                         |         |          |   |      |         |          |   |   |         |         

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Selected Quarterly Financial Data

The following table sets forth selected quarterly
financial data for the years ended December 31, 2003 and
2002:

|                                                               |                               |                                       |        |        |  |       |        |        |  |   |        |      |  |   |        |      | 
|-------------------------------------------------------------- | ----------------------------- | ------------------------------------- | ------ | ------ |  | ----- | ------ | ------ |  | - | ------ | ---- |  | - | ------ | ---- | 
|                                                               |                               |                                      
|                                                               |                               | Quarter                              
|                                                               |                               |                                      
|                                                               |                               | First                                 |        | Second |  | Third |        | Fourth
|                                                               |                               |                                       |        |        |  |       |        |       
|                                                               |                               |                                      
|                                                               |                               | (In thousands, except per share data)
|2003                                                           |                               |                                       |        |        |  |       |        |        |  |   |        |      |  |   |        |     
|Revenues                                                       |                               | $                                     | 55,787 |        |  | $     | 51,243 |        |  | $ | 55,724 |      |  | $ | 57,342 |     
|Operating Income                                               |                               | $                                     | 31,377 |        |  | $     | 26,679 |        |  | $ | 28,789 |      |  | $ | 27,972 |     
|Income before accounting change                                |                               | $                                     | 17,115 |        |  | $     | 14,233 |        |  | $ | 15,768 |      |  | $ | 15,662 |     
|Cumulative effect of accounting change, net of
    tax of $329 |                               |                                       | 863    |        |  |       |       |        |  |   |       |      |  |   |       |     
|                                                               |                               |                                       |        |        |  |       |        |        |  |   |        |      |  |   |        |     
|Net income                                                     |                               | $                                     | 17,978 |        |  | $     | 14,233 |        |  | $ | 15,768 |      |  | $ | 15,662 |     
|                                                               |                               |                                       |        |        |  |       |        |        |  |   |        |      |  |   |        |     
|Basic income per common share:                                 |                               |                                       |        |        |  |       |        |        |  |   |        |      |  |   |        |     
|                                                               | Before accounting change      |                                       | $      | 0.57   |  |       | $      | 0.47   |  |   | $      | 0.52 |  |   | $      | 0.51 | 
|                                                               | Accounting change, net of tax |                                       |        | 0.03   |  |       |        |       |  |   |        |     |  |   |        |     | 
|                                                               |                               |                                       |        |        |  |       |        |        |  |   |        |      |  |   |        |     
|                                                               | After accounting change       |                                       | $      | 0.60   |  |       | $      | 0.47   |  |   | $      | 0.52 |  |   | $      | 0.51 | 
|                                                               |                               |                                       |        |        |  |       |        |        |  |   |        |      |  |   |        |     
|Diluted income per common share:                               |                               |                                       |        |        |  |       |        |        |  |   |        |      |  |   |        |     
|                                                               | Before accounting change      |                                       | $      | 0.57   |  |       | $      | 0.47   |  |   | $      | 0.52 |  |   | $      | 0.51 | 
|                                                               | Accounting change, net of tax |                                       |        | 0.02   |  |       |        |       |  |   |        |     |  |   |        |     | 
|                                                               |                               |                                       |        |        |  |       |        |        |  |   |        |      |  |   |        |     
|                                                               | After accounting change       |                                       | $      | 0.59   |  |       | $      | 0.47   |  |   | $      | 0.52 |  |   | $      | 0.51 | 
|                                                               |                               |                                       |        |        |  |       |        |        |  |   |        |      |  |   |        |     
|2002                                                           |                               |                                       |        |        |  |       |        |        |  |   |        |      |  |   |        |     
|Revenues                                                       |                               | $                                     | 32,297 |        |  | $     | 37,807 |        |  | $ | 43,502 |      |  | $ | 47,086 |     
|Operating Income                                               |                               | $                                     | 12,929 |        |  | $     | 16,951 |        |  | $ | 19,789 |      |  | $ | 22,846 |     
|Net income                                                     |                               | $                                     | 7,110  |        |  | $     | 9,126  |        |  | $ | 10,113 |      |  | $ | 11,336 |     
|Basic income per common share:                                 |                               | $                                     | 0.24   |        |  | $     | 0.30   |        |  | $ | 0.34   |      |  | $ | 0.38   |     
|                                                               |                               |                                       |        |        |  |       |        |        |  |   |        |      |  |   |        |     
|Diluted income per common share:                               |                               | $                                     | 0.24   |        |  | $     | 0.30   |        |  | $ | 0.33   |      |  | $ | 0.38   |     
|                                                               |                               |                                       |        |        |  |       |        |        |  |   |        |      |  |   |        |     

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|        |                                                                                         
|------- | ----------------------------------------------------------------------------------------
|Item 9. | Changes in and Disagreements with
    Accountants on Accounting and Financial Disclosure

On April 1, 2002, we dismissed Arthur
Andersen LLP as our independent accountants effective as of that
date. The decision to dismiss Arthur Andersen LLP was
recommended by the Audit Committee of the Board of Directors and
was approved by the Board of Directors on April 1, 2002.

Arthur Andersens report on the
Companys consolidated financial statements for the fiscal
year ended December 31, 2001 did not contain an adverse
opinion or disclaimer of opinion and was not qualified or
modified as to uncertainty or audit scope. Arthur Andersen LLP
included in its opinion explanatory language related to the
Companys change in its method of accounting for
derivatives as a result of the Companys adoption of
Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging
Activities. During 2001 and the period from
January 1, 2002 through the date of Arthur Andersen
LLPs termination, there were no disagreements between us
and Arthur Andersen LLP on any matter of accounting principles
or practices, financial statement disclosure, or auditing scope
or procedure, that, if not resolved to the satisfaction of
Arthur Andersen LLP, pursuant to Item 304(a)(1) of
Regulation S-K, would have caused it to make reference to
the subject matter of the disagreements in its report.

As required under the regulations of the SEC, we
provided Arthur Andersen LLP with a copy of our disclosure in
connection with this matter and requested Arthur Andersen LLP to
furnish us with a letter addressed to the SEC stating whether it
agreed with our statements and, if not, stating the respects in
which it did not agree. Arthur Andersen LLPs letter was
filed as Exhibit 16.1 to our Current Report on
Form 8-K filed with the SEC on April 5, 2002.

Effective April 11, 2002, we engaged
Ernst & Young LLP, as our new independent accountants
for the fiscal year ending December 31, 2002. The decision
to appoint Ernst & Young LLP was recommended by the
Audit Committee of the Board of Directors and was approved by
the Board of Directors on April 1, 2002.

There have been no disagreements with our
independent accountants on our accounting or financial reporting
that would require our independent accountants to qualify or
disclaim their report on our consolidated financial statements,
or otherwise require disclosure in this Form 10-K.






|         |                        
|-------- | -----------------------
|Item 9A. | Controls and Procedures

Our Chief Executive Officer and our Chief
Financial Officer (our principal executive officer and principal
financial officer, respectively) have concluded, based on their
evaluation as of the end of the period covered by this annual
report on Form 10-K, that our disclosure controls and
procedures are effective to ensure that information required to
be disclosed by us in the reports filed or submitted by us under
the Securities Exchange Act of 1934, as amended, is recorded,
processed, summarized and reported within the time periods
specified in the SECs rules and forms, and include
controls and procedures designed to ensure that information
required to be disclosed by us in such reports is accumulated
and communicated to our management, including our Chief
Executive Officer and our Chief Financial Officer, as
appropriate to allow timely decisions regarding required
disclosure. There were no changes in our internal control over
financial reporting that occurred during the most recent fiscal
quarter that have materially affected, or are reasonably likely
to materially affect, our internal control over financial
reporting.




PART III






|         |                                                       
|-------- | ------------------------------------------------------
|Item 10. | Directors and Executive Officers of the
    Registrant

The information required in response to this item
is set forth in the Companys definitive proxy statement
for the annual meeting of stockholders to be held on
April 29, 2004 and is incorporated herein by reference.

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We have adopted a Code of Business Conduct and
Ethics covering our directors, officers, and employees, which is
available free of charge on our Internet website
(www.encoreacq.com).






|         |                       
|-------- | ----------------------
|Item 11. | Executive Compensation

The information required in response to this item
is set forth in the Companys definitive proxy statement
for the annual meeting of stockholders to be held on
April 29, 2004 and is incorporated herein by reference.






|         |                                                                                                       
|-------- | ------------------------------------------------------------------------------------------------------
|Item 12. | Security Ownership of Certain Beneficial
    Owners and Management and Related Stockholder
    Matters

The information required in response to this item
is set forth in the Companys definitive proxy statement
for the annual meeting of stockholders to be held on
April 29, 2004 and is incorporated herein by reference.






|         |                                                   
|-------- | --------------------------------------------------
|Item 13. | Certain Relationships and Related
    Transactions

The information required in response to this item
is set forth in the Companys definitive proxy statement
for the annual meeting of stockholders to be held on
April 29, 2004 and is incorporated herein by reference.






|         |                                           
|-------- | ------------------------------------------
|Item 14. | Principal Accountant Fees and
    Services

The information required in response to this item
is set forth in the Companys definitive proxy statement
for the annual meeting of stockholders to be held on
April 29, 2004 and is incorporated herein by reference.

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PART IV






|         |                                                                     
|-------- | --------------------------------------------------------------------
|Item 15. | Exhibits, Financial Statement Schedules,
    and Reports on Form 8-K

(a) The following documents are filed as a
part of this Report at page 48:



| |                         
| | ------------------------
| | 1. Financial Statements:

|                                                                                                             |  |  |    | 
|------------------------------------------------------------------------------------------------------------ |  |  | -- | 
|Report of Independent Public Accountant                                                                      |  |  | 49 | 
|Consolidated Balance Sheets as of
    December 31, 2003 and 2002                                             |  |  | 51 | 
|Consolidated Statements of Operations for the
    Years Ended December 31, 2003, 2002 and 2001               |  |  | 52 | 
|Consolidated Statement of Stockholders
    Equity for the Years Ended December 31, 2003, 2002,
    and 2001 |  |  | 53 | 
|Consolidated Statements of Cash Flows for the
    Years Ended December 31, 2003, 2002 and 2001               |  |  | 54 | 
|Notes to Consolidated Financial Statements                                                                   |  |  | 55 | 



| |                                  
| | ---------------------------------
| | 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.

(b) Reports on Form 8-K

We filed the following reports on Form 8-K
during the quarter ended December 31, 2003:



| |    |                                                                                                                                                                                                                                                                                                                                                                                                                                                  
| | -- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | 1. | On November 4, 2003, we filed a
    Form 8-K to furnish certain earnings-related information
    under Items 7 and 12.                                                                                                                                                                                                                                                                                                                           
|
| | 2. | On November 7, 2003, we filed a
    Form 8-K to furnish information under Items 7 and 9
    regarding the appointment of Roy W. Jageman as our Chief
    Financial Officer.                                                                                                                                                                                                                                                                      
|
| | 3. | On November 10, 2003, we filed a
    Form 8-K to furnish information under Items 7 and 9
    regarding a public offering of up to 9.2 million shares of
    our common stock and the use of proceeds therefrom.                                                                                                                                                                                                                                  
|
| | 4. | On November 14, 2003, we filed an
    Item 5 and Item 7 Form 8-K to disclose the
    execution of an underwriting agreement with respect to the
    public offering of up to 9.2 million shares of our common
    stock and the execution of a stock purchase agreement with
    respect to the repurchase of up to 9.2 million shares of
    our common stock from J.P. Morgan Partners (SBIC), LLC and
    Warburg, Pincus Equity Partners L.P.
|
| | 5. | On November 20, 2003, we filed a
    Form 8-K to furnish information under Items 7 and 9
    regarding the closing of a public offering of 8.0 million
    shares of our common stock and the use of proceeds therefrom.                                                                                                                                                                                                                         
|
| | 6. | On December 3, 2003, we filed a
    Form 8-K to furnish information under Items 7 and 9
    regarding the sale of 1,060,000 shares of our common stock
    pursuant the exercise of the underwriters over-allotment
    option and the use of proceeds therefrom.                                                                                                                                                                               

(c) Exhibits

See Exhibits to Index on the following page for a
description of the exhibits filed as a part of this report.

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INDEX TO EXHIBITS

|        |    |             |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|------- | -- | ----------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit |    |            
|No.     |    | Description
|        |    |            
|        | 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  | .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          |  | Indenture, dated as of June 25, 2002, among
    the Company, subsidiary guarantors party thereto and Wells Fargo
    Bank, N.A. (incorporated by reference to Exhibit 4.1 to
    Quarterly Report on Form 10-Q for the quarterly period
    ended June 30, 2002, filed with the SEC on August 9,
    2002).                                                                                                                                                                                                                                
|        | 4  | .3          |  | Form of 8 3/8% Senior Subordinated Note
    to Cede & Co. or its registered assigns, dated
    January 16, 2003.                                                                                                                                                                                                                                                                                                                                                                                                                           
|        | 10 | .1+         |  | 2000 Incentive Stock Plan (incorporated by
    reference to Exhibit 10.1 to the Companys Quarterly
    Report on Form 10-Q for the fiscal quarter ended
    September 30, 2001, filed with the SEC on November 14,
    2002).                                                                                                                                                                                                                                                                                                             
|        | 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 10.2 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 | .4          |  | Credit Agreement, dated June 25, 2002 (the
    Credit Agreement), among the Company, Encore
    Operating, L.P., Fleet National Bank, a national banking
    association, as Administrative Agent, Wachovia Bank, N.A., as
    Syndication Agent, Fortis Capital Corp., as Documentary Agent
    and the financial institutions listed therein (incorporated by
    reference to Exhibit 10.1 to the Companys Quarterly
    Report on Form 10-Q for the quarterly period ended June 30,
    2002, filed with the SEC on August 9, 2002).
|        | 10 | .5*         |  | First Amendment to Credit Agreement dated
    October 31, 2002.                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|        | 10 | .6*         |  | Second Amendment to Credit Agreement dated
    October 21, 2003.                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|        | 10 | .7          |  | 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).                                                                                                                                                                                                                                               
|        | 10 | .8*+        |  | Severance Agreement, dated December 18,
    2003, between the Company and Morris B. Smith.                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|        | 10 | .9*         |  | Stock Purchase Agreement dated March 2, 2004
    by and among Cortez Oil & Gas, Inc., HRM
    Resources, Inc., the Security Holders of Cortez
    Oil & Gas, Inc., and Encore Acquisition Company.                                                                                                                                                                                                                                                                                                                                         
|        | 16 | .1          |  | Current Report on Form 8-K, filed with the SEC on
    April 5, 2002, regarding the dismissal of independent
    auditor.                                                                                                                                                                                                                                                                                                                                                                                                                   
|        | 21 | .1*         |  | Subsidiaries of the Company.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
|        | 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
    Executive Officer)                                                                                                                                                                                                                                                                                                                                                                                                                                                                   

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|        |    |             |  |                                                                                                                                
|------- | -- | ----------- |  | -------------------------------------------------------------------------------------------------------------------------------
|Exhibit |    |            
|No.     |    | Description
|        |    |            
|        | 32 | .1*         |  | Certification Pursuant to 18 U.S.C.
    Section 1350, as Adopted Pursuant to Section 906 of
    the Sarbanes-Oxley Act of 2002.
|        | 32 | .2*         |  | Certification Pursuant to 18 U.S.C.
    Section 1350, as Adopted Pursuant to Section 906 of
    the Sarbanes-Oxley Act of 2002.



---



|  |                                                                       
|- | ----------------------------------------------------------------------
|* | Filed herewith                                                        
| 
|+ | Management contract or compensatory plan,
    contract or arrangement.

Copies of the above exhibits not contained herein
are available at the cost of reproduction to any security holder
upon written request to the Assistant Treasurer, Encore
Acquisition Company, 777 Main Street, Suite 1400,
Fort Worth, Texas 76102.

83



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##### Table of Contents



SIGNATURES

Pursuant to the requirements of Section 13
or 15(d) of the Securities Exchange Act of 1934, the registrant
has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized, on the 11th day of
March, 2004.



| |                           
| | --------------------------
| | ENCORE ACQUISITION COMPANY



| |     |                   
| | --- | ------------------
| | By: | /s/ I. JON BRUMLEY

| |                        
| | -----------------------
| |                        
| | I. Jon Brumley         
| | Chief Executive Officer

KNOW ALL MEN BY THESE PRESENTS, that each
individual whose signature appears below constitutes and
appoints I. Jon Brumley and Roy W. Jageman, and each
of them, his true and lawful attorneys-in-fact and agents with
full power of substitution, for him and in his name, place and
stead, in any and all capacities, to sign any and all amendments
(including post-effective amendments) to this report, and to
file the same, with all exhibits thereto, and all documents in
connection therewith, with the Securities and Exchange
Commission, granting unto said attorneys-in-fact and agents,
full power and authority to do and perform each and every act
and thing requisite and necessary to be done in and about the
premises, as fully to all intents and purposes as he might or
could do in person, hereby ratifying and confirming all that
said attorneys-in-fact and agents, or his or their substitutes,
may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities
Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant in the capacities
indicated on March 11, 2004.

|                                       |  |                                                                                                                            |  |  |  | 
|-------------------------------------- |  | -------------------------------------------------------------------------------------------------------------------------- |  |  |  | 
|                                       |  |                                                                                                                            |  | 
|Signature                              |  | Title or Capacity                                                                                                          |  | 
|                                       |  |                                                                                                                            |  | 
|                                      
|/s/ I. JON BRUMLEYI. Jon Brumley       |  | Chairman of the Board, Chief Executive Officer,
    and Director (Principal Executive Officer)                             |  | 
|                                      
|/s/ JON S. BRUMLEYJon S. Brumley       |  | President and Director                                                                                                     |  | 
|                                      
|/s/ ROY W. JAGEMANRoy W. Jageman       |  | Chief Financial Officer, Treasurer, Executive
    Vice President and Corporate Secretary (Principal Financial
    Officer) |  | 
|                                      
|/s/ ROBERT C. REEVESRobert C. Reeves   |  | Vice President, Controller and Assistant
    Corporate Secretary (Principal Accounting Officer)                            |  | 
|                                      
|/s/ ARNOLD L. CHAVKINArnold L. Chavkin |  | Director                                                                                                                   |  | 
|                                      
|/s/ HOWARD H. NEWMANHoward H. Newman   |  | Director                                                                                                                   |  | 

84



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|                                           |  |                   |  |  |  | 
|------------------------------------------ |  | ----------------- |  |  |  | 
|                                           |  |                   |  | 
|Signature                                  |  | Title or Capacity |  | 
|                                           |  |                   |  | 
|                                          
|/s/ TED A. GARDNERTed A. Gardner           |  | Director          |  | 
|                                          
|/s/ TED COLLINS, JR.Ted Collins, Jr.       |  | Director          |  | 
|                                          
|/s/ JAMES A. WINNE, IIIJames A. Winne, III |  | Director          |  | 

85