ENCORE ACQUISITION CO - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

Commission File No. 1-16295

ENCORE ACQUISITION COMPANY
(Exact name of registrant as specified in its charter)

DELAWARE 75-2759650
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)

777 MAIN STREET 76102
SUITE 1400 (Zip code)
FT. WORTH, TEXAS
(Address of principal executive offices)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(817) 877-9955

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

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 [X] No [ ]

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. [ ]

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

Aggregate market value of the voting and non-voting common
stock held by non-affiliates of the Registrant as of June
28, 2002 (the last business day of Registrant's most
recently completed second fiscal quarter)................. $518,080,000
Number of shares of Common Stock, $0.01 par value,
outstanding as of March 20, 2003.......................... 30,107,883

DOCUMENTS INCORPORATED BY REFERENCE

Parts of the definitive proxy statement for the Company's annual meeting of
stockholders to be held on April 30, 2003 are incorporated by reference into
Part III of this report on Form 10-K.
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ENCORE ACQUISITION COMPANY
2002 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS

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Parts I and II of this annual report on Form 10-K (the "Report") contain
forward-looking statements that involve risks and uncertainties that are made
pursuant to the Safe Harbor Provisions of the Private Securities Litigation
Reform Act of 1995. 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 32, 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.

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

GENERAL

Organized as a Delaware corporation in 1998, Encore Acquisition Company
(together with our subsidiaries, "we", "Encore", or the "Company") is a growing
independent energy company engaged in the acquisition, development,
exploitation, and production of onshore North American oil and natural gas
reserves.

Since inception, the Company has sought to acquire high quality assets with
potential for upside through low-risk development drilling projects. Our growth
has come primarily from the acquisition of producing oil and natural gas
properties and subsequent development of these properties. We have been
successful in purchasing seven major packages of producing properties since
inception in April 1998. The Company has acquired producing properties in the
Williston, Permian, Anadarko, Powder River, and Paradox Basins. All our
producing assets reside onshore in the continental lower 48 United States. See
"-- Properties" beginning on page 12. Since our inception, we have invested
$379.3 million in acquiring producing oil and natural gas properties. We have
invested another $202.9 million for development and exploitation of these
properties.

The Cedar Creek Anticline ("CCA"), in the Williston Basin of Montana and
North Dakota, represents 75% of our total proved reserves as of December 31,
2002. The CCA represents the Company's most valuable asset today and in the
foreseeable future. A large portion of the Company's future success revolves
around future exploitation of and production from this property.

In 2002, our reserve growth was achieved both through acquisitions and
organically through the drill bit by developing a portion of the Company's
inventory of drilling projects that extends over the next several years. We
continued the pursuit of assembling high-quality assets and replenishing our
drilling inventory through acquisitions by adding the Central Permian and
Paradox Basin properties to the Company's portfolio.

On January 4, 2002, we closed our sixth major property package since
inception. These properties were purchased 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. 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 and the average daily
production from the properties for 2002 was 1,978 BOE. The properties have
growth potential through development drilling and waterflood enhancement. During
2002, we drilled 8 wells on our Central Permian properties and plan to drill
additional wells during 2003.

On August 29, 2002, we completed an acquisition of interests in southeast
Utah's Paradox Basin for $17.9 million ($16.7 million after closing
adjustments). The Paradox Basin properties are in two prolific oil producing
units: the Ratherford Unit operated by Exxon Mobil and the Aneth Unit operated
by Chevron Texaco. Since being acquired in 2002, the revenue stream for the
properties was derived 92% from oil and
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the average daily production added from these properties was 871 BOE. Encore
expects to benefit from horizontal redevelopment and tertiary upside
opportunities in the future.

In 2002, we drilled 103 gross operated wells and participated in drilling
another 6 gross non-operated wells for a total of 109 gross wells for the year.
On a net basis, the Company drilled 95 net operated wells and participated in 1
non-operated well in 2002. We invested $80.3 million to drill and complete the
net wells for 2002 or approximately $842,000 net per well. The drilling program
added 13.5 million BOE for 2002 at an average cost of $5.93 per BOE.

The Company's estimated proved reserves at December 31, 2002 were 111.7
MMBls of oil and 99.8 Bcf of natural gas, or 128.3 MMBOE. The proved developed
reserves were 107.6 million BOE, or 84% of total proved reserves at December 31,
2002. Our Reserve-to-Production ratio averaged 17.3 years based upon December
31, 2002 proved reserves and the prior 12 months production, while the R/P Index
for our proved reserves at December 31, 2002 for our Cedar Creek Anticline
properties was 21.4 years. Prevailing prices as of December 31, 2002 were $31.20
per Bbl of oil and $4.79 per Mcf of natural gas. Proved oil and natural gas
reserve quantities are based on estimates prepared by Miller and Lents, Ltd.,
who are independent petroleum engineers.

Production from our properties averaged 16,540 Bbls/D of oil and 22,397
Mcf/D of natural gas, or 20,273 BOE/D, for 2002. The direct lifting costs for
our properties averaged $4.15 per BOE for the year. Production, severance, and
ad valorem taxes were $2.12 per BOE.

On June 25, 2002, the Company sold $150 million of 8 3/8% senior
subordinated notes maturing on June 15, 2012 (the "Notes") in a private offering
exempt from registration requirements under the Securities Act of 1933, as
amended. The offering was made through a private placement pursuant to Rule
144A. 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 the new revolving credit facility ($1.5 million), and to
hold in reserve for the Paradox Basin acquisition ($1.1 million).

In connection with the issuance of the Notes, we entered into a
registration rights agreement, dated June 19, 2002, with the initial purchasers
of the Notes and entered into an indenture governing the Notes. Pursuant to the
registration rights agreement, we filed a registration statement on Form S-4/A
with the SEC, which was declared effective on December 6, 2002, with respect to
the exchange of the Notes for registered notes having terms substantially
identical in all material respects. On January 16, 2003, all of the Notes were
exchanged for the registered notes, Encore's registered senior subordinated
notes due June 15, 2012 were issued and the Notes were cancelled. The Company
did not receive any proceeds from the exchange. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources" on page 29.

Concurrently with the issuance of the Notes, we entered into a new
revolving credit facility with a syndicate of banks, which replaced our prior
credit facility. All of our subsidiaries are guarantors of our revolving credit
facility. The maximum amount available under our revolving credit facility is
$300.0 million, which is secured by a first priority lien on our proved oil and
natural gas reserves representing at least 80% of the present discounted reserve
value. As of December 31, 2002, the amount available to us under our revolving
credit facility is $220.0 million, the amount of which may be increased and
decreased subject to a borrowing base calculation. As of December 31, 2002,
$16.0 million was outstanding under the new revolving credit facility. The
maturity date is June 25, 2006. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources" on page 29.

STRATEGY

Our strategy is to grow our reserves and production through low-risk
development drilling, selective acquisitions, secondary recovery projects and
tertiary recovery projects. This strategy, along with efficient operations,
should maximize internally generated cash flow and shareholder value.

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Thus, our strategy centers around four primary areas:

- an active low-risk development drilling program;

- a disciplined acquisition program;

- secondary and tertiary recovery projects; and

- cost control through efficient operations.

Development of Existing Properties. Our properties generally have long
reserve lives and reasonably stable and predictable reservoir production
characteristics. The R/P Index for our proved reserves at December 31, 2002 was
17.3 years based on the prior 12 months' production. However, the R/P Index for
our proved reserves at December 31, 2002 for our Cedar Creek Anticline
properties, which represented 75% of our total proved reserves, was 21.4 years
based on the prior 12 months' production at December 31, 2002. Our Cedar Creek
Anticline 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 requires a longer time to produce the reserves in place. This results
in a lower production decline rate.

The inventory of potential development drilling locations or major
recompletion opportunities on our existing properties is sufficient to sustain
the same level of capital investment for the next several years. Longer term, we
believe that there is significant value to be created through our High-Pressure
Air Injection project in the CCA. See "-- Present Activities -- Cedar Creek
Anticline High-Pressure Air Injection Limited Scale Program" on page 9.

Continued Disciplined Acquisition Program. We will continue to pursue
acquisitions of properties with similar upside potential to our current
producing properties portfolio. We believe that we are more likely to make large
property acquisitions during periods of low acquisition prices and will more
vigorously pursue development activities during periods of high acquisition
prices. The Company, using the experience of our senior management team, has
developed and refined an acquisition program designed to increase our reserves
and to complement our core properties, while providing some 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.

Secondary and Tertiary Recovery Projects. Secondary and tertiary recovery
is another component of our growth strategy. 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 secondary recovery projects
involve the successful implementation and further enhancements of waterfloods on
the Company's producing properties. The Company also has a tertiary recovery
project which revolves around an initial High-Pressure Air Injection ("HPAI")
program on the Company's CCA asset in Montana. See "-- Present
Activities -- Cedar Creek Anticline High Pressure Air Injection Limited Scale
Program" on page 9. These secondary and tertiary projects are expected to yield
inclining production rates.

Efficient Operations. We operate properties representing 86% of our proved
reserves, which allows us to control capital allocation and expenses. For the
year ended December 31, 2002, our lease operating expenses consisted of direct
lifting costs of $4.15 per BOE produced and production, ad valorem, and
severance tax payments of $2.12 per BOE produced. Our general and administrative
costs averaged $0.83 per BOE produced in 2002.

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 returns on 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.

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BUSINESS ACTIVITIES

The following table sets forth the net production, proved reserves
quantities, and PV-10 values of our principal properties as of December 31,
2002:

PROPERTIES -- PRINCIPAL AREAS OF OPERATIONS

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(1) 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 $4.5 million at December 31, 2002. The Standardized Measure at
December 31, 2002 is $624.7 million. Standardized Measure differs from PV-10
because Standardized Measure includes the effect of future income taxes.

(2) Other includes our Indian Basin, Verden, Bell Creek, and Paradox Basin
properties, which individually represent less than 10% of our net production
for 2002 and PV-10 at December 31, 2002. Additionally, this line includes a
reduction to PV-10 at December 31, 2002, of $8.9 million related to future
corporate indirect costs.

During 2003, we plan to invest approximately $105.0 million to exploit and
develop existing core properties. The $105.0 million budgeted does not include
the possible $25.0 million for additional high-pressure air-injection capital.
See "-- Present Activities -- Cedar Creek Anticline High-Pressure Air Injection
Limited Scale Program" on page 9. With the $105.0 million budgeted capital, we
plan to support a 5 rig, 100 well drilling program in the Cedar Creek Anticline
and a 2 rig, 40 well program in our Permian Basin assets, as well as waterflood
improvements, workovers, and recompletions. If attractive opportunities arise
during that period, we will seek to acquire additional producing oil and natural
gas properties.

OPERATIONS

We act as operator of properties representing approximately 86% of our
proved reserves at December 31, 2002. As operator, we are able to 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 exploiting and developing them. See
"-- Properties -- Nature of Our Ownership Interests" on page 12. During the
years ended December 31, 2002, 2001, and 2000 our approximate costs for
development activities on non-operated properties were $3.4 million, $9.3
million, and $0.3 million, respectively.

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PROVED RESERVES

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):

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(1) Volumetric reserves attributed to the net profits interests in our Cedar
Creek Anticline properties were 16,262 MBOE, 11,062 MBOE and 11,730 MBOE,
respectively, at December 31, 2002, 2001 and 2000. See "-- Net Profits
Interests" on page 12. The volumes attributed to the net profits interests,
which reduce our reserves on a BOE for BOE basis, will fluctuate from period
to period 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 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
$860.6 million at December 31, 2002, $364.4 million at December 31, 2001,
and $689.6 million at December 31, 2000.

(3) 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.

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.

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 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, expenses exclude our
share of 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 calendar year 2002, the Company filed estimates of oil and natural
gas reserves at December 31, 2001 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 Company operated wells at year end, and is reported on a gross basis.
These estimates come directly from the Company's 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 and certain price and cost information for each of the periods
indicated:

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PRODUCING WELLS

The following table sets forth information at December 31, 2002 relating to
the producing wells in which we owned a working interest as of that date. We
also held royalty interests in 1,629 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.

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(1) Our total wells include 850 operated wells and 1,634 non-operated wells.

(2) Other includes our Indian Basin, Verden, Bell Creek and Paradox Basin
properties, which individually represent less than 10% of our net production
for 2002 and PV-10 at December 31, 2002.

ACREAGE

The following table sets forth information at December 31, 2002 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 Crockett, Verden, and CCA properties, which
represent 40%, 35%, and 25% of our total undeveloped acreage, respectively.
These leases expire at various dates ranging from June 2003 to November 2010
with leases representing $352,000 of cost set to expire in 2003 if not
developed.

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.

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Productive wells are those that produce commercial quantities of hydrocarbons,
exclusive of their capacity to produce a reasonable rate of return.

PRESENT ACTIVITIES

As of December 31, 2002, the Company had a total of 5 gross (5 net) wells
that had been spudded and were in varying stages of drilling operations. Also,
there were 5 gross (4.8 net) wells that had reached total depth and were in
varying stages of completion pending first production. Upgrades to facilities
allowing for additional waterflood operations at North Pine in the Cedar Creek
Anticline were also underway, as part of the ongoing North Pine waterflood
reactivation program.

CEDAR CREEK ANTICLINE HIGH-PRESSURE AIR INJECTION LIMITED SCALE PROGRAM

In addition to the conventional development operations planned for 2003,
the Company is currently in Phase I of the High-Pressure Air Injection ("HPAI")
program in the Pennel Unit on the Cedar Creek Anticline. As the name suggests,
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. In June 2002, Encore began injecting air into the
Red River U4 reservoir in a portion of the Pennel Unit of the CCA. Prior to
beginning the air injection program, the project area was producing 360 gross
barrels of oil per day. The project is currently producing an additional 100
gross barrels of oil per day, which the Company believes is due to the
high-pressure air injection process.

Due to these early positive results, the Company is evaluating expanding
the process in the Pennel, Coral Creek, and Little Beaver units on the CCA. We
believe that High-Pressure Air Injection will generate a higher rate of return
than other types of tertiary processes on the Cedar Creek Anticline. If the HPAI
technology can be applied throughout the Cedar Creek Anticline, we believe it
has the potential to yield significant new reserves. We are currently
considering an additional $25.0 million in 2003 for High-Pressure Air Injection.
The potential $25.0 million investment will be to implement the second phase of
a four phase program in the Pennel and Coral Creek Red River U4 zones. The Red
River U4 zone is the same zone where HPAI has been successfully implemented on
the Cedar Creek Anticline in adjacent fields. In addition, we are studying
another program on the Cedar Creek Anticline for our Little Beaver field, the
southern most field in the CCA.

Readers and investors should note that we implemented a limited scale
program and the results are highly prospective. While management is enthusiastic
about the program, continued success of the program, as well as the amount of
additional production and reserves attributable to the program, if any, cannot
be predicted with certainty at this time.

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. 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 2002, our largest purchasers included
ConAgra and Equiva Trading Company (a joint venture between Shell and

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Texaco), which respectively accounted for 16% and 10% 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 its ability to market our oil and natural
gas production.

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 acquire additional properties in the
future will depend upon our ability to conduct efficient operations, to evaluate
and select suitable properties, implement advanced technologies, and to
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 Encore. 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 charged 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. Encore 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 the Company's properties and the direct access to
end-user markets, the future impact of these regulations on marketing Encore's
production or on its 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 Encore's 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. Encore's 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.

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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 Encore is in
substantial compliance with applicable environmental laws and regulations. To
date, we have not expended any material amounts to comply with such regulations,
and management does not currently anticipate that future compliance will have a
materially adverse effect on the consolidated financial position or results of
operations of Encore.

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 which 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.

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 OF THE COMPANY

The Company had 108 employees as of December 31, 2002, 46 of which are
field personnel. None of the employees are represented by any union. The Company
considers its relations with its employees to be good.

INTERNET ADDRESS

We make available electronically, free of charge through our Internet
website address (www.encoreacq.com), our annual reports on Form 10-K, quarterly
reports on Form 10-Q, current reports on Form 8-K, and amendments to those
reports filed with the Securities and Exchange Commission (the "SEC") pursuant
to Section 13(a) of the Exchange Act as soon as reasonably practicable after we
electronically file such material with the SEC. These reports are directly
accessible on the Internet at www.shareholder.com/encore/edgar.cfm.

PROPERTIES

NATURE OF OUR OWNERSHIP INTERESTS

We own interests in oil and natural gas properties located in Montana,
North Dakota, Texas, New Mexico, Oklahoma, and Utah. Substantially all of our
PV-10 reserve value at December 31, 2002 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.

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 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)

11

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.

ROCKY MOUNTAIN PROPERTIES

Cedar Creek Anticline -- Montana and North Dakota

The Cedar Creek Anticline was purchased on June 1, 1999, and we have
subsequently acquired additional working interests from various owners.
Presently, we operate approximately 99% of the 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. The Company's 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, the Company has increased production 67% on the CCA from 7,807 BOE
per day (average June, 1999) to 13,060 BOE per day (average 4Q, 2002). We have
accomplished this ongoing production growth through a combination of additional
acquisition of interests; detailed attention to the existing wellbores; the
addition of strategically positioned new wellbores; and the highly successful
application of horizontal re-entry drilling. In 2002, we drilled 96 gross wells
on the CCA, representing $71.7 million of cost. Of these, 63 were horizontal
re-entry wells which both reestablished production from non-producing wells, and
added additional barrels from existing producing wells. The average daily
production from the CCA was 12,354 BOE per day for 2002.

Our outlook for sustained production growth on the CCA remains strong. The
Company plans to continue the development of the reserve base through currently
identified opportunities, and those that result from the knowledge gained
through continued study and the drilling and exploitation efforts ongoing on
these properties.

The CCA represents 75% of our total proved reserves as of December 31,
2002. The CCA represents the Company's most valuable asset today and in the
foreseeable future. A large portion of the Company's future success revolves
around future exploitation and production from the property.

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 98% of our interests are non-operated; the
largest of which is the Eland Unit in which the Company owns 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 2,238 BOE per day for 2002.

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 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 2003 and a few years beyond.

12

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. The Company
operates 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. The average daily
production from the Bell Creek properties was 354 BOE per day for 2002. We
believe this property has the potential for significant tertiary recovery in the
future.

Paradox Basin -- San Juan County, Utah

On August 29, 2002 the Company completed an acquisition of interests in oil
and natural gas properties in southeast Utah's Paradox Basin. 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 11.06% and 9.68%,
respectively, and the working interest and the net revenue interest in the Aneth
Unit are 13.37% and 11.43%, respectively. The average net production to Encore
since the acquisition is approximately 871 BOE per day. We believe these
properties have horizontal redevelopment, secondary development, and tertiary
recovery potential.

PERMIAN AND ANADARKO BASIN PROPERTIES

Crockett -- Crockett County, Texas

The Crockett properties were purchased on March 30, 2000. The Company has
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. The Company operates approximately 52% 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 prolific Canyon and Strawn Formations.
Both formations contain multiple pay intervals, and continued development
opportunities remain on these properties. In 2002, we invested approximately
$0.6 million drilling on the Crockett properties. Since acquiring these
properties, we have increased production 23% from 8,700 Mcfe per day (average
daily 2000) to 10,682 Mcfe per day (average daily 2002). The Crockett properties
are the Company's most significant producers of natural gas.

In 2003, an active development drilling program is expected on our
non-operated properties. The operator expects to drill approximately 12 wells in
2003 which are included in our 2 rig 40 well program in the Permian Basin.

Indian Basin -- Eddy County, New Mexico

The Indian Basin properties were purchased on August 24, 2000. The Company
owns varied non-operated working interests in these properties (primary area
operators are Marathon and ChevronTexaco), whose production is 95% 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. The
average daily production from the Indian Basin properties was 3,242 Mcfe per day
for 2002.

Verden -- Caddo and Grady Counties, Oklahoma

The Verden properties were purchased on August 24, 2000. The Company owns
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. We have participated in the
drilling of four new wells in this area, and average daily production from the
Verden properties was 4,401 Mcfe per day for 2002.

13

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.
All of these fields contain multiple producing intervals. Average daily
production from the Central Permian properties was 1,978 BOE per day in 2002.

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.

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 the Company's
acreage position in the Cedar Creek Anticline, our primary asset, is subject to
net profits interests.

ITEM 3. LEGAL PROCEEDINGS

The Company is 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 the Company's stockholders during the
fourth quarter ended December 31, 2002.

14

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

The Company's Common Stock, $0.01 par value, is listed on the New York
Stock Exchange and trades under the symbol "EAC". The following table sets forth
quarterly high and low closing sales prices of the Company's Common Stock for
each quarterly period of 2001 and 2002, since our initial public offering
("IPO") on March 8, 2001:

On March 14, 2003, the Company had approximately 1,300 shareholders of
record.

DIVIDENDS

No dividends have been declared or paid on the Company's 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, and any future dividends may also be restricted by
future agreements with our lenders.

15

ITEM 6. SELECTED FINANCIAL DATA

The following selected consolidated financial data since inception 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):

- ---------------

(1) For the years ended December 31, 2002, 2001, 2000, and 1999 the Company
reduced revenue for the payments of the net profits interests by $2.0
million, $2.8 million, $11.5 million, and $4.4 million, respectively.

(2) Net income for the year ended December 31, 2002 includes a $0.2 million
extraordinary loss on early extinguishment of debt, which affects its
comparability with other periods presented.

(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 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

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", 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:

- amount, nature, and timing of capital expenditures;

- drilling of wells;

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

- increases in proved reserves;

- operating costs and other expenses;

- cash flow and anticipated liquidity;

17

- prospect exploitation and property acquisitions; and

- marketing of oil and natural gas.

Any or all of our forward-looking statements in this Report may turn out to
be wrong. They can be affected by inaccurate assumptions we might make or by
known or unknown risks and uncertainties. Many factors mentioned in our
discussion in this Report would be important in determining future results.
Actual future results may vary materially. Factors that could cause our results
to differ materially from the results discussed in the forward-looking
statements include the following:

- the risks associated with operating in one or two major geographic areas;

- the risks associated with drilling of oil and natural gas wells in our
exploitation efforts;

- our ability to find, acquire, market, develop, and produce new
properties;

- oil and natural gas price volatility;

- uncertainties in the estimation of proved reserves and in the projection
of future rates of production and timing of exploitation expenditures;

- operating hazards attendant to the oil and natural gas business;

- drilling and completion risks that are generally not recoverable from
third parties or insurance;

- potential mechanical failure or underperformance of significant wells;

- climatic conditions;

- availability and cost of material and equipment;

- actions or inactions of third-party operators of our properties;

- our ability to find and retain skilled personnel;

- availability of capital;

- the strength and financial resources of our competitors;

- regulatory developments;

- environmental risks; and

- general economic conditions.

When you consider these forward-looking statements, you should keep in mind
these risk factors and the other cautionary statements in this Report.

DESCRIPTION OF CRITICAL ACCOUNTING POLICIES

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.
18

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 financial statements.
Natural gas volumes are converted to equivalent barrels at the rate of six Mcf
to one barrel.

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 recorded in accumulated depletion, depreciation,
and amortization ("DD&A") to reduce our recorded basis in the asset. Each part
of this calculation is subject to a large degree of management judgment,
including the determination of property's reserves, future cash flows, and fair
value.

Management's assumptions used in calculating reserves or regarding the
future cash flows or fair value of our properties are subject to change in the
future. Any change could cause impairment expense to be recorded, reducing our
net income and our basis in the related asset. 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. There
can be no assurance that the proved reserves will be developed within the
periods estimated or that prices and costs will 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.
Additionally, as management's views related to future prices change, this
changes the calculation of future net cash flows and also affects fair value
estimates. Changes in either of these amounts will directly impact the
calculation of impairment.

DD&A expense is also directly affected by the Company's reserve estimates.
Any change in reserves directly impacts the amount of DD&A expense the Company
recognizes in a given period. Assuming no other changes, such as an increase in
depreciable base, as the Company's 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 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 the subsequent three quarters of the
new year.

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 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.

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

19

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.

Prior to January 1, 2001, these agreements were accounted for as hedges
using the deferral method of accounting. Unrealized gains and losses were
generally not recognized until the physical production required by the contracts
was delivered. At the time of delivery, the resulting gains and losses were
recognized as an adjustment to oil and natural gas revenues. The cash flows
related to any recognized gains or losses associated with these hedges were
reported as cash flows from operations. If the hedge was terminated prior to
maturity, gains or losses were deferred and included in income in the same
period as the physical production required by the contracts was delivered.

We also use derivative instruments in the form of interest rate swaps,
which hedge our risk related to interest rate fluctuation. Prior to January 1,
2001, these agreements were accounted for as hedges using the accrual method of
accounting. The differences to be paid or received on swaps designated as hedges
were included in interest expense during the period to which the payment or
receipt related. The cash flows related to recognized gains or losses associated
with these hedges were reported as cash flows from operations.

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 required 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 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 the Company's derivative financial instruments qualify for hedge accounting.
The only exceptions at December 31, 2002 are a written oil put contract
representing 500 Bbls/D for 2003 and several interest rate swap contracts. In
accordance with the provisions of SFAS 133, these are marked-to-market through
earnings each quarter. If oil prices or LIBOR interest rates were to change
dramatically and cause a material increase or decrease in the market value of
these contracts, the change would be recognized in earnings immediately.

Currently, all of the Company's derivative financial instruments that
qualify for hedge accounting 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 into earnings immediately. While management does not
anticipate changing the designation of any of our current derivative contracts
as hedges, factors beyond our control could 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 deemed creditworthy and non-performance under the
terms of the contract was likely. If any of our contracts no longer qualify for
hedge accounting, this potentially could induce high earnings volatility, as any
future changes in the market value of the contract would then be
marked-to-market through earnings.

20

NEW ACCOUNTING STANDARDS

In August 2001, the FASB issued Statement of Financial Accounting Standards
No. 143 ("SFAS 143"), Accounting for Asset Retirement Obligations, which the
Company will be required to adopt 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.

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 recorded in
the second quarter of 2002 will be reclassified to operating income.

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 (in thousands
except per unit amounts):

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 the Company's 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. The Company
recovered a portion of the natural gas price decline through its 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.

For 2003 we anticipate increased production related to our anticipated $105
million capital drilling program. Unless changes are made to our planned
drilling activities or another acquisition is made, production should be
approximately 7.7 million BOE for 2003.

Prices received for oil and natural gas production are largely based on
current market prices, which are beyond our control. During 2002, prices were
trending upward. The NYMEX strip pricing at December 31, 2002 indicates higher
oil and natural gas prices in 2003. We have based our 2003 forecasts on the
assumptions of $23.50 per Bbl and $3.75 per Mcf NYMEX prices. At these assumed
prices, we have forecasted hedge contract payments of approximately $2.3 million
for oil and receipts of $0.6 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 $0.7 million for oil and $0.02
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, the Company will not be able to fund the budgeted $105 million
drilling program for 2003 through internally generated cash flow and available
cash. In this case, the Company would have to borrow money under our existing
revolving credit facility, seek additional equity, or curtail the capital
program. If drilling is curtailed or ended, future cash flows could be
materially negatively impacted.

Direct lifting costs. Direct lifting costs of the Company for the year
ended December 31, 2002 increased as compared to 2001 by $5.5 million. The
increase in direct lifting costs 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" on page 21. On a
per BOE basis, direct lifting costs increased from $4.00 in 2001 to $4.15 in
2002 primarily due to higher per BOE lifting costs for our 2002 acquisitions.

For 2003 we anticipate an increase in total direct lifting costs, as well
as on a per BOE basis. We anticipate this increase due to a full year of
production at our Paradox Basin properties which have a higher per BOE operating
costs than our Company's historical average for direct lifting costs, as well as
expected higher electricity costs, one of the largest components of direct
lifting costs, on our Permian and

22

CCA properties. We have projected total direct lifting costs of approximately
$37.6 million or $4.89 per BOE for 2003.

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" on page 21. As a
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.

For 2003 total production, ad valorem, and severance taxes will depend in a
large part on prevailing prices. However, the production, ad valorem, and
severance tax rate should remain relatively constant at an estimated 9.6% of
wellhead revenues. As production is forecast to increase, similar prices in 2003
as in 2002 would cause an increase in total production, ad valorem, and
severance taxes. Additionally, if prices continue to stay above $30 per Bbl we
will temporarily lose production and severance tax incentives in Montana and
North Dakota, which would cause our tax rates to increase in 2003.

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 "-- Comparison of 2002 and 2001 -- Revenues and Production" on
page 21. 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.

We anticipate the total DD&A expense in 2003 to increase due to increased
production resulting from the Paradox Basin acquisition and our planned 2003
capital expenditures of $105 million. Assuming capital expenditures that do not
differ significantly from our budgeted amount, we expect our DD&A rate for 2003
to be approximately $4.15 per BOE. This per BOE decrease from 2002 is primarily
due to the effects of Statement of Financial Accounting Standards No. 143,
"Accounting for Asset Retirement Obligations" and higher proved reserve volumes
at December 31, 2002. This rate could vary significantly based on actual capital
expenditures, production rates, and any acquisition that closes in 2003.
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 $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.

We have forecast approximately $6.8 -- $7.3 million for general and
administrative expenses in 2003. This represents a modest increase of $0.6 to
$1.1 million from 2002. The increase will result from higher insurance, rent,
salaries, and hiring additional support staff necessary for our growing asset
base.

Other operating expense. Other operating expense for the year ended
December 31, 2002 increased as compared to 2001 by approximately $0.8 million.
This amount primarily consists of 2001 severance payment obligations to former
employees of the Company, 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.

For 2003, we anticipate other operating expense to be approximately $1.0 to
$1.5 million.

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, the Company issued $150.0 million in 8 3/8% senior subordinated notes, and
used most of the

23

proceeds to repay all amounts outstanding under the previous credit facility,
terminated the previous credit facility, and entered into a new revolving credit
facility. See "-- Liquidity and Capital Resources" on page 29. 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 these notes as compared to the floating
rate debt outstanding previously.

At the time the previous credit facility was terminated, the Company 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):

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 stock.

At the end of the fourth quarter of 2002, the Company issued 129,328 shares
of restricted stock to all current employees. Of these, 77,901 shares vest 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 will be recorded over the related service period as
shown in the table below. The remaining 51,427 shares were issued to four
members of senior management and also vest 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. The table below reflects the

24

estimated expense related to the restricted stock grant to be recorded in the
future by year based on the Company's stock price at December 31, 2002 (in
thousands).

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. See "Item 7A. Quantitative and Qualitative Disclosures about Market
Risk -- Commodity Price Sensitivity" on page 32.

Currently this line item on the statement of operations is primarily
dependent on the futures price of oil and LIBOR interest rates. This is due to
the fact that, currently, the main components are the mark-to-market movement
and settlements of our short oil put and our interest rate swaps.

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, 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
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. Any ultimate
recovery on the Enron receivable will be recognized in earnings if and when
management believes recovery of the asset is probable.

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. According to the provisions of SFAS 133, this gain must be recorded in
other comprehensive income until such time as the original hedged production
affects income. As a result, at December 31, 2001, we had $4.8 million in gross
unrecognized gains in other comprehensive income that are being reversed into
earnings during 2002 and 2003. The following table illustrates the current and
future amortization of this amount to revenue (in thousands):

Oil revenues increased $13.3 million from 2000 to 2001. As illustrated
above, this was due to an increase in oil volumes offset by a decrease in net
price per Bbl. Oil volumes increased 974 MBbls from 2000 to 2001 due to a full
year of production from the acquisitions completed during 2000, as well as
increased production from the Company's successful development drilling program.
This increase in

26

production added $2.4 million in wellhead revenue despite a decrease of $5.10
per barrel in the wellhead price received. The decrease in wellhead price
resulted primarily from a decrease in the overall market price for oil in 2001
as reflected in the $4.21 per Bbl decrease in the average NYMEX price from 2000
to 2001. Oil revenues were reduced by $2.7 million and $11.2 million in 2001 and
2000, respectively, for the net profits interests payments held by others in
CCA. The decrease in net profits interests payments in 2001 was due to increased
capital activity, which reduces the net profits interests payments. The decrease
in wellhead oil revenues was offset by a decrease in payments made for hedging,
which decreased $10.9 million. The Company's hedging activities are not a
component of the expenses deducted in calculating net profits interest payments.
The decrease in hedging payments is a direct result of the decrease in the
average NYMEX price for oil.

Natural gas revenues increased from 2000 to 2001 by $13.6 million due to a
3,775 MMcf increase in production, while net price received decreased by $0.11.
The increase in volumes is due to a full year of production for the acquisitions
completed in 2000, as well as increased production in the CCA and Crockett
County properties due to successful development drilling. Wellhead price
received decreased $0.37 per Mcf, while the average NYMEX price increased $0.46
per Mcf. This is the result of higher prices received in relation to NYMEX for
natural gas in the CCA versus the price discount received in the Indian
Basin/Verden areas. Hedging payments decreased $0.26 per Mcf due to different
hedges being in effect during 2001 than 2000.

Direct lifting costs. Direct lifting costs of the Company for the year
ended December 31, 2001 increased as compared to 2000 by $6.5 million. The
increase in direct lifting costs resulted from the increase in volumes related
to the full year effect of our 2000 acquisitions and our successful drilling
program, as well as an increase in direct lifting costs per BOE. See
"-- Comparison of 2001 to 2000 -- Revenues and Production" on page 26. On a per
BOE basis, direct lifting costs increased from $3.99 in 2000 to $4.00 in 2001
due to higher workover and contract labor costs in the CCA resulting from to the
relatively harsh winter and the increased cost for services. Additionally, the
Company invested $1.0 million related to workovers in Bell Creek, which was
acquired in December 2000.

Production, ad valorem, and severance taxes. Production, ad valorem, and
severance taxes for the year ended December 31, 2001 decreased as compared to
2000 by approximately $1.4 million. The decrease is a direct result of the
decrease in wellhead revenue. See "-- Comparison of 2001 to 2000 -- Revenues and
Production" on page 26. As a percentage of oil and natural gas revenues
(excluding the effects of hedges), production, ad valorem, and severance taxes
decreased from 10.6% to 9.1% from 2000 to 2001. This decrease was the result of
a higher production, ad valorem, and severance tax rate in Montana associated
with our CCA asset versus the lower tax rates in Texas, North Dakota, New
Mexico, and Oklahoma associated with our Crockett County, Lodgepole, and Indian
Basin/Verden assets. Thus, as the percentage of revenue from Crockett County,
Lodgepole, and Indian Basin/Verden increased in 2001, the total production, ad
valorem, and severance tax rate for all areas declined.

Depletion, depreciation, and amortization ("DD&A") expense. DD&A expense
increased by approximately $9.6 million from 2000 to 2001. This increase was due
to a 1.6 MMBOE increase in production volumes, as well as an increase in the
DD&A rate per BOE. See "-- Comparison of 2001 to 2000 -- Revenues and
Production" on page 26. The average DD&A rate increased from $4.72 per BOE of
production during 2000 to $5.05 per BOE in 2001. The increase in volumes caused
a $6.4 million increase in related DD&A expense, while the increased DD&A rate
caused a $3.2 million increase. The higher rate in 2001 is attributable to
higher per BOE acquisition costs associated with the Crockett County, Lodgepole,
Indian Basin/Verden, and Bell Creek acquisitions completed in 2000 as compared
to the original rate associated with the Cedar Creek Anticline.

General and administrative (G&A) expense. G&A expense increased $0.7
million from 2000 to 2001 (excluding non-cash stock based compensation of $9.6
million and $26.0 million in 2001 and 2000, respectively). The increase in G&A
resulted from the additional staff and lease space necessary for the Crockett
County, Lodgepole, Indian Basin/Verden, and Bell Creek acquisitions completed in
2000. During 2001, the Company leased an additional floor at the corporate
headquarters and incurred additional costs

27

related to being a publicly traded company. On a per BOE basis, G&A expense fell
to $0.80 during 2001 from $0.93 during 2000. This reduction resulted as fixed
costs were spread over a greater amount of production in 2001 as compared to
2000.

Other Operating Expense. The Company recorded $0.9 million of other
operating expense in 2001 with no similar amount in 2000. This amount primarily
consists of severance payments made during 2001 or accrued at December 31, 2001
to former employees of the Company, as well as transportation costs, namely
pipeline fees paid to third parties. Additionally, geological and geophysical
and delay rentals are recorded on this line in the statement of operations.

Interest expense. Interest expense for the year ended December 31, 2001
decreased $4.4 million from 2000 to 2001. The decrease in interest expense
resulted primarily from the pay down of debt in conjunction with the Company's
initial public offering. In addition the weighted average interest rate,
including hedges, for 2001 was 6.8% compared to 7.4% for 2000. The following
table illustrates the components of interest expense for 2001 and 2000 (in
thousands):

Non-cash stock based compensation expense. Non-cash stock based
compensation expense decreased from $26.0 million for 2000 to $9.6 million for
2001. 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 2001 non-cash compensation expense was recorded in the first quarter
of 2001 and represents the final amount of expense to be recorded related to the
Class A stock.

Derivative fair value loss. The derivative fair value loss of $0.7 million
in 2001 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, 2001. These amounts are now being
recorded as required by Statement of Financial Accounting Standards 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). No
similar amounts were recorded in 2000 as we adopted SFAS 133 effective January
1, 2001.

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, 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
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. Any ultimate
recovery on the Enron receivable will be recognized in earnings when management
believes recovery of the asset is probable.

28

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. According to the provisions of SFAS 133, this gain must be recorded in
other comprehensive income until such time as the original hedged production
affects income. As a result, at December 31, 2001, we had $4.8 million in gross
unrecognized gains in other comprehensive income that will be reversed into
earnings during 2002 and 2003. The following table illustrates the future
amortization of this amount to revenue (in thousands):

Impairment of Oil and 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 our Bell Creek properties. We then compared the net book value of the
Bell Creek properties to their estimated fair value, which resulted in a
write-down of the value of proved oil and 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.

LIQUIDITY AND CAPITAL RESOURCES

Principal uses of capital have been for the acquisition and development of
oil and natural gas properties.

During the year ended December 31, 2002, net cash provided by operations
was $91.5 million, an increase of $11.3 million compared to 2001. This was due
in large part to higher net income in 2002 as compared to 2001. Encore's
operating cash flow is determined in a large part by commodity prices. Assuming
moderate to high commodity prices, the Company's operating cash flow should
remain positive for the foreseeable future. We anticipate that our capital
expenditures will total approximately $105.0 million for 2003. 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 development and acquisition expenditures using internally generated
cash flow, available cash, and our existing credit agreement.

At December 31, 2002, the Company had total assets of $549.9 million. Total
capitalization was $462.3 million, of which 64.1% was represented by
stockholders' equity and 35.9% by senior debt.

On June 25, 2002, the Company sold $150 million of 8 3/8% Senior
Subordinated Notes maturing on June 15, 2012 (the "Notes") in a private offering
exempt from registration requirements of the Securities Act of 1933 as amended.
The offering was made through a private placement pursuant to Rule 144A. 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 the new revolving credit facility ($1.5 million), and to
hold in reserve for the Paradox Basin acquisition ($1.1 million).

29

In connection with the issuance of the Notes, we entered into a
registration rights agreement, dated June 19, 2002, with the initial purchasers
of the Notes and entered into an indenture governing the Notes. The indenture
limits our ability, among other things, to:

- incur additional indebtedness;

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

- make investments;

- incur liens;

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

- engage in transactions with affiliates;

- sell assets, including capital stock of our subsidiaries; and

- consolidate, merge or transfer assets.

Pursuant to the registration rights agreement, we filed a registration
statement on Form S-4/A with the SEC, which was declared effective on December
6, 2002, with respect to the exchange of the Notes for registered notes having
terms substantially identical in all material respects. On January 16, 2003, all
of the Notes were exchanged for the registered notes, Encore's registered senior
subordinated notes due June 15, 2012 were issued and the Notes were cancelled.
The Company did not receive any proceeds from the exchange.

The registered notes are senior subordinated unsecured obligations of
Encore. The registered notes mature on June 15, 2012. We pay interest on the
registered notes semiannually on June 15 and December 15, beginning on December
15, 2002. The registered notes rank equal in right of payment with any of our
future senior subordinated indebtedness and are subordinated in right of payment
to our obligations under our revolving credit facility (see next paragraph) and
of our other existing and future senior indebtedness. The payment of principal,
interest, and premium on the registered notes is fully and unconditionally
guaranteed, jointly and severally, on a senior subordinated basis, by our
existing and some of our future restricted subsidiaries. We are entitled to
redeem the registered notes in whole or in part on or after June 15, 2007 for
the redemption price set forth in the registered notes. Prior to June 15, 2005,
we are entitled to redeem the registered notes, in whole but not in part, at a
redemption price equal to the principal amount of the registered notes plus a
premium. There is no sinking fund for the notes. If we fail to comply with some
of our obligations under the registration rights agreement relating to the
registered notes, we will pay additional interest on the registered notes.

Concurrently with the issuance of the Notes, we entered into a new
revolving credit facility with a syndicate of banks, which replaced our prior
credit facility. All of our subsidiaries are guarantors of our revolving credit
facility. The maximum amount available under our revolving credit facility is
$300.0 million, which is secured by a first priority lien on our proved oil and
natural gas reserves representing at least 80% of the present discounted reserve
value. As of December 31, 2002, the amount available to us under our revolving
credit facility is $220.0 million which may be increased and decreased subject
to a borrowing base calculation. As of December 31, 2002, $16.0 million was
outstanding under the new revolving credit facility. The maturity date is June
25, 2006.

We may choose between two base loan interest rates. The first base interest
rate (the "ABR Rate") is a rate calculated as the highest of:

- the annual rate of interest announced by the Agent Bank as its "base
rate"; and

- the federal funds effective rate plus 0.5%;

30

plus a margin of 0% to 0.75% based upon the level of borrowing. The second base
rate (the "LIBOR Rate") is equal to the London InterBank offered rate plus a
margin of 0% to 1.75% based upon the level of borrowing. In addition to the
foregoing rates, we must pay a commitment fee on unused portions of the
available borrowing base. Interest on ABR Rate loans is paid quarterly in
arrears. At our election, interest periods for LIBOR Rate loans are one, three,
six or twelve months, and interest is payable at the end of each interest period
and at the end of each succeeding three month period.

Borrowings under our revolving credit facility are guaranteed by each of
our subsidiaries and are secured by a mortgage of our oil and natural gas
properties and a pledge of the capital stock and equity interests of our
subsidiaries. We pay customary fees to the various banks and agents.

The borrowing base is to be redetermined each June 1 and December 1. The
bank syndicate has the ability to request one additional borrowing base
redetermination per year, and we are permitted to request two additional
borrowing base redeterminations per year. Generally, if amounts outstanding ever
exceed the borrowing base, we must reduce the amounts outstanding to the
redetermined borrowing base within six months, provided that if amounts
outstanding exceed the borrowing base as a result of any sale of our assets, we
must reduce the amounts outstanding immediately upon consummation of the sale.

Our revolving credit facility contains a number of negative and financial
covenants, all of which we were in compliance with as of December 31, 2002.

These covenants include, among others:

- a prohibition against incurring debt in excess of $15.0 million, except
for borrowings under our revolving credit facility, the outstanding
notes, and the exchange notes;

- a prohibition against paying dividends or purchasing or redeeming capital
stock or prepaying indebtedness (including the outstanding notes and the
exchange notes);

- a restriction on creating liens on our assets;

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

- restrictions on use of proceeds, investments, transactions with
affiliates, changing our principal business, and incurring funding
obligations under ERISA;

- a provision limiting oil and natural gas hedging transactions to a volume
not exceeding 75% of anticipated production from proved reserves;

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

- a requirement that we maintain a ratio of consolidated EBITDA (as defined
in our revolving credit facility agreement) to the sum of consolidated
net interest expense plus our letter of credit fees of not less than 2.5
to 1.0.

Based on current commodity conditions, the Company believes that its
capital resources are adequate to meet the requirements of its business through
2004. Based on our anticipated capital investment programs, we expect to invest
our internally generated cash flow to replace production and enhance our
development programs. During 2003, we plan to invest approximately $105 million
to exploit and develop existing core properties. The $105 million budgeted does
not include the possible $25 million for additional high-pressure air-injection
capital. See "Item 1 Business and Properties -- Present Activities -- Cedar
Creek Anticline High-Pressure Air Injection Limited Scale Program" on page 9.
Additional capital may be required to pursue acquisitions or other capital
projects. Substantially all of these 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.

31

Additionally, we are required to maintain margin amounts and/or letters of
credits on our outstanding hedges with our counter parties if the hedges reach a
certain negative value. At December 31, 2002, the Company had an outstanding
letter of credit with a counterparty in the amount of $2.3 million, which
expired on January 31, 2003. If oil prices continue to rise, we could be
required to make margin deposits or increase our outstanding letters of credits.
Also, subsequent to December 31, 2002, the Company cash settled the two
outstanding $30 million interest rate swaps at a cost of $4.3 million.

The following table illustrates the Company's contractual obligations
outstanding at December 31, 2002:

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, 2002, 2001, and 2000. Average
equivalent prices for 2002, 2001, and 2000 were decreased by $0.70, $2.04, and
$4.92 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.

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. Trades are
executed by the Director of Corporate Planning. The Treasury Department handles
the administration functions, which entail tracking existing trades, confirming
new trades, and conducting monthly settlements. Our Accounting Department
records the transactions in the financial statements. We plan to continue in the
normal course of business to hedge our exposure to fluctuating commodity prices.
These arrangements will not exceed 75% of anticipated production from proved
producing reserves. For the first

32

six months of 2003, we have approximately 72% of our estimated oil production
placed in floors, 45% capped, and 6% in swap agreements and for the last six
months of 2003, we have approximately 63% in floors and 47% capped. For the
first six months of 2004, we have approximately 27% of our oil production placed
in floors and 27% capped and for the last six months of 2004, we have
approximately 3% in floors and 3% capped. In addition, for 2003, we have
approximately 42% of our estimated natural gas placed in floors, 14% capped, and
14% in swap agreements and for 2004 we have approximately 21% in floors and 11%
capped. Our hedging policy does not permit us to engage in hedging transactions
for speculation for our own account.

Counterparties. The Company's counterparties to hedging contracts include:
Bank of America; BNP Paribas; Deutche Bank; Morgan Stanley; Credit Lyonnais; J.
Aron & Company, a wholly-owned subsidiary of Goldman, Sachs & Co.; and CIBC
World Markets ("CIBC"), the marketing arm of the Canadian Imperial Bank of
Commerce. Approximately 58%, 21%, and 16% of estimated oil production hedged is
committed to J. Aron & Company, Morgan Stanley, and Credit Lyonnais,
respectively. Approximately 50%, 33%, and 17% of our hedged gas production is
contracted with Morgan Stanley, J. Aron & Company, and BNP Paribas,
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 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, 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 separately each financial
transaction between the Company and its counterparty, 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.

Commodity price sensitivity. The tables in this section provide
information about derivative financial instruments to which we were a party as
of December 31, 2002 that are sensitive to changes in oil and natural gas
commodity prices.

The Company hedges 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 statement of operations. At December 31, 2002, we had one such contract in
place representing 500 Bbls/D with a strike price of $17.00 per barrel. The
unrealized mark-to-market loss on our outstanding commodity derivatives at
December 31, 2002 was approximately $8.9 million. The fair market value of our
oil hedging contracts was $(4.2) million and the fair market value of our
natural gas hedging contracts was $(0.8) million.

33

OIL HEDGES AT DECEMBER 31, 2002

NATURAL GAS HEDGES AT DECEMBER 31, 2002

Interest rate sensitivity. At December 31, 2002, the Company had total
debt of $166.0 million. Of this amount, $150.0 million bears interest at a fixed
rate of 8 3/8%. The remaining outstanding debt balance of $16.0 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. We have entered into interest rate swap agreements to hedge
the impact of interest rate changes on a portion of our floating rate debt. As
of December 31, 2002, we had interest rate swaps as follows:

Subsequent to December 31, 2002, the Company cash settled the two outstanding
$30 million interest rate swaps at a cost of $4.3 million. Thus, Encore now pays
a LIBOR based floating rate on amounts outstanding under our credit facility and
on $80 million of swap notional. The following table represents the average
three-month forward LIBOR curve by year:

34

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:

Acquisition and Development Costs. Capital costs incurred in the
acquisition, development, exploitation, and revisions of proved oil and natural
gas reserves.

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.

Direct lifting costs. All direct 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.

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.

Gross Acres or Gross Wells. The total acres or wells, as the case may be,
in which we have a working interest.

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.

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.

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.

35

Net Production. Production that is owned by the Company 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. Reserves that are expected to be recovered
from new wells on undrilled acreage or from existing wells where a relatively
major expenditure is required for recompletion.

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.

Tertiary Recovery. An enhanced recovery operation that normally occurs
after waterflooding in which chemicals or natural gasses are used as the
injectant.

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.

36

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Independent Auditor's Report................................ 38
Consolidated Balance Sheets as of December 31, 2002 and
2001...................................................... 40
Consolidated Statements of Operations for the Years Ended
December 31, 2002, 2001, and 2000......................... 41
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2002, 2001, and 2000............. 42
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2002, 2001, and 2000......................... 43
Notes to Consolidated Financial Statements.................. 44
Unaudited Supplemental Information.......................... 61

37

REPORT OF INDEPENDENT AUDITORS

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

We have audited the accompanying consolidated balance sheet of Encore
Acquisition Company and subsidiaries as of December 31, 2002, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
year 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 audit. The financial statements of Encore
Acquisition Company as of December 31, 2001, and for the two-year period 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 audit 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 audit provides a reasonable basis
for our opinion.

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

ERNST & YOUNG LLP

Fort Worth, Texas
January 31, 2003

38

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.

39

ENCORE ACQUISITION COMPANY

CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of these consolidated financial
statements.
40

ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

The accompanying notes are an integral part of these consolidated financial
statements.
41

ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

The accompanying notes are an integral part of these consolidated financial
statements.
42

ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

The accompanying notes are an integral part of these consolidated financial
statements.
43

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, and the
Paradox Basin of Utah.

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.

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 financial statements. Natural gas volumes are converted to equivalent
barrels at the rate of six Mcf to one barrel. See "Note 12 -- New Accounting
Standards" for a discussion of SFAS 143, "Accounting for Asset Retirement
Obligations", which the Company will adopt as of January 1, 2003.

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
44

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the carrying value exceeds fair value. Any impairment charge incurred is
expensed and recorded in accumulated depletion, depreciation, and amortization
("DD&A") to reduce 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 the subsequent three quarters
of the new 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. If
compensation expense for the stock based awards had been determined using the
provisions of 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):

SEGMENT REPORTING

The Company operates in 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.

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 sales
were to ConAgra, Equiva Trading Company and EOTT Energy Co., respectively. For
2000, our largest purchasers included Equiva Trading Company and EOTT Energy Co,
which accounted for 56% and 11% of total oil and natural gas sales,
respectively.

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

45

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 from jointly owned properties as oil and natural
gas is produced and sold, net of royalties. Revenues from natural gas production
are recorded using the sales method, net of royalties. Under this method,
revenue is recognized based on the cash received rather than our proportionate
share of natural gas produced. Natural gas imbalances under-delivered to Encore
at December 31, 2002 and December 31, 2001, were 510,000 MMbtu and 483,000
MMbtu, respectively. Revenues are stated net of any net profits interests held
by others. The reduction in revenue from net profits interest totaled $2.0
million, $2.8 million, and $11.5 million in 2002, 2001, and 2000, 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 statement 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 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
with large financial institutions.

Prior to January 1, 2001, these agreements were accounted for as hedges
using the deferral method of accounting. Unrealized gains and losses were
generally not recognized until the physical production required by the contracts
was delivered. At the time of delivery, the resulting gains and losses were
recognized as an adjustment to oil and natural gas revenues. The cash flows
related to any recognized gains or losses associated with these hedges were
reported as cash flows from operations. If the hedge was terminated prior to
maturity, gains or losses were deferred and included in income in the same
period as the physical production required by the contracts was delivered.

We also use derivative instruments in the form of interest rate swaps,
which hedge our risk related to interest rate fluctuation. Prior to January 1,
2001, these agreements were accounted for as hedges using the accrual method of
accounting. The differences to be paid or received on swaps designated as hedges
were included in interest expense during the period to which the payment or
receipt related. The cash flows related to recognized gains or losses associated
with these hedges were reported as cash flows from operations.

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 and hedging 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 due to
changes in the underlying item being hedged. In
46

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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 taxes of $9.1 million).

Currently, all of our derivative financial instruments that qualify for
hedge accounting 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 into earnings immediately.

USE OF ESTIMATES

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

Estimates with regard to these financial statements include the estimate of
proved oil and natural gas reserve volumes and the estimated future development,
dismantlement, and abandonment costs used in determining amortization
provisions. In addition, significant estimates are required for our assessment
of impairment of long-lived assets. Future changes in the assumptions used could
have a significant impact on whether impairment provisions are required in
future periods.

COMPREHENSIVE INCOME

Comprehensive income includes net income and other comprehensive income,
which includes, but is not limited to, unrealized gains and losses on marketable
securities, foreign currency translation adjustments, minimum pension liability
adjustments, and 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.

With the adoption of SFAS 133 on January 1, 2001, the Company began
recording deferred hedge gains and losses on our derivative financial
instruments as other comprehensive income. For the year ended December 31, 2001,
comprehensive income totaled $20.4 million, while net income totaled $16.2
million. The difference between net income and comprehensive income is the
result of recording a $14.9 million deferred hedge loss as a cumulative change
in accounting, as well as a $19.1 million deferred hedge gain for the year ended
December 31, 2001. The deferred hedge gain for 2001 resulted from a reduction in
the market price of oil and natural gas during the year. The company had $4.2
million at December 31, 2001, in deferred hedge gains, net of tax, in
accumulated other comprehensive income, shown as a component of equity on the
balance sheet.

For the year ended December 31, 2002, comprehensive income totaled $26.9
million, while net income totaled $37.7 million. The difference between net
income and comprehensive income is the result of recording a $10.8 million
deferred hedge loss. The deferred hedge loss for 2002 resulted from an increase
in the market price of oil and natural gas during the year. The company had $6.6
million at December 31, 2002 in deferred hedge losses, net of tax, in
accumulated other comprehensive income, shown as a component of equity on the
balance sheet.

47

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NEW ACCOUNTING STANDARDS

In August 2001, the FASB issued Statement of Financial Accounting Standards
No. 143 ("SFAS 143"), Accounting for Asset Retirement Obligations, which the
Company will be required to adopt 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.

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 recorded in
the second quarter of 2002 will be reclassified to operating income.

3. OIL AND NATURAL GAS PROPERTIES

The cost of oil and natural gas properties at December 31, 2002 includes
$1.2 million of undeveloped leasehold costs. Such properties are held for
development or resale. The following table sets forth costs incurred related to
oil and natural gas properties:

2000 ACQUISITIONS

On February 23, 2000, the Company executed a purchase and sale agreement to
acquire working interests in 278 wells located in Crockett County, Texas
(approximately 130 wells operated, 148 non-operated) for $43 million. The
transaction closed on March 30, 2000.

On March 6, 2000, the Company executed a purchase and sale agreement to
acquire working interests in 25 wells, (23 non-operated, two operated) located
in Stark County, North Dakota for $35.2 million. The transaction closed on March
31, 2000.

48

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company executed a purchase and sale agreement to acquire working
interests in 161 wells located in Oklahoma and New Mexico (approximately seven
wells operated, 154 non-operated) for $25.4 million. The transaction closed on
August 24, 2000 with an effective date of April 1, 2000.

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 sixth major producing
property package since inception. These Central Permian 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.

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 our remaining
non-cancelable future payments under operating leases as of December 31, 2002
(in thousands):

2003........................................................ $959
2004........................................................ 951
2005........................................................ 987
2006........................................................ 520
2007........................................................ 171
Thereafter.................................................. 213

Our operating lease rental expense was approximately $0.9 million, $0.7
million, and $0.3 million in 2002, 2001, and 2000, respectively.

49

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

5. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Accounts payable and accrued liabilities were as follows at December 31 (in
thousands):

6. INDEBTEDNESS

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

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. Borrowings under the credit agreement
totaled $78.0 million as of December 31, 2001. The borrowing base, as
established in the credit agreement, was $180.0 million as of December 31, 2001.
During 2001 and 2000, the weighted average interest rate under the facility was
5.7% and 7.8%, respectively.

In 2001, the Company issued a $35.2 million note payable to the seller in
connection with the Lodgepole acquisition in North Dakota. The note bore monthly
compounded interest at the rate of 4% per annum on the outstanding principal
plus accrued interest. The remaining amount payable at December 31, 2001 was
$1.1 million, which along with accrued interest of $1.3 million, was paid in
January 2002.

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 the new credit
facility ($1.5 million), and to hold in reserve for the Paradox Basin
acquisition ($1.1 million).

50

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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 new facility is $220.0 million, with $16.0 million
outstanding as of December 31, 2002. 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 the Company's borrowing base. Based
on our current $220.0 million borrowing base, our applicable interest rates are
calculated as follows:

Additionally, under the new Revolving Credit 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, 2002, the Company was in compliance with all
covenants.

The following table illustrates the Company's long-term debt maturities at
December 31, 2002 (in thousands):

Consolidated cash payments for interest were $13.2 million, $6.4 million,
and $10.2 million, respectively, for 2002, 2001, and 2000.

51

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 statement of operations were
attributed to the following items (in thousands):

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):

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

52

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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):

No cash income tax payments were made in 2002. Cash income tax payments in
the amount of $1.5 million and $4.0 million were made in 2001 and 2000,
respectively.

TAXES OTHER THAN INCOME TAXES

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

8. STOCKHOLDERS' EQUITY

COMMON STOCK

On August 18, 1998, the Company entered into a Stock Purchase Agreement and
a Stockholders' Agreement (collectively the "Agreements"), with members of our
management ("Management") and

53

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

non-management investors (the "Investors"). Under the terms of the Agreements,
294,901 shares of Class B Common Stock, par value $0.01 per share (the "Class
B") and 73,725 shares of Class A Common Stock, par value $0.01 per share ("Class
A") were authorized to be issued for a total amount of committed consideration
to be invested in the Company of $298 million by Management and the Investors.

At December 31, 2000, 294,901 shares of Class B and 73,725 shares of Class
A were issued and outstanding. The total Management capital commitment for Class
A and Class B shares was approximately $8 million.

During 2000, an additional 4,380 shares of Class A common stock were sold
to employees of the Company.

During 2000, capital calls totaling $21.5 million were initiated in order
to fund the acquisitions of oil and natural gas properties.

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.

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 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 the first quarter of 2001 represented the final compensation expense
to be recorded related to the Class A shares.

54

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

9. EARNINGS (LOSS) 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.

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

- ---------------

(a) Options to purchase 272,177 shares of common stock were outstanding but not
included in calculation of 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 above
amounts.

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 2002, $0.4 million in 2001, and $0.3 million in 2000. The Company's
401(k) plan does not currently allow employees to invest in securities of the
Company.

55

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

INCENTIVE STOCK PLANS

During 2000, the Company's Board of Directors approved the 2000 Incentive
Stock 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 reserved and available for
distribution pursuant to the plan is 1.8 million shares. 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.

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
number of options and their related weighted average strike prices for 2002 and
2001:

- ---------------

(a) None and 4,000 of the options granted in 2002 and 2001, respectively, were
granted to non-employee directors. The weighted average fair value of
individual options granted in 2002 and 2001 was $6.91 and $4.02,
respectively.

(b) The options outstanding at December 31, 2001 had strike prices ranging from
$12.49 to $14.00 and had a weighted average remaining life of 9.4 years. At
December 31, 2002, there were 886,334 options outstanding with strike
prices between $12.49 and $14.00. These had a weighted average remaining
life of 8.5 years and a weighted average strike price of $13.38.
Additionally, at December 31, 2002, there were 292,177 options with strike
prices between $14.01 and $18.60. These had a weighted average remaining
life of 9.9 years and a weighted average strike price of $18.36.

The restricted stock granted under the plan vests equally in years three,
four, and five after issuance. During 2002 and 2001, 129,328 and zero shares,
respectively, of restricted stock was issued to employees. Of the 129,328 issued
at the end of 2002, 77,597 shares 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. The remaining 51,731 shares were
issued to four members of senior management. These shares not only depend on the
passage of time, 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. The stock price on the date of grant in 2002 was
$18.60.

56

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 2002
and 2001:

11. FINANCIAL INSTRUMENTS

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

The book value of cash and cash equivalents approximates fair value because
of the short maturity of these instruments. Since the note payable was payable
on demand if called by the issuer, fair value approximated book 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. At December 31, 2002, we had one such
contract in place representing 500 Bbls/D with a strike price of $17.00 per
barrel.

57

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following tables summarize our open commodity hedging positions as of
December 31, 2002:

OIL HEDGES AT DECEMBER 31, 2002

NATURAL GAS HEDGES AT DECEMBER 31, 2002

As a result of all of our hedging transactions for oil and natural gas we
recognized a pre-tax reduction in earnings of approximately $5.2 million, $12.8
million, and $23.0 million in 2002, 2001, and 2000, respectively. Based on the
fair value of our hedges at December 31, 2002, our unrealized pre-tax loss
recorded in other comprehensive income related to outstanding hedges is $7.3
million for oil and $1.6 million for natural gas. These amounts will be
reclassified to earnings as the related production affects earnings during 2003
and 2004. Of the total deferred hedge loss related to commodity contracts, $8.7
million relates to 2003 contracts and $0.2 million relates to 2004 contracts.
The actual gains or losses we realize from our commodity hedge transactions may
vary significantly from these amounts due to the fluctuation of prices in the
commodity markets. In order to calculate the unrealized gain or loss, the
relevant variables are (1) the type of commodity, (2) the delivery price, and
(3) the delivery location. These calculations may be used to analyze the gains
and losses we might realize on our financial hedging contracts and do not
reflect the effects of price changes on our actual physical commodity sales.

INTEREST RATE DERIVATIVES

As discussed in Note 6, 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 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. The unrealized loss of $3.8 million through June 25, 2002, which was
recognized in accumulated other comprehensive income, is being amortized to
interest expense over the original life of the swaps as follows (in thousands):

58

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

During the third quarter of 2002, the Company cash settled one of the three
interest rate swaps discussed above, resulting in an additional loss of $0.4
million, which was recognized as "Derivative fair value gain/loss" in the
statement of operations.

Also, in conjunction with the sale of the Notes (See Note 6), the Company
entered into an additional interest rate swap, whereby we pay a six-month
trailing LIBOR rate plus 3.89% and receive a fixed 8 3/8% on a notional of $80
million through June 15, 2005. Due to the difference in terms between the swap
and the underlying debt, this instrument does not qualify for hedge accounting
and, along with future changes in the fair value of the two remaining swaps
discussed above, will be marked to market through earnings each period as
"Derivative fair value gain/loss," in the statement of operations.

As of December 31, 2002, we had interest swaps as follows:

As a result of our hedging transactions for interest, we recognized in
interest expense a pre-tax loss of approximately $1.6 million, $0.7 million, and
$0.1 million in 2002, 2001, and 2000, respectively. Additionally, $0.2 million
was recognized in "Derivative fair value gain/loss" in 2002 as our interest rate
swaps do not qualify for hedge accounting after June 25, 2002. The actual gains
or losses we realize from our interest rate swaps may vary significantly from
these amounts due to fluctuations in the LIBOR interest rate.

COUNTERPARTY RISK

The Company's counterparties to hedging contracts include: Bank of America;
BNP Paribas; Deutche Bank; Morgan Stanley; Credit Lyonnais; J. Aron & Company, a
wholly-owned subsidiary of Goldman, Sachs & Co.; and CIBC World Markets
("CIBC"), the marketing arm of the Canadian Imperial Bank of Commerce.
Approximately 58%, 21%, and 16% of estimated oil production hedged is committed
to J. Aron & Company, Morgan Stanley, and Credit Lyonnais, respectively.
Approximately 50%, 33%, and 17% of our hedged gas production is contracted with
Morgan Stanley, J. Aron & Company, and BNP Paribas, 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
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.

59

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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. Any ultimate recovery on the Enron receivable will be recognized
in earnings when management believes recovery of the asset to be probable.

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. According to the provisions of SFAS 133, this gain must be recorded in
other comprehensive income until such time as the original hedged production
affects income. As a result, at December 31, 2001, the Company had $4.8 million
in gross unrecognized gains in other comprehensive income that will be reversed
into earnings during 2002 and 2003. The following table illustrates the current
and future amortization of this amount to revenue (in thousands):

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 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, 2000 and 2002, and determined no
impairment charge was necessary.

14. SUBSEQUENT EVENTS

During January 2003, the Company cash settled the two outstanding $30
million interest rate swaps at a cost of $4.3 million. Thus, Encore now pays a
LIBOR based floating rate on amounts outstanding under our credit facility and
on $80 million of swap notional.

60

UNAUDITED SUPPLEMENTAL INFORMATION

OIL & NATURAL GAS PRODUCING ACTIVITIES

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 indicated 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, 2002, 2001, and, 2000 were $31.20, $19.84, and $26.80 per barrel
for oil and $4.79, $2.57, and $9.77 per Mcf for natural gas respectively. The
net profits interest on our Cedar Creek Anticline properties has been 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 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 shown below. 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
depreciation, depletion, and amortization on these properties.

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

61

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

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:

62

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

63

SELECTED QUARTERLY FINANCIAL DATA

The following table sets forth selected quarterly financial data for the
years ended December 31, 2002 and 2001:

64

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 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 financial statements, or otherwise
require disclosure in this Form 10-K.

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 30, 2003 and is incorporated herein by reference.

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 30, 2003 and is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

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 30, 2003 and is incorporated herein by reference.

65

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 30, 2003 and is incorporated herein by reference.

ITEM 14. 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 a date within 90 days prior to the date of the
filing of 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. No significant changes in our
disclosure controls and procedures or corrective actions have been made
subsequent to the date of such evaluation that could significantly affect these
controls.

66

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 38:

1. Financial Statements:

Report of Independent Public Accountant..................... 38
Consolidated Balance Sheets as of December 31, 2002 and
2001...................................................... 40
Consolidated Statements of Operations for the Years Ended
December 31, 2002, 2001 and 2000.......................... 41
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2002, 2001, and 2000............. 42
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2002, 2001 and 2000.......................... 43
Notes to Consolidated Financial Statements.................. 44

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

The Company filed the following reports on Form 8-K during the quarter
ended December 31, 2002 and through March 14, 2003:

On December 6, 2002, the Company filed a current report on Form 8-K
announcing the filing of amendments to its 2001 Annual Report on Form
10-K and its Quarterly Reports on Form 10-Q for the first three quarters
of 2002.

On February 3, 2003, the Company filed a current report on Form 8-K
announcing year end 2002 reserves, production, and finding and
development costs.

On February 13, 2003, the Company filed a current report on Form 8-K
announcing full year and fourth quarter 2002 results.

(c) Exhibits

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

67

- ---------------

* Filed herewith

** Compensatory plan

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.

68

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 24th day of
March, 2003.

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 Morris B. Smith, 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 and in the capacities and on March 24, 2003.

70

CERTIFICATIONS

I, I. Jon Brumley, Chairman of the Board and Chief Executive Officer of Encore
Acquisition Company, certify that:

1. I have reviewed this annual report on Form 10-K of Encore Acquisition
Company;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

(a) Designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

(b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and

(c) Presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):

(a) All significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal controls;
and

(b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

/s/ I. JON BRUMLEY
--------------------------------------
I. Jon Brumley
Chairman of the Board and Chief
Executive Officer
of Encore Acquisition Company

Date: March 24, 2003

71

CERTIFICATIONS

I, Morris B. Smith, Chief Financial Officer, Treasurer, Executive Vice President
and Secretary of Encore Acquisition Company, certify that:

1. I have reviewed this annual report on Form 10-K of Encore Acquisition
Company;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

(a) Designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

(b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and

(c) Presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):

(a) All significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal controls;
and

(b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

/s/ MORRIS B. SMITH
--------------------------------------
Morris B. Smith
Chief Financial Officer, Treasurer,
Executive Vice President and Secretary
of Encore Acquisition Company

Date: March 24, 2003

72

INDEX TO EXHIBITS