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):

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

25

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

Future impairment charges could result based on changes in the Company's
estimated reserves, management's estimate of future prices, or management's fair
value estimate of our properties. If oil and natural gas prices were to decrease
in the future, our reserves could be negatively impacted and/or management's
estimate of either future cash flows or fair value of our properties could
change. Any of these results could indicate the need for additional impairment
charges.

COMPARISON OF 2001 TO 2000

Set forth below is our comparison of operations during the year ended
December 31, 2001 with the year ended December 31, 2000.

Revenues and Production. For the year ended December 31, 2001, revenues
increased $27.0 million. The following table illustrates the primary components
of oil and natural gas revenue for the years ended December 31, 2001 and 2000,
as well as each year's respective oil and natural gas volumes (in thousands
except per unit amounts):

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 provis