ENCORE ACQUISITION CO - 10-K Annual Report

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

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FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001

COMMISSION FILE NO. 1-16295

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

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. [ ]

Aggregate market value of the voting stock held by
non-affiliates of the Registrant as of March 1, 2002...... $397,296,000
Number of shares of Common Stock, $0.01 par value,
outstanding as of March 1, 2002........................... 30,029,961

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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 26, under the
caption "Glossary of Oil and Natural Gas Terms."

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 rapidly
growing independent energy company engaged in the acquisition, development, and
exploitation of onshore North American oil and natural gas reserves.

Since inception, the Company has maintained a highly disciplined
acquisition process, refined by senior management, to seek and acquire high
quality assets with potential for upside through low-risk development drilling
projects.

Our rapid growth has come primarily from the acquisition of producing oil
and natural gas properties. We have been successful in purchasing six major
packages of producing properties since inception in April 1998. The Company has
acquired producing properties in the Williston, Permian, Anadarko, and Powder
River Basins. All our producing assets reside onshore in the continental lower
48 United States. See "-- Properties". Since our inception, we have invested
$350.8 million in acquiring producing oil and natural gas properties including
our last acquisition that closed in January 2002. We have invested another
$122.5 million for development and exploitation of these properties. The
Company's average inception-to-date "all-in" finding and development cost is
$3.43 per BOE.

The Cedar Creek Anticline ("CCA"), in the Williston Basin of Montana and
North Dakota, represents 90% of our total proved reserves as of December 31,
2001. 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.

The Company strives to acquire long-lived quality assets with upside from
low-risk development drilling opportunities. In 2001, all of our growth was
achieved organically by the drill bit by harvesting a portion of the Company's
extensive inventory of drilling projects. In 2001, we drilled 108 gross operated
wells and participated in drilling another 35 gross non-operated wells for a
total of 143 gross wells for the year. On a net basis, the Company drilled 95
net operated wells and participated in 12 non-operated wells for a total of 107
net wells in 2001. Since our drilling program revolves around low-risk
development opportunities, our success rate for 2001 exceeded 99%. We invested
$87.2 million to drill and complete the 107 net wells for 2001 or approximately
$815,000 net per well. The drilling program added 23.7 million BOE for 2001 at
an average cost of $3.68 per BOE.

The Company's estimated proved reserves at December 31, 2001 were 102.1
MMBls of oil and 78.0 Bcf of natural gas, or 115.0 MMBOE. The proved developed
producing reserves were 89.0 million BOE, or 77% of total proved reserves at
December 31, 2001. Our Reserve-to-Production ratio averaged 18.0 years based
upon December 31, 2001 proved reserves and the prior 12 months' production.
Prevailing prices as of December 31, 2001 were $19.84 per Bbl of oil and $2.57
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 13,820 Bbls/D of oil and 22,197
Mcf/D of natural gas, or 17,520 BOE/D, for the 2001 fiscal year. The direct
lifting costs for our properties averaged $3.93 per BOE for the year.
Production, severance, and ad valorem taxes were $2.16 per BOE.

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On January 4, 2002, the Company closed the purchase of the sixth producing
property package since inception. These Central Permian properties were
purchased from Conoco for approximately $50 million and were not a part of the
Company's 2001 reserve or production base. The properties include two major
operated fields: East Cowden Grayburg and Fuhrman-Nix; and two non-operated
fields: North Cowden and Yates. We believe that we will be able to exploit
significant opportunities in these fields to increase production through
development drilling and waterflood enhancements. See "-- Properties -- Permian
and Anadarko Properties -- Central Permian".

STRATEGY

Our strategy is to grow our reserves and production through selective
acquisitions and low-risk development drilling. We intend to maximize internally
generated cash flow and shareholder value by continuing our low-risk development
program on our existing properties and by acquiring properties with similar
upside potential to our current producing properties portfolio. We believe that
we are more likely to acquire properties during periods of low acquisition
values and will vigorously pursue development activities during periods of high
acquisition values. However, we believe that additional growth will come both
from acquisitions and development projects. Based on our ability to grow our
reserves with internally generated cash flow, we expect our balance sheet to
remain strong.

Secondary and tertiary recovery is the third leg to 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 revolve around the successful
implementation and further enhancements of waterfloods on the Company's quality
asset base. The tertiary recovery project for the Company revolves around an
initial High-Pressure Air Injection ("HPAI") project on the Company's CCA asset
in Montana.

To execute our strategy, we intend to:

- pursue an active low-risk development and exploitation program on
existing properties;

- control costs through efficient operations of existing properties; and

- continue our successful acquisition program.

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, 2001 was
18.0 years based on the prior 12 months' production.

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 approximately four 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 Pilot Program".

Efficient Operations. We operate properties representing 86% of the PV-10
value of our proved reserves, which allows us to control capital allocation and
expenses. For the year ended December 31, 2001, our lease operating expenses
consisted of direct lifting costs of $3.93 per BOE produced and production, ad
valorem, and severance tax payments of $2.16 per BOE produced. Our general and
administrative costs, excluding non-cash stock based compensation expense,
averaged $0.79 per BOE produced in 2001.

Continued Successful Acquisition Program. 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. We have an extensive 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. Through December
31, 2001, the Company has completed five acquisitions, at a total initial
acquisition cost of $301 million, representing 115.0 MMBOE of proved reserves.
In addition, in the fourth quarter of 2001, we entered into a purchase agreement
with Conoco to

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acquire several operated and non-operated properties in the Permian Basin of
Texas for $55 million. The acquisition closed in January 2002 with a final
purchase price of $50 million after closing adjustments and exercise of
preferential rights.

Challenges to Implementing Our Strategy. We face a number of challenges in
implementing our strategy and achieving our goals. Our primary challenge is the
ability to acquire quality producing properties for attractive rates of return,
especially in a changing commodity price environment. In addition, we face
strong competition for capital, expenses, and acquisitions from independents and
major oil companies.

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,
2001:

PROPERTIES -- PRINCIPAL AREAS OF OPERATIONS

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(1) Without adding the unrealized gain from hedging transactions, which
aggregated $3.8 million based on prevailing prices at December 31, 2001.

During 2002, we plan to invest approximately $81 million to exploit and
develop existing core properties. This is in addition to the $50 million paid
for the Permian Basin acquisition, and will support a four-rig, 110 well
drilling program in the Cedar Creek Anticline, the High-Pressure Air Injection
program, waterflood improvements, workovers, and recompletions. If attractive
opportunities arise during that period, we will acquire additional producing oil
and natural gas properties.

OPERATIONS

We act as operator of properties representing approximately 86% of our
PV-10 reserve value at December 31, 2001. 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". During the years ended
December 31, 2001, 2000, and 1999 our approximate costs for development
activities on non-operated properties were $9.3 million, $0.3 million, and $0.9
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, except per unit amounts):

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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
$364.4 million at December 31, 2001, $689.6 million at December 31, 2000,
and $318.3 million at December 31, 1999.

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 many
factors, which include oil and natural gas pricing assumptions, the quality of
available data, 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 is mandated by the SEC. The present value 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 net revenues does not take into
account the effect of various cash outlays, including, among other things,
general and administrative costs and interest expense.

5

During the calendar year 2001, the Company filed estimates of oil and
natural gas reserves at December 31, 2000 with the U.S. Department of Energy on
Form EIA-23. This estimate was based on an internal reserve study and reflected
more reserves than those set forth in the table above. This reduction resulted
from a reassessment of some of our proved undeveloped reserves as a result of
additional drilling.

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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(1) In the year ended December 31, 1999, the Company commenced production June
1, 1999.

(2) Includes the effects of net profits interest expense and the Company's
hedging activities.

PRODUCING WELLS

The following table sets forth information at December 31, 2001 relating to
the producing wells in which we owned a working interest as of that date. We
also held royalty interests in 650 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 699 operated wells and 365 non-operated wells.

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ACREAGE

The following table sets forth information at December 31, 2001 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.

DRILLING RESULTS

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

PRESENT ACTIVITIES

As of December 31, 2001, the Company had a total of six gross (4.8 net)
wells that were in varying stages of drilling operations. Also, there were eight
gross (6.2 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 PILOT PROGRAM

In addition to the conventional development operations planned for 2002,
design and fabrication of compressors and facilities is underway for
implementation of Phase I of the High-Pressure Air Injection program ("HPAI
program") in the Pennel Unit on the Cedar Creek Anticline properties. As the
name suggests, High-Pressure Air Injection involves utilizing specialized
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. The capital outlay for
the initial two projects is approximately $5.0 million and we hope to produce up
to an additional 1.3 million barrels of oil related to the expenditure. The new
compressors for the HPAI program will be in place and operational by summer 2002
and an initial indication of success should occur by the end of the first
quarter of 2003. Peak response will not occur until much later in the future.

We believe that High-Pressure Air Injection, if proven effective and
feasible, would be the most useful tertiary recovery technique applicable to the
Cedar Creek Anticline, with economics comparable to, if not

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better than, current reserve acquisition values. For example, if successful,
production could increase from 25% to 100% over the existing 360 barrels of oil
per day currently produced on the properties involved in the initial pilot
program. This would yield a rate of return in excess of 20% based on a $20.00
per barrel oil price.

If the projects are successful, the High-Pressure Air Injection will be
significantly expanded and added to other applicable areas of the field in the
second half of 2004. If this new High-Pressure technology proves successful and
can be applied throughout the Cedar Creek Anticline, we believe operations of
this type ultimately have the potential to yield significant new reserves.

Readers and investors should note that this is a pilot program to test the
efficacy of a relatively novel tertiary recovery technology and the results are
highly prospective. While management is enthusiastic about the program, the
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 2001, our largest purchasers included
ConAgra, Equiva Trading Company (a joint venture between Shell and Texaco) and
EOTT Energy Co., which respectively accounted for 25%, 17%, and 11% of total oil
and natural gas sales. Management is of the opinion that the loss of any one
purchaser would not have a material adverse effect on its ability to market our
oil and natural gas production. As of March 1, 2002, we no longer market our oil
with EOTT Energy Co. and have substituted Eighty Eight Oil, LLC. as the
purchaser.

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 the Company. 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 gas transportation business cannot be predicted. We,
however, do not believe that we will be affected differently than competing
producers and marketers.

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

Environmental Regulations. Various federal, state and local laws
regulating the discharge of materials into the environment, or otherwise
relating to the protection of the environment, directly impact oil and natural
gas exploration, development and production operations, and consequently may
impact our operations and costs. Management believes that 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.

Rules and Regulations Resulting from Enron's Bankruptcy. Rules and
Regulations governing publicly traded companies often change as a result of the
current and economic and political environment. With the financial collapse of
Enron Corp., regulatory changes are expected that may affect the industry and
Encore. We cannot predict the changes to be implemented, or whether or not such
changes will adversely affect the Company.

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. For certain risks, we may not obtain insurance 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.

Because of significant losses suffered by the insurance industry over the
last few years, we are anticipating significantly higher insurance premiums
related to all areas of our business in 2002 and years beyond.

EMPLOYEES OF THE COMPANY

The Company had 92 employees as of December 31, 2001, of which, 40 are
field personnel. None of the employees are represented by any union. The Company
considers its relations with its employees to be good.

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PROPERTIES

NATURE OF OUR OWNERSHIP INTERESTS

We own interests in oil and natural gas properties located in Montana,
North Dakota, Texas, New Mexico, and Oklahoma. Substantially all of our PV-10
reserve value at December 31, 2001 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.

A major portion of our acreage position in the Cedar Creek Anticline is
subject to net profits interests 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.
These net profits interests are reflected as estimated future production costs
in the reserve report prepared my Miller and Lents, Ltd., and revenues reported
in our financial statements are net of net profits interest payments.

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 36% on the CCA from 9,099 BOE
per day (average June, 1999) to 12,349 BOE per day (average 4Q 2001). 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 2001, we drilled 102 gross wells
on the CCA, representing $73.0 million of cost. Of these, 60 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 11,558 BOE per day for 2001.

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 90% of our total proved reserves as of December 31,
2001. 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 Eland Unit is the largest
accumulation in the trend. The average production from the Lodgepole properties
was 2,337 BOE per day for 2001.

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

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inherently difficult to determine. Since acquiring the properties in March 2000,
the properties have outperformed engineering forecasts. We do not believe that
this trend will continue in the future. In 2002, we are predicting the
properties to go on a steep decline in production. If the properties performance
varies significantly from the Miller and Lents, Ltd. estimates of reserves, then
our future cash flows could be affected in 2002 and a few years beyond.

Bell Creek -- Powder River and Carter Counties, Montana

The Bell Creek properties, located in the Powder River Basin of
southeastern 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 383 BOE per day for 2001.

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 2001 we invested approximately $8.0
million drilling on the Crockett properties, and have increased production 30%
from 8,700 Mcfe per day (average daily 2000) to 11,322 Mcfe per day (average
daily 2001). The Crockett properties are the Company's most significant
producers of natural gas.

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 Chevron), whose production is 97% 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 4,476 Mcfe per day
for 2001.

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 3,654 Mcfe per day for 2001.

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

The Central Permian properties were purchased from Conoco on January 4,
2002 and were not a part of the Company's 2001 reserve or production base. These
properties are all 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 97% oil and the
average daily production from the properties on January 1, 2002 was
approximately 1,690 BOE per day. All of these fields contain multiple producing
intervals. We believe that we will be able to exploit significant opportunities
in the fields that we have identified which include development drilling and
waterflood enhancements. Together with

11

our existing Permian Basin properties, the Central Permian properties further
focus our operational presence in this area of established production and growth
potential.

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 typically 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 are
conventional in the industry for similar properties and do not in the aggregate
materially interfere with the use of the properties.

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, 2001.

12

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 quarter of 2001, since our initial public offering ("IPO") on March 8,
2001:

On March 1, 2002, the Company had approximately 1,250 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.

13

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) 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.

(2) 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;

- 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;

15

- 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. 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.

16

Management's assumptions used in calculating oil and natural gas 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.

BAD DEBT EXPENSE

The Company routinely assesses the recoverability of all material trade and
other receivables to determine their collectibility. The Company historically
has not required collateral or other performance guarantees from creditworthy
counterparties. Many of our receivables are from joint interest owners on
property of which we are the operator. Thus, we may have the ability to withhold
future revenue disbursements to cover any non-payment of joint interest
billings. Our oil and natural gas receivables quickly turnover, usually one
month for oil and two months for gas; thus, signaling any problem accounts in a
timely manner. Counterparties to our derivative commodity and interest rate
contracts are routinely reviewed for creditworthiness to determine the
realizability of any related derivative assets we might carry on our books. This
review of receivables and counterparties is heavily dependent on the judgment of
management. If it is determined that the carrying value of a receivable or
financial instrument might not be recoverable, we record an allowance to the
extent we believe the receivable or asset is not recoverable. The determination
as to what extent a receivable or asset might be impaired is also heavily
dependent on the judgment of management. As more information becomes known
related to a particular counterparty or customer, management will continually
reassess previous judgments and any resulting change in the related allowance
could have a material positive or negative effect on our financial position and
results of operations in the period of the change.

HEDGING AND RELATED ACTIVITIES

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

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

17

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 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, 2001 are two written oil put contracts
representing 1,500 Bbls/D for 2002 sold to finance the purchase of oil collar
contracts. Additionally, another oil put contract representing 500 Bbls/D was
written in February 2002 to finance the purchase of another oil collar contract.
According to the provisions of SFAS 133, these are marked-to-market through
earnings each quarter. If oil prices 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 destination 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 no longer deemed creditworthy and non-performance under the terms
of the contract was likely, (See "Bad Debt Expense" for discussion of management
judgments as it relates to asset realizability). If any of our contracts no
longer qualify for hedge accounting, this could potentially induce high earnings
volatility, as any future changes in the market value of the contract would then
be marked-to-market through earnings.

NET PROFITS INTERESTS

A major portion of our acreage in CCA is subject to net profits interests
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 revenue. The net profits calculations are contractually
defined and complex, but generally provide that net profits are to be determined
after considering operating expense, overhead expense, interest expense, and
developmental drilling costs. These net profits interests are reflected in our
reserve reports as estimated future production costs and in our financial
statements as a reduction in revenues. The impact of future net profits
interests on our financial statements may vary significantly from period to
period due to changes in commodity prices and/or developmental drilling
activity.

18

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 somewhat by a slight
decrease in net price per barrel. Oil volumes increased 682 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. However, total wellhead oil revenues decreased $6.0 million
due to a decrease of $5.01 per Bbl in the price received. This 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. The decrease in wellhead oil revenues was offset by a decrease in payments
made for net profits and hedging, which decreased $8.4 million and $10.9
million, respectively. The decrease in net profits was primarily due to
increased drilling in the Company's CCA property. Capital expenditures for
drilling and development are a large component of the net profits interest on
the CCA, the costs of which are deducted in calculating net profits payments.
Capital expenditures for the CCA increased in 2001 to $73.0 million, versus
$25.5 million for 2000. 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
3,692 MMcf increase in production, while net price received remained relatively
flat. 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 $0.33 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. Net profits payments related to gas decreased $0.07 per Mcf
due to increased drilling in the Cedar Creek Anticline, while hedging payments
decreased $0.24 per Mcf due to different hedges being in effect during 2001 than
2000.

For 2002 the increased production related to our anticipated $81 million
capital drilling program and the Permian Basin acquisition, which together we
forecast to add an average of 1,780 BOE per day for the year.

19

This should help counteract the sharp decline curve we expect on our Lodgepole
property. Unless changes are made to our planned drilling activities, another
acquisition is made, or Lodgepole performs differently than expected, production
should average approximately 19,300 BOE/D for 2002.

Prices received for oil and natural gas production is largely based on
current market prices, which are beyond our control. During 2001, prices were
trending downward. The average NYMEX prices of $25.92 per Bbl and $4.06 per Mcf
in 2001 were significantly higher than the 12-month forward strip prices at
December 31, 2001 of $20.47 per Bbl and $2.81 per Mcf. We feel that oil prices
will rebound somewhat in 2002 from their December 31, 2001 projected levels.
Thus, we have based our 2002 forecasts on the assumptions of $22.50 per Bbl and
$2.75 per Mcf NYMEX prices. At these assumed prices, we have forecasted hedging
payments of approximately $3.4 million for oil and receipts of $0.5 million for
natural gas. However, these amounts will change directly with any change in the
market price of oil and natural gas and with any change in our outstanding hedge
positions. Additionally, we have anticipated net profits payments of $0.4
million for oil and $0.01 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 $22.50
for oil and $2.75 for natural gas, the Company will not be able to fund the
budgeted $81 million drilling program for 2002 through internally generated cash
flows. In this case, the Company would have to borrow money, seek additional
equity, or curtail the capital program. If drilling is curtailed or ended,
future cash flows will be materially negatively impacted.

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
"-- Revenues and Production". On a per BOE basis, direct lifting costs increased
from $3.66 in 2000 to $3.93 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 incurred $1.0 million related to
workovers in Bell Creek, which was acquired in December 2000.

For 2002 we anticipate an increase in total direct lifting costs, as well
as on a per BOE basis. The overall increase in total is directly related to our
Permian Basin acquisition, which closed on January 4, 2002, as well as an
increase in insurance rates on our wells caused by industry wide insurance
losses sustained in 2001. On a per BOE basis, we anticipate higher direct
lifting costs primarily from higher per BOE costs associated with our Permian
Basin acquisition. We have projected total direct lifting costs of approximately
$30.0 million or $4.25 per BOE for 2002.

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. 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.

For 2002 we believe total production, ad valorem, and severance taxes will
increase overall due to the Permian Basin acquisition. However, the production,
ad valorem, and severance tax rate should remain relatively constant at an
estimated 9.6% of wellhead revenues.

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 1.3 MMBOE increase in production volumes, as well as an increase in the
DD&A rate per BOE. See "-- Revenues and Production". The average DD&A rate
increased from $4.34 per BOE of production during 2000 to $4.96 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

20

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.

We anticipate the total DD&A expense in 2002 to increase due to increased
production resulting from the $50 million Permian Basin acquisition and our
planned 2002 capital expenditures of $81 million. Assuming capital expenditures
that do not differ significantly from our budgeted amount, our DD&A rate for
2002 should approximate $4.75 per BOE. This decrease from 2001 primarily
reflects a decrease in anticipated production from some of our higher per BOE
rate properties. This rate could vary significantly based on actual capital
expenditures, production rates, and any acquisition that closes in 2002.
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 $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 related to being a publicly traded
company. On a per BOE basis, G&A expense fell to $0.79 during 2001 from $0.85
during 2000. This reduction resulted as fixed costs were spread over a greater
amount of production in 2001 as compared to 2000.

We have forecasted approximately $6.0 -- $6.5 million for general and
administrative expenses in 2002. This represents a modest increase from 2001.
The increase will result from hiring additional staff necessary after the
Permian Basin acquisition and hiring additional staff necessary to evaluate
potential acquisitions in a year that we expect to see many quality oil and
natural gas properties on the market.

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 income statement.

For 2002, we anticipate other operating expense to be approximately $0.5 to
$1.0 million.

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.

21

The Company does not expect to incur any additional expense associated with
non-cash stock based compensation related to the Company's employees.

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. See "Item 7A. Quantitative and
Qualitative Disclosures about Market Risk -- Commodity Price Sensitivity". These
amounts are now being recorded as required by Statement of Financial Accounting
Standards 133, "Accounting for Derivative Instruments and Hedging Activities"
("SFAS 133"). See "Description of Critical Accounting Policies". No similar
amounts were recorded in 2000 as we adopted SFAS 133 effective January 1, 2001.

Currently this line item on the income statement is primarily dependent on
the futures price of oil. This is due to the fact that, currently, the main
component is the mark-to-market movement of our two short oil puts. The
unrealized loss related to these two written option contracts at December 31,
2001 that has been recognized in earnings was $0.7 million. Additionally, we
wrote another put contract representing 500 Bbls/D of oil in February 2002 to
finance the purchase of another oil collar contract. Since these contracts move
in conjunction with the futures price of oil, if the price of oil moves down, we
will recognize a loss and if it moves up we will recognize a gain. As the market
price of oil continually changes, we cannot reliably estimate the mark-to-market
value of these puts in the future.

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.

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 certain properties. We then compared the net

22

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.

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 2000 TO 1999

Set forth below is our comparison of operations during the year ended
December 31, 2000 with the year ended December 31, 1999. In reading the
comparison, the 2000 period included twelve months of operations while the 1999
period included only seven months of operating activities. Accordingly,
operations in the two accounting periods are not directly comparable.

Revenues. Oil and natural gas revenues of the Company for 2000 increased
as compared to 1999 by $77.7 million, from $31.3 million to $109.0 million. This
increase resulted from the additional five months of production from the CCA
properties acquired in June 1999, as well as the Crockett County and Lodgepole
acquisitions completed in April 2000. The Indian Basin/Verden acquisition
includes four months of production for 2000. The Bell Creek acquisition
accounted for one month of production for 2000. During the fourth quarter of
2000, an unusually severe winter storm briefly disrupted our operation of the
CCA properties. The disruption in operations resulted in a loss of production of
approximately 30 MBOE or $0.8 million of associated revenue. Also, the Indian
Basin gas plant was off-line for one-time modifications in the fourth quarter of
2000. That disruption in operations resulted in loss of production of 20 MBOE or
$0.6 million of revenue. Hedging transactions had the effect of reducing oil and
natural gas revenues by $23.0 million, or $4.52 per BOE, during 2000 and
decreasing oil and natural gas revenues by $4.4 million, or $2.14 per BOE,
during 1999. Net profits interest payments had the effect of reducing oil and
natural gas revenues by $11.5 million, or $2.26 per BOE, during 2000 and
decreasing oil and natural gas revenues by $4.4 million or $2.12 per BOE, during
1999.

On a pro forma basis, the Company's revenues and production volumes for the
year ended December 31, 2000 would have been $129.5 million and 6.0 MMBOE.

Direct lifting costs. Direct lifting costs of the Company for the year
ended December 31, 2000 increased as compared to 1999 by $10.3 million, from
$8.4 million to $18.7 million. The increase in direct lifting costs resulted
from the CCA acquisition completed in June 1999, as well as the Crockett County,
Lodgepole, Indian Basin/Verden and Bell Creek acquisitions completed in 2000. On
a per BOE basis, direct lifting costs decreased from $4.06 to $3.66, primarily
as a result of lower lifting costs associated with our Lodgepole acquisition in
April 2000. Because of the winter storm in the fourth quarter of 2000 at our CCA
properties, direct lifting costs included $0.6 million, or $0.12 per BOE for the
year, of expenses associated with repairing equipment and bringing production
back on line.

On a pro forma basis, the Company's direct lifting costs for the year ended
December 31, 2000 would have been $22.2 million, or $3.70 per BOE.

Production, ad valorem, and severance taxes. Production, ad valorem, and
severance taxes for the year ended December 31, 2000 increased as compared to
1999 by approximately $9.8 million, from $5.4 million to $15.2 million. The
increase in production, ad valorem, and severance taxes resulted from the CCA
acquisition completed in June 1999, as well as the Crockett County, Lodgepole,
Indian Basin/Verden and Bell Creek acquisitions completed in 2000. As a percent
of oil and natural gas revenues (excluding the effects of hedges), production,
ad valorem, and severance taxes decreased from 13.5% to 10.6%. The decrease in
production, ad valorem, and severance taxes as a percent of revenue was a result
of the higher production, ad valorem, and

23

severance tax rate in Montana associated with our CCA asset versus the tax rates
in Texas and North Dakota associated with our Crockett County and Lodgepole
assets, respectively.

On a pro forma basis, the Company's production, ad valorem, and severance
taxes for 2000 would have been $16.7 million, or $2.77 per BOE.

Depletion, depreciation and amortization ("DD&A") expense. DD&A expense
increased by approximately $16.8 million, during 2000 from $5.3 million to $22.1
million as compared to 1999. The increase in DD&A resulted from the CCA
acquisition completed in June 1999, as well as the Crockett County, Lodgepole,
Indian Basin/Verden and Bell Creek acquisitions completed in 2000. The average
DD&A rate of $4.34 per BOE of production during 2000 represents an increase of
$1.79 per BOE from the $2.55 per BOE recorded in 1999. The increase was
attributable to higher per BOE acquisition costs associated with the Crockett
County, Lodgepole, Indian Basin/Verden and Bell Creek acquisitions completed in
2000.

On a pro forma basis, the Company's DD&A for the year ended December 31,
2000 would have been $27.3 million, or $4.55 per BOE.

General and administrative ("G&A") expense. G&A expense increased $0.3
million during 2000, from $4.0 million to $4.3 million (excluding non-cash stock
based compensation of $26.0 million) as compared to 1999. The increase in G&A
resulted from the additional staff and lease space necessary for the CCA
acquisition completed in June 1999, as well as the Crockett County, Lodgepole,
Indian Basin/Verden and Bell Creek acquisitions completed in 2000. On a per BOE
basis, G&A expense fell to $0.85 during 2000 from $1.95 during 1999.

On a pro forma basis, the Company's G&A expense for the year ended December
31, 2000 would have been $4.3 million, or $0.72 per BOE.

Non-cash stock based compensation expense. The Company has recorded $26.0
million of non-cash stock based compensation associated with the purchase by our
management stockholders of Class A common stock under our management stock plan
adopted in August 1998. This amount represents the vested portion of the shares
purchased and is recorded as compensation, based on 90% of the anticipated price
per share associated with our initial public offering, calculated in accordance
with variable plan accounting under APB 25.

Interest expense. Interest expense for the year ended December 31, 2000
was $10.5 million compared to $4.0 million for the year ended December 31, 1999.
The increase in interest expense resulted from the additional borrowing
necessary under the Company's credit agreement for the CCA acquisition completed
in June 1999, as well as the Crockett County acquisition completed in April
2000, the Indian Basin/Verden acquisition completed in August 2000 and the Bell
Creek acquisition completed in November 2000. Additional interest expense during
the first nine months of 2000 resulted from a seller financed note from
Burlington Resources Oil & Gas. The note requires monthly principal payments and
4% interest on the outstanding principal paid at maturity of the note in January
2002.

On a pro forma basis, the Company's interest expense for the year ended
December 31, 2000 would have been $12.4 million, or $2.07 per BOE.

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, 2001, net cash provided by operations
was $80.2 million, an increase of $35.7 million compared to 2000. We anticipate
that our capital expenditures will total approximately $81.0 million for 2002
not including the $50 million Permian Basin acquisition that closed in January
2002. 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.

24

At December 31, 2001, the Company had total assets of $402.0 million. Total
capitalization was $348.4 million, of which 77.3% was represented by
stockholders' equity and 22.7% by senior debt.

The Company's operating subsidiary currently maintains a credit agreement
with a group of banks that matures in May 2004. The Company has guaranteed the
subsidiary's obligations under the credit agreement and has 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, the weighted average interest rate
under the facility was 5.7%. The remaining borrowing base available under the
credit agreement at December 31, 2001, was $102.0 million. We pay certain fees
based on the unused portion of the borrowing base. We financed the $50 million
Permian Basin acquisition, which closed on January 4, 2002, with available
borrowings under the credit agreement. Amounts outstanding under the credit
agreement at February 28, 2002 were $130.0 million, which gave us remaining
borrowing capacity of $50 million as of that date.

The borrowing base is to be redetermined each June 1. The Company and the
bank syndicate each have the ability to request one additional borrowing base
redetermination per year. If amounts outstanding ever exceed the borrowing base,
the Company must reduce the amounts outstanding to the redetermined borrowing
base within six months.

The credit agreement contains a number of negative and financial covenants.
We were in compliance with all of them as of December 31, 2001. The most
important of these covenants are:

- a prohibition against incurring debt in excess of $6.0 million, except
for borrowings under the credit agreement and the seller financing note
described below;

- a prohibition against paying dividends or purchasing or redeeming capital
stock;

- a restriction on creating liens on the Company's assets;

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

- restrictions on investments, transactions with affiliates, changing the
Company's 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; and

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

The Company issued a $35.2 million note payable to Burlington Resources in
connection with the Lodgepole acquisition in North Dakota. The note required
monthly principal payments over the 22 month period ending January 31, 2002. The
note bore monthly compounded interest at the rate of 4% per annum on the
outstanding principal plus accrued interest and was payable at maturity in
January 2002. Principal payments through December 31, 2001 and 2000 totaled
$34.1 million and $17.7 million, respectively. The remaining principal balance
of $1.1 million was paid in January 2002, along with accrued interest, which at
December 31, 2001 totaled $1.3 million.

The Company believes that its capital resources are adequate to meet the
requirements of its business. Based on our anticipated capital investment
programs, we expect to invest our internally generated cash flow to replace
production and enhance our waterflood programs. Additional capital may be
required to pursue acquisitions and longer-term capital projects, such as our
proposed high pressure air injection tertiary recovery project in the CCA, to
increase our reserve base. 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.

25

The following table illustrates the Company's contractual obligations
outstanding at December 31, 2001:

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, 2001, 2000, and 1999. Average
equivalent prices for 2001, 2000, and 1999 were decreased by $2.00, $4.52, and
$2.14 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. Average prices shown in the following
table are netted for the effect of net profits interests.

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 Executive Vice
President of Business Development with input from the Chief Executive Officer
and the Chief Financial Officer. Trades are executed by the Executive Vice
President of Business Development. 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. Currently, for the first six months of 2002, we have approximately 32%
of our oil production placed in floors, 16% capped, and 16% in swap agreements
and for the last six months of 2002, we have approximately 25% of our estimated
oil production in floors, 16% capped, and 13% in swap agreements. In addition,
for 2002, we have approximately 24% of our estimated natural gas placed in
floors, 12% capped, and 12% in swap agreements and for 2003 we have
approximately 14% of our estimated natural gas production

26

in swap agreements. 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, a commercial bank, J. Aron, a wholly-owned subsidiary of
Goldman, Sachs & Co. and a commodities trading firm, and CIBC World Markets
("CIBC"), the marketing arm of the Canadian Imperial Bank of Commerce. As of
December 31, 2001, approximately 67%, 20%, and 13% of hedged oil production is
committed to J. Aron, Bank of America, and CIBC, respectively. All of our hedged
natural gas production is contracted with J. Aron. Performance on all of J.
Aron's contracts with the Company is guaranteed by their parent Goldman, Sachs &
Co. As of December 12, 2001, we have terminated all of our oil and natural gas
contracts with Enron North America Corp. See "Item 6. Comparison of 2001 to
2000 -- Bad Debt Expense". We feel the credit-worthiness of our current
counterparties is sound and do not anticipate any non-performance of contractual
obligations. However, as long as a counterparty maintains an investment grade
credit rating, pursuant to our hedging contracts, no collateral is required.

Commodity price sensitivity. The tables in this section provide
information about derivative financial instruments to which we were a party as
of December 31, 2001 that are sensitive to changes in oil and natural gas
commodity prices. No instrument provides the option to roll the contract forward
rather than make or take delivery.

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 finance the purchase of collar contracts through
the short sale of 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 income statement. At
December 31, 2001, we had two such contracts in place representing 1,500 Bbls/D
with a strike price of $20.00 per barrel. Additionally, we sold another put
contract short representing 500 Bbls/D of oil in February 2002 to finance the
purchase of an oil collar contract. The unrealized mark-to-market gain on our
outstanding commodity derivatives at December 31, 2001 was approximately $3.8
million. The fair market value of our oil hedging contracts was $2.8 million and
the fair market value of our gas hedging contracts was $1.7 million. At December
31, 2001, the fair value liability of the Company's two written put contracts
was $1.1 million.

OIL HEDGES AT DECEMBER 31, 2001

NATURAL GAS HEDGES AT DECEMBER 31, 2001

Since December 31, 2001, the Company has entered into several additional
oil collar contracts representing 3,000 Bbls/D of 2003 production. The weighted
average floor price of these contracts is $19.17 per Bbl and the weighted
average cap price is $25.33 per Bbl.

27

Interest rate sensitivity. At December 31, 2001, the Company had total
debt of $79.1 million. Of this amount, $1.1 million bears interest at a fixed
rate of 4%. The remaining outstanding debt balance of $78.0 million is under our
credit agreement, which is subject to floating market rates of interest.
Borrowings under the credit agreement bear interest at a fluctuating rate that
is linked to LIBOR or the prime rate, at our option. Any increase in these rates
can have an adverse impact on the Company's results of operations and cash flow.
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,
2001, we had interest rate swaps as follows:

28

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.

29

MMcf. One million cubic feet of natural gas.

Net Acres or Net Wells. Gross acres or wells multiplied, as the case may
be, by the percentage working interest owned by us.

Net Production. Production that is owned by 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.

30

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

31

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

32

ENCORE ACQUISITION COMPANY

CONSOLIDATED BALANCE SHEETS

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

33

ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS

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

34

ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

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

35

ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

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

36

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, and the Powder River Basin of Montana.

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, and are
stated at the lower of cost (determined on an average basis) or market.

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.

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.

37

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

STOCK-BASED COMPENSATION

Employee stock options 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. Additionally, in accordance
with Statement of Financial Accounting Standards No. 123, "Accounting for
Stock-Based Compensation", we have disclosed in Note 10 the pro forma effect on
net income and net income per share of recording stock-based compensation using
the estimated fair value of option awards on the grant date.

SEGMENT REPORTING

In accordance with Statement of Financial Accounting Standards No. 131,
"Disclosures about Segments of an Enterprise and Related Information", we have
identified only one operating segment, the development and exploitation of oil
and natural gas reserves. Additionally, all of our assets are located in the
United States and all of our oil and natural gas revenues are derived from
customers located in the United States.

For 2001, ConAgra, Equiva Trading Company (a joint venture between Shell
and Texaco) and EOTT Energy Co., accounted for 25%, 17%, and 11% of total oil
and natural gas sales, 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. As of March 1, 2002, we no longer
market our oil with EOTT Energy Co. and have substituted Eighty Eight Oil, LLC.
as the purchaser.

INCOME TAXES

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

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 at December 31, 2001 were
483,000 MMbtu, and 556,000 MMbtu at December 31, 2000. Revenues are stated net
of any net profits interests held by others. The reduction in revenue from net
profits interest totaled $2.8 million, $11.5 million, and $4.4 million in 2001,
2000, and 1999, 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 on our income statement.

38

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

HEDGING AND RELATED ACTIVITIES

We use various financial instruments for non-trading purposes in the normal
course of our business to manage and reduce price volatility and other market
risks associated with our crude oil and natural gas production. This activity is
referred to as hedging. 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 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

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ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

During 1998, The Company adopted Statement of Financial Accounting
Standards No. 130 ("SFAS 130"), "Reporting Comprehensive Income," which
establishes standards for reporting and display of comprehensive income and its
components in a full set of general purpose financial statements. 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. For the years ended December 31, 2000 and 1999, comprehensive
income and net income were equal and thus, SFAS 130 had no effect on our
financial statements.

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. At December 31, 2001,
the Company had $4.2 million in deferred hedge gains, net of tax, in accumulated
other comprehensive income, shown as a component of equity on the balance sheet.

3. OIL AND NATURAL GAS PROPERTIES

The cost of oil and natural gas properties at December 31, 2001 includes
$0.8 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:

1999 ACQUISITIONS

During June 1999, we purchased from Shell Western E&P Inc. their interests
in approximately 475 oil and natural gas properties (450 operated, 25
non-operated) in the Cedar Creek Anticline located in Southeastern Montana and
Southwestern North Dakota for $172.0 million ($170.5 million of proved
properties and $1.5 million of inventory and other equipment).

The acquisition has been accounted for as a purchase. The operating results
of the Shell Western properties have been included in our consolidated financial
statements since the date of acquisition. During July and October 1999, we
purchased additional working interests within the Cedar Creek Anticline
properties

40

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

from various working interest owners for $22.2 million. These acquisitions were
also accounted for as a purchase and included in our consolidated financial
statements since the date of acquisition.

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.

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.

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.

Unaudited pro forma information, as if the acquisitions were consummated on
January 1, 1999, is as follows (in thousands):

SUMMARY PRO FORMA DATA

2001 ACQUISITIONS

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

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, 2001
(in thousands):

2002........................................................ $885
2003........................................................ 959
2004........................................................ 951
2005........................................................ 987
2006........................................................ 520
Thereafter.................................................. 384

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ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Our operating lease rental expense was approximately $0.7 million, $0.3
million, and $0.3 million in 2001, 2000, and 1999, respectively.

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):

The Company's operating subsidiary currently maintains a credit agreement
with a group of banks that matures in May 2004. All amounts outstanding under
the credit agreement are payable upon maturity in May 2004. The Company has
guaranteed the subsidiary's obligations under the credit agreement and has
pledged the stock and other equity interests of its subsidiaries to secure the
guaranty. Borrowings under the credit agreement totaled $78.0 million and $144.5
million as of December 31, 2001 and 2000. The borrowing base, as established in
the credit agreement, was $180.0 million as of December 31, 2001 and 2000.
During 2001 and 2000, the weighted average interest rate under the facility was
5.7% and 7.8%, respectively. The remaining borrowing base available under the
credit agreement at December 31, 2001, was $102.0 million. The Company pays
certain fees based on the unused portion of the borrowing base.

The borrowing base is to be redetermined each June 1. The Company and the
bank syndicate each have the ability to request one additional borrowing base
redetermination per year. If amounts outstanding ever exceed the borrowing base,
the Company must reduce the amounts outstanding to the redetermined borrowing
base within six months.

42

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The credit agreement contains a number of negative and financial covenants.
The Company was in compliance with all of them as of December 31, 2001. The most
important of these covenants are:

- a prohibition against incurring debt in excess of $6.0 million, except
for borrowings under the credit agreement and the seller financing note
described below;

- a prohibition against paying dividends or purchasing or redeeming capital
stock;

- a restriction on creating liens on the Company's assets;

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

- restrictions on investments, transactions with affiliates, changing the
Company's 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; and

- a requirement that the Company maintain a ratio of consolidated current
assets to consolidated current liabilities as defined in the agreement,
of not less than 1.0 to 1.0.

The Company issued a $35.2 million note payable to the seller in connection
with the Lodgepole acquisition in North Dakota. The note requires monthly
principal payments over the 22 month period ending January 31, 2002. The note
bears monthly compounded interest at the rate of 4% per annum on the outstanding
principal plus accrued interest and is payable at maturity in January 2002.
Principal payments through December 31, 2001 totaled $34.1 million. The
remaining amount payable at December 31, 2001 totals $1.1 million, which along
with accrued interest of $1.3 million, was paid in January 2002.

Consolidated cash payments for interest were $6.4 million, $10.2 million,
and $3.4 million, respectively, for 2001, 2000, and 1999.

7. TAXES

INCOME TAXES

The components of the income tax expense are as follows (in thousands):

43

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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):

Cash income tax payments in the amount of $1.5 million and $4.0 million
were made in 2001 and 2000, respectively. No cash income tax payments were made
in 1999. Our net operating loss carryforward is scheduled to expire in 2021.

44

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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 and 1999, 294,901 and 294,852 shares of Class B and
73,725 and 72,522 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 and 1999, capital calls totaling $21.5 million and $95.7
million, respectively 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 1,000 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 follows variable plan accounting for the Class A stock sold to
management. Accordingly, compensation expense is 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

45

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 vests 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 its 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, $26.0 million in 2000, and none in 1999. 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.

9. EARNINGS (LOSS) PER SHARE ("EPS")

Under Statement of Financial Accounting Standards 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):

46

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 $0.4
million in 2001, $0.3 million in 2000, and $0.1 million in 1999. The Company's
401(k) plan does not currently allow employees to invest in securities of the
Company.

INCENTIVE STOCK PLANS

During 2000, the Company's Board of Directors approved the 2000 Incentive
Stock Plan. The 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. Pursuant
to the plan, during 2001, 936,000 incentive and non-qualified stock options were
granted to employees and 4,000 incentive stock options were granted to
non-employee directors. All options were granted with a strike price equal to
the market price on the date of grant. The options 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 2001:

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

(a) Due to the one-year minimum vesting requirement, none of the options
outstanding at December 31, 2001 were exercisable. The options outstanding
December 31, 2001 had strike prices ranging from $12.49 to $14.00 and had a
weighted average remaining life of 9.4 years.

SFAS 123 DISCLOSURES

The Company follows the provisions of APB 25 in accounting for its stock
based compensation. Accordingly, no compensation expense has been recognized for
its stock option awards. If compensation expense for the stock option 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):

47

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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. The following
amounts represent weighted average values used in the model to calculate the
fair value of the options granted during 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. The fair value of senior debt is
presented at face value given its floating rate structure. Since the note
payable is payable on demand if called by the issuer, fair value approximates
book value.

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 sales volume. Put
contracts provide a fixed floor price on a notional amount of sales 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 sales
volume while allowing some additional price participation if the relevant index
price closes above the floor price. A swaption is an option to enter into a swap
in the future. However, no swaptions were outstanding at December 31, 2001.
Additionally, we occasionally finance the purchase of collar contracts through
the short sale of 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 income statement. At
December 31, 2001, we had two such contracts in place representing 1,500 Bbls/D
in 2002 with a strike price of $20.00 per barrel.

48

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following tables summarize our open hedging positions as of December
31, 2001:

OIL HEDGES AT DECEMBER 31, 2001

NATURAL GAS HEDGES AT DECEMBER 31, 2001

For the first six months of 2002, we have approximately 32% of our oil
production placed in floors, 16% capped, and 16% in swap agreements and for the
last six months of 2002, we have approximately 25% in floors, 16% capped, and
13% in swap agreements. In addition, for 2002, we have approximately 24% of our
estimated natural gas placed in floors, 12% capped, and 12% in swap agreements
and for 2003 we have approximately 14% in swap agreements.

As a result of all of our hedging transactions for oil and natural gas we
recognized a pre-tax loss in earnings of approximately $12.8 million, $23.0
million, and $4.4 million in 2001, 2000, and 1999, respectively. Based on the
fair value of our hedges at December 31, 2001, our unrealized pre-tax gain
recorded in other comprehensive income related to outstanding hedges is $2.4
million for oil and $1.4 million for natural gas. These amounts will be
reclassified to earnings as the related production affects earnings, which for
oil is in 2002 and for gas is $1.0 million in 2002 and $0.4 million in 2003. 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. We do not take into account the time value of money
because of the short-term nature of our hedging instruments. 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

The Company has entered into interest rate swap agreements to hedge the
impact of interest rate changes on a portion of its floating rate debt. As of
December 31, 2001, 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 $0.7 million, $0.1 million, and
$0.1 million in 2001, 2000, and 1999, respectively. Based on the fair value of
our interest rate swaps at December 31, 2001, our pre-tax unrealized loss
recorded in other comprehensive income related to these swaps was $1.9 million.
This amount will be reclassified to interest expense as the related interest
payments become due. For 2002, $0.6 million will be reclassified with the

49

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

remainder over the remaining terms of the swaps. The actual gains or losses we
realize from our interest rate swaps may vary significantly from these amounts
due to the fluctuation of the LIBOR interest rate. We do not take into account
the time value of money because of the short-term nature of our hedging
instruments.

COUNTERPARTY RISK

The Company's counterparties to hedging contracts include: Bank of America,
a commercial bank; J. Aron, a wholly-owned subsidiary of Goldman, Sachs & Co.
and a commodities trading firm; and CIBC World Markets ("CIBC"), the marketing
arm of the Canadian Imperial Bank of Commerce. As of December 31, 2001,
approximately 67%, 20%, and 13% of oil production hedged is committed to J.
Aron, Bank of America, and CIBC, respectively. All of our hedged gas production
is contracted with J. Aron. Performance on all of J. Aron'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 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.

12. NEW ACCOUNTING STANDARDS

In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 141, Business Combinations. This
statement supercedes APB Opinion No. 16, Business Combinations and FASB No. 38,
Accounting for Preacquisition Contingencies of Purchased Enterprises and applies
to all business combinations initiated after June 30, 2001. This statement
eliminates the pooling method of accounting for a business combination and
requires the use of purchase accounting. We feel this statement will not have a
material impact on our financial statements.

In June 2001, the FASB issued Statement of Financial Accounting Standards
No. 142, Goodwill and Other Intangible Assets. This statement is effective for
years beginning after December 15, 2001. This statement addresses financial
accounting and reporting for acquired goodwill and other intangible assets and
supercedes APB Opinion No. 17, Intangible Assets. This statement also addresses
how goodwill and other intangibles should be accounted for after they have been
initially recognized in the financial statements. We feel this statement will
not have a material impact on our financial statements.

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. We are currently
reviewing the provisions of the statement and assessing their impact on our
financial statements. We do not currently know the effect, if any, the adoption
of SFAS 143 will have on our financial statements.

In November 2001, the FASB issued Statement of Financial Accounting
Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived
Assets, which supercedes FASB Statement No. 121, Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of ("SFAS 121").
This statement is effective for years beginning after December 15, 2001. This
statement retains the fundamental provisions of SFAS 121 related to the
recognition and measurement of the impairment of long-lived assets to be held
and used. However, it provides additional guidance on estimating future cash
flows and amends the rules related to assets to be disposed of and held for
sale. We feel this statement will not have a material impact on our financial
statements.

50

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

13. 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 future
amortization of this amount to revenue (in thousands):

14. 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.

51

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

15. SUBSEQUENT EVENT

In January 2002, the Company completed the acquisition of interest in oil
and natural gas properties in the Permian Basin from Conoco. The final purchase
price after closing adjustments and preferential rights were exercised was $50
million. The acquisition was funded with bank financing under the Company's
existing credit facility. The two principal operated properties are the East
Cowden Grayburg and Fuhrman Nix fields; the non-operated properties are
primarily in North Cowden and Yates. Preferential rights were exercised on
non-operated properties in the Yates field. We estimate that the proved reserves
are approximately 9.2 million barrels.

52

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 2001, 2000, and 1999 were $19.84, $26.80, and $23.50 per barrel for
oil and $2.57, $9.77, and $2.00 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 quantities have not been adjusted for the net profits interest. In
addition, future net cash flows 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:

53

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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:

54

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

55

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SELECTED QUARTERLY FINANCIAL DATA

The following table sets forth selected quarterly financial data for the
years ended December 31, 2001 and 2000:

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

(a) Operating income before general and administrative expenses and non-cash
compensation expense.

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

None

56

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 23, 2002 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 23, 2002 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 23, 2002 and is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held on April 23, 2002 and is incorporated herein by reference.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) The following documents are filed as a part of this Report at page 32:

1. Financial Statements:
Report of Independent Public Accountant..................... 32
Consolidated Balance Sheets as of December 31, 2001 and
2000........................................................ 33
Consolidated Statements of Operations for the Years Ended
December 31, 2001, 2000 and 1999............................ 34
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2001, 2000, and 1999............... 35
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2000 and 1999............................ 36
Notes to Consolidated Financial Statements.................. 37

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, 2001 and through March 30, 2002:

On November 16, 2001, the Company filed a report on Form 8-K to
disclose the acquisition of oil and natural gas properties located
in the Permian Basin of West Texas.

On November 30, 2001, the Company filed a report on Form 8-K to
disclose the resignation of Kenneth Hersh from the Board of
Directors, effective November 31, 2001, and the election of Jon S.
Brumley to the Board, effective November 31, 2001.

57

(c) Exhibits

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

INDEX TO EXHIBITS

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

* 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.

58

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 15th day of
March, 2002.

ENCORE ACQUISITION COMPANY

By /s/ I. JON BRUMLEY
--------------------------------------
I. Jon Brumley,
Chairman of the Board, President,
Chief Executive Officer, and Director

Date: March 15, 2002

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 the dates indicated.

59

INDEX TO EXHIBITS