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:

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GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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