INLAND RESOURCES INC - 10-K Annual Report

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

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, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period ___ to ___
Commission File Number 0-16487

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INLAND RESOURCES INC.
(Exact Name of Registrant as Specified in its Charter)

WASHINGTON 91-1307042
(State or Other Jurisdiction of (IRS Employer
Incorporation or Organization) Identification Number)

410 17th Street
Suite 700
Denver, Colorado
(303) 893-0102 80202

(Address of Principal Executive Offices) (Zip Code)
Issuer's telephone number, including area code: (303) 893-0102

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Securities registered pursuant to Section 12(b) of the Act: NONE

Securities registered pursuant to Section 12(g) of the Act: Common Stock, par
value $.001 per share

Check whether the issuer (1) filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12
months (or for such shorter period that the issuer was required to file such
reports), and (2) has been subject to such filing requirements for the past 90
days. YES [X] NO [ ]

Indicated by check mark whether the Issuer is an Accelerated Filer (as
defined in Code 12b-2 of the Act). YES [ ] NO [X]

Check if there is no disclosure of delinquent filers in response to
Item 405 of Regulation S-K contained herein, and none will 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. [X]

At March 14, 2003, the registrant had outstanding 2,897,732 shares of
par value $.001 common stock.

State the aggregate market value of the voting and non-voting common
equity held by non-affiliates computed by reference to the price at which the
common equity was last sold, or the average bid and asked price of such common
equity, as of the last business day of the registrant's most recently completed
second fiscal quarter $606,300.

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

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PART I

The following text is qualified in its entirety by reference to the
more detailed information and consolidated financial statements (including the
notes thereto) appearing elsewhere in this Annual Report on Form 10-K. Unless
the context otherwise requires, references to "Inland" shall mean Inland
Resources Inc., a Washington corporation, and references to the "Company" or its
operations shall mean Inland and its consolidated subsidiary, Inland Production
Company ("IPC"), a Texas corporation. For definitions of certain terms relating
to the oil and gas industry used in this section, see Items 1. and 2. "Business
and Properties - Certain Definitions."

ITEMS 1. & 2. BUSINESS AND PROPERTIES

OVERVIEW

Inland is an independent energy company engaged in the acquisition,
development, and enhancement of oil and gas properties in the western United
States. All of the Company's oil and gas reserves are located in the Monument
Butte Field (the "Field") within the Uinta Basin of northeastern Utah. Until
January 31, 2000, the Company was also engaged in the refining of crude oil and
wholesale marketing of refined petroleum products, including various grades of
gasoline, kerosene, diesel fuel, waxes and asphalt through a former subsidiary,
Inland Refining, Inc. ("Refining"). Inland conducts its operations through its
subsidiary, IPC. In 2002, IPC drilled 17 gross (13 net) developmental wells. At
December 31, 2002, the Company's estimated net proved reserves totaled 66.9
MBOE, having a pre-tax present value discounted at 10%, using constant prices,
of $393 million. The constant prices used at December 31, 2002 were calculated
on the basis of market prices in effect on that date and were approximately
$28.20 per barrel of oil and $2.96 per Mcf of gas.

The Company intends to pursue a strategy of development drilling,
focusing on enhancing operating efficiency and reducing capital costs through
the concentration of assets in selected geographic areas. Currently, the
Company's operations are focused on the full development of the Field, where the
Company operates 724 gross (572 net) oil wells, including 261 gross (210 net)
injection wells. Inland pioneered the secondary water flood recovery processes
used in the Field and currently operates 24 approved secondary recovery projects
in the area. Budgeted development expenditures for 2003 in the Field are
estimated to be $18-$20 million net to the Company.

Effective January 31, 2000, Inland sold all of its capital stock in
Refining to Silver Eagle Refining, Inc. ("Silver Eagle") for $500,000 and the
assumption of various refinery liabilities and obligations. Refining owned the
Wood Cross Refinery in Woods Cross, Utah and the Roosevelt Refinery in
Roosevelt, Utah (which was non-operating at the time of sale and not operated by
Inland while owned ). Prior to the sale, the existing cash, inventory, accounts
receivable and a note receivable were transferred to Inland Working Capital Corp
("IWCC") , a wholly-owned subsidiary of Inland. IWCC agreed to satisfy various
accounts payable and liabilities not assumed as part of the purchase price. As a
result of the sale of Refining to Silver Eagle, the Company is no longer engaged
in the business of refining crude oil and marketing refined petroleum products.
IWCC subsidiary was formally dissolved in July 2001.

CHANGES OF CONTROL AND RECAPITALIZATIONS.

1999 Exchange Agreement - On September 21, 1999, the Company entered
into an Exchange Agreement (the "Exchange Agreement") with Trust Company of the
West, as Sub-Custodian for Mellon Bank for the benefit of Account No. CPFF
873-3032 ("Fund V"), TCW Portfolio No. 1555 DR V Sub-Custody Partnership, L.P.
("Portfolio") (Portfolio and Fund V collectively being referred to as "TCW"),
Inland Holdings LLC ("Holdings"- whose members are Fund V and Portfolio) and
Joint Energy Development Investments II Limited Partnership ("JEDI"). Pursuant
to the Exchange Agreement, Fund V agreed to exchange $75 million in principal
amount of subordinated indebtedness of IPC plus accrued interest of $5.7 million
and Portfolio agreed to exchange warrants to purchase 15,852 shares of Common
Stock for the following securities of Inland, all issued to Holdings,: (1)
10,757,747 shares of Series D Preferred Stock, (2) 5,882,901 shares of Series Z
Preferred Stock, which automatically converted into 588,291 shares of Common
Stock on December 14, 1999, and (3) 1,164,295 shares of Common Stock; and JEDI
agreed to exchange the 100,000 shares of Inland's Series C Cumulative
Convertible Preferred Stock ("Series C Preferred Stock") owned by JEDI, together
with $2.2 million of accumulated dividends thereon, for (A) 121,973 shares of
Series E Preferred Stock and (B) 292,098 shares of Common Stock (the
"Recapitalization"). The Series C Preferred Stock bore annual dividends at a
rate of $10 per share, had a liquidation preference of $100 per share and was
required to be redeemed at a price of $100 per share not later than January 21,
2008.

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March 2001 Transaction - On March 20, 2001, Hampton Investments LLC
("Hampton"), an affiliate of Smith Management LLC ("Smith"), purchased from JEDI
the 121,973 shares of Series E Preferred Stock and 292,098 shares of Common
Stock acquired by JEDI in the Exchange Agreement. Following closing of the
Exchange Agreement and the purchase by Hampton of JEDI's shares, Hampton owned
292,098 shares of Common Stock, representing approximately 10.1% of the
outstanding shares of Common Stock as of March 20, 2001 and Holdings owned
1,752,586 shares of Common Stock, representing approximately 60.5% of the
outstanding shares of Common Stock as of March 20, 2001. TCW Asset Management
Company has the power to vote and dispose of the securities owned by Holdings.

August 2001 Transaction - On August 2, 2001, the Company closed two
subordinated debt transactions totaling $10 million in aggregate with Pengo
Securities Corp. ("Pengo"), transferee from SOLVation Inc., a company affiliated
with Smith, and entered into other restructuring transactions as described
below. The first of the two debt transactions with Pengo was the issuance of a
$5 million unsecured senior subordinated note to Pengo due July 1, 2007. The
interest rate is 11% per annum compounded quarterly. The interest payment is
payable in arrears in cash subject to the approval from the senior bank group
and accumulates if not paid in cash. The Company is not required to make any
principal payments prior to the July 1, 2007 maturity date. However, the Company
is required to make payments of principal and interest in the same amounts as
any principal payment or interest payments on the TCW Subordinated Note
(described below). Prior to the July 1, 2007 maturity date, subject to the bank
subordination agreement, the Company may prepay the senior subordinated note in
whole or in part with no penalty.

The Company also issued a second $5 million unsecured junior
subordinated note to Pengo. The interest rate is 11% per annum compounded
quarterly. The maturity date is the earlier of (i) 120 days after payment in
full of the TCW Subordinated Note or (ii) March 31, 2010. Interest is payable in
arrears in cash subject to the approval from the senior bank group and
accumulates if not paid in cash. The Company is not required to make any
principal payments prior to the March 31, 2010 maturity date. Prior to the March
31, 2010 maturity date, subject to both bank and subordination agreements, the
Company may prepay the junior subordinated note in whole or in part with no
penalty. A portion of the proceeds from the senior and junior subordinated notes
was used to fund a $2 million payment to Holdings and other Company working
capital needs.

In conjunction with the issuance of the two subordinated notes to
Pengo, the Series D Preferred and Series E Preferred stock held by Holdings were
exchanged for an unsecured subordinated note due September 30, 2009 and $2
million in cash from the Company. Holdings had previously purchased the Series E
Preferred Stock from Hampton. The TCW Subordinated Note amount of $98,968,964
represented the face value plus accrued dividends of the Series D Preferred
Stock as of August 2, 2001. The interest rate on this debt is 11% per annum
compounded quarterly. Interest is payable in arrears in cash subject to the
approval from the senior bank group and accumulates if not paid in cash.
Interest payments will be made quarterly, commencing on the earlier of September
30, 2005 or the end of the first calendar quarter after the senior bank debt has
been reduced to $40 million or less, subject to both bank and senior
subordination agreements. Beginning the earlier of two years prior to the
maturity date or the first December 30 after the repayment in full of the senior
bank debt, subject to both bank and senior subordination agreements, the Company
will make equal annual principal payments of one third of the aggregate
principal amount of the TCW Subordinated Note. Any unpaid principal or interest
amounts are due in full on the September 30, 2009 maturity date. Prior to the
September 30, 2009 maturity date, subject to both bank and senior subordination
agreements, the Company may prepay the TCW Subordinated Note in whole or in part
with no penalty. As a result of the exchange, the Company retired both the
Series D and Series E Preferred stock. Due to the related party nature of this
transaction, the difference between the aggregate subordinated note balance and
$2 million cash paid to Holdings and the aggregate liquidation value of the
Series D and E preferred stock plus accrued dividends of $1,449,000 was recorded
as an increase to additional paid-in capital.

As part of this restructuring, Holdings also sold to Hampton, 1,455,390
shares of Inland common stock held by Holdings. Consequently, Hampton now
controls approximately 80% of the issued and outstanding shares of the Company.
Holdings also terminated any existing option rights to the Company's common
stock, and relinquished the right to elect four persons to the Company's Board
of Directors to Hampton. However, Holdings has the right to nominate one person
to the Company's Board. Remaining board members will be nominated by the
Company's stockholders. As long as Hampton or its affiliates own at least a
majority of the common stock of the Company, Hampton has agreed with Holdings
that Hampton will have the right to appoint at least two members to the board.

January 30, 2003 Transaction - An amendment to the Fortis Credit
Agreement dated February 3, 2003 was executed to provide for (1) extension of
the Company's borrowing base of $83.5 million through July 31, 2003, (2) a
credit commitment of $5 million for letters of credit to support commodity price
hedging and other obligations to be secured by

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letters of credit, (3) modification of the maturity date of the revolving
facility to be paid in installments between 2004 and 2008 if the Company obtains
$15 million of capital in the form of equity, debt or contributed property by
December 31, 2003 and modification of certain financial covenants such that the
Company expects to be in compliance throughout 2003. The Company agreed to hedge
50% of its net oil and gas production through December 31, 2004 by June 30,
2003. Also, by December 31, 2003 and by each December 31 thereafter during the
term of the credit agreement, the Company agreed to hedge 50% of the oil and gas
production for the following twelve months. The bank amendment does not become
effective until the actual closing of the "TCW and Smith Exchange" (discussed
below) except that the Company will be able to use the $5 million letters of
credit for commodity price hedging for a period of 90 days after the date of the
amendment.

On January 30, 2003, TCW agreed to exchange its subordinated note in
the principal amount of $98,968,964, plus all accrued and unpaid interest, for
22,053,000 shares of the Company's common stock and that number of shares of
Series F Preferred Stock equal to 911,588 shares plus 338 shares for each day
after November 30, 2002. Smith has also agreed to exchange its Junior
Subordinated Note in the principal amount of $5,000,000, plus all accrued and
unpaid interest, for that number of shares of Series F Preferred Stock equal to
68,854 shares plus 27 shares for each day after November 30, 2002. The Company
will authorize 1,100,000 shares of Series F Preferred Stock.

In the event of a voluntary or involuntary liquidation, dissolution or
winding up of the Company, the holders of the Series F Preferred Stock shall be
entitled to receive, in preference to the holders of the common stock, a per
share amount equal to $100, as adjusted for any stock dividends, combinations or
splits with respect to such shares, plus all accrued or declared but unpaid
dividends on such shares. Each share of Series F Preferred Stock will be
automatically converted into 100 shares of the Company's common stock when
sufficient shares of Common Stock have been authorized.

TCW and two Smith Parties will form a new Delaware corporation to be
known as Inland Resources Inc. ("Newco"). TCW will contribute to Newco all of
TCW's holdings in the Company's common stock and Series F Preferred Stock in
exchange for 92.5% of the common stock of Newco, and each of the Smith Parties
will contribute to Newco all of its holdings in the Company's common stock and
Series F Preferred Stock in exchange for an aggregate of 7.5% of the common
stock of Newco. Newco will then own 99.7% of the Company's common stock and
common stock equivalents.

Upon the formation of Newco and closing of the TCW and Smith Exchange,
the Board of Directors of Newco will meet to pass a resolution for Inland to
merge with and into Newco, with Newco surviving as a Delaware corporation (the
"Merger"). No action is required by the Company's stockholders or Board of
Directors under the relevant provisions of Washington and Delaware law with
respect to a merger of a subsidiary owned more than 90% by its parent
corporation. Stockholders unaffiliated with Newco are expected to receive cash
of t $1.00 per share as a result of the Merger.

Stockholders of Inland will have the right to dissent from the Merger
and have a court appraise the value of their shares. Stockholders electing to
exercise their right of appraisal will not receive the $1.00 per share paid to
all other public stockholders, but will instead receive the appraised value,
which may be more or less than $1.00 per share.

The Merger will result in Inland terminating its status as a reporting
company under the Securities Exchange Act of 1934 and its stock ceasing to be
traded on the over-the-counter bulletin board. Its successor, Newco, will
instead be a private company owned by three shareholders. On February 3, 2003,
the Company filed a Schedule 13E-3 with the Securities and Exchange Commission
in order to complete the TCW and Smith Exchange.

At the date of this report, however, the Company is unable to complete
the amendment to the Fortis Credit Agreement because it is contingent upon the
closing of the TCW and Smith Exchange. The Company's inability to effect the
amendment to the Fortis Credit Agreement would raise substantial doubt about the
Company's ability to continue as a going concern. The Fortis Credit Agreement
has been amended on five previous occasions; however, there can be no absolute
assurance that the February 3, 2003 amendment will go into effect and that the
Senior Lenders will not assert their rights to foreclose on their collateral.
Foreclosure by the Senior Lenders on their collateral would have a material
adverse effect on the Company's financial position and results of operations.
Should the Senior Lenders attempt to foreclose, the Company would immediately
seek alternative financing, the potential sale of a portion or all of its oil
and gas properties, or bankruptcy protection. Although there can be no assurance
that alternative financing or the potential sale of a portion or all of its oil
and gas properties would be successful.

In addition to the defaults under its debt agreements, the Company has
suffered losses from operations and has

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a net capital deficit, and therefore, there is a substantial doubt about its
ability to continue as a going concern. The accompanying financial statements
have been prepared assuming the Company will continue as a going concern. The
financial statements do not include any adjustments that might result from the
outcome of this uncertainty.

OIL AND GAS EXPLORATION AND PRODUCTION OPERATIONS

General. The Company conducts exploration and production activities
primarily through IPC, which owns all of the oil and gas acreage, wells, gas
gathering systems, water delivery, injection and disposal systems and other oil
and gas related tangible assets of the Company. IPC serves as the operator of
724 wells, or 98% of the wells in which the Company has an interest. Certain
disclosures with respect to production, exploration and transportation
activities for Inland's fiscal years 2002, 2001 and 2000 are set forth in pages
F-24 and F-27 of this Annual Report.

Oil and Gas Reserves. The following table sets forth the Company's
estimated quantities of proved oil and gas reserves and the estimated future net
revenues (by reserve categories) without consideration of indirect costs such as
interest, administrative expenses or income taxes. These estimates were prepared
by the Company, with certain portions having been reviewed by Ryder Scott
Company, L.P., an independent reservoir engineering firm. The review by Ryder
Scott Company, L.P. consisted of properties which comprised approximately 80% of
the total present worth of future net revenue discounted at 10% as of December
31, 2002. See also, the Supplemental Oil and Gas Disclosures appearing on pages
F-24 through F-27 of this Annual Report.

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(1) Pre-tax and undiscounted.

(2) Pre-tax and discounted at 10%.

Future net revenues from reserves at December 31, 2002 were calculated
on the basis of market prices in effect on that date and were approximately
$28.20 per barrel of oil and $2.96 per Mcf of gas. The value of the estimated
proved gas reserves are net of deductions for shrinkage and natural gas required
to power field operations.

Petroleum engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact manner.
Estimates of economically recoverable oil and gas reserves and of future net
cash flows necessarily depend upon a number of variable factors and assumptions,
including the following:

o historical production from the area compared with production from other
producing areas;

o the assumed effects of regulations by governmental agencies;

o assumptions concerning future oil and gas prices; and

o assumptions concerning future operating costs, production taxes,
development costs and work over and remediation costs.

Because all reserve estimates are to some degree subjective, the
quantities of oil and gas that are ultimately

5

recovered, the production and operating costs incurred, the amount and timing of
future development expenditures and future oil and gas sales prices may differ
materially from those assumed in estimating reserves. Furthermore, different
reserve engineers may make different estimates of reserves and cash flows based
on the same available data. Inland's actual production, revenues and
expenditures with respect to reserves will likely vary from estimates, and the
variances may be material.

No estimates of total proved net oil and gas reserves have been filed
by the Company with, or included in any report to, any United States authority
or agency pertaining to the Company's individual reserves since the beginning of
the Company's last fiscal year.

Production, Unit Prices and Costs. The following table sets forth
certain information regarding the production volumes of, average sale prices
received for, and average production costs for the sales of oil and gas by the
Company. See also, the Supplemental Oil and Gas Disclosures appearing on pages
F-24 through F-27 of this Annual Report.

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(1) Net of lease fuel used for operations.

(2) Does not reflect the effects of hedging transactions.

(3) Includes direct lifting costs (labor, repairs and maintenance,
materials and supplies) and the administrative costs of production
offices, insurance and property taxes.

Drilling Activities. The following table sets forth the number of oil
and gas wells drilled during 2002, 2001 and 2000 in which the Company had an
interest.

(1) All of the completed wells have multiple completions, including both
oil completions and gas completions. Consequently, pursuant to the
rules of the Securities and Exchange Commission, each well is
classified as an oil well.

(2) Three of the wells (gross and net) were completed as water injection
wells.

The information contained in the foregoing table should not be
considered indicative of future drilling performance nor should it be assumed
that there is any necessary correlation between the number of productive wells
drilled and the amount of oil and gas that may ultimately be recovered by the
Company. The Company does not anticipate any significant acquisitions of
properties or major equipment at this time.

The Company owns a drilling rig acquired in October 2002 which conducts
operations exclusively for the Company.

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Productive Oil And Gas Wells and Water Injection Wells. The following
table reflects the number of productive oil and gas wells and water injection
wells in which the Company held a working interest as of December 31, 2002:

(1) The Company is an operator of 724 gross wells (572 net) and a
non-operator with respect to 18 gross (3 net) wells.

(2) Net wells represent the sum of the actual percentage working interests
owned by the Company in gross wells at December 31, 2002.

(3) All of the Company's wells are located in the Field.

Acreage Data. The following table reflects the developed and
undeveloped acreage that the Company held as of December 31, 2002:

(1) Undeveloped acreage includes 58,303 gross (43,604 net) acres held by
production at December 31, 2002.

(2) All of the Company's acreage is located in the Field.

As of December 31, 2002, the undeveloped acreage not held by production
involves 117 leases with remaining terms of up to 6 years. Leases covering
approximately 2,471 net acres have expiration dates in 2003. The Company intends
to renew expiring leases in areas considered to have good development potential.
The Company also intends to continue paying delay rentals and minimum royalties
necessary to maintain these leases (an expense estimated to be approximately
$87,000 net to the Company in 2003). To the extent that wells cannot be drilled
in time to hold a lease, which the Company desires to retain, the Company may
negotiate a farm-out arrangement of such lease and may retain an override or
back-in interest.

Secondary Recovery Enhancement Activities. Inland presently engages in
secondary recovery enhancement operations in the Field through water flooding.
Water flooding involves the pumping of large volumes of water into an oil
producing reservoir to increase and maintain reservoir pressures and displace
oil, resulting in greater crude oil production. Inland currently operates 24
approved water flood units or areas. At December 31, 2002, the Company had 264
wells (including 3 non operated wells) injecting an aggregate of approximately
17,000 BWPD. During 2002, the Company installed 13 miles of water pipelines to
handle low pressure water delivery and high pressure water injection. The
Company also converted 33 gross (26 net) oil wells into injection wells. At
December 31, 2002, the Company owned and operated 195 miles of water pipelines
and seven water injection plants with an injection capacity of 20,000 BWPD.
Inland has experienced stabilized or increasing production in many wells
offsetting its water injection operations. Inland intends to continue
aggressively developing secondary recovery water flood operations by extending
infrastructure and initiating injection in up to 35 wells in the Field during
2003.

The Company has agreements with the Johnson Water District, the Upper
Country Water District and the State of Utah to take up to 37,000 BWPD, subject
to availability, from their water pipelines for the Company's water flood
injection operations in the Field. All water rights are subject to various terms
and conditions including state and federal environmental regulations and system
availability. Inland believes that these agreements will provide sufficient
water to handle all water injection needs at peak field development.

Gas Gathering and Transportation Systems. As of the 2002 year end, the
Company produced approximately 13 MMcf of natural gas per day and sold
approximately 9.5 MMcf of natural gas per day. The difference between the volume
of natural gas produced and sold is the amount of natural gas that the Company
uses as lease fuel for operations. The

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Company collects and markets approximately 90% of its operated gas production
using its gas gathering, transportation and compression system. The system
consists of approximately 367 miles of pipelines and 2 compression facilities
using 5 compressors and 2 dehydration units, a sulfatreat unit and gas
conditioning plant with a throughput capacity of 20 MMcf per day. The gas
conditioning plant lowers the Btu content of the gas to meet specifications, and
generates approximately 0.8 gallons of hydrocarbon liquids per Mcf of gas
processed. The gas conditioning plant commenced operations in September of 2002.
The sulfatreat unit commenced operations in March 2003. The sulfatreat unit
treats the gas for trace amounts of hydrogen sulfide.

Delivery Commitments. The Company has long term purchase agreements
with Big West and Wasatch, but there are no material delivery commitments under
such contracts.

Markets for Oil and Gas. The availability of a ready market and the
prices obtained for the Company's oil and gas depend on many factors beyond the
Company's control, including the extent of domestic production and imports of
oil and gas, the proximity and capacity of natural gas pipelines and other
transportation facilities, fluctuating demands for oil and gas, the marketing of
competitive fuels, and the effects of governmental regulation of oil and gas
production and sales. The crude oil produced from the Field is called Black Wax.
The Black Wax produced from the Field is primarily transported by truck and
refined in Salt Lake City at one of four large refineries operated by Big West,
Tesoro (formally BP), ChevronTexaco and ConocoPhillips. Transportation of large
quantities of Black Wax by pipeline is not currently feasible., . Black Wax is a
valuable commodity since it is low in sulfur content and can be distilled and
cracked into high margin petroleum products such as gasoline, diesel and jet
fuel; however, it does not blend well with other crude oil feedstocks in the
refining process. Since Black Wax has limited compatibility in blending, the
demand for Black Wax tends to become inelastic as the supply of Black Wax
reaches the cracking and blending capacity of the Salt Lake City refineries. The
Company estimates the existing refining capacity for Black Wax in Salt Lake City
to be higher than local production.

The Company has various contracts to sell its Black Wax crude oil to
the Salt Lake City refiners. The pricing mechanism under each contract is
directly related to the average monthly settlement prices of certain futures
contracts quoted on the New York Mercantile Exchange index ("NYMEX"). The
negative basis differential between NYMEX and the Company's wellhead price
averaged $3.13 per barrel during year 2002. From January 2002 and through
December 2005, the Company has a contract with Big West to sell up to 7,000
barrels of oil per day at NYMEX less $3.00 per barrel. The NYMEX price ranged
from $17.97 to $32.72 during 2002 and was $29.39 for December 2002. The NYMEX
price ranged from $19.40 to $29.69 during 2001 and was $19.40 for December 2001.
During 2002 and 2001, the Company sold 46% and 0%, respectively, of its oil
production to Big West. During 2002 and 2001, the Company sold 26% and 56%,
respectively, of its oil production to Tesoro (formally BP). During 2002 and
2001, the Company sold 28% and 35%, respectively, of its oil production to
ChevronTexaco.

Periodically, the Company enters into commodity contracts to hedge or
otherwise reduce the impact of oil price fluctuations. The amortized cost and
the monthly settlement gain or losses are reported as adjustments to revenue in
the period in which the related oil is sold. Hedging activities do not affect
the actual sales price for the Company's crude oil. The Company is subject to
the creditworthiness of its counterparties since the contracts are not
collateralized. Prior to January 1, 2002, the Company entered into all of its
hedging contracts with Enron North America Corp. ("ENAC"). On December 2, 2001,
Enron and ENAC filed for Chapter 11 bankruptcy., Under the provisions of SFAS
No. 133, the Company ceased accounting for the ENAC derivative contracts as
hedges at a date corresponding to the deterioration in the credit of ENAC and
Enron in mid-October 2001. At this date, changes in the fair value of the
derivative contracts no longer were considered effective in offsetting changes
in the cash flows of the hedged production. Consequently, the Company recorded a
loss of $2.2 million for the year ended December 31, 2001 and deferred a
corresponding amount in accumulated other comprehensive income, based on the
estimated fair value of the derivative contracts at that date.

Of the $2.2 million deferred in accumulated other comprehensive income,
$1,444,000 and $480,000 was reclassified out of accumulated other comprehensive
income in 2002 and 2001, respectively, resulting in increases in crude oil sales
revenues. The remaining $231,000 deferred in accumulated other comprehensive
income will be reclassified to crude oil sales revenue in 2003.

The Company markets substantially all of its operated gas production.
The Company had contracts to sell 3,400 Mcf per day from January 2001 through
October 2001 at $4.70 per Mcf. Also, the Company had contracts to sell 5,042 Mcf
per day from November 2001 through March 2002 at $2.89 per Mcf and 5,042 Mcf per
day from April 2002 through October of 2002 at $2.28 per Mcf. The Company
currently has contracts to sell 5,130 Mcf per day from November 2002 through
October 2003 at $2.61 per Mcf and 3,420 Mcf per day from November 2002 through
October of 2003 at $2.59

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per Mcf. Natural gas marketed by the Company not subject to gas purchase
agreements is sold on a month-to-month basis in the spot market, the price of
which ranged from $1.09 per Mcf to $3.29 per Mcf during 2002 and from $1.13 per
Mcf to $10.21 per Mcf during 2001, and was $2.91 per Mcf for December 2002. All
spot market sales during 2002 and 2001 were made to Wasatch Energy Corporation
("Wasatch"). Inland believes that the loss of Wasatch as a purchaser of its gas
production would not have a material adverse effect on its results of operations
due to the availability of other natural gas purchasers in the area.

Hydrocarbon liquids produced at the Company's gas conditioning plant
are marketed as "Y" grade liquids by Custom Energy Construction Inc., an
unaffiliated party. The facility commenced operations in September 2002 and
produced 1.1 million gallons or 26,057 barrels of hydrocarbon liquids for the
September through December 2002 period. The average net price received for the
"Y" grade liquids for the four months in 2002 was $19.28 per barrel or $.459 per
gallon.

Regulation of Exploration and Production. The Company's oil and gas
exploration, production and related operations are subject to extensive rules
and regulations promulgated by federal and state agencies. Failure to comply
with such rules and regulations can result in substantial penalties. The
regulatory burden on the oil and gas industry increases the Company's cost of
doing business and affects its profitability. Because such rules and regulations
are frequently amended or interpreted differently by regulatory agencies, Inland
is unable to accurately predict the future cost or impact of complying with such
laws.

The Company's oil and gas exploration and production operations are
affected by state and federal regulation of oil and gas production, federal
regulation of gas sold in interstate and intrastate commerce, state and federal
regulations governing environmental quality and pollution control, state limits
on allowable rates of production by a well or proration unit and the amount of
oil and gas available for sale, state and federal regulations governing the
availability of adequate pipeline and other transportation and processing
facilities, and state and federal regulation governing the marketing of
competitive fuels. For example, a productive gas well may be "shut-in" because
of an over-supply of gas or lack of an available gas pipeline in the areas in
which Inland may conduct operations. State and federal regulations generally are
intended to prevent waste of oil and gas, protect rights to produce oil and gas
between owners in a common reservoir, control the amount of oil and gas produced
by assigning allowable rates of production and control contamination of the
environment. Pipelines are subject to the jurisdiction of various federal, state
and local agencies.

Many state authorities require permits for drilling operations,
drilling bonds and reports concerning operations and impose other requirements
relating to the exploration and production of oil and gas. Such states also have
ordinances, statutes or regulations addressing conservation matters, including
provisions for the unitization or pooling of oil and gas properties, the
regulation of spacing, plugging and abandonment of such wells, and limitations
establishing maximum rates of production from oil and gas wells. However, no
Utah regulations provide such production limitations with respect to the Field.

Environmental Regulation. The recent trend in environmental legislation
and regulation has been generally toward stricter standards, and this trend will
likely continue. The Company does not presently anticipate that it will be
required to expend amounts relating to its oil and gas production operations
that are material in relation to its total capital expenditure program by reason
of environmental laws and regulations, but because such laws and regulations are
subject to interpretation by enforcement agencies and are frequently changed by
legislative bodies, the Company is unable to accurately predict the ultimate
cost of such compliance for 2003.

The Company is subject to numerous laws and regulations governing the
discharge of materials into the environment or otherwise relating to
environmental protection. These laws and regulations may require the acquisition
of a permit before drilling commences, restrict the types, quantities and
concentration of various substances that can be released into the environment in
connection with drilling and production activities, limit or prohibit drilling
activities on certain lands lying within wilderness, wetlands, and areas
containing threatened and endangered plant and wildlife species, and impose
substantial liabilities for unauthorized pollution resulting from the Company's
operations.

The following environmental laws and regulatory programs appeared to be
the most significant to the Company's operations in 2002, and are expected to
continue to be significant in 2003:

Regulated Access to Public Lands. A substantial portion of the
Company's operations occur on federal leaseholds. During 1996, the Vernal, Utah
office of the Bureau of Land Management ("BLM") undertook the preparation of an

9

Environmental Assessment ("EA") to evaluate the environmental impacts of the
Company's proposed development plan within the Field. The Agency's Record of
Decision ("ROD") on the EA, which was issued on February 3, 1997, identified
surface stipulations and mitigation measures that the Company must implement to
protect various surface resources, including protected and sensitive plant and
wildlife species, archaeological and paleontological resources, soils and
watersheds. The Company has proven itself successful at continuing to develop
oil and gas resources in the Field while complying with the surface stipulations
and mitigation measures contained in the 1997 ROD. In 2002, the BLM began
evaluating the environmental impacts of 600 to 900 new wells proposed for
development by the Company over a five to ten year period beginning in 2004. An
Environmental Impact Statement ("EIS") is currently being prepared by BLM, and a
final ROD on the EIS should be issued in mid-2003.

On February 16, 1999, the United States Fish and Wildlife Service
("USFWS") issued a Proposed Rule to list the mountain plover, a small
ground-nesting bird, as "threatened" under the Federal Endangered Species Act.
The Field contains the only known breeding population of mountain plover in
Utah. On December 5, 2002, The USFWS re-opened the comment period for the
proposed listing of the mountain plover. The USFWS and BLM are likely to
implement additional restrictive surface stipulations in the Field once a Final
Rule to list the mountain plover as threatened is issued. Based on preliminary
discussions with the USFWS and BLM, the Company believes it will be able to
comply with any additional surface stipulations without causing a material
impact on its future drilling plans in the Field.

Clean Water and Oil Pollution Regulatory Programs. The federal Clean
Water Act ("CWA") regulates discharges of pollutants to surface waters. The
discharge of crude oil and petroleum products to surface waters also is
precluded by the Oil Pollution Act ("OPA"). The Company's operations are
inherently subject to accidental spills and releases of crude oil and drilling
fluids that may give rise to liability to governmental entities or private
parties under federal, state or local environmental laws, as well as under
common law. Minor spills occur from time to time during the normal course of the
Company's production operations. The Company maintains spill prevention control
and countermeasure plans ("SPCC plans") for facilities that store large
quantities of crude oil or petroleum products to prevent the accidental
discharge of these potential pollutants to surface waters. As of December 31,
2002, the Company had undertaken all investigative or remedial work required by
governmental agencies to address potential contamination by accidental spills or
discharges of crude oil or drilling fluids.

The Company's operations involve the injection of water into the
subsurface to enhance oil recovery. Under the Safe Drinking Water Act ("SDWA"),
oil and gas operators, such as the Company, must obtain a permit for the
construction and operation of underground Class II enhanced recovery underground
injection wells. To protect against contamination of drinking water, the
Environmental Protection Agency ("EPA") and the State of Utah regulate the
quality of water that may be injected into the subsurface, and require that
mechanical integrity tests be performed on injection wells every five years. In
addition, the Company is required to monitor the pressure at which water is
injected, and must not exceed the maximum allowable injection pressure set by
the EPA and the State of Utah.

The Company has obtained the necessary permits for the Class II
injection wells it operates, and monitors the water quality of injection water
at several injection stations. The Company also maintains a schedule to conduct
mechanical integrity tests for each well every five years. The Company
experienced some difficulty monitoring and regulating injection pressures at
each individual injection well during the period from 1995 to 1998. The Company
reached a final Settlement with EPA on injection well over pressuring during the
1995 to 1998 time period, and has fulfilled its obligations under that
settlement agreement. The Company developed a computer program in 1999 to assist
with monitoring injection pressures that has enhanced the Company's efforts to
meet EPA requirements.

Clean Air Regulatory Programs. The Company's operations are subject to
the federal Clean Air Act ("CAA"), and state implementing regulations. Among
other things, the CAA requires all major sources of hazardous air pollutants, as
well as major sources of certain other criteria pollutants, to obtain operating
permits, and in some cases, construction permits. The permits must contain
applicable Federal and state emission limitations and standards as well as
satisfy other statutory and regulatory requirements. The 1990 Amendments to the
CAA also established new monitoring, reporting, and recordkeeping requirements
to provide a reasonable assurance of compliance with emission limitations and
standards. The Company currently obtains construction and operating permits for
its compressor engines, and is not presently aware of any potential adverse
claims in this regard.

Waste Disposal Regulatory Programs. The Company's operations generate
and result in the transportation and disposal of large quantities of produced
water and other wastes classified by EPA as "nonhazardous solid wastes". The EPA
is currently considering the adoption of stricter disposal and clean-up
standards for nonhazardous solid wastes under

10

the Resource Conservation and Recovery Act ("RCRA"). In some instances, EPA has
already required the clean up of certain nonhazardous solid waste reclamation
and disposal sites under standards similar to those typically found only for
hazardous waste disposal sites. It also is possible that wastes that are
currently classified as "nonhazardous" by EPA, including some wastes generated
during the Company's drilling and production operations, may in the future be
reclassified as "hazardous wastes". Because hazardous wastes require much more
rigorous and costly treatment, storage, transportation and disposal
requirements, such changes in the interpretation and enforcement of the current
waste disposal regulations would result in significant increases in waste
disposal expenditures by the Company.

The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons who are considered to have caused or contributed to the release or
threatened release of a "hazardous substance" into the environment. These
persons include the current or past owner or operator of the disposal site or
sites where the release occurred and companies that transported disposed or
arranged for the disposal of the hazardous substances under CERCLA. These
persons may be subject to joint and several liabilities for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources. The Company is not presently
aware of any potential adverse claims in this regard.

Health and Safety Regulatory Programs. The Company's operations also
are subject to regulations promulgated by the Occupational Safety and Health
Administration ("OSHA") regarding worker and work place safety. The Company
currently provides health and safety training and equipment to its employees and
is adopting additional corporate policies and procedures to comply with OSHA's
workplace safety standards.

Operational Hazards And Uninsured Risks. The oil and gas business
involves certain inherent operating hazards such as well blowouts, cratering,
explosions, uncontrollable flows of oil, gas or well fluids, fires, formations
with abnormal pressures, pollution, releases of toxic gas and other
environmental hazards and risks. Any of these operating hazards could result in
substantial losses to the Company. In accordance with customary industry
practices, the Company maintains insurance against some, but not all, of these
risks and losses. The Company is also required under various operating
agreements to maintain certain insurance coverage on existing wells and all new
wells drilled during drilling operations, and name others as additional insureds
under such insurance coverage. The occurrence of an event that is not fully
covered by insurance could have an adverse impact on the Company's financial
condition and results of operations.

Competition. Many companies and individuals are engaged in the oil and
gas business. Inland is faced with strong competition from major oil and gas
companies and other independent operators attempting to acquire prospective oil
and gas leases, producing oil and gas properties and other mineral interests.
Some competitors are very large, well-established companies with substantial
capabilities and long earnings records. Inland may be at a disadvantage in
acquiring oil and gas prospects since it must compete with individuals and
companies that have greater financial resources and larger technical staffs than
Inland.

DISCONTINUED REFINING OPERATIONS

General. As noted above under "Overview", Inland sold its refinery
operations effective as of January 31, 2000 by selling all of its stock in
Refining to Silver Eagle. The Company's refining operations were conducted
through its wholly-owned subsidiary, Refining, at the Woods Cross Refinery, a
hydroskimming plant with an overall crude capacity of approximately 10,000 BPD.

Environmental Regulations Associated with Discontinued Refining
Operations. As of December 31, 2002, the Company was not aware of any remaining
liabilities associated with any of its previously held refining properties.
There remains, however, the possibility that federal, state, or local
governmental agencies, or private parties could attempt to join the Company in
clean-up efforts associated with previously held refining properties should they
be required.

EMPLOYEES

At March 12, 2003, the Company had 114 employees, consisting of 5
officers, 23 technical, clerical and administrative employees and 86 field
operations staff involved in the Company's oil and gas operations in Utah.

11

SEC REPORTS

The Company is obligated to file with the Securities and Exchange
Commission certain interim and periodic reports including this annual report
containing audited financial statements. The Company intends to continue filing
these reports under the Securities Exchange Act of 1934 until such time that the
Merger becomes effective, when it will elect to terminate its registration under
such Act. The Company does not maintain a website or otherwise post any of its
reports on the Internet.

OTHER PROPERTY

The Company's principal executive office is located in Denver,
Colorado. The Company leases approximately 16,500 square feet pursuant to a
lease that expires in December 2003 and provides for a rental rate of $25,000
per month. Such space is adequate for the foreseeable future. The Company owns
the Roosevelt Utah field office (20,200 square feet) and land (40 acres).

CERTAIN DEFINITIONS

The following are abbreviations and words commonly used in the oil and gas
industry and in this Annual Report.

"Bbl" or "barrel" means barrels, a standard measure of volume for oil,
condensate and natural gas liquids which equals 42 U.S. gallons.

"BOE" means equivalent barrels of oil. In reference to natural gas, natural gas
equivalents are determined using the ratio of six Mcf of natural gas to one Bbl
of crude oil, condensate or natural gas liquids.

"BPD" means barrels per day.

"BWPD" means barrels of water per day.

"development well" means a well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.

"exploration well" means a well drilled to find commercially productive
hydrocarbons in an unproved area or to extend significantly a known oil or
natural gas reservoir.

"farm-in" or "farm-out" refers to an agreement whereunder the owner of a working
interest in an oil and gas lease delivers the contractual right to earn the
working interest or a portion thereof to another party who desires to drill on
the leased acreage. Generally, the assignee is required to drill one or more
wells in order to earn a working interest in the acreage. The assignor usually
retains a royalty or a working interest after payout in the lease. The assignor
is said to have "farmed-out" the acreage. The assignee is said to have
"farmed-in" the acreage.

"gathering system" means a pipeline system connecting a number of wells,
batteries or platforms to an interconnection with an interstate pipeline.

"gross" oil and natural gas wells or "gross" acres are the total number of wells
or acres, respectively, in which the Company has an interest, without regard to
the size of that interest.

"MBls" means one thousand barrels.

"MBOE" means one thousand equivalent barrels of oil.

"Mcf" means one thousand cubic feet, a standard measure of volume for gas.

"MMcf" means one million cubic feet.

"net" oil and natural gas wells or "net" acres are the total gross number of
wells or acres respectively in which the Company

12

has an interest multiplied times the Company's or other referenced party's
working interest in such wells or acres.

"posted field price" is an industry term for the fair market value of oil in a
particular field.

"productive wells" are producing wells or wells capable of production

In this Annual Report, natural gas volumes are stated at the legal pressure base
of the state or area in which the reserves are located and at 60 degrees
Fahrenheit.

ITEM 3. LEGAL PROCEEDINGS

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

[THIS SPACE INTENTIONALLY LEFT BLANK]

13

PART II

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

PRICE RANGE OF COMMON STOCK

Since July 29, 1999, Inland's Common Stock has been traded over-the-counter and
quoted from time to time in the OTC Bulletin Board and in the "Pink Sheets"
under the trading symbol "INLN". Prior to July 29, 1999, Inland's Common Stock
was quoted on the Nasdaq SmallCap Market under the symbol "INLN". As of March
14, 2003, there were approximately 506 holders of record of Inland's Common
Stock. The following table sets forth the range of high and low bid prices as
reported by the OTC Bulletin Board for the periods indicated after July 29,
1999. The quotations reflect inter-dealer prices without retail markup, markdown
or commission, and may not necessarily represent actual transactions.

DIVIDEND POLICY

Inland has not paid cash dividends on Inland's Common Stock during the last five
years and does not intend to pay cash dividends on Common Stock in the
foreseeable future. The payment of future dividends will be determined by
Inland's Board of Directors in light of conditions then existing, including
Inland's earnings, financial condition, capital requirements, restrictions in
financing agreements, business conditions and other factors. The Fortis Credit
Agreement forbids the payment of dividends by Inland on its Common Stock.

DISCLOSE ANY REDEMPTIONS OF CAPITAL STOCK DURING THE FOURTH QUARTER OF 2002

None.

14

EQUITY COMPENSATION PLAN INFORMATION

ITEM 6. SELECTED FINANCIAL DATA

The following tables set forth-selected historical consolidated financial and
operating data for Inland as of and for each of the five years ended December
31, 2002. Such data should be read together with the historical consolidated
financial statements of Inland incorporated in this annual report.

15

(1) Excludes production taxes.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

The following discussion should be read in conjunction with the
Company's consolidated financial statements and notes thereto included elsewhere
in this Annual Report and the information set forth under the heading "Selected
Financial Data" and is intended to assist in the understanding of the Company's
financial position and results of operations for each of the years ended
December 31, 2002, 2001, and 2000.

GENERAL

Inland is an independent energy company engaged in the acquisition,
development and enhancement of oil and gas properties in the western United
States. All of the Company's oil and gas reserves are located in the Monument
Butte Field (the "Field") within the Uinta Basin of northeastern Utah.

On January 31, 2000, the Company sold its 100% owned subsidiary, Inland
Refining, Inc. The subsidiary owned the Woods Cross Refinery and a nonoperating
refinery located in Roosevelt, Utah. Due to this sale, the Company is no longer
involved in the refining of crude oil or the sale of refined products. As a
result, all refining operations have been classified as discontinued operations
in the accompanying consolidated financial statements.

17

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion of financial condition and results of operation are
based upon the information reported in our consolidated financial statements.
The preparation of these financial statements requires us to make assumptions
and estimates that affect the reported amounts of assets, liabilities, revenues
and expenses as well as the disclosure of contingent assets and liabilities at
the date of our financial statements. We base our decisions on historical
experience and various other sources that are believed to be reasonable under
the circumstances. Actual results may differ from the estimates we calculated
due to changing business conditions or unexpected circumstances. Policies we
believe are critical to understanding our business operations and results of
operations are detailed below. For additional information on our significant
accounting policies you should see Note 1 in our accompanying consolidated
financial statements.

Successful Efforts Method of Accounting. The Company accounts for its
natural gas and crude oil exploration and development activities utilizing the
successful efforts method of accounting. Under this method, costs of productive
exploratory wells, development dry holes and productive wells and undeveloped
leases are capitalized. Gas and oil lease acquisition costs are also
capitalized. Exploration costs, including personnel costs, certain geological
and geophysical expenses and delay rentals for gas and oil leases, are charged
to expense as incurred. Exploratory drilling costs are initially capitalized,
but charged to expense if and when the well is determined not to have found
reserves in commercial quantities. The sale of a partial interest in a proved
property is accounted for as a cost recovery and no gain or loss is recognized
as long as this treatment does not significantly affect the unit-of-production
amortization rate. A gain or loss is recognized for all other sales of producing
properties.

The application of the successful efforts method of accounting requires
management's judgment to determine the proper classification of wells designated
as developmental or exploratory which will ultimately determine the proper
accounting treatment of the costs incurred. The results from a drilling
operation can take considerable time to analyze and the determination that
commercial reserves have been discovered requires both judgment and industry
experience. Wells may be completed that are assumed to be productive and
actually deliver gas and oil in quantities insufficient to be economic, which
may result in the abandonment of the wells at a later date. Wells are drilled
that have targeted geologic structures that are both developmental and
exploratory in nature and an allocation of costs is required to properly account
for the results. The evaluation of gas and oil leasehold acquisition costs
requires judgment to estimate the fair value of these costs with reference to
drilling activity in a given area. Drilling activities in an area by other
companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant
impact on the operational results reported when the Company is entering a new
exploratory area in hopes of finding a gas and oil field that will be the focus
of future development drilling activity. Any initial exploratory wells that are
unsuccessful are expensed. Seismic costs can be substantial which will result in
additional exploration expenses when incurred.

Oil and gas reserve quantities. Estimated reserve quantities and the
related estimates of future net cash flows affect our periodic calculations of
depletion, depreciation and impairment for our proved oil and gas properties.
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operation conditions. Future inflows and
future production and development costs are determined by applying benchmark
prices and costs, including transportation and basis differentials, in effect at
the end of each period to the estimated quantities of oil and gas remaining to
be produced at the end of that period. Expected cash flows are reduced to
present value using a discount rate that depends upon the calculation for which
the reserve estimates will be used. Reserve estimates are inherently imprecise.
Estimates of new discoveries are more imprecise that those of proved producing
oil and gas properties. We expect that periodic reserve estimates will change in
the future, as additional information becomes available or as oil and gas prices
and costs change. For any period, unknown circumstances could have caused us to
calculate more or less depletion, depreciation or impairment. Changes in these
calculations caused by changes in reserve quantities or net cash flows are
recorded in the period that the reserve estimates changed.

Impairment of Oil and Gas Properties. The Company reviews its oil and
gas properties for impairment whenever events and circumstances indicate a
decline in the recoverability of their carrying value. The Company estimates the
expected undiscounted future cash flows of its gas and oil properties and
compares such future cash flows to the carrying amount of the oil and gas
properties to determine if the carrying amount is recoverable. If the carrying
amount exceeds the estimated undiscounted future cash flows, the Company will
adjust the carrying amount of the oil and gas properties to their fair value.
The factors used to determine fair value include estimates of proved reserves,
future commodity pricing, future production

18

estimates, anticipated capital expenditures, and a discount rate commensurate
with the risk associated with realizing the expected cash flows projected. There
were no impairments of producing gas and oil properties in 2002, 2001 or 2000.
Given the complexities associated with gas and oil reserve estimates and the
history of price volatility in the gas and oil markets, events may arise that
would require the Company to record an impairment of the recorded book values
associated with oil and gas properties.

Derivative Instruments and Hedging Activities. The Company periodically
hedges a portion of its gas and oil production through swap and collar
agreements. The purpose of the hedges is to provide a measure of stability to
our cash flows in an environment of volatile gas and oil prices and to manage
the exposure to commodity price risk. We recognize all derivative instruments as
assets or liabilities in the balance sheet at fair value. For cash flow hedges,
changes in fair value, to the extent the hedge is effective, are recognized in
other comprehensive income until the hedged item is recognized in earnings. For
derivative instruments that do not qualify as hedges, changes in fair value are
recognized in earnings currently.

The estimation of fair values for our hedging derivatives requires
substantial judgment. The fair values of our derivatives are estimated on a
monthly basis using an option-pricing model. The option-pricing model uses
various factors that include closing exchange prices on the NYMEX,
over-the-counter quotations, volatility and the time value of options. These
pricing and discounting variables are sensitive to market volatility as well as
changes in future price forecasts, regional price differentials and interest
rates.

Revenue recognition. The Company is engaged in the acquisition,
development, and enhancement of oil and gas properties of crude oil and natural
gas. Our revenue recognition policy is significant because our revenue is a key
component of our results of operations. We derive our revenue primarily from the
sale of produced crude oil and natural gas. Revenue is recorded in the month our
production is delivered to the purchaser, but payment is generally received
between 30 and 60 days after the date of production. At the end of each period
we make estimates of the amount of production delivered to the purchaser and the
price we will receive. We use our knowledge of our properties, their historical
performance, NYMEX and local spot market prices and other factors as the basis
for these estimates. Variances between our estimates and the actual amounts
received are recorded in the month payment is received. The Company accounts for
oil and gas sales using the entitlements method. Under the entitlements method,
revenue is recorded based upon the Company's share of volumes sold, regardless
of whether the Company has taken its proportionate share of volumes produced.
The Company records a receivable or payable to the extent it receives less or
more than its proportionate share.

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2002 COMPARED WITH YEAR ENDED DECEMBER 31, 2001

Oil and Gas Sales. Crude oil and natural gas sales revenues for the
year ended December 31, 2002 decreased $2.1 million, or 6.5% from the previous
year. As shown in the table below, the $2.1 million decrease in 2002 was caused
by lower crude oil and natural gas sales volumes offset partially by increased
natural gas liquids sales volumes, lower hedging loss and the reclass of
$1,444,000 of non-cash hedging gains from accumulated other comprehensive income
to oil and gas revenues. Oil sales in 2002 were $1.4 million, or 5%, lower than
in 2001 due to lower sales volumes offset by partially higher sales prices. Gas
sales in 2002 were $3.3 million, or 44%, lower than in 2001 due to lower sales
volumes and lower sales prices. The Company operates and is in control of over
98% of its oil and gas production. Crude oil sales as a percentage of total oil
and gas sales were 85% and 79% during 2002 and 2001, respectively. Crude oil
will continue to be the predominant product produced from the Field.

The Company periodically enters into price protection agreements to
hedge against volatility in crude oil prices. During 2001, the Company entered
into all of its hedging contracts with Enron North America Corp. ("ENAC"). On
December 2, 2001, ENAC filed for Chapter 11 bankruptcy. The ENAC bankruptcy
caused default on all of the Company's hedging contracts from November 2001
through September 30, 2003. As discussed in Note 2 to the Consolidated Financial
Statements, in 2001 the Company recorded a loss of $2.2 million to the statement
of operations to reflect ineffectiveness of the derivative contracts and
deferred a corresponding amount in accumulated other comprehensive income. Of
the $2.2 million deferred in accumulated other comprehensive income, $1.4
million and $480,000 was reclassified out of accumulated other comprehensive
income in 2002 and 2001, respectively, resulting in increases in crude oil sales
revenues. The remaining $231,000 deferred in accumulated other comprehensive
income will be reclassified to oil and gas sales revenue in 2003. Although
hedging activities do not affect the Company's actual sales price for crude oil
in the Field, the financial impact of hedging transactions is reported as an
adjustment to oil and gas sales revenue in the period in which the related oil
is sold. Excluding the effects of the ENAC derivatives discussed above, oil and
gas sales revenues were decreased by $1.7 million and $2.5 million during

19

year 2002 and 2001, respectively, to recognize hedging contract settlement
losses. See Item 7A "Quantitative and Qualitative Disclosures About Market
Risk".

Lease Operating Expenses. Lease operating expense for the year ended
December 31, 2002 increased $1,591,000, or 17% from the previous year. Lease
operating expense per BOE increased from $5.78 per BOE sold in 2001 to $7.35 per
BOE in 2002. The increase in lease operating expenses is due to an increase in
well count resulting from the drilling of 17 new wells and returning 32 shut in
wells to production and higher costs of materials and labor due to increased
demand for products, services and employees in the Monument Butte region and
neighboring areas.

Production Taxes. Production taxes as a percentage of sales were 1.2%
in 2002 and 1.4% in 2001. Production tax expense consists of estimates of the
Company's yearly effective tax rate for Utah state severance tax and production
ad valorem tax. Changes in sales prices, tax rates, tax exemptions and the
timing, location and results of drilling activities can all affect the Company's
actual effective tax rate.

Exploration. Exploration expense in 2002 and 2001 represents the
Company's cost to retain unproved acreage including delay rentals.

Depletion, Depreciation and Amortization. Depletion, depreciation and
amortization for the year ended December 31, 2002 decreased 4%, or $350,000,
from the previous year. The decrease resulted from decreased oil and gas sales
volumes and a higher average depletion rate. Depletion, which is based on the
units-of-production method, comprises the majority of the total charge. The
depletion rate is a function of capitalized costs and related underlying proved
reserves in the periods presented. The Company's average actual depletion rate
was $5.46 per BOE sold during 2002 compared to $5.26 per BOE sold during 2001.
An increase in 2001 capital expenditures increased the actual depletion rate in
2002. Based on December 31, 2002 proved oil and gas reserves, the Company's
depletion rate entering 2003 is $5.57 per BOE.

General and Administrative, Net. General and administrative expense for
the year ended December 31, 2002 decreased $287,000, or 19% from the previous
year. General and administrative expense is reported net of operator fees and
reimbursements which were $8.5 million and $7.5 million during 2002 and 2001,
respectively. Gross general and administrative expense was $9.7 million in 2002
and $9.0 million in 2001. The lower net general and administrative expenses for
2002 from the previous year was due to higher reimbursement from operating
overhead and labor partially offsetting the Company's higher labor and benefit
costs.

Interest Expense. Interest expense for the year ended December 31, 2002
increased $6.2 million, or 52% from the previous year. The increase was the
result of the August 2, 2001 issuance of subordinated debt of $109 million at a
rate of 11% per annum. Interest expense on the subordinated debt for 2002 and
2001 was $13 million and $5 million, respectively. Offsetting the higher
subordinated debt interest was interest on the senior bank debt, which decreased
$1.9 million or 29% from the previous year, due to lower floating interest
rates. Borrowings during 2002 and 2001 were at effective interest rates of 8.9%
and 8.8%, respectively.

20

Other Income. Other income in 2002 and 2001 primarily represents
interest earned on the investment of surplus cash balances and miscellaneous
other income.

Income Taxes. In 2002 and 2001, no income tax provision or benefit was
recognized due to net operating losses incurred and the establishment of a full
valuation allowance.

Preferred Series D Stock Dividends. Inland's Preferred Series D Stock
accrued dividends at 11.25% compounded quarterly. The amount accrued in 2001
represented those dividends earned through August 1, 2001 . As discussed under
Note 4 to the Consolidated Financial Statements, the Company's Preferred Series
D Stock was cancelled in exchange for the TCW subordinated notes and $2 million
on August 2, 2001.

Preferred Series E Stock Dividends. Inland's Preferred Series E Stock
accrued dividends at 11.5% compounded quarterly. The amount accrued in 2001
represented those dividends earned through August 1, 2001 . As discussed under
Note 4 to the Consolidated Financial Statements, the Company's Preferred Series
E Stock was cancelled on August 2, 2001.

Preferred Series D Stock Discount. Inland's Preferred Series D Stock
was initially recorded on the financial statements at a discount of $20.2
million and was being accreted to face value ($80.7 million) over the minimum
mandatory redemption period, that started on April 1, 2002 and ended on April 1,
2004. As discussed under Note 4 to the Consolidated Financial Statements, the
Company's Preferred Series D Stock was cancelled in exchange for TCW
subordinated notes and $2 million on August 2, 2001.

Preferred Series E Stock Discount. Inland's Preferred Series E Stock
was initially recorded on the financial statements at a discount of $4.2 million
and was being accreted to face value ($12.2 million) over the period to the
minimum mandatory redemption date of April 1, 2004. As discussed under Note 4 to
the Consolidated Financial Statements, the Company's Preferred Series E Stock
was cancelled on August 2, 2001.

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2001 COMPARED WITH YEAR ENDED DECEMBER 31, 2000

Oil and Gas Sales. Crude oil and natural gas revenue for the year ended
December 31, 2001 increased $3.5 million, or 12% from the previous year. As
shown in the table below, the $3.5 million variance in 2001 was caused by higher
oil and natural gas sales volumes and higher average natural gas prices, offset
partially by lower crude oil prices. The Company operates and is in control of
over 98% of its oil and gas production. Crude oil sales as a percentage of total
oil and gas sales were 79% and 83% during 2001 and 2000, respectively. Crude oil
will continue to be the predominant product produced from the Field.

The Company periodically enters into price protection agreements to
hedge against volatility in crude oil prices. During 2001 and 2000, the Company
entered into all of its hedging contracts with ENAC. On December 2, 2001, ENAC
filed for Chapter 11 bankruptcy. The ENAC bankruptcy caused default on all of
the Company's hedging contracts from November 2001 through September 30, 2003.
As discussed in Note 2 to the Consolidated Financial Statements, the Company
recorded a loss of $2.2 million to the statement of operations to reflect
ineffectiveness of the derivative contracts and deferred a corresponding amount
in accumulated other comprehensive income. Of the $2.2 million deferred in
accumulated other comprehensive income, $480,000 was reclassified out of
accumulated other comprehensive income in 2001 resulting in an increase in crude
oil sales revenues. Although hedging activities do not affect the Company's
actual sales price for crude oil in the Field, the financial impact of hedging
transactions is reported as an adjustment to oil and gas sales revenue in the
period in which the related oil is sold. Excluding the effects of the ENAC
derivative discussed above, oil and gas sales revenues were decreased by $2.5
million and $6.1 million during year 2001 and 2000, respectively, to recognize
hedging contract settlement losses. See Item 7A "Quantitative and Qualitative
Disclosures About Market Risk".

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Lease Operating Expenses. Lease operating expense for the year ended
December 31, 2001 increased $1,748,000, or 23% from the previous year. Lease
operating expense per BOE increased from $5.23 per BOE sold in 2000 to $5.78 per
BOE in 2001. The increase in year 2001 on a BOE basis is due to substantially
higher costs of materials and labor, due to increased demand for products,
services and employees in the Monument Butte region and neighboring areas.

Production Taxes. Production taxes as a percentage of sales were 1.4%
in 2001 and 1.4% in 2000. Production tax expense consists of estimates of the
Company's yearly effective tax rate for Utah state severance tax and production
ad valorem tax. Changes in sales prices, tax rates, tax exemptions and the
timing, location and results of drilling activities can all affect the Company's
actual effective tax rate.

Exploration. Exploration expense in 2001 and 2000 represents the
Company's cost to retain unproved acreage including delay rentals.

Depletion, Depreciation and Amortization. Depletion, depreciation and
amortization for the year ended December 31, 2001 increased 17%, or $1.3
million, from the previous year. The increase resulted from increased sales
volumes and a higher average depletion rate. Depletion, which is based on the
units-of-production method, comprises the majority of the total charge. The
depletion rate is a function of capitalized costs and related underlying proved
reserves in the periods presented. The Company's average depletion rate was
$5.26 per BOE sold during 2001 compared to $4.95 per BOE sold during 2000. An
increase in the 2000 and 2001 capital expenditures, which were not offset by an
increase in oil and gas reserves until the end of 2001, increased the actual
depletion rate in 2001.

General and Administrative, Net. General and administrative expense for
the year ended December 31, 2001 decreased $642,000, or 30% from the previous
year. General and administrative expense is reported net of operator fees and
reimbursements which were $7.5 million and $5.5 million during 2001 and 2000,
respectively. Gross general and administrative expense was $9 million in 2001
and $7.6 million in 2000. The lower net general and administrative expenses for
2001 was due to higher reimbursement from operating overhead, drilling and labor
due to the 2001 drilling program offset by higher labor and benefit costs.

Interest Expense. Interest expense for the year ended December 31, 2001
increased $3.7 million, or 45% from the previous year. The increase was the
result of the August 2, 2001 issuance of subordinated debt of $109 million at a
rate of 11% per annum. Interest expense on the subordinated debt for 2001 was $5
million compared to none for 2000. Interest on the senior bank debt decreased
$1.5 million or 19% from the previous year due to lower floating interest rates.
Borrowings during 2001 and 2000 were recorded at effective interest rates of
8.8% and 10.2%, respectively.

Other Income. Other income in 2001 and 2000 primarily represents
interest earned on the investment of surplus cash balances and miscellaneous
other income.

Income Taxes. In 2001 and 2000, no income tax provision or benefit was
recognized due to net operating losses incurred and the establishment of a full
valuation allowance.

Preferred Series D Stock Dividends. Inland's Preferred Series D Stock
accrued dividends at 11.25% compounded quarterly. The amount accrued represented
those dividends earned through August 1, 2001 and during 2000, respectively. As
discussed under Note 4 to the Consolidated Financial Statements, the Company's
Preferred Series D Stock was canceled in exchange for the TCW subordinated notes
and $2 million on August 2, 2001.

Preferred Series E Stock Dividends. Inland's Preferred Series E Stock
accrued dividends at 11.5% compounded quarterly. The amount accrued represented
those dividends earned through August 1, 2001 and during 2000, respectively. As
discussed under Note 4 to the Consolidated Financial Statements, the Company's
Preferred Series E Stock was canceled on August 2, 2001.

22

Preferred Series D Stock Discount. Inland's Preferred Series D Stock
was initially recorded on the financial statements at a discount of $20.2
million and was being accreted to face value ($80.7 million) over the minimum
mandatory redemption period, that started on April 1, 2002 and ended on April 1,
2004. As discussed under Note 4 to the Consolidated Financial Statements, the
Company's Preferred Series D Stock was canceled in exchange for TCW subordinated
notes and $2 million on August 2, 2001.

Preferred Series E Stock Discount. Inland's Preferred Series E Stock
was initially recorded on the financial statements at a discount of $4.2 million
and was being accreted to face value ($12.2 million) over the period to the
minimum mandatory redemption date of April 1, 2004. As discussed under Note 4 to
the Consolidated Financial Statements, the Company's Preferred Series E Stock
was canceled on August 2, 2001.

LIQUIDITY AND CAPITAL RESOURCES

FORTIS CREDIT AGREEMENT

Effective September 21, 1999, the Company entered into a credit
agreement (the "Fortis Credit Agreement"). The current participants are Fortis
Capital Corp. and U.S. Bank National Association (the "Senior Lenders"). At
December 31, 2002, the Company had borrowed all funds under its current
borrowing base of $83.5 million. The borrowing base is calculated as the
collateral value of proved reserves and is subject to redetermination October 1
and April 1. If the borrowing base is lower than the outstanding principal
balance then drawn, the Company must immediately pay the difference. The
borrowing base has yet to be redetermined as discussed below.

In conjunction with Pengo financing, discussed below, the Fortis Credit
Agreement with the senior bank group was amended to change the maturity date to
June 30, 2007 from April 1, 2002, or potentially earlier if the borrowing base
is determined to be insufficient. Interest accrues under the Fortis Credit
Agreement, at the Company's option, at either (i) 2% above the prime rate or
(ii) at various rates above the LIBOR rate. The LIBOR rates are determined by
the Company's senior debt to EBITDA ratios. If the senior debt to EBITDA ratio
is greater than 4.00 to 1.00, the rate is 3.25% above the LIBOR rate; if the
senior debt to EBITDA ratio is equal to or less than 4.00 to 1.00 but greater
than 3.00 to 1.00, the rate is 2.75% above the LIBOR rate; if the senior debt to
EBITDA ratio is less than 3.00 to 1.00, the rate is 2.25% above the LIBOR rate.
As of December 31, 2002, $83.5 million was borrowed under the LIBOR option at
weighted average interest rate of 5.2%. The revolving termination date is June
30, 2004 at which time the loan converts into a term loan payable in 12 equal
quarterly installments of principal, with accrued interest, beginning September
30, 2004. The Fortis Credit Agreement has covenants that restrict the payment of
cash dividends, borrowings, sale of assets, loans to others, investments, merger
activity and hedging contracts without the prior consent of the lenders and
requires the Company to maintain certain net worth, interest coverage and
working capital ratios. The Fortis Credit Agreement is secured by a first lien
on substantially all assets of the Company.

As of March 31, 2002, the Company was not in compliance with the senior
debt to EBITDA ratio. Subsequent to March 31, 2002, the senior lenders waived
compliance with the debt to EBITDA ratio related to March 31, 2002. However, the
Company was not in compliance with its bank covenants as of June 30, 2002,
September 30, 2002 and December 31, 2002 for the senior debt to EBITDA ratios.
Also, the Company was not in compliance with its bank covenant for the current
ratio. Under the terms of the Fortis Credit Agreement, no notice or period of
time to cure the default is required, and therefore the Company was in default.
As a result of the noncompliance with such covenant, the Senior Lenders have the
ability to call the amount payable immediately. As a result of the covenant
violations, the entire amount payable to the Senior Lenders of $83.5 million has
been classified as a current liability. Also, since the subordinated debt has
cross default provisions in their agreements, the Company has reclassified its
subordinated debt as of December 31, 2002, aggregating $127 million, as a
current liability.

An amendment of the Fortis Credit Agreement dated February 3, 2003 was
executed to provide for (1) extension of the Company's borrowing base of $83.5
million through July 31, 2003, (2) a credit commitment of $5 million for letters
of credit to support commodity price hedging and other obligations to be secured
by letters of credit, (3) modification of the maturity date of the revolving
facility to be paid in installments between 2004 and 2008 if the Company obtains
$15 million of capital in the form of equity, debt or contributed property by
December 31, 2003 and modification of certain financial covenants such that the
Company expects to be in compliance throughout 2003. The Company agreed to hedge
50% of its

23

net oil and gas production through December 31, 2004 by June 30, 2003. Also, by
December 31, 2003 and by each December 31 thereafter during the term of the
credit agreement, the Company agreed to hedge 50% of the oil and gas production
for the following twelve months. However, the bank amendment does not become
effective until the actual closing of the "TCW and Smith Exchange" (discussed
below) except that the Company will be able to use the $5 million letters of
credit for commodity price hedging for a period of 90 days after the date of the
amendment.

On January 30, 2003, TCW agreed to exchange its subordinated note in
the principal amount of $98,968,964, plus all accrued and unpaid interest for
22,053,000 shares of the Company's common stock and that number of shares of
Series F Preferred Stock equal to 911,588 shares plus 338 shares for each day
after November 30, 2002 through the closing date of the TCW and Smith Exchange.
Smith has also agreed to exchange its Junior Subordinated Note in the principal
amount of $5,000,000, plus all accrued and unpaid interest for that number of
shares of Series F Preferred Stock equal to 68,854 shares plus 27 shares for
each day after November 30, 2002 through the closing date of the TCW and Smith
Exchange. The Company will authorize 1,100,000 shares of Series F Preferred
Stock to consummate the Exchange.

In the event of a voluntary or involuntary liquidation, dissolution or
winding up of the Company, the holders of the Series F Preferred Stock shall be
entitled to receive, in preference to the holders of the common stock, a per
share amount equal to $100, as adjusted for any stock dividends, combinations or
splits with respect to such shares, plus all accrued or declared but unpaid
dividends on such shares. Each share of Series F Preferred Stock will be
automatically converted into 100 shares of the Company's common stock when
sufficient shares of Common Stock have been authorized.

TCW and two Smith Parties will form a new Delaware corporation to be
known as Inland Resources Inc. ("Newco"). TCW will contribute to Newco all of
TCW's holdings in the Company's common stock and Series F Preferred Stock in
exchange for 92.5% of the common stock of Newco, and each of the Smith Parties
will contribute to Newco all of its holdings in the Company's common stock and
Series F Preferred Stock in exchange for an aggregate of 7.5% of the common
stock of Newco. Newco will then own 99.7% of the Company's common stock and
common stock equivalents.

Upon the formation of Newco and closing of the TCW and Smith Exchange,
the Board of Directors of Newco will meet to pass a resolution for Inland to
merge with and into Newco, with Newco surviving as a Delaware corporation (the
"Merger"). No action is required by the Company's shareholders or Board of
Directors under the relevant provisions of Washington and Delaware law with
respect to a merger of a subsidiary owned more than 90% by its parent
corporation. Stockholders unaffiliated with NEWCO will receive cash of $1.00 per
share as a result of the Merger.

Stockholders of Inland will have the right to dissent from the Merger
and have a court appraise the value of their shares. Stockholders electing to
exercise their right of appraisal will not receive the $1.00 per share paid to
all other public shareholders, but will instead receive the appraised value,
which may be more or less than $1.00 per share. Details of the Exchange and
Merger will be set forth in a Transaction Statement to be mailed to each
stockholders 20 days prior to the effective date which will occur when such
statement clears the SEC review process.

The Merger will result in Inland terminating its status as a reporting
company under the Securities Exchange Act of 1934 and its stock ceasing to be
traded on the over-the-counter bulletin board. Its successor, Newco, will
instead be a private company owned by three stockholders. On February 3, 2003,
the Company filed a Schedule 13E-3 with the Securities and Exchange Commission
in order to complete the TCW and Smith Exchange.

SUBORDINATED UNSECURED DEBT TO PENGO SECURITIES CORP.

On August 2, 2001, the Company closed two subordinated debt
transactions totaling $10 million in aggregate with Pengo. The first of the two
debt transactions with Pengo was the issuance of a $5 million unsecured senior
subordinated note to Pengo due July 1, 2007. The interest rate is 11% per annum
compounded quarterly. The interest payment is payable in arrears in cash subject
to the approval from the senior bank group and accumulates if not paid in cash.
The Company is not required to make any principal payments prior to the July 1,
2007 maturity date. However, the Company is required to make payments of
principal and interest in the same amounts as any principal payment or interest
payments on the "TCW Subordinated Note" (described below). Prior to the July 1,
2007 maturity date, subject to the bank subordination agreement, the Company may
prepay the senior subordinated note in whole or in part with no penalty. Since
the subordinated debt has cross default provisions in their agreements, the
Company has classified the subordinated debt as of December 31, 2002 as a
current liability.

24

The Company also issued a second $5 million unsecured junior
subordinated note to Pengo. The interest rate is 11% per annum compounded
quarterly. The maturity date is the earlier of (i) 120 days after payment in
full of the TCW Subordinated Note or (ii) March 31, 2010. Interest is payable in
arrears in cash subject to the approval from the senior bank group and
accumulates if not paid in cash. The Company is not required to make any
principal payments prior to the March 31, 2010 maturity date. Prior to the March
31, 2010 maturity date, subject to both bank and subordination agreements, the
Company may prepay the junior subordinated note in whole or in part with no
penalty. A portion of the proceeds from the senior and junior subordinated notes
was used to fund a $2 million payment to TCW and other Company working capital
needs.

TCW SUBORDINATED NOTE

In conjunction with the issuance of the two subordinated notes to
Pengo, the Series D Preferred and Series E Preferred stock held by Inland
Holdings LLC, a company controlled by TCW, were exchanged for an unsecured
subordinated note due September 30, 2009 and $2 million in cash from the
Company. The note amount of $98,968,964 represented the face value plus accrued
dividends of the Series D Preferred stock as of August 2, 2001. The interest
rate is 11% per annum compounded quarterly. Interest shall be payable in arrears
in cash subject to the approval from the senior bank group and accumulates if
not paid in cash. Interest payments will be made quarterly, commencing on the
earlier of September 30, 2005 or the end of the first calendar quarter after the
senior bank debt has been reduced to $40 million or less, subject to both bank
and senior subordination agreements. Beginning the earlier of two years prior to
the maturity date or the first December 30 after the repayment in full of the
senior bank debt, subject to both bank and senior subordination agreements, the
Company will make equal annual principal payments of one third of the aggregate
principal amount of the TCW Subordinated Note. Any unpaid principal or interest
amounts are due in full on the September 30, 2009 maturity date. Prior to the
September 30, 2009 maturity date, subject to both bank and senior subordination
agreements, the Company may prepay the TCW Subordinated Note in whole or in part
with no penalty. Since the subordinated debt has cross default provisions in
their agreements, the Company has classified the subordinated debt as of
December 31, 2002 as a current liability.

CASH FLOW AND CAPITAL PROJECTS

During 2002, the Company generated $17.3 million of EBITDA (earnings
before interest, taxes, depletion, depreciation and amortization) of which it
used $13.6 million to continue development of the Field and $4.6 million to
service interest on senior bank borrowings. During 2002, the Company financed
the construction of a gas liquids plant through the issuance of a $1.4 million
note payable. Field development in 2002 consisted of drilling 17 gross wells (13
net wells), converting 33 gross (26 net) wells to water injection and continued
extension of the gas gathering and water delivery infrastructures.

The Company's net capital budget for development of the Field in year
2003 is estimated to be $18 to $20 million. The Company plans to drill 48 wells
(37 net wells), complete 45 workovers and convert 35 producing wells to water
injection. Although there can be no assurance, the Company believes that cash on
hand along with future cash to be generated from operations will be sufficient
to implement its development plans for 2003. The level of these and other
capital expenditures is largely discretionary, and the amount of funds devoted
to any particular activity may increase or decrease significantly depending on
available opportunities, commodity prices, operating cash flows and development
results, among other items. The Company's contractual obligations are listed in
the following table (in thousands):

Going Concern

At the date of this report, however, the Company is unable to complete
the amendment to the Fortis Credit Agreement because it is contingent upon the
closing of the TCW and Smith Exchange. The defaults and cross defaults on the
Company's debt essentially result in all of the debt potentially due and
payable. In addition to the defaults under its debt agreements, the Company has
suffered losses from operations and has a net capital deficit. The Company's
current financial condition and

25

inability to effect the amendment to the Fortis Credit Agreement would raise
substantial doubt about the Company's ability to continue as a going concern.
The Fortis Credit Agreement has been amended on five previous occasions;
however, there can be no absolute assurance that the February 3, 2003 amendment
will go into effect and that the Senior Lenders will not assert their rights to
foreclose on their collateral. Foreclosure by the Senior Lenders on their
collateral would have a material adverse effect on the Company's financial
position and results of operations. Should the Senior Lenders attempt to
foreclose, the Company would immediately seek alternative financing, the
potential sale of a portion or all of its oil and gas properties, or bankruptcy
protection. Although there can be no assurance that alternative financing or the
potential sale of a portion or all of its oil and gas properties would be
successful. The accompanying financial statements have been prepared assuming
the Company will continue as a going concern. The financial statements do not
include any adjustments that might result from the outcome of this uncertainty.

The Company's auditors have included in their report dated March 14,
2003 on the consolidated financial statements, an explanatory paragraph which
states that the accompanying consolidated financial statements have been
prepared assuming that the Company will continue as a going concern. As
discussed in Note 14 to the consolidated financial statements, the Company has
suffered losses from operations, has a net capital deficiency and has defaulted
on its senior indebtedness, which raise substantial doubt about its ability to
continue as a going concern. Management's plans with regard to these matters are
also described in Note 14. The consolidated financial statements do not include
any adjustments that might result from the outcome of this uncertainty.

RECENTLY ADOPTED ACCOUNTING STANDARDS

In June 2001, SFAS No. 141 "Business Combination" and SFAS No. 142
"Goodwill and Other Intangible Assets" were issued, which requires all business
combinations to be accounted for using the purchase method and changes the
treatment of goodwill created in a business combination. The adoption of these
two statements did not have an impact on the Company.

SFAS No. 143, "Accounting for Asset Retirement Obligations," requires