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

----------

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

<Table>
<Caption>
PAGE

PART I
Items 1. & 2. Business and Properties........................................................................2
Item 3. Legal Proceedings.............................................................................13
Item 4. Submission of Matters to a Vote of Security Holders...........................................13

PART II
Item 5. Market for Registrant's Common Stock and Related Stockholder Matters..........................14
Item 6. Selected Financial Data.......................................................................15
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.........17
Item 7A. Quantitative and Qualitative Disclosures About Market Risks...................................27
Item 8. Financial Statements and Supplementary Data...................................................29
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure..........29

PART III
Item 10. Directors and Executive Officers of the Registrant............................................30
Item 11. Executive Compensation........................................................................31
Item 12. Security Ownership of Certain Beneficial Owners and Management................................34
Item 13. Certain Relationships and Related Transactions................................................36
Item 14. Controls and Procedures ......................................................................39

PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K ..............................40
</Table>

-i-

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.

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

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.

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

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.

<Table>
<Caption>
As of December 31, 2002
------------------------------------------
Proved Proved Total
Developed Undeveloped Proved
------------ ------------ ------------
(In thousands)

Net Proved Reserves
Oil (MBls) 17,148 33,991 51,139

Gas (MMcf) 23,740 60,248 83,988

Natural Gas Liquids (MBls) 520 1,307 1,827

MBOE (6Mcf per Bbl) 21,625 45,338 66,963

Estimated Future Net Revenues(1) $ 314,010 $ 726,452 $ 1,040,462
Present Value of Future Net Revenues(2) $ 175,373 $ 218,028 $ 393,401
</Table>

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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

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.

<Table>
<Caption>
Year Ended December 31,
------------------------------------
2002 2001 2000
---------- ---------- ----------

Net Production:
Oil (MBbls) 1,122 1,212 1,072
Gas (MMcf)(1) 2,106 2,423 2,289
Natural Gas Liquids (MBbls) 15 -- --
Total (MBOE) 1,488 1,616 1,454
Average Sale Price(2):
Oil (per Bbl) $ 22.88 $ 22.31 $ 26.71
Gas (per Mcf) $ 1.96 $ 3.05 $ 2.60
Average Production Cost:
($/BOE)(3) $ 7.35 $ 5.78 $ 5.23
</Table>

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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.

<Table>
<Caption>
2002 2001 2000
----------------- ----------------- --------------------
Gross Net Gross Net Gross Net
------- ------- ------- ------- ------- -------

Development wells:
Oil(1) 17 13 44 34.5 43(2) 34.5(2)
Dry -- -- 1 .5 1 1
------- ------- ------- ------- ------- -------
Total 17 13 45 35.0 44 35.5
======= ======= ======= ======= ======= =======
</Table>

(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.

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:

<Table>
<Caption>
Wells(1)
---------------------------------------
Gross Net(2)
------------------ ------------------
Water Water
Location Oil(1) Injection Oil(1) Injection
- -------- ------ --------- ------ ---------

Utah(3) 478 264 365 210
</Table>

(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:

<Table>
<Caption>
Developed Acreage Undeveloped Acreage(1)
----------------- ----------------------
Gross Net Gross Net
Location Acres Acres Acres Acres
- -------- ------- ------- ------- -------

Utah(2) 28,432 22,444 83,368 61,850
</Table>

(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

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

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

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

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.

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

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]

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.

<Table>
<Caption>
Common Stock Bid Price Range
----------------------------
High Low
------ -----

YEAR ENDED DECEMBER 31, 2002
First Quarter .................... $ 2.75 $1.40
Second Quarter ................... 2.40 2.00
Third Quarter .................... 2.50 1.40
Fourth Quarter ................... 1.50 .90

YEAR ENDED DECEMBER 31, 2001
First Quarter .................... $ 1.87 $1.03
Second Quarter ................... 1.69 1.25
Third Quarter .................... 1.60 1.30
Fourth Quarter ................... 2.10 1.32
</Table>

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.

EQUITY COMPENSATION PLAN INFORMATION

<Table>
<Caption>
(a) (b) (c)
----------------------- ------------------- -----------------------
Number of securities
remaining available for
future issuance under
Number of securities to Weighted-average equity compensation
be issued upon exercise exercise price of plans (excluding
of outstanding options, outstanding options securities reflected in
Plan category warrants and rights warrants and rights column (a)
- ------------- ----------------------- ------------------- -----------------------

Equity compensation plans
approved by security
holders 7,980 $49.49 63,300

Equity compensation plans
not approved by security
holders 325,000 $ 2.67 0

Total 332,980 $ 3.80 63,300
</Table>

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.

<Table>
<Caption>
Year Ended December 31,
--------------------------------------------------------
2002 2001 2000 1999 1998
-------- -------- -------- -------- --------
(dollars in thousands, except for unit amounts)

REVENUE AND EXPENSE DATA:
Revenues:
Oil and gas sales ....................................... $ 29,878 $ 31,967 $ 28,497 $ 16,399 $ 21,278
Operating expenses:
Lease operating expenses ................................ 10,935 9,344 7,596 7,160 8,362
Production taxes ........................................ 357 479 483 192 454
Exploration ............................................. 136 143 135 155 153
Impairment .............................................. -- -- -- -- 1,327
Depletion, depreciation and amortization ................ 8,756 9,106 7,816 9,882 12,025
General and administrative, net ......................... 1,199 1,486 2,128 3,136 2,061
-------- -------- -------- -------- --------
Total operating expenses ............................. 21,383 20,558 18,158 20,525 24,382
-------- -------- -------- -------- --------
Operating income (loss) .................................... 8,495 11,409 10,339 (4,126) (3,104)
Interest expense ........................................... (18,227) (12,031) (8,298) (15,989) (14,895)
Unrealized derivative loss ................................. -- (2,200) -- -- --
Interest and other income .................................. 104 626 103 72 107
-------- -------- -------- -------- --------
Net income (loss) from continuing operations ............... (9,628) (2,196) 2,144 (20,043) (17,892)
Loss from discontinued operations .......................... -- -- (250) (16,274) (5,560)
-------- -------- -------- -------- --------
Net income (loss) before extraordinary loss and
cumulative effect of change in accounting principle ..... (9,628) (2,196) 1,894 (36,317) (23,452)
Extraordinary loss ......................................... -- -- -- (556) --
Cumulative effect of change in accounting principle ........ -- 45 -- -- --
-------- -------- -------- -------- --------
Net income (loss) .......................................... (9,628) (2,151) 1,894 (36,873) (23,452)
Accrued Preferred Series C Stock dividends ................. -- -- -- (663) (1,084)
Accrued Preferred Series D Stock dividends ................. -- (6,342) (9,732) (2,262) --
Accrued Preferred Series E Stock dividends ................. -- (980) (1,506) (350) --
Accretion of Preferred Series D Stock discount ............. -- (3,318) (6,300) (1,473) --
Accretion of Preferred Series E Stock discount ............. -- (535) (900) (220) --
Excess carrying value of preferred over
redemption consideration ................................. -- 1,449 -- -- --
-------- -------- -------- -------- --------
Net loss attributable to common stockholders ............... $ (9,628) $(11,877) $(16,544) $(41,841) $(24,536)
======== ======== ======== ======== ========
Net income (loss) .......................................... $ (9,628) $ (2,151) $ 1,894 $(36,873) $(23,452)
Cumulative effect of a change in accounting principle ...... -- (1,972) -- -- --
Change in fair value of derivative contracts ............... (3,219) 1,186 -- -- --
Derivative contract settlements ............................ 220 2,461 -- -- --
-------- -------- -------- -------- --------
Comprehensive income (loss) ................................ $(12,627) $ (476) $ 1,894 $(36,873) $(23,452)
======== ======== ======== ======== ========
Loss per common share from continuing operations
Basic and diluted ..................................... $ (3.32) $ (4.11) $ (5.62) $ (17.56) $ (22.62)
Loss per common share before extraordinary loss and
cumulative effect of change in accounting
principle
Basic and diluted ..................................... $ (3.32) $ (4.11) $ (5.62) $ (28.99) $ (29.25)

Loss per common share:
Basic and diluted ..................................... $ (3.32) $ (4.09) $ (5.71) $ (29.37) $ (29.25)

</Table>

<Table>
<Caption>
Year Ended December 31,
------------------------------------------------------------------
2002 2001 2000 1999 1998
---------- ---------- ---------- ---------- ----------
(dollars in thousands, except for unit amounts)

BALANCE SHEET DATA (AT END OF PERIOD):
Oil and gas properties, net ................................ $ 166,334 $ 162,025 $ 148,955 $ 142,412 $ 159,105
Total assets ............................................... 177,216 173,376 160,065 153,402 187,781
Debt ....................................................... 211,906 197,456 83,500 79,082 156,973
Preferred stock ............................................ -- -- 91,243 72,805 11,102
Stockholders' equity (deficit) ............................. (43,039) (30,412) (20,210) (3,666) 7,039
OTHER FINANCIAL DATA:
Net cash provided by (used in) operating activities ........ $ 11,876 $ 16,663 $ 7,992 $ (7,513) $ 6,822
Net cash used in investing activities ...................... (13,605) (22,289) (14,137) (3,772) (39,391)
Net cash provided by financing activities .................. 1,305 6,727 4,085 10,502 47,076
OPERATING DATA:
Sales volumes (net):
Oil (MBbls) ........................................... 1,122 1,212 1,072 1,165 1,501
Gas (MMcf) ............................................ 2,106 2,423 2,289 2,901 3,006
Natural Gas Liquids (MBbls) ........................... 15 -- -- -- --
MBOE .................................................. 1,488 1,616 1,454 1,649 2,002
BOEPD ................................................. 4,077 4,427 3,973 4,518 5,485
Average prices (excluding hedging activities):
Oil (per Bbl) ......................................... $ 22.88 $ 22.31 $ 26.71 $ 14.38 $ 9.82
Gas (per Mcf) ......................................... 1.96 3.05 2.60 1.56 2.00
Natural Gas Liquids (per Bbl) ......................... 19.47 -- -- -- --
Per BOE ............................................... 20.43 21.30 23.79 12.90 10.35
Production and operating costs (per BOE)(1) ................ $ 7.35 $ 5.78 $ 5.23 $ 4.34 $ 4.18
</Table>

(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.

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

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

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

<Table>
<Caption>
Year Ended December 31, 2002 Year Ended December 31, 2001
------------------------------------ ------------------------------------
Net Volume Net Volume
(MBbls or Average Sales (MBbls or Average Sales
MMcfs) Price (in 000's) MMcfs) Price (in 000's)
---------- ---------- ---------- ---------- ---------- ----------

Crude Oil Sales 1,122 $ 22.88 $ 25,668 1,212 $ 22.31 $ 27,034
Natural Gas Sales 2,106 $ 1.96 4,138 2,423 $ 3.05 7,394
Natural Gas Liquids 15 $ 19.47 292 -- -- --
Reclass of non-cash gains
from Accumulated Other
Comprehensive Income 1,444 --
Hedging Loss (1,664) (2,461)
---------- ----------
Total Oil and Gas Sales $ 29,878 $ 31,967
---------- ----------
</Table>

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.

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".

<Table>
<Caption>
Year Ended December 31, 2001 Year Ended December 31, 2000
------------------------------------ ------------------------------------
Net Volume Net Volume
(MBbls or Average Sales (MBbls or Average Sales
MMcfs) Price (in 000's) MMcfs) Price (in 000's)
---------- ---------- ---------- ---------- ---------- ----------

Crude Oil Sales 1,212 $ 22.31 $ 27,034 1,072 $ 26.71 $ 28,627
Natural Gas Sales 2,423 $ 3.05 7,394 2,289 $ 2.60 5,953
Hedging Loss (2,461) (6,083)
---------- ----------
Total Oil and Gas Sales $ 31,967 $ 28,497
---------- ----------
</Table>

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.

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.

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

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.

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.

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):

<Table>
<Caption>
Contractual Less Than 1-3 4-5 After 5
Obligations Total 1 Year Years Years Years
- ----------- --------- --------- --------- --------- ---------

Long-term debt $ 211,906 $ 476 $ 91,832 $ 119,598 $ --
Operating leases 299 299 -- -- --
--------- --------- --------- --------- ---------
Total Contractual $ 212,205 $ 775 $ 91,832 $ 119,598 $ --
========= ========= ========= ========= =========
</Table>

Going Concern

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
entities to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred and a corresponding increase in
the carrying amount of the related long-lived asset. The Company will be
required to adopt SFAS No. 143 effective January 1, 2003. Upon adoption of SFAS
No. 143 the Company expects to record an asset retirement obligation liability
of $3.4 million, an increase to net properties and equipment of $2 million and
an after tax credit of $1.4 million as a cumulative effect of a change in
accounting principle.

In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets". SFAS No. 144 supersedes SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of". SFAS No. 121 did not address the accounting for a
segment of a business accounted for as a discontinued operation which resulted
in two accounting models for long-lived assets to be disposed of. SFAS No. 144
establishes a single accounting model for long-lived assets to be disposed of by
sale and requires that those long-lived assets be measured at the lower of
carrying amount or fair value less cost to sell, whether reported in continuing
operations or in discontinued operations. SFAS No. 144 is effective for fiscal
years beginning after December 15, 2001. The Company's adoption of SFAS No. 144
on January 1, 2002, had no impact on its financial position or results of
operations .

In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities". SFAS No. 146 is to be applied
prospectively to exit or disposal activities initiated after December 31, 2002.
The standard requires companies to recognize costs associated with exit or
disposal activities when they are incurred rather than at the date of a
commitment to an exit or disposal plan. Examples of costs covered by the
standard include lease termination costs and certain employee severance costs
that are associated with a restructuring, discontinued operation, plant closing
or other exit or disposal activity. Management does not expect the adoption of
SFAS No. 146 to have a material impact on the financial position or results of
operations of the Company.

SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and
Disclosure-an amendment of FASB Statement No. 123," was issued in December 2002.
The standard provides alternative methods of transition for a voluntary change
to the fair value based method of accounting for employee stock-based
compensation. SFAS No. 148 does not change the provisions of SFAS No. 123 that
permit entities to continue to apply the intrinsic value method of APB 25,
"Accounting for Stock Issued to Employees." The Company's accounting for
stock-based compensation will not change as a result of SFAS No. 148 as it
intends to continue following the provisions of APB 25. SFAS No. 148 does
require certain new disclosures in both annual and interim financial statements.
The new interim disclosure provisions will be effective in the first quarter of
2003.

FASB Interpretation 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantee of Indebtedness of
Others," was issued in November 2002. FIN 45 requires that upon issuance of a
guarantee, the guarantor must recognize a liability for the fair value of the
obligation it assumes under that guarantee. FIN 45's provisions for initial
recognition and measurement should be applied on a prospective basis to
guarantees issued or modified after December 31, 2002. The guarantor's previous
accounting for guarantees that were issued before the date of FIN 45's initial
application may not be revised or restated to reflect the effect of the
recognition and measurement provisions of the interpretation. The disclosure
requirements are effective for financial statements of both interim and annual
periods that end after December 15, 2002. The Company is not a guarantor under
any significant guarantees and thus this interpretation is not expected to have
a significant effect on its financial position or results of operations.

FASB Interpretation 46, "Consolidation of Variable Interest Entities,
An Interpretation of ARB 51," was issued in January 2003. The primary objectives
of FIN 46 are to provide guidance on how to identify entities for which control
is achieved through means other than through voting rights (variable interest
entities or VIEs) and how to determine when and which business enterprise should
consolidate the VIE. This new model for consolidation applies to an entity in
which either (1) the equity investors do not have a controlling financial
interest or (2) the equity investment at risk is insufficient to finance that
entity's activities without receiving additional subordinated financial support
from other parties. The Company does not expect the adoption of this standard to
have any impact on its financial position or results of operations.

INFLATION AND CHANGES IN PRICES

Inland's revenues and the value of its oil and gas properties have been
and will be affected by changes in oil and gas prices. Inland's ability to
borrow from traditional lending sources and to obtain additional capital on
attractive terms is also substantially dependent on oil and gas prices. Oil and
gas prices are subject to significant seasonal and other fluctuations that are
beyond Inland's ability to control or predict. Although the level of inflation
affects certain of Inland's costs and expenses, inflation did not have a
significant effect on Inland's result of operations during 2002 or 2001.

FORWARD LOOKING STATEMENTS

Certain statements in this report, including statements of the
Company's and management's expectation, intentions, plans and beliefs, including
those contained in or implied by "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the Notes to Consolidated
Financial Statements, are "forward-looking statements", within the meaning of
Section 21E of the Securities Exchange Act of 1934, that are subject to certain
events, risk and uncertainties that may be outside the Company's control. These
forward-looking statements include statements of management's plans and
objectives for the Company's future operations and statements of future economic
performance, information regarding drilling schedules, expected or planned
production or transportation capacity, future production levels of fields,
marketing of crude oil and natural gas, the Company's capital budget and future
capital requirements, credit facilities, the Company's meeting its future
capital needs, the Company's realization of its deferred tax assets, the level
of future expenditures for environmental costs and the outcome of regulatory and
litigation matters, and the assumptions described in this report underlying such
forward-looking statements. Actual results and developments could differ
materially from those expressed in or implied by such statements due to a number
of factors, including, without limitation, those described in the context of
such forward-looking statements, fluctuations in the price of crude oil and
natural gas, the success rate of exploration efforts, timeliness of development
activities, risk incident to the drilling and completion for oil and gas wells,
future production and development costs, the strength and financial resources of
the Company's competitors, the Company's ability to find and retain skilled
personnel, climatic conditions, the results of financing efforts, the political
and economic climate in which the Company conducts operations and the risk
factors described from time to time in the Company's other documents and reports
filed with the SEC.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Market risk generally represents the risk that losses may occur in the
value of financial instruments as a result of movements in interest rates and
commodity prices.

INTEREST RATE RISK. Inland is exposed to some market risk due to the
floating interest rate under the Fortis Credit Agreement. See Item 7. -
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources." All borrowings under the Fortis
Credit Agreement are due and payable in 12 equal quarterly installments of
principal with accrued interest, beginning September 30, 2004. As of December
31, 2002, the Fortis Credit Agreement had a principal balance of $83.5 million
locked in at various interest rates as described below:

<Table>
<Caption>
Principal Amount Period Locked In Interest Rate
- ---------------- ---------------- -------------

$83 million January 1, 2003 - May 19, 2003 5.20%
$500,000 January 1, 2003 - May 19, 2003 5.22%
</Table>

A 1% increase in interest rates would increase annual interest expense
on the $83.5 million secured note payable by $835,000.

The fair value of the secured note payable to the Senior Lenders
approximates the carrying value, since the notes bear interest at a variable
rate.

The interest rate on the Company's subordinated debt and other debt is
fixed and therefore the Company is not subject to interest rate risk. The
carrying value of the debt approximates the fair value of the debt.

COMMODITY RISKS. Inland hedges a portion of its oil production to
reduce its exposure to fluctuations in the market prices thereof. Inland uses
various financial instruments whereby monthly settlements are based on
differences between the prices specified in the instruments and the settlement
prices of certain futures contracts quoted on the NYMEX index. Gains or losses
on hedging activities are recognized as oil and gas sales in the period in which
the hedged production is sold.

As discussed in Note 2 of the Consolidated Financial Statements on
December 2, 2001, ENAC filed for Chapter 11 bankruptcy. The bankruptcy caused
ENAC to default on all of the Company's hedging contracts from November 2001
through September 30, 2003. 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.
The amount deferred in accumulated other comprehensive income will be
reclassified to earnings based on the originally scheduled delivery period.
Amounts reclassified to earnings in 2002 and 2001 were $1,444,000 and $480,000,
respectively. Amounts expected to be reclassified to earnings in 2003 are
$231,000.

On March 11, 2002, the Company hedged 30,000 net barrels per month with a
Shell Trading Company ("Shell") for the April 2002 to December 2002 period using
a swap with a settlement amount of $23.90 per barrel. On various dates between
March and August of 2002, the Company hedged a total of 60,000 net barrels per
month for the January 2003 to August 2003 period with Shell using a swap with
various settlement amounts that average $24.78. Shell has the right to require
the Company to post collateral for the difference between the mid market
estimate of the cost of liquidating and terminating the hedging position and
$500,000. As of December 31, 2002, Fortis Capital Corp. had issued a letter of
credit of $1.4 million to Shell to cover any deficiencies between the $500,000
credit margin and the mid market estimate from Shell.

On January 16, 2003, the Company hedged 60,000 net barrels per month with
Shell for the September 2003 to December 2003 period using a swap with a
settlement amount of $25.63 per barrel. On February 26, 2003, the Company hedged
another 40,000 net barrels per month with Shell for the January 2004 to December
2004 period using a various swaps with an average settlement amount of $25.25
per barrel. On February 27, 2003 Shell increased the Company's credit margin
from $500,000 to $1,500,000. . On March 18, 2003, Fortis Capital Corp. issued a
letter of credit totaling $3 million to cover any deficiencies between the
$1,500,000 credit margin and the mid market estimate from Shell.

On April 8, 2002, the Company hedged 30,000 net barrels per month with
Big West Oil Company (Big West") for the May 2002 to December 2002 period using
a swap with a settlement amount of $24.90 per barrel.

On January 27, 2003, the Company hedged 30,000 net barrels per month with
Big West for the January 2004 to December 2004 period using various swaps with
an average settlement amount of $23.95 per barrel. On February 18, 2003, the
Company hedged another 10,000 net barrels per month with Big West for the
January 2004 to December 2004 period using a swap with an average settlement
amount of $24.90 per barrel. Big West has the right to require the Company to
post collateral for the difference between the mid market estimate of the cost
of liquidating and terminating the above mentioned hedging position and
$1,000,000.

The potential gains or (losses) on the Company's open derivative
positions based on a hypothetical average market price of equivalent product for
this period is as follows (in thousands except for NYMEX prices):

<Table>
<Caption>
Average NYMEX Per Barrel Market Price for the Contract Period
------------------------------------------------------------------------------
$ 20.00 $ 24.00 $ 28.00 $ 30.00 $ 34.00 $ 38.00 $ 40.00
-------- -------- -------- -------- -------- -------- --------

All Contracts -2003 $ 3,647 $ 767 $ (2,113) $ (3,553) $ (6,433) $ (9,313) $(10,753)
All Contracts - 2004 $ 4,532 $ 692 $ (3,148) $ (5,068) $ (8,908) $(12,748) $(14,668)
-------- -------- -------- -------- -------- -------- --------
</Table>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and supplementary data required by this item
begin at page F-1 hereof.

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

Not applicable.

[THIS SPACE INTENTIONALLY LEFT BLANK]

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

DIRECTORS AND EXECUTIVE OFFICERS

The following table provides information as of March 17, 2003, with
respect to each of the Company's directors and executive officers:

<Table>
<Caption>
SERVED AS EXECUTIVE
OFFICER OR
NAME AGE POSITION DIRECTOR SINCE
---- --- -------- -------------------

DIRECTORS
Arthur J. Pasmas(1) 68 Director (Chairman) 2001

Marc MacAluso(1) 42 Director, Chief Executive 1999
Officer and Chief Operating
Officer

Bill I. Pennington 51 Director, President and 1994
Chief Financial Officer

Bruce M. Schnelwar(1) 61 Director 2001

Dewey A. Stringer III(1) 60 Director 2001

OTHER OFFICERS

William T. War 60 Vice President 1998

Michael B. Guinn 42 Vice President 2002

Daniel W. Shewmake 63 Vice President 2002
</Table>

- ----------

(1) Member of the Audit Committee.

ARTHUR J. PASMAS. Mr. Pasmas has served as Vice President of Smith
Management LLC (or affiliated entities), New York, New York, a private company
engaged in various businesses and investments, including oil and gas, since
1984. He currently manages oil and gas investments as Vice President for Smith
Management LLC from offices in Houston, Texas. He was appointed as a director
and Chairman of the Board on August 2, 2001. He was also a director of the
Company from 1994 until September 1999, and was Co-Chief Executive Officer of
the Company from November 1998 until September 1999.

MARC MACALUSO. Mr. MacAluso was appointed as Chief Executive Officer
and Chief Operating Officer on February 1, 2001, and has served as a director
since October 14, 1999. He was Senior Vice President of TCW Asset Management
Company in Houston, Texas from August 1994 through January 2001, where he was
involved in all aspects of mezzanine financing for TCW's Energy Group. He joined
TCW Asset Management Company after leading new business development at American
Exploration Company. Prior to American Exploration Company, his experience
includes various assignments with Shell Oil Company and Shell Western E&P, Inc.

BILL I. PENNINGTON. Mr. Pennington has served as Chief Financial
Officer of the Company since September 21, 1994 and as President since November
16, 2000. He also served as Chief Executive Officer from September 23,

1999 until February 1, 2001 and as Vice President from March 22, 1996 until
September 23, 1999. He was appointed as a director of the Company on September
23, 1999. He served as a director of the Company from September 21, 1994 until
September 25, 1996 and as Treasurer of the Company from September 21, 1994 until
March 22, 1996. He also served as President, Chief Operating Officer and a
Director of Lomax Exploration Company, now known as IPC, from May 1987 until the
Company's acquisition of IPC on September 21, 1994. From March 1986 until May
1987, Mr. Pennington was a manager with the accounting firm of Coopers & Lybrand
in Houston, Texas. Mr. Pennington is a certified public accountant.

BRUCE M. SCHNELWAR. Mr. Schnelwar has served as a director of the
Company since March 22, 2001. He also was a director of the Company from
February 1998 until September 1999. He has served since August 1994 as Executive
Vice President and Chief Financial Officer of Smith Management LLC (or
affiliated entities).

DEWEY A. STRINGER III. Mr. Stringer has served as a director of the
Company since August 2, 2001. Mr. Stringer has been President of Petro-Guard
Co., Inc., a private oil and gas exploration company located in Houston, Texas
since July 1987.

WILLIAM T. WAR. Mr. War has served as Vice President of the Company
since October 5, 1998. From September 1992 until his association with the
Company, Mr. War was Project Manager for Louisiana Land & Exploration/Burlington
Resource's Lost Cabin Gas Plant.

MICHAEL B. GUINN. Mr. Guinn has served as Vice President of Operations
for the Company since November 21, 2002. From September 1997 until his
appointment to Vice President, Mr. Guinn was in charge of all Roosevelt Utah
operations for the Company as District Engineer. Prior to employment with the
Company, Mr. Guinn was employed by Coastal Oil and Gas as the Assistant Plant
Manager/ Process Engineer at the Altamont Bluebell gas processing facility.

DANIEL W. SHEWMAKE. Mr. Shewmake has served as Vice President of
Development for the Company since November 21, 2002. He has also served as
Senior Geologist since his employment in December, 2000. From January 2000 until
December of 2002, Mr. Shewmake served as a contractor for the Company. He was
employed a total of 38 years as a petroleum geologist in exploration and
production for several companies including Exxon, Anadarko, Superior, Valero and
Snyder.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Section 16(a) of the Securities Exchange Act of 1934, as amended (the
"Exchange Act"), requires the Company's officers and directors, and persons who
beneficially own more than 10% of the Common Stock to file reports of ownership
and changes in ownership with the Securities and Exchange Commission (the
"Commission"). Based solely upon a review of Forms 3, 4 and 5 and amendments
thereto furnished to the Company pursuant to Rule 16a-3(e) promulgated under the
Exchange Act or upon written representations received by the Company, the
Company is not aware of any failure by any officer, director or beneficial owner
of more than 10% of the Company's Common Stock to timely file with the
Commission any Form 3, 4 or 5 during 2002.

BOARD OF DIRECTOR'S MEETINGS

The Company conducted three meetings of the Board of Director's in
2002. One of the three meetings was an audit committee meeting, which was
attended by four of the five Company directors. The other two meetings were
attended by all of the Company directors. In addition, there were three
unanimous consents during the 2002 year.

ITEM 11. EXECUTIVE COMPENSATION

Summary Compensation Table. The following table sets forth the
compensation earned by the Company's Chief Executive Officer and each of its
five other most highly compensated executive officers for the year ended
December 31, 2002 (collectively, the "Named Officers") in salary and bonus for
services rendered in all capacities to the Company for the fiscal years ended
December 31, 2002, 2001 and 2000:

<Table>
<Caption>
ANNUAL COMPENSATION LONG TERM COMPENSATION
------------------------------------------ -------------------------
SECURITIES
UNDERLYING
OTHER ANNUAL OPTIONS OR ALL OTHER
Name/Principal Position YEAR SALARY BONUS COMPENSATION WARRANTS COMPENSATION
- ----------------------- ---- -------- ------- ------------ ---------- ------------

Arthur J. Pasmas, 2002 $ -- $ -- $202,986(1) -- --
Chairman(1) 2001 $ -- -- $199,992(1) -- --
2000 $ -- -- $199,992(1) -- --

Marc MacAluso, Chief 2002 $250,000 $30,000 $ -- 150,000(4) --
Executive Officer and Chief 2001 $235,537 -- $ 27,952(3) -- --
Operating Officer(2) 2000 $ -- -- $ -- -- --

Bill I. Pennington, 2002 $250,000 $30,000 $ -- 150,000(4) --
President and Chief 2001 $250,000 -- $ 10,200 87,500(6) --
Financial Officer(5) 2000 $250,000 -- $ 6,544 --

William T. War, 2002 $148,745 $ 5,000 $ -- -- --
Vice President, Production 2001 $155,346 $75,000 $ 10,200 -- --
2000 $175,000 $50,000 $ 5,020 25,000 --

Michael B. Guinn, 2002 $120,000 $24,000 $ -- -- --
Vice President, Operations 2001 $109,230 $24,000 $ -- -- --
2000 $ 98,041 $ -- $ -- 3,800 --

Daniel W. Shewmake, 2002 $100,000 $20,000 $ -- -- --
Vice President, Development 2001 $100,000 $20,000 $ -- -- --
2000 $ -- $ -- $ 64,078(7) -- --
</Table>

- ----------

(1) Mr. Pasmas was appointed as a director and Chairman on August 2, 2001.
He was also a director of the Company from 1994 until September 1999,
and was Co-Chief Executive Officer of the Company from November 1998
until September 1999. The $202,986 represents total compensation paid
to Mr. Pasmas during 2002 for his compensation as the Chairman of the
Board. The $199,992 represents total compensation paid to Mr. Pasmas
during 2001 for his consulting agreement terminated on August 2, 2001
and his compensation as the Chairman of the Board for the reminder of
the 2001 year. The $199,992 for the year 2000 was for consulting fees
paid to Mr. Pasmas as a non officer and director.

(2) Mr. MacAluso was appointed Chief Executive Officer and Chief Operating
Officer on February 1, 2001. He was not an officer of the Company prior
to his appointment as Chief Executive Officer and Chief Operating
Officer on February 1, 2001.

(3) Moving expenses in 2001 for Mr. MacAluso.

(4) Options issued to Mr. MacAluso and Mr. Pennington on February 1, 2001.

(5) Mr. Pennington was Chief Executive Officer until from September 23,
1999 until February 1, 2001.

(6) These options were mutually terminated by the Company and Mr.
Pennington effective February 1, 2001.

(7) The $64,078 for the year 2000 was for consulting fees paid to Mr.
Shewmake as a non officer and director.

Option/Warrant/SAR Grants. The following table sets forth certain
information regarding options, warrants and SARs granted during 2002:

<Table>
<Caption>
POTENTIAL
REALIZABLE VALUE AT
INDIVIDUAL GRANTS ASSUMED ANNUAL
- ------------------------------------------------------------------------------------- RATES OF STOCK
NUMBER OF PERCENT OF TOTAL PRICE APPRECIATION
SECURITIES UNDERLYING OPTIONS/WARRANTS/SARS EXERCISE OR FOR OPTION TERM
OPTIONS/WARRANTS/SARS GRANTED TO EMPLOYEES BASE PRICE EXPIRATION -------------------
NAME GRANTED (#) IN FISCAL YEAR ($/SH) DATE 5%($) 10%($)
- ---- ----------- --------------------- ----------- ---------- ----- ------

NONE.
</Table>

Option/Warrant/SAR Exercises and Year-End Value Table. The following table
sets forth certain information regarding option exercises and the value of the
outstanding options to purchase Common Stock held by the Named Officers at
December 31, 2002:

<Table>
<Caption>
NUMBER OF SECURITIES VALUE OF UNEXERCISED
UNDERLYING UNEXERCISED IN-THE-MONEY OPTIONS
OPTIONS AT FISCAL YEAR END AT FISCAL YEAR END(1)
NUMBER OF SHARES --------------------------- ---------------------------
ACQUIRED OR REALIZED
NAME EXERCISED VALUE EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ---- ---------------- -------- ----------- ------------- ----------- -------------

Marc MacAluso -- -- 100,500 49,500 -- --
Bill I. Pennington -- -- 150,000 -- -- --
William T. War -- -- 25,000 -- -- --
Michael B. Guinn -- -- 3,800 -- -- --
</Table>

(1) Value is based on the closing bid price of $0.92 per share on December
31, 2002.

Long-Term Incentive Plans. The following table sets forth certain
information regarding long-term incentive awards granted during 2002 to the
Named Officers:

<Table>
<Caption>
ESTIMATED FUTURE PAYMENTS UNDER
PERFORMANCE OR NON-STOCK PRICE-BASED PLANS
NUMBER OF SHARES, OTHER PERIOD -------------------------------
UNITS OR OTHER UNTIL MATURATION THRESHOLD TARGET MAXIMUM
NAME RIGHTS # OR PAYOUT ($ OR #) ($ OR #) ($ OR #)
- ---- ----------------- ---------------- --------- -------- --------

Marc MacAluso -- 12/31/03(1) $ -- $ -- $ --

Bill I. Pennington -- 12/31/03(1) $ -- $ -- $ --

William T. War -- -- $ -- $ -- $ --

Michael B.Guinn -- -- $ -- $ -- $ --
</Table>

- ----------

(1) The Employment Agreements of Messrs. MacAluso and Pennington provide
for an annual performance bonus of up to $50,000 and $50,000,
respectively, based on meeting or exceeding annual performance targets.
Actual bonuses of $30,000 each were paid in 2002 for 2001 performance.
No bonuses have been awarded for the 2002 year.

Compensation of Directors. The members of the Board of Directors of the
Company are entitled to reimbursement for their reasonable expenses in
connection with their travel to and from, and attendance at, meetings of the
Board of Directors or committees thereof. Members of the Board who are not
employees of the Company or employees of either TCW or Smith with exception of
the Chairman of the Board, are paid an annual fee of $25,000 and no additional
meeting fees for meetings of the Board or any committee. The Board of Directors
may grant discretionary options to directors.

Employment Agreements. Effective February 1, 2001, the Company entered
into an employment agreement with Mr. MacAluso. The Company entered into a new
employment agreement with Mr. Pennington effective February 1, 2001, pursuant to
which the Company and Mr. Pennington agreed to terminate his prior employment
agreement. Mr. Pennington also agreed to cancel all outstanding options granted
to him.

Pursuant to their employment agreements, dated effective February 1,
2001, the Company agreed to pay Messrs. MacAluso and Pennington base salaries of
$250,000 and annual bonuses of up to $50,000 contingent upon the Company
reaching or exceeding certain performance targets to be set by the Board for
each year. Their employment agreements have an initial term of three years and
automatically are extended for additional one year periods unless either party
terminates the agreement prior to the end of the current term. The Company also
agreed to grant each of them options to purchase 90,000 shares of the Company's
Common Stock at an exercise price of $1.625 per share and options to purchase
60,000 shares of the Company's Common Stock at an exercise price of $2.84 per
share, with such options vesting ratably over twelve fiscal quarters, with the
first one-twelfth vesting on March 1, 2001. However, Mr. Pennington is fully
vested in his 150,000 options due to change of control of the Company. The
options for 90,000 shares are also subject to automatic increase upon the
issuance of additional shares by the Company in a pro rata amount based on the
percentage increase in the number of outstanding shares of the Company. The
exercise price for such new options would be the same as the issue price of the
new shares issued by the Company. Their new employment agreements also entitle
them to participate in all employee benefit plans and programs of the Company.
Each agreement also provides that if the employee is permanently disabled during
the term of the Agreement, he will continue to be employed at 50% of his base
salary until the first to occur of his death, expiration of 12 months, or
expiration of the employment agreement. Upon termination of employment by the
Company without cause or after a subsequent change of control of the Company,
any unvested portion of their options immediately vest. Upon termination of
employment by the Company or the employee following a change of control of the
Company, the Company agrees to pay the employee an amount equal to the greater
of $250,000 or the remaining unpaid base salary for the remaining term of the
employment agreement and agrees to continue all employee benefits for a period
of one year. Additionally, they will be entitled to severance payments in
accordance with the Company's severance policy which provide for a severance
payment if the employee is terminated due to a change in control in an amount
determined based on the number of years of employment, ranging from two weeks'
base salary for one years' employment up to six months base salary for
employment of five years or more. The Company also agreed to pay various
temporary housing, commuting, moving and relocation expenses of Mr. MacAluso in
connection with his transfer from Houston, Texas to Denver, Colorado. These
expenses were $27,952. In addition, the Company agreed to purchase the equity in
Mr. MacAluso's house in Houston for $141,000 (based on appraised value) and
assumed the financial responsibility for its ultimate sale which was completed
in April of 2001.

These Employment Agreements will be assumed by Newco in the Merger and
will be amended to substitute a new provision dealing with stock options.
Existing options will be cancelled, and pursuant to such amendments, each
executive will be granted options to purchase common shares of Newco for an
exercise price based upon the $1.00 per share amount paid to unaffiliated
shareholders of the Company and the outstanding number of shares of common stock
and common stock equivalents of the Company immediately prior to the Merger. See
"Security Ownership of Certain Beneficial Owners and Management."

Mr. War's employment agreement was amended effective November 16, 2000
to eliminate the $75,000 termination payment payable by the Company if his
employment was terminated by the Company without cause or following a change in
control, and the $75,000 severance payment if he was terminated without cause.
Under the amended employment agreement, Mr. War was paid a bonus of $50,000 in
January 2001 upon execution of the amendment and paid another $25,000 in
December 2001. On January 2, 2002, Mr. War's employment contract was terminated.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

The Company has no compensation committee, and the full Board of
Directors determines the compensation to be paid to executive officers of the
Company, subject to approval by TCW Asset Management Company. Messrs. MacAluso
and Pennington participated in deliberations by the Board of Directors
concerning executive officer compensation during 2002.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information regarding the ownership of
Common Stock as of March 13, 2002, by each stockholder known to the Company to
own beneficially more than five percent of the outstanding Common Stock, each
current director, each Named Officer, and all executive officers and directors
of the Company as a group, based on information provided to the Company by such
persons. Except as otherwise stated, each such person has sole investment and
voting power with respect to the shares set forth in the table:

<Table>
<Caption>
Number
Name and Address Of
of Beneficial Owner Shares Percent

Hampton Investments LLC(1) 2,318,186 71.7
885 Third Avenue, 34th Floor
New York, New York 10022

Inland Holdings LLC(2) 297,196 9.2
TCW Asset Management Company
865 S. Figuero, Suite 1800
Los Angeles, California 90017

Marc MacAluso(3) 150,000 4.6
410 17th Street
Suite 700
Denver, Colorado 80202

Bill I. Pennington(3) 152,168 4.7
410 17th Street
Suite 700
Denver, Colorado 80202

Arthur J. Pasmas(1,4) 2,318,186 71.7
5858 Westheimer, Suite 400
Houston, Texas 77057

Bruce M. Schnelwar(1,4)
885 Third Avenue, 34th Floor 2,318,186 71.7
New York, New York 10022

Dewey A. Stringer III 1,990 *
5858 Westheimer, Suite 400
Houston, Texas 77057

William T. War(3) 25,000 *
410 17th Street
Suite 700
Denver, Colorado 80202

Michael B. Guinn 3,800 *
Rt. 3 Box 3630
Myton UT 84052

All executive officers and 332,958 11.0
directors as a group (5 persons)(3)
</Table>

- ----------

* Less than 1%

(1) JWA Investments IV LLC is the managing member of Hampton Investments
and may be deemed to also beneficially own these shares and John W.
Adams is the sole member of JWA Investments and may be deemed to
beneficially own these shares.

(2) Inland Holdings LLC ("Holdings") owns these shares of record and
beneficially. The members of Holdings are Trust Company of the West, as
Sub-Custodian for Mellon Bank for the benefit of Account No. CPFF
873-3032 ("Fund V"), and TCW Portfolio No. 1555 DR V Sub-Custody
Partnership, L.P. ("Portfolio"). TCW Asset Management Company has the
power to vote and dispose of the shares owned by Holdings and may be
deemed to beneficially own such shares.

(3) Includes shares issuable under outstanding stock options and warrants
granted to Messrs. MacAluso, Pennington and War and all executive
officers and directors appointees as a group for 150,000, 152,167,
25,000 and 329,158 shares, respectively.

(4) Each of Messrs. Pasmas and Schnelwar are officers of Smith Management
LLC, an affiliate of Hampton Investments, but each of them disclaims
beneficial ownership of any of the shares owned by Hampton Investments.

In connection with Items 1 and 2 "Business and Properties - Recent Developments
- - Change of Control and Recapitalization", Holdings and Hampton Investments with
their respective affiliates have agreed to vote to ensure that (i) the Company
and Subsidiary Boards each consist of six members, subject to certain
exceptions, (ii) as long as Hampton Investments and its affiliates hold at least
a majority of the Common Stock of the Company, Hampton Investments and its
affiliates have the right to appoint at least two members to the Company and
Subsidiary Boards or, if greater, at least one-third of the members of the
Board, and (iii) as long as the provisions in the Exchange and Note Issuance
Agreement relating to Board representation are applicable, the Requisite Holders
have the right to have one or more individuals designated for election to, and
be elected to, the Company and Subsidiary Boards, as provided in the Exchange
and Note Issuance Agreement and discussed above. Hampton Investments have
appointed Messrs. Pasmas and Stringer as representatives on the Board.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

1999 EXCHANGE AGREEMENT

On September 21, 1999, the Company entered into an Exchange Agreement
(the "1999 Exchange Agreement") with TCW and its affiliates. Pursuant to the
1999 Exchange Agreement, TCW agreed to exchange $75 million in principal amount
of subordinated indebtedness of the Company plus accrued interest of $5.7
million and warrants to purchase 15,852 shares of common stock for the following
securities of Inland: (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, (3) 1,164,295 shares of
common stock; and (4) 100,000 shares of Inland's Series C Cumulative Convertible
Preferred Stock ("Series C Preferred Stock"), together with $2.2 million of
accumulated dividends thereon, for 121,973 shares of Series E Preferred Stock,
and 292,098 shares of common stock (the "1999 Recapitalization"). The Series C
Preferred Stock bore dividends at an annual 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.

MARCH 2001 TRANSACTION

On March 20, 2001, Hampton purchased from TCW the 121,973 shares of
Series E Preferred Stock and 292,098 shares of common stock acquired by TCW in
the recapitalization. Following closing of the TCW Exchange Agreement and the
purchase by Hampton of TCW's shares, TCW owned 1,752,586 shares of common stock,
representing approximately 60.5% of the outstanding shares of common stock as of
March 20, 2001 and Hampton owned 292,098 shares of common stock, representing
approximately 10.1% of the outstanding shares of common stock as of March 20,
2001. The Company's Articles of Incorporation, as amended (the "Articles"),
provided that the common stock, Series D Preferred Stock and Series E Preferred
Stock shall vote together as a single class and not as a separate voting group
or class on all matters presented to the shareholders of the Company, except as
mandated by law or as expressly set forth in the Articles. The Series D
Preferred Stock and the Series E Preferred Stock were entitled to vote with the
common stock on the basis of one vote for each 10 shares of Series D Preferred
Stock and Series E Preferred Stock.

AUGUST 2001 TRANSACTION

On August 2, 2001, the Company closed two subordinated debt
transactions totaling $10 million in aggregate with Pengo, 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.
Accrued interest at September 30, 2002 was $672,000, and the note will continue
to accrue interest at the stated rate to maturity, giving effect to the
transactions described herein. 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 debt (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 Smith. 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 debt 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 separate subordination agreements with the
Company's bank lenders and with TCW, 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.

In conjunction with the issuance of the two subordinated notes to
Pengo, the Series D Preferred and Series E Preferred Stock held by TCW were
exchanged for an unsecured subordinated note due September 30, 2009 and $2
million in cash from the Company. The note amount was for $98,968,964 that
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 separate subordination agreements
with the Company's bank lenders and with Pengo, as holder of the Company's $5
million senior subordinated note. 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 such agreements, the Company will make equal
annual principal payments of one third of the original principal amount of the
TCW subordinated note. All unpaid principal or interest is due in full on the
September 30, 2009 maturity date. Prior to the September 30, 2009 maturity date,
subject to both of the bank and senior subordinated note subordination
agreements, the Company may prepay the TCW subordinated note in whole or in part
with no penalty. As a result of the 1999 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 TCW and the aggregate liquidation value of the Series D
and E Preferred Stock plus accrued dividends of $13,083,000 was recorded as an
increase to additional paid-in capital.

As part of this restructuring, TCW also sold to Hampton 1,455,390
shares of TCW's common stock in the Company. Consequently, Hampton now owns
approximately 80% of the issued and outstanding shares of the Company. TCW 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, TCW has the right to nominate one person to the Company's
Board. Remaining Board members will be nominated by the Company's shareholders.
As long as Hampton or its affiliates own at least a majority of the common stock
of the Company, Smith has agreed with TCW that Smith will have the right to
appoint at least two members to the Board.

In connection with the August 2001 exchange transaction discussed
above, pursuant to an Amended and Restated Registration Rights Agreement (the
"Registration Rights Agreement"), dated August 2, 2001, by and among TCW, the
Company and Hampton, the Company granted certain demand and piggyback
registration rights to Hampton and TCW in respect of common stock held by them.
Under the Registration Rights Agreement, Hampton may require the Company to
effect three demand registrations and TCW may require the Company to effect one
demand registration. Each of TCW and Hampton is entitled to include their shares
on any registration statement filed by the Company under the Securities Act of
1933, subject to standard underwriters' kick-out clauses and other conditions.
The Company will be responsible for paying the costs and expenses associated
with all registration statements, including the fees of one law firm acting as
counsel to the holders requesting registration but excluding underwriting
discounts and commissions and any other expenses of the party requesting
registration.

FARMOUT AGREEMENT. The Company entered into a Farmout Agreement with
Smith Management, LLC, an affiliate of the Smith Parties effective June 1, 1998.
As of December 31, 1998, an affiliate of Smith received 15,222 shares of common
stock as payment of proceeds under the Farmout Agreement. Effective November 1,
1998, an Amendment to the Farmout Agreement was executed that suspended future
drilling rights under the Farmout Agreement until such time as both the Company,
the Smith Parties and the Company's bank lenders agreed to recommence such
rights. In addition, a provision was added that gave the Smith affiliate the
option to receive cash rather than common stock if the average stock price was
calculated at less than $3.00 per share, such cash to be paid only if the
Company's bank lenders agreed to such payment. The Farmout Agreement was further
amended as part of the 1999 Recapitalization to eliminate this option, to
provide for cash payments only effective June 1, 1999, and to allow the Company
to retain all proceeds under the Farmout Agreement accrued from November 1, 1998
through May 31, 1999. The Farmout Agreement provides that the Smith affiliate
will reconvey all drill sites to the Company once the Smith affiliate has
recovered from production an amount equal to 100% of its expenditures, including
management fees and production taxes, plus an additional sum equal to 18% per
annum on such expended sums.

CONSULTING AGREEMENT. The Company entered into a Consulting Agreement
with Arthur J. Pasmas on September 21, 1999 pursuant to which Mr. Pasmas was to
receive $200,000 annually for consulting services to be provided to the Company
until September 21, 2002. This Consulting Agreement was mutually terminated by
the Company and Mr. Pasmas on August 2, 2001 when he was appointed to the Board
of the Company. The Company has agreed to pay Mr. Pasmas $200, 000 annually for
serving as Chairman of the Board. Mr. Pasmas has been Vice President of Smith
Management LLC (or affiliated entities) since 1985.

COMPENSATION OF DIRECTORS. The members of the Board of Directors of the
Company are entitled to reimbursement for their reasonable expenses in
connection with their travel to and from, and attendance at, meetings of the
Board of Directors or committees thereof. Effective September 23, 1999, members
of the Board who are not employees of the Company are paid an annual fee of
$25,000 and no additional meeting fees for meetings of the Board or any
committee. The Board of Directors may grant discretionary options to directors.

EMPLOYMENT AGREEMENTS. Effective February 1, 2001, the Company entered
into employment agreements with Mr. MacAluso and Mr. Pennington. Pursuant to
their employment agreements, the Company agreed to pay Messrs. MacAluso and
Pennington base salaries of $250,000 and annual bonuses of up to $50,000
contingent upon the Company reaching or exceeding certain performance targets to
be set by the Board for each year. Their employment agreements have an initial
term of three years and automatically are extended for additional one year
periods unless either party terminates the agreement prior to the end of the
current term. The Company also agreed to grant each of them options to purchase
90,000 shares of the Company's Common Stock at an exercise price of $1.625 per
share and options to purchase 60,000 shares of the Company's Common Stock at an
exercise price of $2.84 per share, with such options vesting ratably over twelve
fiscal quarters, with the first one-twelfth vesting on March 1, 2001. However,
Mr. Pennington is fully vested in his 150,000 options due to a change of control
of the Company. The options for 90,000 shares are also subject to automatic
increase upon the issuance of additional shares by the Company in a pro rata
amount based on the percentage increase in the number of outstanding shares of
the Company. The exercise price for such new options would be the same as the
issue price of the new shares issued by the Company. Their employment agreements
also entitle them to participate in all employee benefit plans and programs of
the Company. Each agreement also provides that if the employee is permanently
disabled during the term of the Agreement, he will continue to be employed at
50% of his base salary until the first to occur of his death, expiration of 12
months, or expiration of the employment agreement. Upon termination of
employment by the Company without cause or after a subsequent change of control
of the Company, any unvested portion of their options immediately vest. Upon
termination of employment by the Company or the employee following a change of
control of the Company, the Company agrees to pay the employee an amount equal
to the greater of $250,000 or the remaining unpaid base salary for the remaining
term of the employment agreement and agrees to continue all employee benefits
for a period of one year. Additionally, in such event Messrs. MacAluso and
Pennington will be entitled to severance payments in accordance with the
Company's severance policy, which provide for a severance payment if the
employee is terminated due to a change in control in an amount determined based
on the number of years of employment, ranging from two weeks' base salary for
one year's employment up to six months base salary for employment of five years
or more. The Company also agreed to pay various temporary housing, commuting,
moving and relocation expenses of Mr. MacAluso in connection with his transfer
from Houston, Texas to Denver, Colorado. These expenses were $27,952. In
addition, the Company agreed to purchase the equity in Mr. MacAluso's house in
Houston for $141,000 (based on appraised value) and assumed the financial
responsibility for its ultimate sale which was completed in April of 2001.

DEVELOPMENT AGREEMENT. Pursuant to the Exchange Agreement, the Company
agreed to enter into a five-year Development Agreement with Smith Energy
Partnership, which is the Smith affiliate that is now party to the Farmout
Agreement described above ("Smith Energy"), pursuant to which the Company will
agree to regulate the cash expenditures attributable to the Smith Energy
interests in properties jointly owned with the Company in the Monument Butte
Field in Utah such that the projected annual expenditures would not be
anticipated to exceed the projected cash flow available to Smith Energy from the
properties for the year in question. Any monthly deficit would be advanced by
the Company for the benefit of Smith Energy and recovered from future net cash
flows otherwise accruing to the Smith Energy interests.

All transactions set forth above have been approved by disinterest
members of the Board of Directors of Company, and are considered to be fair and
reasonable to the Company.

ITEM 14. CONTROLS AND PROCEDURES

(a) Within the 90-day period prior to the date of this report, we carried
out an evaluation, under the supervision and with the participation of
our management, including the Chief Executive Officer and Chief
Financial Officer, of the effectiveness of the design and operation of
our disclosure controls and procedures pursuant to Rule 13a-14 of the
Securities Exchange Act of 1934 (the "Exchange Act"). Based upon that
evaluation, the Chief Executive officer and Chief Financial Officer
concluded that our disclosure controls and procedures are effective in
timely alerting them to material information relating to the Company
(including it consolidated subsidiaries) required to be included in our
Exchange Act filings.

(b) There have been no significant changes in our internal controls or in
other factors, which could significantly affect internal controls
subsequent to the date we carried out our evaluation.

[THIS SPACE INTENTIONALLY LEFT BLANK.]

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) The following documents are filed as part of this Annual Report or
incorporated by reference:

1. Financial Statements

See "Index to Consolidated Financial Statements" on page F-1
of this Annual Report.

2. Financial Statement Schedules

None. All financial statement schedules are omitted because
the information is not required, is not material or is
otherwise included in the consolidated financial statements or
notes thereto included elsewhere in this Annual Report.

3. (a) Exhibits

Item
Number Description

2.1 Agreement and Plan of Merger between Inland Resources
Inc. ("Inland"), IRI Acquisition Corp. and Lomax
Exploration Company (exclusive of all exhibits)
(filed as Exhibit 2.1 to Inland's Registration
Statement on Form S-4, Registration No. 33-80392, and
incorporated herein by this reference).

3.1 Amended and Restated Articles of Incorporation, as
amended through December 14, 1999 (filed as Exhibit
3.1 to Inland's Current Report on Form 8-K dated
September 21, 1999, and incorporated herein by
reference).

3.2 By-Laws of Inland (filed as Exhibit 3.2 to Inland's
Registration Statement on Form S-18, Registration No.
33-11870-F, and incorporated herein by reference).

3.2.1 Amendment to Article IV, Section 1 of the Bylaws of
Inland adopted February 23, 1993 (filed as Exhibit
3.2.1 to Inland's Annual Report on Form 10-K for the
year ended December 31, 1992, and incorporated herein
by reference).

3.2.2 Amendment to the Bylaws of Inland adopted April 8,
1994 (filed as Exhibit 3.2.2 to Inland's Registration
Statement on Form S-4, Registration No. 33-80392, and
incorporated herein by reference).

3.2.3 Amendment to the Bylaws of Inland adopted April 27,
1994 (filed as Exhibit 3.2.3 to Inland's Registration
Statement on Form S-4, Registration No. 33-80392, and
incorporated herein by reference).

*4.1 Third Amended and Restated Credit Agreement dated
November 30, 2001, between Inland Production Company
(as borrower), Inland Resources Inc.(as guarantor)
and Fortis Capital Corp. (as agent).

10.1 1988 Option Plan of Inland Gold and Silver Corp.
(filed as Exhibit 10(15) to Inland's Annual Report on
Form 10-K for the year ended December 31, 1988, and
incorporated herein by reference).

10.1.1 Amended 1988 Option Plan of Inland Gold and Silver
Corp. (filed as Exhibit 10.10.1 to Inland's Annual
Report on Form 10-K for the year ended December 31,
1992, and incorporated herein by reference).

10.1.2 Amended 1988 Option Plan of Inland, as amended
through August 29, 1994 (including amendments
increasing the number of shares to 212,800 and
changing "formula award") (filed as Exhibit 10.1.2 to
Inland's Annual Report on Form 10-KSB for the year
ended December 31, 1994, and (incorporated herein by
reference).

10.1.3 Automatic Adjustment to Number of Shares Covered by
Amended 1988 Option Plan executed effective June 3,
1996 (filed as Exhibit 10.1 to Inland's Quarterly
Report on Form 10-QSB for the quarter ended June 30,
1996, and incorporated herein by reference).

10.2 Letter agreement dated October 30, 1996 between
Inland and Johnson Water District (filed as Exhibit
10.41 to Inland's Annual Report on Form 10-KSB for
the year ended December 31, 1996, and incorporated
herein by reference).

10.4 Farmout Agreement between Inland and Smith Management
LLC dated effective as of June 1, 1998 (filed as
Exhibit 10.1 to Inland's Current Report on Form 8-K
dated June 1, 1998, and incorporated herein by
reference).

10.10 Employment Agreement between Inland and William T.
War dated effective as of October 1, 1999 (filed as
Exhibit 10.14 to Inland's Annual Report on Form 10-K
for the year ended December 31, 1999, and
incorporated herein by reference).

10.11 Stock Option Agreement between Inland and William T.
War dated October 1, 1999 representing 25,000
post-split shares of Common Stock (filed as Exhibit
10.15 to Inland's Annual Report on Form 10-K for the
year ended December 31, 1999, and incorporated herein
by reference).

10.12 Amendment to Employment Agreement between Inland and
William T. War, amending the Employment Agreement
filed as Exhibit 10.10.

10.13 Employment Agreement between Inland and Michael J.
Stevens dated effective as of February 1, 2001.

10.14 Employment Agreement between Inland and Marc MacAluso
dated effective as of February 1, 2001 and.

10.15 Stock Option Agreement between Inland and Marc
MacAluso dated effective as of February 1, 2001
representing 150,000 post-split shares of Common
Stock.

10.16 Employment Agreement between Inland and Bill I.
Pennington dated effective as of February 1, 2001
and.

10.17 Stock Option Agreement between Inland and Bill I.
Pennington dated effective as of February 1, 2001
representing 150,000 post-split shares of Common
Stock.

10.18 Oil Purchase and Delivery Agreement dated November 7,
2000.

10.19 Common Stock Purchase Agreement dated August 2, 2001
by and between Inland Holdings, LLC ("Inland
Holdings") and Hampton Investments LLC ("Hampton
Investments")(without exhibits or schedules)(filed as
Exhibit 10.1 to the Company's Current Report on Form
8-K dated August 2, 2001, and incorporated herein by
reference).

10.20 Contribution Agreement dated August 2, 2001 by and
among Park Hampton Holdings LLC ("Hampton Holdings"),
Pengo Securities Corp. ("Pengo"), Smith Energy
Partnership ("SEP"), the five individuals and Hampton
Investments (filed as Exhibit 10.2 to the Company's
Current Report on Form 8-K dated August 2, 2001, and
incorporated herein by reference).

10.21 Series E Preferred Stock Purchase Agreement dated as
of August 2, 2001 by and between Hampton Investments
and Inland Holdings (without exhibits or
schedules)(filed as Exhibit 10.3 to the Company's
Current Report on Form 8-K dated August 2, 2001, and
incorporated herein by reference).

10.22 Termination Agreement dated as of August 2, 2001 by
and between Hampton Investments and Inland (without
exhibits or schedules)(filed as Exhibit 10.4 to the
Company's Current Report on Form 8-K dated August 2,
2001, and incorporated herein by reference).

10.23 Exchange and Note Issuance Agreement dated August 2,
2001 by and among Inland, Production and Inland
Holdings (without exhibits or schedules)(filed as
Exhibit 10.5 to the Company's Current Report on Form
8-K dated August 2, 2001, and incorporated herein by
reference).

10.24 Termination Agreement dated as of August 2, 2001 by
and among Inland and Inland Holdings (without
exhibits or schedules)(filed as Exhibit 10.6 to the
Company's Current Report on Form 8-K dated August 2,
2001, and incorporated herein by reference).

10.25 Amended and Restated Registration Rights Agreement
dated as of August 2, 2001 by and among Inland,
Inland Holdings and Hampton Investments (without
exhibits or schedules)(filed as Exhibit 10.7 to the
Company's Current Report on Form 8-K dated August 2,
2001, and incorporated herein by reference).

10.26 Amended and Restated Shareholders Agreement dated as
of August 2, 2001 by and among Inland, Inland
Holdings and Hampton Investments (without exhibits or
schedules)(filed as Exhibit 10.8 to the Company's
Current Report on Form 8-K dated August 2, 2001, and
incorporated herein by reference).

10.27 Senior Subordinated Note Purchase Agreement dated as
of August 2, 2001 by and among Inland, Production and
SOLVation(without exhibits or schedules)(filed as
Exhibit 10.9 to the Company's Current Report on Form
8-K dated August 2, 2001, and incorporated herein by
reference).

10.28 Junior Subordinated Note Purchase Agreement dated as
of August 2, 2001 by and among Inland, Production and
SOLVation (without exhibits or schedules)(filed as
Exhibit 10.10 to the Company's Current Report on Form
8-K dated August 2, 2001, and incorporated herein by
reference).

10.29 Exchange and Stock Issuance Agreement dated as of
January 30, 2003, by and among Inland Resources Inc.,
Inland Production Company, Inland Holdings, LLC and
SOLVation, Inc., (filed as an exhibit to the
Company's Schedule 13E-3 dated February 5, 2003 and
incorporated herein by reference).

10.30 Form of Amendment No. 1 to Employment Agreement by
and between Marc MacAluso and Newco, attached as an
exhibit to the Exchange Agreement (filed as an
exhibit to the Company's Schedule 13E-3 dated
February 5, 2003 and incorporated herein by
reference).

10.31 Form of Amendment No. 1 to Employment Agreement by
and between Bill I. Pennington and Newco, attached as
an exhibit to the Exchange Agreement (filed as an
exhibit to the Company's Schedule 13E-3 dated
February 5, 2003 and incorporated herein by
reference).

10.32 Form of Second Amended and Restated Registration
Rights Agreement by and among Inland Resources Inc.,
Inland Holdings, LLC, Hampton Investments LLC and
SOLVation, Inc, attached as Exhibit E to the Exchange
Agreement (filed as an exhibit to the Company's
Schedule 13E-3 dated February 5, 2003 and
incorporated herein by reference).

10.33 Form of First Amendment to Senior Subordinated Note
Purchase Agreement, attached as an exhibit to the
Exchange Agreement (filed as an exhibit to the
Company's Schedule 13E-3 dated February 5, 2003 and
incorporated herein by reference).

10.34 Form of Development Agreement, attached as an exhibit
to the Exchange Agreement (filed as an exhibit to the
Company's Schedule 13E-3 dated February 5, 2003 and
incorporated herein by reference).

10.35 Investors' Agreement dated as of January 30, 2003
(the "Investors' Agreement"), by and among Newco,
Inland Holdings, LLC, Hampton Investments LLC and
SOLVation, Inc (filed as an exhibit to the Company's
Schedule 13E-3 dated February 5, 2003 and
incorporated herein by reference).

10.36 Fourth Amendment to Third Amended and Restated Credit
Agreement (filed as an exhibit to the Company's
Schedule 13E-3 dated February 5, 2003 and
incorporated herein by reference).

*21.1 Subsidiaries of Inland

*23.2 Consent of Ryder Scott Company, L.P.

*23.3 Consent of KPMG LLP

*99.1 Certification of Chief Executive Officer pursuant to
section 1350 as adopted pursuant to section 906 of
the Sarbanes-Oxley Act of 2002.

*99.2 Certification of Chief Financial Officer pursuant to
section 1350 as adopted pursuant to section 906 of
the Sarbanes-Oxley Act of 2002.

*99.3 Certification of Chief Executive Officer pursuant to
section 1350 as adopted pursuant to section 302 of
the Sarbanes-Oxley Act of 2002.

*99.4 Certification of Chief Financial Officer pursuant to
section 1350 as adopted pursuant to section 302 of
the Sarbanes-Oxley Act of 2002.

* Filed herewith

(b) Reports on Form 8-K

None.

[THIS SPACE INTENTIONALLY LEFT BLANK]

SIGNATURES

In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934,
Inland has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.

INLAND RESOURCES INC.
March 31, 2003
By: /s/ MARC MACALUSO
--------------------------------------
Marc MacAluso
Chief Executive Officer

POWER OF ATTORNEY

Each person whose signature appears below hereby appoints Bill I. Pennington as
his attorney-in-fact to sign on his behalf and in the capacity stated below and
to file all amendments to this Annual Report, which amendment or amendments may
make such changes and additions thereto as such attorney-in-fact may deem
necessary or appropriate.

<Table>

March 31, 2003 /s/ ARTHUR J. PASMAS
Arthur J. Pasmas
Chairman of the Board

March 31, 2003 /s/ MARC MACALUSO
Marc MacAluso
Director, Chief Executive Officer and
Chief Operating Officer (Principal
Executive Officer)

March 31, 2003 /s/ BILL I. PENNINGTON
Bill I. Pennington
Director, President and Chief Financial
Officer
(Principal Financial Officer)

March 31, 2003 /s/ BRUCE M. SCHNELWAR
Bruce M. Schnelwar
Director

March 31, 2003 /s/ DEWEY A. STRINGER III
Dewey A. Stringer III
Director
</Table>

INDEX TO FINANCIAL STATEMENTS

<Table>
<Caption>
Page
----

Independent Auditors' Report F-1
Report of Independent Public Accountants F-2
Consolidated Balance Sheets, December 31, 2002 and 2001 F-3
Consolidated Statements of Operations for the years ended
December 31, 2002, 2001 and 2000 F-5
Consolidated Statements of Stockholders' Deficit for the
years ended December 31, 2002, 2001 and 2000 F-7
Consolidated Statements of Cash Flows for the years ended
December 31, 2002, 2001 and 2000 F-8
Notes to Consolidated Financial Statements F-9
</Table>

INDEPENDENT AUDITORS' REPORT

The Board of Directors and Stockholders
Inland Resources Inc.:

We have audited the accompanying consolidated balance sheets of Inland Resources
Inc. (a Washington corporation) and subsidiaries as of December 31, 2002 and
2001, and the related consolidated statements of operations, stockholders'
deficit and cash flows for the years then ended. These consolidated financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits. The 2000 consolidated financial statements of
Inland Resources Inc. and subsidiaries as listed in the accompanying index were
audited by other auditors who have ceased operations. Those auditors expressed
an unqualified opinion on those consolidated financial statements in their
report dated March 26, 2002.

We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, the 2002 and 2001 consolidated financial statements referred to
above present fairly, in all material respects, the financial position of Inland
Resources Inc. and subsidiaries as of December 31, 2002 and 2001, and the
results of their operations and their cash flows for the years then ended in
conformity with accounting principles generally accepted in the United States of
America.

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.

As discussed in Note 1 to the consolidated financial statements, the Company
changed its method of accounting for derivative instruments and hedging
activities in 2001.

KPMG LLP

Denver, Colorado
March 14, 2003

F-1

THE FOLLOWING REPORT IS A COPY OF THE PREVIOUSLY ISSUED REPORT FROM ARTHUR
ANDERSEN LLP (ANDERSEN). ANDERSEN DID NOT PERFORM ANY PROCEDURES IN CONNECTION
WITH THIS ANNUAL REPORT ON FORM 10-K NOR HAS ANDERSEN PROVIDED A CONSENT TO THE
INCLUSION OF ITS REPORT IN THIS FORM 10-K. ACCORDINGLY, THIS REPORT HAS NOT BEEN
REISSUED BY ANDERSEN.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and Stockholders of
Inland Resources Inc.:

We have audited the accompanying consolidated balance sheets of Inland Resources
Inc. (a Washington corporation) and subsidiaries as of December 31, 2001 and
2000, and the related consolidated statements of operations, stockholders'
deficit and cash flows for each of the three years in the period ended December
31, 2001. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Inland Resources Inc. and
subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.

As explained in Note 3 to the consolidated financial statements, the Company
changed its method of accounting for derivative instruments and hedging
activities on January 1, 2001.

/s/ ARTHUR ANDERSEN LLP

Denver, Colorado,
March 26, 2002

F-2

Page 1 of 2

INLAND RESOURCES INC.

CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)

<Table>
<Caption>
December 31,
ASSETS 2002 2001
---------- ----------

CURRENT ASSETS:
Cash and cash equivalents $ 1,525 $ 1,949
Accounts receivable and accrued sales 3,351 3,320
Inventory 1,088 1,192
Other current assets 510 443
---------- ----------
Total current assets 6,474 6,904
---------- ----------
PROPERTY AND EQUIPMENT, AT COST:
Oil and gas properties (successful efforts method) 217,961 205,535
Accumulated depletion, depreciation and amortization (51,627) (43,510)
---------- ----------
Total oil and gas properties, net 166,334 162,025

Other property and equipment, net 2,737 2,230
---------- ----------
Total property and equipment, net 169,071 164,255

OTHER LONG-TERM ASSETS 1,671 2,217
---------- ----------
Total assets $ 177,216 $ 173,376
========== ==========
</Table>

The accompanying notes are an integral part of
the consolidated balance sheets.

F-3

Page 2 of 2

INLAND RESOURCES INC.

CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)

<Table>
<Caption>
December 31,
LIABILITIES AND STOCKHOLDERS' DEFICIT 2002 2001
---------- ----------

CURRENT LIABILITIES:
Accounts payable $ 3,614 $ 4,011
Accrued expenses 3,180 2,321
Senior secured debt 83,500 83,500
Other notes payable 1,388 --
Senior subordinated unsecured debt including accrued interest 5,828 5,228
Subordinated unsecured debt including accrued interest 115,362 103,500
Junior subordinated unsecured debt including accrued interest 5,828 5,228
Fair value of derivative instruments 1,555 --
---------- ----------
Total current liabilities 220,255 203,788

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS' DEFICIT:
Common stock, par value $.001; 25,000,000 shares authorized,
2,897,732 issued and outstanding 3 3
Additional paid-in capital 41,431 41,431
Accumulated other comprehensive income (loss) (1,324) 1,675
Accumulated deficit (83,149) (73,521)
---------- ----------
Total stockholders' deficit (43,039) (30,412)
---------- ----------
Total liabilities and stockholders' deficit $ 177,216 $ 173,376
========== ==========
</Table>

The accompanying notes are an integral part of
the consolidated balance sheets.

F-4

Page 1 of 2

INLAND RESOURCES INC.

CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands)

<Table>
<Caption>
For the Years Ended December 31,
--------------------------------------
2002 2001 2000
---------- ---------- ----------

REVENUES:
Oil and gas sales $ 29,878 $ 31,967 $ 28,497

OPERATING EXPENSES:
Lease operating expenses 10,935 9,344 7,596
Production taxes 357 479 483
Exploration 136 143 135
Depletion, depreciation and amortization 8,756 9,106 7,816
General and administrative, net 1,199 1,486 2,128
---------- ---------- ----------
Total operating expenses 21,383 20,558 18,158
---------- ---------- ----------
OPERATING INCOME 8,495 11,409 10,339
OTHER INCOME (EXPENSE):
Interest expense (18,227) (12,031) (8,298)
Unrealized derivative loss -- (2,200) --
Interest and other income 104 626 103
---------- ---------- ----------
NET INCOME (LOSS) FROM CONTINUING OPERATIONS (9,628) (2,196) 2,144

LOSS ON SALE OF DISCONTINUED OPERATIONS -- -- (250)
---------- ---------- ----------
NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT
OF CHANGE IN ACCOUNTING PRINCIPLE (9,628) (2,196) 1,894

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE -- 45 --
---------- ---------- ----------
NET INCOME (LOSS): (9,628) (2,151) 1,894
Accrued Preferred Series D dividends -- (6,342) (9,732)
Accrued Preferred Series E dividends -- (980) (1,506)
Accretion of Preferred Series D discount -- (3,318) (6,300)
Accretion of Preferred Series E discount -- (535) (900)
Excess carrying value of preferred stock over
redemption consideration -- 1,449 --
---------- ---------- ----------
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS $ (9,628) $ (11,877) $ (16,544)
========== ========== ==========
</Table>

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

F-5

Page 2 of 2

INLAND RESOURCES INC.

CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)

<Table>
<Caption>
For the Years Ended December 31,
--------------------------------------
2002 2001 2000
---------- ---------- ----------

NET INCOME (LOSS) $ (9,628) $ (2,151) $ 1,894

BASIC AND DILUTED NET LOSS PER SHARE:
Continuing operations $ (3.32) $ (4.11) $ (5.62)
Loss on sale of discontinued operations -- -- (0.09)
Cumulative effect of change in accounting principle -- 0.02 --
---------- ---------- ----------
BASIC AND DILUTED NET LOSS PER SHARE $ (3.32) $ (4.09) $ (5.71)
========== ========== ==========

BASIC AND DILUTED WEIGHTED AVERAGE
COMMON SHARES OUTSTANDING 2,898 2,898 2,898
========== ========== ==========
</Table>

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

F-6

INLAND RESOURCES INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' DEFICIT
(In thousands)

<Table>
<Caption>
Accumulated
Additional Other
Common Stock Paid-In Accumulated Comprehensive Stockholders
Shares Amount Capital Deficit Income Deficit
------ ------ ---------- ----------- ------------- ------------

BALANCES, December 31, 1999 2,898 $ 3 $ 69,595 $ (73,264) $ -- $ (3,666)

Accretion of Preferred Series D discount -- -- (6,300) -- -- (6,300)
Accretion of Preferred Series E discount -- -- (900) -- -- (900)
Accrued Preferred Series D dividends -- -- (9,732) -- -- (9,732)
Accrued Preferred Series E dividends -- -- (1,506) -- -- (1,506)
Net income -- -- -- 1,894 -- 1,894
------ ------ ---------- ----------- ------------- ------------
BALANCES, December 31, 2000 2,898 3 51,157 (71,370) -- (20,210)
Accretion of Preferred Series D discount -- -- (3,318) -- -- (3,318)
Accretion of Preferred Series E discount -- -- (535) -- -- (535)
Accrued Preferred Series D dividends -- -- (6,342) -- -- (6,342)
Accrued Preferred Series E dividends -- -- (980) -- -- (980)
Excess carrying value of preferred over
redemption consideration -- -- 1,449 -- -- 1,449
Comprehensive income (loss):
Net loss -- -- -- (2,151) -- (2,151)
Cumulative effect of change in accounting
principle -- -- -- -- (1,972) (1,972)
Changes in fair value of derivative contracts -- -- -- -- 1,186 1,186
Derivative contract settlements reclassified
to income -- -- -- -- 2,461 2,461
------------
Total comprehensive loss (476)
------ ------ ---------- ----------- ------------- ------------
BALANCES, December 31, 2001 2,898 3 41,431 (73,521) 1,675 (30,412)
Comprehensive income (loss):
Net loss -- -- -- (9,628) -- (9,628)
Changes in fair value of derivative contracts -- -- -- -- (3,219) (3,219)
Derivative contract settlements reclassified
to income -- -- -- -- 220 220
------------
Total comprehensive loss (12,627)
------ ------ ---------- ----------- ------------- ------------
BALANCES, December 31, 2002 2,898 $ 3 $ 41,431 $ (83,149) $ (1,324) $ (43,039)
====== ====== ========== =========== ============= ============
</Table>

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

F-7

INLAND RESOURCES INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(See Note 9)
(In thousands)

<Table>
<Caption>
For the Years Ended December 31,
--------------------------------------
2002 2001 2000
---------- ---------- ----------

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (9,628) $ (2,151) $ 1,894
Adjustments to reconcile net income (loss) to net cash
provided by operating activities
Depletion, depreciation and amortization 8,756 9,106 7,816
Amortization of debt issuance costs and debt discount 588 615 480
Loss on disposition of assets 32 -- 51
Non cash (income) charges related to derivatives (1,444) 1,720 --
Interest expense converted into debt 13,062 4,987 --
Effect of changes in assets and liabilities-
Cumulative effect of change in accounting principle -- (45) --
Loss on sale of discontinued operations -- -- 250
Accounts receivable and accrued sales (31) 1,964 (3,118)
Inventory 104 (357) 452
Other assets (25) 24 (184)
Accounts payable and accrued expenses 462 800 351
---------- ---------- ----------
Net cash provided by operating activities 11,876 16,663 7,992
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Development expenditures and equipment purchases (13,605) (22,289) (14,137)
---------- ---------- ----------
Net cash used by investing activities (13,605) (22,289) (14,137)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt 1,388 10,000 4,585
Retirement of preferred stock -- (2,000) --
Debt issuance costs (83) (1,273) (500)
---------- ---------- ----------
Net cash provided by financing activities 1,305 6,727 4,085
---------- ---------- ----------
NET CASH AND CASH EQUIVALENTS PROVIDED (USED)
BY CONTINUING OPERATIONS (424) 1,101 (2,060)

NET CASH AND CASH EQUIVALENTS PROVIDED
BY DISCONTINUED OPERATIONS -- -- 1,890

CASH AND CASH EQUIVALENTS, at beginning of period 1,949 848 1,018
---------- ---------- ----------
CASH AND CASH EQUIVALENTS, at end of period $ 1,525 $ 1,949 $ 848
========== ========== ==========
</Table>

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

F-8

INLAND RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2002

----------

1. BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Business

Inland Resources Inc. ("Inland" or the "Company") is an independent energy
company with all of its producing oil and gas property interests located in the
Monument Butte Field (the "Field") within the Uinta Basin of Northeastern Utah.
During the period from December 31, 1997 to January 31, 2000, the Company also
operated a crude oil refinery located in Woods Cross, Utah (the "Woods Cross
Refinery"). On December 10, 1999, the Company's board of directors voted to sell
the Woods Cross Refinery operations and a nonoperating refinery pursuant to a
plan of dissolution. The sale of the Woods Cross Refinery and the nonoperating
refinery closed on January 31, 2000. Certain current assets were excluded from
the sale and were also liquidated in 2000 pursuant to the plan of dissolution.

Consolidation

The accompanying consolidated financial statements include the accounts of the
Company and its subsidiaries, all of which are wholly-owned. All significant
intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America, requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Oil and gas prices have a significant influence on estimates made by management.
Changes in oil and gas prices and production rates directly affect the economics
of estimated oil and gas reserves. These economics have significant effects upon
predicted reserve quantities and valuations. These estimates are the basis for
the calculation of depletion, depreciation and amortization of the Company's oil
and gas properties and whether an assessment of impairment is required.
Forecasted oil and gas pricing estimates factor into estimated future cash flow
projections used in assessing impairment for the oil and gas properties.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and amounts due from banks and
other investments with original maturities of less than three months.

Concentrations of Credit Risk

The Company regularly has cash held by a single financial institution that
exceeds depository insurance limits. The Company places such deposits with
institutions that management believes are of high credit quality. The Company
has not experienced any credit losses. Substantially all of the Company's

F-9

receivables are within the oil and gas industry, primarily from its oil and gas
purchasers and joint interest owners. Although diversified with many companies,
collectibility is dependent upon the general economic conditions of the
industry.

Fair Value of Financial Instruments

The Company's financial instruments consist of cash, trade receivables, trade
payables, accrued liabilities, long-term debt and derivative instruments. The
carrying value of cash and cash equivalents, trade receivables and trade
payables are considered to be representative of their fair market value, due to
the short maturity of these instruments. The fair value of variable interest
rate long-term debt approximates fair value. The fixed rate debt is unique to
the Company, as such, the fair value is not readily determinable. The estimated
fair value of derivative contracts are estimated based on market conditions in
effect at the end of each reporting period.

Inventories

Inventories consist of tubular goods valued at the lower of average cost or
market. Materials and supplies inventories are stated at cost and are charged to
capital or expense, as appropriate, when used.

Accounting for Oil and Gas Operations

The Company follows the successful efforts method of accounting for oil and gas
operations. The use of this method results in the capitalization of those costs
associated with the acquisition, exploration and development of properties that
produce revenue or are anticipated to produce future revenue. The Company does
not capitalize general and administrative expenses directly identifiable with
such activities or lease operating expenses associated with secondary recovery
startup projects. Costs of unsuccessful exploration efforts are expensed in the
period it is determined that such costs are not recoverable through future
revenues. Geological and geophysical costs are expensed as incurred. The cost of
development wells are capitalized whether productive or nonproductive. Upon the
sale of proved properties, the cost and accumulated depletion are removed from
the accounts. Any gain or loss is recorded in the results of operations.
Interest is capitalized during the drilling and completion period of wells and
on other major projects.

The provision for depletion, depreciation and amortization of developed oil and
gas properties is based on the units of production method. This method utilizes
proved oil and gas reserves determined using market prices at the end of each
reporting period. Dismantlement, restoration and abandonment costs have
historically been, in management's opinion, offset by residual values of lease
and well equipment. As a result, no accrual for such costs has been provided.
SFAS No. 143, "Accounting for Asset Retirement Obligations" discussed later in
this note, will require the fair value of such costs to be recorded effective
January 1, 2003.

Impairment Review

The Company reviews and evaluates its long-lived assets for impairment when
events or changes in circumstances indicate that the related carrying amounts
may not be recoverable. An impairment loss is measured as the amount by which
asset carrying value exceeds fair value. A calculation of the aggregate
before-tax undiscounted future net revenues is performed for the Company's oil
and gas properties. The Company utilizes an estimated price scenario based on
its budget and future estimates of oil and gas prices from industry projections
and quoted futures prices. The assumptions used at December 31, 2002 were based
on an average oil price of $28.20 per barrel and $2.96 per Mcf over the
remaining estimated life of the properties.

F-10

The Company also periodically assesses unproved oil and gas properties for
impairment. Impairment represents management's estimate of the decline in
realizable value experienced during the period for leases not expected to be
utilized by the Company.

In August 2001, SFAS No. 144 "Accounting for the Impairment or Disposal of
Long-Lived Assets" was issued. The statement established a single accounting
model, based on the framework of SFAS No. 121 ("Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of"), for long-lived
assets to be disposed of by sale. Adoption of the statement on January 1, 2002
had no material impact on the Company's financial position or results of
operations.

Property and Equipment

Property and equipment is recorded at cost. Replacements and major improvements
are capitalized, while maintenance and repairs are charged to expense as
incurred. Upon sale or retirement, the asset cost and accumulated depreciation
are removed from the accounts and any resulting gain or loss is reflected in
operations. Depreciation is calculated using the straight-line method over the
estimated useful lives of the related assets, generally ranging from three to
thirty years. Maintenance and repairs are expensed as incurred. Major
improvements are capitalized and the assets replaced are retired.

Income Taxes

The Company uses the liability method of accounting for income taxes. Under the
liability method, deferred income taxes are recorded for differences between the
book and tax basis of assets and liabilities at tax rates in effect when the
balances are expected to reverse. A valuation allowance against deferred tax
assets is recorded when the conclusion by Company management is reached, based
on available evidence, that the tax benefits are not expected to be realized.

Revenue Recognition

Sales of crude oil and natural gas are recorded upon delivery to purchasers. 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 of the related
revenue.

Loss Per Share

Net loss per share is presented for basic and diluted net loss and, if
applicable, for net loss from discontinued operations and extraordinary losses.
Basic earnings per share is computed by dividing net loss attributable to common
stockholders by the weighted-average number of common shares for the period. The
computation of diluted earnings per share includes the effects of additional
common shares that would have been outstanding if potentially dilutive common
shares had been issued. As the Company was in a net loss available to common
stockholders position for each of the periods presented, all outstanding options
were considered antidilutive.

Comprehensive Income (Loss)

In addition to net income (loss), comprehensive loss includes all changes in
equity during a period, except those resulting from investments by and
distributions to owners. Beginning January 1, 2001, with the adoption of SFAS
No. 133, the portion of changes in fair value of derivative instruments that
qualify for cash flow hedges is included in accumulated comprehensive income
(loss).

F-11

Stock-Based Compensation

The Company has elected to account for stock options and warrants granted to
employees and non-employee directors of the Company under APB Opinion No. 25 and
its interpretations. If compensation expense for grants of stock options and
warrants had been determined consistent with SFAS No. 123, "Accounting for
Stock-Based Compensation," the Company's net loss and loss per share ("LPS")
would have been the following pro forma amounts (in thousands, except per share
data):

<Table>
<Caption>
2002 2001 2000
---------- ---------- ----------

Net loss, attributable to common stockholders:
As reported $ (9,628) $ (11,877) $ (16,544)
Pro forma (9,920) (12,225) (16,991)
Basic and Diluted LPS:
As reported $ (3.32) $ (4.09) $ (5.71)
Pro forma (3.42) (4.22) (5.86)
</Table>

Recently Issued 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 also changes the treatment of
goodwill created in a business combination to discontinue amortization of
goodwill. The adoption of these two statements did not have an impact on the
Company's financial position or results of operations.

SFAS No. 143, "Accounting for Asset Retirement Obligations," requires entities
to record the fair value of a liability for an asset retirement obligation in
the period in which it is incurred and a corresponding increase in the carrying
amount of the related long-lived asset. The Company will be required to adopt
SFAS No. 143 effective January 1, 2003. Upon adoption of SFAS No. 143 the
Company expects to record an asset retirement obligation liability of $2.7
million, an increase to net properties and equipment of $1.6 million, and an
after tax charge of $1 million as a cumulative effect of a change in accounting
principle.

In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets". SFAS No. 144 supersedes SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of". SFAS No. 121 did not address the accounting for a segment of a
business accounted for as a discontinued operation which resulted in two
accounting models for long-lived assets to be disposed of. SFAS No. 144
establishes a single accounting model for long-lived assets to be disposed of by
sale and requires that those long-lived assets be measured at the lower of
carrying amount or fair value less cost to sell, whether reported in continuing
operations or in discontinued operations. SFAS No. 144 is effective for fiscal
years beginning after December 15, 2001. The Company's adoption of SFAS No. 144
on January 1, 2002, had no impact on its financial position or results of
operations.

In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities". SFAS No. 146 is to be applied prospectively
to exit or disposal activities initiated after December 31, 2002. The standard
requires companies to recognize costs associated with exit or disposal
activities when they are incurred rather than at the date of a commitment to an
exit or disposal plan. Examples of costs covered by the standard include lease
termination costs and certain employee severance costs that are associated with
a restructuring, discontinued operation, plant closing or other exit or disposal
activity. Management does not expect the adoption of SFAS No. 146 to have a
material impact on the financial position or results of operations of the
Company.

F-12

FASB Interpretation 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantee of Indebtedness of Others," was issued
in November 2002. FIN 45 requires that upon issuance of a guarantee, the
guarantor must recognize a liability for the fair value of the obligation it
assumes under that guarantee. FIN 45's provisions for initial recognition and
measurement should be applied on a prospective basis to guarantees issued or
modified after December 31, 2002. The guarantor's previous accounting for
guarantees that were issued before the date of FIN 45's initial application may
not be revised or restated to reflect the effect of the recognition and
measurement provisions of the interpretation. The disclosure requirements are
effective for financial statements of both interim and annual periods that end
after December 15, 2002. The Company is not a guarantor under any significant
guarantees and thus this interpretation is not expected to have a significant
effect on its financial position or results of operations.

FASB Interpretation 46, "Consolidation of Variable Interest Entities, An
Interpretation of ARB 51," was issued in January 2003. The primary objectives of
FIN 46 are to provide guidance on how to identify entities for which control is
achieved through means other than through voting rights (variable interest
entities or VIEs) and how to determine when and which business enterprise should
consolidate the VIE. This new model for consolidation applies to an entity in
which either (1) the equity investors do not have a controlling financial
interest or (2) the equity investment at risk is insufficient to finance that
entity's activities without receiving additional subordinated financial support
from other parties. The Company does not expect the adoption of this standard to
have any impact on its financial position or results of operations.

Reclassifications

Certain amounts in prior years have been reclassified to conform to the 2002
presentation.

2. FINANCIAL INSTRUMENTS:

SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities"
("SFAS No. 133") was issued in June 1998. This statement establishes accounting
and reporting standards for derivative instruments and hedging activity. SFAS
No. 133 requires recognition of all derivative instruments on the balance sheet
as either assets or liabilities measured at fair value. Changes in the
derivative's fair value are recognized currently in earnings unless specific
hedge accounting criteria are met. Gains and losses on derivative hedging
instruments must be recorded in either other comprehensive income or current
earnings, depending on the nature and designation of the instrument.

F-13

In 2001 and prior years, the Company entered into certain commodity derivative
contracts with Enron North America Corp. ("ENAC"), a subsidiary of Enron Corp.
("Enron"). 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 $2.155 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 $2.155 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, as an increase 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.

Crude Oil Hedging Activities

As mentioned above, the Company terminated all of its hedging contracts with
ENAC on January 30, 2002 for the years 2002 and 2003. During 2001, the Company
hedged 990,000 net barrels of crude oil production under various collars and
swaps from ENAC. The Company recorded a reduction of revenue of $2.9 million
under these contracts upon settlement in 2001. During 2000, the Company hedged
720,000 net barrels of crude oil production under various collars from ENAC. The
Company recorded a reduction of revenue of $6.1 million in 2000 under these
contracts.

On March 11, 2002, the Company hedged 30,000 net barrels per month with Shell
Trading Company ("Shell") for the April 2002 to December 2002 period using a
swap with a settlement amount of $23.90 per barrel. On various dates between
March and August of 2002, the Company hedged a total of 60,000 net barrels per
month for the January 2003 to August 2003 period with Shell using a swap with
various settlement amounts that average $24.78 per barrel. Shell has the right
to require the Company to post collateral for the difference between the mid
market estimate of the cost of liquidating and terminating the hedging positions
and a "credit margin" of $500,000. As of December 31, 2002, Fortis Capital Corp.
had issued a letter of credit to Shell on the Company's behalf in the amount of
$1.4 million to cover any deficiencies between the $500,000 credit margin and
the mid market estimate from Shell.

On January 16, 2003, the Company hedged 60,000 net barrels per month with Shell
for the September 2003 to December 2003 period using a swap with a settlement
amount of $25.63 per barrel. On February 26, 2003, the Company hedged another
40,000 net barrels per month with Shell for the January 2004 to December 2004
period using a various swaps with an average settlement amount of $25.25 per
barrel. On February 27, 2003 Shell increased the Company's credit margin from
$500,000 to $1,500,000. On March 18, 2003, Fortis Capital Corp. issued a letter
of credit totaling $3 million (in replacement of the $1.4 million letter of
credit) to cover any deficiencies between the $1,500,000 credit margin and the
mid market estimate from Shell.

On April 8, 2002, the Company hedged 30,000 net barrels per month with Big West
Oil Company ("Big West") for the May 2002 to December 2002 period using a swap
with a settlement amount of $24.90 per barrel. On January 27, 2003, the Company
hedged 30,000 net barrels per month with Big West for the January 2004 to
December 2004 period using various swaps with an average settlement amount of
$23.95 per barrel. On February 18, 2003, the Company hedged another 10,000 net
barrels per month with Big West for the January 2004 to December 2004 period
using a swap with an average settlement amount of $24.90 per barrel. Big West
has the right to require the Company to post collateral for the difference
between the mid market estimate of the cost of liquidating and terminating the
above mentioned hedging position and $1,000,000.

F-14

The Company recognized a reduction in revenues of $1,664,000 during the year
ended December 31, 2002 under these Shell and Big West contracts upon
settlement. Unrealized losses of $1,324,000 at December 31, 2002 have been
deferred as a component of accumulated other comprehensive income.

3. LOSS PER SHARE:

The calculation of loss per share for the years ended December 31, 2002, 2001
and 2000 is as follows (in thousands, except per share data):

<Table>
<Caption>
2002 2001 2000
--------------------------- --------------------------- ---------------------------
Income Per Share Income Per Share Income Per Share
(Loss) Shares Amount (Loss) Shares Amount (Loss) Shares Amount
------- ------ --------- ------- ------ --------- ------- ------ ---------

Income (loss) from continuing
operations $(9,628) $(2,196) $ 2,144
Accrued Preferred Series D dividends -- (6,342) (9,732)
Accrued Preferred Series E dividends -- (980) (1,506)
Accretion of Series D discount -- (3,318) (6,300)
Accretion of Series E discount -- (535) (900)
Excess carrying value of Preferred
over redemption consideration -- 1,449 --
------- ------- -------
BASIC AND DILUTED LOSS
PER SHARE:
Loss from continuing operations
attributable to common
stockholders $(9,628) 2,898 $ (3.32) $(11,922) 2,898 $ (4.11) $(16,294) 2,898 $ (5.62)
======= ========= ======== ========= ======== =========
</Table>

4. RESTRUCTURING TRANSACTIONS:

1999 Exchange Agreement

On September 21, 1999, the Company entered into an Exchange Agreement (the
"Exchange Agreement") with Trust Company of the West and affiliated entities
("TCW" or "Holdings") and Joint Energy Development Investments II Limited
Partnership ("JEDI") pursuant to which TCW agreed to exchange certain
indebtedness and warrants to purchase Common Stock, for shares of Common Stock
and two new series of Preferred Stock of the Company, and JEDI agreed to
exchange 100,000 shares of Series C Preferred Stock of the Company for shares of
Common Stock and a third new series of Preferred Stock of the Company. Pursuant
to the Exchange Agreement, TCW agreed to exchange $75 million of subordinated
indebtedness plus accrued interest of $5.7 million and warrants to purchase
15,852 shares of Common Stock for the following securities of the Company: (i)
10,757,747 shares of newly designated Series D Redeemable Preferred Stock of the
Company ("Series D Preferred Stock"), (ii) 5,882,901 shares of newly designated
Series Z Convertible Preferred Stock of the Company ("Series Z Preferred Stock")
and (3) 1,164,295 shares of Common Stock. On December 14, 1999 all shares of
Series D Preferred Stock were converted into 588,291 shares of Common Stock. In
addition, JEDI agreed to exchange the 100,000 shares of the Company's Series C
Cumulative Convertible Preferred Stock ("Series C Preferred Stock") owned by
JEDI, together with $2.2 million of accumulated dividends thereon, for (i)
121,973 shares of newly designated Series E Redeemable Preferred Stock of the
Company ("Series E Preferred Stock") and (ii) 292,098 shares of Common Stock.

The Series D Preferred Stock accrued dividends at a rate of $0.16875 per share
per quarter (9% annual rate) if paid in cash on a current basis or $0.2109375
per share per quarter (11.25% annual rate compounded quarterly) if accumulated
and not paid on a current basis. No dividends were paid on Common Stock or any
other series of preferred stock as there were accrued and unpaid dividends on
the Series D Preferred Stock. The Series D Preferred Stock also had liquidation
preference over all other classes and series of stock, in an amount equal to
$7.50 per share ($80.7 million). The difference between

F-15

the book value and the liquidation value of the Series D Preferred Stock at the
exchange date ($20.2 million) was being accreted over the minimum redemption
period beginning on April 1, 2002, and resulted in a charge against earnings
available for common stockholders until it was exchanged on August 2, 2001 as
discussed below.

The Series E Preferred Stock accrued dividends at a rate of $2.3125 per share
per quarter (9.25% annual rate) if paid in cash on a current basis or $2.875 per
share per quarter (11.5% annual rate compounded quarterly) if accumulated and
not paid on a current basis. No dividends were paid on Common Stock as there
were accrued and unpaid dividends on the Series E Preferred Stock. The Series E
Preferred Stock also had liquidation preference over all other classes and
series of stock, except the Series D Preferred Stock, in an amount equal to
$100.00 per share ($12.2 million). The difference between the book value and the
liquidation value of the Series E Preferred Stock at the exchange date ($4.2
million) was being accreted over the minimum redemption period to April 1, 2004,
and resulted in a charge against earnings available for common stockholders
until exchanged on August 2, 2001, as discussed below.

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 Company also issued a $5 million unsecured junior subordinated note to
Pengo. 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
shares of the Series D Preferred Stock and Series E Preferred Stock held by
Holdings were exchanged for an unsecured subordinated note (the "TCW
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. 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 Preferred Stock 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 carrying value of the Series D Preferred Stock and Series E Preferred
Stock plus accrued dividends was recorded as an increase to additional paid-in
capital of $1,449,000.

F-16

As part of this restructuring, Holdings also sold to Hampton, 1,455,390 shares
of the Company's Common Stock. 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 Board of
Directors and elected 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.

5. DISCONTINUED OPERATIONS:

Pursuant to a decision by the Company's Board of Directors on December 10, 1999
to dispose of the Company's refinery operations, 100% of the stock in Inland
Refining, Inc., a wholly owned subsidiary, was sold on January 31, 2000 to
Silver Eagle Refining, Inc. ("Silver Eagle"). This subsidiary owned the Woods
Cross Refinery and a nonoperating refinery located in Roosevelt, Utah. The sales
price was $500,000 together with the assumption by Silver Eagle of refinery
assets, liabilities and obligations including all environmental related
liabilities. Prior to the sale, the Company transferred the existing inventory,
cash, accounts receivable and a note receivable to another wholly-owned
subsidiary of the Company. This subsidiary also agreed to satisfy various
accounts payable and accrued liabilities not assumed by Silver Eagle. These
assets and liabilities were disposed of during 2000.

As a result of 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. In 2000 the Company recorded a loss of $250,000 to reflect
adjustments to the final disposal costs associated with the refinery.

6. OTHER PROPERTY AND EQUIPMENT:

<Table>
<Caption>
December 31,
--------------------
2002 2001
-------- --------
(in thousands)
Estimated
Useful Lives
------------

Vehicles 4 Years $ 1,788 $ 1,554
Drilling rig 7 years 716 --
Buildings 20-30 Years 980 1,013
Furniture and fixtures 5 Years 1,260 1,326
Leasehold improvements 5 Years 112 86
Land 36 36
-------- --------
4,892 4,015
Less: accumulated depreciation (2,155) (1,785)
-------- --------
Total $ 2,737 $ 2,230
======== ========
</Table>

7. LONG-TERM DEBT (See Note 4):

Fortis Credit Agreement

Effective September 21, 1999, the Company entered into a credit agreement (the
"Fortis Credit Agreement") whose current participants are Fortis Capital Corp.
and U.S. Bank National Association (the "Senior Lenders").

F-17

In conjunction with the August 2, 2001 Pengo financing, the Senior Lenders
amended the Fortis Credit Agreement 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 London Interbank Offering Rate ("LIBOR") rate. The LIBOR rates are
determined based on the senior debt to EBITDA. 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 a weighted average interest rate of 5.20%. 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 borrowing base is calculated
as the collateral value of the Company's proved reserves. The borrowing base is
subject to ongoing redeterminations each October 1 and April 1. The April 1,
2002 determination was received on March 26, 2002 and the borrowing base was set
at $83.5 million. If the borrowing base is lower than the outstanding principal
balance then drawn, the Company must immediately pay the difference. However,
further redeterminations subsequent to April 1, 2003 have not been required by
the Senior Lenders pending closure of the refinancing discussed in Note 14. The
Fortis Credit Agreement is secured by a first lien on substantially all assets
of the Company. At December 31, 2002, the Company had been advanced all funds
under its current borrowing base of $83.5 million.

As of March 31, 2002, the Company was not in compliance with the senior debt to
EBITDA ratio. On June 6, 2002, the senior lenders waived compliance with the
debt to EBITDA ratio related to March 31, 2002. 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 as of December
31, 2002. 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 covenants, 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
agreements contain cross default provisions, the Company has classified its
subordinated debt as of December 31, 2002, aggregating $127 million, as a
current liability.

Subordinated Unsecured Debt to Pengo Securities Corp.

As discussed in Note 4, 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.

The Company also issued a $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

F-18

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.

Subordinated Unsecured Debt to TCW

As discussed in Note 4, 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 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.

Custom Energy Note Payable

During 2002, the Company contracted Custom Energy Construction, Inc. ("Custom")
for the installation of a gas liquids processing facility located in the Field.
The total cost of the facility was $1.4 million, which is financed through a
non-recourse promissory note with Custom. Principal and interest payments at 7%
per annum are made from hydrocarbon liquid proceeds generated by the plant over
a 5-year period. As of December 31, 2002, the amount due to Custom is $994,000.
Completion of the gas plant and operations started in September 2002. Custom's
collateral for the promissory note is a first lien on the plant.

A summary of the Company's debt (including accrued unpaid interest) follows (in
thousands):

<Table>
<Caption>
December 31,
-------------------
2002 2001
-------- --------

Fortis Credit Agreement $ 83,500 $ 83,500
Senior Subordinated Unsecured Debt including accrued interest 5,828 5,228
Subordinated Unsecured Debt including accrued interest 115,362 103,500
Junior Subordinated Unsecured Debt including accrued interest 5,828 5,228
Custom Energy Note Payable 994 --
Other 394 --
-------- --------
Total long-term debt $211,906 $197,456
======== ========
</Table>

As a result of defaults under the Fortis Credit Agreement and cross default
provisions in the Company's other debt agreements, all long term debt at
December 31, 2002 and 2001 has been classified as current.

F-19

8. INCOME TAXES:

In 2002, 2001 and 2000, no income tax provision or benefit was recognized due to
the effect of net operating losses and the recording of a valuation allowance
against portions of the deferred tax assets that did not meet the utilization
criteria of more likely than not. Deferred income taxes reflect the impact of
temporary differences between amounts of assets and liabilities for financial
reporting purposes and such amounts as measured by tax laws. The tax effect of
the temporary differences and carryforwards giving rise to the Company's
deferred tax assets and liabilities at December 31, 2002 and 2001 is as follows
(in thousands):

<Table>
<Caption>
December 31, December 31,
2002 2001
------------ ------------

Deferred tax assets:
Net operating loss carryforwards $ 38,965 $ 32,158
Other 350 625
Valuation allowance (24,288) (20,181)
------------ ------------
Deferred tax assets 15,027 12,602
------------ ------------
Deferred tax liabilities:
Depletion, depreciation and amortization
of property and equipment (15,027) (12,602)
------------ ------------
Deferred tax liabilities (15,027) (12,602)
------------ ------------
Net deferred tax assets $ -- $ --
============ ============
</Table>

A valuation allowance is to be provided if it is more likely than not that some
portion or all of a deferred tax asset will not be realized. The Company's
ability to realize the benefit of its tax assets depends on the generation of
future taxable income through profitable operations and expansion of the
Company's oil and gas producing properties. The market, capital and
environmental risks associated with that growth requirement caused the Company
to conclude that a valuation allowance should be provided, except to the extent
that the benefit of operating loss carryforwards can be used to offset future
reversals of existing deferred tax liabilities. The Company will continue to
monitor the need for the valuation allowance that has been provided.

Income tax (benefit) expense for 2002, 2001 and 2000 differed from amounts
computed by applying the statutory federal income tax rate as follows (in
thousands):

<Table>
<Caption>
For the Year December 31,
--------------------------------
2002 2001 2000
-------- -------- --------

Expected statutory income tax (benefit)
expense at 34% $ (3,274) $ (731) $ 644
State income taxes, net of Federal
impact (318) (71) 62
Change in valuation allowance, net 4,107 784 (492)
Other (515) 18 (214)
-------- -------- --------
Net income tax (benefit)
expense $ -- $ -- $ --
======== ======== ========
</Table>

F-20

No state or federal income taxes are payable at December 31, 2002 or 2001, and
the Company did not pay any income taxes in 2002, 2001 or 2000. At December 31,
2002, the Company had tax basis net operating loss carryforwards available to
offset future regular and alternative taxable income of $104 million that expire
from 2004 to 2022. Utilization of the net operating loss carryforwards are
limited under the change of ownership tax rules.

9. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

Cash paid for interest during 2002, 2001 and 2000 was approximately $4,576,000,
$6,428,000 and $7,857,000, respectively.

As a result of the restructuring discussed in Note 4, the Company converted
Preferred Stock to debt in the amount of $98,968,964, during 2001.

In 2000, the Company sold surface land to a former officer of the Company for
the assumption of a note payable of $167,000, by the former officer, that had
previously been recorded on the Company's financial statements.

10. COMMITMENTS AND CONTINGENCIES:

Lease Commitments

The Company leases 16,500 square feet of office space under a noncancellable
operating lease that expires in 2003. Future payments under this lease are
estimated at $300,000 for 2003. Total lease expense during 2002, 2001 and 2000
was $298,000, $299,000 and $300,000, respectively.

401(k) Plan

The Company provides a voluntary 401(k) employee savings plan which covers all
full-time employees who meet certain eligibility requirements. Voluntary
contributions are made to the 401(k) plan by participants. In addition, the
Company matches 100% of the first 6% of salary contributed by each employee.
Matching contributions of $225,000, $224,000 and $191,000 were made by the
Company during 2002, 2001 and 2000, respectively.

Legal Proceedings

The Company is from time to time involved in various legal proceedings
characterized as normally incidental to the business. Management believes its
defenses to any existing litigation will be meritorious and any adverse
decisions in any pending or threatened proceedings or any amounts which it may
be required to pay by reason thereof will not have a material adverse effect on
its financial condition or results of operations.

Consulting and Employment Agreements

The Company entered into a consulting agreement on September 21, 1999 with a
former director of the Company, who was also an officer of Smith Management,
pursuant to which this individual was to receive $200,000 annually, paid in
equal monthly installments for consulting services to be provided to the Company
until September 21, 2002. The consulting agreement was terminated in August,
2001 as part of the Pengo transaction described in Note 4.

F-21

The Company has employment agreements with certain employees of the Company
which provide for payment to the employees upon termination following a change
in control.

11. STOCK OPTIONS:

1988 Stock Option Plan

On August 25, 1988, the Company's Board of Directors adopted an incentive stock
option plan (the "1988 Plan") for the benefit of key employees and directors of
the Company. A total of 21,280 shares of common stock are reserved for issuance
under the 1988 Plan. All options under the 1988 Plan are granted, exercisable
and expire 10 years from the date of grant.

1997 Stock Option Plan

On April 30, 1997, the Company's Board of Directors adopted an incentive stock
option plan (the "1997 Plan") for the benefit of key employees and directors of
the Company. Options under the 1997 Plan vest based upon the determination made
by the Company's Compensation Committee at the time of grant, and expire 10
years from the date of grant. The Company reserved 50,000 shares for grant under
the 1997 Plan of which 41,850 options were granted through December 31, 2002 at
prices equal to the market value of the Company's stock on the date of grant.
All granted options are vested. There are 43,800 shares available for grant as
of December 31, 2002.

A summary of option grants, exercises and average prices under both the 1988
Plan and the 1997 Plan is presented below:

<Table>
<Caption>
Weighted Option
Average Exercise
Number of Exercise Price
Options Price Range
--------- -------- --------

Balance, December 31, 1999 48,316 $ 37.20 $10.00 - $110.00
Cancelled (26,580) 29.50 10.00 - 110.00
--------- -------- ----------------
Balance, December 31, 2000 21,736 46.88 10.00 - 110.00
Cancelled (11,340) 47.94 10.00 - 110.00
Expired (1,156) 51.27 10.00 - 110.00
--------- -------- ----------------
Balance, December 31, 2001 9,240 45.02 10.00 - 110.00
Expired (1,260) 13.89 10.00 - 110.00
--------- -------- ----------------
Balance, December 31, 2002 7,980 $ 49.49 $10.00 - $110.00
========= ======== ================

Plan options exercisable as of
December 31, 2002 7,980 $ 49.49
========= ========
</Table>

Non-Plan Grants

From time to time the Company grants nonqualified ("Non-Plan") options to
purchase common stock to its executive officers. The grants have vesting periods
of three to five years. These grants were made at fair value. The option lives
are five to seven years. The table below summarizes the activities associated
with these grants to executive officers:

F-22

<Table>
<Caption>
Weighted Options Weighted
Average Exercise Fair Value
Number of Exercise Price of Options
Options Price Range Granted
--------- -------- ---------------- ----------

Balance, December 31, 1999 146,200 $ 10.42 $ 9.38 - $100.00
Cancelled (4,500) 95.56 90.00 - 100.00
--------- -------- ----------------
Balance, December 31, 2000 141,700 9.38 9.38 - 9.38
Granted 300,000 2.11 1.63 - 2.84 $ 1.49
==========
Cancelled (116,700) 9.38 9.38 - 9.38
--------- -------- ----------------
Balance, December 31, 2001 325,000 2.67 1.63 - 9.38
No activity -- --
--------- -------- ----------------
Balance, December 31, 2002 325,000 $ 2.67 $ 1.63 - 9.38
========= ======== ================

Non-Plan options exercisable
as of December 31, 2002 275,500 $ 2.77
========= ========
</Table>

The fair value of options granted in 2001 was estimated using the following
weighted average assumptions. No options were granted during 2002 and 2000.

<Table>
<Caption>
2001
-------

Weighted average remaining life 5 years
Risk-free interest rate 4.7%
Expected dividend yield 0%
Expected lives 5 years
Expected volatility 152.4%
</Table>

The following table summarizes information for options outstanding as of
December 31, 2002 for all Plan and Non-Plan options.

<Table>
<Caption>
Options Outstanding Options Exercisable
------------------------------------------------ ----------------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Range of Contractual Life Exercise Exercise
Exercise Price Number (Years) Price Number Price
- ---------------- ------- ---------------- -------- ------- --------

$ 1.63 - $ 2.84 300,000 4.7 $ 2.11 250,500 $ 2.11
$ 9.38 - $10.00 28,000 5.2 9.80 28,000 9.80
$ 31.25 - $37.50 900 1.4 34.17 900 34.17
$ 40.63 - $50.00 880 1.1 45.99 880 45.99
$ 84.40 - $90.00 2,400 4.9 87.20 2,400 87.20
$110.00 800 5.0 110.00 800 110.00
------- --- -------- ------- --------
332,980 3.7 $ 3.80 283,480 $ 4.10
======= === ======== ======= ========
</Table>

All options cancelled and reissued are subject to the criteria of FASB
Interpretation No. 44 "Accounting for Certain Transactions Involving Stock
Compensation - an Interpretation of APB Opinion No. 25"

F-23

("FIN 44"). In 1999, 33,500 options were cancelled and reissued at market price.
These options are being accounted for as a variable option grant based on the
market price on July 1, 2000. These options have been marked-to-market with
gains and losses recorded in income for each reporting period subsequent to July
1, 2000 to the extent there are increases in the Company's stock price above the
market value of the stock on July 1, 2000. There was no adjustment made for
these options in the years ended December 31, 2002, 2001 and 2000 as the stock
price has not exceeded the stock price in effect on July 1, 2000. During 2001,
116,700 Non-Plan options at an exercise price of $9.38 were cancelled and
300,000 new Non-Plan options were granted. The grant price for the new options
was $1.63 for 180,000 shares and $2.84 for 120,000 shares. These options are
accounted for as variable option grants. There were no adjustments made for
these options in the years ended December 31, 2002 and 2001, as the market price
of the Company's stock did not exceed the grant price of the options.

12. OIL AND GAS PRODUCING ACTIVITIES:

Major Customers

Sales to the following companies represented 10% or more of the Company's
revenues, excluding effects of hedging, (in thousands):

<Table>
<Caption>
2002 2001 2000
---------- ---------- ----------

Crude Oil:
Tesoro (formally BP) $ 6,644 $ 15,101 $ 17,016
ChevronTexaco 7,213 9,497 11,611
Big West 11,748 -- --
Gas:
Wasatch 4,137 7,622 5,556
</Table>

Costs Incurred

Cost incurred in oil and gas producing activities were as follows (in
thousands):

<Table>
<Caption>
2002 2001 2000
---------- ---------- ----------

Unproved property acquisition cost $ -- $ -- $ 33
Development cost 12,426 21,576 13,709
Exploration cost 136 143 135
---------- ---------- ----------
Total $ 12,562 $ 21,719 $ 13,877
========== ========== ==========
</Table>

F-24

Net Capital Costs

Net capitalized costs related to the Company's oil and gas producing activities
are summarized as follows (in thousands):

<Table>
<Caption>
2001 2000 2000
---------- ---------- ----------

Unproved properties $ 2,652 $ 2,894 $ 3,797
Proved properties 203,644 195,766 174,348
Gas and water transportation facilities 11,665 6,875 5,814
---------- ---------- ----------
Total 217,961 205,535 183,959

Accumulated depletion, depreciation and
amortization (51,627) (43,510) (35,004)
---------- ---------- ----------
Total $ 166,334 $ 162,025 $ 148,955
========== ========== ==========
</Table>

Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

SFAS No. 69, "Disclosures about Oil and Gas Producing Activities," prescribes
guidelines for computing a standardized measure of future net cash flow and
changes therein relating to estimated proved reserves. The Company has followed
these guidelines which are briefly discussed below. Future cash inflows and
future production and development costs are determined by applying yearend
prices and costs to the estimated quantities of oil and gas to be produced.
Estimated future income taxes are computed using current statutory income tax
rates including consideration for estimated future statutory depletion. The
resulting future net cash flows are reduced to present value amounts by applying
a 10% ("PV10%") annual discount factor.

The assumptions used to compute the standardized measure are those prescribed by
the Financial Accounting Standards Board and, as such, do not necessarily
reflect the Company's expectations of actual revenues to be derived from those
reserves nor their present worth. The limitations inherent in the reserve
quantity estimation process are equally applicable to the standardized measure
computations since these estimates are the basis for the valuation process.

The following summary sets forth the Company's future net cash flows relating to
proved oil and gas reserves based on the standardized measure prescribed in SFAS
No. 69 (in thousands):

<Table>
<Caption>
December 31,
--------------------------------------------
2002 2001 2000
------------ ------------ ------------

Future cash inflows $ 1,738,458 $ 1,102,973 $ 1,633,382
Future production costs (487,689) (351,973) (292,305)
Future development costs (210,307) (192,672) (202,071)
Future income tax provision (315,772) (145,950) (369,220)
------------ ------------ ------------
Future net cash flows 724,690 412,378 769,786
Less effect of 10% discount factor (429,065) (254,683) (445,360)
------------ ------------ ------------
Standardized measure of discounted
future net cash flows $ 295,625 $ 157,695 $ 324,426
============ ============ ============
</Table>

F-25

The principal sources of changes in the standardized measure of discounted
future net cash flows are as follows for the years ended December 31, 2002, 2001
and 2000 (in thousands):

<Table>
<Caption>
2002 2001 2000
---------- ---------- ----------

Standardized measure, beginning of year $ 157,695 $ 324,426 $ 198,312
Sales of reserves in place -- -- --
Sales of oil and gas produced excluding effects of
hedging, net of production costs (18,807) (24,276) (26,501)
Net change in sales prices and production costs 174,666 (271,039) 168,192
Extensions, discoveries and improved
recovery, net 20,871 5,566 12,269
Revisions of previous quantity estimates (12,004) 44,898 8,667
Change in future development costs (5,355) 12,176 (7,396)
Net change in income taxes (62,377) 87,208 (66,753)
Accretion of discount 19,309 44,703 25,417
Changes in production rates and other 21,627 (65,967) 12,219
---------- ---------- ----------
Standardized measure, end of year $ 295,625 $ 157,695 $ 324,426
========== ========== ==========
</Table>

Oil and Gas Reserve Quantities (Unaudited)

The reserve information presented below is based upon reports prepared by the
Company's in-house petroleum engineer. The independent petroleum engineering
firm of Ryder Scott Company, L.P. reviewed 80% of the PV10% value of the
reserves. The Company emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of producing
oil and gas properties. As a result, revisions to previous estimates are
expected to occur as additional production data becomes available or economic
factors change.

Proved oil and gas reserves are 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 operating conditions. Proved developed oil and gas
reserves are those expected to be recovered through existing wells with existing
equipment and operating methods. The fluctuation of oil and gas prices has a
significant impact on the standardized measure. Future increases or decreases in
oil or gas prices increase or decrease the standardized measure accordingly. As
of December 31, 2002, the Company used prices of $28.20 per Bbl and $2.96 per
Mcf. Prices used by the Company in 2001 were $16.84 per Bbl and $2.23 per Mcf.
Prices used by the Company in 2000 were $23.78 per Bbl and $7.73 per Mcf.

F-26

Presented below is a summary of the changes in estimated proved reserves of the
Company, all of which are located in the United States, for the years ended
December 31, 2002, 2001 and 2000:

<Table>
<Caption>
2002 2001 2000
--------------------------- ------------------------ ------------------------
Oil (MBbl)(1) Gas (MMcf) Oil (MBbl) Gas (MMcf) Oil (MBbl) Gas (MMcf)
------------- ---------- ---------- ---------- ---------- ----------

Proved reserves, beginning of year 54,571 82,507 47,159 66,187 47,129 60,935
Sales of reserves in place -- -- -- -- -- --
Extensions and discoveries -- -- -- -- 660 1,584
Improved recoveries 1,955 118 1,324 629 400 200
Production (1,137) (2,106) (1,212) (2,423) (1,072) (2,289)
Revisions of previous estimates (2,423) 3,469 7,300 18,114 42 5,757
------------- ---------- ---------- ---------- ---------- ----------
Proved reserves, end of year 52,966 83,988 54,571 82,507 47,159 66,187
============= ========== ========== ========== ========== ==========

Proved developed reserves,
end of year 17,668 23,740 18,409 20,682 17,531 13,647
============= ========== ========== ========== ========== ==========
</Table>

(1) A total of 1,827 Mbbl of proved natural gas liquids are included in proved
oil reserves for the 2002 year as improved recoveries.

13. QUARTERLY EARNINGS (UNAUDITED):

Summarized unaudited quarterly financial data for 2002 and 2001 is as follows
(in thousands, except per share data):

<Table>
<Caption>
Quarter Ended
--------------------------------------------------------------------
March 31, June 30, September 30, December 31,
2002 2002 2002 2002
-------------- -------------- -------------- --------------

Revenues $ 7,113 $ 7,851 $ 7,157 $ 7,757
Operating income 1,676 2,977 1,622 2,220
Net loss (2,819) (1,475) (2.921) (2,413)
Basic and diluted loss
per share attributable to
common stockholders $ (0.97) $ (0.51) $ (1.01) $ (0.83)
</Table>

<Table>
<Caption>
Quarter Ended
-----------------------------------------------------------------------
March 31, June 30, September 30, December 31,
2001(1) 2001 2001 2001(2)
-------------- -------------- -------------- --------------

Revenues $ 8,169 $ 8,572 $ 8,103 $ 7,123
Operating income 3,287 3,384 2,772 1,966
Net income (loss) 867 1,720 (310) (4,428)
Basic and diluted loss
per share attributable to
common stockholders $ (1.42) $ (1.01) $ (.14) $ (1.53)
</Table>

(1) Operating income and net income for the quarter ended March 31, 2001 were
adjusted for the reversal of a non-cash charge related to the stock option
repricing discussed in Note 11.

(2) Includes a non-cash loss of $1,675,000 related to the loss of effectiveness
of derivative contracts following the filing of Chapter 11 bankruptcy of
ENAC, as discussed in Note 2.

F-27

14. Subsequent Events:

Pending Refinancing, Exchange, Merger and Going Private Transactions

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
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 $1.00 per share as a
result of the Merger.

F-28

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.

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 being 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 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.

F-29

INDEX TO EXHIBITS

<Table>
<Caption>
Item
Number Description
- ------ -----------

3.2 By-Laws of Inland (filed as Exhibit 3.2 to Inland's
Registration Statement on Form S-18, Registration No.
33-11870-F, and incorporated herein by reference).

3.2.2 Amendment to the Bylaws of Inland adopted April 8,
1994 (filed as Exhibit 3.2.2 to Inland's Registration
Statement on Form S-4, Registration No. 33-80392, and
incorporated herein by reference).

*4.1 Third Amended and Restated Credit Agreement dated
November 30, 2001, between Inland Production Company
(as borrower), Inland Resources Inc.(as guarantor)
and Fortis Capital Corp. (as agent).

10.1 1988 Option Plan of Inland Gold and Silver Corp.
(filed as Exhibit 10(15) to Inland's Annual Report on
Form 10-K for the year ended December 31, 1988, and
incorporated herein by reference).

<Table>

10.12 Amendment to Employment Agreement between Inland and
William T. War, amending the Employment Agreement
filed as Exhibit 10.10.

10.13 Employment Agreement between Inland and Michael J.
Stevens dated effective as of February 1, 2001.

10.14 Employment Agreement between Inland and Marc MacAluso
dated effective as of February 1, 2001 and.

10.15 Stock Option Agreement between Inland and Marc
MacAluso dated effective as of February 1, 2001
representing 150,000 post-split shares of Common
Stock.

10.16 Employment Agreement between Inland and Bill I.
Pennington dated effective as of February 1, 2001
and.

10.17 Stock Option Agreement between Inland and Bill I.
Pennington dated effective as of February 1, 2001
representing 150,000 post-split shares of Common
Stock.

10.18 Oil Purchase and Delivery Agreement dated November 7,
2000.

<Table>

10.36 Fourth Amendment to Third Amended and Restated Credit
Agreement (filed as an exhibit to the Company's
Schedule 13E-3 dated February 5, 2003 and
incorporated herein by reference).

*21.1 Subsidiaries of Inland

*23.2 Consent of Ryder Scott Company, L.P.

*23.3 Consent of KPMG LLP

*99.1 Certification of Chief Executive Officer pursuant to
section 1350 as adopted pursuant to section 906 of
the Sarbanes-Oxley Act of 2002.

*99.2 Certification of Chief Financial Officer pursuant to
section 1350 as adopted pursuant to section 906 of
the Sarbanes-Oxley Act of 2002.

*99.3 Certification of Chief Executive Officer pursuant to
section 1350 as adopted pursuant to section 302 of
the Sarbanes-Oxley Act of 2002.

*99.4 Certification of Chief Financial Officer pursuant to
section 1350 as adopted pursuant to section 302 of
the Sarbanes-Oxley Act of 2002.
</Table>

* Filed herewith