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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2000

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

For the transition period to
----------- -----------

Commission File Number 0-16487

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

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

410 17th Street
Suite 700
Denver, Colorado
(303) 893-0102 80202
(Address of Principal Executive Offices) (Zip Code)
Issuer's telephone number, including area code: (303) 893-0102

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

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

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

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 15, 2001, the registrant had outstanding 2,897,732 shares of
par value $.001 common stock. The aggregate value on such date of the common
stock of the Registrant held by non-affiliates was an estimated $550,000.

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

PAGE

PART I
Items 1. & 2. Business and Properties........................................................................2
Item 3. Legal Proceedings.............................................................................11
Item 4. Submission of Matters to a Vote of Security Holders...........................................11

PART II
Item 5. Market for Registrant's Common Stock and Related Stockholder Matters..........................12
Item 6. Selected Financial Data.......................................................................12
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.........14
Item 7A. Quantitative and Qualitative Disclosures About Market Risks...................................20
Item 8. Financial Statements and Supplementary Data...................................................21
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure..........21

PART III
Item 10. Directors and Executive Officers of the Registrant............................................22
Item 11. Executive Compensation........................................................................23
Item 12. Security Ownership of Certain Beneficial Owners and Management................................26
Item 13. Certain Relationships and Related Transactions................................................28

PART V
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...............................30

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PART I

The following text is qualified in its entirety by reference to the
more detailed information and consolidated financial statements (including the
notes thereto) appearing elsewhere in this Annual Report on Form 10-K. Unless
the context otherwise requires, references to "Inland" shall mean Inland
Resources Inc., a Washington corporation, and references to the "Company" or its
operations shall mean Inland and its consolidated subsidiaries, including Inland
Production Company ("IPC"), a Utah corporation, and Inland Working Capital
Company ("IWCC"), a Utah 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."

All references to shares of Inland's common stock, par value $.001 per
share ("Common Stock"), and share prices in this Form 10-K have been adjusted to
give effect to the 1-for-10 reverse stock split effected December 14, 1999.

ITEMS 1. & 2. BUSINESS AND PROPERTIES

OVERVIEW

Inland Resources Inc. 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 subsidiaries, IPC and IWCC. In 2000, IPC drilled 44 gross
(35.5 net) developmental wells. At December 31, 2000, the Company's estimated
net proved reserves totaled 58,191 MBOE, having a pre-tax present value
discounted at 10% using constant prices of $447 million.

The Company intends to pursue a balanced strategy of development
drilling and acquisitions, 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 662 gross (523 net) oil
wells, including 201 gross (165 net) injection wells. Inland pioneered the
secondary water flood recovery processes used in the Field and currently
operates 21 approved secondary recovery projects in the area. Budgeted
development expenditures for 2001 in the Field are $17 million net to the
Company.

RECENT DEVELOPMENTS

Sale of Refinery Operations. 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 owns the Wood Cross Refinery in Woods Cross, Utah and the
Roosevelt Refinery in Roosevelt, Utah (which was non-operating at the time of
sale). Prior to the sale, the existing cash, inventory, accounts receivable and
a note receivable were transferred to IWCC, and 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.

Change of Control and Recapitalization. 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") 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 issued to Holdings, whose members are
Fund V and Portfolio: (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

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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 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.

On March 20, 2001, Hampton Investments LLC ("Hampton"), an affiliate of
Smith Management LLC, purchased from JEDI the 121,973 shares of Series E
Preferred Stock and 292,098 shares of Common Stock acquired by JEDI in the
recapitalization. Following closing of the Exchange Agreement and the purchase
by Hampton of JEDI's shares, Holdings owns 1,752,586 shares of Common Stock,
representing approximately 60.5% of the outstanding shares of Common Stock at
March 20, 2001, and Hampton owns 292,098 shares of Common Stock, representing
approximately 10.1% of the outstanding shares of Common Stock at March 20, 2001.
The Company's Articles of Incorporation, as amended (the "Articles"), provide
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 stockholders 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 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. Pursuant to the Articles, the total number of votes of the
combined class of Common Stock, Series D Preferred Stock and Series E Preferred
Stock outstanding at March 20, 2001 is 3,985,704 votes, of which 2,828,361 votes
(representing approximately 71% of the total) are owned by Holdings, and 304,295
votes (representing approximately 7.6% of the total) are owned by Hampton. TCW
Asset Management Company has the power to vote and dispose of the securities
owned by Holdings. Various persons and entities that may be considered related
to Hampton own an additional 548,338 shares of Common Stock, so that together
with Hampton such persons, entities and Hampton own an aggregate of 840,436
shares of Common Stock and 852,633 votes (representing approximately 21.4% of
the total).

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
662 wells, or 97% 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 1998, 1999 and 2000 are set forth in pages
F-23 and F-24 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, an independent reservoir engineer. The review by Ryder Scott Company
consisted of properties which comprised approximately 80% of the total present
worth of future net revenue discounted at 10% as of December 31, 2000. The total
proved net reserves estimated by the Company were within 10% of those reviewed
and estimated by Ryder Scott Company; however, on a well by well basis,
differences of greater than 10% may exist. See also, the Supplemental Oil and
Gas Disclosures appearing on pages F-23 through F-26 of this Annual Report.

As of December 31, 2000
----------------------------------
Proved Proved Total
Developed Undeveloped Proved
--------- ----------- ------
(dollars in thousands)

Net Proved Reserves
Oil (MBls) 17,531 29,628 47,159
Gas (MMcf) 13,647 52,540 66,187
MBOE (6Mcf per Bbl) 19,806 38,385 58,191
Estimated Future Net Revenues(1) $ 344,340 $ 794,666 $1,139,006
Present Value of Future Net Revenues(2) $ 179,199 $ 267,834 $ 447,033

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(1) Undiscounted.
(2) Discounted at 10%.

Future net revenues from reserves at December 31, 2000 were calculated
on the basis of market prices in effect on that date and were approximately
$23.78 per barrel of oil and $7.73 per Mcf of gas. The value of the estimated
proved gas reserves are net of deductions for shrinkage and natural gas required
to power future 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 remedial costs.

Because all reserve estimates are to some degree subjective, (a) the
quantities of oil and gas that are ultimately recovered, (b) the production and
operating costs incurred, (c) the amount and timing of future development
expenditures and (d) 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 proven 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-23 through F-26 of this Annual Report.

Year Ended December 31,
------------------------
2000 1999 1998
------ ------ ------

Net Production:
Oil (MBls) ............... 1,072 1,165 1,501
Gas (MMcf)(1) ............ 2,289 2,901 3,006
Total (MBOE) ......... 1,454 1,649 2,002
Average Sale Price(2):
Oil (per Bbl) ............ $26.71 $14.38 $ 9.82
Gas (per Mcf)(3) ......... $ 2.60 $ 1.56 $ 2.00
Average Production Cost:
($/BOE)(4) ........... $ 5.23 $ 4.34 $ 4.18

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(1) Excludes lease fuel used for operations.
(2) Does not reflect the effects of hedging transactions.
(3) Includes natural gas liquids.
(4) 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 in which the Company had an interest during 2000, 1999 and
1998.

2000 1999 1998
--------------- ------------- -----------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- ----

Development wells:
Oil(1) ............ 43(2) 34.5(2) 8 7.5 90 69
Dry ............... 1 1 5 4
---- ---- ---- ---- ---- ----
Total ......... 44 35.5 8 7.5 95 73
==== ==== ==== ==== ==== ====

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(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 own any drilling rigs and all of its drilling
activities are conducted by independent contractors on a day rate or footage
basis under standard drilling contracts.

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, 2000:

Wells(1)
--------------------------------------------
Gross(2) Net(2)
------------------- -------------------
Water Water
Location Oil(1) Injection Oil(1) Injection
- -------- ------ --------- ------ ---------

Utah(3) 476 204 360 166

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(1) The Company is an operator of 662 gross wells (523 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, 2000.

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

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Acreage Data. The following table reflects the developed and undeveloped
acreage that the Company held as of December 31, 2000:

Developed Acreage Undeveloped Acreage(1)
----------------- ----------------------
Gross Net Gross Net
Location Acres Acres Acres Acres
-------- ----- ----- ----- -----

Utah(2) 26,200 21,900 106,300 82,000

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(1) Undeveloped acreage includes 58,000 gross (43,300 net) acres held by
production at December 31, 2000.
(2) All of the Company's acreage is located in the Field.

As of December 31, 2000, the undeveloped acreage not held by production
involves 250 leases with remaining terms of up to 10 years. Leases covering
approximately 1,860 net acres have expiration dates in 2001. 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 of approximately $76,000 net to
the Company in 2000). 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 retaining an override or back-end 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 or maintain reservoir pressures, resulting in
greater crude oil production. Inland currently operates 21 approved water flood
units or areas. At December 31, 2000, the Company had 201 wells injecting an
aggregate of 12,000 BWPD. During 2000, the Company installed 20 miles of water
pipelines to handle low pressure water delivery and high pressure water
injection. The Company also converted 41 gross (33 net) oil wells into injection
wells. At December 31, 2000, the Company owned and operated 140 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 50 wells in the Field during 2001.

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 at peak field development.

Gas Gathering And Transportation Systems. The Company currently
produces approximately 11 MMcf of natural gas per day and sells approximately 7
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 325 miles of pipelines and 2
compression facilities using 5 compressors and 2 dehydration units with a
throughput capacity of 22.5 MMcf per day.

Delivery Commitments. The Company has no material delivery commitments
under 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 Flying J, BP, Chevron
and Phillips. Transportation of large quantities of Black Wax by pipeline is not
currently feasible, and transportation by truck or rail to refineries in
California or Colorado is not economical. 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,

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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 is aware of refinery modifications in the Salt
Lake City market that should further increase the demand for Black Wax in the
next two years.

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 $3.56 during year 2000 and the fourth quarter of 1999. The Company
expects the basis differential to approximate $3.60 through August 2002.
Subsequent to August 2002 and through December 2005, the Company has a contract
with one of the refiners to sell up to 7,000 barrels of oil per day at NYMEX
less $3.00. The NYMEX price ranged from $25.54 to $34.26 during 2000 and was
$28.40 for December 2000. The NYMEX price ranged from $12.02 to $26.09 during
1999.

Prior to the fourth quarter of 1999, the Company sold Black Wax at the
average monthly posted field price less a deduction of approximately $1.00 per
barrel for oil quality adjustments. The posted field price ranged from $7.75 to
$23.75 during 1999. During 2000 and 1999, the Company sold 59% and 29%,
respectively, of its oil production to BP. During 2000, the Company sold 41% of
its oil production to Chevron. During 1999, the Company sold 63% of its crude
oil production to Refining.

The Company markets substantially all of its operated gas production.
The Company currently has contracts to sell 3,400 Mcf per day through October
2001 at $4.70 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 $2.52 to $7.18 per Mcf during 2000 and from $1.67 to
$3.30 per Mcf during 1999, and was $7.18 per Mcf for December 2000. All spot
market sales during 2000 and 1999 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.

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 2001.

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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 2000, and are expected to
continue to be significant in 2001:

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 and socioeconomic
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 successfully at
continuing to develop oil and gas resources in the Field while complying with
the surface stipulations and mitigation measures contained in the ROD.

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. The USFWS had not issued a Final Rule to list the mountain plover as of
December 31, 2000, however, 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,
2000, 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
has reached a tentative Settlement with EPA on injection well over pressuring
during the 1995 to 1998 time period, and is currently in substantial compliance
with the EPAs underground injection program. 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. As of December 31, 2000, the Company had taken all steps necessary to
be in substantial compliance with this CAA and its implementing regulations.

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 liability 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 (a) well blowouts, (b)
cratering, (c) explosions, (d) uncontrollable flows of oil, gas or well fluids,
(e) fires, (f) formations with abnormal pressures, (g) pollution, (h) releases
of toxic gas and (i) 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 (a) maintain certain insurance
coverage on existing wells and all new wells drilled during drilling operations,
and (b) 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 which have greater financial resources and larger technical staffs
than Inland.

With respect to Black Wax production, additional competitive pressures
result from the inelasticity in the demand for Black Wax after the refining
capacity in the Salt Lake City area is reached.

DISCONTINUED REFINING OPERATIONS

General. As noted above under "Recent Developments -- Sale of Refinery
Operations," 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.

The financial statements included with this Annual Report reflect all
necessary adjustments to record Refining at net realizable value as of December
31, 1999, and the financial statements for prior periods have been restated to
remove the separate segment information for the refining operations and to
reflect the refining operations as discontinued operations. Consequently,
separate segment information, and a separate discussion of refinery operations,
is not included in this Annual Report.

Environmental Regulations Associated with Discontinued Refining
Operations. As of December 31, 2000, 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 15, 2001, the Company had 96 employees, consisting of four
executive officers, 17 technical, clerical and administrative employees and 75
field operations staff involved in the Company's oil and gas operations in Utah.

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 which expires in December 2002 and provides for a rental rate of $25,000
per month.

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]

11
13

PART II

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

PRICE RANGE OF COMMON STOCK

Since July 29, 1999, Inland's Common Stock has been traded
over-the-counter and quoted from time to time in the OTC Bulletin Board "pink
sheets" under the trading symbol "INLN". Prior to July 29, 1999, Inland's Common
Stock was quoted on the National Association of Securities Dealer's Automated
Quotation System ("Nasdaq") under the symbol "INLN". As of March 15, 2001, there
were approximately 500 holders of record of Inland's Common Stock. The following
table sets forth the range of high and low sales prices as reported by Nasdaq
for the periods indicated prior to July 29, 1999, and 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.
All prices have been adjusted to give retroactive effect to the 1-for-10
reverse split of the Common Stock effected on December 14, 1999. This adjustment
was made by multiplying the actual price by a factor of 10. There can be no
assurance that the shares would have traded at such adjusted price had the
reverse split occurred prior to the dates reflected below.

Common Stock Price Range
------------------------
High Low
------ ------

YEAR ENDED DECEMBER 31, 2000
First Quarter .................. $ 7.00 $ 2.13
Second Quarter ................. 7.00 3.00
Third Quarter .................. 5.75 4.25
Fourth Quarter ................. 3.88 0.94

YEAR ENDED DECEMBER 31, 1999
First Quarter .................. $52.50 $11.90
Second Quarter ................. 26.90 7.50
Third Quarter .................. 15.00 2.50
Fourth Quarter ................. 13.75 2.50

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. In
addition, Inland's charter forbids the payment of cash dividends on Common Stock
if there are accumulated and unpaid dividends on the Series D Preferred Stock or
Series E Preferred Stock.

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, 2000. Inland utilizes the successful efforts method of
accounting for oil and gas activities. Such data should be read together with
the historical consolidated financial statements of Inland, incorporated by
reference in this annual report.

Year Ended December 31,
-------------------------------------------------------------
2000 1999 1998 1997 1996
--------- --------- --------- --------- ---------
(dollars in thousands, except for unit amounts)

REVENUE AND EXPENSE DATA:
Revenues:
Oil and gas sales .......................................... $ 28,497 $ 16,399 $ 21,278 $ 17,182 $ 10,704
Operating Expenses:
Lease operating expenses ................................... 7,596 7,160 8,362 3,780 1,435
Production taxes ........................................... 483 192 454 383 610
Exploration ................................................ 135 155 153 61 167
Impairment ................................................. -- -- 1,327 -- --
Depletion, depreciation and amortization ................... 7,816 9,882 12,025 6,480 3,428
General and administrative, net ............................ 2,128 3,136 2,061 2,118 1,670
--------- --------- --------- --------- ---------
Total operating expenses ................................ 18,158 20,525 24,382 12,822 7,310
--------- --------- --------- --------- ---------
Operating income (loss) ....................................... 10,339 (4,126) (3,104) 4,360 3,394

Interest expense .............................................. (8,298) (15,989) (14,895) (4,759) (1,633)
---------
Interest and other income ..................................... 103 72 107 380 414
Loss from discontinued operations ............................. (250) (16,274) (5,560) -- (30)
--------- --------- --------- --------- ---------
Net income (loss) before extraordinary loss ................... 1,894 (36,317) (23,452) (19) 2,145
Extraordinary loss ............................................ -- (556) -- (1,160) --
--------- --------- --------- --------- ---------
Net income (loss) ............................................. 1,894 (36,873) (23,452) (1,179) 2,145

Redemption premium - Preferred Series A Stock ................. -- -- -- -- (214)
Redemption premium - Preferred Series B Stock ................. -- -- -- (580) --
Accrued Preferred Series C Stock dividends .................... -- (663) (1,084) (450) --
Accrued Preferred Series D Stock dividends .................... (9,732) (2,262) -- -- --
Accrued Preferred Series E Stock dividends .................... (1,506) (350) -- -- --
Accretion of Preferred Series D Stock Discount ................ (6,300) (1,473) -- -- --
Accretion of Preferred Series E Stock Discount ................ (900) (220) -- -- --
--------- --------- --------- --------- ---------
Net income (loss) attributable to common stockholders ......... $ (16,544) $ (41,841) $ (24,536) $ (2,209) $ 1,931
--------- --------- --------- --------- ---------
Earnings (loss) per common share before extraordinary loss
Basic .................................................... $ (5.71) $ (28.99) $ (29.25) $ (1.42) $ 3.80
Diluted .................................................. (5.71) (28.99) (29.25) (1.42) 3.00
Earnings (loss) per common share:
Basic .................................................... $ (5.71) $ (29.37) $ (29.25) $ (2.99) $ 3.80
Diluted .................................................. (5.71) (29.37) (29.25) (2.99) 3.00

BALANCE SHEET DATA (AT END OF PERIOD):
Oil and gas properties, net ................................... $ 148,955 $ 142,412 $ 159,105 $ 133,820 $ 42,998
Total assets .................................................. $ 160,065 $ 153,402 $ 187,781 $ 175,953 $ 57,329

Debt .......................................................... $ 83,500 $ 79,082 $ 156,973 $ 123,111 $ 21,120
Stockholders' equity (deficit) ................................ $ (20,210) $ (3,666) $ 7,039 $ 30,672 $ 31,972

13
15

OTHER FINANCIAL DATA:
Net cash provided by (used in) operating activities .... $ 7,992 $ (7,513) $ 6,822 $ 5,668 $ 5,006
Net cash used in investing activities .................. (14,137) (3,772) (39,391) (99,272) (23,752)
Net cash provided by financing activities .............. 4,085 10,502 47,076 107,128 25,806

OPERATING DATA:
Sales Volumes (net):
Oil (MBbls) ....................................... 1,072 1,165 1,501 855 502
Gas (MMcf) ........................................ 2,289 2,901 3,006 1,637 710
MBOE .............................................. 1,454 1,649 2,002 1,128 620
BOEPD ............................................. 3,973 4,518 5,485 3,090 1,698
Average Prices (excluding hedging activities):

Oil (per Bbl) ..................................... $ 26.71 $ 14.38 $ 9.82 $ 16.17 $ 20.18
Gas (per Mcf) ..................................... 2.60 1.56 2.00 2.19 1.56
Per BOE ........................................... 23.79 12.90 10.35 15.23 17.26

Production and operating costs (per BOE) (1) .......... $ 5.23 $ 4.34 $ 4.18 $ 3.35 $ 2.31

- ---------

(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, 2000, 1999 and 1998.

GENERAL

Inland is a diversified and 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. The Woods Cross refinery was originally
purchased on December 31, 1997 for $22.9 million and the Roosevelt refinery was
originally purchased on September 16, 1998 for $2.25 million. 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.

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2000 COMPARED WITH YEAR ENDED DECEMBER 31, 1999

Oil and Gas Sales. Crude oil and natural gas revenue for the year ended
December 31, 2000 increased $12.1 million, or 74% from the previous year. As
shown in the table below, the variance was caused by higher average crude oil
and natural gas prices offset by lower sales volumes. The Company operates and
is in control of over 99% of its oil and gas production. Crude oil sales as a
percentage of total oil and gas sales were 83% and 79% during 2000 and 1999,
respectively. Crude oil will continue to be the predominant product produced
from the Field.

The Company has entered into price protection agreements to hedge against
volatility in crude oil prices. 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 crude oil revenue in the
period in which the related oil is sold. Crude oil sales were decreased by $6.1
million and $4.9 million during year 2000 and 1999, respectively, to recognize
hedging contract settlement losses. See Item 7A "Quantitative and Qualitative
Disclosures About Market Risk."

Year Ended December 31, 2000 Year Ended December 31, 1999
------------------------------------------ ------------------------------------------
Net Volume Average Sales Net Volume Average Sales
(Bbls or Mcfs) Price (in 000's) (Bbls or Mcfs) Price (in 000's)
-------------- ------- ---------- -------------- ------- ----------

Crude Oil Sales 1,071,752 $26.71 $ 28,627 1,165,117 $14.38 $ 16,754
Natural Gas Sales 2,289,059 $ 2.60 5,953 2,900,501 $ 1.56 4,517
Hedging Loss (6,083) (4,872)
-------- --------
Total Revenue $ 28,497 $ 16,399
======== ========

Lease Operating Expenses. Lease operating expense for the year ended
December 31, 2000 increased $436,000, or 6.1% from the previous year. Lease
operating expense per BOE increased from $4.34 per BOE sold in 1999 to $5.23 in
2000. The increase on a BOE basis is due to the lower volume produced and
general price increases throughout year 2000.

Production Taxes. Production taxes as a percentage of sales were 1.4%
in 2000 and 1.0% in 1999. 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 2000 and 1999 represents the
Company's cost to retain unproved acreage.

Depletion, Depreciation and Amortization. Depletion, depreciation and
amortization for the year ended December 31, 2000 decreased 21%, or $2.1
million, from the previous year. The decrease resulted from decreased sales
volumes and a lower 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
$4.95 per BOE sold during 2000 compared to $5.59 per BOE sold during 1999. Based
on December 31, 2000 proved reserves, the Company's depletion rate entering 2001
is $5.12 per BOE.

General and Administrative, Net. General and administrative expense for
the year ended December 31, 2000 decreased $1.0 million, or 32% from the
previous year. The 2000 amount includes $430,000 related to an unsuccessful
business combination and employee severance costs. The 1999 amount includes $1.2
million related to the Company's financial restructuring. After removal of these
costs, general and administrative expense was 12% lower between periods. General
and administrative expense is reported net of operator fees and reimbursements
which were $5.5 million and $4.7 million during 2000 and 1999, respectively.
Gross general and administrative expense was $7.2 million (net of one-time
costs) in 2000 and $6.6 million (net of restructuring costs) in 1999. The
increase in reimbursements and expense is a function of operated field activity;
which decreased in 1999 when the Company suspended development activity until
the fourth quarter, then increased in year 2000 when the Company was active with
development activities throughout the year.

Interest Expense. Interest expense for the year ended December 31, 2000
decreased $7.7 million, or 48% from the previous year. The decrease was the
result of the financial restructuring performed in September 1999 when
approximately $80.0 million of debt was converted to preferred stock. Borrowings
during 2000 and 1999 were recorded at effective interest rates of 10.2% and
10.6%, respectively.

Other Income. Other income in 2000 and 1999 primarily represents
interest earned on the investment of surplus cash balances.

Income Taxes. In 2000 and 1999, no income tax provision or benefit was
recognized due to net operating losses incurred and the establishment of a full
valuation allowance.

Discontinued Operations. During 1999, the Company operated the Woods
Cross Refinery and incurred an operating loss of $1.8 million. On January 31,
2000, the refinery along with certain other assets were sold to Silver Eagle.
Although the margins obtained for refined product sales in the Salt Lake City
region were strong for most of the year, the Company suffered from inefficient
operations since it was unable to secure sufficient quantities of feedstock due
to its financial condition. After the Company's financial restructuring in
September 1999, increasing crude oil costs reduced margins on refined product
sales to unacceptable levels. These circumstances combined with the availability
of alternative buyers for the Company's crude oil caused the Company to
discontinue refinery operations in December 1999 and subsequently sell Refining
on January 31, 2000. As a result of this activity, the accompanying consolidated
financial statements for the current period and all prior periods have been
adjusted to report refining operations as discontinued operations. The Company
recorded a charge of $14.5 million in 1999 to record the disposal of the
refining business segment. The Company recorded an additional loss of $250,000
during 2000 to reflect adjustments to the refinery shut-down accruals.

Extraordinary Item. Effective September 21, 1999, the Company
restructured an existing obligation to TCW and amended the terms of its farmout
arrangement with Smith Energy Partnership. As a result of these transactions,
unamortized debt issue costs of $556,000 were written off as an extraordinary
loss.

Accrued Preferred Series C Stock Dividends. Inland's Preferred Series C
Stock was exchanged for Common Stock and Preferred Series E Stock as part of the
financial restructuring transaction on September 21, 1999. Prior to that time,
the Preferred Series C Stock accrued dividends at 10% compounded quarterly. The
amount accrued represents those dividends earned during 1999.

Accrued Preferred Series D Stock Dividends. Inland's Preferred Series D
Stock accrues dividends at 11.25% compounded quarterly. The amount accrued
represents those dividends earned during 2000 and the fourth quarter of 1999,
respectively.

Accrued Preferred Series E Stock Dividends. Inland's Preferred Series E
Stock accrues dividends at 11.5% compounded quarterly. The amount accrued
represents those dividends earned during 2000 and the fourth quarter of 1999,
respectively.

Accretion of 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 is being accreted to face value ($80.7 million) over the
minimum mandatory redemption period which starts on April 1, 2002 and ends on
April 1, 2004.

Accretion of 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 is being accreted to face value ($12.2 million) over the
period to the minimum mandatory redemption date of April 1, 2004.

YEAR ENDED DECEMBER 31, 1999 COMPARED WITH YEAR ENDED DECEMBER 31, 1998

Oil and Gas Sales. Crude oil and natural gas revenue for the year ended
December 31, 1999 decreased $4.9 million, or 23% from the previous year. Prior
to considering hedging losses of $4.9 million in 1999, the Company's oil and gas
revenues were flat between years. The lack of change in oil and gas revenues was
a function of increased crude oil sales prices offset by sales volume decreases.
Sales volumes decreased 18% from 2.0 MBOE in 1998 to 1.65 MBOE in 1999 due to
normal production decline. The Company's production decline leveled out by year
end 1999 due to the drilling of eight wells during the fourth quarter of 1999.
Crude oil sales as a percentage of total oil and gas sales were 79% and 72% in
1999 and 1998, respectively. Crude oil will continue to be the predominant
product produced from the Field.

Inland has entered into price protection agreements to hedge against
the volatility in crude oil prices. Although hedging activities do not affect
Inland's actual sales price for crude oil in the Field, the financial impact of
hedging transactions is reported as an adjustment to crude oil revenue in the
period in which the related oil is sold. Crude oil sales were decreased by $4.9
million in 1999 and increased by $550,000 during 1998 to recognize hedging
contract settlement gains and losses and contract purchase cost amortization.
See Item 7A "Quantitative and Qualitative Disclosures About Market Risk."

Year Ended December 31, 1999 Year Ended December 31, 1998
------------------------------------------ ------------------------------------------
Net Volume Average Sales Net Volume Average Sales
(Bbls or Mcfs) Price (in 000's) (Bbls or Mcfs) Price (in 000's)
-------------- ------- ---------- -------------- ------- ----------

Crude Oil Sales 1,165,117 $14.38 $ 16,754 1,501,379 $9.82 $ 14,754
Natural Gas Sales 2,900,501 $ 1.56 4,517 3,006,169 $2.00 5,974
Hedging Income (Loss) (4,872) 550
-------- --------
Total Revenue $ 16,399 $ 21,278
======== ========

Lease Operating Expenses. Lease operating expense for the year ended
December 31, 1999 decreased $1.2 million, or 14% from the previous year. Lease
operating expense per BOE increased from $4.18 per BOE sold in 1998 to $4.34 in
1999. The increase on a BOE basis is due to the lower volume produced, offset by
cost reductions during 1999.

Production Taxes. Production taxes as a percentage of sales were 1.0%
in 1999 and 2.2% in 1998. 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 1999 and 1998 represents the
Company's cost to retain unproved acreage.

Impairment. Impairment reflects the adjustment in carrying value to
write down a note receivable and certain undeveloped acreage to their estimated
net realizable value at December 31, 1998.

Depletion, Depreciation and Amortization. Depletion, depreciation and
amortization for the year ended December 31, 1999 decreased 18%, or $2.1
million, from the previous year. The decrease resulted from decreased sales
volumes and a slightly lower 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 $5.59 per BOE sold during 1999 compared to $5.70 per BOE sold during 1998.

General and Administrative, Net. General and administrative expense for
the year ended December 31, 1999 increased $1.1 million, or 52% from the
previous year. The 1999 amount includes $1.2 million related to the Company's
financial restructuring. After removal of the restructuring costs, general and
administrative expense was slightly lower between periods. General and
administrative expense is reported net of operator fees and reimbursements which
were $4.7 million and $5.7 million during 1999 and 1998, respectively. Gross
general and administrative expense was $6.6 million (net of restructuring costs)
in 1999 and $7.8 million in 1998. The decrease in reimbursements and expense is
a function of the level of operated field activity, which decreased when the
Company temporarily terminated development activity from late 1998 to late 1999.

Interest Expense. Interest expense for the year ended December 31, 1999
increased $1.1 million, or 7.3% from the previous year. The increase resulted
from an increase in the average amount of borrowings outstanding during the year
and immediately prior to the financial restructuring performed in September
1999. Borrowings during 1999 and 1998 were recorded at an effective interest
rate of approximately 10.6%.

Other Income. Other income in 1999 and 1998 primarily represents
interest earned on the investment of surplus cash balances.

Income Taxes. In 1999 and 1998, no income tax provision or benefit was
recognized due to net operating losses incurred and the establishment of a full
valuation allowance.

Discontinued Operations. During 1999, the Company operated the Woods
Cross Refinery and incurred an operating loss of $1.8 million. Although the
margins obtained for refined product sales in the Salt Lake City region were
strong for most of the year, the Company suffered from inefficient operations
since it was unable to secure sufficient quantities of feedstock due to its
financial condition. After the Company's financial restructuring in September
1999, increasing crude oil costs reduced margins on refined product sales to
unacceptable levels. These circumstances combined with the availability of
alternative buyers for the Company's crude oil caused the Company to discontinue

17
19

refinery operations in December 1999. The refinery was subsequently sold along
with a nonoperating refinery in Roosevelt, Utah on January 31, 2000.

As a result of this activity, the accompanying consolidated financial
statements for the current period and all prior periods have been adjusted to
report refining operations as discontinued operations. The Company recorded a
charge of $14.5 million in 1999 to record the disposal of the refining business
segment.

LIQUIDITY AND CAPITAL RESOURCES

FORTIS CREDIT AGREEMENT

Effective September 21, 1999, the Company entered into a credit
agreement (the "Fortis Credit Agreement") the current members of which are
Fortis Capital Corp. and U.S. Bank National Association (the "Senior Lenders").
At December 31, 2000, the Company had advanced 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 on April
1, 2001. If the borrowing base is lower than the outstanding principal balance
then drawn, the Company must immediately pay the difference.

All borrowings under the Fortis Credit Agreement are due on April 1,
2002, or potentially earlier if the borrowing base is determined to be
insufficient. In addition, the Company's Series D Preferred Stock must be
redeemed equally over three years beginning upon the earlier of September 21,
2004 or the repayment in full of the Company's existing senior credit facility,
which by its terms is April 1, 2002. The Company does not expect to generate
sufficient cash from operations before April 1, 2002 to satisfy these
commitments. As a result, the Company is developing a plan to address this issue
which may include (1) renegotiating its existing Fortis Credit Agreement to
provide for repayment terms beyond April 1, 2002 (2) entering into a new senior
credit facility with repayment terms beyond April 1, 2002 (3) issuing
subordinated debt of the Company (4) selling equity of the Company (5) selling
assets of the Company. Although management cannot give assurance, they believe
the Company will be successful in obtaining modifications to existing agreements
or raising the necessary capital from other sources in the time frames required.

Interest accrues under the Fortis Credit Agreement, at the Company's
option, at either (i) 2% above the prime rate or (ii) 3% above the LIBOR rate.
As of March 15, 2001, all amounts were borrowed under the LIBOR option at an
effective interest rate of 8.04% through August 27, 2001. The Fortis Credit
Agreement also contains a provision that the LIBOR rate margin will increase to
3.5% at September 30, 2001 and 4.0% at December 31, 2001 if the Company has not
raised $10.0 million of additional equity. The Fortis Credit Agreement has
covenants that restrict the payment of cash dividends, borrowings, sale of
assets, loans to others, investment and 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.

CASH FLOW AND CAPITAL PROJECTS

During the year 2000, the Company borrowed $4.6 million under the Fortis
Credit Agreement and generated $18.2 million of EBITDA (earnings before
interest, taxes, depreciation and amortization) of which it used $14.1 million
to continue development of the Field and $8.3 million to service interest on
borrowings. Field development in year 2000 consisted of drilling 44 wells and
converting 41 wells to water injection along with the continued extension of the
gas gathering and water delivery infrastructures.

The Company's capital budget for development of the Field in year 2001 is
$17.0 million net to the Company. The Company plans to drill 52 wells and
convert 50 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 the next
year. 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.

RECENTLY ADOPTED ACCOUNTING STANDARDS

In September 2000, the Emerging Issues Task Force reached a consensus
on issue No. 00-10, "Accounting for Shipping and Handling Fees and Costs" (EITF
No. 00-10"), which requires shipping and handling costs to be reflected as an
operating expense rather than as a reduction of revenue. The Company was
required to adopt the provisions of EITF No. 00-10 in the fourth quarter of
2000. Therefore, transportation costs are included in lease operating expenses
for 2000 on the accompanying statement of operations. The Company has assessed
the impact of this standard and has determined that the EITF does not have any
significant impact on prior periods. Adoption of the provisions of EITF No.
00-10 had no impact on net income.

In June 1998, SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities" ("SFAS No. 133") was issued, which establishes accounting
and reporting standards for derivative instruments and hedging activity. SFAS
No. 133 requires recognization of all derivative instruments on the balance
sheet as either assets or liabilities and measurement of fair value. Changes in
the derivative's fair value will be recognized currently in earnings unless
specific hedge accounting criteria are met. Gains and losses on derivate hedging
instruments must be recorded in either other comprehensive income or current
earnings, depending on the nature and designation of the instrument. The impact
of adopting SFAS No. 133 on January 1, 2001 results in recording a liability of
$1,927,000 and recording a cumulative effect of a change in accounting principle
as accumulated comprehensive loss in the equity section of $2,086,000 and income
recorded as cumulative effect of accounting change to the statement of
operations of $159,000.

DELISTING OF COMMON STOCK

Effective with the close of business July 28, 1999, the Company's
Common Stock was delisted from the Nasdaq SmallCap Market. The Company was no
longer able to satisfy the net tangible asset maintenance standard for continued
listing. The Company's Common Stock is now traded on the NASD over-the-counter
bulletin board under the same symbol "INLN".

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 2000 or 1999.

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,
foreign currency exchange 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 April 1, 2002. As of December 31, 2000, the
Fortis Credit Agreement had a principal balance of $83,500,000. At March 1,
2001, the Company locked in the interest rate at 8.04% per annum through August
27, 2001. Assuming the principal is paid according to the terms of the loan, an
increase in interest rates could result in an increase in interest expense on
the existing principal balance for the remaining term of the loan, as shown by
the following chart:

Increase in Interest Expense Without Hedge
------------------------------------------
January 1, 2001 January 1, 2002
through through
December 31, 2001 April 1, 2002
----------------- ---------------

1% increase in Interest Rates $278,000 $209,000
2% increase in Interest Rates $556,000 $418,000

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

20
22

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.

Inland has entered into various contracts in the form of swaps or
collars to hedge crude oil production during calendar years 2001 and 2002. The
potential gains or (losses) on these contracts based on a hypothetical average
market price of equivalent product for these periods are as follows:

Average NYMEX Per Barrel Market Price for the Contract Period
----------------------------------------------------------------------------------------------
$20.00 $22.00 $24.00 $26.00 $28.00 $30.00 $32.00
-------- -------- ----------- ----------- ----------- ----------- -----------

All Contracts - 2001 $761,000 $215,000 $(1,190,000) $(2,447,000) $(3,879,000) $(5,379,000) $(6,879,000)
All Contracts - 2002 $540,000 $180,000 $ -0- $ (111,000) $ (439,000) $ (799,000) $(1,159,000)

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

None.

[THIS SPACE INTENTIONALLY LEFT BLANK]

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23

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

DIRECTORS AND EXECUTIVE OFFICERS

The following table provides information as of March 15, 2001, with
respect to each of the Company's directors and executive officers:

SERVED AS EXECUTIVE
OFFICER OR
NAME AGE POSITION DIRECTOR SINCE
---- --- -------- -------------------

DIRECTORS

John D. Lomax(1) 76 Director (Chairman) 1999
Marc MacAluso(1) 40 Director, Chief Executive 1999
Officer and Chief
Operating Officer

Bill I. Pennington 49 Director, President and 1994
Chief Financial Officer

T Brooke Farnsworth(1) 56 Director 1999

OTHER EXECUTIVE OFFICERS

Michael J. Stevens 35 Vice President, Secretary 1993
and Treasurer
William T. War 58 Vice President 1998

- ----------

(1) Member of the Audit Committee.

JOHN D. LOMAX. Mr. Lomax has served as Chairman since September 23,
1999 and a director of the Company since September 13, 1999. He also served as
Chairman and a director of the Company from September 1994 until September 1996.
Mr. Lomax has been retired for the past five years.

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 Inland Production Company
("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.

T BROOKE FARNSWORTH. Mr. Farnsworth was appointed as a director on
September 13, 1999. He was a director of the Company from September 1994 until
September 1996. Mr. Farnsworth has practiced law in Houston, Texas for more than
29 years, where presently he is the Managing Partner of the law firm of
Farnsworth & vonBerg. He served as Secretary of IPC from 1985 until September
21, 1994 and as a director of IPC from 1992 until September 21, 1994.

MICHAEL J. STEVENS. Mr. Stevens has been the Controller of the Company
since June 28, 1993, the Secretary since September 30, 1993, and a Vice
President since April 30, 1997. He was the Treasurer of the Company from
September 30, 1993 until September 21, 1994, and was reappointed as Treasurer on
March 22, 1996. Mr. Stevens is a certified public accountant. Mr. Stevens is
leaving the Company and taking a position with another company in May 2001.

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.

On March 22, 2001, Hampton Investments LLC, as the owner of Series E
Preferred Stock, notified the Company that it was exercising its right to
appoint Bruce M. Schnelwar to the Board.

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 2000.

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 two
other most highly compensated executive officers for the year ended December 31,
2000 (collectively, the "Named Officers") in salary and bonus for services
rendered in all capacities to the Company for the fiscal years ended December
31, 2000, 1999 and 1998:

ANNUAL COMPENSATION LONG TERM COMPENSATION
------------------- --------------------------
SECURITIES
UNDERLYING
OTHER ANNUAL OPTIONS OR ALL OTHER
NAME/PRINCIPAL POSITION YEAR SALARY BONUS COMPENSATION WARRANTS COMPENSATION
- ----------------------- ---- ------ ----- ------------ -------- ------------

Bill I. Pennington, Chief 2000 $250,000 $ -- $10,200 -- --
Executive Officer(1) 1999 $201,000 -- $ 6,544 87,500(3) --
1998 $175,000 -- $21,705(2) -- --

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25

Michael J. Stevens, 2000 $130,000 $50,000 $10,200 -- --
Vice President, Secretary and 1999 $102,000 $50,000 $ 6,459 29,200(3) --
Treasurer 1998 $100,000 -- $13,933(4) -- --

William T. War, 2000 $175,000 $50,000 $10,200 -- --
Vice President 1999 $162,000 -- $ 5,020 25,000 --
1998 $ 54,000 -- -- -- --

- ---------

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

(2) Vacation compensation in 1998 for Mr. Pennington totaled $12,453 and
401(k) matching compensation totaled $9,252.

(3) These options were mutually terminated by the Company and each officer
effective February 1, 2001.

(4) Vacation compensation in 1998 for Mr. Stevens totaled $7,933 and 401(k)
matching compensation totaled $6,000.

Option/Warrant/SAR Grants. The following table sets forth certain
information regarding options, warrants and SARs granted during 2000:

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%($)
---- --------------------- --------------------- ---------- ---------- ----- ------

Bill I. Pennington -- -- -- -- -- --

Michael J. Steve -- -- -- -- -- --

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

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, 2000:

NUMBER OF SECURITIES VALUE OF UNEXERCISED
UNDERLYING UNEXERCISED IN-THE-MONEY OPTIONS
NUMBER OF SHARES OPTIONS AT FISCAL YEAR END AT FISCAL YEAR END (1)
ACQUIRED ON REALIZED -------------------------- --------------------------
NAME EXERCISE VALUE UNEXERCISABLE EXERCISABLE UNEXERCISABLE EXERCISABLE
---------------- -------- ------------- ----------- ------------- -----------

Bill I. Pennington -- -- 17,500(2) 70,000(2) -- --
Michael J. Stevens -- -- 5,840(2) 23,260(2) -- --
William T. War -- -- 5,000 20,000 -- --

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

(1) Value is based on the closing bid price of $0.94 per share on
December 31, 2000.
(2) These options were mutually terminated by the Company and each officer
on February 1, 2001.

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26

Long-Term Incentive Plans. The following table sets forth certain
information regarding long-term incentive awards granted during 2000 to the
Named Officers:

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

Bill I. Pennington -- 12/31/05(1) $250,000 $250,000 $250,000

Michael J. Stevens -- 12/31/05(1) $125,000 $125,000 $125,000

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

- ---------

(1) The Employment Agreements of Messrs. Pennington and Stevens provide for
a performance bonus of $250,000 and $125,000, respectively, vesting ratably
over a three year period if they continue to be employed on each of
December 31, 2000, 2001 and 2002, based on the Company meeting or exceeding
total earnings before interest, taxes, depreciation and amortization
("EBITDA"). However, the Employment Agreements were terminated February 1,
2001 by mutual agreement between the Company and Messrs. Pennington and
Stevens.

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, except that Messrs. Lomax and Farnsworth were each paid $35,000 in
year 2000 for serving on a special committee of the Board. The Board of
Directors may grant discretionary options to directors.

Employment Agreements. The Company entered into new employment
agreements with Messrs. Pennington and Stevens effective February 1, 2001,
pursuant to which the Company and Messrs. Pennington and Stevens mutually agreed
to terminate their prior employment agreements and Messrs. Pennington and
Stevens agreed to cancel all outstanding options granted to them. Effective
February 1, 2001, the Company also entered into an employment agreement with Mr.
MacAluso.

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. 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

25
27

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. It is estimated that these expenses
will total $20,000. In addition, the Company agreed to purchase the equity in
Mr. MacAluso's house in Houston for $141,000 (based on appraised value) and has
assumed the financial responsibility for its ultimate sale.

Under Mr. Stevens' new employment agreement, he is employed by the
Company through May 31, 2001 at a base salary of $43,000 for the term of the
agreement. Upon termination of the employment agreement, unless it is terminated
for cause, the Company will pay Mr. Stevens $100,000 and he shall be entitled to
keep all of his office furniture and computer. If he is terminated without cause
prior to May 31, 2001, the Company will also pay him the unpaid portion of his
$43,000 base salary.

Mr. War's employment agreement was also 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 upon
execution of the amendment and will be paid $25,000 on December 31, 2001, or
earlier if his employment is terminated prior to such date, unless it is
terminated for cause by the Company. Additionally, he will be entitled to six
months' base salary ($87,500) pursuant to the Company's severance policy if his
employment is terminated following a change in control prior to expiration of
the term of his employment agreement.

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. Mr. Pennington,
the Chief Executive Officer of the Company during 2000, participated in
deliberations by the Board of Directors concerning executive officer
compensation during 2000.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information regarding the
ownership of Common Stock, Series D Preferred Stock and Series E Preferred Stock
as of March 20, 2001, by each stockholder known to the Company to own
beneficially more than five percent of the outstanding Common Stock, Series D
Preferred Stock or Series E Preferred 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:

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28

PREFERRED STOCK COMMON STOCK
--------------------- --------------------
NUMBER NUMBER
NAME AND ADDRESS OF OF
OF BENEFICIAL OWNER SHARES PERCENT SHARES PERCENT
------------------- ------ ------- ------ -------

SERIES D
PREFERRED STOCK

Inland Holdings Llc (1) 10,757,747 100.0 1,752,586 60.5
TCW Asset
Management Company
865 S. Figuero
Suite 1800
Los Angeles, California 90017

SERIES E
PREFERRED STOCK

Pengo Securities Corp.(2) 121,973 100.0 840,436 29.0
885 Third Avenue, 34th Floor
New York, New York 10022

Marc MacAluso (3) -- -- 150,000 4.9
410 17th Street
Suite 700
Denver, Colorado 80202

John D. Lomax (3) -- -- 2,816 *
791 Nyes Place
Laguna Beach, CA 92651

Bill I. Pennington (3) -- -- 155,668 5.1
410 17th Street
Suite 700
Denver, Colorado 80202

T Brooke Farnsworth (3) -- -- 300 *
333 North Sam Houston Parkway
Suite 300
Houston, Texas 77060

Michael J. Stevens -- -- -- --
410 17th Street
Suite 700
Denver, Colorado 80202

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

All executive officers and -- -- 333,784 10.4
directors as a group
(6 persons) (3)

- ----------

* Less than 1%

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29

(1) 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.
The holder of Series D Preferred Stock has the right to appoint four members to
the Board.

(2) Pengo Securities Corp. ("Pengo"), an affiliate of Smith Management LLC
("Smith Management") owns of record and beneficially 412,927 shares of Common
Stock. Smith Energy Partnership, an affiliate of Smith Management, owns of
record and beneficially 15,222 shares of Common Stock. Randall D. Smith owns of
record and beneficially 87,441 shares. Jeffrey A. Smith and John W. Adams, both
of whom are officers and directors of Pengo and Smith Management, each own
16,374 shares of Common Stock. Hampton Investments LLC ("Hampton") is the record
and beneficial owner of 121,973 shares of Series E Preferred Stock and 292,098
shares of Common Stock. The 412,927 shares of Common Shares owned by Pengo and
the 15,222 shares of Common Stock owned by Smith Energy Partnership may be
deemed beneficially owned by Pengo Industries, Inc. The 292,098 shares of Common
Stock owned by Hampton may be deemed beneficially owned by Randall D. Smith
collectively, Pengo, Pengo Industries, Inc., Hampton and Messrs. Randall D.
Smith, Adams and Jeffrey A. Smith beneficially own the 840,436 shares of Common
Stock included in the table. Except as provided in this note regarding their
respective beneficial ownership, the parties disclaim beneficial ownership of
any of the shares included in the table. Hampton, as the holder of Series E
Preferred Stock, has the right, at its election, to appoint one member to the
Board, and on March 22, 2001 advised the Company that it was electing Bruce M.
Schnelwar to the Company's Board.

(3) Includes shares issuable under outstanding stock options and warrants
granted to Messrs. MacAluso, Lomax, Pennington, Farnsworth and War and all
executive officers and directors as a group for 150,000, 100, 150,000, 300,
25,000 and 325,400 shares, respectively.

In connection with the Exchange Agreement discussed under Items 1 and 2
"Business and Properties - Recent Developments - Change of Control and
Recapitalization", Inland, Holdings, Fund V and Pengo, Smith Energy Partnership,
Randall D. Smith, Jeffrey A. Smith, Barbara Stovall Smith, John W. Adams and
Arthur J. Pasmas (collectively, the "Smith Group") entered into a Shareholders
Agreement which sets forth certain rights among Holdings, JEDI and the Smith
Group relating to transfers of shares and certain voting rights. Under the
Shareholders Agreement, Holdings, JEDI and the Smith Group agreed with each
other to vote their respective shares to ensure that the Board of Inland would
consist of six members and that one member would be designated for election to
the Board by the holders of Common Stock and Series Z Preferred Stock. Each of
JEDI and Holdings further agreed not to vote their respective shares of Common
Stock and Series Z Preferred Stock in the election of such one designated Board
member for as long as they owned Series D Preferred Stock or Series E Preferred
Stock and the Smith Group continued to hold 10% or more of the combined
outstanding shares of Common Stock and Series Z Preferred Stock, provided, that
if Holdings does not at such time hold enough Series D Preferred Stock to
entitle it to elect four members to the Board, Holdings will be entitled to vote
an amount of its Common Stock proportionate to the reduction in number of
directors it is entitled to designate as a holder of Series D Preferred Stock.
Each member of the Smith Group agreed not to vote their shares of Common Stock
for the election of the one board member to be designated for election by the
holders of Common Stock and Series Z Preferred Stock as long as it continued to
hold 10% or more of the combined outstanding shares of Common Stock and Series Z
Preferred Stock. On March 20, 2001, Hampton Investments LLC, an entity related
to the Smith Group, purchased the Series E Preferred Stock and Common Stock
owned by JEDI and the rights of JEDI under the Shareholders Agreement.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Registration Rights Agreement. In connection with the Exchange
Agreement discussed under Items 1 and 2 "Business and Properties - Recent
Developments - Change of Control and Recapitalization," the Company entered into
a Registration Rights Agreement (the "Registration Agreement") with Holdings,
Portfolio, JEDI and the Smith Group pursuant to which the Company granted
Holdings, JEDI and the Smith Group piggy-back registration rights to include
their shares on any registration statement filed by the Company under the
Securities Act of 1933, as amended, subject to standard underwriters' kick-out
clauses and other conditions. The Company also granted to Holdings, JEDI and the

28
30

Smith Group demand registration rights which entitle Holdings to require the
Company to file up to three registration statements to register its shares,
entitle JEDI to require the Company to file up to two registration statements to
register its shares and entitle the Smith Group to require the Company to file
one registration statement to register its shares. 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 ("Smith Management") effective June 1, 1998. As of December
31, 1998, SEP, an affiliate of Smith Management, received 152,220 pre-split
(15,222 post-split) 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, Smith Management and the
Company's senior lenders agreed to recommence such rights. In addition, a
provision was added that gave Smith Management 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 only to be paid if the Company's senior lenders agreed to
such payment. The Farmout Agreement was further amended on September 21, 1999 as
part of the 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 Smith Management will reconvey all
drillsites to the Company once Smith Management 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 will
receive $200,000 annually for consulting services to be provided to the Company
until September 21, 2002. Mr. Pasmas has been Vice President of Smith Management
(or affiliated entities) since 1987.

[THIS SPACE INTENTIONALLY LEFT BLANK.]

29
31

PART IV

ITEM 14. 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 Credit Agreement dated September 23, 1997 between Inland
Production Company ("IPC"), Inland, ING (U.S.) Capital
Corporation, as Agent, and Certain Financial Institutions, as
banks (filed as Exhibit 4.1 to Inland's Current Report on Form
8-K dated September 23, 1997, and incorporated herein by
reference).

4.1.1 Third Amendment to Credit Agreement entered into as of April
22, 1998, amending Exhibit 4.1 (filed as Exhibit 4.1.1 to
Inland's Quarterly Report on Form 10-Q for the quarter ended
March 31, 1998, and incorporated herein by reference).

30
32

4.1.2 Amended and Restated Credit Agreement dated as of September
11, 1998 amending and restating Exhibit 4.1 (filed as Exhibit
4.1.2 to Inland's Annual Report on Form 10-K for the year
ended December 31, 1998, and incorporated herein by
reference).

4.1.3 First Amendment to Amended and Restated Credit Agreement dated
as of March 5, 1999 amending Exhibit 4.1.2 (filed as Exhibit
4.1.3 to Inland's Annual Report on Form 10-K for the year
ended December 31, 1998, and incorporated herein by
reference).

4.1.4 Second Amended and Restated Credit Agreement dated September
15, 1999, but effective as of September 21, 1999, amending and
restating Exhibit 4.1 (without exhibits or schedules) (filed
as Exhibit 4.1 to Inland's Current Report on Form 8-K dated
September 21, 1999, and incorporated herein by reference).

4.2 Credit Agreement dated September 23, 1997, among IPC, Inland,
Trust Company of the West, and TCW Asset Management Company,
in the capacities described therein (filed as Exhibit 4.2 to
Inland's Current Report on Form 8-K dated September 23, 1997,
and incorporated herein by reference).

4.2.1 Second Amendment to Credit Agreement entered into as of April
22, 1998, amending Exhibit 4.2 (filed as Exhibit 4.2.1 to
Inland's Quarterly Report on Form 10-Q for the quarter ended
March 31, 1998, and incorporated herein by reference).

4.2.2 Amended and Restated Credit Agreement dated as of September
11, 1998, amending and restating Exhibit 4.2 (filed as Exhibit
4.2.2 to Inland's Annual Report on Form 10-K for the year
ended December 31, 1998, and incorporated herein by
reference).

4.2.3 First Amendment to Amended and Restated Credit Agreement dated
as of March 5, 1999, amending Exhibit 4.2.2 (filed as Exhibit
4.2.3 to Inland's Annual Report on Form 10-K for the year
ended December 31, 1998, and incorporated herein by
reference).

4.2.4 Exchange Agreement dated as of September 21, 1999 by and
between Inland, IPC, Refining, Trust Company of the West, a
California trust company, as Sub-Custodian for Mellon Bank
for the benefit of Account No. CPFF 873-3032, Inland Holdings
LLC, TCW Portfolio No. 1555 DR V Sub-Custody Partnership, L.P.
and Joint Energy Development Investments II Limited
Partnership (without exhibits or schedules), terminating
Exhibits 4.2 and 4.3, as previously amended, and Exhibits 4.4,
4.5, 10.10 and 10.11 (filed as Exhibit 10.1 to Inland's
Current Report on Form 8-K dated September 21, 1999, and
incorporated herein by reference).

4.3 Intercreditor Agreement dated September 23, 1997, between IPC,
TCW Asset Management Company, Trust Company of the West and
ING (U.S.) Capital Corporation (filed as Exhibit 4.3 to
Inland's Current Report on Form 8-K dated September 23, 1997,
and incorporated herein by reference).

4.3.1 Third Amendment to Intercreditor Agreement entered into as of
April 22, 1998, amending Exhibit 4.3 (filed as Exhibit 4.3.1
to Inland's Quarterly Report on Form 10-Q for the quarter
ended March 31, 1998, and incorporated herein by reference).

4.3.2 Amended and Restated Intercreditor Agreement dated as of
September 11, 1998, amending and restating Exhibit 4.3 (filed
as Exhibit 4.3.2 to Inland's Annual Report on Form 10-K for
the year ended December 31, 1998, and incorporated herein by
reference).

31
33

4.3.3 First Amendment to Amended and Restated Intercreditor
Agreement dated as of March 5, 1999, amending Exhibit 4.3.2
(filed as Exhibit 4.3.3 to Inland's Annual Report on Form 10-K
for the year ended December 31, 1998, and incorporated herein
by reference).

4.4 Warrant Agreement by and between Inland and TCW Portfolio No.
1555 DR V Sub-Custody Partnership, L.P. dated September 23,
1997 (filed as Exhibit 4.4 to Inland's Current Report on Form
8-K dated September 23, 1997, and incorporated herein by
reference).

4.5 Warrant issued by Inland pursuant to the Warrant Agreement,
dated September 23, 1997, representing the right to purchase
100,000 shares of Inland's Common Stock (filed as Exhibit 4.5
to Inland's Current Report on Form 8-K dated September 23,
1997, and incorporated herein by reference).

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).

10.3 Interest Rate Cap Agreement dated April 30, 1998 between IPC
and Enron Capital and Trade Resources Corp. (filed as Exhibit
10.4 to Inland's Quarterly Report on Form 10-Q for the quarter
ended March 31, 1998, 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).

10.5 Warrant Agreement dated as of March 5, 1999 between Inland
Resources Inc. and TCW Portfolio No. 1555 DR V Sub-Custody
Partnership, L.P. (filed as Exhibit 10.20 to Inland's Annual
Report on Form 10-K for the year ended December 31, 1998, and
incorporated herein by reference).

10.6 Warrant Certificate dated March 5, 1999 between Inland and TCW
Portfolio No. 1555 DR V Sub-Custody Partnership, L.P.
representing 5,852 shares (filed as Exhibit 10.21 to Inland's
Annual Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).

32
34

10.7 Shareholders Agreement dated as of September 21, 1999 between
Inland, Holdings, Fund V, JEDI and Pengo Securities Corp.,
Smith Energy Partnership, Randall D. Smith, Jeffrey A. Smith,
Barbara Stovall Smith, John W. Adams and Arthur J. Pasmas
(collectively, the "Smith Group") (filed as Exhibit 10.2 to
Inland's Current Report on Form 8-K dated September 21, 1999,
and incorporated herein by reference).

10.8 Registration Rights Agreement dated as of September 21, 1999
between Inland, Holdings, Portfolio, JEDI and the Smith Group
filed as Exhibit 10.3 to Inland's Current Report on Form 8-K
dated September 21, 1999, and incorporated herein by
reference).

10.9 Severance Agreement between Inland and John E. Dyer dated
November 18, 1999 (filed as Exhibit 10.13 to Inland's Annual
Report on Form 10-K for the year ended December 31, 1999, 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.

*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.

*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.

*21.1 Subsidiaries of Inland.

*23.1 Consent of Arthur Andersen LLP.

*23.2 Consent of Ryder Scott Company Petroleum Engineers.

- ---------
* Filed herewith

33
35

(b) Reports on Form 8-K

None.

[THIS SPACE INTENTIONALLY LEFT BLANK]

34
36

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 30, 2001
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.

March 29, 2001 /s/ JOHN D. LOMAX
-------------------------------
John D. Lomax
Chairman of the Board

March 30, 2001 /s/ MARC MACALUSO
-------------------------------
Marc MacAluso
Director, Chief Executive Officer and Chief
Operating Officer (Principal Executive Officer)

March 30, 2001 /s/ BILL I. PENNINGTON
-------------------------------
Bill I. Pennington
Director, President and Chief Financial Officer
(Principal Financial Officer)

March 27, 2001 /s/ T BROOKE FARNSWORTH
-------------------------------
T Brooke Farnsworth
Director

March 30, 2001 /s/ MICHAEL J. STEVENS
-------------------------------
Michael J. Stevens
Vice President, Secretary and Treasurer
(Principal Accounting Officer)

35
37

INDEX TO FINANCIAL STATEMENTS

PAGE
----

Report of Independent Public Accountants ............................... F-2
Consolidated Balance Sheets, December 31, 2000 and 1999 ................ F-3
Consolidated Statements of Operations for the three years ended
December 31, 2000, 1999 and 1998 ................................ F-5
Consolidated Statements of Stockholders' Equity for the
three years ended December 31, 2000, 1999 and 1998 .............. F-7
Consolidated Statements of Cash flows for the three years ended
December 31, 2000, 1999 and 1998 ................................ F-8
Notes to Consolidated Financial Statements ............................. F-9

F-1
38
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, 2000 and
1999, and the related consolidated statements of operations, stockholders'
equity (deficit) and cash flows for each of the three years in the period ended
December 31, 2000. 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, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.

/s/ ARTHUR ANDERSEN LLP
Denver, Colorado,
March 29, 2001.

F-2
39

INLAND RESOURCES INC.

CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)

December 31,
----------------------
ASSETS 2000 1999
--------- ---------

CURRENT ASSETS:
Cash and cash equivalents $ 848 $ 1,018
Accounts receivable and accrued sales 5,284 2,166
Inventory 835 1,287
Other current assets 381 50
Net current assets of discontinued operations -- 2,140
--------- ---------
Total current assets 7,348 6,661
--------- ---------
PROPERTY AND EQUIPMENT, AT COST:
Oil and gas properties (successful efforts method) 183,959 170,217
Accumulated depletion, depreciation and amortization (35,004) (27,805)
--------- ---------
Total oil and gas properties, net 148,955 142,412

Other property and equipment, net 1,997 2,437
--------- ---------
Total property and equipment, net 150,952 144,849

OTHER LONG-TERM ASSETS 1,765 1,892
--------- ---------
Total assets $ 160,065 $ 153,402
========= =========

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

F-3
40

INLAND RESOURCES INC.

CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)

December 31,
----------------------
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) 2000 1999
--------- ---------

CURRENT LIABILITIES:
Accounts payable $ 2,141 $ 3,422
Accrued expenses 3,391 1,759
--------- ---------
Total current liabilities 5,532 5,181

LONG-TERM DEBT 83,500 79,082

COMMITMENTS AND CONTINGENCIES (Notes 1 and 11)

MANDATORILY REDEEMABLE PREFERRED STOCK:
Series D Stock, 10,757,747 shares issued and outstanding,
liquidation preference of $80.7 million 68,273 61,973
Accrued preferred series D dividends 11,994 2,262

Series E Stock, 121,973 shares issued and outstanding, liquidation
preference of $12.2 million 9,120 8,220
Accrued preferred series E dividends 1,856 350

STOCKHOLDERS' EQUITY (DEFICIT):
Preferred Class A stock, par value $.001; 20,000,000 shares authorized,
Series D and Series E outstanding

Common stock, par value $.001; 25,000,000 shares authorized,
2,897,732 issued and outstanding 3 3
Additional paid-in capital 51,157 69,595
Accumulated deficit (71,370) (73,264)
--------- ---------
Total stockholders' deficit (20,210) (3,666)
--------- ---------
Total liabilities and stockholders' deficit $ 160,065 $ 153,402
========= =========

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

F-4
41

INLAND RESOURCES INC.

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

For the Years Ended December 31,
--------------------------------
2000 1999 1998
-------- -------- --------

REVENUES:
Oil and gas sales $ 28,497 $ 16,399 $ 21,278

OPERATING EXPENSES:
Lease operating expenses 7,596 7,160 8,362
Production taxes 483 192 454
Exploration 135 155 153
Impairment -- -- 1,327
Depletion, depreciation and amortization 7,816 9,882 12,025
General and administrative, net 2,128 3,136 2,061
-------- -------- --------
Total operating expenses 18,158 20,525 24,382
-------- -------- --------
OPERATING INCOME (LOSS) 10,339 (4,126) (3,104)
Interest expense (8,298) (15,989) (14,895)
Interest and other income 103 72 107
-------- -------- --------
NET INCOME (LOSS) FROM CONTINUING OPERATIONS
BEFORE EXTRAORDINARY LOSS 2,144 (20,043) (17,892)

LOSS FROM DISCONTINUED OPERATIONS -- (1,774) (5,560)

LOSS ON SALE OF DISCONTINUED OPERATIONS (250) (14,500) --
-------- -------- --------
NET INCOME (LOSS) BEFORE EXTRAORDINARY LOSS 1,894 (36,317) (23,452)

EXTRAORDINARY LOSS ON EARLY EXTINGUISHMENT
OF DEBT -- (556) --
-------- -------- --------
NET INCOME (LOSS) AND COMPREHENSIVE
INCOME (LOSS) 1,894 (36,873) (23,452)

Accrued preferred series C dividends -- (663) (1,084)
Accrued preferred series D dividends (9,732) (2,262) --
Accrued preferred series E dividends (1,506) (350) --
Accretion of preferred series D discount (6,300) (1,473) --
Accretion of preferred series E discount (900) (220) --
-------- -------- --------
NET LOSS ATTRIBUTABLE TO COMMON
STOCKHOLDERS $(16,544) $(41,841) $(24,536)
======== ======== ========

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

F-5
42

INLAND RESOURCES INC.

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

For the Years Ended December 31,
------------------------------------
2000 1999 1998
---------- ---------- --------

BASIC AND DILUTED NET LOSS PER SHARE:
Continuing operations $ (5.62) $ (17.56) $ (22.62)
Discontinued operations -- (1.25) (6.63)
Sale of discontinued operations (0.09) (10.18) --
Extraordinary loss -- (0.38) --
---------- ---------- --------
Total $ (5.71) $ (29.37) $ (29.25)
========== ========== ========

Basic and diluted weighted average common
shares outstanding 2,897,732 1,424,439 838,790
========== ========== ========

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

F-6
43

INLAND RESOURCES INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
(In thousands, except share amounts)

Common Stock Additional
--------------------- Paid-In Accumulated
Shares Amount Capital Deficit
--------- --------- --------- ---------

BALANCES, December 31, 1997 835,983 $ 1 $ 41,863 $ (11,192)

Issuance of common stock under
Farmout Agreement 15,222 -- 866 --
Accrued Preferred Series C dividends -- -- -- (1,084)
Exercise of employee stock options 1,772 -- 37 --
Net loss -- -- -- (23,452)
--------- --------- --------- ---------
BALANCES, December 31, 1998 852,977 1 42,766 (35,728)

Accrued Preferred Series C dividends -- -- -- (663)
Common stock including Preferred Series Z
stock issued in exchange of TCW debt 1,164,295 1 21,698 --
Common stock issued in exchange of JEDI
Preferred Series C stock 292,098 -- 3,600 --
Other 71 -- -- --
Net gain under related party transaction -- -- 5,836 --
Accretion of Preferred Series D discount -- -- (1,473) --
Accretion of Preferred Series E discount -- -- (220) --
Accrued Preferred Series D dividends -- -- (2,262) --
Accrued Preferred Series E dividends -- -- (350) --
Conversion of Preferred Series Z stock to
common stock 588,291 1 -- --
Net loss -- -- -- (36,873)
--------- --------- --------- ---------
BALANCES, December 31, 1999 2,897,732 3 69,595 (73,264)

Accretion of Preferred Series D discount -- -- (6,300) --
Accretion of Preferred Series E discount -- -- (900) --
Accrued Preferred Series D dividends -- -- (9,732) --
Accrued Preferred Series E dividends -- -- (1,506) --
Net income -- -- -- 1,894
--------- --------- --------- ---------
BALANCES, December 31, 2000 2,897,732 $ 3 $ 51,157 $ (71,370)
========= ========= ========= =========

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

F-7
44

INLAND RESOURCES INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(See Note 10)
(In thousands)

For the Years Ended December 31,
--------------------------------
2000 1999 1998
-------- -------- --------

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 1,894 $(36,873) $(23,452)
Adjustments to reconcile net income (loss) to net cash
provided (used) by operating activities
Loss from discontinued operations 250 16,274 5,348
Depletion, depreciation and amortization 7,816 9,882 12,025
Amortization of debt issuance costs and debt discount 480 762 587
Loss on disposition of assets 51 -- --
Loss on early extinguishment of debt -- 556 --
Noncash interest consideration -- 8,592 866
Impairment of assets -- -- 1,327
Effect of changes in current assets and liabilities--
Accounts receivable and accrued sales (3,118) (800) 1,662
Inventory 452 128 578
Other assets (184) 16 1,869
Accounts payable and accrued expenses 351 (6,050) 6,012
-------- -------- --------
Net cash provided (used) by operating activities 7,992 (7,513) 6,822
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Development expenditures and equipment purchases (14,137) (3,772) (39,391)
-------- -------- --------
Net cash used in investing activities (14,137) (3,772) (39,391)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common stock -- -- 37
Proceeds from issuance of long-term debt 4,585 11,581 47,750
Payments of long-term debt -- (86) (9)
Debt issuance costs (500) (493) (702)
Restructuring costs related to Series D and Series E -- (500) --
-------- -------- --------
Net cash provided by financing activities 4,085 10,502 47,076
-------- -------- --------
NET CASH AND CASH EQUIVALENTS (USED) PROVIDED
BY CONTINUING OPERATIONS (2,060) (783) 14,507

NET CASH AND CASH EQUIVALENTS PROVIDED (USED)
BY DISCONTINUED OPERATIONS 1,890 526 (13,837)

CASH AND CASH EQUIVALENTS, at beginning of period 1,018 1,275 605
-------- -------- --------
CASH AND CASH EQUIVALENTS, at end of period $ 848 $ 1,018 $ 1,275
======== ======== ========

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

F-8
45

INLAND RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2000

1. BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Business

Inland Resources Inc. ("Inland" or the "Company") is an independent energy
company with substantially all of its producing oil and gas property interests
located in the Monument Butte 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"). The refinery had a processing capacity of approximately 10,000
barrels per day and tankage capacity of 485,000 barrels. 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 liquidated
pursuant to the plan of dissolution in 2000.

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 of continuing operations have been
eliminated in consolidation.

Reverse Split

On December 10, 1999, the Company's shareholders approved a 1-for-10 reverse
stock split of the Company's common stock. The effect of the stock split was to
lower the authorized common shares from 25,000,000 shares to 2,500,000 shares
and reduce outstanding common shares from 23,093,689 shares to 2,309,441 shares.
The shareholders further approved an increase in the number of post-split
authorized shares from 2,500,000 shares to 25,000,000. Par value remained at
$0.001 per common share. All per share disclosures including loss per share and
weighted average common and common equivalent shares outstanding as reported on
the consolidated balance sheet, consolidated statement of operations and
consolidated statement of stockholders' equity (deficit) have been calculated
based on post-reverse split share amounts.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with generally accepted
accounting principles 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. The impact of oil and gas
prices has a significant influence on estimates made by management. Changes in
oil and gas prices directly effect the economic limits of estimated oil and gas
reserves. These economic limits have significant effects upon predicted reserve
quantities and valuations. These estimates drive the calculation of depletion,
depreciation and amortization for the oil and gas

F-9

properties and the need for an assessment as to whether an impairment is
required. Overall 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 in a single financial institution which exceeds
depository insurance limits. The Company places such deposits with high credit
quality institutions and has not experienced any credit losses. Substantially
all of the Company's receivables are within the oil and gas industry, primarily
from its oil and gas purchasers and joint interest owners. Although diversified
within many companies, collectibility is dependent upon the general economic
conditions of the industry. To date, write-offs of uncollectible accounts have
been minimal.

Fair Value of Financial Instruments

The Company's financial instruments consist of cash, trade receivables, trade
payables, accrued liabilities, long-term debt, mandatorily redeemable preferred
stock 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 the preferred stock is not readily determinable
and long-term debt is based on variable rate interest and accordingly,
approximates fair value. The 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 and any gain or loss is charged to income. Interest is capitalized
during the drilling and completion period of wells and on other major projects.
The amount of interest capitalized was $120,000, $0 and $150,000 during 2000,
1999 and 1998, respectively.

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 are, in
management's opinion, offset by residual values of lease and well equipment. As
a result, no accrual for such costs is provided.

F-10
47

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 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, 2000 were based on an
average oil price of $19.07 per barrel and $2.83 per Mcf over the remaining
estimated life of the properties.

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.

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 provided 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.

Environmental

Environmental costs are expensed or capitalized based upon their future economic
benefit. Costs which are improvements are capitalized. Costs related to
environmental remediation and reclamation are expensed. Liabilities for
remediation and reclamation costs are accrued when it is determined that an
obligation exists and the amount of the costs can be reasonably estimated.

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 that the
tax benefits, based on available evidence, are not expected to be realized.

Revenue Recognition

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

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 all periods presented, there were no dilutive
securities.

F-11

Comprehensive Income (Loss)

In addition to net income (loss), comprehensive income (loss) includes all
changes in equity during a period, except those resulting from investments by
and distributions to owners. There are no items of comprehensive loss for any
periods presented. Beginning January 2001 with the adoption of SFAS No. 133, the
effective portion of changes in fair value of derivative instruments that
qualify for cash flow hedges will also be included in comprehensive income
(loss).

Recently Adopted Accounting Standards

In September 2000, the Emerging Issues Task Force reached a consensus on issue
No. 00-10, "Accounting for Shipping and Handling Fees and Costs" ("EITF No.
00-10"), which requires shipping and handling costs to be reflected as an
operating expense rather than as a reduction of revenue. The Company was
required to adopt the provisions of EITF No. 00-10 in the fourth quarter of
2000. Therefore, transportation costs are included in lease operating expenses
for 2000 on the accompanying statement of operations. The Company has assessed
the impact of this standard and has determined that the EITF does not have any
significant impact on prior periods. Adoption of the provisions of EITF No.
00-10 had no impact on net income.

Reclassifications

Certain amounts in prior years have been reclassified to conform to the 2000
presentation.

2. FINANCIAL INSTRUMENTS:

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 loss 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. The Company has not incurred any significant losses nor does the
Company expect any to occur.

In June 1998, SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS No. 133") was issued, which 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 and measurement of fair value. Changes in the
derivative's fair value will be 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. The impact
of adopting SFAS No. 133 on January 1, 2001 results in recording a liability of
$1,927,000 and recording a cumulative effect of a change in accounting principle
as accumulated comprehensive loss in the equity section of $2,086,000 and to
income recorded as cumulative effect of accounting change to the statement of
operations of $159,000.

Crude Oil Hedging Activities

The Company has various contracts that hedge crude oil production structured as
cost free collars whereby if the average monthly price, based on NYMEX Light
Sweet Crude Oil Futures Contracts, is between a floor and a ceiling, no payment
is exchanged between the parties. All contracts are with Enron Capital and Trade
Resources Corp ("Enron"). The Company has hedged 750,000 barrels of its
projected year 2001 oil production (approximately 60,000 barrels per month)
under various collars with floors ranging from $19.00 to $24.00 per barrel and
ceilings ranging from $20.80 to $26.75 per barrel. The Company has hedged
180,000 barrels of its projected year 2002 oil production (60,000 barrels per
month for January through March) under various collars with floors

F-12
49
at $23.00 per barrel and ceilings ranging from $24.77 to $26.35 per barrel. The
Company may enter into additional year 2001 and 2002 oil hedges depending on
market conditions. As of December 31, 2000, the fair value of these contracts is
a liability of $1,927,000.

During the year 2000, the Company hedged 720,000 barrels of crude oil production
under various collars from Enron. The Company recorded a reduction of revenue of
$6.1 million under these contracts.

During the period April 1, 1999 to December 31, 1999, the Company hedged oil
production under two contracts from Enron. The contracts were structured as
swaps covering 80,000 barrels per month at an average strike price of $14.28.
The Company recorded a reduction to revenue of $4.9 million under these
contracts during 1999.

During 1998 the Company had various contracts in place consisting of puts, calls
and collars. Each of the contracts was completely settled as of December 31,
1998. The effect of all hedging contracts in 1999 resulted in income of
$550,000.

3. LOSS PER SHARE:

The calculation of loss per share for the years ended December 31, 2000, 1999
and 1998 is as follows (in thousands, except per share data):

2000 1999 1998
-------------------------- ------------------------ -------------------------
Income Per Share Per Share Per Share
(Loss) Shares Amount Loss Shares Amount Loss Shares Amount
------ ------ --------- -------- ------ -------- -------- ------ -==-----

Income (loss) from continuing
operations before extraordinary
item $ 2,144 $(20,043) $(17,892)
Accrued Preferred Series C dividends -- (663) (1,084)
Accrued Preferred Series D dividends (9,732) (2,262) --
Accrued Preferred Series E dividends (1,506) (350) --
Accretion of Series D discount (6,300) (1,473) --
Accretion of Series E discount (900) (220) --
-------- ------- --------
BASIC AND DILUTED LOSS
PER SHARE:
Loss from continuing operations
before extraordinary loss
available to common
stockholders $(16,294) 2,898 $(5.62) $(25,011) 1,424 $(17.56) $(18,976) 839 $(22.62)
======== ====== ======== ====== ======== =======

4. RESTRUCTURING TRANSACTION:

On September 21, 1999, the Company entered into an Exchange Agreement (the
"Exchange Agreement") with Trust Company of the West and affiliated entities
("TCW") 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 (the "Recapitalization").

Pursuant to the Exchange Agreement, TCW agreed to exchange $75.0 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

F-13
50
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 (iii) 1,164,295 shares of Common Stock.
On December 14, 1999, all shares of Series Z Preferred Stock were converted into
588,291 shares of Common Stock. In addition, JEDI agreed to exchange 100,000
shares ($10.0 million par value) 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.

On March 20, 2001, Hampton Investments LLC ("Hampton") an affiliate of Smith
Management LLC, purchased from JEDI the 121,973 shares of Series E Preferred
Stock and 292,098 shares of Common Stock acquired by JEDI in the
recapitalization. Following closing of the Exchange Agreement and the purchase
by Hampton of JEDI's shares, TCW owns 1,752,586 shares of Common Stock,
representing approximately 60.5% of the outstanding shares of Common Stock, and
Hampton owns 292,098 shares of Common Stock, representing approximately 10.1% of
the outstanding shares of Common Stock. In connection with the Exchange
Agreement, the Articles of Incorporation (the "Articles") of the Company were
amended to designate the Series D Preferred Stock and Series E Preferred Stock.
The amended Articles provide 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, except as mandated by law or as expressly set
forth in the Articles. The Series D Preferred Stock and the Series E Preferred
Stock vote with the Common Stock on a share-for-share basis. Pursuant to the
amended Articles, the total number of votes of the combined class of Common
Stock, Series D Preferred Stock and Series E Preferred Stock outstanding at
December 31, 2000 is 3,985,704 votes, of which 2,828,361 votes (representing
approximately 71% of the total) are owned by TCW, and 304,295 votes
(representing approximately 7.6% of the total) are owned by Hampton. Various
persons and entities that may be considered related to Hampton on an additional
548,338 shares of Common Stock, so that together with Hampton such persons,
entities and Hampton own an aggregate of 840,436 shares of Common Stock and
852,633 votes (representing approximately 21.4% of the total).

Under the amended Articles, the Series D Preferred Stock accrues 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 may be
paid on Common Stock or any other series of preferred stock while there are any
accrued and unpaid dividends on the Series D Preferred Stock. The Series D
Preferred Stock also has liquidation preference over all other classes and
series of stock, in an amount equal to $7.50 per share ($80.7 million). The
Series D Preferred Stock may be redeemed at any time by the Company (subject to
the senior credit facility being repaid) for a redemption price of $7.50 per
share and must be redeemed in equal amounts over three years commencing upon the
earlier of September 21, 2004 or the repayment in full of the Company's existing
senior credit facility which is April 1, 2002. The difference between the book
value and the liquidation value of the Series D Preferred Stock at the exchange
date ($20.2 million) is being accreted over the minimum redemption period
beginning on April 1, 2002, and results in a charge against earnings available
for common stockholders. In addition to voting as a class with the Common Stock
and Series E Preferred Stock as discussed above, holders of 75% of the
outstanding shares of Series D Preferred Stock, voting as a separate voting
group, must approve any modification to the dividend rates, liquidation
preferences or other privileges of the Series D Preferred Stock, any merger or
consolidation of the Company in which the Company is not the surviving entity,
any transaction which will result in the holders of voting stock of the Company
immediately prior to such transaction owning less than 50% of the outstanding
voting stock of the Company after the transaction or the sale or other transfer
of substantially all of the assets of the Company. Further, a majority of the
outstanding shares of Series D Preferred Stock, voting as a separate voting
group, have the right to elect (i) four members of the Board for as long as at
least 37.5% of the original shares of Series D Preferred Stock remain
outstanding; (ii) three members of the Board for as long as at least 25%, but
less than 37.5% remain outstanding; (iii)

F-14

two members of the Board for as long as at least 12.5%, but less than 25% remain
outstanding; and (iv) one member of the Board for as long as any shares of
Series D Preferred Stock remain outstanding even though they are less than 12.5%
of the original shares issued. As the number of members that may be elected by
holders of Series D Preferred Stock decline, the holders of Common Stock are
entitled to elect those members to the Board.

Under the amended Articles, the Series E Preferred Stock accrues 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 may be
paid on Common Stock while there are any accrued and unpaid dividends on the
Series E Preferred Stock. The Series E Preferred Stock also has 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
Series E Preferred Stock may be redeemed at any time by the Company (subject to
the senior credit facility being repaid on April 1, 2002 and the Series D
Preferred Stock having been redeemed) for a redemption price of $100.00 per
share and must be redeemed upon the earlier of September 21, 2006 or the
redemption of all outstanding shares of Series D Preferred Stock. The difference
between the book value and the liquidation value of the Series E Preferred Stock
at the exchange date ($4.2 million) is being accreted over the minimum
redemption period to April 1, 2004, and results in a charge against earnings
available for common shareholders. In addition to voting as a class with Common
Stock and Series D Preferred Stock as discussed above, holders of 75% of the
outstanding shares of Series E Preferred Stock, voting as a separate voting
group, must approve any modification to the dividend rates, liquidation
preferences or other privileges of the Series E Preferred Stock; any merger or
consolidation of the Company in which the Company is not the surviving entity or
any transaction which will result in the holders of voting stock of the Company
immediately prior to such transaction owning less than 50% of the outstanding
voting stock of the Company after the transaction, unless, in either case, the
holders of Series E Preferred Stock receive shares with substantially the same
rights and preferences as correspond to the Series E Preferred Stock; any merger
in which the holders of Common Stock receive consideration in exchange for their
Common Stock other than Common Stock of the surviving corporation that is junior
to the securities issued to the holders of Series E Preferred Stock; or the sale
or other transfer of substantially all of the assets of the Company unless, so
long as the Series D Preferred Stock is outstanding, at least 60% of the Series
E Preferred Stock is redeemed or the holders of Series E Preferred Stock receive
an amount equal to 60% of 10/85ths of the total consideration received by the
holders of Series D Preferred Stock and Series E Preferred Stock in the same
form of consideration as that received by the holders of Series D Preferred
Stock. Further, a majority of the outstanding shares of Series E Preferred
Stock, voting as a separate voting group, have the right to elect one member of
the Board.

One of the conditions to closing the Exchange Agreement was that Inland's senior
lenders would enter into a restructuring of the senior credit facility
acceptable to TCW, JEDI and the Company. As a result, effective as of September
21, 1999, the Company entered into the Second Amended and Restated Credit
Agreement (the "Fortis Credit Agreement") whose current participants are Fortis
Capital Corp. and U.S. Bank National Association (the "Senior Lenders") pursuant
to which the Senior Lenders agreed to increase the borrowing base from $73.25
million to $83.5 million, inclusive of a sublimit for letters of credit of $4.0
million.

The Company also amended its Farmout Agreement with Smith Energy Partnership
("Smith") in conjunction with the financial restructuring on September 21, 1999.
The Farmout Agreement was originally entered into effective June 1, 1998. As of
December 31, 1998 Smith had received 15,222 (post reverse split) shares of
Common Stock as payment of net proceeds through October 31, 1998 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 the Company, Smith and the Company's senior lenders
agreed to recommence such rights. In addition, a provision was added that gave
Smith the option to receive cash rather than Common Stock if the average

F-15
52

stock price was calculated at less than $3.00 (post reverse split) per share,
such cash only to be paid if the Company's senior lenders agreed to such
payment. The Amendment to the Farmout Agreement on September 21, 1999 eliminated
this option and provided for cash payments only effective June 1, 1999. The
Amendment also allowed the Company to retain all proceeds under the Farmout
Agreement accrued from November 1, 1998 through May 31, 1999. As a result of
this Amendment, and the fact that the Company has no further obligations in
relation to these properties, the production loan previously recorded by the
Company is no longer considered outstanding. As a result, the Company has
removed all previously recorded drilling costs, accumulated depletion, debt
issue costs, loans and accrued interest as of September 21, 1999 and will no
longer record revenue and costs from wells drilled under the Farmout Agreement
in its Consolidated Statement of Operations or Consolidated Statement of Cash
Flows. The $5.8 million gain recognized upon the removal of previously recorded
account balances was charged directly to equity due to the related-party nature
of the transaction. The Farmout Agreement continues to provide that Smith will
reconvey all drillsites to the Company once Smith 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.

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 Woods Cross
refinery was originally purchased on December 31, 1997 for $22.9 million and the
Roosevelt refinery was originally purchased on September 16, 1998 for $2.25
million. 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 asset 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. To account for the sale, the Company recorded a loss on
sale of discontinued operations of $14.5 million at December 31, 1999. The
Company recorded an additional loss of $250,000 to reflect adjustments to the
final disposal costs associated with the refinery. In addition, certain prior
year amounts were reclassified as discontinued operations, with no net effect on
net loss or accumulated deficit as previously reported. Revenue from
discontinued operations was $70.3 million and $68.5 million during the years
ended December 31, 1999 and 1998, respectively. The net current assets of
discontinued operations at December 31, 1999 consist of $7.9 million of current
assets consisting primarily of inventory and accounts receivable, offset by $5.8
million of liabilities, primarily accounts payable and accrued liabilities.

F-16
53

6. OTHER PROPERTY AND EQUIPMENT:

December 31,
----------------
2000 1999
------- -------
(in thousands)

Vehicles $ 1,599 $ 1,579
Land and buildings 1,003 1,214
Furniture and fixtures 1,258 1,416
Leasehold improvements 86 86
------- -------
3,946 4,295

Less accumulated
depreciation (1,949) (1,858)
------- -------
Total $ 1,997 $ 2,437
======= =======

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

TCW and Fortis Credit Agreements

On September 30, 1997, the Company closed separate Credit Agreements with TCW
and ING (U.S.) Capital Corporation ("ING"). The TCW Credit Agreement provided
the Company with $75.0 million, all of which was funded at closing. The TCW
Credit Agreement originally provided for quarterly interest payments only, at a
rate of 9.75% per annum, until the earlier of December 31, 2003 or the date on
which the ING loan was paid in full. The Company initially granted a warrant to
TCW to purchase 10,000 shares of common stock at an exercise price of $100.00
per share (subject to anti-dilution adjustments) and later granted TCW a warrant
to purchase 5,852 shares of Common Stock at $17.50 (subject to anti-dilution
adjustments) for an amendment that deferred certain interest payments during
1999. The Senior Lenders received warrants to purchase 5,000 shares of common
stock at $17.50 (subject to anti-dilution adjustments) as consideration for
entering into the amendment in March 1999. The Company also granted registration
rights in connection with such warrants. The TCW Credit Agreement was secured by
a second lien on substantially all assets of the Company. As discussed in Note
4, on September 21, 1999, TCW exchanged the outstanding principal balance of
$75.0 million, accrued interest of $5.7 million and 15,852 warrants for
Preferred Series D Stock and Common Stock of the Company.

As discussed in Note 4, on September 21, 1999, the Company entered into the
Fortis Credit Agreement with its Senior Lenders as part of the Recapitalization
which was further amended on January 31, 2000, March 20, 2000, September 30,
2000, November 14, 2000 and on March 29, 2001.

The outstanding principal balance at December 31, 2000 was $83.5 million. All
borrowings under the Fortis Credit Agreement are due on April 1, 2002, or
potentially earlier if the borrowing base is determined to be insufficient. The
borrowing base is calculated as the collateral value of proved reserves and will
be redetermined on April 1, 2001 and October 1, 2001 and may be redetermined at
the option of the Senior Lenders one additional time. Upon redetermination, if
the borrowing base is lower than the outstanding principal balance then drawn,
the Company must immediately pay the difference. Interest accrues, at the
Company's option, at either (i) 2% above the prime rate or (ii) 3% above the
LIBOR rate. The Fortis Credit Agreement also contains a provision that the LIBOR
rate margin will increase to 3.5% at September 30, 2001 and to 4.0% at December
31, 2001 if the Company has not raised $10.0 million of additional equity. At
December 31, 2000, substantially all amounts were borrowed under the LIBOR
option at an effective rate of 8.04% through August 27, 2001. The Fortis Credit
Agreement has covenants that restrict the payment of cash dividends, borrowings,
sale of assets, loans to others, investment and merger activity and hedging
contracts without the prior consent of the lenders and requires the Company

F-17
54

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.

A summary of the Company's long-term debt follows (in thousands):

December 31,
-----------------
2000 1999
------- -------

Fortis Credit Agreement $83,500 $78,915
Other -- 167
------- -------
Total long-term debt $83,500 $79,082
======= =======

All amounts outstanding as of December 31, 2000 are due on April 1, 2002.

8. INCOME TAXES:

In 2000, 1999 and 1998, 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, 2000 and 1999 is as follows
(in thousands):

Deferred
December 31, Expense December 31,
2000 (Benefit) 1999
------------ ---------- ------------

Deferred tax assets:

Net operating loss carryforwards $ 25,691 $ 4,350 $ 21,341

Valuation allowance (16,037) (492) (15,545)
-------- -------- --------
Deferred tax assets 9,654 3,858 5,796
-------- -------- --------
Deferred tax liabilities:
Depletion, depreciation and amortization
of property and equipment (9,654) (3,858) (5,796)
-------- -------- --------
Deferred tax liabilities (9,654) (3,858) (5,796)
-------- -------- --------
Net deferred tax assets $ -- $ -- $ --
======== ======== ========

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

F-18
55

deferred tax liabilities. The Company will continue to monitor the need for the
valuation allowance that has been provided.

Income tax expense for 2000, 1999 and 1998 differed from amounts computed by
applying the statutory federal income tax rate as follows (in thousands):

December 31,
--------------------------------
2000 1999 1998
-------- -------- --------

Expected statutory tax expenses at 34% $ 644 $(12,537) $ (7,974)
Change in valuation allowance, net (492) 12,514 8,292
Other (152) 23 (318)
-------- -------- --------
Net tax expense $ -- $ -- $ --
======== ======== ========

No state or federal income taxes are payable at December 31, 2000 or 1999, and
the Company did not pay any income taxes in 2000, 1999 or 1998. At December 31,
2000, the Company had tax basis net operating loss carryforwards available to
offset future regular and alternative taxable income of $68.9 million, that
expire from 2001 to 2020. Utilization of the net operating loss carryforwards
are limited under the change of ownership tax rules.

9. CAPITAL STOCK (SEE NOTE 4):

Series D and Series E Preferred Stock

See Note 4 for a full description of the Series D and Series E rights and
preferences.

10. SUPPLEMENTAL DISCLOSURE OF
CASH FLOW INFORMATION (SEE NOTE 4):

Cash paid for interest during 2000, 1999 and 1998 was approximately $7,857,000,
$6,112,000 and $11,629,000, respectively.

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.

As part of the Smith Farmout restructuring, the following accounts were impacted
in 1999:

Oil and gas properties $(13,833)
Accumulated depletion, depreciation and amortization 2,837
Deferred debt offering costs (233)
Smith Farmout loan 15,085
Smith Farmout accrued interest 2,792
Additional paid-in capital (5,837)

F-19
56

During 1998, the Company paid interest on the Smith Farmout transaction, as
allowed by its terms, by issuing common stock valued at $866,000.

11. COMMITMENTS AND CONTINGENCIES:

Lease Commitments

The Company leases 16,500 square feet of office space under a noncancellable
operating lease. Future payment under this lease is as follows (in thousands):

2001 $300
2002 300
----
Total $600
====

Total lease expense during 2000, 1999 and 1998 was $300,000, $264,000 and
$264,000, 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.
During the period January 1, 1999 to September 30, 1999, the Company match was
reduced to 100% of the first 2% of salary contributed. Matching contributions of
$191,000, $104,000 and $206,000 were made by the Company during 2000, 1999 and
1998, 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.

The Company is currently involved in a dispute with a third party relating to
gathering fees. The issue has been remanded to arbitration. Management is not
able to estimate the outcome of the arbitration as of the filing date.

Consulting Agreement

The Company entered into a consulting agreement on September 21, 1999 with a
former director of the Company that was also an officer of Smith Management
pursuant to which this individual will receive $200,000 annually, paid in equal
monthly installments for consulting services to be provided to the Company until
September 21, 2002.

F-20
57

12. 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, 2000 at
prices equal to the market value of the Company's stock on the date of grant.
All granted options are vested except for 10,000 options which vest on December
31, 2001. There are 8,150 shares available for grant as of December 31, 2000.

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

Weighted Option Weighted
Average Exercise Fair Value
Number of Exercise Price of Options
Options Price Range Granted
--------- -------- ----------------- ----------

Balance, December 31, 1997 22,270 $ 75.80 $ 25.00 - $115.00
Granted 3,000 84.40 84.40 - 84.40 $60.79
======
Exercised (680) 54.60 25.00 - 68.70
-------- -------- ---------------
Balance, December 31, 1998 24,590 76.40 25.00 - 115.00
Granted 30,000 10.00 10.00 - 10.00 $ 8.23
======
Cancelled (4,474) 39.10 25.00 - 68.70
Expired (1,800) 115.00 115.00 - 115.00
-------- -------- -----------------
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
======== ======== =================

Plan options exercisable as of
December 31, 2000 11,736 $ 78.30
======== =======

F-21

Non-Plan Grants

From time to time the Company grants nonqualified options to purchase common
stock to its executive officers. The grants have a vesting period of five years.
These grants were made at fair value. The grants' lives are ten years. The table
below summarizes the activities associated with these grants to executive
officers:

Weighted Options Weighted
Average Exercise Fair Value
Number of Exercise Price of Options
Options Price Range Granted
--------- -------- -------- ----------

Balance, December 31, 1997
and 1998* 94,692 $82.10 $31.30 - $110.00
Granted 141,700 9.38 9.38 - 9.38 $7.22
=====
Cancelled (90,192) 82.60 31.25 - 110.00
-------- ------ ----------------
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
======== ====== ================

Non-Plan options exercisable
as of December 31, 2000 28,340 $ 9.38
======== ======

*No activity during 1998.

The following table summarizes information for options outstanding as of
December 31, 2000 for all Plan and Non-Plan options.

Options Outstanding Options Exercisable
------------------------------- ---------------------------
Weighted Weighted Weighted
Average Average Average
Range of Remaining Exercise Exercise
Exercise Price Number Contractual Life Price Number Price
--------------- ------- ---------------- --------- ------ --------

$ 9.38 - $10.00 151,700 8.9 $ 9.42 28,340 $ 9.38
25.00 - 37.50 1,440 3.3 32.98 1,440 32.98
40.63 - 53.00 2,056 2.0 49.62 2,056 49.62
68.70 - 90.00 5,240 6.1 85.65 5,240 85.65
94.40 - 110.00 3,000 6.8 106.88 3,000 106.88
------- --- ------- ------ -------
163,436 8.6 $14.21 40,076 $ 29.56
======= === ======= ====== =======

All options cancelled and reissued are subject to the criteria of the FASB
Interpretation No. 44 "Accounting for Certain Transactions Involving Stock
Compensation - an Interpretation of APB Opinion No. 25" ("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 rate value of
the stock on July 1, 2000. There was no adjustment made for these options in the

F-22
59

year ended December 31, 2000 as the stock price has not exceeded the stock price
in effect on July 1, 2000. Subsequent to December 31, 2000, 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
and $2.84 for 120,000. The new grants' lives are eight years and vest over a
three year period. The 300,000 stock options will be treated as a variable stock
option grant prospectively from the date of the new option grants.

The Company has elected to account for grants of 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 Statement of Financial
Accounting Standards 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):

2000 1999 1998
-------- --------- --------

Net loss, attributable
to common stockholders As reported $(16,544) $ (41,841) $(24,536)
Pro forma (16,991) (42,376) (25,978)

Basic and Diluted LPS As reported $ (5.71) $ (29.37) $ (29.25)
Pro forma (5.86) (29.76) (30.80)

The pro forma adjustments are calculated using an estimate of the fair value of
each option on the date of grant. No options were granted during 2000.

1999 1998
------- -------

Weighted average remaining life 5 years 5 years
Risk-free interest rate 6.0% 5.3%
Expected dividend yield 0% 0%
Expected lives 5 years 5 years
Expected volatility 113.2% 87.5%

13. OIL AND GAS PRODUCING ACTIVITIES:

Major Customers

Sales to the following Companies represented 10% or more of the Company's
revenues (in thousands):

2000 1999 1998
---- ---- ----

BP $17,016 $4,858 $ --
Chevron 11,611 -- 10,370
Wasatch 5,556 -- --

F-23

Cost Incurred in Oil and Gas Producing Activities (in thousands):

2000 1999 1998
------- ------- -------

Unproved property acquisition cost $ 33 $ -- $ 303
Proved property acquisition cost -- -- 105
Development cost 13,709 3,512 37,709
Exploration cost 135 155 153
------- ------- -------
Total $13,877 $ 3,667 $38,270
======= ======= =======

Net Capital Costs

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

2000 1999 1998
--------- --------- ---------

Unproved properties $ 3,797 $ 4,410 $ 14,585
Proved properties 174,348 160,889 161,472
Gas transportation facilities 5,814 4,918 4,481
--------- --------- ---------
Total 183,959 170,217 180,538

Accumulated depletion, depreciation and
amortization (35,004) (27,805) (21,433)
--------- --------- ---------
Total $ 148,955 $ 142,412 $ 159,105
========= ========= =========

Standardized Measure of Discounted
Future Net Cash Flows (Unaudited)

SFAS No. 69 "Disclosures about Oil and Gas Producing Activities" ("SFAS No. 69")
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% 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.

F-24
61

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):

2000 1999 1998
----------- ----------- -----------

Future cash inflows $ 1,633,382 $ 1,127,531 $ 183,642
Future production costs (292,305) (259,022) (88,870)
Future development costs (202,071) (189,297) --
Future income tax provision (369,220) (188,630) --
----------- ----------- -----------
Future net cash flows 769,786 490,582 94,772
Less effect of 10% discount factor (445,360) (292,270) (40,659)
----------- ----------- -----------
Standardized measure of discounted
future net cash flows $ 324,426 $ 198,312 $ 54,113
=========== =========== ===========

The principal sources of changes in the standardized measure of discounted
future net cash flows are as follows for the years ended December 31, 2000, 1999
and 1998 (in thousands):

2000 1999 1998
--------- --------- ---------

Standardized measure, beginning of year $ 198,312 $ 54,113 $ 78,622
Purchase of reserves in place -- -- 76
Sales of reserves in place -- (15,548) --
Sales of oil and gas produced excluding
hedging, net of production costs (26,501) (13,919) (11,912)
Net change in sales prices and production costs 168,192 123,905 (96,051)
Extensions, discoveries and improved
recovery, net 12,269 -- 7,910
Revisions of previous quantity estimates 8,667 349,080 (58,104)
Change in future development costs (7,396) (111,348) 232,087
Net change in income taxes (66,753) (55,855) 15,200
Accretion of discount 25,417 5,411 9,384
Changes in production rates and other 12,219 (137,527) (123,099)
--------- --------- ---------
Standardized measure, end of year $ 324,426 $ 198,312 $ 54,113
========= ========= =========

Oil and Gas Reserve Quantities (Unaudited)

The reserve information presented below is based upon reports prepared by the
Company's in-house petroleum engineer and reviewed by the independent petroleum
engineering firm of Ryder Scott Company. 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.

F-25

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 impact 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 value of the standardized measure
accordingly. As of December 31, 2000, the Company used prices of $23.78 per Bbl
and $7.73 per Mcf which is reflective of the market price at yearend. Prices
used by the Company in 1999 were $21.56 per Bbl and $1.83 per Mcf.

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, 2000, 1999 and 1998:

2000 1999 1998
---------------------- ----------------------- ------------------------
Oil (MBbl) Gas (MMcf) Oil (MBbl) Gas (MMcf) Oil (MBbl) Gas (MMcf)
---------- ---------- ---------- ---------- ---------- ----------

Proved reserves, beginning of year 47,129 60,935 18,602 18,063 37,135 75,483
Purchase of reserves in place -- -- -- -- 21 14
Sales of reserves in place -- -- (2,487) (3,100) -- --
Extensions and discoveries 660 1,584 -- -- -- --
Improved recoveries 400 200 -- -- 3,145 2,814
Production (1,072) (2,289) (1,165) (2,901) (1,501) (3,006)
Revisions of previous estimates 42 5,757 32,179 48,873 (20,198) (57,242)
------- ------- ------- ------- ------- -------
Proved reserves, end of year 47,159 66,187 47,129 60,935 18,602 18,063
======= ======= ======= ======= ======= =======
Proved developed reserves,
end of year 17,531 13,647 16,634 15,476 18,394 18,030
======= ======= ======= ======= ======= =======

14. QUARTERLY EARNINGS (UNAUDITED):

Summarized unaudited quarterly financial data for 2000 and 1999 is as follows
(in thousands, except per share data):

Quarter Ended
-------------------------------------------------
March 31, June 30, September 30, December 31,
2000 2000 2000 2000
------- ------- ------- -------

Revenues $ 6,094 $ 7,063 $ 7,461 $ 7,879
Operating income 2,059 2,878 2,638 2,764
Net income 77 847 209 761
Basic and diluted loss
per share available to
common stockholders (1.56) (1.30) (1.52) (1.33)

F-26
63

Quarter Ended
-----------------------------------------------------
March 31, June 30, September 30, December 31,
1999 1999 1999 1999
-------- -------- -------- --------

Revenues $ 4,034 $ 4,381 $ 4,359 $ 3,625
Operating loss (1,298) (634) (1,678) (516)
Net loss before extraordinary item (6,016) (4,622) (6,929) (18,750)
Net loss (6,016) (4,622) (7,485) (18,750)
Basic and diluted loss per share available
to common stockholders before
extraordinary item (7.35) (5.76) (6.59) (15.92)
Basic and diluted loss per share available
to common stockholders (7.35) (5.76) (7.11) (15.92)

F-27
64

EXHIBIT INDEX