1
================================================================================
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, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period ___ to ___
Commission File Number 0-16487
---------------
INLAND RESOURCES INC.
(Exact Name of Registrant as Specified in its Charter)
WASHINGTON 91-1307042
(State or Other Jurisdiction of (IRS Employer
Incorporation or Organization) Identification Number)
410 17th Street
Suite 700
Denver, Colorado
(303) 893-0102 80202
(Address of Principal Executive Offices) (Zip Code)
---------------
Issuer's telephone number, including area code: (303) 893-0102
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $.001 per share
Check whether the issuer (1) filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12
months (or for such shorter period that the issuer was required to file such
reports), and (2) has been subject to such filing requirements for the past 90
days. YES X NO ___
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, 1999, the registrant had outstanding 8,529,765 shares of
par value $.001 common stock. The aggregate value on such date of the voting
stock of the Registrant held by non-affiliates was an estimated $5,114,000.
DOCUMENTS INCORPORATED BY REFERENCE
Part III of this Annual Report on Form 10-K incorporates certain
information by reference from the definitive Proxy Statement for the
registrant's 1999 Annual Meeting of Stockholders.
================================================================================
2
TABLE OF CONTENTS
PAGE
PART I
Items 1 & 2. Business and Properties..................................................................1
Item 3. Legal Proceedings.......................................................................14
Item 4. Submission Of Matters To a Vote Of Security Holders.....................................14
PART II
Item 5. Market For Registrant's Common Stock and Related Stockholder Matters....................15
Item 6. Selected Financial Data.................................................................16
Item 7. Management's Discussion And Analysis of Financial Condition and Results of Operations...17
Item 7A. Quantitative and Qualitative Disclosures About Market Risks.............................25
Item 8. Financial Statements and Supplementary Data.............................................26
Item 9. Changes In And Disagreements With Accountants On Accounting And Financial Disclosure ...26
PART III
Item 10. Directors and Executive Officers of the Registrant......................................27
Item 11. Executive Compensation..................................................................27
Item 12. Security Ownership of Certain Beneficial Owners and Management..........................27
Item 13. Certain Relationships and Related Transactions..........................................27
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.........................28
i
3
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 Refining, Inc.
("Refining"), 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."
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. The Company is 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. Inland conducts its operations through
its subsidiaries, IPC and Refining. In 1998, IPC drilled 95 gross (73 net)
developmental wells. At December 31, 1998, the Company's estimated net proved
reserves totaled 21.6 MBOE, having a pre-tax present value discounted at 10%
using constant prices of $54.1 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 600 gross (506 net) oil
wells, including 141 gross (121 net) injection wells. Inland pioneered the
secondary water flood recovery processes used in the Field and currently
operates 20 approved secondary recovery projects in the area. Budgeted
development expenditures for 1999 in the Field are $500,000 net to the Company.
Inland also has budgeted $900,000 for refinery upgrades.
RECENT DEVELOPMENTS
On January 18, 1999, Inland entered into a non-binding letter of intent
with Flying J Inc. ("Flying J") and Smith Management LLC ("Smith Management")
regarding the acquisition of certain assets by Inland from Flying J or one of
its subsidiaries. The acquisition includes a 25,000 BPD refinery located in
North Salt Lake City, eleven Flying J gasoline stations located primarily in the
Salt Lake City area and Idaho and all oil and gas reserves owned by Flying J in
the Uinta Basin, fifteen miles north of the Field. The purchase price is $80
million in cash and approximately 12.8 million shares of Inland common stock,
par value $0.001 per share, which is equal to approximately 60% of the shares
outstanding after the acquisition. A restructuring of the Company's capital and
debt structure could be required to effectuate the acquisition. Management
anticipates that if the transaction is consummated, it will close during the
third quarter of 1999. The acquisition is contingent on preparation of
definitive documents, financing, due diligence procedures and approval by
regulatory agencies, Inland's lenders, the Board of Directors of each company
and Inland's shareholders. The failure of any one of these events could prevent
the consummation of the acquisition.
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
non-refining oil and gas related tangible assets of the Company. IPC serves as
the operator for the drilling, completion and operation of 600 wells, or 97% of
the wells in which the Company has an interest. Revenues, profits and losses and
total assets with respect to production, exploration and transportation
activities for Inland's fiscal years 1996, 1997 and 1998 are set forth in pages
F-5 and F-30 of this Annual Report.
1
4
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 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, 1998. 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-30 through F-33 of this Annual Report.
As of December 31, 1998
--------------------------------------
Proved Proved Total
Developed Undeveloped Proved
--------- ----------- ---------
(dollars in thousands)
Net Proved Reserves
Oil (MBls) 18,394 208 18,602
Gas (MMcf) 18,030 33 18,063
MBOE (6Mcf per Bbl) 21,398 214 21,612
Estimated Future Net Revenues(1) $ 94,060 $712 $ 94,772
Present Value of Future Net Revenues(2) $ 53,863 $250 $ 54,113
- -------------------
(1) Undiscounted.
(2) Discounted at 10%.
Future net revenues from reserves at December 31, 1998 were calculated
on the basis of average prices in effect on that date and were approximately
$7.60 per barrel of oil and $2.34 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. The standard measure of discounted future net
revenues (defined as the estimated future net revenues after taxes and
discounted at 10%) is equal to the present value of future net revenues because
depreciation and depletion of the tax basis of the oil and gas properties
completely offsets projected future net revenues.
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 workover 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
2
5
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-30 through F-33 of this Annual Report.
Year Ended December 31,
-----------------------------
1998 1997 1996
------ ------ ------
Net Production:
Oil (MBls) ............... 1,501 855 502
Gas (MMcf)(1) ............ 3,006 1,637 710
Total (MBOE) ......... 2,002 1,128 620
Average Sale Price(2):
Oil (per Bbl) ............ $ 9.82 $16.17 $20.18
Gas (per Mcf)(3) ......... $ 2.00 $ 2.19 $ 1.56
Average Production Cost:
($/BOE)(4) ........... $ 4.18 $ 3.35 $ 2.31
- -------------------------
(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 1998, 1997 and
1996.
1998 1997 1996
------------------ ------------------ -------------------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
Development wells:
Oil(1)............... 90 69 73 64 57 50.1
Water Injection...... -- -- -- -- 4 2.8
Dry.................. 5 4 5 4.8 2 2
----- ----- ----- ----- ----- -----
Total............ 95 73 78 68.8 63 54.9
===== ===== ===== ===== ===== =====
Exploratory wells:
Oil(1)............... -- -- 2 2 -- --
Dry.................. -- -- -- -- 1 1
----- ----- ----- ----- ----- -----
Total............ 0 0 2 2 1 1
===== ===== ===== ===== ===== =====
3
6
1998 1997 1996
------------------ ------------------ -------------------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
Total wells:
Oil(1)............... 90 69 75 66.0 57 50.1
Water Injection...... -- -- -- - 4 2.8
Dry.................. 5 4 5 4.8 3 3.0
----- ----- ----- ----- --- -----
Total............ 95 73 80 70.8 64 55.9
===== ===== ===== ===== === =====
- --------------------
(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.
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, 1998:
Wells(1)
-------------------------------------------------------------------------------
Gross(2) Net(2)
---------------------------------- ----------------------------------
Water Water
Location Oil(1) Injection Oil(1) Injection
-------- --- --------- --- ---------
Utah(3) 473 144 387.5 121
Other(4) 2 -- 0.5 --
----- ------ ----- ------
Total 475 144 388.0 121
===== ====== ===== ======
- -------------------
(1) The Company is an operator of 600 gross wells (506 net) and a non-operator
with respect to 19 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, 1998.
(3) All of the Company's wells in Utah are located in the Field.
(4) The Company has one producing oil or gas well in each of Wyoming and
Oklahoma; however, there are no reserves attributable to such wells.
Acreage Data. The following table reflects the developed and
undeveloped acreage that the Company held as of December 31, 1998:
Developed Acreage Undeveloped Acreage(1)
---------------------------------- ----------------------------------
Gross Net Gross Net
Location Acres Acres Acres Acres
-------- ------ ------ ------- -------
Utah(2) 24,000 19,400 126,500 98,700
Other(3) 700 100 8,300 8,100
------ ------ ------ ------
Total 24,700 19,500 134,800 106,800
====== ====== ======= =======
- ---------------
(1) Undeveloped acreage includes 60,100 gross (58,800 net) acres held by
production at December 31, 1998.
(2) All of the Company's acreage in Utah is located in the Field.
(3) The Company has one producing oil or gas well in each of Wyoming and
Oklahoma; however, there are no reserves attributable to such acreage.
4
7
As of December 31, 1998, the undeveloped acreage not held by production
involves 363 leases with remaining terms of up to 10 years. Leases covering
approximately 5,400 net acres have expiration dates in 1999. 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 $94,000 net to
the Company in 1998). 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 20 approved water flood
units or areas. At December 31, 1998, the Company had 141 wells injecting an
aggregate of 13,000 BWPD. During 1998, the Company installed 25 miles of water
pipelines to handle low pressure water delivery and high pressure water
injection and built two new water injection plants. The Company also converted
31 gross (28 net) oil wells into injection wells. At December 31, 1998, the
Company owned and operated 105 miles of water pipelines and eight water
injection plants with an injection capacity of 32,000 BWPD. Inland has
experienced stabilized or increasing production in many wells offsetting its
water injection operations. It intends to continue aggressively developing
secondary recovery water flood operations by extending infrastructure and
initiating injection in as many as 30 wells in the Field during 1999.
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 13.5 MMcf of natural gas per day and sells approximately 10.5 MMcf of
natural gas per day. The difference between the volume of natural gas produced
and sold is the amount of natural gas that the Company uses as lease fuel for
operations. The Company collects and markets approximately 88% of its operated
gas production using its gas gathering, transportation and compression system.
During 1998, the Company continued development of this system by installing 66
miles of gas gathering and fuel pipelines and one gas compression and
dehydration unit. The system now consists of approximately 310 miles of
pipelines and two compression facilities using five compressors and two
dehydration units with a throughput capacity of 22.5 MMcf per day. Inland also
owns an 84% partnership interest in the West Monument Butte Pipeline Company,
which owns a portion of the "Travis Expansion Unit" gas gathering and
transportation system.
Delivery Commitments. Approximately 12% of the natural gas produced by
the Company is sold pursuant to contracts which do not obligate the Company to
deliver a fixed quantity of natural gas, but require it to deliver all of its
production from the wells, net of lease fuel used, subject to such contracts.
These contracts expire between December 1999 and March 2000. The Company also
has a contract to sell 4,300 Mcf per day for the period April 1999 through March
2000 at a fixed price of $1.97 per Mcf. The majority of the Company's remaining
production is sold on a month-to-month basis in the spot market.
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. In 1998, there was a substantial decrease in oil and gas
prices worldwide. Continuing decreases in the prices of oil and gas would have
continuing adverse effects on the Company's proved reserves, revenues,
profitability and cash flow.
5
8
The crude oil produced from the Field is called Black Wax.
Approximately 16,000 BPD of Black Wax crude oil is currently produced in Utah
and refined in Salt Lake City. Transporting Black Wax crude oil to refineries in
California or Colorado is not practical because of the high cost of
transportation over such distances by truck or rail. Black Wax can be distilled
and cracked into high margin petroleum products such as gasoline, diesel and jet
fuel; however, it does not blend well with other crude oil feedstocks in the
refining process. Since Black Wax has limited compatibility in blending with
other crude oil feedstocks, the demand for Black Wax at the Salt Lake City
refineries tends to become inelastic as the supply of Black Wax reaches the
blending capacity of the Salt Lake City refineries.
The Company estimates the existing refining capacity for Black Wax in
Salt Lake City to be approximately equal to production. Since 1995, the basis
differential (the difference between the price of West Texas Intermediate crude
oil delivered to Cushing, Oklahoma ("NYMEX") and the wellhead price for Black
Wax) has increased from $1.50 to $4.40 today. This widening basis differential
has been caused in part by the substantial growth in production in the Field
which the Company has grown from approximately 100 BPD in 1993 to approximately
5,300 BPD as of March 1999.
"Black Wax" is sold at the average monthly posted field price less a
deduction of approximately $0.90 per barrel for oil quality adjustments. The
posted field price ranged from $7.25 to $14.25 during 1998 and $14.00 to $24.25
during 1997, and was $8.50 per barrel on December 31, 1998. During 1998 and
1997, the Company sold approximately 51% and 89%, respectively, of its oil
production to Chevron. In 1998, the Company sold 35% of its crude oil to
Refinery, and 13% of its crude oil to BP Amoco. Inland believes that the loss of
either Chevron or BP Amoco as a purchaser of its production would not have a
material adverse effect on its results of operations due to the Company's
ownership of the Woods Cross Refinery.
As the quantity of Black Wax produced within the Field grows, physical
limitations within the regional refineries will limit the amount of Black Wax
that can be economically processed. One of the reasons for acquiring the Woods
Cross Refinery was to provide a refining source, if needed, for the Company's
Black Wax production. Until refinery modifications at one or more of the other
refineries are accomplished, there may continue to be downward pressure on Black
Wax pricing. See "Refining Operations." If the Flying J transaction is
completed, Inland will acquire an additional refinery to process the Company's
Black Wax production.
The natural gas produced by the Company not subject to gas purchase
agreements is sold on a month-to-month basis in the spot market, the price of
which ranged from $1.78 to $2.38 per Mcf during 1998 and from $1.61 to $4.91 per
Mcf during 1997, and was $2.34 per Mcf for December 1998. All spot market sales
during 1998 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.
6
9
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 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 Inland's operations.
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 Monument Butte 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 successfully complied with the surface stipulations
and mitigation measures contained in the ROD, while significantly increasing its
drilling rate on federal leaseholds in 1998. The cost of compliance with surface
stipulations in the Monument Butte Field was approximately $315,000 in 1998. The
Company estimates that the cost of compliance with surface stipulations will
decrease substantially in 1999 due to a reduction in drilling activity.
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 Monument Butte Field contains the only known breeding population of mountain
plover in Utah. The USFWS and BLM are likely to implement additional restrictive
surface stipulations in the Monument Butte Field in order to provide additional
protection to the mountain plover and its habitat. 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 Monument Butte Field.
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
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. While the Company
experienced some difficulty monitoring and regulating injection pressures at
each individual well-head during 1998, the Company is in substantial compliance
with its underground injection program. The Company recently developed a
computer program to assist with monitoring injection pressures that will enhance
efforts to monitor injection pressures during 1999.
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
7
10
interpretation by enforcement agencies and frequently changed legislative
bodies, the Company is unable to predict the ultimate cost of such compliance
for 1999.
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 us. In accordance with
customary industry practices, we maintain 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 our 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. Until the Company is successful
in converting its current refineries or acquiring refineries capable of Black
Wax processing, these competitive pressures will persist.
REFINING OPERATIONS
The Company's refining operations are 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 Refinery
is located on approximately 42 acres owned by Refining in Woods Cross, Utah. The
refinery receives crude oil on the BP Amoco and Chevron pipelines and ships
products by truck, rail or the Chevron products pipeline to Idaho and
Washington. The refinery has a 485,000 barrel capacity of tankage on site.
The Woods Cross Refinery is currently processing approximately 3,000
BPD of Black Wax crude. The refinery has the capacity to process 5,000 BPD, but
does not dedicate this entire amount to Black Wax processing due to the
availability of alternative feedstocks at economic prices. Currently, the
Company produces approximately 5,300 BPD of Black Wax from the Field. Revenues,
profits and losses and total assets with respect to refining operations for
Inland's fiscal years 1996, 1997 and 1998 are set forth in pages F-5 and F-30
of this Annual Report.
Crude Oil Supply. In recent years, the crude oil supply in the Salt
Lake City area has been limited because of (1) a decrease in production of local
crudes and (2) limited pipeline capacities and, therefore, limited access to
crude outside the region. Crude is imported into the area by tank truck or rail
car, but these transportation methods are more expensive than the pipelines.
Refining acquires crude oil from a number of sources, including major oil
companies and small independent producers, under arrangements which contain
market-responsive pricing provisions.
Refining obtains and processes three primary crude oil supplies:
o Wyoming Sweet, which comprised approximately 34% of the Company's
refining crude oil feedstock in 1998, is obtained and processed
pursuant to contracts with various oil producers that are generally
terminable by either party on 30 days' notice.
o Yellow Wax crude, which comprised approximately 29% of the Company's
refining crude oil feedstock in 1998, is obtained and processed
pursuant to a processing agreement with Pennzoil terminable by either
8
11
party upon twelve months' notice. Pennzoil supplies Yellow Wax crude to
Refining and purchases the resulting wax distillate and vacuum tower
bottoms. Refining also obtains additional barrels of Yellow Wax from
Pennzoil and other sources pursuant to month-to-month purchase
contracts. Yellow Wax is delivered to the Salt Lake City area by
insulated tank truck.
o Black Wax crude, which comprised approximately 28% of the Company's
refining crude oil feedstock in 1998, is obtained from the Company's
production in the Field in addition to various other oil producers.
Refining modified its facilities in 1998 to allow it to increase its
Black Wax crude processing capability from 2,000 BPD to 5,000 BPD.
Black Wax is transported to the refinery by insulated tank truck.
The remainder of crude oil feedstock comes from a variety of other sources.
In addition to crude, Refining purchases other feedstocks, including
blowing flux, finished gasoline and diesel and MTBE. Blowing flux is purchased
from regional suppliers at market rates and delivered via truck or rail car.
Finished gasoline and diesel is purchased from other area refineries or
suppliers to meet contractual obligations during refinery downtimes or
slowdowns, or when profitable resale opportunities arise. MTBE is supplied to
Refining by truck or rail pursuant to month-to-month contracts with regional or
Gulf Coast suppliers.
The Company believes an adequate supply of crude oil and other
feedstocks will be available for the foreseeable future. However, there is no
assurance that this situation will continue. The Company continues to evaluate
other supplemental crude oil supply alternatives for its refinery on both a
short-term and long-term basis. Among other alternatives, the Company has
considered making additional equipment modifications to increase its ability to
use alternative crude oils. If additional supplemental crude oil becomes
necessary, the Company intends to implement then available alternatives as
necessary and as are most advantageous under then prevailing conditions.
Implementation of supplemental supply alternatives may result in additional raw
material costs, operating costs, capital costs, or a combination thereof in
amounts which are not presently ascertainable by the Company, but which will
vary depending on factors such as the specific alternative implemented, the
quantity of supplemental feedstocks required, and the date of implementation.
Marketing of Products. The Company currently owns no retail outlets for
its gasoline and diesel products and, therefore, sells such products on a
wholesale basis to a broad base of independent retailers, jobbers and major oil
companies in the region. Prices are determined by local market conditions at the
"terminal rack" located at the refinery or at pipeline terminals. The customer
typically supplies his own truck transportation. Two large local distributors,
Maverick Country Stores and Brad Hall & Associates, began purchasing increasing
volumes of gasoline from the Company in 1998 pursuant to month-to-month
contracts. Revenue from each of these two purchasers exceeded 10% of the
Company's revenues from refining operations and, the combined revenue from both
of these purchasers represented 48% of 1998 refining revenue. Depending on the
future level of such purchases, the loss of such customers could have a
short-term material adverse effect on the Company until replacement purchasers
are obtained.
The Company sells its roofing asphalt to a broad base of customers in
the Salt Lake City area, Arizona, Nevada and northern California at prices
determined by local market conditions. No single purchaser of the Company's
asphalt products accounted for more than 10% of the Company's revenues from
refining operations in 1998 or 1997.
In 1998 and 1997, the Company's sales of its Yellow Wax products to
Pennzoil constituted approximately 65% of its Yellow Wax production but did not
represent more than 10% of the Company's revenues from refining operations
during either year.
Scheduled Maintenance and Capital Improvements. Each refinery operating
unit requires regular maintenance and repair shutdowns (referred to as
"turnarounds") during which it is not in operation. Turnaround cycles vary for
different units. In general, Refining manages refinery turnarounds so that some
units continue to operate while others are down for scheduled maintenance.
Turnaround work proceeds on a continuous 24-hour basis in order to minimize unit
down time. The Company expenses current maintenance charges and capitalizes
turnaround costs which are then amortized over the estimated period until the
next turnaround. The Company plans
9
12
to expend approximately $2.2 million (including $400,000 in turnarounds) during
1999 implementing various necessary repairs and maintenance and environmental
upgrades.
Volatility Of Crude Oil Prices And Refining Margins. The Company's cash
flow from refining operations is primarily dependent upon the production and
sale of quantities of refined products at refinery margins sufficient to cover
fixed and variable expenses. In recent years, crude oil costs and prices of
refined products have fluctuated substantially. These costs and prices depend on
numerous factors, including the demand for crude oil, gasoline and other refined
products.
Crude oil supply contracts are generally relatively short-term
contracts with market-responsive pricing provisions. The prices that the Company
receives for its refined products are affected by local factors such as product
pipeline capacity, local market conditions and the level of operations of out of
state refineries. A large, rapid increase in crude oil prices would adversely
affect the Company's operating margins if the increased cost of raw materials
could not be passed along to its customers. The Company generally does not hedge
a significant portion of its feedstock purchases or refined product sales.
Competition. The petroleum industry is highly competitive in all
phases, including (1) the refining of crude oil, (2) the marketing of refined
petroleum products and (3) the exploration and production of oil and gas
reserves. The Company currently competes with four other refineries in the Salt
Lake City metropolitan area owned by BP Amoco, Chevron, Flying J and Phillips
Petroleum Co. These companies have substantially greater financial resources,
staffs and facilities than the Company's and therefore, may be better able than
the Company to withstand volatile industry conditions, such as shortages or
excesses of crude oil or refined products or intense price competition at the
wholesale and retail level. BP Amoco's refinery has a capacity of 53,000 BPD,
Chevron's has a capacity of 45,000 BPD, Flying J's (which is the refinery
subject to the letter of intent dated January 18, 1999 with the Company) has
25,000 BPD capacity and Phillips has 25,000 BPD capacity. Each refinery is more
sophisticated than the Woods Cross Refinery and, therefore, more capable of
producing higher end gasoline products, as well as the asphalt and wax
distillates produced by Refining.
Seasonality. The Company experiences seasonal fluctuations with its
gasoline and diesel fuel products. The demand for such products is significantly
stronger during the spring, summer and early fall because of increased tourist
travel.
Regulatory, Environmental and Other Matters Affecting Refining
Operations. The Company's refining operations are subject to a variety of
federal, state and local health, safety, and environmental laws and regulations
governing process operations, product specifications, the discharge of
pollutants into the air and water, and the generation, treatment, storage,
transportation and disposal of solid and hazardous materials and wastes. The
Company believes that the refinery is capable of processing currently utilized
feedstocks in substantial compliance with existing environmental laws and
regulations; however, compliance with more stringent laws or regulations, as
well as more vigorous enforcement policies of regulatory agencies, could have an
adverse effect on the financial position of the Company. Regulatory agencies
frequently propose and implement new laws and regulations, and each new
applicable law or regulation may increase the Company's overall compliance
costs. In addition, many regulatory programs under existing environmental laws
and regulations are "phased in" over time, causing incremental increases in
compliance costs as each new program is implemented.
The Company cannot predict what additional health, safety, and
environmental legislation or regulations will be enacted or become effective in
the future or how existing or future laws or regulations will be administered,
interpreted, or enforced with respect to products or activities to which they
have not been previously applied. Refining and marketing trade associations
track the development and implementation of new laws and regulations that may
affect the refining and marketing industry in the future. The following
currently appear to be the most significant of existing and proposed new health,
safety, and environmental laws and regulations as they relate to the Company's
operations during 1999 and beyond. Where possible, the Company has attempted to
estimate a range of its costs of compliance based upon its current understanding
of such laws and regulations. The current estimates of costs provided are
preliminary only and actual costs may differ significantly from these estimates.
Clean Air Regulatory Programs. Refining is subject to the federal Clean
Air Act ("CAA"), state equivalents, and implementing regulations. Among other
things, the CAA requires all major sources of hazardous
10
13
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.
Authorities at the State of Utah, Division of Air Quality ("DAQ") are
currently reviewing each "applicable requirement" of the Woods Cross Refinery
Comprehensive Air Permit submitted in October of 1995. For each "applicable
requirement" of the final permit, there are periodic monitoring provisions under
the Periodic Monitoring Program, which should be sufficient to assure
compliance. Agency officials expect guidance from Region-VIII of the
Environmental Protection Agency requiring that the DAQ complete its review and
publish Comprehensive Air Permits within the next two years. The Woods Cross
Refinery is currently in compliance with all CAA regulations, and will not need
to submit Compliance Assurance Monitoring Plans ("CAM") under the Periodic
Monitoring Program for any processes as currently operated. This assessment is
subject to change, should business decisions or economic conditions require that
the Woods Cross Facility revise its Title V Comprehensive Air Permit.
The cost of such modifications cannot be predicted at this time.
Under the CAA Amendments of 1990, Refining also will be required to
prepare a Risk Management Plan by June of 1999 for the Woods Cross Refinery. The
focus of this new regulatory program is emergency response preparedness in the
event of an accidental release of flammables or toxics that have the potential
to impact public health. The Woods Cross Refinery currently has an Integrated
Pollution Prevention Plan, which addresses the requirements for an Oil Spill
Prevention Control and Countermeasures ("SPCC") Plan and a Storm Water Pollution
Prevention ("SWPP") Plan. In 1999, Refining will complete the development of an
Integrated Contingency Plan ("ICP"), which will address the requirements of
Process Safety Management Procedures and Risk Management Planning, and which
will meet all federal, state, and local contingency planning requirements. The
Federal Oil Pollution Act of 1990 ("OPA 90") requires that certain refinery
operations also maintain a Facility Response Plan for responding to accidental
releases. This planning requirement also will be incorporated into the
comprehensive ICP for the Woods Cross Refinery. The Company does not believe the
cost of developing the ICP will be material, although there can be no assurance
until it is completed.
During 1997, the EPA proposed a controversial new CAA rule regarding
haze. A final rule may be issued in 1999. The impact on Refining from this rule
is not yet known.
Clean Water Regulatory Programs. The federal Clean Water Act ("CWA")
imposes restrictions and controls on discharges to water. Such discharges may be
authorized by permit. The refinery maintains a current wastewater discharge
permit and is in substantial compliance with its discharge limitations. The
Woods Cross Refinery currently operates a groundwater collection trench and pump
system to prevent potential groundwater contamination from migrating offsite.
Water that collects in the trench is pumped to the Refinery's process water
treatment system and is discharged, under permit, as wastewater.
In 1998, Refining submitted to the Utah Division of Water Quality
("DWQ") a revised Groundwater Management Plan for the Woods Cross Refinery.
Refining has not yet received response and comment from DWQ, but anticipates a
response in 1999. The anticipated 1999 cost of continuing existing groundwater
programs and implementing the revised Groundwater Management Plan is $125,000.
The actual 1999 cost and additional ongoing costs related to the Groundwater
Management Plan cannot be estimated until the Plan has been approved and
finalized by DWQ.
Waste Disposal Regulatory Programs. Refining operations are inherently
subject to accidental spills, discharges, or other releases of petroleum or
hazardous substances 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. Accidental discharges of contaminants have occurred from time
to time during the normal course of operations of the Company's Woods Cross
Refinery. Refining has undertaken or intends to undertake all investigative or
remedial work thus far required by governmental agencies to address potential
contamination by Refining and minimize future discharges.
11
14
At the present time, no portion of the Woods Cross Refinery is actively
regulated under the Resource Conservation and Recovery Act ("RCRA"). In 1998,
Refining acquired an inactive facility in Roosevelt, Utah, that is currently
undergoing soil and groundwater remediation activities required under RCRA. The
costs of the RCRA remediation are being paid by Pennzoil Products Company
(Pennzoil), the former owner and operator of the facility. Pennzoil is obligated
by contract to complete the RCRA-mandated soil and groundwater remediation to
the satisfaction of federal, state, and local authorities. The Company estimates
that it will incur minimal compliance costs related to the inactive Roosevelt
Refinery during 1999, but long-term costs related to this facility cannot be
estimated at this time.
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. It is not uncommon for neighboring landowners and
other third parties to file claims for personal injury and property damage
allegedly caused by the hazardous substances released into the environment.
Refining periodically disposes of hazardous waste off site at licensed disposal
facilities. The Company is not presently aware of any potential adverse claims
in this regard.
The Company's operations generate and result in the transportation,
treatment, and disposal of both hazardous and nonhazardous solid wastes that are
subject to the disposal requirements of RCRA and comparable state and local
requirements. The EPA is currently considering the adoption of stricter disposal
standards for nonhazardous waste. Further, it is possible that some wastes that
are currently classified as nonhazardous, perhaps including wastes generated
during pipeline, drilling and production operations, may in the future be
designated as "hazardous wastes," which are subject to more rigorous and costly
treatment, storage, transportation and disposal requirements. Such changes in
the regulations may result in additional expenditures or operating expenses by
the Company. On August 8, 1998, the Environmental Protection Agency added four
petroleum refining wastes to the list of RCRA hazardous wastes. While the full
impact of this new rule has yet to be determined, the rule may impose increased
expenditures and operating expenses on the Company, which may take on additional
obligations relating to the treatment, storage, transportation and disposal of
certain petroleum refining wastes that were not previously regulated as
hazardous waste. Certain wastes that were not previously regulated as hazardous
waste may now fall within the definition of CERCLA hazardous substances.
Health and Safety Regulatory Programs. Refining also is subject to
regulations promulgated by the Occupational Safety and Health Administration
("OSHA") regarding management of process safety hazards. Under regulations
governing Process Safety Management ("PSM") process hazard analyses ("PHA") were
to be completed over a four-year period from 1993 through mid-1997. These
analyses had not been completed for the Woods Cross Refinery as of January of
1998. During a six-month period in 1998, Refining committed the resources to
completing PHA for all refinery processes. Work began on addressing the
recommendations identified from the PHA. During 1999, refinery personnel will
continue to address the identified recommendations. The anticipated cost for
implementing the recommendations identified from the PHA over the next three
years is estimated to be $1 million. The cost to address individual
recommendations ranges from zero (in the event that it is determined that no
action should result from the recommendation) to significant. An example of
significant costs that may result would be an expansion to the Distributed
Control System that would allow additional process monitors to be tied into
automatic alarms. The costs for 1999 are dependent on the identified action
items, priorities, and available funds.
EMPLOYEES
At March 15, 1999, the Company had 163 employees, consisting of five
executive officers, 21 clerical and administrative employees and 57 field
operations staff involved in the Company's oil and gas operations in Utah and 80
employees employed in the refining operations at the Wood Cross Refinery.
12
15
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 $22,000
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.
"MTBE" is a gasoline blendstock component used in the production of
gasoline.
"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
13
16
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.
14
17
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK
Inland's common stock is quoted on the National Association of
Securities Dealer's Automated Quotation System ("Nasdaq") under the symbol
"INLN". The closing price of Inland's common stock on Nasdaq was $2.06 per share
on March 15, 1999. As of March 15, 1999, there were approximately 462 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. The
quotations reflect inter-dealer prices without retail markup, markdown or
commission, and may not necessarily represent actual transactions.
Common Stock Price Range
------------------------
High Low
------- ------
YEAR ENDED DECEMBER 31, 1997
First Quarter ...................................... $ 11.00 $ 8.38
Second Quarter ..................................... 10.25 8.13
Third Quarter ...................................... 12.63 8.75
Fourth Quarter ..................................... 12.63 10.00
YEAR ENDED DECEMBER 31, 1998
First Quarter ...................................... $ 10.50 $ 8.50
Second Quarter ..................................... 9.25 8.38
Third Quarter ...................................... 9.50 4.25
Fourth Quarter ..................................... 6.50 0.88
PERIOD FROM JANUARY 1, 1999 THROUGH MARCH 15, 1999..... $ 5.25 $ 1.19
DIVIDEND POLICY
Inland has not paid cash dividends on Inland's common stock during the
last two 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 ING Credit
Agreement and TCW Credit Agreement forbid 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 C preferred stock.
RECENT SALES OF UNREGISTERED SECURITIES
The following information relates to sales and other issuances by
Inland within the past three fiscal years of Inland securities, the sales or
issuance of which were not registered pursuant to the Securities Act of 1933
(the "Securities Act").
As of December 31, 1998, Smith Energy Partnership ("SEP"), an affiliate
of Smith Management, received 152,220 shares of Inland common stock as payment
of proceeds under the Farmout Agreement between Inland and Smith Management
effective June 1, 1998. To Inland's knowledge, SEP (a) is an "accredited
investor" within the
15
18
meaning of Section 501(a) of Regulation D, (b) is the only record holder of
shares of common stock issued pursuant to the Farmout Agreement, and (c) intends
to hold the shares for investment purposes. Based on these facts and other
circumstances, Inland issued its common stock to SEP without registration under
the Securities Act in reliance on the exemption provided by Section 4(2) of the
Securities Act.
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, 1998. 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,
-----------------------
1998 1997 1996 1995 1994
-------- -------- -------- -------- --------
(dollars in thousands, except for unit amounts)
REVENUE AND EXPENSE DATA:
Revenues:
Refined product sales ........................ $ 68,477 $ -- $ -- $ -- $ --
Oil and gas sales ............................ 14,920 17,182 10,704 1,905 1,063
Management fees .............................. -- -- -- 326 --
-------- -------- -------- -------- --------
Total revenues ............................ 83,397 17,182 10,704 2,231 1,063
-------- -------- -------- -------- --------
Operating Expenses:
Cost of refinery feedstock ................... 51,908 -- -- -- --
Refinery operating expenses .................. 9,858 -- -- -- --
Lease operating expenses ..................... 8,362 3,780 1,435 1,010 915
Production taxes ............................. 454 383 610 133 90
Exploration .................................. 153 61 167 342 306
Impairment ................................... 4,164 -- -- -- --
Depletion, depreciation and amortization ..... 12,795 6,480 3,428 858 330
General and administrative, net .............. 3,974 2,118 1,670 1,335 1,004
-------- -------- -------- -------- --------
Total operating expenses .................. 91,668 12,822 7,310 3,678 2,645
-------- -------- -------- -------- --------
Operating income (loss) ......................... (8,271) 4,360 3,394 (1,447) (1,582)
Interest expense ................................ (15,290) (4,759) (1,633) (749) (143)
Interest and other income ....................... 321 380 414 128 54
Gain on sale of assets .......................... -- -- -- 850 --
Loss on disposal of discontinued operations ..... -- -- (30) (500) (100)
-------- -------- -------- -------- --------
Net income (loss) before extraordinary item ..... (23,240) (19) 2,145 (1,718) (1,771)
Extraordinary item .............................. (212) (1,160) -- (216) --
-------- -------- -------- -------- --------
Net income (loss) ............................... (23,452) (1,179) 2,145 (1,934) (1,771)
Redemption premium - Series A Stock ............. -- -- (214) -- --
Redemption premium - Series B Stock ............. -- (580) -- -- --
Accrued Series C Stock dividends ................ (1,084) (450) -- -- --
-------- -------- -------- -------- --------
Net income (loss) attributable to common
stockholders ................................. $(24,536) $ (2,209) $ 1,931 $ (1,934) $ (1,771)
======== ======== ======== ======== ========
Earnings (loss) per common share before
extraordinary item:
Basic ...................................... $ (2.90) $ (0.14) $ 0.38 $ (0.63) $ (0.95)
Diluted .................................... (2.90) (0.14) 0.30 (0.63) (0.95)
Earnings (loss) per common share:
Basic ...................................... $ (2.93) $ (0.30) $ 0.38 $ (0.63) $ (0.95)
Diluted .................................... (2.93) (0.30) 0.30 (0.63) (0.95)
16
19
Year Ended December 31,
-----------------------
1998 1997 1996 1995 1994
--------- --------- --------- --------- ---------
BALANCE SHEET DATA (AT END OF PERIOD):
Oil and gas properties, net ....................... $ 159,105 $ 133,820 $ 42,998 $ 16,819 $ 12,041
Total assets ...................................... $ 195,829 $ 175,953 $ 57,329 $ 21,923 $ 17,038
Debt .............................................. $ 158,823 $ 123,111 $ 21,120 $ 4,636 $ 2,458
Stockholders' equity .............................. $ 7,039 $ 30,672 $ 31,972 $ 13,979 $ 9,924
OTHER FINANCIAL DATA:
Net cash provided by operating activities ......... $ 12,770 $ 5,668 $ 5,006 $ 302 $ (2,310)
Net cash used in investing activities ............. (45,327) (122,222) (23,752) (8,030) (2,507)
Net cash provided by financing activities ......... 33,579 107,128 25,806 9,008 6,205
OPERATING DATA:
Sales Volumes:
Oil (MBbls) .................................. 1,501 855 502 105 46
Gas (MMcf) ................................... 3,006 1,637 710 109 171
MBOE ......................................... 2,002 1,128 620 123 75
BOEPD ........................................ 5,485 3,090 1,698 336 204
Average Prices (excluding hedging activities):
Oil (per Bbl) ................................ $ 9.82 $ 16.17 $ 20.18 $ 17.10 $ 16.09
Gas (per Mcf) ................................ 2.00 2.19 1.56 1.21 1.78
Per BOE ...................................... 10.35 15.23 17.26 15.52 14.26
Production and operating costs
(per BOE)(1) ............................... 4.18 3.35 2.31 8.23 12.27
- --------------------
(1) Excludes production and ad valorem 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, 1998, 1997, and 1996.
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 Field within the Uinta Basin of northeastern Utah. The Company is also
engaged in the refining of crude oil and the wholesale marketing of refined
petroleum products, including various grades of gasoline, kerosene, diesel fuel,
waxes and asphalt.
In September 1997, the Company acquired 153 gross (46.9 net) wells from
Enserch Exploration Company ("Enserch") and 279 gross (184 net) wells from
Equitable Resources Energy Company ("EREC") in two separate transactions. In
addition, the Company acquired an oil refinery located in Woods Cross, Utah (the
"Woods Cross Refinery") on December 31, 1997. On September 16, 1998, the Company
acquired a non-operating crude oil refinery known as the Roosevelt Refinery.
These acquisitions were accounted for as purchases, and therefore, the assets
and results of operations are included in the Company's financial statements
from the effective acquisition dates forward.
17
20
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1998 COMPARED WITH YEAR ENDED DECEMBER 31, 1997
Refined Products Sales. The Company averaged refined product sales
of 9,000 barrels per day from the Woods Cross Refinery during 1998, of which 58%
represented gasoline and diesel products. The Company performed various major
repair and maintenance procedures during the initial six months of 1998 which
contributed to a growth in average sales volume from 8,500 barrels per day
during the initial six months of 1998 to 9,500 barrels per day during the last
six months of 1998. Due to market conditions in the Salt Lake region, the
efficiencies of increasing volumes were offset by decreasing average sales
prices. The sales price of the Company's product slate averaged $19.90 for 1998.
The Company did not have refining operations during 1997.
Oil and Gas Sales. The Company eliminated in consolidation $6.4
million of crude oil sales made between its production operations and the Woods
Cross Refinery during 1998. Prior to considering intercompany eliminations,
crude oil and natural gas revenue for the year ended December 31, 1998
increased $4.1 million, or 24% from the previous year. The increase was
attributable to the acquisitions of the properties from Enserch and EREC and
the effects of the Company's development drilling results. During 1997 and
1998, the Company drilled 175 wells. Although production increased 77% on a BOE
basis, the revenue increase was only 24% due primarily to a 39% decrease in the
average price received for crude oil production from $16.17 during 1997 to
$9.82 during 1998. Natural gas prices also declined by 9% from $2.19 per Mcf
during 1997 to $2.00 per Mcf during 1998. Oil sales as a percentage of total
oil and gas sales were 72 % and 80% in 1998 and 1997, respectively. Crude oil
is expected to continue as 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 increased by
$550,000 during 1998 and decreased by $217,000 during 1997 to recognize hedging
contract settlement gains and losses and contract purchase cost amortization.
See Item 7A "Quantitative and Qualitative Disclosures About Market Risk."
Cost of Refinery Feedstock - The Company's average cost of crude oil
and other refinery feedstocks, including transportation charges, was $16.79 per
barrel during 1998. The Company eliminated in consolidation $6.4 million of
costs associated with sales between its production operations and the Woods
Cross Refinery. The Company did not have refining operations during 1997.
Refinery Operating Expenses. During 1998, the Company upgraded and
repaired key refinery equipment. Operating costs, consisting primarily of direct
labor, utilities and repairs averaged $3.00 per barrel sold. The refinery is
considered to be in good operating condition. Routine turnaround projects
totaling approximately $400,000 are expected in 1999, in addition to ongoing
repairs and upgrades to the Company's buildings, tanks and roads. The Company
did not have refining operations during 1997.
Lease Operating Expenses. Lease operating expense for the year ended
December 31, 1998 increased 121%, or $4.58 million, from the previous year as a
result of the large increase in the number of producing wells the Company
operates from 151 wells at the beginning of 1997 to 600 at the end of 1998.
Lease operating expense per BOE sold for the year ended December 31, 1998 was
$4.18 as compared to $3.35 for the year ended December 31, 1997. The increase on
a BOE basis is the result of the acquisitions of the properties from Enserch and
EREC in September 1997 that included a large number of lower producing wells.
Production Taxes. Production taxes as a percentage of sales were 2.2%
in both 1998 and 1997. 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 1998 and 1997 represents the
Company's cost to retain unproved acreage.
18
21
Impairment. Impairment reflects the adjustment in carrying value to
write down the Roosevelt Refinery, a note receivable and certain undeveloped
acreage to their estimated net realizable value.
Depletion, Depreciation and Amortization. Depletion, depreciation and
amortization for the year ended December 31, 1998 increased 97%, or $6.3
million, from the previous year. The increase resulted from a higher average
depletion rate and increased sales volumes. In addition, the refinery purchase
increased the depreciable basis of assets. 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
$5.70 per BOE sold during 1998 compared to $5.52 per BOE sold during 1997. Based
on December 31, 1998 proved reserves, the Company's depletion rate entering 1999
is $6.67 per BOE.
General and Administrative, Net. General and administrative expense for
the year ended December 31, 1998 increased 88%, or $1.85 million, from the
previous year. This expense would have decreased slightly if not for the $1.9
million of general and administrative expense related to refining operations
that were not present in the prior year. As a result, general and administrative
expense for production operations is reported net of operator fees and
reimbursements which were $5.7 million and $3.2 million during 1998 and 1997,
respectively. Gross general and administrative expense for production operations
was $7.8 million in 1998 and $5.3 million in 1997. The increase in
reimbursements and expense is a function of the level of operated field activity
which increased dramatically with the purchases of the properties from Enserch
and EREC and development drilling activity.
Interest Expense. Interest expense for the year ended December 31, 1998
increased 221%, or $10.5 million to $15.3 million from $4.8 million, for the
year ended December 31, 1997. The increase resulted from a significant increase
in the average amount of borrowings outstanding due to the leveraged purchases
of the properties from Enserch and EREC, the Woods Cross Refinery and
development drilling activity. Borrowings during 1998 and 1997 were recorded at
an effective interest rate of approximately 10.6%.
Other Income. Other income in 1998 and 1997 primarily represents
interest earned on the investment of surplus cash balances.
Income Taxes. In 1998 and 1997, no income tax provision or benefit was
recognized due to net operating losses incurred and the reversal and recording
of a full valuation allowance.
Extraordinary Item. On May 29, 1998, the Company refinanced its Credit
Agreement with Banque Paribas and wrote off $212,000 of debt issuance cost. On
September 30, 1997, the Company refinanced an existing obligation to a former
lender causing unamortized debt issue costs of $296,000 to be written off as an
extraordinary loss. On June 30, 1997, the Company refinanced an obligation to
Trust Company of the West causing debt issue costs of $291,000 and an
unamortized loan discount of $573,000 to be written off as an extraordinary
loss.
Redemption Premium Preferred Series B Stock. During July 1997, Inland
called for the redemption of its Series B Convertible Preferred Stock (the
"Series B Stock"). All Series B holders elected to convert their holdings to
common stock rather than have their shares redeemed for cash. The amount
recorded as a redemption premium represents the excess consideration paid over
the carrying amount of the Series B Stock.
Accrued Series C Stock Dividends. Inland's Series C Stock accrues
dividends at 10% compounded quarterly. No dividends on the stock have been
paid since it was issued on July 21, 1997. The amount accrued represents those
dividends earned during 1998 or 1997, respectively.
YEAR ENDED DECEMBER 31, 1997 COMPARED WITH YEAR ENDED DECEMBER 31, 1996
Oil and Gas Sales. Crude oil and natural gas revenue for the year ended
December 31, 1997 increased by $6.5 million, or 61%, from the previous year. The
increase was attributable to the acquisitions of the properties from Enserch and
EREC and the effects of the Company's development drilling results. During 1996
and 1997, the Company drilled 144 wells. Although production increased 82% on a
BOE basis, the revenue increase was only 61% due primarily to a 20% decrease in
the average price received for crude oil production from $20.18 during 1996 to
$16.17 during 1997. Natural gas prices contributed to the revenue increase by
improving 40% from
19
22
$1.56 per Mcf during 1996 to $2.19 per Mcf during 1997. Oil sales as a
percentage of total oil and gas sales were 80% and 89% in 1997 and 1996,
respectively.
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
$217,000 during 1997 and $535,000 during 1996 to recognize hedging contract
settlement gains and losses and contract purchase cost amortization. See
Item 7A "Quantitative and Qualitative Disclosures About Market Risk."
Lease Operating Expenses. Lease operating expenses for the year ended
December 31, 1997 increased 163%, or $2.3 million from the previous year, as a
result of the large increase in the number of producing wells the Company
operates from 87 wells at the beginning of 1996 to 510 at the end of 1997. Lease
operating expense per BOE sold for the year ended December 31, 1997 increased
$1.04 to $3.35 from $2.31 for the year ended December 31, 1996. The increase on
a BOE basis is the result of the acquisitions of the properties from Enserch and
EREC in September 1997 that included a large number of lower producing wells.
Production Taxes. Production taxes as a percentage of sales was 2.2%
for the year ended December 31, 1997 as compared to 5.4% for the year ended
December 31, 1996. 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. The ad valorem tax does not correspond directly with the Company's
revenues; therefore, as the Company's revenues increased in 1997, the ad valorem
tax decreased as a percentage of sales. In addition, the amount of severance tax
paid as a percentage of sales also decreased due to the increasing number of
wells that qualified for exemptions or credits from severance tax.
Exploration. Exploration expense in 1997 and 1996 represents Inland's
share of costs to retain unproved acreage and drilling costs related to one
uneconomic exploration well in 1996.
Depletion, Depreciation and Amortization. Depletion, depreciation and
amortization for the year ended December 31, 1997 increased $3.1 million from
the previous year. The increase resulted from a higher average depletion rate
and increased sales volumes. 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
$5.52 per BOE sold during 1997 compared to $5.17 per BOE sold during 1996.
General and Administrative, Net. General and administrative expense for
the year ended December 31, 1997 increased $448,000 from the previous year.
General and administrative expense is reported net of operator fees and
reimbursements which were $3.2 million and $1.9 million during 1997 and 1996,
respectively. Gross general and administrative expense was $5.3 million in 1997
and $3.6 million in 1996. The increase in reimbursements and expense is a
function of the level of operated field activity which increased dramatically
with the purchases of the properties from Enserch and EREC and development
drilling activity.
Interest Expense. Interest expense for the year ended December 31, 1997
increased $3.1 million to $4.8 million from $1.7 million for the year ended
December 31, 1996. The increase in expense between periods was due to a
significant increase in the average amount of borrowings outstanding due to the
leveraged purchases of the properties from Enserch and EREC, and development
drilling activity. Borrowings during 1997 averaged approximately $45 million,
compared to an approximate average of $15 million of borrowings during 1996.
Borrowings during 1997 and 1996 were recorded at an effective interest rates of
approximately 10.6% and 11%, respectively. The change in the effective interest
rate resulted from various debt refinancings performed during 1997.
Other Income. Other income in 1997 and 1996 primarily represents
interest earned on the investment of surplus cash balances.
20
23
Income Taxes. In 1997 and 1996, no income tax provision or benefit was
recognized due to net operating losses incurred and the reversal and recording
of a full valuation allowance.
Extraordinary Item. On September 30, 1997, the Company refinanced an
existing obligation to a former lender causing unamortized debt issue costs of
$296,000 to be written off as an extraordinary loss. On June 30, 1997, the
Company refinanced an obligation to Trust Company of the West causing debt issue
costs of $291,000 and an unamortized loan discount of $573,000 to be written off
as an extraordinary loss.
Redemption Premium Preferred Series A Stock. During August 1996, Inland
called for the redemption of its Series A preferred stock. The amount recorded
as a dividend represents the excess of the redemption amount over the carrying
amount for those Series A holders who elected to redeem their shares rather than
convert.
Redemption Premium Preferred Series B Stock. During July 1997, Inland
called for the redemption of its Series B Stock. All Series B holders elected to
convert their holdings to common stock rather than have their shares redeemed
for cash. The amount recorded as a redemption premium represents the excess
consideration paid over the carrying amount of the Series B Stock.
Accrued Series C Stock Dividends. Inland's Series C stock accrues
dividends at 10% or $1,000,000 per year. No dividends have been paid since the
stock was issued on July 21, 1997. The amount accrued represents those dividends
earned during the period through December 31, 1997.
Discontinued Operations. Effective December 30, 1996, Inland sold the
Toiyabe Mine and completely divested itself of any remaining business activities
related to the mining of precious metals. During 1996, Inland focused
reclamation activities on recontouring and revegetating certain disturbed land
areas, lowering constituent levels in leachate solution and certain other
miscellaneous tasks. Costs incurred in performing these operations were
$129,000. Placer Dome U.S. Inc. purchased the Toiyabe Mine from the Company and
assumed responsibility for all past, present and future environmental and
reclamation activities, liabilities and expenses. The Company paid Placer
$500,000 in consideration of the assumption of such responsibilities. As a
result, the Company has no future liability for the Toiyabe Mine, unless Placer
fails to honor its agreement with Inland to assume and pay such liabilities.
LIQUIDITY AND CAPITAL RESOURCES
During 1998, the Company continued its development of the Field by
drilling 95 gross (73 net) development wells and converting 31 gross (28 net)
wells to injection. The Company also expanded and upgraded its water delivery
and gas gathering infrastructures. Total capital costs incurred in the
development of the Field were $37.7 million. The Company also used $5.9 million
to perform capital upgrades at its Woods Cross Refinery and purchase an idle
refinery in Roosevelt Utah and used $12.5 million to repay a former lender. The
Company funded these activities with new borrowings of $47.75 million and cash
generated from operations of $12.8 million. The remaining net change in cash was
caused by various other smaller items.
Commencing June 1, 1998, the Company's drilling program was conducted
under the Farmout Agreement with SEP. Funds expended by Smith Management
pursuant to this Agreement were treated as debt by the Company for financial
reporting purposes. Forty-three wells were drilled under the Farmout Agreement
in 1998, aggregating net expenditures to Smith Management of $15.1 million
(including management fees). Under the Farmout Agreement, Smith Management
agreed to fund 100% of the drilling and completion costs for wells commenced
prior to October 1, 1998 and 70% for wells commenced after September 30, 1998.
At the Company's option, Smith Management agreed to take production proceeds
payments either in cash or in shares of the Company's common stock. If the
Company elects to pay using common stock, the stock is priced at a 10% discount
to average closing price for the production month to which the payment relates.
Through December 31, 1998, the Company has elected to make all payments in the
form of common stock totaling 152,220 shares. 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 agree 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 price was calculated at less than
$3.00 per share, such cash only to be paid if the Company's senior lenders agree
to such payment. The Farmout Agreement provides that Smith Management will
reconvey all drillsites to the Company
21
24
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.
The accompanying consolidated financial statements have been prepared
assuming the Company will continue as a going concern. The continuing low oil
price environment has significantly impacted the Company's financial condition.
The Company has a working capital deficit of $145.0 million at December 31, 1998
and generated a net loss of $23.5 million during the year ended December 31,
1998. Approximately $141.7 million of the deficit is caused by principal amounts
related to the Company's long-term debt facilities. Based on current conditions,
the Company will not be able to make its principal payments as scheduled under
its long-term debt facilities. In addition, at December 31, 1998 the Company was
in default of certain provisions of its credit agreements and required
additional capital outside of cash flow from operations to fund a portion of its
outstanding accounts payable. The short-term liquidity issues were temporarily
mitigated (as further explained below) in March 1999 when the Company's senior
lenders advanced $3.25 million which the Company immediately used to reduce
outstanding accounts payable.
The Company is considering a number of additional strategies to cure
its working capital and liquidity issues. A solution that the Company is
currently pursuing is the Flying J acquisition. On January 18, 1999, Inland
entered into a non-binding letter of intent with Flying J and Smith Management
regarding the acquisition of certain assets by Inland from Flying J or one of
its subsidiaries. The acquisition includes a 25,000 BPD refinery located in
North Salt Lake City, eleven Flying J gasoline stations located primarily in the
Salt Lake City area and Idaho and all oil and gas reserves owned by Flying J in
the Uinta Basin, fifteen miles north of the Field. The purchase price is $80
million in cash and approximately 12.8 million shares of Inland common stock,
par value $0.001 per share, which is equal to approximately 60% of the shares
outstanding after the acquisition. This transaction would be accounted for as a
reverse merger. A restructuring of the Company's capital and debt structure
could be required to effectuate the acquisition. Management anticipates that if
the transaction is consummated, it will close during the third quarter of 1999.
The acquisition is contingent on preparation of definitive documents, financing,
due diligence procedures and approval by regulatory agencies, Inland's lenders,
the Board of Directors of each company and Inland's shareholders. The failure of
any one of these events could prevent the consummation of the acquisition.
If the proposed Flying J transaction is not consummated, the Company
will attempt to restructure its capital such that a drilling program can be
resumed although there is no assurance that the Company will be successful.
Until the capital restructuring is complete, the Company does not plan to drill
additional wells, focusing instead on its continuing efforts to pressurize the
Field through additional development of its water injection infrastructure. The
Company plans to convert 30 of its oil wells to injection wells during 1999
while incurring net capital expenditures of $500,000. The Company also expects
to spend $900,000 performing required capital improvements at the Woods Cross
Refinery. 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, capital
availability and market conditions.
Other possible solutions include obtaining additional modifications to
its credit agreements, selling assets, issuing additional debt or selling equity
of the Company. The Company believes its lenders will assist in solving the
Company's liquidity and working capital issues, although management can not be
assured that the Company will obtain modifications or concessions from its
lenders or raise the necessary capital from other sources in the time frames
required. As a result, the Company may have to further slow or stop development
of the Field and suspend all upgrades at the Woods Cross Refinery. As a result
of the items noted above, there is substantial doubt about the Company's ability
to continue as a going concern. The consolidated financial statements do not
include any adjustments relating to the recoverability and classification of
asset carrying amounts or the amount and classifications of liabilities that
might result should the Company be unable to continue as a going concern.
Financing. On September 30, 1997, the Company closed separate Credit
Agreements with Trust Company of the West and TCW Asset Management Company in
their capacities as noteholder and agent (collectively "TCW") and ING (U.S.)
Capital Corporation ("ING"). Subsequent to the closing of the ING Credit
Agreement, U.S. Bank National Association and Meespierson Capital Corp.
(collectively referred to herein with ING as the "Senior Lenders") became loan
participants in the ING Credit Agreement. The Credit Agreement with TCW provided
the Company with $75.0 million, all of which was funded at closing. The ING
Credit Agreement provides the Company with a borrowing base that was $70 million
at December 31, 1998. The borrowing base under the ING facility is
22
25
limited to the collateral value of proved reserves as determined semiannually by
the Senior Lenders. At December 31, 1998, the Company had $67.7 million of
borrowings and $2.3 million of letter of credit obligations outstanding under
the ING Credit Agreement and $75.0 million borrowed under the TCW Credit
Agreement.
On March 11, 1999, the Company entered into amendments to the ING
Credit Agreement and the TCW Credit Agreement. The ING amendment increased the
borrowing base to $73.25 million. The Company immediately borrowed the
additional $3.25 million of availability and used the proceeds to reduce
accounts payable. The Senior Lenders received a warrant to purchase 50,000
shares of common stock at $1.75 as consideration for entering into the
amendment. Under the TCW amendment, TCW agreed to defer the quarterly payments
for interest accruing during the initial six months of 1999 until the earlier of
December 31, 2003 or the date on which the ING loan is paid in full. The
deferred interest will bear interest at 12%. TCW received a warrant to purchase
58,512 shares of common stock at $1.75 as consideration for entering into the
amendment.
The ING Credit Agreement constitutes a revolving line of credit until
March 31, 1999, at which time it converts to a term loan payable in quarterly
installments through March 29, 2003. The quarterly installments, based on a
$73.25 million borrowing base, are $9.5 million on June 29, 1999, $6.2 million
for the next two quarters, $4.7 million for the next four quarters, $3.9 million
for the next four quarters, $3.5 million for the next four quarters, and $3.0
million on March 29, 2003. The ING loan bears interest, at the Company's option,
at either (i) the average prime rates announced from time to time by The Chase
Manhatten Bank, Citibank, N.A. and Morgan Guaranty Trust Company of New York
plus 0.5% per annum; or (ii) at LIBOR plus 1.75%. The Company has consistently
selected the LIBOR rate option resulting in a currently effective interest rate
of approximately 6.8%. As required by the ING and TCW Credit Agreements, on
April 30, 1998 the Company paid $140,000 to put in place an interest rate hedge.
The hedge covers the period June 12, 1998 through December 12, 2000 and
effectively provides a 6.75% LIBOR rate interest ceiling (before consideration
of the 1.75% adjustment) on $35.0 million of borrowings under the ING Credit
Agreement. The ING Credit Agreement is secured by a first lien on substantially
all assets of the Company.
The TCW Credit Agreement is comprised of a $65.0 million tranche and a
$10.0 million tranche and is payable interest only, at a rate of 9.75% per
annum, quarterly until the earlier of December 31, 2003 or the date on which the
ING loan is paid in full. At that time, the TCW Credit Agreement converts to a
term loan payable in twelve quarterly installments of principal and interest.
The quarterly principal installments are $6.25 million for the first four
quarters, $8.75 million for the next four quarters and $3.75 million for the
last four quarters. The Company granted a warrant to TCW to purchase 100,000
shares of common stock at an exercise price of $10.00 per share (subject to
anti-dilution adjustments) at any time after September 23, 2000 and before
September 23, 2007. The Company also granted piggyback registration rights in
connection with such warrants. TCW is also entitled to additional interest on
the $65.0 million tranche in an amount that yields TCW a 12.5% internal rate of
return, such interest payment to be made concurrently with the final payment of
all principal and interest on the TCW Credit Agreement. For purposes of the
internal rate of return calculation, the Company is given credit for the funding
fee of $2.25 million paid to TCW at closing. In regards to the $10.0 million
tranche, upon payment in full of the TCW Credit Agreement by the Company, TCW
may elect to "put" their warrants back to the Company and accept a cash payment
which will cause TCW to achieve a 12.5% rate of return on such tranche. The TCW
Credit Agreement restricts any repayment of the indebtedness until October 1,
1999. The TCW Credit Agreement is secured by a second lien on substantially all
assets of the Company.
The TCW and ING Credit Agreements have common 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. At December 31, 1998 the Company was in
violation of certain covenants common to both the ING Credit Agreement and the
TCW Credit Agreement. All lenders have been notified of the covenant defaults,
including the filings of liens by vendors. Based on the recent borrowing base
increase and interest deferral, the Company's lenders have shown a willingness
to help the Company solve its working capital and liquidity issues. Although
there can be no assurance, the Company does not expect its lenders to issue
notices of default allowing them to call their debt for repayment in the near
future. The Company's management is estimating that current cash flow
projections will not be sufficient to repay scheduled maturities given the oil
and gas pricing environment in 1999. As a result, all borrowings for both of
these facilities have been classified as current under the
cross-collateralization provisions of such facilities.
23
26
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 certain of Inland's
costs and expenses are affected by the level of inflation, inflation did not
have a significant effect on Inland's result of operations during 1998 or 1997.
YEAR 2000 ISSUES
The Company is aware of the issues associated with the programming code
in many existing computer systems as the millennium approaches. The "Year 2000"
problem is pervasive; virtually every computer operation may be affected in some
way by the rollover of the digit value to 00. The risk is that computer systems
will not properly recognize sensitive information when the year changes to 2000.
Systems that do not properly recognize such information could generate erroneous
data or cause a system to fail, resulting in business interruption.
The Company has conducted a review of its computer systems and is
taking steps to correct Year 2000 compliance issues. The Company benefits from
having relatively new computer systems in most locations. The Company believes
its computer hardware and software is over 90% Year 2000 compliant. Computer
hardware and software that is not Year 2000 compliant is scheduled to be updated
before June 1999. The Company's operations are not extremely dependent on vendor
compliance with Year 2000 issues. To the extent a major vendor is not Year 2000
compliant by June 1999, the Company believes that alternative vendors that are
Year 2000 compliant will be available and selected. In summary, management
believes that Year 2000 issues can be mitigated without a significant effect on
the Company's financial position. The Company expects to expend less than
$50,000 to become fully Year 2000 compliant. However, given the complexity of
the Year 2000 issue, there can be no assurance that the Company will be able to
address the problem without incurring costs that are material to future
financial results or future financial condition.
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 "Business and Properties" and "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
the Flying J transaction, information regarding drilling schedules, expected or
planned production or transportation capacity, future production levels of
fields, marketing of crude oil and natural gas, sources of crude oil for
refining, marketing of refined products, refinery maintenance, operations and
upgrades, the Company's capital budget and future capital requirements, 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 Securities and Exchange
Commission (the "Commission").
24
27
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 ING Credit Agreement. See Item 7. -
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources." The ING Credit Agreement is a
revolving line of credit until March 31, 1999, at which time it converts to a
term loan payable in quarterly installments through March 29, 2003. As of
December 31, 1998, the ING Credit Facility had a principal balance of
$67,665,000 at an average floating interest rate of 7.07% per annum and
$2,335,000 of letters of credit obligations outstanding. Assuming no hedge, and
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, 1999 January 1, 2000 January 1, 2001 January 1, 2002 January 1, 2003
through through through through through
December 31, 1999 December 31, 2000 December 31, 2001 December 31, 2002 March 29, 2003
- --------------------------------------------------------------------------------------------------------------------
1% increase in $630,000 $430,000 $257,000 $109,000 $6,000
Interest Rates
- --------------------------------------------------------------------------------------------------------------------
2% increase in $1,267,000 $877,000 $537,000 $246,000 $19,000
Interest Rates
- --------------------------------------------------------------------------------------------------------------------
On April 30, 1998, as required by the ING Credit Agreement, Inland
entered into an interest rate hedge covering the ING Credit Agreement at a cost
of $140,000. This interest rate cap agreement with Enron Capital and Trade
Resources Corp. covers the period June 12, 1998 through December 12, 2000 and
provides a 6.75% LIBOR rate, the net effect of which is to cap the interest rate
at 8.5% on $35.0 million of borrowings. Pursuant to the ING Credit Agreement,
this hedge must be renewed or replaced through the remaining term of the loan.
Assuming the renewal of the terms of the interest rate cap agreement, the effect
of the hedge through March 29, 2003 will be to limit hypothetical increases in
interest expenses under the ING Credit Agreement, as shown by the following
chart:
---------------------------------------------------------------------------------------------------
Increase in Interest Expense with Hedge
---------------------------------------------------------------------------------------------------
January 1, 1999 January 1, 2000 January 1, 2001 January 1, 2002 January 1, 2003
through through through through through
December 31, 1999 December 31, 2000 December 31, 2001 December 31, 2002 March 29, 2003
- --------------------------------------------------------------------------------------------------------------------
1% increase in $630,000 $430,000 $257,000 $109,000 $6,000
Interest Rates
- --------------------------------------------------------------------------------------------------------------------
2% increase in $1,067,000 $667,000 $374,000 $164,000 $10,000
Interest Rates
- --------------------------------------------------------------------------------------------------------------------
The TCW Credit Agreement is composed of two revolving tranches, and is
ultimately convertible to a term loan payable over three years. The TCW Credit
Agreement calculates interest based on both a fixed rate and, alternatively, an
internal rate of return. As a result, there is no interest rate risk with
respect to this facility.
Commodity Risks. Inland hedges a portion of its oil and gas 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
25
28
contracts quoted on the NYMEX or certain other indices. Gains or losses on
hedging activities are recognized as oil and gas sales in the period in which
the hedged production is sold.
On March 10, 1999 Inland entered into two swap agreements with Enron
Capital and Trade Resources Corp. ("Enron"), each of which cover 40,000 barrels
per month of crude oil production during the period April 1, 1999 through
December 31, 1999. The swap price on the first contract is $14.02 and the swap
price on the second contract is $14.54, based on NYMEX Light Sweet Crude Oil
Futures Contracts. The potential gains or losses on these contracts based on a
hypothetical average market price of equivalent product for the period from
April 1, 1999 to December 31, 1999 are as follows:
-------------------------------------------------------------------------------------------------
Average NYMEX Per Barrel Market Price for the Contract Period
-------------------------------------------------------------------------------------------------
$12.00 $13.00 $14.00 $15.00 $16.00 $17.00 $18.00
- ---------------------------------------------------------------------------------------------------------------------
$14.02 Contract $727,000 $367,000 $7,000 $(353,000) $(713,000) $(1,073,000) $(1,433,000)
- ---------------------------------------------------------------------------------------------------------------------
$14.54 Contract $914,000 $554,000 $194,000 $(166,000) $(526,000) $(886,000) $(1,246,000)
- ---------------------------------------------------------------------------------------------------------------------
Inland has a hedge (the "Enron Hedge") in place with Enron that hedges
crude oil production over a five year period beginning January 1, 1996 in
monthly amounts escalating from 8,500 Bbls in January 1996 to 14,000 Bbls in
December 2000. The hedge is structured as a cost free collar whereby if the
average monthly price, based on NYMEX Light Sweet Crude Oil Futures Contracts,
is between $18.00 and $20.55 per barrel, no payment is exchanged between the
parties. On January 1, 1997, Inland paid $34,170 to enter into a contract with
Koch Gas Services Company ("Koch") that exactly offsets the effect of the Enron
Hedge during the period January 1998 through December 2000. As a result, the
potential for gains and losses with respect to the Enron Hedge expired on
January 1, 1998, and Inland recognized no net gain or loss on the Enron Hedge in
1998.
On May 12, 1997, Inland entered into a put contract with Enron for
100,000 barrels per month for the period January 1998 through March 1998 at a
put price of $16.00 per barrel. Inland recorded $95,000 of income under this
contract in the first quarter of 1998.
On March 12, 1998, Inland entered into a cost free collar with Enron
whereby the average monthly price, based on NYMEX Light Sweet Crude Oil Futures
Contracts, is between $14.50 and $17.70 per barrel. The collar covered 75,000
barrels per month for the period from April 1998 through December 1998. For the
year ended December 31, 1998, Inland recognized income of $532,000 on this
contract.
During 1998 and 1997, Inland had various other contracts in place
consisting of puts, calls and collars. Each of the contracts was completely
settled as of December 31, 1998. The effects of all hedging contracts resulted
in income of $550,000 in 1998 and a loss of $217,000 in 1997.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and supplementary data required hereunder are
included in this Annual Report or incorporated by reference as set forth in Item
14(a).
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
26
29
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information regarding the directors and executive officers of the
Registrant in the Proxy Statement relating to the Company's 1999 Annual Meeting,
which will be filed with the Commission within 120 days after December 31, 1998,
is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information regarding executive compensation in the Proxy Statement
relating to the Company's 1999 Annual Meeting, which will be filed with the
Commission within 120 days after December 31, 1998, is incorporated herein by
reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information regarding the security ownership of certain beneficial
owners and management in the Proxy Statement relating to the Company's 1999
Annual Meeting, which will be filed with the Commission within 120 days after
December 31, 1998, is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information regarding certain relationships and related
transactions in the Proxy Statement relating to the Company's 1999 Annual
Meeting, which will be filed with the Commission within 120 days after December
31, 1998, is incorporated herein by reference.
27
30
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 statements 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 July 21, 1997 (filed as Exhibit 3.1 to Inland's Form
10-QSB for the quarter ended June 30, 1997, 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 fiscal 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).
* 4.1.2 Amended and Restated Credit Agreement dated as of
September 11, 1998 amending and restating Exhibit 4.1.
* 4.1.3 First Amendment to Amended and Restated Credit Agreement
dated as of March 5, 1999 amending Exhibit 4.1.2.
28
31
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.
* 4.2.3 First Amendment to Amended and Restated Credit Agreement
dated as of March 5, 1999, amending Exhibit 4.2.2.
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.
* 4.3.3 First Amendment to Amended and Restated Intercreditor
Agreement dated as of March 5, 1999, amending Exhibit 4.3.2.
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).
4.6 Credit Agreement dated as of December 24, 1997 between
Inland Refining, Inc. and Banque Paribas (without exhibits)
(filed as Exhibit 4.1 to the Company's Current Report on
Form 8-K dated December 31, 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 fiscal 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 fiscal 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 fiscal year ended December 31, 1994, and incorporated
herein by reference).
29
32
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 Warrant Agreement and Warrant Certificate between Kyle R.
Miller and Inland dated February 23, 1993 (filed as Exhibit
10.2 to Inland's Current Report on Form 8-K dated February
23, 1993, and incorporated herein by reference).
10.2.1 Warrant Certificate between Kyle R. Miller and Inland dated
October 15, 1993 representing 3,150 shares (filed as Exhibit
10.2.1 to Inland's Annual Report on Form 10-KSB for the
fiscal year ended December 31, 1994, and incorporated herein
by reference).
10.2.2 Warrant Certificate between Kyle R. Miller and Inland dated
March 22, 1994 representing 5,715 shares (filed as Exhibit
10.2.2 to Inland's Annual Report on Form 10-KSB for the
fiscal year ended December 31, 1994, and incorporated herein
by reference).
10.2.3 Warrant Certificate between Kyle R. Miller and Inland dated
September 21, 1994 representing 44,811 shares (filed as
Exhibit 10.2.3 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1994, and incorporated
herein by reference).
10.2.4 Warrant Certificate between Kyle R. Miller and Inland dated
September 21, 1994 representing 38,523 shares (filed as
Exhibit 10.2.4 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1994, and incorporated
herein by reference).
10.2.5 Warrant Certificate between Kyle R. Miller and Inland dated
September 21, 1994 representing 30,000 shares (filed as
Exhibit 10.2.5 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1994, and incorporated
herein by reference).
10.2.6 Amendment to Warrant Certificates filed as Exhibits 10.2,
10.2.1 and 10.2.2 (filed as Exhibit 10.2.6 to Inland's
Annual Report on Form 10-KSB for the fiscal year ended
December 31, 1994, and incorporated herein by reference).
10.2.7 Warrant Certificate between Kyle R. Miller and Inland dated
November 16, 1993 representing 1,500 shares (filed as
Exhibit 10.2.7 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1995, and incorporated
herein by reference).
10.2.8 Warrant Certificate between Kyle R. Miller and Inland dated
March 15, 1995 representing 1,250 shares (filed as Exhibit
10.2.8 to Inland's Annual Report on Form 10-KSB for the
fiscal year ended December 31, 1995, and incorporated herein
by reference).
10.2.9 Warrant Certificate between Kyle R. Miller and Inland dated
November 6, 1995 representing 30,000 shares (filed as
Exhibit 10.2.9 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1995, and incorporated
herein by reference).
10.2.10 First Amendment to Warrant Agreement between Inland and
Kyle R. Miller dated October 19, 1995 (filed as Exhibit 10.1
to Inland's Quarterly Report on Form 10-QSB for the fiscal
quarter ended September 30, 1995, and incorporated herein by
reference).
10.2.11 Warrant Certificate between Inland and Kyle R. Miller dated
May 22, 1996 (corrected version) (filed as Exhibit 10.2.11
to Inland's Annual Report on Form 10-KSB for the fiscal year
ended December 31, 1996, and incorporated herein by
reference).
30
33
10.2.12 Warrant Certificate between Inland and Kyle R. Miller dated
January 23, 1997 representing 70,000 shares (filed as
Exhibit 10.2.12 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1996, and incorporated
herein by reference).
10.2.13 Option Certificate between Inland and Kyle R. Miller dated
November 10, 1997 representing 225,000 shares (filed as
Exhibit 10.2.13 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1997, and incorporated
herein by reference).
10.3 Employment Agreement between Inland and Kyle R. Miller dated
June 1, 1996 (filed as Exhibit 10.2 to Inland's Quarterly
Report on Form 10-QSB for the quarter ended June 30, 1996,
and incorporated herein by reference).
10.4 Employment Agreement between Inland and Bill I. Pennington
dated June 1, 1996 (corrected version) (filed as Exhibit
10.9.2 to Inland's Annual Report on Form 10-KSB for the
fiscal year ended December 31, 1996, and incorporated herein
by reference).
10.5 Chevron Crude Oil Purchase Contract No. 531144 dated
October 25, 1998, as amended by Amendment No. 1 dated
November 27, 1989, Amendment No. 2 dated September 12, 1990,
Amendment 3 dated July 15, 1991, Amendment No. 4 dated
January 22, 1992, Amendment No. 5 dated January 13, 1993,
and the March 4, 1992 letter from Chevron U.S.A. Products
Company to all Chevron Products Company customers (filed as
Exhibit 10.29 to Inland's Registration Statement on Form
S-4, Registration No. 33 80392, and incorporated herein by
reference).
10.6 Registration Rights Agreement dated September 21, 1994
between Inland and Energy Management Corporation, a wholly
owned subsidiary of Smith Management Company, Inc. and the
assignee of Smith Management Company, Inc. under the
Subscription Agreement filed as Exhibit 10.9 (filed as
Exhibit 10.19 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1994, and incorporated
herein by reference).
10.6.1 Correspondence constituting an amendment/clarification of
the Registration Rights Agreement filed as Exhibit 10.10
(filed as Exhibit 10.19.1 to Inland's Annual Report on Form
10-KSB for the fiscal year ended December 31, 1994, and
incorporated herein by reference).
10.6.2 Registration Rights Agreement dated March 20, 1995 between
Inland and Energy Management Corporation (filed as Exhibit
10.19.2 to Inland's Annual Report on Form 10-KSB for the
fiscal year ended December 31, 1994, and incorporated herein
by reference).
10.7 Warrant Certificate dated November 22, 1995 granted by
Inland to Randall D. Smith, together with Exhibit "A", a
Registration Rights Agreement (filed as Exhibit 10.29.1 to
Inland's Annual Report on Form 10-KSB for the fiscal year
ended December 31, 1995, and incorporated herein by
reference).
10.7.1 Form of Registration Rights Agreement dated June 12, 1996
between Inland, Smith Management Company, Inc. and Randall
D. Smith, Jeffrey A. Smith and John W. Adams (filed as
Exhibit 10.2 to Inland's Current Report on Form 8-K dated
June 12, 1996, and incorporated herein by reference).
10.7.2 Security Agreement dated June 12, 1996 between
Randall D. Smith, Jeffrey A. Smith and John W. Adams and
Inland (filed as Exhibit 10.3 to Inland's Current Report on
Form 8-K dated June 12, 1996, and incorporated herein by
reference).
31
34
10.7.3 Form of Agreement dated June 12, 1996 between Inland and
Arthur J. Pasmas (filed as Exhibit 10.4 to Inland's Current
Report on Form 8-K dated June 12, 1996, and incorporated
herein by reference).
10.7.4 Form of Registration Rights Agreement entered into as of
July 31, 1996 between Inland and Arthur J. Pasmas (filed as
Exhibit 10.5 to Inland's Current Report on Form 8-K dated
June 12, 1996, and incorporated herein by reference).
10.7.5 Form of Amendment to Registration Rights Agreement filed as
Exhibit 10.29.6 (filed as Exhibit 10.29.7 to Inland's Annual
Report on Form 10-KSB for the fiscal year ended December 31,
1996, and incorporated herein by reference).
10.8 Crude Oil Call/Put Option (Costless Collar) between IPC and
Koch Gas Services Company dated November 20, 1995 (filed as
Exhibit 10.30 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1995, and incorporated
herein by reference).
10.9 Swap Agreement dated November 22, 1994 between Inland and
Joint Energy Development Investments Limited Partnership
(filed as Exhibit 10.1 to Inland's Quarterly Report on Form
10-QSB for the fiscal quarter ended June 30, 1995, and
incorporated herein by reference).
10.10 Employment Agreement between Inland and John E. Dyer dated
June 1, 1996 (corrected version) (filed as Exhibit 10.35 to
Inland's Annual Report on Form 10-KSB for the fiscal year
ended December 31, 1996, and incorporated herein by
reference).
10.10.1 Amendment to Employment Agreement filed as Exhibit 10.26
(filed as Exhibit 10.35.1 to Inland's Annual Report on Form
10-KSB for the fiscal year ended December 31, 1996, and
incorporated herein by reference).
10.11 Warrant Certificate between Inland and John E. Dyer dated
May 22, 1996 representing 50,000 shares (corrected version)
(filed as Exhibit 10.37 to Inland's Annual Report on Form
10-KSB for the fiscal year ended December 31, 1996, and
incorporated herein by reference).
10.11.1 Warrant Certificate between Inland and John E. Dyer dated
January 23, 1997 representing 70,000 shares (filed as
Exhibit 10.37.1 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1996, and incorporated
herein by reference).
10.11.2 Option Certificate between Inland and John E. Dyer dated
November 10, 1997 representing 150,000 shares (filed as
Exhibit 10.28.2 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1997, and incorporated
herein by reference).
10.12 Warrant Certificate between Inland and Bill I. Pennington
dated May 22, 1996 representing 50,000 shares (corrected
version) (filed as Exhibit 10.38 to Inland's Annual Report
on Form 10-KSB for the fiscal year ended December 31, 1996,
and incorporated herein by reference).
10.12.1 Warrant Certificate between Inland and Bill I. Pennington
dated January 23, 1997 representing 60,000 shares (filed as
Exhibit 10.38.1 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1996, and incorporated
herein by reference).
10.12.2 Option Certificate between Inland and Bill I. Pennington
dated November 10, 1997 representing 125,000 shares (filed
as Exhibit 10.29.2 to Inland's Annual Report on Form 10-KSB
for the fiscal year ended December 31, 1997, and
incorporated herein by reference).
10.13 Option Certificate between Inland and Michael J. Stevens
dated November 10, 1997
32
35
representing 100,000 shares (filed as Exhibit 10.30 to
Inland's Annual Report on Form 10-KSB for the fiscal year
ended December 31, 1997, and incorporated herein by
reference).
10.14 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 fiscal year ended
December 31, 1996, and incorporated herein by reference).
10.15 Collar between Koch Oil Company and Inland effective
January 1, 1997 (filed as Exhibit 10.42 to Inland's Annual
Report on Form 10-KSB for the fiscal year ended December 31,
1996, and incorporated herein by reference).
10.16 Securities Purchase Agreement dated July 21, 1997 between
Inland and Joint Energy Development Investments Limited
Partnership (filed as Exhibit 10.1 to Inland's Quarterly
Report on Form 10-QSB for the quarter ended June 30, 1997,
and incorporated herein by reference).
10.16.1 Registration Rights Agreement dated July 21, 1997 between
Inland and Joint Energy Development Investments Limited
Partnership (filed as Exhibit 10.2 to Inland's Quarterly
Report on Form 10-QSB for the quarter ended June 30, 1997,
and incorporated herein by reference).
10.17 Employment Agreement between Inland and Michael J. Stevens
dated May 1, 1997 (filed as Exhibit 10.39 to Inland's Annual
Report on Form 10-KSB for the fiscal year ended December 31,
1997, and incorporated herein by reference).
10.18 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).
10.19 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).
* 10.20 Warrant Agreement dated as of March 5, 1999 between Inland
Resources Inc. and TCW Portfolio No. 1555 DR V Sub-Custody
Partnership, L.P.
* 10.21 Warrant Certificate dated March 5, 1999 between Inland and
TCW Portfolio No. 1555 DR V Sub-Custody Partnership, L.P.
representing 58,512 shares.
* 10.22 Swap Agreement dated March 10, 1999 between Inland and Enron
Capital and Trade Resources Corp.
* 10.23 Swap Agreement dated March 10, 1999 between Inland and Enron
Capital and Trade Resources Corp.
* 21.1 Subsidiaries of Inland.
* 23.1 Consent of Arthur Andersen LLP.
* 23.2 Consent of Ryder Scott Company Petroleum Engineers.
* 27.1 Financial Data Schedule.
- ------------------------------------
* Filed herewith
(b) Reports on Form 8-K
No reports on Form 8-K were filed during the fourth quarter of 1998.
33
36
SIGNATURES
In accordance with Section 13 or 15(d) of the Securities Exchange Act
of 1934, the Company has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
INLAND RESOURCES INC.
March 29, 1999
By: /s/ Kyle R. Miller
----------------------------------
Kyle R. Miller
Co-Chairman of the Board and Chief
Executive Officer
POWER OF ATTORNEY
Each person whose signature appears below hereby appoints Kyle R.
Miller 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, 1999 /s/ ARTHUR J. PASMAS
---------------------------------------------
Arthur J. Pasmas
Co-Chairman of the Board and Chief Executive
Officer
March 29, 1999 /s/ JOHN E. DYER
---------------------------------------------
John E. Dyer
President and Chief Operating Officer
March 29, 1999 /s/ BILL I. PENNINGTON
---------------------------------------------
Bill I. Pennington
Vice President and Chief Financial
Officer (Principal Financial Officer)
March 29, 1999 /s/ MICHAEL J. STEVENS
---------------------------------------------
Michael J. Stevens
Secretary, Treasurer and Controller
(Principal Accounting Officer)
March 29, 1999 /s/ THOMAS J. TRZANOWSKI
---------------------------------------------
Thomas J. Trzanowski
Director
March 29, 1999 /s/ GREGORY S. ANDERSON
---------------------------------------------
Gregory S. Anderson
Director
March 29, 1999 /s/ BRUCE M. SCHNELWAR
---------------------------------------------
Bruce M. Schnelwar
Director
37
INDEX TO FINANCIAL STATEMENTS
Page
----
Report of Independent Public Accountants F-2
Consolidated Balance Sheets, December 31, 1998 and 1997 F-3
Consolidated Statements of Operations for the three years ended
December 31, 1998, 1997 and 1996 F-5
Consolidated Statements of Stockholders' Equity for the
three years ended December 31, 1998, 1997 and 1996 F-7
Consolidated Statements of Cash flows for the three years ended
December 31, 1998, 1997 and 1996 F-8
Notes to Consolidated Financial Statements F-9
F - 1
38
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Inland Resources Inc.:
We have audited the accompanying consolidated balance sheets of Inland
Resources Inc. (a Washington corporation) and subsidiaries as of December 31,
1998 and 1997, and the related consolidated statements of operations, changes
in stockholders' equity and cash flows for each of the three years in the
period ended December 31, 1998. 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 generally accepted auditing
standards. 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, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As discussed in Note 1 to
the consolidated financial statements, the Company has suffered recurring
losses from operations and has a net working capital deficiency and under
current conditions, will not be able to satisfy its scheduled repayments under
its long-term debt facilities that raises substantial doubt about its ability
to continue as a going concern. Management's plans in regard to these matters
are also described in Note 1. The consolidated financial statements do not
include any adjustments relating to the recoverability and classification of
asset carrying amounts or the amount and classification of liabilities that
might result should the Company be unable to continue as a going concern.
Denver, Colorado,
March 29, 1999.
F-2
39
INLAND RESOURCES INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
December 31,
----------------------
ASSETS 1998 1997
------- --------
CURRENT ASSETS:
Cash and cash equivalents $ 1,627 $ 605
Accounts receivable and accrued sales 5,682 13,601
Inventory 5,353 6,974
Other current assets 700 2,087
--------- ---------
Total current assets 13,362 23,267
--------- ---------
PROPERTY AND EQUIPMENT, AT COST:
Oil and gas properties (successful efforts method) 180,538 143,829
Accumulated depletion, depreciation and amortization (21,433) (10,009)
--------- ---------
Total oil and gas properties, net 159,105 133,820
Other property and equipment, net 20,212 14,698
--------- ---------
Total property and equipment, net 179,317 148,518
OTHER LONG-TERM ASSETS 3,150 4,168
--------- ---------
Total assets $ 195,829 $ 175,953
========= =========
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 1998 1997
------- --------
CURRENT LIABILITIES:
Accounts payable $ 14,282 $ 6,238
Accrued expenses 2,408 3,614
Current portion of long-term debt 141,709 167
--------- ---------
Total current liabilities 158,399 10,019
LONG-TERM DEBT 17,114 122,944
ENVIRONMENTAL LIABILITY 875 1,000
COMMITMENTS AND CONTINGENCIES (Notes 1 and 11)
MANDATORILY REDEEMABLE PREFERRED SERIES C
STOCK, 100,000 shares issued and outstanding 9,568 9,568
ACCRUED PREFERRED SERIES C DIVIDENDS 1,534 450
WARRANTS OUTSTANDING 1,300 1,300
STOCKHOLDERS' EQUITY:
Preferred Class A stock, par value $.001; 20,000,000
shares authorized -- --
Common stock, par value $.001; 25,000,000 shares authorized,
8,529,765 and 8,359,830 issued and outstanding, respectively 9 8
Additional paid-in capital 42,758 41,856
Accumulated deficit (35,728) (11,192)
--------- ---------
Total stockholders' equity 7,039 30,672
--------- ---------
Total liabilities and stockholders' equity $ 195,829 $ 175,953
========= =========
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,
----------------------------------
1998 1997 1996
----------------------------------
REVENUES:
Refined product sales $ 68,477 $ -- $ --
Oil and gas sales 14,920 17,182 10,704
-------- -------- --------
Total revenues 83,397 17,182 10,704
OPERATING EXPENSES:
Cost of refinery feedstock 51,908 -- --
Refinery operating expenses 9,858 -- --
Lease operating expenses 8,362 3,780 1,435
Production taxes 454 383 610
Exploration 153 61 167
Impairment 4,164 -- --
Depletion, depreciation and amortization 12,795 6,480 3,428
General and administrative, net 3,974 2,118 1,670
-------- -------- --------
Total operating expenses 91,668 12,822 7,310
-------- -------- --------
OPERATING INCOME (LOSS) (8,271) 4,360 3,394
INTEREST EXPENSE (15,290) (4,759) (1,633)
INTEREST AND OTHER INCOME 321 380 384
-------- -------- --------
NET INCOME (LOSS) BEFORE EXTRAORDINARY LOSS (23,240) (19) 2,145
EXTRAORDINARY LOSS ON EARLY
EXTINGUISHMENT OF DEBT (Note 7) (212) (1,160) --
-------- -------- --------
NET INCOME (LOSS) (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 (1,084) (450) --
-------- -------- --------
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON
STOCKHOLDERS $(24,536) $ (2,209) $ 1,931
======== ======== ========
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,
----------------------------------------------
1998 1997 1996
------------- ------------- -------------
BASIC NET INCOME (LOSS) PER SHARE:
Continuing operations $ (2.90) $ (0.14) $ 0.38
Extraordinary loss (0.03) (0.16) --
------------- ------------- -------------
Total $ (2.93) $ (0.30)$ 0.38
============= ============= =============
Basic weighted average common
shares outstanding 8,387,895 7,377,944 5,148,056
============= ============= =============
DILUTED NET INCOME (LOSS) PER SHARE:
Continuing operations $ (2.90) $ (0.14)$ 0.30
Extraordinary loss (0.03) (0.16) --
------------- ------------- -------------
Total $ (2.93) $ (0.30)$ 0.30
============= ============= =============
Diluted weighted average common
shares outstanding 8,387,895 7,377,944 6,499,098
============= ============= =============
The accompanying notes are an integral part
of the consolidated financial statements.
F-6
43
INLAND RESOURCES INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In thousands, except share amounts)
Accrued
Preferred Stock Series B Common Stock
Shares Amount Dividend Shares Amount
-------- --------- ---------- -------- ---------
BALANCES, December 31, 1995 $ 106,850 $ 4,100 $ -- 40,927,999 $ 41
One-for-ten reverse stock split -- -- -- (36,835,151) (37)
Purchase of Farmout Inc. -- -- -- 1,309,880 1
Redemption of Preferred Series A (13,713) (740) -- -- --
Conversion of Preferred Series A (93,137) (3,360) -- 900,831 1
Issuance of Preferred Series B 1,000,000 10,000 -- -- --
Exercise of employee stock options -- -- -- 8,500 --
Accrued Preferred Series B dividend -- -- 670 -- --
Net income -- -- -- -- --
----------- ----------- ----------- ----------- -----------
BALANCES, December 31, 1996 1,000,000 10,000 670 6,312,059 6
Accrued Preferred Series B dividend -- -- 1,150 -- --
Conversion of Preferred Series B (1,000,000) (10,000) (1,820) 1,977,671 2
Preferred Series C dividends -- -- -- -- --
Exercise of employee stock options -- -- -- 70,100 --
Net loss -- -- -- -- --
----------- ----------- ----------- ----------- -----------
BALANCES, December 31, 1997 -- -- -- 8,359,830 8
Issuance of common stock under
Farmout Agreement -- -- -- 152,220 1
Preferred Series C dividends -- -- -- -- --
Exercise of employee stock options -- -- -- 17,715 --
Net loss -- -- -- -- --
----------- ----------- ----------- ----------- -----------
BALANCES, December 31, 1998 -- $ -- $ -- 8,529,765 $ 9
=========== =========== =========== =========== ===========
Additional
Paid-In Accumulated
Capital Deficit
----------- ------------
BALANCES, December 31, 1995 $ 19,146 $ (9,308)
One-for-ten reverse stock split 37 --
Purchase of Farmout Inc. 6,541 --
Redemption of Preferred Series A -- --
Conversion of Preferred Series A 3,360 --
Issuance of Preferred Series B -- --
Exercise of employee stock options 45 --
Accrued Preferred Series B dividend -- (670)
Net income -- 2,145
----------- -----------
BALANCES, December 31, 1996 29,129 (7,833)
Accrued Preferred Series B dividend -- (1,150)
Conversion of Preferred Series B 12,398 (580)
Preferred Series C dividends (450)
Exercise of employee stock options 329 --
Net loss -- (1,179)
----------- -----------
BALANCES, December 31, 1997 41,856 (11,192)
Issuance of common stock under
Farmout Agreement 865 --
Preferred Series C dividends -- (1,084)
Exercise of employee stock options 37 --
Net loss -- (23,452)
----------- -----------
BALANCES, December 31, 1998 $ 42,758 $ (35,728)
=========== ===========
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,
-----------------------------------
1998 1997 1996
--------- ---------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (23,452) $ (1,179) $ 2,145
Adjustments to reconcile net income (loss) to net cash
provided by operating activities-
Net cash used by discontinued operations -- -- (129)
Loss on disposal of discontinued operations -- -- 30
Depletion, depreciation and amortization 12,795 6,480 3,428
Amortization of debt issuance costs and debt discount 697 265 199
Loss on early extinguishment of debt 212 1,160 --
Impairment of assets 4,164 -- --
Interest payment with common stock 866 -- --
Effect of changes in current assets and liabilities--
Accounts receivable and accrued sales 7,919 (950) (1,376)
Inventory 1,257 (1,131) (445)
Other current assets 1,599 405 (223)
Accounts payable and accrued expenses 6,713 618 1,377
--------- --------- ---------
Net cash provided by operating activities 12,770 5,668 5,006
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Development expenditures and equipment purchases (41,993) (29,740) (23,252)
Acquisition of Roosevelt Refinery (3,334) -- --
Acquisition of oil and gas properties -- (69,532) --
Acquisition of Woods Cross Refinery, net -- (22,950) --
Payment to sell discontinued operations -- -- (500)
--------- --------- ---------
Net cash used in investing activities (45,327) (122,222) (23,752)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of preferred stock -- 9,568 10,000
Proceeds from sale of common stock 37 328 45
Proceeds from issuance of long-term debt 77,550 161,000 16,578
Payments of long-term debt (42,984) (60,099) (73)
Debt issuance costs (1,024) (3,669) (4)
Redemption of Preferred Series A stock -- -- (740)
--------- --------- ---------
Net cash provided by financing activities 33,579 107,128 25,806
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS 1,022 (9,426) 7,060
CASH AND CASH EQUIVALENTS, at beginning of period 605 10,031 2,971
--------- --------- ---------
CASH AND CASH EQUIVALENTS, at end of period $ 1,627 $ 605 $ 10,031
========= ========= =========
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, 1998
(1) BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business
Inland Resources Inc. (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. The
Company also operates a crude oil refinery located in Woods Cross, Utah (the
"Woods Cross Refinery"). The refinery has a processing capacity of
approximately 10,000 barrels per day and tankage capacity of 485,000 barrels
(see Note 5).
Going Concern
The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as going concern. However, the continuing low oil
price environment has significantly impacted the Company's financial condition.
The Company has a working capital deficit of $145.0 million at December 31, 1998
and generated a net loss of $23.5 million in the year ended December 31, 1998.
Approximately $141.7 million of the deficit is caused by principal amounts
related to the Company's long-term debt facilities. Based on current conditions,
the Company will not be able to make its principal payments as scheduled under
its long-term debt facilities. In addition, at December 31, 1998 the Company was
in default of certain provisions of its credit agreements and required
additional capital outside of cash flow from operations to fund a portion of its
outstanding accounts payable. The short-term liquidity issues were temporarily
mitigated in March 1999 when the Company's senior lenders advanced $3.25 million
which the Company immediately used to reduce outstanding accounts payable. As a
result of the items noted above, there is substantial doubt about the Company's
ability to continue as a going concern. The consolidated financial statements do
not include any adjustments relating to the recoverability and classification of
asset carrying amounts or the amount and classification of liabilities that
might result should the Company be unable to continue as a going concern.
The Company is considering a number of additional strategies to cure its
working capital and liquidity issues. A solution the Company is currently
pursuing is the following transaction. On January 18, 1999, the Company entered
into a non-binding letter of intent with Flying J Inc. ("Flying J") and Smith
Management LLC ("Smith Management") (an affiliate majority shareholder in the
Company) regarding the acquisition of certain assets by the Company from Flying
J or one of its subsidiaries. The acquisition includes a 25,000 barrel per day
refinery located in North Salt Lake City, eleven Flying J gasoline stations
located primarily in the Salt Lake City area and Idaho and all oil and gas
reserves owned by Flying J in the Uinta Basin, fifteen miles north of the
Monument Butte Field. The purchase price is $80.0 million in cash and
approximately 12.8 million shares of
F-9
46
the Company's common stock, par value $0.001 per share, which is equal to
approximately 60% of the shares outstanding after the acquisition. This
transaction would be accounted for as a reverse merger. A restructuring of the
Company's capital and debt structure could be required to effectuate the
acquisition. Management anticipates that if the transaction is consummated, it
will close during the third quarter of 1999. The acquisition is contingent on
preparation of definitive documents, financing, due diligence procedures and
approval by regulatory agencies, the Company's lenders, the Board of Directors
of each company and the Company's shareholders. The failure of any one of these
events could prevent the consummation of the acquisition.
If the proposed Flying J transaction is not consummated, the Company will
attempt to restructure its capital such that a drilling program can be resumed
although there is no assurance that the Company will be successful. Until the
capital restructuring is complete, the Company does not plan to drill
additional wells focusing instead on its continuing efforts to pressurize the
Monument Butte Field through additional development of its water injection
infrastructure. The Company plans to convert 30 wells to injection during 1999
while incurring net capital expenditures of $500,000. The Company also expects
to spend $900,000 performing required capital improvements at the Woods Cross
Refinery. 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,
capital availability and market conditions.
Other possible solutions the Company is considering include obtaining
additional modifications to its credit agreement, selling assets, issuing
additional debt or selling equity. The Company believes its lenders will assist
in solving the Company's liquidity and working capital issues, although
management can not be assured that the Company will obtain modifications or
concessions from its lenders or raise the necessary capital from other sources
in the time frames required. As a result, the Company may have to further slow
or stop development of the Monument Butte Field and suspend all upgrades at the
Woods Cross Refinery.
Consolidation
The accompanying financial statements include the accounts of the Company and
its subsidiaries, all of which are wholly-owned. All significant intercompany
accounts and transactions have been eliminated in consolidation.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with 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
depreciation, depletion and amortization for the oil and gas 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 as do refined product
pricing estimates for the refinery operations.
F-10
47
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, joint interest owners and refined product
purchasers. Although diversified within many companies, collectibility is
dependent upon the general economic conditions of the industry. To date,
write-offs of uncollectable accounts have been minimal.
Fair Value of Financial Instruments
The Company's financial investments consist of cash, trade receivables, trade
payables, accrued liabilities, long-term debt and mandatorily redeemable
preferred stock. 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.
Inventories and Exchanges
Inventories consist of crude oil and refined products recorded at the lower of
cost on a first-in, first-out basis or market. Also included in inventory is
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.
The Company has product exchange agreements with other companies. Exchange
transactions are considered asset exchanges, with deliveries offset against
receipts. The net exchange balance is included in inventory.
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 $150,000, $135,000 and
$135,000 during 1998, 1997 and 1996, respectively.
F-11
48
The provision for depletion, depreciation and amortization of developed oil and
gas properties is based on the units of production method, based on proved oil
and gas reserves determined using prices being received by the Company 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.
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 each asset base
which generates a distinct cash flow stream. The asset bases considered by the
Company were the oil and gas properties and the operating refinery. For the oil
and gas operations, the Company utilized an estimated price scenario based on
its budget and future estimates of oil and gas prices from industry projections
and future quoted prices. The assumptions used were based on an average oil
price of $12.90 per barrel and $2.26 per Mcf over the remaining estimated life
of the properties. The refinery operations considered historical trends and
future projections of crude prices and sales prices in developing the estimate
of future cash flows. If the net capitalized cost of each distinct asset pool
exceeds the applicable undiscounted calculation, the excess, as measured by fair
value, is recorded as a charge to operations.
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 the Company.
The Company assessed the realizability of the Roosevelt Refinery (see Note 5)
as an asset to be disposed of. Originally the Company intended to reactivate
the Roosevelt Refinery, however, the strategy changed shortly following its
purchase and the plan to merge with Flying J. Therefore the net realizable
value is the most appropriate estimate of carrying value. As such, the
Roosevelt Refinery is recorded as property held for sale with a projected net
realizable value of $500,000 after considering an impairment of $2.8 million.
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 scheduled
repairs and maintenance (turnaround) of the refinery operating units are accrued
and expensed over the estimated period until the next turnaround. Major
improvements are capitalized, and the assets replaced, are retired.
F-12
49
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 is recorded when
the conclusion by Company management is reached that the realizability of the
deferred tax asset is not more likely then not going to be realized.
Revenue Recognition
Sales of crude oil, natural gas and refined products are recorded upon delivery
to purchasers.
Earnings Per Share
Earnings or loss per share are presented for basic diluted net income (loss)
and, if applicable, for net income (loss) before extraordinary loss. Basic
earnings per share is computed by dividing net income (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 (see Note 4).
Recent Accounting Pronouncements
The FASB issued SFAS No. 130 "Reporting Comprehensive Income" in June 1997
which established standards for reporting and displaying comprehensive income
and its components in a full set of general purpose financial statements. In
addition to net income, comprehensive income includes all changes in equity
during a period, except those resulting from investments by and distributions
to owners. The adoption of SFAS No. 130 in the first quarter of 1998 did not
have any impact on the Company.
(2) FINANCIAL INSTRUMENTS
Periodically, the Company enters into commodity contracts to hedge or otherwise
reduce the impact of oil and gas price fluctuations and to help ensure the
repayment of indebtedness. The amortized cost and the monthly settlement gain
or loss are reported as adjustments to revenue in the period in which the
related oil or gas is sold or the scheduled settlement of interest rate
instruments. Hedging activities do not affect the actual sales price or
interest rate for the Company's crude oil and natural gas or debt facilities.
The Company is subject to the creditworthiness of its counterparties since the
contracts are not collateralized.
F-13
50
In June 1998, SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS No. 133"), 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 Company is currently assessing the effect of adopting SFAS No. 133 on its
financial statements and plans to adopt the statement on January 1, 2000.
Crude Oil Hedging Activities
As of December 31, 1998 the Company has a hedge in place with Enron (the "Enron
Hedge") that hedges crude oil production over a five year period beginning
January 1, 1996 in monthly amounts escalating from 8,500 Bbls in January 1996
to 14,000 Bbls in December 2000. The hedge is structured as a cost free collar
whereby if the average monthly price, based on NYMEX Light Sweet Crude Oil
Futures Contracts, is between $18.00 and $20.55 per barrel, no payment is
exchanged between the parties. On January 1, 1997, the Company paid $34,170 to
enter into a contract with Koch Gas Services Company ("Koch") that exactly
offsets the effect of the Enron Hedge during the period January 1998 through
December 2000. As a result, the potential for gains and losses with respect to
the Enron Hedge expired on January 1, 1998, and the Company recognized no net
gain or loss on the Enron Hedge in 1998, nor will any gain or loss be
recognized on the Enron Hedge in the future.
On May 12, 1997, the Company entered into a put contract with Enron for 100,000
barrels per month for the period January 1998 through March 1998 at a put price
of $16.00 per barrel. The Company recorded $95,000 of income under this
contract in the first quarter of 1998.
On March 12, 1998 the Company entered into a cost free collar with Enron
whereby the average monthly price, based on NYMEX Light Sweet Crude Oil Futures
Contracts, is between $14.50 and $17.70 per barrel. The collar covered 75,000
barrels per month for the period from April 1998 through December 1998. For the
year ended December 31, 1998, the Company recognized income of $532,000 on this
contract.
During 1998, 1997 and 1996 the Company had various other 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 resulted
in income of $550,000 in 1998 and losses of $217,000 and $535,000 in 1997 and
1996, respectively.
On March 10, 1999, the Company entered into two hedge contracts with Enron
Capital and Trade Resources Corp. ("Enron"), each of which cover 40,000 barrels
per month of crude oil production during the period April 1, 1999 through
December 31, 1999. The swap price on the first contract is $14.02 and the swap
price on the second contract is $14.54 based on NYMEX Light Sweet Crude Oil
Futures Contracts.
F-14
51
Interest Rate Hedging Activity
In April 1998, the Company entered into an interest rate put, whereby the
Company is paid the difference between 6.75% and LIBOR on a notional principle
amount of $35.0 million when the LIBOR rate is above 6.75%. The cost of this
put was $140,000 and will be amortized through December 2000, at which time the
put expires. The Company received no payments under this arrangement in 1998.
(3) INVENTORIES
Inventories at December 31, 1998 and 1997 consist of the following (in
thousands):
1998 1997
-------- --------
Crude oil $ 827 $ 1,006
Refined product 2,910 3,685
Tubular goods 1,416 1,994
Material and supplies 200 289
------- -------
Total $ 5,353 $ 6,974
======= =======
(4) EARNINGS (LOSS) PER SHARE
The calculation of earnings (loss) per share for the years ended December 31,
1998, 1997 and 1996 is as follows (in thousands, except per share data):
1998 1997 1996
------------------------------ -------------------------- -----------------------------
Per Share Per Share Per Share
Loss Shares Amount Income Shares Amount Income Shares Amount
------------------------------ -------------------------- -----------------------------
Income (loss) before extraordinary
item (23,240) $ (19) $2,145
Less: Preferred Series A redemption
premium - - (214)
Preferred Series B redemption
premium - (580) -
Preferred Series C stock
premium (1,084) (450) -
-------- ------
BASIC EARNINGS (LOSS) PER SHARE
Income (loss) before extraordinary
item attributable to common
stockholders (24,324) 8,388 $(2.90) (1,049) 7,378 $(0.14) 1,931 5,148 $0.38
====== ====== =====
EFFECT OF DILUTIVE SECURITIES
Options and warrants - - - - - 111
Convertible preferred stock - - - - - 667
Stock dividend on convertible
preferred stock - - - - - 573
-------- ------- ----- ------ ------
DILUTED EARNINGS (LOSS)
PER SHARE
Income (loss) before
extraordinary item
attributable to common
stockholders plus
assumed conversion $(24,324) 8,388 $(2.90) $(1,049) 7,378 $(0.14) $1,931 6,499 $0.30
======== ===== ====== ======= ===== ====== ====== ===== =====
F-15
52
(5) ACQUISITIONS
Farmout Inc.
On June 12, 1996, the Company entered into an agreement to acquire one hundred
percent (100%) of the outstanding capital stock of Farmout Inc., a company
affiliated with Smith Management, in exchange for 1,309,880 shares of the
Company's common stock. Under the terms of the agreement, the Company did not
issue the common stock until January 2, 1997. Since no contingencies existed as
to the common stock issuance, the 1,309,880 shares are considered outstanding
for purposes of reporting in the accompanying consolidated financial
statements. The purchase was valued at $6.55 million for accounting purposes.
The only assets of Farmout Inc. were twenty producing wells. Farmout Inc. had
no liabilities at the purchase date. Income tax liabilities arising prior to
June 12, 1996 are the responsibility of the prior owners and income tax
liabilities from June 12, 1996 forward are the responsibility of the Company.
The acquisition of Farmout Inc. was accounted for as a purchase, therefore, the
assets and results of operations of Farmout Inc. are included in the Company's
consolidated financial statements from the acquisition date forward.
Enserch
Effective September 1, 1997, the Company purchased producing oil and gas
properties and undeveloped acreage allocated in the Monument Butte region from
Enserch Exploration, Inc. ("Enserch") for $10.4 million. The acquisition was
accounted for as a purchase, therefore assets and results of operations of the
Enserch properties are included in the Company's consolidated financial
statements from the acquisition date forward. The Company funded this
acquisition with debt.
EREC
Effective September 30, 1997, the Company purchased producing oil and gas
properties and undeveloped acreage, in the same region as the Enserch
acquisition, from Equitable Resources Energy Company ("EREC") for a purchase
price of $56.0 million. The acquisition was also accounted for as a purchase,
and therefore the assets and results of operations of the EREC properties are
included in the Company's consolidated financial statements from the
acquisition date forward. The Company also funded the EREC acquisition with
debt.
Woods Cross Refinery
On December 31, 1997, the Company purchased certain assets and liabilities of
the refining business Crysen Refining, Inc. for a purchase price of $22.9
million. The acquisition was funded with bank debt. The acquisition of the
Woods Cross Refinery was accounted for as a purchase as of December 31, 1997,
and the assets and liabilities assumed are included in the Company's
consolidated balance sheet as of that date. Because the purchase was closed on
December 31, 1997, no revenues or expenses have been recorded in the Company's
1996 or 1997 consolidated statement of operations, while the 1998 consolidated
statement of operations includes a full year of refining operations.
F-16
53
In conjunction with the purchase of the Woods Cross Refinery, the Company also
purchased certain inventory and held a note receivable related to a refinery
located in Tacoma, Washington. A former director of Inland Refining, Inc. (a
wholly owned subsidiary of the Company), is also a director of the company to
which the note was issued. On February 1, 1999, the Company sold the inventory
to the same company holding the note and received $435,000 in immediate value
and added $200,000 to the note receivable. The note receivable totals $700,000,
bears interest at 10% and is payable at $15,000 per month with the balance due
June 15, 2000. This note is backed by the personal guarantee of the note
holder.
Roosevelt Refinery
On September 16, 1998, the Company closed on the acquisition of a crude oil
refinery know as the Roosevelt Refinery for a total purchase price of $2.25
million. This refinery was inactive at the time of purchase and remains so
today. Originally, the Company intended to reactivate the refinery to process
its production from the exploration and production segment and spent an
additional $1.09 million on consulting services related to design
considerations. Because of the plans to merge with Flying J, the Company
currently plans to sell the refinery or the units and equipment combined
therein. As a result, this asset is held as available for sale and has been
recorded at management's estimate of fair value.
(6) OTHER PROPERTY AND EQUIPMENT
December 31,
----------------------------
1998 1997
---------- ----------
(in thousands)
Vehicles $ 1,774 $ 1,054
Land and buildings 2,632 1,699
Refining plant and equipment 15,672 11,619
Furniture and fixtures 1,465 940
Leasehold improvements 165 24
Property held for sale 500 -
--------- ---------
22,208 15,336
Less accumulated depreciation (1,996) (638)
--------- ---------
Total $ 20,212 $ 14,698
========= =========
(7) LONG-TERM DEBT
TCW I Agreement
On November 29, 1995, the Company entered into a Credit Agreement (the "TCW I")
with Trust Company of the West and affiliated entities (collectively "TCW"),
which provided a recourse loan facility to the Company of up to $25.0 million
for the development of the Monument Butte Field. The Company advanced $5.0
million at closing. During 1996, $16.5 million of the $20.0 million of
remaining loan availability was drawn to fund development drilling in the
Monument Butte Field.
F-17
54
The remaining amount was drawn in January 1997. The TCW I bore interest at 10%
per annum. Interest was payable quarterly beginning March 1996 and minimum
payments of principal were required quarterly beginning March 1997. In addition
to these payments, the Company granted TCW an initial 7% overriding royalty
interest, proportionately reduced to the Company's working interest in the oil
and gas properties, commencing November 29, 1995 and continuing until the
internal annual rate of return to TCW equaled 16%, at which time it reduced to
3%, proportionately reduced to the Company's working interest, until TCW's
internal rate of return equaled 22%.
The TCW I subjected the Company to penalties on the overriding royalty interest
if the loan was prepaid prior to November 29, 1997. The Company paid a $250,000
commitment fee at closing and recorded an $800,000 loan discount relating to
the 7% override which was being amortized over the term of the loan using the
effective interest method. During 1997, the Company refinanced the TCW I and
expensed the unamortized discount and debt issuance costs totaling
approximately $864,000 as an extraordinary loss.
CIBC Loan Agreement
On June 30, 1997, the Company entered into a $50.0 million Credit Agreement
with Canadian Imperial Bank of Commerce (the "CIBC Loan Agreement"). The
initial advance of $26.0 million was funded on June 30, 1997. The loan
proceeds, along with cash on hand, were used to retire The TCW I loan
obligation and to purchase the override on the Company's properties held by
TCW. On August 15, 1997, an additional $9.0 million was drawn under the
facility to fund the acquisition of properties from Enserch. Interest under the
CIBC Loan Agreement was calculated at the London interbank eurodollar rate
("LIBOR") plus a spread of 1.875% or approximately 7.5%. The CIBC Loan
Agreement was repaid in full with proceeds provided by the financing described
below on September 30, 1997, resulting in the Company expensing the unamortized
debt issuance costs of approximately $296,000 as an extraordinary loss.
TCW and ING Credit Agreements
On September 30, 1997, the Company closed separate Credit Agreements with Trust
Company of the West and TCW Asset Management Company in their capacities as
noteholder and agent (collectively "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 ING Credit Agreement provided the Company
with an initial borrowing base of $45.0 million of which $17.8 million was
drawn at closing. Subsequent to closing of the ING Credit Agreement, a portion
of this loan was participated to Meespierson Capital Corp. and U.S. Bank
National Association. The proceeds from the loans were used to finance the
acquisition of the properties purchased from EREC, fund full repayment of the
CIBC Loan Agreement, pay transaction costs and provide the Company with working
capital. An additional $17.2 million was drawn under the ING Credit Agreement
before December 31, 1997 to fund operating capital and the acquisition of the
Woods Cross Refinery
The ING Credit Agreement constitutes a revolving line of credit until March 31,
1999, at which time it converts to a term loan payable in quarterly
installments through March 29, 2003. The quarterly installments, based on a
$73.25 million borrowing base, are $9.5 million on June 29, 1999, $6.2 million
for the next two quarters, $4.7 million for the next four quarters, $3.9
million for the next four quarters, $3.5 million for the next four quarters,
and $3.0 million on March 29, 2003. As of
F-18
55
December 31, 1998, $67.7 million was outstanding under the ING Credit
Agreement. Letters of credit, used to secure purchases of crude inventory for
the refining operations, of $2.3 million were also outstanding as of December
31, 1998. The ING loan bears interest, at the Company's option, at either (i)
the average prime rates announced from time to time by The Chase Manhattan
Bank, Citibank, N.A. and Morgan Guaranty Trust Company of New York plus 0.5%
per annum; or (ii) at LIBOR plus 1.75%. The Company has consistently selected
the LIBOR rate option resulting in a currently effective interest rate of
approximately 6.8%. As required by the ING and TCW Credit Agreements, on April
30, 1998 the Company paid $140,000 to put in place an interest rate hedge. The
hedge covers the period June 12, 1998 through December 12, 2000 and effectively
provides a 6.75% LIBOR rate interest ceiling (before consideration of the 1.75%
adjustment) on $35.0 million of borrowings under the ING Credit Agreement. The
ING Credit Agreement is secured by a first lien on substantially all assets of
the Company. The borrowing base under the ING facility is limited to the
collateral value of proved reserves as determined semiannually by the lender.
The TCW Credit Agreement is comprised of a $65.0 million tranche and a $10.0
million tranche and is payable interest only, at a rate of 9.75% per annum,
quarterly until the earlier of December 31, 2003 or the date on which the ING
loan is paid in full. At that time, the TCW Credit Agreement loan converts to a
term loan payable in twelve quarterly installments of principal and interest.
The quarterly principal installments are $6.25 million for the first four
quarters, $8.75 million for the next four quarters and $3.75 million for the
last four quarters. The Company granted a warrant to TCW to purchase 100,000
shares of common stock at an exercise price of $10.00 per share (subject to
anti-dilution adjustments) at any time after September 23, 2000 and before
September 23, 2007 (see Note 12). The Company also granted registration rights
in connection with such warrants. TCW is also entitled to additional interest
on the $65.0 million tranche in an amount that yields TCW a 12.5% internal rate
of return, such interest payment to be made concurrently with the final payment
of all principal and interest on the TCW Credit Agreement. Interest expense is
calculated using the effective interest method for these borrowings. For
purposes of the internal rate of return calculation, the Company is given
credit for the funding fee of $2.25 million paid to TCW at closing. In regards
to the $10 million tranche, upon payment in full of TCW Credit Agreement by the
Company, TCW may elect to "put" their warrant back to the Company and accept a
cash payment which will cause TCW to achieve a 12.5% rate of return on this
tranche. The TCW Credit Agreement restricts repayment of the indebtedness until
October 1, 1999. The TCW Credit Agreement is secured by a second lien on
substantially all assets of the Company.
On March 11, 1999, the Company entered into amendments of the ING Credit
Agreement and the TCW Credit Agreement. The ING amendment increased the
borrowing base to the $73.25 million noted earlier. The Company immediately
borrowed the additional $3.25 million of availability and used the proceeds to
reduce accounts payable. ING received a warrant to purchase 50,000 shares of
common stock at $1.75 as consideration for entering into the amendment. Under
the TCW amendment, TCW agreed to defer the quarterly payments for interest
accruing during the initial six months of 1999 until the earlier of December
31, 2003 or the date on which the ING loan is paid in full. The deferred
interest will bear interest at 12%. TCW received a warrant to purchase 58,512
shares of common stock at $1.75 as consideration for entering into the
amendment. The fair value of the borrowings under the ING and TCW Credit
Agreements cannot currently be assessed due to the current financial condition
of the Company.
F-19
56
The TCW and ING Credit Agreements have common 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. At December 31, 1998, the Company was in
violation of certain covenants common to both the ING Credit Agreement and the
TCW Credit Agreement. All lenders have been notified of the covenant defaults
including the filings of liens by vendors. In management's opinion, based on the
recent borrowing base increase and interest deferral, the Company's lenders
have shown a willingness to help the Company solve its working capital and
liquidity issues. Although there cannot be assurances, the Company does not
expect its lenders to issue notices of default allowing them to call their debt
for repayment in the near future. The Company's management is estimating that
current cash flow projections will not be sufficient to repay scheduled
maturities given the projected oil and gas pricing environment in 1999. As a
result, all borrowings for both these facilities have been classified as
current under the cross-collateralization provisions of these agreements.
Banque Paribas
The Company's Credit Agreement with Banque Paribas constituted a revolving line
of credit in an amount not to exceed $23.75 million. The Company initially drew
$12.5 million to partially fund the Crysen acquisition on December 31, 1997.
The facility was used to fund working capital requirements and for letters of
credit obligations. The Credit Agreement was secured by all refining assets of
the Company. The Company's ability to borrow funds or have letters of credit
issued under the Credit Agreement was subject to its compliance with various
financial covenants and ratios. Amounts outstanding bear interest at the prime
rate of The Chase Manhattan Bank in New York, New York, and interest is payable
monthly. On May 29, 1998, the Company repaid in full, the Credit Agreement with
Banque Paribas, resulting in $212,000 of unamortized debt issuance costs being
expensed as an extraordinary item.
Phillips
The Company assumed a $1.7 million note payable to Phillips Petroleum Company
("Phillips") in connection with the Crysen transaction. This note is unsecured
and is repayable based on quantities of Phillips' crude oil processed through
the Woods Cross Refinery, on a monthly basis. This agreement includes
provisions for minimum refining requirements per month. Phillips greatly
curtailed deliveries under the terms of the note, resulting in only a slight
decrease in the outstanding principal from December 31, 1997 to 1998. If the
note is not repaid by June 2003, the remaining principal outstanding at that
date is repayable in equal monthly installments over 5 years. Subsequent to
June 2003, the remaining principal outstanding bears interest at prime plus 3%,
with a cap of 12%. Based on the uniqueness of this transaction, fair value is
not a relevant measure for the Phillips note.
Smith Farmout
Commencing June 1, 1998, the Company's drilling program was conducted under a
Farmout Agreement with Smith Energy Partnership, an affiliate of Smith
Management. Funds expended by Smith Management pursuant to this agreement were
treated as debt by the Company for financial reporting purposes. Forty-three
wells were drilled under the Farmout Agreement in 1998, aggregating net
expenditures to Smith Management of $15.1 million (including management fees).
F-20
57
Under the Farmout Agreement, Smith Management agreed to fund 100% of the
drilling and completion costs for wells commenced prior to October 1, 1998 and
70% for wells commenced after September 30, 1998. At the Company's option,
Smith Management agreed to take production proceed payments either in cash or
in shares of the Company's common stock. If the Company elects to pay using
common stock, the stock is priced at a 10% discount to average closing price
for the production month to which the payment relates. Through December 31,
1998, the Company has elected to make all payments in the form of common stock
totaling 152,220 shares. Due to the uncertainty of timing for repayment of the
borrowings, all amounts outstanding have been classified as long-term,
scheduled beyond five years. 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 agree 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 price was calculated at less than $3.00
per share, such cash only to be paid if the Company's senior lenders agree to
such payment. The Farmout Agreement provides that Smith Management will
reconvey all drill sites 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% on
such expended sums. The carrying value of the Smith Farmout borrowing cannot be
determined given the Company's current financial condition.
A summary of the Company's long-term debt follows (in thousands):
December 31,
-----------------------
1998 1997
---------- ----------
TCW Credit Agreement $ 75,000 $ 75,000
Less discount on TCW Credit Agreement (955) (1,231)
--------- ---------
74,045 73,769
Smith Farmout 15,085 --
ING Credit Agreement 67,665 35,000
Banque Paribas -- 12,481
Phillips 1,593 1,660
Other 435 201
--------- ---------
Total 158,823 123,111
Current portion (141,709) (167)
--------- ---------
Long-term portion $ 17,144 $ 122,944
========= =========
F-21
58
As of December 31, 1998, the annual principal payments on long-term debt for
the next five years are as follows (in thousands):
1999 141,709
2000 30
2001 33
2002 37
2003 194
Thereafter 16,820
----------
$ 158,823
==========
(8) INCOME TAXES
In 1998 and 1997, 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, 1998 is as follows (in
thousands):
Deferred
December 31, Expense December 31,
1998 (Benefit) 1997
----------- ---------- ------------
Deferred tax assets:
Net operating loss carryforwards $ 14,174 $ 7,273 $ 6,901
Smith Farmout debt 5,483 5,483 --
-------- -------- --------
Total 19,657 12,756 6,901
Valuation allowance (9,939) (8,292) (1,647)
-------- -------- --------
Deferred tax assets 9,718 4,464 5,254
-------- -------- --------
Deferred tax liabilities:
Depletion, depreciation and amortization
of property and equipment (9,718) (4,464) (5,254)
-------- -------- --------
Deferred tax liabilities (9,718) (4,464) (5,254)
-------- -------- --------
Net deferred tax assets $ -- $ -- $ --
======== ======== ========
F-22
59
A valuation allowance is to be provided if it is more likely than not that some
portion or all of a deferred tax asset will not be realized. The Company's
ability to realize the benefit of its tax assets depends on the generation of
future taxable income through profitable operations and expansion of the
Company's oil and gas producing properties. The market, capital and
environmental risks associated with that growth requirement caused the Company
to conclude that a valuation allowance should be provided, except to the extent
that the benefit of operating loss carryforwards can be used to offset future
reversals of existing deferred tax liabilities. The Company will continue to
monitor the need for the valuation allowance that has been provided.
Income tax expense for 1998, 1997 and 1996 differed from amounts computed by
applying the statutory federal income tax rate as follows (in thousands):
December 31,
-------------------------------
1998 1997 1996
-------- -------- ---------
Expected statutory tax expenses at 34% $(7,974) $ (401) $ 729
Change in valuation allowance, net 8,292 540 (740)
Other (318) (139) 11
------- ------- -------
Net tax expense $ -- $ -- $ --
======= ======= =======
In 1997, $1.77 million of the valuation allowance was reversed upon the
acquisition of Farmout Inc. as the book basis in the purchased assets was
greater than the associated tax basis. No state or federal income taxes are
payable at December 31, 1998 or 1997, and the Company did not pay any income
taxes in 1998, 1997 or 1996.
At December 31, 1998, the Company had tax basis net operating loss
carryforwards available to offset future regular and alternative taxable income
of $38.0 million, that expire from 1999 to 2018. Utilization of the net
operating loss carryforwards are limited under the change of ownership tax
rules.
(9) CAPITAL STOCK
Common Stock
On May 22, 1996, 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 100,000,000 shares to 10,000,000 shares and
reduce outstanding common shares from 40,927,999 shares to 4,092,800 shares.
The shareholders further approved an increase in the number of post-split
authorized shares from 10,000,000 shares to 25,000,000. All earnings per share
amounts and weighted average common and common equivalent shares outstanding as
reported on the consolidated statement of operations have been calculated based
on post-reverse split share amounts.
F-23
60
Preferred Stock
On July 31, 1996, the Company sold an affiliate of Smith 950,000 shares of a
newly designated series of preferred stock of the Company (the "Series B
Stock") which has 1,000,000 shares designated in the series. A director of the
Company who is also a vice president of Smith entered into a similar agreement
pursuant to which he agreed to purchase the remaining 50,000 shares of Series B
Stock. The Series B Stock was issued by the Company for cash of $10.00 per
share (an aggregate of $10.0 million). Concurrently with the issuance of the
Series B Stock, the Company called for redemption of its outstanding Series A
Convertible Preferred Stock (the "Series A Stock"). Each record holder of
Series A Stock had the right to elect to receive either (i) cash in the amount
of $54.00 per share, or (ii) 9.6726 shares of common stock for each share of
Series A Stock. During 1996, 93,137 shares of Series A Stock elected to convert
into 900,831 shares of common stock. The remaining 13,713 shares of Series A
Stock were redeemed for $740,000.
The Series B Stock bears a dividend of 12% per annum on the Redemption Price
(defined below); has a liquidation preference over common stock equal to $10.00
per share plus any accumulated and unpaid dividends; is redeemable at a
"Redemption Price" equal to $10.00 per share, plus accumulated and unpaid
dividends; is convertible at a "Conversion Price" of $6.27 per share (divided
into the Redemption Price) subject to certain anti-dilution adjustments; and is
entitled to one vote per share of Series B Stock on all matters submitted to
the stockholders of the Company and will vote with the common stock as one
voting group or class, and not as a separate voting group or class, except
where required by law or except with regard to various amendments to the
Company's Articles of Incorporation affecting the Series B Stock or creating
another series of preferred stock with rights equal to or greater than the
rights of the Series B Stock. In addition, if at any time prior to July 31,
1998, (i) the Company sells all or substantially all of its assets other than
in the ordinary course of business, (ii) the Company merges or consolidates
with or into another person, (iii) a change of control of the Company occurs or
(iv) the Company is liquidated or dissolved, the holders of Series B Stock will
be entitled to a full two years of accumulated dividends in calculating amounts
payable upon liquidation, redemption or conversion to a number of calculated
common shares.
On July 21, 1997, the Company closed the sale of 100,000 shares of a newly
designated Series C Cumulative Convertible Preferred Stock (the "Series C Stock
") to an affiliate of Enron Corp. for cash of $10.0 million ($9.6 million net
of closing fees). Concurrently with the issuance of the Series C Stock, the
Company called for redemption its outstanding Series B Stock. The holders of
the Series B Stock waived redemption and instead elected to convert their
Series B Stock into 1,977,671 shares of the Company's common stock.
The Series C Stock is initially convertible at any time by the holder into
8.333 shares of the Company common stock, an effective conversion price of
$12.00 per share. The Series C Stock bears a dividend of 10% per annum.
Accumulated dividends may also be converted by the holder at the same ratio as
the Series C Stock. Subsequent to July 21, 2000, (the third anniversary), the
Company has the option to redeem for cash at par value ($100 per share) all
outstanding shares of Series C Stock plus accrued dividends. If not converted
by the holder or redeemed for cash by the Company prior to the later of (i)
July 21, 2005 (the eighth anniversary) or (ii) six months following maturity of
any high yield offering or long-term debt financing in the aggregate amount of
at least $25.0 million obtained after July 21, 1997, the Company must redeem
the Series C Stock and all
F-24
61
accrued dividends for (i) cash or, at the Company's election, (ii) common stock
issued at 80% of the market price of the common stock on the day of redemption.
Given the Company's current financial situation, the fair value of this
financial instrument cannot be reasonably determined.
The Company must also redeem the Series C Stock if (i) the Company enters into
any new line of business (other than exploration, development and production of
oil and gas) and holders of Series C Stock elect to be redeemed prior to the
Company commencing such new line of business, (the holder however waived its
right to redeem its shares as a result of closing on the purchase of the Woods
Cross Refinery) or (ii) the Company proposes to enter into a merger,
consolidation or share exchange pursuant to which holders of common stock would
receive cash or other property (rather than stock in the surviving company) in
a per share amount less than the effective conversion price for the Series C
Stock (which is initially $12 per share). The Series C Stock votes with common
stockholders on all matters based on the number of shares of Company common
stock the Series C Stock is convertible into; except for the approval of
amendments to the Series C Stock, the authorization of any other series of
preferred stock having equal or greater rights, and the approval of any merger,
consolidation or share exchange involving the Company unless the holder of the
Series C Stock receives equivalent stock with equivalent rights. In these
instances, the Series C Stock votes as a separate class. The Series C Stock
also carries anti-dilution protection, rights to demand registration at the
Company's expense and a liquidation preference equal to par value of all
outstanding shares plus accrued dividends.
(10) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest during 1998, 1997 and 1996 was approximately
$11,629,000, $4,092,000 and $1,616,000, respectively.
During 1998, the Company paid interest on the Smith Farmout transaction, as
allowed by its terms, by issuing common stock valued at $866,000.
During 1996, the Company purchased Farmout Inc. by issuing common stock valued
at $6,542,000.
(11) COMMITMENTS AND CONTINGENCIES
Lease Commitments
The Company leases office space, railcars, catalyst and equipment under
noncancellable operating leases. The Company has sublet office space under a
previous office lease to a third party. The difference between the sublease
income over the life of the previous lease and the required rental payments to
be made by the Company was charged to expense in 1997. Lease payments under
these outstanding leases, net of the sublease income, are approximately as
follows (in thousands):
1999 $1,347
2000 1,168
2001 1,049
2002 917
2003 402
------
Total $4,883
======
F-25
62
Total lease expense during 1998, 1997 and 1996 was $962,000, $148,000 and
$108,000, respectively.
Environmental Laws and Regulations
The Company is subject to increasingly demanding environmental standards
imposed by federal, state and local laws and regulations. It is the policy of
the Company to comply with applicable environmental laws and regulations.
Governmental regulations covering environmental issues are very complex and are
subject to continual change. Accordingly, changes in the regulations or
interpretations thereof, and the ultimate settlement of the amounts sought from
other parties, could result in material future costs to the Company in excess
of the amounts accrued. In connection with the Crysen acquisition, the Company
established a reserve of $1.0 million to accrue for environmental obligations,
various amounts were expended during 1998 against this accrual. As of December
31, 1998, the Company has a remaining accrual of $875,000 as management's
estimate of the most likely liability. The range of the liability is estimated
to be 44% lower and 11% higher. The Company is currently assessing the impact
of proposed Clean Air legislation on it operations.
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.
Effective January 1, 1999, the Company match was reduced to 100% of the first
2% of salary contributed. Matching contributions of $373,000, $50,000 and
$17,000 were made by the Company during 1998, 1997 and 1996, 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.
(12) STOCK OPTIONS AND WARRANTS
1988 Stock Option Plan
On August 25, 1988, the Company's Board of Directors adopted an incentive stock
option plan (the "1988 Plan") for key employees and directors of the Company. A
total of 212,800 shares of common stock are reserved for issuance under the
1988 Plan. All options under the Plan are granted and become exercisable 90
days after grant date and expire 10 years from the date of grant. All options
were exercisable at December 31, 1998.
F-26
63
1997 Stock Option Plan
On April 30, 1997, another incentive stock option plan (the "1997 Plan") was
adopted by the Board of Directors 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 500,000
shares for grant under the 1997 Plan of which 118,500 options (determined to
vest immediately) were granted during 1997 and 1998 at prices equal to the
market value of the Company's stock on the date of grant. There are 381,500
shares available for grant as of December 31, 1998.
A summary of option grants, exercise 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, 1995 150,460 $ 4.74 $2.50 - $ 11.50
Granted 62,340 6.54 5.00 - 6.87 $2.99
====
Exercised (8,500) 5.31 3.13 - 6.50
------- ------ -------------------
Balance, December 31, 1996 204,300 5.26 2.50 - 11.50
Granted 88,500 10.36 8.50 - 11.00 $5.54
====
Exercised (70,100) 4.69 3.13 - 6.87
------- ------ -------------------
Balance, December 31, 1997 222,700 7.58 2.50 - 11.50
Granted 30,000 8.44 8.44 - 8.44 $6.08
====
Exercised (6,800) 5.46 2.50 - 6.87
------- ------ -------------------
Balance, December 31, 1998* 245,900 $ 7.64 $ 2.50 $ 11.50
======= ====== ======== ========
*All options are exercisable as of December 31, 1998.
Non-Plan Grants
On May 22, 1996, the Warrant Agreement entered into on February 23, 1993, with
the co-chief executive officer of the Company was terminated. The Warrant
Agreement provided for the automatic grant of five-year warrants equal to 5% of
the number of shares issued by the Company with an exercise price equal to the
price at which such shares were issued. In consideration for the termination of
the Warrant Agreement, the Compensation Committee extended the term of all
warrants granted under the agreement (a total of 201,911 warrants) to June 1,
2003. All such warrants were outstanding and exercisable at December 31, 1998.
F-27
64
From time to time the Company grants nonqualified warrants and options to
purchase common stock to its executive officers. The grants have vesting
periods ranging from immediate to three years. The grants' lives vary from five
to ten years. The table below summarizes the activities associated with these
grants to executive officers.
Weighted
Weighted Warrant Fair Value
Number of Average Exercise of Options
Options and Exercise Price and Warrants
Warrants Price Range Granted
--------- --------- --------------- ------------
Balance, December 31, 1995 201,911 $ 4.93 $5.00 - $ 6.51
Terminated (201,911) 4.93 5.00 - 6.51
Granted 401,911 5.36 3.13 - 6.50 $2.51
====
-------- ------ --------------
Balance, December 31, 1996 401,911 5.36 3.13 - 6.50
Granted 545,000 10.33 9.00 - 11.00 $4.89
====
-------- ------ --------------
Balance, December 31, 1997
and 1998* 946,911 $ 8.21 $3.13 - $11.00
======== ====== ===== ======
Non plan options and warrants
exercisable as of
December 31, 1998 624,411 $ 7.15
======= ======
*No activity during 1998.
As discussed in Note 7, during 1997, a warrant to purchase 100,000 shares of
common stock was issued to TCW in conjunction with the debt offering. These
warrants vest on September 23, 2000 and have a ten year life. The discounted
value ascribed to these warrants was $1,300,000 and was recorded as warrants
outstanding on the date of grant.
During 1997, the Company also granted warrants to purchase 300,000 shares of
common stock to four officers of the Company at a grant price of $16.00 per
warrant. These grants are not actually considered outstanding until certain
performance targets have been met by the Company. The grant period begins on
November 11, 2000 and extends over a three year period. As a result of the
unknown market price at the time of actual grant, these warrants are accounted
for as a variable option plan and the value of the grant is marked-to-market. As
of December 31, 1998, no compensation expense has been recorded associated with
these warrants.
On March 15, 1995, the Company issued a consultant a warrant to purchase 25,000
shares of Common Stock at $6.50 per share. The warrant was exercised in 1998.
F-28
65
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. If compensation expense for grants of stock options and
warrants had been determined consistent with Statement on Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation," the Company's net
income (loss) and earnings per share ("EPS") would have been reduced to the
following pro forma amounts (in thousands, except per share data):
1998 1997 1996
-------- --------- ---------
Net income (loss) As reported $(23,452) $(1,179) $2,145
Pro forma (24,714) (5,734) 1,451
Basic EPS As reported (2.93) (0.30) 0.38
Pro forma (3.08) (0.92) 0.29
Diluted EPS As reported (2.93) (0.30) 0.30
Pro forma (3.08) (0.92) 0.23
Due to the requirements of Statement No. 123, the calculated compensation
expense in 1998, 1997 and 1996 as adjusted in the pro forma amounts above, may
not be representative of compensation expense to be calculated in future years.
The pro forma adjustments are calculated using an estimate of the fair value of
each option and warrant on the date of grant. The Company used the following
assumptions within the Black-Scholes pricing model to estimate the fair value
of stock option and warrant grants in 1998, 1997 and 1996:
1998 1997 1996
-------- -------- ---------
Weighted average remaining life 5 years 4.9 years 4.8 years
Risk-free interest rate 5.3% 5.7% to 6.5% 5.1% to 7.3%
Expected dividend yield 0% 0% 0%
Expected lives 5 years 3 to 5 years 3 to 5 years
Expected volatility 87.5% 54.3% 57.1%
(13) SEGMENT AND RELATED INFORMATION
In 1998, the Company adopted SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information" that established standards for reporting
information about operating segments. SFAS No. 131 also establishes standards
for related disclosures about products and services and major customers.
The Company operates in two segments; oil and gas exploration, development and
production ("E&P") operations in the Monument Butte Field in Utah and crude oil
refining in Woods Cross, Utah. No segment disclosures are presented for 1997 or
1996 as Inland operated only in the E&P segment until the acquisition of the
Woods Cross Refinery on December 31, 1997 for $22.9 million. Segment
disclosures for the year ended December 31, 1998 are as follows (in thousands).
F-29
66
Year Ended December 31, 1998
-----------------------------------------
E&P Refinery Eliminations Total
------- ---------- ------------- -------
Revenues from external customers $ 14,920 $ 68,477 $ -- $ 83,397
Revenues from transactions with operating
segments of the same enterprise 6,358 -- (6,358) --
Interest income and other 604 215 (498) 321
Interest expense 14,895 892 (497) 15,290
Lease operating and production taxes 8,816 -- -- 8,816
Depreciation, depletion and amortization 12,025 770 -- 12,795
Extraordinary items -- 212 -- 212
Capital additions 39,391 5,936 -- 45,327
Total assets at December 31, 1998 183,389 27,222 (14,782) 195,829
Sales to the following Company's represented 10% or more of the Company's
revenues (in thousands):
1998 1997 1996
-------- -------- --------
Customer A $19,141 $ -- $ --
Customer B 11,232 -- --
Customer C 10,370 12,320 10,129
Customer D -- 3,086 1,196
(14) OIL AND GAS PRODUCING ACTIVITIES
Cost Incurred in Oil and Gas Producing Activities (in thousands):
1998 1997 1996
-------- ------- --------
Unproved property acquisition cost $ 303 $12,543 $ 189
Proved property acquisition cost 105 56,989 363
Development cost 37,709 28,563 21,577
Exploration cost 153 61 875
------- ------- -------
Total $38,270 $98,156 $23,004
======= ======= =======
F-30
67
Net Capital Costs
Net capitalized costs related to the Company's oil and gas producing activities
are summarized as follows (in thousands):
1998 1997 1996
-------- -------- --------
Unproved properties $ 14,585 $ 13,806 $ 6,165
Proved properties 161,472 127,500 39,693
Gas and water transportation facilities 4,481 2,523 975
--------- --------- ---------
Total 180,538 143,829 46,833
Accumulated depletion, depreciation and
amortization (21,433) (10,009) (3,835)
--------- --------- ---------
Total $ 159,105 $ 133,820 $ 42,998
========= ========= =========
Results of Operations For Oil and Gas Producing Activities
Had the Company been in position to pay income taxes based on the statutory tax
rate for the period, the results of operations, defined as revenues, less
production costs, exploration expenses, depreciation, depletion and
amortization, valuation provisions and income taxes would have been $187,000,
$4,275,000 and $3,342,000 for the years ended December 31, 1998, 1997 and 1996,
respectively.
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, as discussed previously, are equally applicable to
the standardized measure computations since these estimates are the basis for
the valuation process.
F-31
68
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):
1998 1997 1996
-------- --------- ---------
Future cash inflows $ 183,642 $ 694,065 $ 210,473
Future production costs (88,870) (251,434) (63,007)
Future development costs -- (232,087) (31,941)
Future income tax provision -- (33,394) (27,174)
--------- --------- ---------
Future net cash flows 94,772 177,150 88,351
Less effect of 10% discount factor (40,659) (98,528) (35,368)
--------- --------- ---------
Standardized measure of discounted
future net cash flows $ 54,113 $ 78,622 $ 52,983
========= ========= =========
The principal sources of changes in the standardized measure of discounted
future net cash flows are as follows for the years ended December 31, 1998,
1997 and 1996 (in thousands):
1998 1997 1996
-------- --------- ---------
Standardized measure, beginning of year $ 78,622 $ 52,983 $ 9,431
Purchase of reserves in place 76 45,747 5,398
Sales of oil and gas produced, net of
production costs (12,462) (13,019) (8,659)
Net change in prices, net production cost (96,051) (42,277) 13,448
Extensions, discoveries and improved
recovery, net 7,910 12,922 96,807
Revisions of previous quantity estimates (58,104) 12,351 1,428
Change in future development costs 232,087 9,557 (16,122)
Net change in income taxes 15,200 3,706 (22,954)
Accretion of discount 9,384 7,190 (13,838)
Changes in production rates and other (122,549) (10,538) (11,956)
--------- --------- ---------
Standardized measure, end of year $ 54,113 $ 78,622 $ 52,983
========= ========= =========
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-32
69
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, 1998, the Company used prices of $7.60 per Bbl
and $2.34 per Mcf which is reflective of the actual price received by the
Company. The Company is currently receiving approximately $11.00 per Bbl and
$1.90 per Mcf for the sale of its oil and gas.
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, 1998, 1997 and 1996:
1998 1997 1996
--------------------- --------------------- ---------------------
Oil (MBbl) Gas (MMcf) Oil (MBbl) Gas (MMcf) Oil (MBbl) Gas (MMcf)
--------------------- --------------------- ---------------------
Proved reserves, beginning of year 37,135 75,483 7,312 10,188 3,016 5,663
Purchase of reserves in place 21 14 15,071 26,387 485 1,202
Extensions and discoveries -- -- 12,836 34,744 3,950 5,807
Improved recoveries 3,145 2,814 1,723 (1,870) -- --
Production (1,501) (3,006) (855) (1,637) (502) (710)
Revisions of previous estimates (20,198) (57,242) 1,048 7,671 363 (1,774)
------- ------- ------- ------- ------- -------
Proved reserves, end of year 18,602 18,063 37,135 75,483 7,312 10,188
======= ======= ======= ======= ======= =======
Proved developed reserves,
beginning of year 12,980 15,224 4,385 5,409 1,227 1,223
======= ======= ======= ======= ======= =======
Proved developed reserves,
end of year 18,394 18,030 12,980 15,224 4,385 5,409
======= ======= ======= ======= ======= =======
(15) QUARTERLY EARNINGS (UNAUDITED)
Summarized unaudited quarterly financial data for 1998 and 1997 is as follows
(in thousands, except per share data):
Quarter Ended
--------------------------------------------------
March 31, June 30, September 30, December 31,
1998 1998 1998 1998
---------- ---------- ---------- --------------
Revenues $ 22,081 $ 21,753 $ 20,845 $ 18,718
Operating income (loss) (603) 1,356 (459) (8,565)
Net loss before extraordinary item (3,870) (2,136) (4,224) (13,010)
Net loss (3,870) (2,348) (4,224) (13,010)
Basic and diluted loss per share
before extraordinary item (0.49) (0.28) (0.53) (1.60)
Basic and diluted loss per share (0.49) (0.31) (0.53) (1.60)
F-33
70
Quarter Ended
--------------------------------------------------
March 31, June 30, September 30, December 31,
1997 1997 1997 1997
---------- ---------- ---------- --------------
Revenues $3,602 $2,885 $3,915 $6,780
Operating income 1,114 587 860 1,798
Net income (loss) before
extraordinary item 631 78 323 (1,051)
Net income (loss) 631 (768) 28 (1,051)
Basic earnings (loss) per share
before extraordinary item 0.10 0.01 (0.03) (0.15)
Diluted earnings (loss) per share
before extraordinary item 0.08 0.01 (0.03) (0.15)
Basic earnings (loss) per share 0.10 (0.12) (0.07) (0.15)
Diluted earnings (loss) per share 0.08 (0.09) (0.07) (0.15)
F-34
71
INDEX TO 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 July 21, 1997 (filed as Exhibit 3.1 to Inland's Form
10-QSB for the quarter ended June 30, 1997, 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 fiscal 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).
* 4.1.2 Amended and Restated Credit Agreement dated as of
September 11, 1998 amending and restating Exhibit 4.1.
* 4.1.3 First Amendment to Amended and Restated Credit Agreement
dated as of March 5, 1999 amending Exhibit 4.1.2.
72
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.
* 4.2.3 First Amendment to Amended and Restated Credit Agreement
dated as of March 5, 1999, amending Exhibit 4.2.2.
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.
* 4.3.3 First Amendment to Amended and Restated Intercreditor
Agreement dated as of March 5, 1999, amending Exhibit 4.3.2.
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).
4.6 Credit Agreement dated as of December 24, 1997 between
Inland Refining, Inc. and Banque Paribas (without exhibits)
(filed as Exhibit 4.1 to the Company's Current Report on
Form 8-K dated December 31, 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 fiscal 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 fiscal 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 fiscal year ended December 31, 1994, and incorporated
herein by reference).
73
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 Warrant Agreement and Warrant Certificate between Kyle R.
Miller and Inland dated February 23, 1993 (filed as Exhibit
10.2 to Inland's Current Report on Form 8-K dated February
23, 1993, and incorporated herein by reference).
10.2.1 Warrant Certificate between Kyle R. Miller and Inland dated
October 15, 1993 representing 3,150 shares (filed as Exhibit
10.2.1 to Inland's Annual Report on Form 10-KSB for the
fiscal year ended December 31, 1994, and incorporated herein
by reference).
10.2.2 Warrant Certificate between Kyle R. Miller and Inland dated
March 22, 1994 representing 5,715 shares (filed as Exhibit
10.2.2 to Inland's Annual Report on Form 10-KSB for the
fiscal year ended December 31, 1994, and incorporated herein
by reference).
10.2.3 Warrant Certificate between Kyle R. Miller and Inland dated
September 21, 1994 representing 44,811 shares (filed as
Exhibit 10.2.3 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1994, and incorporated
herein by reference).
10.2.4 Warrant Certificate between Kyle R. Miller and Inland dated
September 21, 1994 representing 38,523 shares (filed as
Exhibit 10.2.4 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1994, and incorporated
herein by reference).
10.2.5 Warrant Certificate between Kyle R. Miller and Inland dated
September 21, 1994 representing 30,000 shares (filed as
Exhibit 10.2.5 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1994, and incorporated
herein by reference).
10.2.6 Amendment to Warrant Certificates filed as Exhibits 10.2,
10.2.1 and 10.2.2 (filed as Exhibit 10.2.6 to Inland's
Annual Report on Form 10-KSB for the fiscal year ended
December 31, 1994, and incorporated herein by reference).
10.2.7 Warrant Certificate between Kyle R. Miller and Inland dated
November 16, 1993 representing 1,500 shares (filed as
Exhibit 10.2.7 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1995, and incorporated
herein by reference).
10.2.8 Warrant Certificate between Kyle R. Miller and Inland dated
March 15, 1995 representing 1,250 shares (filed as Exhibit
10.2.8 to Inland's Annual Report on Form 10-KSB for the
fiscal year ended December 31, 1995, and incorporated herein
by reference).
10.2.9 Warrant Certificate between Kyle R. Miller and Inland dated
November 6, 1995 representing 30,000 shares (filed as
Exhibit 10.2.9 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1995, and incorporated
herein by reference).
10.2.10 First Amendment to Warrant Agreement between Inland and
Kyle R. Miller dated October 19, 1995 (filed as Exhibit 10.1
to Inland's Quarterly Report on Form 10-QSB for the fiscal
quarter ended September 30, 1995, and incorporated herein by
reference).
10.2.11 Warrant Certificate between Inland and Kyle R. Miller dated
May 22, 1996 (corrected version) (filed as Exhibit 10.2.11
to Inland's Annual Report on Form 10-KSB for the fiscal year
ended December 31, 1996, and incorporated herein by
reference).
74
10.2.12 Warrant Certificate between Inland and Kyle R. Miller dated
January 23, 1997 representing 70,000 shares (filed as
Exhibit 10.2.12 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1996, and incorporated
herein by reference).
10.2.13 Option Certificate between Inland and Kyle R. Miller dated
November 10, 1997 representing 225,000 shares (filed as
Exhibit 10.2.13 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1997, and incorporated
herein by reference).
10.3 Employment Agreement between Inland and Kyle R. Miller dated
June 1, 1996 (filed as Exhibit 10.2 to Inland's Quarterly
Report on Form 10-QSB for the quarter ended June 30, 1996,
and incorporated herein by reference).
10.4 Employment Agreement between Inland and Bill I. Pennington
dated June 1, 1996 (corrected version) (filed as Exhibit
10.9.2 to Inland's Annual Report on Form 10-KSB for the
fiscal year ended December 31, 1996, and incorporated herein
by reference).
10.5 Chevron Crude Oil Purchase Contract No. 531144 dated
October 25, 1998, as amended by Amendment No. 1 dated
November 27, 1989, Amendment No. 2 dated September 12, 1990,
Amendment 3 dated July 15, 1991, Amendment No. 4 dated
January 22, 1992, Amendment No. 5 dated January 13, 1993,
and the March 4, 1992 letter from Chevron U.S.A. Products
Company to all Chevron Products Company customers (filed as
Exhibit 10.29 to Inland's Registration Statement on Form
S-4, Registration No. 33 80392, and incorporated herein by
reference).
10.6 Registration Rights Agreement dated September 21, 1994
between Inland and Energy Management Corporation, a wholly
owned subsidiary of Smith Management Company, Inc. and the
assignee of Smith Management Company, Inc. under the
Subscription Agreement filed as Exhibit 10.9 (filed as
Exhibit 10.19 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1994, and incorporated
herein by reference).
10.6.1 Correspondence constituting an amendment/clarification of
the Registration Rights Agreement filed as Exhibit 10.10
(filed as Exhibit 10.19.1 to Inland's Annual Report on Form
10-KSB for the fiscal year ended December 31, 1994, and
incorporated herein by reference).
10.6.2 Registration Rights Agreement dated March 20, 1995 between
Inland and Energy Management Corporation (filed as Exhibit
10.19.2 to Inland's Annual Report on Form 10-KSB for the
fiscal year ended December 31, 1994, and incorporated herein
by reference).
10.7 Warrant Certificate dated November 22, 1995 granted by
Inland to Randall D. Smith, together with Exhibit "A", a
Registration Rights Agreement (filed as Exhibit 10.29.1 to
Inland's Annual Report on Form 10-KSB for the fiscal year
ended December 31, 1995, and incorporated herein by
reference).
10.7.1 Form of Registration Rights Agreement dated June 12, 1996
between Inland, Smith Management Company, Inc. and Randall
D. Smith, Jeffrey A. Smith and John W. Adams (filed as
Exhibit 10.2 to Inland's Current Report on Form 8-K dated
June 12, 1996, and incorporated herein by reference).
10.7.2 Security Agreement dated June 12, 1996 between
Randall D. Smith, Jeffrey A. Smith and John W. Adams and
Inland (filed as Exhibit 10.3 to Inland's Current Report on
Form 8-K dated June 12, 1996, and incorporated herein by
reference).
75
10.7.3 Form of Agreement dated June 12, 1996 between Inland and
Arthur J. Pasmas (filed as Exhibit 10.4 to Inland's Current
Report on Form 8-K dated June 12, 1996, and incorporated
herein by reference).
10.7.4 Form of Registration Rights Agreement entered into as of
July 31, 1996 between Inland and Arthur J. Pasmas (filed as
Exhibit 10.5 to Inland's Current Report on Form 8-K dated
June 12, 1996, and incorporated herein by reference).
10.7.5 Form of Amendment to Registration Rights Agreement filed as
Exhibit 10.29.6 (filed as Exhibit 10.29.7 to Inland's Annual
Report on Form 10-KSB for the fiscal year ended December 31,
1996, and incorporated herein by reference).
10.8 Crude Oil Call/Put Option (Costless Collar) between IPC and
Koch Gas Services Company dated November 20, 1995 (filed as
Exhibit 10.30 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1995, and incorporated
herein by reference).
10.9 Swap Agreement dated November 22, 1994 between Inland and
Joint Energy Development Investments Limited Partnership
(filed as Exhibit 10.1 to Inland's Quarterly Report on Form
10-QSB for the fiscal quarter ended June 30, 1995, and
incorporated herein by reference).
10.10 Employment Agreement between Inland and John E. Dyer dated
June 1, 1996 (corrected version) (filed as Exhibit 10.35 to
Inland's Annual Report on Form 10-KSB for the fiscal year
ended December 31, 1996, and incorporated herein by
reference).
10.10.1 Amendment to Employment Agreement filed as Exhibit 10.26
(filed as Exhibit 10.35.1 to Inland's Annual Report on Form
10-KSB for the fiscal year ended December 31, 1996, and
incorporated herein by reference).
10.11 Warrant Certificate between Inland and John E. Dyer dated
May 22, 1996 representing 50,000 shares (corrected version)
(filed as Exhibit 10.37 to Inland's Annual Report on Form
10-KSB for the fiscal year ended December 31, 1996, and
incorporated herein by reference).
10.11.1 Warrant Certificate between Inland and John E. Dyer dated
January 23, 1997 representing 70,000 shares (filed as
Exhibit 10.37.1 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1996, and incorporated
herein by reference).
10.11.2 Option Certificate between Inland and John E. Dyer dated
November 10, 1997 representing 150,000 shares (filed as
Exhibit 10.28.2 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1997, and incorporated
herein by reference).
10.12 Warrant Certificate between Inland and Bill I. Pennington
dated May 22, 1996 representing 50,000 shares (corrected
version) (filed as Exhibit 10.38 to Inland's Annual Report
on Form 10-KSB for the fiscal year ended December 31, 1996,
and incorporated herein by reference).
10.12.1 Warrant Certificate between Inland and Bill I. Pennington
dated January 23, 1997 representing 60,000 shares (filed as
Exhibit 10.38.1 to Inland's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1996, and incorporated
herein by reference).
10.12.2 Option Certificate between Inland and Bill I. Pennington
dated November 10, 1997 representing 125,000 shares (filed
as Exhibit 10.29.2 to Inland's Annual Report on Form 10-KSB
for the fiscal year ended December 31, 1997, and
incorporated herein by reference).
10.13 Option Certificate between Inland and Michael J. Stevens
dated November 10, 1997
76
representing 100,000 shares (filed as Exhibit 10.30 to
Inland's Annual Report on Form 10-KSB for the fiscal year
ended December 31, 1997, and incorporated herein by
reference).
10.14 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 fiscal year ended
December 31, 1996, and incorporated herein by reference).
10.15 Collar between Koch Oil Company and Inland effective
January 1, 1997 (filed as Exhibit 10.42 to Inland's Annual
Report on Form 10-KSB for the fiscal year ended December 31,
1996, and incorporated herein by reference).
10.16 Securities Purchase Agreement dated July 21, 1997 between
Inland and Joint Energy Development Investments Limited
Partnership (filed as Exhibit 10.1 to Inland's Quarterly
Report on Form 10-QSB for the quarter ended June 30, 1997,
and incorporated herein by reference).
10.16.1 Registration Rights Agreement dated July 21, 1997 between
Inland and Joint Energy Development Investments Limited
Partnership (filed as Exhibit 10.2 to Inland's Quarterly
Report on Form 10-QSB for the quarter ended June 30, 1997,
and incorporated herein by reference).
10.17 Employment Agreement between Inland and Michael J. Stevens
dated May 1, 1997 (filed as Exhibit 10.39 to Inland's Annual
Report on Form 10-KSB for the fiscal year ended December 31,
1997, and incorporated herein by reference).
10.18 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).
10.19 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).
* 10.20 Warrant Agreement dated as of March 5, 1999 between Inland
Resources Inc. and TCW Portfolio No. 1555 DR V Sub-Custody
Partnership, L.P.
* 10.21 Warrant Certificate dated March 5, 1999 between Inland and
TCW Portfolio No. 1555 DR V Sub-Custody Partnership, L.P.
representing 58,512 shares.
* 10.22 Swap Agreement dated March 10, 1999 between Inland and Enron
Capital and Trade Resources Corp.
* 10.23 Swap Agreement dated March 10, 1999 between Inland and Enron
Capital and Trade Resources Corp.
* 21.1 Subsidiaries of Inland.
* 23.1 Consent of Arthur Andersen LLP.
* 23.2 Consent of Ryder Scott Company Petroleum Engineers.
* 27.1 Financial Data Schedule.
- --------------------------------
* Filed herewith