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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period ___ to ___
Commission File Number 0-16487
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INLAND RESOURCES INC.
(Exact Name of Registrant as Specified in its Charter)
WASHINGTON 91-1307042
(State or Other Jurisdiction of (IRS Employer
Incorporation or Organization) Identification Number)
410 17th Street
Suite 700
Denver, Colorado
(303) 893-0102 80202
(Address of Principal Executive Offices) (Zip Code)
Issuer's telephone number, including area code: (303) 893-0102
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Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act: Common Stock, par
value $.001 per share
Check whether the issuer (1) filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12
months (or for such shorter period that the issuer was required to file such
reports), and (2) has been subject to such filing requirements for the past 90
days. YES [X] NO [ ]
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, 2000, the registrant had outstanding 2,897,732 shares of
par value $.001 common stock. The aggregate value on such date of the common
stock of the Registrant held by non-affiliates was an estimated $1,178,000.
DOCUMENTS INCORPORATED BY REFERENCE
None
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TABLE OF CONTENTS
PAGE
PART I
Items 1. & 2. Business and Properties.......................................................................1
Item 3. Legal Proceedings............................................................................11
Item 4. Submission Of Matters To a Vote Of Security Holders..........................................11
PART II
Item 5. Market For Registrant's Common Stock and Related Stockholder Matters.........................13
Item 6. Selected Financial Data......................................................................14
Item 7. Management's Discussion And Analysis of Financial Condition and Results of Operations........15
Item 7A. Quantitative and Qualitative Disclosures About Market Risks..................................22
Item 8. Financial Statements and Supplementary Data..................................................23
Item 9. Changes In And Disagreements With Accountants On Accounting And Financial Disclosure.........23
PART III
Item 10. Directors and Executive Officers of the Registrant...........................................24
Item 11. Executive Compensation.......................................................................26
Item 12. Security Ownership of Certain Beneficial Owners and Management...............................29
Item 13. Certain Relationships and Related Transactions...............................................31
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K..............................33
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PART I
The following text is qualified in its entirety by reference to the
more detailed information and consolidated financial statements (including the
notes thereto) appearing elsewhere in this Annual Report on Form 10-K. Unless
the context otherwise requires, references to "Inland" shall mean Inland
Resources Inc., a Washington corporation, and references to the "Company" or its
operations shall mean Inland and its consolidated subsidiaries, including Inland
Production Company ("IPC"), a Utah corporation, Inland Refining, Inc.
("Refining"), a Utah corporation, and Inland Working Capital Company ("IWCC"), a
Utah corporation. For definitions of certain terms relating to the oil and gas
industry used in this section, see Items 1. and 2. "Business and Properties --
Certain Definitions."
All references to shares of Inland's common stock, par value $.001 per
share ("Common Stock"), and share prices in this Form 10-K have been adjusted to
give effect to the 1-for-10 reverse stock split effected December 14, 1999.
ITEMS 1. & 2. BUSINESS AND PROPERTIES
OVERVIEW
Inland Resources Inc. is an independent energy company engaged in the
acquisition, development, and enhancement of oil and gas properties in the
western United States. All of the Company's oil and gas reserves are located in
the Monument Butte Field (the "Field") within the Uinta Basin of northeastern
Utah. Until January 31, 2000, the Company was also engaged in the refining of
crude oil and wholesale marketing of refined petroleum products, including
various grades of gasoline, kerosene, diesel fuel, waxes and asphalt through
Refining. Inland conducts its operations through its subsidiaries, IPC and IWCC.
In 1999, IPC drilled 8 gross (7.5 net) developmental wells. At December 31,
1999, the Company's estimated net proved reserves totaled 57,285 MBOE, having a
pre-tax present value discounted at 10% using constant prices of $254 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 616 gross (486 net) oil
wells, including 163 gross (134 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 2000 in the Field are $14.5 million net to the
Company.
RECENT DEVELOPMENTS
Sale of Refinery Operations. Effective January 31, 2000, Inland sold
all of its capital stock in Refining to Silver Eagle Refining, Inc. ("Silver
Eagle") for $500,000 and the assumption of various refinery liabilities and
obligations. Refining owns the Wood Cross Refinery in Woods Cross, Utah and the
Roosevelt Refinery in Roosevelt, Utah (which was non-operating at the time of
sale). Prior to the sale, the existing cash, inventory, accounts receivable and
a note receivable were transferred to IWCC, and IWCC agreed to satisfy various
accounts payable and liabilities not assumed as part of the purchase price. As a
result of the sale of Refining to Silver Eagle, the Company is no longer engaged
in the business of refining crude oil and marketing refined petroleum products.
Change of Control and Recapitalization. On September 21, 1999, the
Company entered into an Exchange Agreement (the "Exchange Agreement") with Trust
Company of the West, as Sub-Custodian for Mellon Bank for the benefit of Account
No. CPFF 873-3032 ("Fund V"), TCW Portfolio No. 1555 DR V Sub-Custody
Partnership, L.P. ("Portfolio") (Portfolio and Fund V collectively being
referred to as "TCW"), Inland Holdings LLC ("Holdings") and Joint Energy
Development Investments II Limited Partnership ("JEDI"). Pursuant to the
Exchange Agreement, Fund V agreed to exchange $75 million in principal amount of
subordinated indebtedness of IPC plus accrued interest of $5.7 million and
Portfolio agreed to exchange warrants to purchase 15,852 shares of Common Stock
for the following securities of Inland issued to Holdings, whose members are
Fund V and Portfolio: (1) 10,757,747 shares of Series D Preferred Stock, (2)
5,882,901 shares of Series Z Preferred Stock, which automatically converted into
588,291 shares of Common Stock on December 14, 1999, and (3) 1,164,295 shares of
Common Stock; and JEDI agreed to exchange the 100,000 shares of Inland's Series
C Cumulative Convertible Preferred Stock ("Series C Preferred Stock") owned by
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JEDI, together with $2.2 million of accumulated dividends thereon, for (A)
121,973 shares of Series E Preferred Stock and (B) 292,098 shares of Common
Stock (the "Recapitalization"). The Series C Preferred Stock bore dividends at a
rate of $10 per share, had a liquidation preference of $100 per share and was
required to be redeemed at a price of $100 per share not later than January 21,
2008.
Following closing of the Exchange Agreement, Holdings owns 1,752,586
shares of Common Stock, representing approximately 60.5% of the outstanding
shares of Common Stock at March 15, 2000, and JEDI owns 292,098 shares of Common
Stock, representing approximately 10.1% of the outstanding shares of Common
Stock at March 15, 2000. The Company's Articles of Incorporation, as amended
(the "Articles"), provide that the Common Stock, Series D Preferred Stock and
Series E Preferred Stock shall vote together as a single class and not as a
separate voting group or class on all matters presented to the stockholders of
the Company, except as mandated by law or as expressly set forth in the
Articles. The Series D Preferred Stock and the Series E Preferred Stock vote
with the Common Stock on the basis of one vote for each 10 shares of Series D
Preferred Stock and Series E Preferred Stock. Pursuant to the Articles, the
total number of votes of the combined class of Common Stock, Series D Preferred
Stock and Series E Preferred Stock outstanding at March 15, 2000 is 3,985,704
votes, of which 2,828,361 votes (representing approximately 71% of the total)
are owned by Holdings, and 304,295 votes (representing approximately 7.6% of the
total) are owned by JEDI. TCW Asset Management Company has the power to vote and
dispose of the securities owned by Holdings.
OIL AND GAS EXPLORATION AND PRODUCTION OPERATIONS
General. The Company conducts exploration and production activities
primarily through IPC, which owns all of the oil and gas acreage, wells, gas
gathering systems, water delivery, injection and disposal systems and other oil
and gas related tangible assets of the Company. IPC serves as the operator of
616 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 1997, 1998 and 1999 are set
forth in pages F-5 and F-26 of this Annual Report.
Oil and Gas Reserves. The following table sets forth the Company's
estimated quantities of proved oil and gas reserves and the estimated future net
revenues (by reserve categories) without consideration of indirect costs such as
interest, administrative expenses or 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, 1999. 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-25 through F- 27 of this Annual Report.
As of December 31, 1999
----------------------------------
Proved Proved Total
Developed Undeveloped Proved
--------- ----------- -------
(dollars in thousands)
Net Proved Reserves
Oil (MBls) 16,634 30,495 47,129
Gas (MMcf) 15,475 45,460 60,935
MBOE (6Mcf per Bbl) 19,213 38,072 57,285
Estimated Future Net Revenues(1) $245,850 $433,364 $679,214
Present Value of Future Net Revenues(2) $118,915 $135,252 $254,167
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(1) Undiscounted.
(2) Discounted at 10%.
Future net revenues from reserves at December 31, 1999 were calculated
on the basis of average prices received by the Company in effect on that date
and were approximately $21.56 per barrel of oil and $1.83 per Mcf of gas. The
value of the estimated proved gas reserves are net of deductions for shrinkage
and natural gas required to power future field operations.
Petroleum engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact manner.
Estimates of economically recoverable oil and gas reserves and of future net
cash flows necessarily depend upon a number of variable factors and assumptions,
including the following:
o historical production from the area compared with production from other
producing areas;
o the assumed effects of regulations by governmental agencies;
o assumptions concerning future oil and gas prices; and
o assumptions concerning future operating costs, production taxes,
development costs and work over and remedial costs.
Because all reserve estimates are to some degree subjective, (a) the
quantities of oil and gas that are ultimately recovered, (b) the production and
operating costs incurred, (c) the amount and timing of future development
expenditures and (d) future oil and gas sales prices may differ materially from
those assumed in estimating reserves. Furthermore, different reserve engineers
may make different estimates of reserves and cash flows based on the same
available data. Inland's actual production, revenues and expenditures with
respect to reserves will likely vary from estimates and the variances may be
material.
No estimates of total proven net oil and gas reserves have been filed
by the Company with, or included in any report to, any United States authority
or agency pertaining to the Company's individual reserves since the beginning of
the Company's last fiscal year.
Production, Unit Prices and Costs. The following table sets forth
certain information regarding the production volumes of, average sale prices
received for, and average production costs for the sales of oil and gas by the
Company. See also, the Supplemental Oil and Gas Disclosures appearing on pages
F-25 through F-27 of this Annual Report.
Year Ended December 31,
-------------------------------------
1999 1998 1997
--------- --------- ---------
Net Production:
Oil (MBls) ........................ 1,165 1,501 855
Gas (MMcf) (1) .................... 2,901 3,006 1,637
Total (MBOE) ............. 1,649 2,002 1,128
Average Sale Price(2):
Oil (per Bbl) ..................... $ 14.38 $ 9.82 $ 16.17
Gas (per Mcf)(3) .................. $ 1.56 $ 2.00 $ 2.19
Average Production Cost:
($/BOE)(4) .................... $ 4.34 $ 4.18 $ 3.35
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(1) Excludes lease fuel used for operations.
(2) Does not reflect the effects of hedging transactions.
(3) Includes natural gas liquids.
(4) Includes direct lifting costs (labor, repairs and maintenance,
materials and supplies) and the administrative costs of
production offices, insurance and property taxes.
Drilling Activities. The following table sets forth the number of oil
and gas wells drilled in which the Company had an interest during 1999, 1998 and
1997.
1999 1998 1997
------------- ------------ ------------
Gross Net Gross Net Gross Net
----- ---- ----- ---- ----- ----
Development wells:
Oil(1) ................. 8.0 7.5 90 69 73 64
Dry .................... -- -- 5 4 5 4.8
---- ---- ---- ---- ---- ----
Total ...... 8.0 7.5 95 73 78 68.8
==== ==== ==== ==== ==== ====
Exploratory wells:
Oil(1) .............. -- -- -- -- 2 2
Dry ................. -- -- -- -- -- --
---- ---- ---- ---- ---- ----
Total ...... 0 0 0 0 2 2
==== ==== ==== ==== ==== ====
Total wells:
Oil(1) .............. 8.0 7.5 90 69 75 66.0
Dry ................. -- -- 5 4 5 4.8
---- ---- ---- ---- ---- ----
Total ...... 8.0 7.5 95 73 80 70.8
==== ==== ==== ==== ==== ====
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(1) All of the completed wells have multiple completions,
including both oil completions and gas completions.
Consequently, pursuant to the rules of the Securities and
Exchange Commission, each well is classified as an oil well.
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, 1999:
Wells(1)
-----------------------------------------------
Gross(2) Net(2)
--------------------- --------------------
Water Water
Location Oil(1) Injection Oil(1) Injection
- -------- ------ --------- ------ ---------
Utah(3) 468 166 354 135
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(1) The Company is an operator of 616 gross wells (486 net) and a
non-operator with respect to 18 gross (3 net) wells.
(2) Net wells represent the sum of the actual percentage working
interests owned by the Company in gross wells at December 31,
1999.
(3) All of the Company's wells are located in the Field.
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Acreage Data. The following table reflects the developed and
undeveloped acreage that the Company held as of December 31, 1999:
Developed Acreage Undeveloped Acreage(1)
-------------------- ---------------------
Gross Net Gross Net
Location Acres Acres Acres Acres
- -------- ------ ------ ------- ------
Utah(2) 25,500 20,800 120,300 95,500
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(1) Undeveloped acreage includes 58,500 gross (57,100 net) acres
held by production at December 31, 1999.
(2) All of the Company's acreage is located in the Field.
As of December 31, 1999, the undeveloped acreage not held by production
involves 313 leases with remaining terms of up to 10 years. Leases covering
approximately 11,800 net acres have expiration dates in 2000. 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 1999). 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, 1999, the Company had 166 wells injecting an
aggregate of 14,000 BWPD. During 1999, the Company installed 15 miles of water
pipelines to handle low pressure water delivery and high pressure water
injection. The Company also converted 22 gross (16.4 net) oil wells into
injection wells. At December 31, 1999, the Company owned and operated 120 miles
of water pipelines and seven water injection plants with an injection capacity
of 30,000 BWPD. Inland has experienced stabilized or increasing production in
many wells offsetting its water injection operations. Inland intends to continue
aggressively developing secondary recovery water flood operations by extending
infrastructure and initiating injection in as many as 50 wells in the Field
during 2000.
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 10.0 MMcf of natural gas per day and sells approximately 7.5 MMcf of
natural gas per day. The difference between the volume of natural gas produced
and sold is the amount of natural gas that the Company uses as lease fuel for
operations. The Company collects and markets approximately 90% of its operated
gas production using its gas gathering, transportation and compression system.
The system consists of approximately 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.
Delivery Commitments. The Company has no material delivery commitments
under contracts and substantially all of the Company's natural gas production is
sold on a month-to-month basis in the spot market. See "Markets for Oil and
Gas," below.
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.
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The crude oil produced from the Field is called Black Wax. The Black
Wax produced from the Field is primarily transported by truck and refined in
Salt Lake City. Transportation of large quantities of Black Wax by pipeline is
not currently feasible, and transportation by truck or rail to refineries in
California or Colorado is not economical. Black Wax is a valuable commodity
since it is low in sulfur content and can be distilled and cracked into high
margin petroleum products such as gasoline, diesel and jet fuel; however, it
does not blend well with other crude oil feedstocks in the refining process.
Since Black Wax has limited compatibility in blending, the demand for Black Wax
tends to become inelastic as the supply of Black Wax reaches the cracking and
blending capacity of the Salt Lake City refineries.
The Company estimates the existing refining capacity for Black Wax in
Salt Lake City to be slightly higher than local production. From 1995 to late
1999, 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) increased from $1.50 to $4.50 per barrel. This widening of
the basis differential was caused in part by the Company's substantial
production growth, which peaked in late 1998 at over 6,000 BPD from 100 BPD in
1993. Consistent with other producers in the area, the Company's Black Wax
production declined throughout 1999 as the low oil price environment reduced
drilling activities. The Company's production in December 1999 was 3,800 BPD. As
further explained below, the lower production base of Black Wax in Utah has
increased demand and allowed the Company to decrease the basis differential to
approximately $3.60 per barrel today.
Throughout most of 1999, the Company sold Black Wax at the average
monthly posted field price less a deduction of approximately $1.00 per barrel
for oil quality adjustments. The posted field price ranged from $7.75 to $23.75
during 1999 and $7.25 to $14.25 during 1998, and was $22.25 per barrel on
December 31, 1999. During 1999 and 1998, the Company sold approximately 8% and
51%, respectively, of its oil production to Chevron. In 1999, the Company sold
63% of its crude oil to Refining, and 29% of its crude oil to BP Amoco.
Late in 1999, the Company signed separate contracts with two Salt Lake
City refineries to sell Black Wax crude oil. The contracts expire at the end of
December 2000 and September 2001. The Company estimates the effect of the
contracts will be to lower the basis differential from NYMEX to $3.60 per barrel
during 2000. The NYMEX price ranged from $12.02 to $26.09 per barrel during 1999
and was $26.09 per barrel in December 1999. The availability of these
alternative purchasers contributed to the Company's decision to sell Refining.
It is possible that 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. As a result, there may be
downward pressure on Black Wax pricing beyond calendar year 2000. The Company
continues to work with area refineries to obtain a long-term solution for Black
Wax processing.
As noted above, the Company markets substantially all of its operated
gas production. The Company currently has a contract to sell 4,300 Mcf per day
through March 2000 at $1.97 per Mcf and a contract covering the period April
2000 through October 2000 to sell 2,600 Mcf per day at $2.41 per Mcf. Natural
gas marketed by the Company not subject to gas purchase agreements is sold on a
month-to-month basis in the spot market, the price of which ranged from $1.67 to
$3.30 per Mcf during 1999 and from $1.78 to $2.38 per Mcf during 1998, and was
$2.33 per Mcf for December 1999. All spot market sales during 1999 were made to
Wasatch Energy Corporation ("Wasatch"). Inland believes that the loss of Wasatch
as a purchaser of its gas production would not have a material adverse effect on
its results of operations due to the availability of other natural gas
purchasers in the area.
Regulation of Exploration and Production. The Company's oil and gas
exploration, production and related operations are subject to extensive rules
and regulations promulgated by federal and state agencies. Failure to comply
with such rules and regulations can result in substantial penalties. The
regulatory burden on the oil and gas industry increases the Company's cost of
doing business and affects its profitability. Because such rules and regulations
are frequently amended or interpreted differently by regulatory agencies, Inland
is unable to accurately predict the future cost or impact of complying with such
laws.
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The Company's oil and gas exploration and production operations are
affected by state and federal regulation of oil and gas production, federal
regulation of gas sold in interstate and intrastate commerce, state and federal
regulations governing environmental quality and pollution control, state limits
on allowable rates of production by a well or proration unit and the amount of
oil and gas available for sale, state and federal regulations governing the
availability of adequate pipeline and other transportation and processing
facilities, and state and federal regulation governing the marketing of
competitive fuels. For example, a productive gas well may be "shut-in" because
of an over-supply of gas or lack of an available gas pipeline in the areas in
which Inland may conduct operations. State and federal regulations generally are
intended to prevent waste of oil and gas, protect rights to produce oil and gas
between owners in a common reservoir, control the amount of oil and gas produced
by assigning allowable rates of production and control contamination of the
environment. Pipelines are subject to the jurisdiction of various federal, state
and local agencies.
Many state authorities require permits for drilling operations,
drilling bonds and reports concerning operations and impose other requirements
relating to the exploration and production of oil and gas. Such states also have
ordinances, statutes or regulations addressing conservation matters, including
provisions for the unitization or pooling of oil and gas properties, the
regulation of spacing, plugging and abandonment of such wells, and limitations
establishing maximum rates of production from oil and gas wells. However, no
Utah regulations provide such production limitations with respect to the Field.
Environmental Regulation. The recent trend in environmental legislation
and regulation has been generally toward stricter standards, and this trend will
likely continue. The Company does not presently anticipate that it will be
required to expend amounts relating to its oil and gas production operations
that are material in relation to its total capital expenditure program by reason
of environmental laws and regulations, but because such laws and regulations are
subject to interpretation by enforcement agencies and are frequently changed by
legislative bodies, the Company is unable to accurately predict the ultimate
cost of such compliance for 2000.
The Company is subject to numerous laws and regulations governing the
discharge of materials into the environment or otherwise relating to
environmental protection. These laws and regulations may require the acquisition
of a permit before drilling commences, restrict the types, quantities and
concentration of various substances that can be released into the environment in
connection with drilling and production activities, limit or prohibit drilling
activities on certain lands lying within wilderness, wetlands, and areas
containing threatened and endangered plant and wildlife species, and impose
substantial liabilities for unauthorized pollution resulting from the Company's
operations.
The following environmental laws and regulatory programs appeared to be
the most significant to the Company's operations in 1999, and are expected to
continue to be significant in 2000:
Regulated Access to Public Lands. A substantial portion of the
Company's operations occur on federal leaseholds. During 1996, the Vernal, Utah
office of the Bureau of Land Management ("BLM") undertook the preparation of an
Environmental Assessment ("EA") to evaluate the environmental and socioeconomic
impacts of the Company's proposed development plan within the Field. The
Agency's Record of Decision ("ROD") on the EA, which was issued on February 3,
1997, identified surface stipulations and mitigation measures that the Company
must implement to protect various surface resources, including protected and
sensitive plant and wildlife species, archaeological and paleontological
resources, soils and watersheds. The Company has proven itself successfully at
continuing to develop oil and gas resources in the Field while complying with
the surface stipulations and mitigation measures contained in the ROD.
On February 16, 1999, the United States Fish and Wildlife Service
("USFWS") issued a Proposed Rule to list the mountain plover, a small
ground-nesting bird, as "threatened" under the Federal Endangered Species Act.
The Field contains the only known breeding population of mountain plover in
Utah. The USFWS had not issued a Final Rule to list the mountain plover as of
December 31, 1999, however, the USFWS and BLM are likely to implement additional
restrictive surface stipulations in the Field once a Final Rule to list the
mountain plover as threatened is issued. Based on preliminary discussions with
the USFWS and BLM, the Company believes it will be able to comply with any
additional surface stipulations without causing a material impact on its future
drilling plans in the Field.
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Clean Water and Oil Pollution Regulatory Programs. The federal Clean
Water Act ("CWA") regulates discharges of pollutants to surface waters. The
discharge of crude oil and petroleum products to surface waters also is
precluded by the Oil Pollution Act ("OPA"). The Company's operations are
inherently subject to accidental spills and releases of crude oil and drilling
fluids that may give rise to liability to governmental entities or private
parties under federal, state or local environmental laws, as well as under
common law. Minor spills occur from time to time during the normal course of the
Company's production operations. The Company maintains spill prevention control
and countermeasure plans ("SPCC plans") for facilities that store large
quantities of crude oil or petroleum products to prevent the accidental
discharge of these potential pollutants to surface waters. As of December 31,
1999, the Company had undertaken all investigative or remedial work required by
governmental agencies to address potential contamination by accidental spills or
discharges of crude oil or drilling fluids.
The Company's operations involve the injection of water into the
subsurface to enhance oil recovery. Under the Safe Drinking Water Act ("SDWA"),
oil and gas operators, such as the Company, must obtain a permit for the
construction and operation of underground Class II enhanced recovery underground
injection wells. To protect against contamination of drinking water, the
Environmental Protection Agency ("EPA") and the State of Utah regulate the
quality of water that may be injected into the subsurface, and require that
mechanical integrity tests be performed on injection wells every five years. In
addition, the Company is required to monitor the pressure at which water is
injected, and must not exceed the maximum allowable injection pressure set by
the EPA and the State of Utah.
The Company has obtained the necessary permits for the Class II
injection wells it operates, and monitors the water quality of injection water
at several injection stations. The Company also maintains a schedule to conduct
mechanical integrity tests for each well every five years. The Company
experienced some difficulty monitoring and regulating injection pressures at
each individual injection well during the period from 1995 to 1998. The Company
has reached a tentative Settlement with EPA on injection well over pressuring
during the 1995 to 1998 time period, and is currently in substantial compliance
with the EPAs underground injection program. The Company developed a computer
program in 1999 to assist with monitoring injection pressures that has enhanced
the Company's efforts to meet EPA requirements.
Clean Air Regulatory Programs. The Company's operations are subject to
the federal Clean Air Act ("CAA"), and state implementing regulations. Among
other things, the CAA requires all major sources of hazardous air pollutants, as
well as major sources of certain other criteria pollutants, to obtain operating
permits, and in some cases, construction permits. The permits must contain
applicable Federal and state emission limitations and standards as well as
satisfy other statutory and regulatory requirements. The 1990 Amendments to the
CAA also established new monitoring, reporting, and recordkeeping requirements
to provide a reasonable assurance of compliance with emission limitations and
standards. As of December 31, 1999, the Company had taken all steps necessary to
be in substantial compliance with this CAA and its implementing regulations.
Waste Disposal Regulatory Programs. The Company's operations generate
and result in the transportation and disposal of large quantities of produced
water and other wastes classified by EPA as "nonhazardous solid wastes." The EPA
is currently considering the adoption of stricter disposal and clean-up
standards for nonhazardous solid wastes under the Resource Conservation and
Recovery Act ("RCRA"). In some instances, EPA has already required the clean up
of certain nonhazardous solid waste reclamation and disposal sites under
standards similar to those typically found only for hazardous waste disposal
sites. It also is possible that wastes that are currently classified as
"nonhazardous" by EPA, including some wastes generated during the Company's
drilling and production operations, may in the future be reclassified as
"hazardous wastes." Because hazardous wastes require much more rigorous and
costly treatment, storage, transportation and disposal requirements, such
changes in the interpretation and enforcement of the current waste disposal
regulations would result in significant increases in waste disposal expenditures
by the Company.
The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons who are considered to have caused or contributed to the release or
threatened release of a "hazardous substance" into the environment. These
persons include the current or past owner or operator of the disposal site or
sites where the release occurred and companies that transported, disposed or
arranged for the disposal of the hazardous
8
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substances under CERCLA. These persons may be subject to joint and several
liability for the costs of cleaning up the hazardous substances that have been
released into the environment and for damages to natural resources. The Company
is not presently aware of any potential adverse claims in this regard.
Health and Safety Regulatory Programs. The Company's operations also
are subject to regulations promulgated by the Occupational Safety and Health
Administration ("OSHA") regarding worker and work place safety. The Company
currently provides health and safety training and equipment to its employees and
is adopting additional corporate policies and procedures to comply with OSHA's
workplace safety standards.
Operational Hazards And Uninsured Risks. The oil and gas business
involves certain inherent operating hazards such as (a) well blowouts, (b)
cratering, (c) explosions, (d) uncontrollable flows of oil, gas or well fluids,
(e) fires, (f) formations with abnormal pressures, (g) pollution, (h) releases
of toxic gas and (i) other environmental hazards and risks. Any of these
operating hazards could result in substantial losses to the Company. In
accordance with customary industry practices, the Company maintains insurance
against some, but not all, of these risks and losses. The Company is also
required under various operating agreements to (a) maintain certain insurance
coverage on existing wells and all new wells drilled during drilling operations,
and (b) name others as additional insureds under such insurance coverage. The
occurrence of an event that is not fully covered by insurance could have an
adverse impact on the Company's financial condition and results of operations.
Competition. Many companies and individuals are engaged in the oil and
gas business. Inland is faced with strong competition from major oil and gas
companies and other independent operators attempting to acquire prospective oil
and gas leases, producing oil and gas properties and other mineral interests.
Some competitors are very large, well-established companies with substantial
capabilities and long earnings records. Inland may be at a disadvantage in
acquiring oil and gas prospects since it must compete with individuals and
companies which have greater financial resources and larger technical staffs
than Inland.
With respect to Black Wax production, additional competitive pressures
result from the inelasticity in the demand for Black Wax after the refining
capacity in the Salt Lake City area is reached.
DISCONTINUED REFINING OPERATIONS
General. As noted above under "Recent Developments - Sale of Refinery
Operations," Inland sold its refinery operations effective as of January 31,
2000 by selling all of its stock in Refining to Silver Eagle. The Company's
refining operations were conducted through its wholly-owned subsidiary,
Refining, at the Woods Cross Refinery, a hydroskimming plant with an overall
crude capacity of approximately 10,000 BPD. The 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.
Throughout 1999, the Woods Cross Refinery processed approximately 3,200
BPD of Black Wax crude. The refinery has the capacity to process 5,000 BPD, but
did not dedicate this entire amount to Black Wax processing due to the
availability of alternative feedstocks at economic prices. In December 1999, the
Company produced approximately 3,800 BPD of Black Wax from the Field.
The financial statements included with this Annual Report reflect all
necessary adjustments to record Refining at net realizable value as of December
31, 1999, and the financial statements for prior periods have been restated to
remove the separate segment information for the refining operations and to
reflect the refining operations as discontinued operations. Consequently,
separate segment information, and a separate discussion of refinery operations,
is not included in this Annual Report.
Environmental Regulations Associated with Discontinued Refining
Operations. As of December 31, 1999, the Company was not aware of any remaining
liabilities associated with any of its previously held refining properties.
There remains, however, the possibility that federal, state, or local
governmental agencies, or private parties, could attempt to join the Company in
clean-up efforts associated with previously held refining properties should they
be
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required.
EMPLOYEES
At March 15, 2000, the Company had 90 employees, consisting of three
executive officers, 23 clerical and administrative employees and 64 field
operations staff involved in the Company's oil and gas operations in Utah.
OTHER PROPERTY
The Company's principal executive office is located in Denver,
Colorado. The Company leases approximately 16,500 square feet pursuant to a
lease which expires in December 2002 and provides for a rental rate of $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.
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"net" oil and natural gas wells or "net" acres are the total gross
number of wells or acres respectively in which the Company has an interest
multiplied times the Company's or other referenced party's working interest in
such wells or acres.
"posted field price" is an industry term for the fair market value of
oil in a particular field.
"productive wells" are producing wells or wells capable of production
In this Annual Report, natural gas volumes are stated at the legal
pressure base of the state or area in which the reserves are located and at 60
degrees Fahrenheit.
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The annual meeting of Inland's stockholders was held on December 10,
1999. At the meeting, the stockholders approved a 1-for-10 reverse split of the
Common Stock and an amendment to Inland's Articles of Incorporation to increase
the post-split number of authorized shares of Common Stock to 25,000,000 shares,
and the directors named below were elected to hold office until the 2000 annual
meeting of stockholders or until their successors are elected and qualified.
The reverse split and amendment to the Articles of Incorporation was
approved by the affirmative vote of all shares of Series D Preferred Stock,
Series E Preferred Stock and Series Z Preferred Stock and 1,264,299 shares of
Common Stock voting as one combined voting class, and 1,264,299 shares of Common
Stock voting as a separate voting class; and 5,505 shares of Common Stock were
voted against the proposal, no shares were withheld and 29 shares represented
abstentions or broker non-votes.
Following is a tabulation of the votes relating to the election of
directors:
Abstention or
Shares voted Shares voted Shares broker non-vote
Name "for" "against" withheld shares
- ------------------ ------------ ------------ -------- ---------------
SERIES D PREFERRED
STOCK DIRECTORS:
John D. Lomax 10,757,747 -- -- --
Bill I. Pennington 10,757,747 -- -- --
Marc MacAluso 10,757,747 -- -- --
T Brooke Farnsworth 10,757,747 -- -- --
COMMON STOCK
DIRECTOR:
John E. Dyer (1) 103,398 341 -- 1,799
- -------------
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14
(1) Mr. Dyer agreed to resign as a director upon the written request of a
majority of the Board or TCW Asset Management Company. On February 2, 2000, TCW
Asset Management Company requested Mr. Dyer's resignation and he resigned on
that date.
[THIS SPACE INTENTIONALLY LEFT BLANK]
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15
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK
Since July 29, 1999, Inland's Common Stock has been traded
over-the-counter and quoted from time to time in the OTC Bulletin Board "pink
sheets" under the trading symbol "INLN". Prior to July 29, 1999, Inland's Common
Stock was quoted on the National Association of Securities Dealer's Automated
Quotation System ("Nasdaq") under the symbol "INLN". As of March 15, 2000, there
were approximately 450 holders of record of Inland's Common Stock. The following
table sets forth the range of high and low sales prices as reported by Nasdaq
for the periods indicated prior to July 29, 1999, and the range of high and low
bid prices as reported by the OTC Bulletin Board for the periods indicated after
July 29, 1999. The quotations reflect inter-dealer prices without retail markup,
markdown or commission, and may not necessarily represent actual transactions.
All prices have been adjusted to give retroactive effect to the 1-for-10 reverse
split of the Common Stock effected on December 14, 1999. This adjustment was
made by multiplying the actual price by a factor of 10. There can be no
assurance that the shares would have traded at such adjusted price had the
reverse split occurred prior to the dates reflected below.
Common Stock Price Range
------------------------
High Low
---------- ---------
YEAR ENDED DECEMBER 31, 1999
First Quarter .................... $ 52.50 $ 11.90
Second Quarter ................... 26.90 7.50
Third Quarter .................... 15.00 2.50
Fourth Quarter ................... 13.75 2.50
YEAR ENDED DECEMBER 31, 1998
First Quarter .................... $ 105.00 $ 85.00
Second Quarter ................... 92.50 83.80
Third Quarter .................... 95.00 42.50
Fourth Quarter ................... 65.00 8.80
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 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 D Preferred Stock or
Series E Preferred Stock.
RECENT SALES OF UNREGISTERED SECURITIES
On December 14, 1999, the Series Z Convertible Preferred Stock of
Inland was automatically converted into 588,291 shares of Common Stock upon
approval of the 1-for-10 reverse split of the Common Stock and the filing of the
amended Articles of Incorporation to effectuate such reverse split. Inland
issued its Common Stock upon conversion of the Series Z Preferred Stock without
registration under the Securities Act of 1933 (the "Securities Act") in reliance
on the exemption provided by Section 4(2) of the Securities Act.
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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, 1999. 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,
-----------------------------------------------------------
1999 1998 1997 1996 1995
--------- --------- --------- -------- --------
(dollars in thousands, except for unit amounts)
REVENUE AND EXPENSE DATA:
Revenues:
Oil and gas sales ........................................ $ 16,399 $ 21,278 $ 17,182 $ 10,704 $ 1,905
Management fees .......................................... -- -- -- -- 326
--------- --------- --------- -------- --------
Total revenues ........................................ 16,399 21,278 17,182 10,704 2,231
--------- --------- --------- -------- --------
Operating Expenses:
Lease operating expenses ................................. 7,160 8,362 3,780 1,435 1,010
Production taxes ......................................... 192 454 383 610 133
Exploration .............................................. 155 153 61 167 342
Impairment ............................................... -- 1,327 -- -- --
Depletion, depreciation and amortization ................. 9,882 12,025 6,480 3,428 858
General and administrative, net .......................... 3,136 2,061 2,118 1,670 1,335
--------- --------- --------- -------- --------
Total operating expenses .............................. 20,525 24,382 12,822 7,310 3,678
--------- --------- --------- -------- --------
Operating income (loss) ....................................... (4,126) (3,104) 4,360 3,394 (1,447)
Interest expense .............................................. (15,989) (14,895) (4,759) (1,633) (749)
Interest and other income ..................................... 72 107 380 414 128
Gain on sale of assets ........................................ -- -- -- -- 850
Loss from discontinued operations ............................. (16,274) (5,560) -- (30) (500)
--------- --------- --------- -------- --------
Net income (loss) before extraordinary loss ................... (36,317) (23,452) (19) 2,145 (1,718)
Extraordinary loss ............................................ (556) -- (1,160) -- (216)
--------- --------- --------- -------- --------
Net income (loss) ............................................. (36,873) (23,452) (1,179) 2,145 (1,934)
Redemption premium - Preferred Series A Stock ................. -- -- -- (214) --
Redemption premium - Preferred Series B Stock ................. -- -- (580) -- --
Accrued Preferred Series C Stock dividends .................... (663) (1,084) (450) -- --
Accrued Preferred Series D Stock dividends .................... (2,262) -- -- -- --
Accrued Preferred Series E Stock dividends .................... (350) -- -- -- --
Accretion of Preferred Series D Stock Discount ................ (1,473) -- -- -- --
Accretion of Preferred Series E Stock Discount ................ (220) -- -- -- --
--------- --------- --------- -------- --------
Net income (loss) attributable to common stockholders ......... $ (41,841) $ (24,536) $ (2,209) $ 1,931 $ (1,934)
--------- --------- --------- -------- --------
Earnings (loss) per common share before extraordinary loss
Basic ................................................ $ (28.99) $ (29.25) $ (1.42) $ 3.80 $ (6.30)
Diluted .............................................. (28.99) (29.25) (1.42) 3.00 (6.30)
Earnings (loss) per common share:
Basic ................................................ $ (29.37) $ (29.25) $ (2.99) $ 3.80 $ (6.30)
Diluted .............................................. (29.37) (29.25) (2.99) 3.00 (6.30)
BALANCE SHEET DATA (AT END OF PERIOD):
Oil and gas properties, net ................................... $ 142,412 $ 159,105 $ 133,820 $ 42,998 $ 16,819
Total assets .................................................. $ 153,658 $ 187,781 $ 175,953 $ 57,329 $ 21,923
Debt .......................................................... $ 79,338 $ 156,973 $ 123,111 $ 21,120 $ 4,636
Stockholders' equity (deficit) ................................ $ (3,666) $ 7,039 $ 30,672 $ 31,972 $ 13,979
14
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Year Ended December 31,
--------------------------------------------------------
1999 1998 1997 1996 1995
-------- -------- --------- -------- -------
(dollars in thousands, except for unit amounts)
OTHER FINANCIAL DATA:
Net cash provided by (used in) operating activities .................. $ (7,513) $ 6,822 $ 5,668 $ 5,006 $ 30
Net cash used in investing activities ................................ (3,772) (39,391) (99,272) (23,752) (8,030)
Net cash provided by financing activities ............................ 10,502 47,076 107,128 25,806 9,008
OPERATING DATA:
Sales Volumes:
Oil (MBbls) ................................................. 1,165 1,501 855 502 105
Gas (MMcf) .................................................. 2,901 3,006 1,637 710 109
MBOE ........................................................ 1,649 2,002 1,128 620 123
BOEPD ....................................................... 4,518 5,485 3,090 1,698 336
Average Prices (excluding hedging activities):
Oil (per Bbl) ............................................... $ 14.38 $ 9.82 $ 16.17 $ 20.18 $ 17.10
Gas (per Mcf) ............................................... 1.56 2.00 2.19 1.56 1.21
Per BOE ..................................................... 12.90 10.35 15.23 17.26 15.52
Production and operating costs (per BOE) (1) ........................ $ 4.34 4.18 3.35 2.31 8.23
- ------------------------
(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, 1999, 1998, and 1997.
GENERAL
Inland is a diversified and independent energy company engaged in the
acquisition, development and enhancement of oil and gas properties in the
western United States. All of the Company's oil and gas reserves are located in
the Monument Butte Field (the "Field") within the Uinta Basin of northeastern
Utah. 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.
On January 31, 2000, the Company sold its 100% owned subsidiary, Inland
Refining, Inc. The subsidiary owned the Woods Cross Refinery and a nonoperating
refinery located in Roosevelt, Utah. The Woods Cross refinery was originally
purchased on December 31, 1997 for $22.9 million and the Roosevelt refinery was
originally purchased on September 16, 1998 for $2.25 million. Due to this sale,
the Company is no longer involved in the refining of crude oil or the sale of
refined products. As a result, all refining operations have been classified as
discontinued operations in the accompanying consolidated financial statements.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1999 COMPARED WITH YEAR ENDED DECEMBER 31, 1998
Oil and Gas Sales. Crude oil and natural gas revenue for the year ended
December 31, 1999 decreased
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$4.9 million, or 23% from the previous year. Prior to considering hedging losses
of $4.9 million in 1999, the Company's oil and gas revenues were flat between
years. The lack of change in oil and gas revenues was a function of increased
product sales prices offset by sales volume decreases. The average price per BOE
sold increased 25% from $10.35 per Bbl in 1998 to $12.90 per Bbl in 1999. Sales
volumes decreased 18% from 2.0 MBOE in 1998 to 1.65 MBOE in 1999 due to normal
production decline. The Company's production decline leveled out by year end
1999 due to the drilling of eight wells during the fourth quarter of 1999. Crude
oil sales as a percentage of total oil and gas sales were 79% and 72% in 1999
and 1998, respectively. Crude oil will continue to be the predominant product
produced from the Field.
Inland has entered into price protection agreements to hedge against
the volatility in crude oil prices. Although hedging activities do not affect
Inland's actual sales price for crude oil in the Field, the financial impact of
hedging transactions is reported as an adjustment to crude oil revenue in the
period in which the related oil is sold. Crude oil sales were decreased by $4.9
million in 1999 and increased by $550,000 during 1998 to recognize hedging
contract settlement gains and losses and contract purchase cost amortization.
See Item 7A "Quantitative and Qualitative Disclosures About Market Risk."
Lease Operating Expenses. Lease operating expense for the year ended
December 31, 1999 decreased $1.2 million, or 14% from the previous year. Lease
operating expense per BOE increased from $4.18 per BOE sold in 1998 to $4.34 in
1999. The increase on a BOE basis is due to the lower volume produced, offset by
cost reductions during 1999.
Production Taxes. Production taxes as a percentage of sales were 1.0%
in 1999 and 2.2% in 1998. Production tax expense consists of estimates of the
Company's yearly effective tax rate for Utah state severance tax and production
ad valorem tax. Changes in sales prices, tax rates, tax exemptions and the
timing, location and results of drilling activities can all affect the Company's
actual effective tax rate.
Exploration. Exploration expense in 1999 and 1998 represents the
Company's cost to retain unproved acreage.
Impairment. Impairment reflects the adjustment in carrying value to
write down a note receivable and certain undeveloped acreage to their estimated
net realizable value at December 31, 1998.
Depletion, Depreciation and Amortization. Depletion, depreciation and
amortization for the year ended December 31, 1999 decreased 18%, or $2.1
million, from the previous year. The decrease resulted from decreased sales
volumes and a slightly lower average depletion rate. Depletion, which is based
on the units-of-production method, comprises the majority of the total charge.
The depletion rate is a function of capitalized costs and related underlying
proved reserves in the periods presented. The Company's average depletion rate
was $5.59 per BOE sold during 1999 compared to $5.70 per BOE sold during 1998.
Based on December 31, 1999 proved reserves, the Company's depletion rate
entering 2000 is $4.86 per BOE.
General and Administrative, Net. General and administrative expense for
the year ended December 31, 1999 increased $1.1 million, or 52% from the
previous year. The 1999 amount includes $1.2 million related to the Company's
financial restructuring. After removal of the restructuring costs, general and
administrative expense was slightly lower between periods. General and
administrative expense is reported net of operator fees and reimbursements which
were $4.7 million and $5.7 million during 1999 and 1998, respectively. Gross
general and administrative expense was $6.6 million (net of restructuring costs)
in 1999 and $7.8 million in 1998. The decrease in reimbursements and expense is
a function of the level of operated field activity, which decreased when the
Company temporarily terminated development activity from late 1998 to late 1999.
Interest Expense. Interest expense for the year ended December 31, 1999
increased $1.1 million, or 7.3% from the previous year. The increase resulted
from an increase in the average amount of borrowings outstanding during the year
and immediately prior to the financial restructuring performed in September
1999. Borrowings during 1999 and
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1998 were recorded at an effective interest rate of approximately 10.6%. The
effects of the financial restructuring will significantly lower outstanding
borrowings and interest cost in future periods.
Other Income. Other income in 1999 and 1998 primarily represents
interest earned on the investment of surplus cash balances.
Income Taxes. In 1999 and 1998, no income tax provision or benefit was
recognized due to net operating losses incurred and the reversal and recording
of a full valuation allowance.
Discontinued Operations. During 1999, the Company operated the Woods
Cross Refinery and incurred an operating loss of $1.8 million. Although the
margins obtained for refined product sales in the Salt Lake City region were
strong for most of the year, the Company suffered from inefficient operations
since it was unable to secure sufficient quantities of feedstock due to its
financial condition. After the Company's financial restructuring in September
1999, increasing crude oil costs reduced margins on refined product sales to
unacceptable levels. These circumstances combined with the availability of
alternative buyers for the Company's crude oil caused the Company to discontinue
refinery operations in December 1999. The refinery was subsequently sold along
with a nonoperating refinery in Roosevelt, Utah on January 31, 2000.
As a result of this activity, the accompanying consolidated financial
statements for the current period and all prior periods have been adjusted to
report refining operations as discontinued operations. The Company recorded a
charge of $14.5 million in 1999 to record the disposal of the refining business
segment.
Extraordinary Item. Effective September 21, 1999, the Company
restructured an existing obligation to TCW and amended the terms of its farmout
arrangement with Smith Energy Partnership. As a result of these transactions,
unamortized debt issue costs of $556,000 were written off as an extraordinary
loss.
Accrued Preferred Series C Stock Dividends. Inland's Preferred Series C
Stock was exchanged for Common Stock and Preferred Series E Stock as part of the
financial restructuring transaction on September 21, 1999. Prior to that time,
the Preferred Series C Stock accrued dividends at 10% compounded quarterly. The
amount accrued represents those dividends earned during 1999 or 1998,
respectively.
Accrued Preferred Series D Stock Dividends. Inland's Preferred Series D
Stock accrues dividends at 11.25% compounded quarterly. The amount accrued
represents those dividends earned during the fourth quarter of 1999.
Accrued Preferred Series E Stock Dividends. Inland's Preferred Series E
Stock accrues dividends at 11.5% compounded quarterly. The amount accrued
represents those dividends earned during the fourth quarter of 1999.
Accretion of Preferred Series D Stock Discount. Inland's Preferred
Series D Stock was initially recorded on the financial statements at a discount
of $20.2 million and is being accreted to face value over the minimum mandatory
redemption period which begins on October 1, 2001.
Accretion of Preferred Series E Stock Discount. Inland's Preferred
Series E Stock was initially recorded on the financial statements at a discount
of $4.2 million and is being accreted to face value over four years, the
minimum mandatory redemption period.
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YEAR ENDED DECEMBER 31, 1998 COMPARED WITH YEAR ENDED DECEMBER 31, 1997
Oil and Gas Sales. 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 a total of 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 will continue to be the predominant product produced
from the Field.
Inland has entered into price protection agreements to hedge against
the volatility in crude oil prices. Although hedging activities do not affect
Inland's actual sales price for crude oil in the Field, the financial impact of
hedging transactions is reported as an adjustment to crude oil revenue in the
period in which the related oil is sold. Crude oil sales were 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."
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
operated 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.
Impairment. Impairment reflects the adjustment in carrying value to
write down a note receivable and certain undeveloped acreage to their estimated
net realizable value at December 31, 1998.
Depletion, Depreciation and Amortization. Depletion, depreciation and
amortization for the year ended December 31, 1998 increased 86%, or $5.55
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
$5.70 per BOE sold during 1998 compared to $5.52 per BOE sold during 1997.
General and Administrative, Net. General and administrative expense for
the year ended December 31, 1998 decreased 3% from the previous year. General
and administrative expense 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 213%, or $10.1 million, compared to the year ended December 31, 1997.
The increase resulted from a significant increase in the average amount
18
22
of borrowings outstanding due to the leveraged purchases of the properties from
Enserch and EREC 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.
Discontinued Operations. The Company acquired the Woods Cross Refinery
effective December 31, 1997. As a result, the Company had no refining operations
during 1997.
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 B Stock. During July 1997, the
Company called for the redemption of its Preferred Series B Stock. All Series B
stockholders 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
Preferred Series B Stock.
Accrued Preferred Series C Stock Dividends. The Company's Preferred
Series C Stock accrues dividends at 10% compounded quarterly. The amount accrued
represents those dividends earned during 1998 or 1997, respectively.
LIQUIDITY AND CAPITAL RESOURCES
FINANCIAL RESTRUCTURING
On September 21, 1999, the Company entered into an Exchange Agreement
(the "Exchange Agreement") with Trust Company of the West and affiliated
entities ("TCW") and Joint Energy Development Investments II Limited Partnership
("JEDI") pursuant to which TCW agreed to exchange certain indebtedness and
warrants to purchase Common Stock, for shares of Common Stock and two new series
of Preferred Stock of the Company, and JEDI agreed to exchange 100,000 shares of
Series C Preferred Stock of the Company for shares of Common Stock and a third
new series of Preferred Stock of the Company (the "Recapitalization").
Pursuant to the Exchange Agreement, TCW agreed to exchange $75.0
million of subordinated indebtedness plus accrued interest of $5.7 million and
warrants to purchase 15,852 shares of Common Stock for the following securities
of the Company: (i) 10,757,747 shares of newly designated Series D Redeemable
Preferred Stock of the Company ("Series D Preferred Stock"), (ii) 5,882,901
shares of newly designated Series Z Convertible Preferred Stock of the Company
("Series Z Preferred Stock") and (iii) 1,164,295 shares of Common Stock. On
December 14, 1999, all shares of Series Z Preferred Stock were converted into
588,291 shares of Common Stock. In addition, JEDI agreed to exchange 100,000
shares ($10.0 million par value) of the Company's Series C Cumulative
Convertible Preferred Stock ("Series C Preferred Stock") owned by JEDI, together
with $2.2 million of accumulated dividends thereon, for (i) 121,973 shares of
newly designated Series E Redeemable Preferred Stock of the Company ("Series E
Preferred Stock") and (ii) 292,098 shares of Common Stock.
One of the conditions to closing the Exchange Agreement was that
Inland's senior lenders would enter into a restructuring of the senior credit
facility acceptable to TCW, JEDI and the Company. As a result, effective as of
September 21, 1999, the Company entered into the Second Amended and Restated
Credit Agreement (the "ING
19
23
Credit Agreement") with ING (U.S.) Capital Corporation, U.S. Bank National
Association and Meespierson Capital Corporation (the "Senior Lenders") pursuant
to which the Senior Lenders agreed to increase the borrowing base from $73.25
million to $83.5 million, inclusive of a sublimit for letters of credit of $4.0
million. The outstanding principal balance at December 31, 1999 was $78,915,000.
The Company also had $1.9 million of outstanding letters of credit at December
31, 1999. All borrowings under the ING Credit Agreement are due on October 1,
2001, or potentially earlier if the borrowing base is determined to be
insufficient. The borrowing base is calculated as the collateral value of proved
reserves and will be redetermined on October 1, 2000 and April 1, 2001 and may
be redetermined at the option of the Senior Lenders one additional time after
October 1, 2000. Upon redetermination, if the borrowing base is lower than the
outstanding principal balance then drawn, the Company must immediately pay the
difference. Interest accrues, at the Company's option, at either (i) 2% above
the prime rate or (ii) 3% above the LIBOR rate. At December 31, 1999,
substantially all amounts were borrowed under the LIBOR option at an effective
rate of 9.17% through June 29, 2000. The Company paid a facility fee of $150,000
and an additional fee of $208,000 to the Senior Lenders at closing. The Company
must also pay a facility fee equal to 0.50% of the borrowing base on April 1,
2001 and again on September 30, 2001. The Senior Lenders will also receive a fee
equal to 1% of the borrowing base on October 1, 2000 if ING (U.S.) Capital
Corporation continues to be a member of the Senior Lenders at September 30,
2000. The ING Credit Agreement has covenants that restrict the payment of cash
dividends, borrowings, sale of assets, loans to others, investment and merger
activity and hedging contracts without the prior consent of the lenders and
requires the Company to maintain certain net worth, interest coverage and
working capital ratios. Subsequent to year end, certain covenants were amended
allowing the Company to remain in compliance at December 31, 1999. The ING
Credit Agreement is secured by a first lien on substantially all assets of the
Company.
The Company also amended its Farmout Agreement with Smith Energy
Partnership ("Smith") in conjunction with the financial restructuring on
September 21, 1999. The amendment provided that effective June 1, 1999, net
revenues would be paid in cash only, rather than the cash or stock option
previously allowed. The amendment also allowed the Company to retain all net
revenues under the Farmout Agreement during the period November 1, 1998 through
May 31, 1999. As a result of this recent amendment, and the fact that the
Company has no further obligations in relation to these properties, the
production loan previously recorded by the Company is no longer considered
outstanding. As a result, the Company has removed all previously recorded
drilling costs, accumulated depletion, debt issue costs, loans and accrued
interest as of September 21, 1999 and will no longer record revenue and costs
from wells drilled under the Farmout Agreement in its Consolidated Statement of
Operations or Consolidated Statement of Cash Flows. The Company recognized a
$5.8 million gain (charged directly to equity because of the related party
involvement) upon the removal of previously recorded account balances.
EFFECT OF FINANCIAL RESTRUCTURING ON LIQUIDITY AND CAPITAL RESOURCES
As a result of the financial restructuring, the Company has
significantly improved its financial flexibility. The exchange of subordinated
debt for equity securities has significantly decreased the Company's debt
service requirements thereby increasing discretionary cash flow available for
capital projects. The restructuring of the ING Credit Agreement's principal
repayment terms beyond calendar year 2000 allows the Company to reinvest its
operating cash flow for further development of the Field. As of March 15, 2000,
the Company had $3.5 million of borrowing base availability under the ING Credit
Agreement and no outstanding letter of credit obligations. In addition,
substantially all vendors were on current terms with the Company.
The Company reinitiated its drilling program in October 1999 based on
liquidity generated from the financial restructuring. The Company drilled eight
wells in 1999 and has plans to drill as many as 50 wells in 2000. The Company
also continued its efforts to pressurize the Field by converting 22 wells to
water injection in 1999 with plans to convert as many as 50 wells to water
injection in 2000. The level of these and other capital expenditures is largely
discretionary, and the amount of funds devoted to any particular activity may
increase or decrease significantly depending on available opportunities,
commodity prices, operating cash flows and development results, among other
items.
During 1999, the Company borrowed $11.25 million under the ING Credit
Agreement and generated $5.8 million of cash from operations which it primarily
used to service debt ($6.1 million), reduce outstanding accounts
20
24
payable ($6.0 million) and continue its development of the Field ($3.8 million).
The Company's capital budget for development of the Field in year 2000 is $14.5
million. Although there can be no assurance, the Company believes that cash on
hand along with future cash to be generated from operations and borrowing base
availability will be sufficient to implement its development plans and service
its debt for the next year.
DELISTING OF COMMON STOCK
Effective with the close of business July 28, 1999, the Company's
Common Stock was delisted from the Nasdaq SmallCap Market. The Company was no
longer able to satisfy the net tangible asset maintenance standard for continued
listing. The Company's Common Stock is now traded on the NASD over-the-counter
bulletin board under the same symbol "INLN".
INFLATION AND CHANGES IN PRICES
Inland's revenues and the value of its oil and gas properties have been
and will be affected by changes in oil and gas prices. Inland's ability to
borrow from traditional lending sources and to obtain additional capital on
attractive terms is also substantially dependent on oil and gas prices. Oil and
gas prices are subject to significant seasonal and other fluctuations that are
beyond Inland's ability to control or predict. Although 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 1999 or 1998.
YEAR 2000 ISSUES
The Company is aware of the issues associated with the programming code
in many existing computer systems and devices with embedded technology. The
"Year 2000" problem concerns the inability of information and technology-based
operating systems to properly recognize and process date-sensitive information
beyond December 31, 1999. The conversion from calendar year 1999 to calendar
year 2000 occurred without any disruption to the Company's operations or
business systems. The Company will continue to monitor any Year 2000 issues,
both internally and with third party dependencies with respect to vendors,
customers, and other significant business relationships. The total costs
incurred to date in the assessment, evaluation and remediation of Year 2000
matters plus any additional costs that may be incurred are expected to be less
than management's original estimate of $50,000.
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
drilling schedules, expected or planned production or transportation capacity,
future production levels of fields, marketing of crude oil and natural gas, the
Company's capital budget and future capital requirements, 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
21
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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").
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." All borrowings under the ING
Agreement are due and payable October 1, 2001. As of December 31, 1999, the ING
Credit Agreement had a principal balance of $78,915,000 at an average floating
interest rate of 9.17% per annum, which rate has been locked in through June 29,
2000. 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, 2000 January 1, 2001
through through
December 31, October 1, 2001
2000
--------------- ---------------
1% increase in $ 395,000 $ 593,000
Interest Rates
2% increase in $ 790,000 $ 1,186,000
Interest Rates
On April 30, 1998, 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 9.75% on $35.0 million of borrowings. The
effect of the hedge through December 31, 2000 will be to limit hypothetical
increases in interest expenses under the ING Credit Agreement to $325,000
assuming a 1% increase in interest rates and $550,000 assuming a 2% increase in
interest rates.
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 contracts quoted on the NYMEX index. Gains or losses on hedging
activities are recognized as oil and gas sales in the period in which the hedged
production is sold.
Inland has entered into various contracts in the form of swaps or collars to
hedge crude oil production during calendar years 2000 and 2001. The potential
gains or losses on these contracts based on a hypothetical average market price
of equivalent product for these periods are as follows:
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26
Average NYMEX Per Barrel Market Price for the Contract Period
-----------------------------------------------------------------------------------
$ 20.00 $ 22.00 $ 24.00 $ 26.00 $ 28.00 $ 30.00 $ 32.00
------- -------- ---------- ---------- ---------- ---------- ----------
All Contracts - 2000 $33,000 $381,000 $1,620,000 $3,060,000 $4,500,000 $5,940,000 $7,380,000
All Contracts - 2001 $ 0 $126,000 $1,070,000 $2,097,000 $3,087,000 $4,077,000 $5,067,000
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and supplementary data required by this item
begin at page F-1 hereof.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
[THIS SPACE INTENTIONALLY LEFT BLANK]
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS AND EXECUTIVE OFFICERS
The following table provides information as of March 15, 2000, with
respect to each of the Company's directors and executive officers:
SERVED AS EXECUTIVE
OFFICER OR
NAME AGE POSITION DIRECTOR SINCE
---- --- -------- -------------------
DIRECTORS
John D. Lomax(1) 75 Director (Chairman) 1999
Bill I. Pennington 48 Director, Chief Executive 1994
Officer and Chief Financial
Officer
Marc MacAluso 39 Director 1999
T Brooke Farnsworth(1) 55 Director 1999
OTHER EXECUTIVE OFFICERS
Michael J. Stevens 34 Vice President, Secretary 1993
and Treasurer
William T. War 56 Vice President 1998
- ------------------
(1) Member of the Audit Committee.
JOHN D. LOMAX. Mr. Lomax has served as Chairman since September 23,
1999 and a director of the Company since September 13, 1999. He also served as
Chairman and a director of the Company from September 1994 until September 1996.
Mr. Lomax has been retired for the past five years.
BILL I. PENNINGTON. Mr. Pennington has served as Chief Financial
Officer of the Company since September 21, 1994, and as Chief Executive Officer
since September 23, 1999. He also served as Vice President from March 22,1996
until his election as Chief Executive Officer. He was appointed as a director of
the Company on September 23, 1999. He served as a director of the Company from
September 21, 1994 until September 25, 1996 and as Treasurer of the Company from
September 21, 1994 until March 22, 1996. He also served as President, Chief
Operating Officer and a Director of Lomax Exploration Company, now known as
Inland Production Company ("IPC"), from May 1987 until the Company's acquisition
of IPC on September 21, 1994. From March 1986 until May 1987, Mr. Pennington was
a manager with the accounting firm of Coopers & Lybrand in Houston, Texas. Mr.
Pennington is a certified public accountant.
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MARC MACALUSO. Mr. MacAluso was appointed as a director on October 14,
1999. He has been Senior Vice President of TCW Asset Management Company in
Houston, Texas since August 1994, where he is involved in all aspects of
mezzanine financing for TCW's Energy Group. He joined TCW Asset Management
Company after leading new business development at American Exploration Company.
Prior to American Exploration Company, his experience includes various
assignments with Shell Oil Company and Shell Western E&P, Inc.
T BROOKE FARNSWORTH. Mr. Farnsworth was appointed as a director on
September 13, 1999. He was a director of the Company from September 1994 until
September 1996. Mr. Farnsworth has practiced law in Houston, Texas for more than
27 years, where presently he is the Managing Partner of the law firm of
Farnsworth & vonBerg. He served as Secretary of IPC from 1985 until September
21, 1994 and as a director of IPC from 1992 until September 21, 1994.
MICHAEL J. STEVENS. Mr. Stevens has been the Controller of the Company
since June 28, 1993, the Secretary since September 30, 1993 and a Vice President
since April 30, 1997. He was the Treasurer of the Company from September 30,
1993 until September 21, 1994, and was reappointed as Treasurer on March 22,
1996. Prior to his association with the Company, he was a manager with Coopers &
Lybrand and senior internal auditor at Diversified Energy, Inc., a publicly
traded oil and gas company in Minneapolis, Minnesota. Mr. Stevens is a certified
public accountant.
WILLIAM T. WAR. Mr. War has served as Vice President of the Company
since October 5, 1998. From June, 1990 until his association with the Company,
Mr. War was Project Manager for Louisiana Land & Exploration/Burlington
Resource's Lost Cabin Gas Plant. From October 1978 to November 1987, he founded
and served as President of Fuel Chemicals Incorporated and co-founded and served
as Executive Vice President of JN Exploration and Production and JN
Incorporated/Nielson International. Prior thereto since 1966, he served in
engineering, management and executive positions with Shell, Union Carbide, Dow
Chemical and Husky Oil.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934, as amended (the
"Exchange Act"), requires the Company's officers and directors, and persons who
beneficially own more than 10% of the Common Stock to file reports of ownership
and changes in ownership with the Securities and Exchange Commission (the
"Commission").
Based solely upon a review of Forms 3, 4 and 5 and amendments thereto
furnished to the Company pursuant to Rule 16a-3(e) promulgated under the
Exchange Act or upon written representations received by the Company, the
Company is not aware of any failure by any officer, director or beneficial owner
of more than 10% of the Company's Common Stock to timely file with the
Commission any Form 3, 4 or 5 during 1999.
25
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ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table. The following table sets forth the
compensation earned by the Company's Chief Executive Officers and each of its
two other most highly compensated executive officers for the year ended December
31, 1999 (collectively, the "Named Officers") in salary and bonus for services
rendered in all capacities to the Company for the fiscal years ended December
31, 1999, 1998 and 1997:
ANNUAL COMPENSATION LONG TERM COMPENSATION
----------------------------------------- ------------------------------
SECURITIES
UNDERLYING
OTHER ANNUAL OPTIONS OR ALL OTHER
NAME/PRINCIPAL POSITION YEAR SALARY BONUS COMPENSATION WARRANTS COMPENSATION
- ----------------------- ---- ------ ----- ------------ ---------- ------------
Bill I. Pennington, Chief 1999 $201,000 -- $ 6,544 87,500 --
Executive Officer and Chief 1998 $175,000 -- $21,705(2) -- --
Financial Officer(1) 1997 $148,236 $60,000 $ 3,958 18,500 --
Arthur J. Pasmas, 1999 $100,000 -- -- -- $ 50,000
Co-Chief Executive Officer(1) 1998 -- -- -- -- --
1997 -- -- -- -- --
Kyle R. Miller, 1999 $177,000 -- $21,255(3) -- $375,000
Co-Chief Executive Officer(1) 1998 $250,000 -- $36,373(3) -- --
1997 $199,559 $85,000 $19,147 29,500 --
Michael J. Stevens, 1999 $102,000 $50,000 $ 6,459 29,200 --
Vice President, Secretary and 1998 $100,000 -- $13,933(4) -- --
Treasurer 1997 $ 90,430 $25,000 $ 3,459 10,000 --
William T. War, 1999 $162,000 -- $ 5,020 25,000 --
Vice President 1998 $ 54,000 -- -- -- --
1997 -- -- -- -- --
- ---------------------
(1) Mr. Pennington was elected Chief Executive Officer on September 23,
1999. Messrs. Pasmas and Miller served as Co- Chief Executive Officers
until Mr. Pasmas resigned on September 21, 1999 and Mr. Miller resigned on
September 23, 1999. Mr. Pasmas entered into a consulting agreement with
the Company on September 21, 1999 pursuant to which he will receive
$200,000 annually for consulting services for three years. The amount
under "Other Annual Compensation" for Mr. Pasmas includes the consulting
fee paid to him during 1999. Mr. Miller received a severance payment from
the Company of $375,000 upon his resignation as Co-Chief Executive
Officer, which is included in the table above under "All Other
Compensation."
(2) Vacation compensation in 1998 for Mr. Pennington totaled $12,453 and
401(k) matching compensation totaled $9,252.
(3) Vacation compensation in 1998 for Mr. Miller totaled $15,623. His 401(k)
matching compensation totaled $11,255 in 1999 and $8,750 in 1998. In
addition, Mr. Miller received $10,000 in 1999 and $12,000 in 1998
compensation with respect to his automobile.
(4) Vacation compensation in 1998 for Mr. Stevens totaled $7,933 and 401(k)
matching compensation totaled $6,000.
Option/Warrant/SAR Grants. The following table sets forth certain
information regarding options, warrants and SARs granted during 1999:
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30
POTENTIAL
REALIZABLE VALUE AT
INDIVIDUAL GRANTS ASSUMED ANNUAL
-------------------------------------------------------------- RATES OF STOCK
NUMBER OF PERCENT OF TOTAL PRICE APPRECIATION
SECURITIES UNDERLYING OPTIONS/WARRANTS/SARS EXERCISE OR FOR OPTION TERM
OPTIONS/WARRANTS/SARS GRANTED TO EMPLOYEES BASE PRICE EXPIRATION ---------------------
NAME GRANTED (#) IN FISCAL YEAR ($/SH) DATE 5%($) 10%($)
---- --------------------- --------------------- ----------- ---------- -------- ----------
Bill I. Pennington 87,500(1) 51% $ 9.375 10/1/09 $516,000 $1,308,000
Arthur J. Pasmas -- -- -- -- -- --
Kyle R. Miller -- -- -- -- -- --
Michael J. Stevens 29,200(1) 17% $ 9.375 10/1/09 $172,000 $ 436,000
William T. War 25,000(2) 15% $ 9.375 10/1/09 $147,000 $ 374,000
- -------------
(1) The options were granted October 1, 1999 and vest 10% on each of the
first four anniversary dates of the date of grant and 60% on the fifth
anniversary if the option holder continues to be employed by the Company
on each anniversary date. The options terminate five years after the last
option vests.
(2) The option was granted October 1, 1999 and vests 20% on each of the
first five anniversary dates of the date of grant if the option holder
continues to be employed by the Company on each anniversary date. The
option terminates five years after the last option vests.
Option/Warrant/SAR Exercises and Year-End Value Table. The following
table sets forth certain information regarding option exercises and the value of
the outstanding options to purchase Common Stock held by the Named Officers at
December 31, 1999:
NUMBER OF SECURITIES VALUE OF UNEXERCISED
UNDERLYING UNEXERCISED IN-THE-MONEY OPTIONS
OPTIONS AT FISCAL YEAR END AT FISCAL YEAR END (1)
NUMBER OF SHARES ---------------------------- ---------------------------
ACQUIRED ON REALIZED
NAME EXERCISE VALUE EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ---- -------- -------- ----------- ------------- ----------- -------------
Bill I. Pennington -- -- -- 87,500 -- --
Arthur J. Pasmas -- -- 1,500 -- -- --
Kyle R. Miller -- -- -- -- -- --
Michael J. Stevens -- -- -- 29,200 -- --
William T. War -- -- -- 25,000 -- --
- ---------------------
(1) Value is based on the closing bid price of $3.25 per share on December
31, 1999.
Long-Term Incentive Plans. The following table sets forth certain
information regarding long-term incentive awards granted during 1999 to the
Named Officers:
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ESTIMATED FUTURE PAYMENTS UNDER
PERFORMANCE OR NON-STOCK PRICE-BASED PLANS
NUMBER OF SHARES, OTHER PERIOD ------------------------------------
UNITS OR OTHER RIGHTS UNTIL MATURATION THRESHOLD TARGET MAXIMUM
NAME # OR PAYOUT ($ OR #) ($ OR #) ($ OR #)
- ---- --------------------- ---------------- --------- -------- --------
Bill I. Pennington -- 12/31/05(1) $250,000 $250,000 $250,000
Arthur J. Pasmas -- -- -- -- --
Kyle R. Miller -- -- -- -- --
Michael J. Stevens -- 12/31/05(1) $125,000 $125,000 $125,000
William T. War -- -- -- -- --
- --------------
(1) The Employment Agreements of Messrs. Pennington and Stevens provide for
a performance bonus of $250,000 and $125,000, respectively, vesting
ratably over a three year period if they continue to be employed on
each of December 31, 2000, 2001 and 2002, based on the Company meeting
or exceeding total earnings before interest, taxes, depreciation and
amortization ("EBITDA"). The year 2000 EBITDA target has been set at
$17.3 million while the year 2001 and year 2002 EBITDA targets will be
established at a later date. The vested bonuses are payable in three
equal amounts on December 31, 2003, 2004 and 2005.
Compensation of Directors. The members of the Board of Directors of the
Company are entitled to reimbursement for their reasonable expenses in
connection with their travel to and from, and attendance at, meetings of the
Board of Directors or committees thereof. Prior to September 23, 1999, directors
of the Company who were not employees were paid an annual fee of $12,000, plus
$1,000 for each meeting attended personally, $500 for each meeting attended
telephonically and $500 for each meeting of any committee whether attended
personally or telephonically. Effective September 23, 1999, members of the Board
who are not employees of the Company are paid an annual fee of $25,000 and no
additional meeting fees for meetings of the Board or any committee. Prior to
September 23, 1993, each non-employee director was also granted an option for
600 shares of Common Stock upon the date of initial election and upon the date
of each reelection to the Board at an exercise price equal to the fair market
value of the Common Stock on the business day preceding the date of election or
reelection. The Board of Directors may also grant discretionary options to
directors.
Messrs. Lomax and Farnsworth each received $25,000 as compensation for
serving on the Special Committee of the Board of Directors which evaluated the
recapitalization of the Company closed on September 21, 1999 and made
recommendations to the full Board of Directors.
Employment Agreements. The Company entered into new employment
agreements with Messrs. Pennington, Stevens and War effective October 1, 1999,
pursuant to which the Company and Messrs. Pennington, Stevens and War mutually
agreed to terminate their prior employment agreements, Messrs. Pennington and
Stevens agreed to cancel all outstanding options or warrants granted to them,
the Company agreed to grant new options or warrants to Mr. Pennington (87,500
shares of Common Stock), Mr. Stevens (29,200 shares of Common Stock) and Mr. War
(25,000 shares of Common Stock) exercisable at the closing sale price of the
Common Stock on the effective date of their new employment agreements ($9.375
per share) and vesting over a five year period. Each of Messrs. Pennington and
Stevens waived their right to terminate their prior employment agreements upon
the change of control occasioned by the recapitalization of the Company closed
September 21, 1999 and to waive their severance payment thereunder. Pursuant to
their new employment agreements, the Company agreed to pay them base salaries of
$250,000 (Mr. Pennington), $130,000 (Mr. Stevens) and $175,000 (Mr. War), a
retention bonus of $100,000 (Mr. Stevens), payable $50,000 on execution of the
agreement and $10,000 during each of the next five quarters, and a performance
bonus of $250,000 (Mr. Pennington) and $125,000 (Mr. Stevens) vesting ratably
over the next three years based on the Company meeting or exceeding certain
performance criteria, and payable ratably over the following three years. Their
new employment agreements also entitle them to participate in all employee
28
32
benefit plans and programs of the Company. Each agreement also provides that if
the employee is permanently disabled during the term of the Agreement, he will
continue to be employed at 50% of his base salary until the first to occur of
his death, expiration of 12 months, or expiration of the employment agreement.
On a subsequent change of control of the Company, any unvested portion of their
options or warrants immediately vest and any unvested portion of the performance
bonuses of Messrs. Pennington and Stevens immediately vest and are payable if
they are terminated by the Company within 90 days. Mr. War's new employment
agreement provides that any non-vested options will vest immediately if he is
terminated without cause because it is determined his services are no longer
required as a result of a successful long-term refinery solution for the
Company's black wax crude oil. Mr. Pennington's new employment agreement
provides that if his employment is terminated by the Company for any reason
prior to September 30, 2001, he will receive a termination payment of $168,000,
decreased by $21,000 for each calendar quarter during which he was employed by
the Company under the new employment agreement. The new employment agreement of
Mr. Stevens provides that if the Company terminates his employment for any
reason, he will be paid any unpaid portion of his retention bonus. Mr. War's new
employment agreement provides that he will receive a termination payment of
$75,000 if his employment is terminated without cause or as a result of a change
of control.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
Arthur J. Pasmas served as Chairman of the Compensation Committee of
Inland's Board of Directors and also served as Co-Chief Executive Officer until
September 21, 1999. Mr. Pasmas received $100,000 as compensation for his duties
as Co-Chief Executive Officer in 1999 and $50,000 in consulting fees in 1999
following his resignation as Co-Chief Executive Officer. Since September 21,
1999, the Company has had no compensation committee and the full Board of
Directors determines the compensation to be paid to executive officers of the
Company. Mr. Pennington, the Chief Executive Officer and Chief Financial Officer
of the Company, and Kyle R. Miller and John E. Dyer, former executive officers
of the Company, participated in deliberations by the Board of Directors
concerning executive officer compensation after September 21, 1999.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information regarding the
ownership of Common Stock, Series D Preferred Stock and Series E Preferred Stock
as of March 15, 2000, by each stockholder known to the Company to own
beneficially more than five percent of the outstanding Common Stock, Series D
Preferred Stock or Series E Preferred Stock, each current director, each Named
Officer, and all executive officers and directors of the Company as a group,
based on information provided to the Company by such persons. Except as
otherwise stated, each such person has sole investment and voting power with
respect to the shares set forth in the table:
PREFERRED STOCK COMMON STOCK
------------------------ ---------------------------
NUMBER NUMBER
NAME AND ADDRESS OF OF
OF BENEFICIAL OWNER SHARES PERCENT SHARES PERCENT
------------------- ------ ------- ------ -------
SERIES D
PREFERRED STOCK
---------------
Inland Holdings LLC (1) 10,757,747 100.0 1,752,586 60.5
TCW Asset
Management Company
1000 Louisiana Street
Suite 2175
Houston, Texas 77002
29
33
PREFERRED STOCK COMMON STOCK
------------------------ ---------------------------
NUMBER NUMBER
NAME AND ADDRESS OF OF
OF BENEFICIAL OWNER SHARES PERCENT SHARES PERCENT
------------------- ------ ------- ------ -------
SERIES E
PREFERRED STOCK
---------------
Enron Corp. (2) 121,973 100.0 292,098 10.1
Joint Energy Development
Investments Ii Limited
Partnership
1400 Smith Street
Houston, Texas 77002
Pengo Securities Corp.(3) -- -- 516,390 17.8
885 Third Avenue, 34th Floor
New York, New York 10022
Marc Macaluso -- -- 100 *
1000 Louisiana Street
Suite 2175
Houston, Texas 77002
John D. Lomax (4) -- -- 2,816 *
791 Nyes Place
Laguna Beach, Ca 92651
Bill I. Pennington (4) -- -- 89,668 3.0
410 17th Street
Suite 700
Denver, Colorado 80202
T Brooke Farnsworth (4) -- -- 300 *
333 North Sam Houston Parkway
Suite 300
Houston, Texas 77060
Michael J. Stevens (4) -- -- 29,200 1.0
4100 17th Street
Suite 700
Denver, Colorado 80202
William T. War (4) -- -- 25,000 *
410 17th Street
Suite 700
Denver, Colorado 80202
Kyle R. Miller -- -- -- --
19 South Lane
Englewood, Colorado 80110
Arthur J. Pasmas(3) -- -- 23,571 *
5858 Westheimer, Suite 400
Houston, Texas 77057
All Executive Officers and -- -- 147,084 4.8
Directors as a Group
(6 Persons) (4)
- ------------------------
* Less than 1%
30
34
(1) Inland Holdings LLC ("Holdings") owns these shares of record and
beneficially. The members of Holdings are Trust Company of the West, as
Sub-Custodian for Mellon Bank for the benefit of Account No. CPFF
873-3032 ("Fund V"), and TCW Portfolio No. 1555 DR V Sub-Custody
Partnership, L.P. ("Portfolio"). TCW Asset Management Company has the
power to vote and dispose of the shares owned by Holdings and may be
deemed to beneficially own such shares. Marc MacAluso is Senior Vice
President of TCW Asset Management Company, but disclaims any beneficial
ownership of these shares. Holdings and TCW Asset Management Company
disclaim any beneficial ownership of the shares owned by Mr. MacAluso.
The holder of Series D Preferred Stock has the right to appoint four
members to the Board.
(2) Joint Energy Development Investments II Limited Partnership ("JEDI") is
the record and beneficial owner of these shares, which may also be
deemed to be beneficially owned by Enron Corp. JEDI, as the holder of
Series E Preferred Stock, has the right, at its election, to appoint
one member to the Board, but has not elected to exercise this right.
(3) Pengo Securities Corp. ("Pengo"), an affiliate of Smith Management,
owns of record and beneficially 402,927 shares of Common Stock. SEP
owns of record and beneficially 15,222 shares of Common Stock. Randall
D. Smith owns of record and beneficially 87,441 shares Jeffrey A. Smith
and John W. Adams, both of whom are officers and directors of Pengo and
Smith Management, each own 16,374 shares of Common Stock. Pengo
disclaims beneficial ownership of the shares owned by Randall D. Smith,
John W. Adams and Jeffrey A. Smith and the shares owned by Messrs.
Smith, Adamas and Smith are not included in the table of shares owned
by Pengo. Arthur J. Pasmas is Vice President of Smith Management. Mr.
Pasmas disclaims beneficial ownership of the shares of the Company's
Common Stock owned by Pengo and Pengo disclaims beneficial ownership of
the shares of the Company's Common Stock owned by Mr. Pasmas, and their
respective shares are not included in the table in the shares owned by
the other. The ownership by Mr. Pasmas reflects options to acquire
1,500 shares of common stock.
(4) Includes shares issuable under outstanding stock options and warrants
granted to Messrs. Lomax, Pennington, Farnsworth, Stevens and War and
all executive officers and directors as a group for 100, 87,500, 300,
29,200, 25,000 and 142,100 shares, respectively.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
TCW Indebtedness. IPC owed Fund V $75 million in principal amount of
subordinated indebtedness at December 31, 1998, and $75 million in principal and
accrued interest of $5.7 million at September 21, 1999. As noted above under
Items 1 and 2 "Business and Properties - Recent Developments - Change of Control
and Recapitalization," Fund V agreed to exchange such indebtedness for shares of
Series D Preferred Stock, Series Z Preferred Stock and Common Stock issued to
Holdings. Marc MacAluso is Senior Vice President of TCW Asset Management
Company. TCW Asset Management Company has the power to vote and dispose of the
securities owned by Holdings.
Exchange of Series C Preferred Stock. As noted above under Items 1 and
2 "Business and Properties - Recent Developments - Change of Control and
Recapitalization," JEDI agreed pursuant to the Exchange Agreement to exchange
its 100,000 shares of Series C Preferred Stock having a redemption price of $10
million, together with 2.2 million of accumulated dividends, for 121,973 shares
of Series E Preferred Stock and 292,098 shares of Common Stock.
Registration Rights Agreement. In connection with the Exchange
Agreement, the Company entered into a Registration Rights Agreement (the
"Registration Agreement") with Holdings, Portfolio, JEDI and the Smith Group
pursuant to which the Company granted Holdings, JEDI and the Smith Group
piggy-back registration rights to include their shares on any registration
statement filed by the Company under the Securities Act of 1933, as amended,
subject to standard underwriters' kick-out clauses and other conditions. The
Company also granted to Holdings, JEDI and the Smith Group demand registration
rights which entitle Holdings to require the Company to file up to three
registration statements to register its shares, entitle JEDI to require the
Company to file up to two registration statements to register its shares and
entitle the Smith Group to require the Company to file one registration
statement to register its shares. The Company will be responsible for paying the
costs and expenses associated with all registration statements, including the
fees of one law firm acting as counsel to the holders
31
35
requesting registration, but excluding underwriting discounts and commissions
and any other expenses of the party requesting registration.
Farmout Agreement. The Company entered into a Farmout Agreement with
Smith Management LLC ("Smith Management") effective June 1, 1998. As of December
31, 1998, SEP, an affiliate of Smith Management, received 152,220 pre-split
(15,222 post-split) shares of Common Stock as payment of proceeds under the
Farmout Agreement. Effective November 1, 1998, an Amendment to the Farmout
Agreement was executed that suspended future drilling rights under the Farmout
Agreement until such time as both the Company, Smith Management and the
Company's senior lenders agreed to recommence such rights. In addition, a
provision was added that gave Smith Management the option to receive cash rather
than Common Stock if the average stock price was calculated at less than $3.00
per share, such cash only to be paid if the Company's senior lenders agreed to
such payment. The Farmout Agreement was further amended on September 21, 1999 as
part of the Recapitalization to eliminate this option, to provide for cash
payments only effective June 1, 1999, and to allow the Company to retain all
proceeds under the Farmout Agreement accrued from November 1, 1998 through May
31, 1999. The Farmout Agreement provides that Smith Management will reconvey all
drillsites to the Company once Smith Management has recovered from production an
amount equal to 100% of its expenditures, including management fees and
production taxes, plus an additional sum equal to 18% per annum on such expended
sums.
Consulting Agreement. The Company entered into a Consulting Agreement
with Arthur J. Pasmas on September 21, 1999 pursuant to which Mr. Pasmas will
receive $200,000 annually for consulting services to be provided to the Company
until September 21, 2002. Mr. Pasmas has been Vice President of Smith Management
(or affiliated entities) since 1987.
Severance Agreement with Kyle R. Miller. Effective September 23, 1999,
Kyle R. Miller resigned as Chief Executive Officer and he and the Company
entered into a Severance Agreement pursuant to which the Company made a
severance payment to him of $375,000 and Mr. Miller agreed to cancel all
outstanding warrants and options granted to him. The Company and Mr. Miller
mutually agreed to terminate his employment agreement, including the
noncompetition provision, and granted mutual releases to each other. Mr. Miller
also resigned as a member of the Board effective October 11, 1999.
Severance Agreement with John E. Dyer. The Company entered into a
Severance Agreement with John E. Dyer in November 1999 pursuant to which the
Company agreed to pay $157,500 as his severance payment under his employment
agreement and grant him an option to become effective as of May 1, 2000, which
option will be exercisable after May 1, 2000 and before May 30, 2000, to acquire
certain real estate in Duchesne County, Utah from the Company for $100 plus the
assumption of the Company's obligations under a deed of trust with an
outstanding balance of $168,000 at December 31, 1999. The Company paid $217,000
for this real estate in May 1995. Pursuant to the Severance Agreement, Mr. Dyer
agreed to cancel all outstanding warrants and options granted to him, the
Company and Mr. Dyer mutually terminated the noncompetition provision of his
previous employment agreement and the Company and Mr. Dyer granted mutual
releases to each other. Pursuant to the Severance Agreement, Mr. Dyer resigned
as President and Chief Operating Officer on December 31, 1999. He also resigned
as a member of the Board of Directors effective February 2, 2000.
32
36
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this Annual Report or
incorporated by reference:
1. Financial Statements
See "Index to Consolidated Financial Statements" on page F-1
of this Annual Report.
2. Financial Statement Schedules
None. All financial statement schedules are omitted because
the information is not required, is not material or is
otherwise included in the consolidated financial statements or
notes thereto included elsewhere in this Annual Report.
3. (a) Exhibits
Item
Number Description
2.1 Agreement and Plan of Merger between Inland Resources Inc. ("Inland"),
IRI Acquisition Corp. and Lomax Exploration Company (exclusive of all
exhibits) (filed as Exhibit 2.1 to Inland's Registration Statement on
Form S-4, Registration No. 33- 80392, and incorporated herein by this
reference).
3.1 Amended and Restated Articles of Incorporation, as amended through
December 14, 1999 (filed as Exhibit 3.1 to Inland's Current Report on
Form 8-K dated September 21, 1999, and incorporated herein by
reference).
3.2 By-Laws of Inland (filed as Exhibit 3.2 to Inland's Registration
Statement on Form S-18, Registration No. 33-11870-F, and incorporated
herein by reference).
3.2.1 Amendment to Article IV, Section 1 of the Bylaws of Inland adopted
February 23, 1993 (filed as Exhibit 3.2.1 to Inland's Annual Report on
Form 10-K for the year ended December 31, 1992, and incorporated herein
by reference).
3.2.2 Amendment to the Bylaws of Inland adopted April 8, 1994 (filed as
Exhibit 3.2.2 to Inland's Registration Statement on Form S-4,
Registration No. 33-80392, and incorporated herein by reference).
3.2.3 Amendment to the Bylaws of Inland adopted April 27, 1994 (filed as
Exhibit 3.2.3 to Inland's Registration Statement on Form S-4,
Registration No. 33-80392, and incorporated herein by reference).
4.1 Credit Agreement dated September 23, 1997 between Inland Production
Company ("IPC"), Inland, ING (U.S.) Capital Corporation, as Agent, and
Certain Financial Institutions, as banks (filed as Exhibit 4.1 to
Inland's Current Report on Form 8-K dated September 23, 1997, and
incorporated herein by reference).
4.1.1 Third Amendment to Credit Agreement entered into as of April 22, 1998,
amending Exhibit 4.1 (filed as Exhibit 4.1.1 to Inland's Quarterly
Report on Form 10-Q for the quarter ended March 31, 1998, and
incorporated herein by reference).
33
37
4.1.2 Amended and Restated Credit Agreement dated as of September 11, 1998
amending and restating Exhibit 4.1 (filed as Exhibit 4.1.2 to Inland's
Annual Report on Form 10-K for the year ended December 31, 1998, and
incorporated herein by reference).
4.1.3 First Amendment to Amended and Restated Credit Agreement dated as of
March 5, 1999 amending Exhibit 4.1.2 (filed as Exhibit 4.1.3 to
Inland's Annual Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).
4.1.4 Second Amended and Restated Credit Agreement dated September 15, 1999,
but effective as of September 21, 1999, amending and restating Exhibit
4.1 (without exhibits or schedules) (filed as Exhibit 4.1 to Inland's
Current Report on Form 8-K dated September 21, 1999, and incorporated
herein by reference).
4.2 Credit Agreement dated September 23, 1997, among IPC, Inland, Trust
Company of the West, and TCW Asset Management Company, in the
capacities described therein (filed as Exhibit 4.2 to Inland's Current
Report on Form 8-K dated September 23, 1997, and incorporated herein by
reference).
4.2.1 Second Amendment to Credit Agreement entered into as of April 22, 1998,
amending Exhibit 4.2 (filed as Exhibit 4.2.1 to Inland's Quarterly
Report on Form 10-Q for the quarter ended March 31, 1998, and
incorporated herein by reference).
4.2.2 Amended and Restated Credit Agreement dated as of September 11, 1998,
amending and restating Exhibit 4.2 (filed as Exhibit 4.2.2 to Inland's
Annual Report on Form 10-K for the year ended December 31, 1998, and
incorporated herein by reference).
4.2.3 First Amendment to Amended and Restated Credit Agreement dated as of
March 5, 1999, amending Exhibit 4.2.2 (filed as Exhibit 4.2.3 to
Inland's Annual Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).
4.2.4 Exchange Agreement dated as of September 21, 1999 by and between
Inland, IPC, Refining, Trust Company of the West, a California trust
company, as Sub-Custodian for Mellon Bank for the benefit of Account
No. CPFF 873-3032, Inland Holdings LLC, TCW Portfolio No. 1555 DR V
Sub-Custody Partnership, L.P. and Joint Energy Development Investments
II Limited Partnership (without exhibits or schedules), terminating
Exhibits 4.2 and 4.3, as previously amended, and Exhibits 4.4, 4.5,
10.10 and 10.11 (filed as Exhibit 10.1 to Inland's Current Report on
Form 8-K dated September 21, 1999, and incorporated herein by
reference).
4.3 Intercreditor Agreement dated September 23, 1997, between IPC, TCW
Asset Management Company, Trust Company of the West and ING (U.S.)
Capital Corporation (filed as Exhibit 4.3 to Inland's Current Report on
Form 8-K dated September 23, 1997, and incorporated herein by
reference).
4.3.1 Third Amendment to Intercreditor Agreement entered into as of April 22,
1998, amending Exhibit 4.3 (filed as Exhibit 4.3.1 to Inland's
Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, and
incorporated herein by reference).
34
38
4.3.2 Amended and Restated Intercreditor Agreement dated as of September 11,
1998, amending and restating Exhibit 4.3 (filed as Exhibit 4.3.2 to
Inland's Annual Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).
4.3.3 First Amendment to Amended and Restated Intercreditor Agreement dated
as of March 5, 1999, amending Exhibit 4.3.2 (filed as Exhibit 4.3.3 to
Inland's Annual Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).
4.4 Warrant Agreement by and between Inland and TCW Portfolio No. 1555 DR V
Sub-Custody Partnership, L.P. dated September 23, 1997 (filed as
Exhibit 4.4 to Inland's Current Report on Form 8-K dated September 23,
1997, and incorporated herein by reference).
4.5 Warrant issued by Inland pursuant to the Warrant Agreement, dated
September 23, 1997, representing the right to purchase 100,000 shares
of Inland's Common Stock (filed as Exhibit 4.5 to Inland's Current
Report on Form 8-K dated September 23, 1997, and incorporated herein by
reference).
10.1 1988 Option Plan of Inland Gold and Silver Corp. (filed as Exhibit
10(15) to Inland's Annual Report on Form 10-K for the year ended
December 31, 1988, and incorporated herein by reference).
10.1.1 Amended 1988 Option Plan of Inland Gold and Silver Corp. (filed as
Exhibit 10.10.1 to Inland's Annual Report on Form 10-K for the year
ended December 31, 1992, and incorporated herein by reference).
10.1.2 Amended 1988 Option Plan of Inland, as amended through August 29, 1994
(including amendments increasing the number of shares to 212,800 and
changing "formula award") (filed as Exhibit 10.1.2 to Inland's Annual
Report on Form 10-KSB for the year ended December 31, 1994, and
incorporated herein by reference).
10.1.3 "Automatic Adjustment to Number of Shares Covered by Amended 1988
Option Plan" executed effective June 3, 1996 (filed as Exhibit 10.1 to
Inland's Quarterly Report on Form 10-QSB for the quarter ended June 30,
1996, and incorporated herein by reference).
10.2 Letter agreement dated October 30, 1996 between Inland and Johnson
Water District (filed as Exhibit 10.41 to Inland's Annual Report on
Form 10-KSB for the year ended December 31, 1996, and incorporated
herein by reference).
10.3 Interest Rate Cap Agreement dated April 30, 1998 between IPC and Enron
Capital and Trade Resources Corp. (filed as Exhibit 10.4 to Inland's
Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, and
incorporated herein by reference).
10.4 Farmout Agreement between Inland and Smith Management LLC dated
effective as of June 1, 1998 (filed as Exhibit 10.1 to Inland's Current
Report on Form 8-K dated June 1, 1998, and incorporated herein by
reference).
35
39
10.5 Warrant Agreement dated as of March 5, 1999 between Inland Resources
Inc. and TCW Portfolio No. 1555 DR V Sub-Custody Partnership, L.P.
(filed as Exhibit 10.20 to Inland's Annual Report on Form 10-K for the
year ended December 31, 1998, and incorporated herein by reference).
10.6 Warrant Certificate dated March 5, 1999 between Inland and TCW
Portfolio No. 1555 DR V Sub-Custody Partnership, L.P. representing
5,852 shares (filed as Exhibit 10.21 to Inland's Annual Report on Form
10-K for the year ended December 31, 1998, and incorporated herein by
reference).
*10.7 Employment Agreement between Inland and Bill I. Pennington dated
effective as of October 1, 1999.
*10.8 Employment Agreement between Inland and Michael J. Stevens dated
effective as of October 1, 1999.
*10.9 Stock Option Agreement between Inland and Bill I. Pennington dated
effective as of October 1, 1999 representing 87,500 post-split shares
of Common Stock.
*10.10 Stock Option Agreement between Inland and Michael J. Stevens dated
October 1, 1999 representing 29,200 post-split shares of Common Stock.
10.11 Shareholders Agreement dated as of September 21, 1999 between Inland,
Holdings, Fund V, JEDI and Pengo Securities Corp., Smith Energy
Partnership, Randall D. Smith, Jeffrey A. Smith, Barbara Stovall Smith,
John W. Adams and Arthur J. Pasmas (collectively, the "Smith Group")
(filed as Exhibit 10.2 to Inland's Current Report on Form 8-K dated
September 21, 1999, and incorporated herein by reference).
10.12 Registration Rights Agreement dated as of September 21, 1999 between
Inland, Holdings, Portfolio, JEDI and the Smith Group filed as Exhibit
10.3 to Inland's Current Report on Form 8-K dated September 21, 1999,
and incorporated herein by reference).
*10.13 Severance Agreement between Inland and John E. Dyer dated November 18,
1999.
*10.14 Employment Agreement between Inland and William T. War dated effective
as of October 1, 1999.
*10.15 Stock Option Agreement between Inland and William T. War dated October
1, 1999 representing 25,000 post-split shares of Common Stock.
*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
36
40
(b) Reports on Form 8-K
Inland filed a Current Report on Form 8-K dated October 4, 1999
reporting information under the following Form 8-K items:
Item 1. Changes in Control of Registrant
Item 5. Other Events
Item 7. Financial Statements and Exhibits
No financial statements were included in the October 4, 1999 Form 8-K.
37
41
SIGNATURES
In accordance with Section 13 or 15(d) of the Securities Exchange Act
of 1934, Inland has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
INLAND RESOURCES INC.
March 23, 2000
By: /s/ Bill I. Pennington
-----------------------------------
Bill I. Pennington
Chief Executive Officer
POWER OF ATTORNEY
Each person whose signature appears below hereby appoints Bill I.
Pennington as his attorney-in-fact to sign on his behalf and in the capacity
stated below and to file all amendments to this Annual Report, which amendment
or amendments may make such changes and additions thereto as such
attorney-in-fact may deem necessary or appropriate.
March __, 2000
---------------------------------------------------
John D. Lomax
Chairman of the Board
March 23, 2000 /s/ BILL I. PENNINGTON
---------------------------------------------------
Bill I. Pennington
Director, Chief Executive Officer and Chief
Financial Officer (Principal Executive Officer
and Principal Financial Officer)
March 23, 2000 /s/ MARC MACALUSO
---------------------------------------------------
Marc MacAluso
Director
March 23, 2000 /s/ T BROOKE FARNSWORTH
---------------------------------------------------
T Brooke Farnsworth
Director
March 23, 2000 /s/ MICHAEL J. STEVENS
---------------------------------------------------
Michael J. Stevens
Vice President, Secretary and Treasurer
(Principal Accounting Officer)
38
42
INDEX TO FINANCIAL STATEMENTS
Page
----
Report of Independent Public Accountants F-2
Consolidated Balance Sheets, December 31, 1999 and 1998 F-3
Consolidated Statements of Operations for the three years ended
December 31, 1999, 1998 and 1997 F-5
Consolidated Statements of Stockholders' Equity for the
three years ended December 31, 1999, 1998 and 1997 F-7
Consolidated Statements of Cash flows for the three years ended
December 31, 1999, 1998 and 1997 F-8
Notes to Consolidated Financial Statements F-9
F-1
43
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
Inland Resources Inc.:
We have audited the accompanying consolidated balance sheets of Inland Resources
Inc. (a Washington corporation) and subsidiaries as of December 31, 1999 and
1998, and the related consolidated statements of operations, changes in
stockholders' equity (deficit) and cash flows for each of the three years in the
period ended December 31, 1999. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Inland Resources Inc. and
subsidiaries as of December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States.
/s/ ARTHUR ANDERSEN LLP
Denver, Colorado,
March 24, 2000.
F-2
44
INLAND RESOURCES INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
December 31,
------------------------
ASSETS 1999 1998
--------- ---------
CURRENT ASSETS:
Cash and cash equivalents $ 1,018 $ 1,275
Accounts receivable and accrued sales 2,166 1,366
Inventory 1,287 1,415
Other current assets 306 218
Net current assets of discontinued operations 2,140 3,764
--------- ---------
Total current assets 6,917 8,038
--------- ---------
PROPERTY AND EQUIPMENT, AT COST:
Oil and gas properties (successful efforts method) 170,217 180,538
Accumulated depletion, depreciation and amortization (27,805) (21,433)
--------- ---------
Total oil and gas properties, net 142,412 159,105
Other property and equipment, net 2,437 2,850
--------- ---------
Total property and equipment, net 144,849 161,955
OTHER LONG-TERM ASSETS 1,892 2,613
NET LONG-TERM ASSETS OF DISCONTINUED OPERATIONS -- 15,175
--------- ---------
Total assets $ 153,658 $ 187,781
========= =========
The accompanying notes are an integral part
of the consolidated balance sheets.
F-3
45
INLAND RESOURCES INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
December 31,
------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) 1999 1998
--------- ---------
CURRENT LIABILITIES:
Accounts payable $ 3,422 $ 10,461
Accrued expenses 1,759 906
Current portion of long-term debt 266 141,709
--------- ---------
Total current liabilities 5,447 153,076
LONG-TERM DEBT 79,072 15,264
COMMITMENTS AND CONTINGENCIES (Notes 1 and 11)
MANDATORILY REDEEMABLE PREFERRED STOCK:
Series C Stock, 100,000 shares issued and outstanding -- 9,568
Accrued preferred Series C dividends -- 1,534
Series D Stock, 10,757,747 shares issued and outstanding,
liquidation preferred of $80.7 million 61,973 --
Accrued preferred series D dividends 2,262 --
Series E Stock, 121,973 shares issued and outstanding, liquidation
preferred of $12.2 million 8,220 --
Accrued preferred series E dividends 350 --
WARRANTS OUTSTANDING -- 1,300
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred Class A stock, par value $.001; 20,000,000 shares authorized,
Series D and Series E outstanding
Common stock, par value $.001; 25,000,000 shares authorized,
2,897,732 and 852,977 issued and outstanding, respectively 3 1
Additional paid-in capital 69,595 42,766
Accumulated deficit (73,264) (35,728)
--------- ---------
Total stockholders' equity (deficit) (3,666) 7,039
--------- ---------
Total liabilities and stockholders' equity (deficit) $ 153,658 $ 187,781
========= =========
The accompanying notes are an integral part
of the consolidated balance sheets.
F-4
46
INLAND RESOURCES INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
For the Years Ended December 31,
------------------------------------
1999 1998 1997
-------- -------- --------
REVENUES:
Oil and gas sales $ 16,399 $ 21,278 $ 17,182
OPERATING EXPENSES:
Lease operating expenses 7,160 8,362 3,780
Production taxes 192 454 383
Exploration 155 153 61
Impairment -- 1,327 --
Depletion, depreciation and amortization 9,882 12,025 6,480
General and administrative, net 3,136 2,061 2,118
-------- -------- --------
Total operating expenses 20,525 24,382 12,822
-------- -------- --------
OPERATING INCOME (LOSS) (4,126) (3,104) 4,360
INTEREST EXPENSE (15,989) (14,895) (4,759)
INTEREST AND OTHER INCOME 72 107 380
-------- -------- --------
NET LOSS FROM CONTINUING OPERATIONS
BEFORE EXTRAORDINARY LOSS (20,043) (17,892) (19)
LOSS FROM DISCONTINUED OPERATIONS (1,774) (5,560) --
LOSS ON SALE OF DISCONTINUED OPERATIONS (14,500) -- --
-------- -------- --------
NET LOSS BEFORE EXTRAORDINARY LOSS (36,317) (23,452) (19)
EXTRAORDINARY LOSS ON EARLY EXTINGUISHMENT
OF DEBT (556) -- (1,160)
-------- -------- --------
NET LOSS (36,873) (23,452) (1,179)
REDEMPTION PREMIUM - PREFERRED SERIES B STOCK -- -- (580)
ACCRUED PREFERRED SERIES C STOCK DIVIDENDS (663) (1,084) (450)
ACCRUED PREFERRED SERIES D STOCK DIVIDENDS (2,262) -- --
ACCRUED PREFERRED SERIES E STOCK DIVIDENDS (350) -- --
ACCRETION OF PREFERRED SERIES D STOCK DISCOUNT (1,473) -- --
ACCRETION OF PREFERRED SERIES E STOCK DISCOUNT (220) -- --
-------- -------- --------
NET LOSS ATTRIBUTABLE TO COMMON
STOCKHOLDERS $(41,841) $(24,536) $ (2,209)
======== ======== ========
The accompanying notes are an integral part
of the consolidated financial statements.
F-5
47
INLAND RESOURCES INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
For the Years Ended December 31,
-------------------------------------------------
1999 1998 1997
------------- ------------- -------------
BASIC AND DILUTED NET LOSS PER SHARE:
Continuing operations $ (17.56) $ (22.62) $ (1.42)
Discontinued operations (1.25) (6.63) --
Sale of discontinued operations (10.18) -- --
Extraordinary loss (0.38) -- (1.57)
------------- ------------- -------------
Total $ (29.37) $ (29.25) $ (2.99)
============= ============= =============
Basic and diluted weighted average common
shares outstanding 1,424,439 838,790 737,794
============= ============= =============
The accompanying notes are an integral part
of the consolidated financial statements.
F-6
48
INLAND RESOURCES INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
(In thousands, except share amounts)
Preferred Stock Accrued Common Stock Additional
--------------------- Series B --------------- Paid-In Accumulated
Shares Amount Dividend Shares Amount Capital Deficit
-------- ------ -------- ------ ------ ---------- -----------
BALANCES, December 31, 1996 1,000,000 $ 10,000 670 631,206 $1 $ 29,134 $ (7,833)
Accrued Preferred Series B dividend -- -- 1,150 -- - -- (1,150)
Conversion of Preferred Series B (1,000,000) (10,000) (1,820) 197,767 - 12,400 (580)
Preferred Series C dividend -- -- -- -- - -- (450)
Exercise of employee stock option -- -- -- 7,010 - 329 --
Net loss -- -- -- -- - -- (1,179)
---------- -------- -------- --------- -- -------- --------
BALANCES, December 31, 1997 835,983 1 41,863 (11,192)
Issuance of common stock under
Farmout Agreement -- -- -- 15,222 - 866 --
Preferred Series C dividends -- -- -- -- - -- (1,084)
Exercise of employee stock options -- -- -- 1,772 - 37 --
Net loss -- -- -- -- - -- (23,452)
---------- -------- -------- --------- -- -------- --------
BALANCES, December 31, 1998 852,977 1 42,766 (35,728)
Preferred Series C dividends -- -- -- -- - -- (663)
Common stock including Preferred Series Z
stock issued in exchange of TCW debt -- -- -- 1,164,295 1 21,698 --
Common stock issued in exchange of JEDI
Preferred Series C stock -- -- -- 292,098 - 3,600 --
Other -- -- -- 71 - -- --
Net gain under related party transaction -- -- -- -- - 5,836
Accretion of Preferred Series D discount -- -- -- -- - (1,473) --
Accretion of Preferred Series E discount -- -- -- -- - (220) --
Preferred Series D dividends -- -- -- -- - (2,262) --
Preferred Series E dividends -- -- -- -- - (350) --
Conversion of Preferred Series Z stock to
common stock -- -- -- 588,291 1 -- --
Net loss -- -- -- -- - -- (36,873)
---------- -------- -------- --------- -- -------- --------
BALANCES, December 31, 1999 2,897,732 $3 $ 69,595 $(73,264)
========== ======== ======== ========= == ======== ========
The accompanying notes are an integral part of
the consolidated financial statements.
F-7
49
INLAND RESOURCES INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(See Note 10)
(In thousands)
For the Years Ended December 31,
---------------------------------
1999 1998 1997
-------- -------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss $(36,873) $(23,452) $ (1,179)
Adjustments to reconcile net loss to net cash
provided (used) by operating activities
Loss from discontinued operations 16,274 5,348 --
Depletion, depreciation and amortization 9,882 12,025 6,480
Amortization of debt issuance costs and debt discount 762 587 265
Loss on early extinguishment of debt 556 -- 1,160
Noncash interest consideration 8,592 866 --
Impairment of assets -- 1,327 --
Effect of changes in current assets and liabilities
Accounts receivable and accrued sales (800) 1,662 (950)
Inventory 128 578 (1,131)
Other current assets 16 1,869 405
Accounts payable and accrued expenses (6,050) 6,012 618
-------- -------- ---------
Net cash provided (used) by operating activities (7,513) 6,822 5,668
-------- -------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Development expenditures and equipment purchases (3,772) (39,391) (29,740)
Acquisition of oil and gas properties -- -- (69,532)
-------- -------- ---------
Net cash used in investing activities (3,772) (39,391) (99,272)
-------- -------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of preferred stock -- -- 9,568
Proceeds from sale of common stock -- 37 328
Proceeds from issuance of long-term debt 11,581 47,750 161,000
Payments of long-term debt (86) (9) (60,099)
Debt issuance costs (493) (702) (3,669)
Restructuring costs related to Series D and Series E (500) -- --
-------- -------- ---------
Net cash provided by financing activities 10,502 47,076 107,128
-------- -------- ---------
NET CASH AND CASH EQUIVALENTS PROVIDED (USED)
BY CONTINUING OPERATIONS (783) 14,507 13,524
NET CASH AND CASH EQUIVALENTS PROVIDED (USED)
BY DISCONTINUED OPERATIONS 526 (13,837) (22,950)
CASH AND CASH EQUIVALENTS, at beginning of period 1,275 605 10,031
-------- -------- ---------
CASH AND CASH EQUIVALENTS, at end of period $ 1,018 $ 1,275 $ 605
======== ======== =========
The accompanying notes are an integral part
of the consolidated financial statements.
F-8
50
INLAND RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 1999
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. During the
period from December 31, 1997 to January 31, 2000, the Company also operated a
crude oil refinery located in Woods Cross, Utah (the "Woods Cross Refinery").
The refinery had a processing capacity of approximately 10,000 barrels per day
and tankage capacity of 485,000 barrels. On December 10, 1999, the Company's
board of directors voted to sell the Woods Cross Refinery operations and a
nonoperating refinery pursuant to a plan of dissolution. The sale of the Woods
Cross Refinery and the nonoperating refinery closed on January 31, 2000. Certain
current assets were excluded from the sale and will be liquidated pursuant to
the plan of dissolution and are expected to be monetized by the end of 2000.
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 of continuing operations have been eliminated in
consolidation.
Reverse Split
- -------------
On December 10, 1999, the Company's shareholders approved a 1-for-10 reverse
stock split of the Company's common stock. The effect of the stock split was to
lower the authorized common shares from 25,000,000 shares to 2,500,000 shares
and reduce outstanding common shares from 23,093,689 shares to 2,309,441 shares.
The shareholders further approved an increase in the number of post-split
authorized shares from 2,500,000 shares to 25,000,000. Par value remained at
$0.001 per common share. All per share disclosures including loss per share and
weighted average common and common equivalent shares outstanding as reported on
the consolidated balance sheet, consolidated statement of operations and
consolidated statement of stockholders' equity have been calculated based on
post-reverse split share amounts.
Use of Estimates in the Preparation of Financial Statements
- -----------------------------------------------------------
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates. The impact of oil and gas
prices has a significant influence on estimates made by management. Changes in
oil and gas prices directly effect the economic limits of estimated oil and gas
F-9
51
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.
Cash and Cash Equivalents
- -------------------------
Cash and cash equivalents include cash on hand and amounts due from banks and
other investments with original maturities of less than three months.
Concentrations of Credit Risk
- -----------------------------
The Company regularly has cash in a single financial institution which exceeds
depository insurance limits. The Company places such deposits with high credit
quality institutions and has not experienced any credit losses. Substantially
all of the Company's receivables are within the oil and gas industry, primarily
from its oil and gas purchasers and joint interest owners. Although diversified
within many companies, collectibility is dependent upon the general economic
conditions of the industry. To date, write-offs of uncollectable accounts have
been minimal.
Fair Value of Financial Instruments
- -----------------------------------
The Company's financial instruments consist of cash, trade receivables, trade
payables, accrued liabilities, long-term debt 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. The fair value of
the preferred stock is not readily determinable and long-term debt is based on
variable rate interest, accordingly approximates fair value. The fair value of
crude oil contracts are estimated based on market conditions in effect at the
end of each reporting period.
Inventories
- -----------
Inventories consist of tubular goods valued at the lower of average cost or
market. Materials and supplies inventories are stated at cost and are charged to
capital or expense, as appropriate, when used.
Accounting for Oil and Gas Operations
- -------------------------------------
The Company follows the successful efforts method of accounting for oil and gas
operations. The use of this method results in the capitalization of those costs
associated with the acquisition, exploration and development of properties that
produce revenue or are anticipated to produce future revenue. The Company does
not capitalize general and administrative expenses directly identifiable with
such activities or lease operating expenses associated with secondary recovery
startup projects. Costs of unsuccessful exploration efforts are expensed in the
period it is determined that such costs are not recoverable through future
revenues. Geological and geophysical costs are expensed as incurred. The cost of
development wells are capitalized whether productive or nonproductive. Upon the
sale of proved properties, the cost and accumulated depletion are removed from
the accounts and any gain or loss is charged to income. Interest is capitalized
during the drilling and completion period of wells and on other major projects.
The amount of interest capitalized was $0, $150,000 and $135,000 during 1999,
1998 and 1997, respectively.
The provision for depletion, depreciation and amortization of developed oil and
gas properties is based on the units of production method. This method utilized
proved oil and gas reserves determined using
F-10
52
market prices at the end of each reporting period. Dismantlement, restoration
and abandonment costs are in management's opinion, offset by residual values of
lease and well equipment. As a result, no accrual for such costs is provided.
Impairment Review
- -----------------
The Company reviews and evaluates its long-lived assets for impairment when
events or changes in circumstances indicate that the related carrying amounts
may not be recoverable. An impairment loss is measured as the amount by which
asset carrying value exceeds fair value. A calculation of the aggregate
before-tax undiscounted future net revenues is performed for the oil and gas
properties. The Company 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 $21.56
per barrel and $1.83 per Mcf over the remaining estimated life of the
properties.
The Company also periodically assesses unproved oil and gas properties for
impairment. Impairment represents management's estimate of the decline in
realizable value experienced during the period for leases not expected to be
utilized the Company.
Property and Equipment
- ----------------------
Property and equipment is recorded at cost. Replacements and major improvements
are capitalized while maintenance and repairs are charged to expense as
incurred. Upon sale or retirement, the asset cost and accumulated depreciation
are removed from the accounts and any resulting gain or loss is reflected in
operations. Depreciation is provided using the straight-line method over the
estimated useful lives of the related assets, generally ranging from three to
thirty years. Maintenance and repairs are expensed as incurred. Major
improvements are capitalized, and the assets replaced, are retired.
Environmental
- -------------
Environmental costs are expensed or capitalized based upon their future economic
benefit. Costs which are improvements are capitalized. Costs related to
environmental remediation and reclamation are expensed. Liabilities for
remediation and reclamation costs are accrued when it is determined that an
obligation exists and the amount of the costs can be reasonably estimated.
Income Taxes
- ------------
The Company uses the liability method of accounting for income taxes. Under the
liability method, deferred income taxes are recorded for differences between the
book and tax basis of assets and liabilities at tax rates in effect when the
balances are expected to reverse. A valuation allowance against deferred tax
assets is recorded when the conclusion by Company management is reached that the
tax benefits, based on available evidence, are not expected to be realized.
Revenue Recognition
- -------------------
Sales of crude oil and natural gas are recorded upon delivery to purchasers.
Loss Per Share
- --------------
Net loss per share is presented for basic and diluted net loss and, if
applicable, for net loss from discontinued operations and extraordinary losses.
Basic earnings per share is computed by dividing net loss attributable to common
stockholders by the weighted-average number of common shares for the
F-11
53
period. The computation of diluted earnings per share includes the effects of
additional common shares that would have been outstanding if potentially
dilutive common shares had been issued. As the Company was in a net loss
position for all periods presented, there were no dilutive securities.
Reclassifications
- -----------------
Certain amounts in prior years have been reclassified to conform to the 1999
presentation.
2. FINANCIAL INSTRUMENTS:
----------------------
Periodically, the Company enters into commodity contracts to hedge or otherwise
reduce the impact of oil 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 is
sold or the scheduled settlement of interest rate instruments. Hedging
activities do not affect the actual sales price for the Company's crude oil or
interest rate for the Company's debt facilities. The Company is subject to the
creditworthiness of its counterparties since the contracts are not
collateralized. The Company has not incurred any significant losses nor does the
Company expect any to occur.
In June 1998, SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS No. 133") was issued, which establishes accounting and
reporting standards for derivative instruments and hedging activity. The
adoption of SFAS No. 133 was deferred to all fiscal quarters of all fiscal years
beginning after June 15, 2000, by SFAS No. 137 "Accounting for Derivative
Instruments and Hedging activities -Deferred of the Effective Date of FASB
Statement No. 133 - an Amendment of FASB Statement No. 133. 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 and plans to adopt
the statement on January 1, 2001.
Crude Oil Hedging Activities
- ----------------------------
The Company has various contracts that hedge crude oil production structured as
cost free collars whereby if the average monthly price, based on NYMEX Light
Sweet Crude Oil Futures Contracts, is between floor and a ceiling, no payment is
exchanged between the parties. The Company has hedged 720,000 barrels of its
projected year 2000 oil production (60,000 barrels per month) under various
collars with floors ranging from $19.00 to $20.00 per barrel and ceilings
ranging from $19.70 to $22.50 per barrel. The Company has hedged 495,000 barrels
of its projected year 2001 oil production (60,000 barrels per month for January
through June and 45,000 barrels per month for July through September) under
various collars with floors ranging from $19.00 to $20.50 per barrel and
ceilings ranging from $20.80 to $22.15 per barrel. The Company may enter into
additional year 2000 and 2001 oil hedges depending on market conditions. As of
December 31, 1999, the fair value of these contracts is a liability of $480,100.
During the period April 1, 1999 to December 31, 1999, the Company hedged oil
production under two contracts from Enron Capital and Trade Resources Corp.
("Enron"). The contracts were structured as swaps covering 80,000 barrels per
month at an average strike price of $14.28 (based on NYMEX Light Sweet Crude Oil
Futures Contracts). The Company recorded a reduction to revenue of $4.9 million
under these contracts during 1999.
F-12
54
During 1998 and 1997 the Company had various contracts in place consisting of
puts, calls and collars. Each of the contracts was completely settled as of
December 31, 1998. The effect of all hedging contracts in these years resulted
in income of $550,000 in 1998 and a loss of $217,000 in 1997.
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 1999 or
1998. The fair value of this put contract as of December 31, 1999 was de
minimus.
3. LOSS PER SHARE:
---------------
The calculation of loss per share for the years ended December 31, 1999, 1998
and 1997 is as follows (in thousands, except per share data):
1999 1998 1997
--------------------------- ------------------------ ---------------------------
Per Share Per Share Per Share
Loss Shares Amount Loss Shares Amount Loss Shares Amount
---- ------ --------- ---- ------ --------- ---- ------ ---------
Loss from continuing operations
before extraordinary item $(20,043) $(17,892) $ (19)
Preferred Series B redemption
premium -- (580)
Preferred Series C stock dividends (663) (1,084) (450)
Preferred Series D stock dividends (2,262)
Preferred Series E stock dividends (350)
Accretion of Series D stock discount (1,473)
Accretion of Series E stock discount (220)
-------- -------- -------
BASIC AND DILUTED LOSS
PER SHARE:
Loss from continuing operations
before extraordinary loss
available to common
shareholders $(25,011) 1,424 $(17.56) $(18,976) 839 $(22.62) $(1,049) 738 $ (1.42)
======== ======= ======== ======= ======= =======
4. RESTRUCTURING TRANSACTION:
--------------------------
On September 21, 1999, the Company entered into an Exchange Agreement (the
"Exchange Agreement") with Trust Company of the West and affiliated entities
("TCW") and Joint Energy Development Investments II Limited Partnership ("JEDI")
pursuant to which TCW agreed to exchange certain indebtedness and warrants to
purchase Common Stock, for shares of Common Stock and two new series of
Preferred Stock of the Company, and JEDI agreed to exchange 100,000 shares of
Series C Preferred Stock of the Company for shares of Common Stock and a third
new series of Preferred Stock of the Company (the "Recapitalization").
Pursuant to the Exchange Agreement, TCW agreed to exchange $75.0 million of
subordinated indebtedness plus accrued interest of $5.7 million and warrants to
purchase 15,852 shares of Common Stock for the following securities of the
Company: (i) 10,757,747 shares of newly designated Series D Redeemable Preferred
Stock of the Company ("Series D Preferred Stock"), (ii) 5,882,901 shares of
newly designated Series Z Convertible Preferred Stock of the Company ("Series Z
Preferred Stock") and (iii) 1,164,295 shares of Common Stock. On December 14,
1999, all shares of Series Z Preferred Stock were converted into 588,291 shares
of Common Stock. In addition, JEDI agreed
F-13
55
to exchange 100,000 shares ($10.0 million par value) of the Company's Series C
Cumulative Convertible Preferred Stock ("Series C Preferred Stock") owned by
JEDI, together with $2.2 million of accumulated dividends thereon, for (i)
121,973 shares of newly designated Series E Redeemable Preferred Stock of the
Company ("Series E Preferred Stock") and (ii) 292,098 shares of Common Stock.
At December 31, 1999, TCW owns 1,752,586 shares of Common Stock, representing
approximately 60.5% of the outstanding shares of Common Stock, and JEDI owns
292,098 shares of Common Stock, representing approximately 10.1% of the
outstanding shares of Common Stock. In connection with the Exchange Agreement,
the Articles of Incorporation (the "Articles") of the Company were amended to
designate the Series D Preferred Stock and Series E Preferred Stock. The amended
Articles provide that the Common Stock, Series D Preferred Stock and Series E
Preferred Stock shall vote together as a single class and not as a separate
voting group or class, except as mandated by law or as expressly set forth in
the Articles. The Series D Preferred Stock and the Series E Preferred Stock vote
with the Common Stock on a share-for-share basis. Pursuant to the amended
Articles, the total number of votes of the combined class of Common Stock,
Series D Preferred Stock and Series E Preferred Stock presently outstanding is
3,985,704 votes, of which 2,828,361 votes (representing approximately 71% of the
total) are owned by TCW, and 304,295 votes (representing approximately 7.6% of
the total) are owned by JEDI.
Under the amended Articles, the Series D Preferred Stock accrues dividends at a
rate of $0.16875 per share per quarter (9% annual rate) if paid in cash on a
current basis or $0.2109375 per share per quarter (11.25% annual rate compounded
quarterly) if accumulated and not paid on a current basis. No dividends may be
paid on Common Stock or any other series of preferred stock while there are any
accrued and unpaid dividends on the Series D Preferred Stock. The Series D
Preferred Stock also has liquidation preference over all other classes and
series of stock, in an amount equal to $7.50 per share ($80.7 million). The
Series D Preferred Stock may be redeemed at any time by the Company (subject to
the senior credit facility being repaid) for a redemption price of $7.50 per
share and must be redeemed in equal amounts over three years commencing upon the
earlier of September 21, 2004 or the repayment in full of the Company's existing
senior credit facility which is October 1, 2001. The difference between the book
value and the liquidation value of the Series D Preferred Stock at the exchange
date ($20.2 million) is being accreted over the minimum redemption period
beginning on October 1, 2001, and results in a charge against earnings available
for common shareholders. In addition to voting as a class with the Common Stock
and Series E Preferred Stock as discussed above, holders of 75% of the
outstanding shares of Series D Preferred Stock, voting as a separate voting
group, must approve any modification to the dividend rates, liquidation
preferences or other privileges of the Series D Preferred Stock, any merger or
consolidation of the Company in which the Company is not the surviving entity,
any transaction which will result in the holders of voting stock of the Company
immediately prior to such transaction owning less than 50% of the outstanding
voting stock of the Company after the transaction or the sale or other transfer
of substantially all of the assets of the Company. Further, a majority of the
outstanding shares of Series D Preferred Stock, voting as a separate voting
group, have the right to elect (i) four members of the Board for as long as at
least 37.5% of the original shares of Series D Preferred Stock remain
outstanding; (ii) three members of the Board for as long as at least 25%, but
less than 37.5% remain outstanding; (iii) two members of the Board for as long
as at least 12.5%, but less than 25% remain outstanding; and (iv) one member of
the Board for as long as any shares of Series D Preferred Stock remain
outstanding even though they are less than 12.5% of the original shares issued.
As the number of members that may be elected by holders of Series D Preferred
Stock decline, the holders of Common Stock are entitled to elect those members
to the Board.
Under the amended Articles, the Series E Preferred Stock accrues dividends at a
rate of $2.3125 per share per quarter (9.25% annual rate) if paid in cash on a
current basis or $2.875 per share per quarter (11.5% annual rate compounded
quarterly) if accumulated and not paid on a current basis. No dividends may be
paid on Common Stock while there are any accrued and unpaid dividends on the
Series E Preferred Stock.
F-14
56
The Series E Preferred Stock also has liquidation preference over all other
classes and series of stock, except the Series D Preferred Stock, in an amount
equal to $100.00 per share ($12.2 million). The Series E Preferred Stock may be
redeemed at any time by the Company (subject to the senior credit facility being
repaid on October 1, 2001 and the Series D Preferred Stock having been redeemed)
for a redemption price of $100.00 per share and must be redeemed upon the
earlier of September 21, 2006 or the redemption of all outstanding shares of
Series D Preferred Stock. The difference between the book value and the
liquidation value of the Series E Preferred Stock at the exchange date ($4.2
million) is being accreted over the minimum redemption period to October 1,
2003, and results in a charge against earnings available for common
shareholders. In addition to voting as a class with Common Stock and Series D
Preferred Stock as discussed above, holders of 75% of the outstanding shares of
Series E Preferred Stock, voting as a separate voting group, must approve any
modification to the dividend rates, liquidation preferences or other privileges
of the Series E Preferred Stock; any merger or consolidation of the Company in
which the Company is not the surviving entity or any transaction which will
result in the holders of voting stock of the Company immediately prior to such
transaction owning less than 50% of the outstanding voting stock of the Company
after the transaction, unless, in either case, the holders of Series E Preferred
Stock receive shares with substantially the same rights and preferences as
correspond to the Series E Preferred Stock; any merger in which the holders of
Common Stock receive consideration in exchange for their Common Stock other than
Common Stock of the surviving corporation that is junior to the securities
issued to the holders of Series E Preferred Stock; or the sale or other transfer
of substantially all of the assets of the Company unless, so long as the Series
D Preferred Stock is outstanding, at least 60% of the Series E Preferred Stock
is redeemed or the holders of Series E Preferred Stock receive an amount equal
to 60% of 10/85ths of the total consideration received by the holders of Series
D Preferred Stock and Series E Preferred Stock in the same form of consideration
as that received by the holders of Series D Preferred Stock. Further, a majority
of the outstanding shares of Series E Preferred Stock, voting as a separate
voting group, have the right to elect one member of the Board; although they
have not yet exercised this right.
One of the conditions to closing the Exchange Agreement was that Inland's senior
lenders would enter into a restructuring of the senior credit facility
acceptable to TCW, JEDI and the Company. As a result, effective as of September
21, 1999, the Company entered into the Second Amended and Restated Credit
Agreement (the "ING Credit Agreement") with ING (U.S.) Capital Corporation, U.S.
Bank National Association and Meespierson Capital Corporation (the "Senior
Lenders") pursuant to which the Senior Lenders agreed to increase the borrowing
base from $73.25 million to $83.5 million, inclusive of a sublimit for letters
of credit of $4.0 million. The outstanding principal balance at December 31,
1999 was $78,915,000. The Company also had $1.9 million of outstanding letters
of credit at December 31, 1999. All borrowings under the ING Credit Agreement
are due on October 1, 2001, or potentially earlier if the borrowing base is
determined to be insufficient. The borrowing base is calculated as the
collateral value of proved reserves and will be redetermined on October 1, 2000
and April 1, 2001 and may be redetermined at the option of the Senior Lenders
one additional time after October 1, 2000. Upon redetermination, if the
borrowing base is lower than the outstanding principal balance then drawn, the
Company must immediately pay the difference. Interest accrues, at the Company's
option, at either (i) 2% above the prime rate or (ii) 3% above the LIBOR rate.
At December 31, 1999, substantially all amounts were borrowed under the LIBOR
option at an effective rate of 9.17% through June 29, 2000. The Company paid a
facility fee of $150,000 and an additional fee of $208,000 to the Senior Lenders
at closing. The Company must also pay a facility fee equal to 0.50% of the
borrowing base on April 1, 2001 and again on September 30, 2001. The Senior
Lenders will also receive a fee equal to 1% of the borrowing base on October 1,
2000 if ING (U.S.) Capital Corporation continues to be a member of the Senior
Lenders at September 30, 2000. The ING Credit Agreement has covenants that
restrict the payment of cash dividends, borrowings, sale of assets, loans to
others, investment and merger activity and hedging contracts without the prior
consent of the lenders and requires the Company to maintain certain net worth,
interest coverage and working capital ratios. Subsequent to year end, certain
covenants were
F-15
57
amended allowing the Company to remain in compliance at December 31, 1999. The
ING Credit Agreement is secured by a first lien on substantially all assets of
the Company.
The Company also amended its Farmout Agreement with Smith Energy Partnership
("Smith") in conjunction with the financial restructuring on September 21, 1999.
The Farmout Agreement was originally entered into effective June 1, 1998. As of
December 31, 1998 Smith had received 15,222 (post reverse split) shares of
Common Stock as payment of net proceeds through October 31, 1998 under the
Farmout Agreement. Effective November 1, 1998, an Amendment to the Farmout
Agreement was executed that suspended future drilling rights under the Farmout
Agreement until such time as the Company, Smith and the Company's senior lenders
agreed to recommence such rights. In addition, a provision was added that gave
Smith the option to receive cash rather than Common Stock if the average stock
price was calculated at less than $3.00 (post reverse split) per share, such
cash only to be paid if the Company's senior lenders agreed to such payment. The
amendment to the Farmout Agreement on September 21, 1999 eliminated this option
and provided for cash payments only effective June 1, 1999. The amendment also
allowed the Company to retain all proceeds under the Farmout Agreement accrued
from November 1, 1998 through May 31, 1999. As a result of this recent
amendment, and the fact that the Company has no further obligations in relation
to these properties, the production loan previously recorded by the Company is
no longer considered outstanding. As a result, the Company has removed all
previously recorded drilling costs, accumulated depletion, debt issue costs,
loans and accrued interest as of September 21, 1999 and will no longer record
revenue and costs from wells drilled under the Farmout Agreement in its
Consolidated Statement of Operations or Consolidated Statement of Cash Flows.
The $5.8 million gain recognized upon the removal of previously recorded account
balances was charged directly to equity due to the related-party nature of the
transaction. The Farmout Agreement continues to provide that Smith will reconvey
all drillsites to the Company once Smith has recovered from production an amount
equal to 100% of its expenditures, including management fees and production
taxes, plus an additional sum equal to 18% per annum on such expended sums.
5. DISCONTINUED OPERATIONS:
------------------------
Pursuant to a decision by the Company's board of directors on December 10, 1999
to dispose of the Company's refinery operations, 100% of the stock in Inland
Refining, Inc., a wholly owned subsidiary was sold on January 31, 2000 to Silver
Eagle Refining, Inc. ("Silver Eagle"). This subsidiary owned the Woods Cross
Refinery and a nonoperating refinery located in Roosevelt, Utah. The Woods Cross
refinery was originally purchased on December 31, 1997 for $22.9 million and the
Roosevelt refinery was originally purchased on September 16, 1998 for $2.25
million. The sales price was $500,000 together with the assumption by Silver
Eagle of refinery assets, liabilities and obligations including all
environmental related liabilities. Prior to the sale, the Company transferred
the existing inventory, cash, accounts receivable and a note receivable to
another wholly owned subsidiary of the Company. This subsidiary also agreed to
satisfy various accounts payable and accrued liabilities not assumed by Silver
Eagle. These asset and liabilities will be disposed of within one year of
December 10, 1999.
As a result of this sale, the Company is no longer involved in the refining of
crude oil or the sale of refined products. As a result, all refining operations
have been classified as discontinued operations in the accompanying consolidated
financial statements. To account for the sale, the Company recorded a loss on
sale of discontinued operations of $14.5 million at December 31, 1999. In
addition, certain prior year amounts were reclassified as discontinued
operations, with no net effect on net loss or accumulated deficit as previously
reported. Revenue from discontinued operations was $70.3 million and $68.5
million during the years ended December 31, 1999 and 1998, respectively. The net
current assets of discontinued operations at December 31, 1999 consist of $7.9
million of current assets consisting primarily of inventory and accounts
receivable, offset by $5.8 million of liabilities, primarily accounts payable
and accrued liabilities.
F-16
58
6. ACQUISITIONS:
-------------
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 allocated in the Monument Butte region from
Equitable Resources Energy Company ("EREC") for a purchase price of $56.0
million. The acquisition was accounted for as a purchase, 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
funded this acquisition with debt.
6. OTHER PROPERTY AND EQUIPMENT:
-----------------------------
December 31,
--------------------
1999 1998
------- -------
(in thousands)
Vehicles $ 1,579 $ 1,381
Land and buildings 1,214 1,232
Furniture and fixtures 1,416 1,377
Leasehold improvements 86 86
------- -------
4,295 4,076
Less accumulated depreciation (1,858) (1,226)
------- -------
Total $ 2,437 $ 2,850
======= =======
7. LONG-TERM DEBT (See Note 4):
----------------------------
TCW and ING Credit Agreements
- -----------------------------
On September 30, 1997, the Company closed separate Credit Agreements with TCW
and ING (U.S.) Capital Corporation ("ING"). The TCW Credit Agreement provided
the Company with $75.0 million, all of which was funded at closing. The TCW
Credit Agreement originally provided for quarterly interest payments only, at a
rate of 9.75% per annum, until the earlier of December 31, 2003 or the date on
which the ING loan was paid in full. The Company initially granted a warrant to
TCW to purchase 10,000 shares of common stock at an exercise price of $100.00
per share (subject to anti-dilution adjustments) and later granted TCW a warrant
to purchase 5,852 shares of common stock at $17.50 (subject to anti-dilution
adjustments) for an amendment that deferred certain interest payments during
1999. The Company also granted registration rights in connection with such
warrants. The TCW Credit Agreement was secured by a second lien on substantially
all assets of the Company. As discussed in Note 4, on September 21, 1999, TCW
exchanged the outstanding principal balance of $75.0 million, accrued interest
of $5.7 million and 15,852 warrants for Preferred Series D Stock and Common
Stock of the Company.
F-17
59
As discussed in Note 4, on September 21, 1999, the Company entered into the
Second Amended and Restated Credit Agreement with its Senior Lenders as part of
the Recapitalization which was further amended on January 31, 2000 and March 20,
2000. Prior to the terms of that amendment, the ING Credit Agreement constituted
a revolving line of credit which converted to a term loan payable in quarterly
installments through March 29, 2003. The borrowing base under the prior ING
facility was limited to the collateral value of proved reserves as determined
semiannually by the lender. The prior ING loan accrued 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 ING
Credit Agreement was secured by a first lien on substantially all assets of the
Company. On March 11, 1999, the Company amended the prior ING Credit Agreement
to increase the borrowing base to $73.25 million. The Senior Lenders received
warrants to purchase 5,000 shares of common stock at $17.50 (subject to
anti-dilution adjustments) as consideration for entering into the amendment.
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).
Due to the subsequent amendment made as discussed in Note 4, the Company no
longer classifies the Smith Farmout obligation as debt.
A summary of the Company's long-term debt follows (in thousands):
December 31,
-----------------------
1999 1998
-------- ---------
TCW Credit Agreement $ -- $ 75,000
Less discount on TCW Credit Agreement -- (955)
-------- ---------
-- 74,045
ING Credit Agreement 78,915 67,665
Smith Farmout -- 15,085
Other 423 178
-------- ---------
Total 79,338 156,973
Current portion (266) (141,709)
-------- ---------
Long-term portion $ 79,072 $ 15,264
======== =========
F-18
60
As of December 31, 1999, the annual principal payments on long-term debt for the
next five years are as follows (in thousands):
2000 $ 266
2001 78,927
2002 13
2003 13
2004 14
Thereafter 105
-------
$79,338
=======
8. INCOME TAXES:
-------------
In 1999, 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, 1999 is as follows (in
thousands):
Deferred
December 31, Expense December 31,
1999 (Benefit) 1998
------------ --------- ------------
Deferred tax assets:
Net operating loss carryforwards $ 28,249 $ 14,075 $ 14,174
Smith Farmout debt -- (5,483) 5,483
-------- -------- --------
Total 28,249 8,592 19,657
Valuation allowance (22,453) (12,514) (9,939)
-------- -------- --------
Deferred tax assets 5,796 (3,922) 9,718
-------- -------- --------
Deferred tax liabilities:
Depletion, depreciation and amortization
of property and equipment (5,796) 3,922 (9,718)
-------- -------- --------
Deferred tax liabilities (5,796) 3,922 (9,718)
-------- -------- --------
Net deferred tax assets $ -- $ -- $ --
======== ======== ========
A valuation allowance is to be provided if it is more likely than not that some
portion or all of a deferred tax asset will not be realized. The Company's
ability to realize the benefit of its tax assets depends on the generation of
future taxable income through profitable operations and expansion of the
Company's oil and gas producing properties. The market, capital and
environmental risks associated with that growth requirement caused the Company
to conclude that a valuation allowance should be provided, except to the extent
that the benefit of operating loss carryforwards can be used to offset future
reversals of existing
F-19
61
deferred tax liabilities. The Company will continue to monitor the need for the
valuation allowance that has been provided.
Income tax expense for 1999, 1998 and 1997 differed from amounts computed by
applying the statutory federal income tax rate as follows (in thousands):
December 31,
--------------------------------
1999 1998 1997
-------- ------- -----
Expected statutory tax expenses at 34% $(12,537) $(7,974) $(401)
Change in valuation allowance, net 12,514 8,292 540
Other 23 (318) (139)
-------- ------- -----
Net tax expense $ -- $ -- $ --
======== ======= =====
In 1997, $1.77 million of the valuation allowance was reversed upon the
acquisition of certain properties, 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, 1999 or 1998, and the Company did not pay any income
taxes in 1999, 1998 or 1997.
At December 31, 1999, the Company had tax basis net operating loss carryforwards
available to offset future regular and alternative taxable income of $29.7
million, that expire from 2000 to 2019. Utilization of the net operating loss
carryforwards are limited under the change of ownership tax rules.
9. CAPITAL STOCK (SEE NOTE 4):
---------------------------
Series C Preferred Stock
- ------------------------
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 JEDI for cash of $10.0 million ($9.6 million net of
closing fees). As discussed in Note 4, on September 21, 1999, JEDI exchanged
their Series C Stock and accrued dividends for Preferred Series E Stock and
Common Stock of the Company.
Series D and Series E Preferred Stock
- -------------------------------------
See Note 4 for a full description of the Series D and Series E rights and
preferences.
F-20
62
10. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (SEE NOTE 4):
--------------------------------------------------------------
Cash paid for interest during 1999, 1998 and 1997 was approximately $6,112,000,
$11,629,000 and $4,092,000, respectively.
As part of the Smith Farmout restructuring, the following accounts were
impacted:
Oil and gas properties $(13,833)
Accumulated depreciation, depletion and amortization 2,837
Deferred debt offering costs (233)
Smith Farmout loan 15,085
Smith Farmout accrued interest 2,792
Additional paid-in capital (5,837)
During 1998, the Company paid interest on the Smith Farmout transaction, as
allowed by its terms, by issuing common stock valued at $866,000.
11. COMMITMENTS AND CONTINGENCIES:
------------------------------
Lease Commitments
- -----------------
The Company leases 16,500 square feet of office space under a noncancellable
operating lease. Future payment under this lease is as follows (in thousands):
2000 $264
2001 264
2002 264
----
Total $792
====
Total lease expense during 1999, 1998 and 1997 was $264,000, $264,000 and
$148,000, respectively.
401(k) Plan
- -----------
The Company provides a voluntary 401(k) employee savings plan which covers all
full-time employees who meet certain eligibility requirements. Voluntary
contributions are made to the 401(k) Plan by participants. In addition, the
Company matches 100% of the first 6% of salary contributed by each employee.
During the period January 1, 1999 to September 30, 1999, the Company match was
reduced to 100% of the first 2% of salary contributed. Matching contributions of
$104,000, $206,000 and $50,000 were made by the Company during 1999, 1998 and
1997, 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.
F-21
63
Consulting Agreement
- --------------------
The Company entered into a consulting agreement on September 21, 1999 with a
former director of the Company that was also an officer of Smith Management
pursuant to which this individual will receive $200,000 annually, paid in equal
monthly installments for consulting services to be provided to the Company until
September 21, 2002.
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 21,280 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.
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 50,000 shares for grant under
the 1997 Plan of which 41,850 options were granted through December 31, 1999 at
prices equal to the market value of the Company's stock on the date of grant.
All granted options are vested except for 30,000 options which vest on December
31, 2001. There are 8,150 shares available for grant as of December 31, 1999.
A summary of option grants, exercises and average prices under both the plans is
presented below:
Weighted Option Weighted
Average Exercise Fair Value
Number of Exercise Price of Options
Options Price Range Granted
--------- -------- ------------------ ----------
Balance, December 31, 1996 20,430 $ 52.60 $ 25.00 - $115.00
Granted 8,850 103.60 85.00 - 110.00 $55.43
Exercised (7,010) 46.90 31.30 - 68.70 ======
------ -------- ------------------
Balance, December 31, 1997 22,270 75.80 25.00 - 115.00
Granted 3,000 84.40 84.40 - 84.40 $60.79
Exercised (680) 54.60 25.00 - 68.70 ======
------ -------- ------------------
Balance, December 31, 1998 24,590 76.40 25.00 - 115.00
Granted 30,000 10.00 10.00 - 10.00 $ 8.23
Cancelled (4,474) 39.10 25.00 - 68.70 ======
Expired (1,800) 115.00 115.00 - 115.00
------ -------- ------------------
Balance, December 31, 1999 48,316 $ 37.20 $ 10.00 - $115.00
====== ======== ==================
Plan options exercisable as of
December 31, 1999 18,316 $ 83.38
====== ========
F-22
64
Non-Plan Grants
- ---------------
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 five 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, 1996 40,192 $ 53.60 $31.30 - $ 65.00
Granted 54,500 103.30 90.00 - 110.00 $49.83
--------- -------- ---------------- ======
Balance, December 31, 1997
and 1998* 94,692 82.10 31.30 - 110.00
Granted 141,700 9.38 9.38 - 9.38 $ 7.22
Cancelled (90,192) 82.60 31.25 - 110.00 ======
--------- -------- ----------------
Balance, December 31, 1999 146,200 $ 10.42 $ 9.38 - $100.00
======= ======== ================
Non plan options and warrants
exercisable as of
December 31, 1999 4,500 $ 95.56
========= ========
*No activity during 1998.
The following table summarizes information for options currently outstanding as
of December 31, 1999 for all Plan and Non-Plan options.
Options and
Options and Warrants Outstanding Warrants Exercisable
---------------------------------------------------- --------------------------
Weighted Weighted Weighted
Average Average Average
Range of Remaining Exercise Exercise
Exercise Price Number Contractual Life Price Number Price
-------------- ------ ---------------- ----- ------ -----
$ 9.38 - $ 10.00 171,700 9.8 $ 9.49 -- $ --
25.00 - 53.00 4,096 4.3 41.47 4,096 41.47
65.00 - 85.00 5,720 6.2 77.23 5,720 77.23
90.00 - 110.00 13,000 7.0 101.30 13,000 101.30
------- -------- ------ -------
194,516 $ 17.07 22,816 $ 85.78
======= ======== ====== =======
F-23
65
All options canceled and reissued are subject to the criteria of the FASB
Exposure Draft titled "Accounting for Certain Transactions Involving Stock
Compensation - an Interpretation of APB Opinion No. 25" ("APB 25
Interpretation"). In 1999, 33,500 options were canceled and reissued at market
price. On July 1, 2000 (the expected effective date of the Exposure Draft),
these options will be accounted for as a variable option grant based on the
market price on July 1, 2000. These options will be marked-to-market with gains
and losses recorded in income for each reporting period subsequent to July 1,
2000 to the extent there are increases in the Company's stock price above the
market rate value of the stock on July 1, 2000.
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 loss and loss
per share ("LPS") would have been the following pro forma amounts (in thousands,
except per share data):
1999 1998 1997
-------- -------- -------
Net loss, attributable
to common stockholders As reported $(41,841) $(24,536) $(2,209)
Pro forma (42,376) (25,978) (6,764)
Basic and Diluted LPS As reported $ (28.37) $ (29.25) $ (2.99)
Pro forma (29.76) (30.80) (9.27)
Due to the requirements of Statement No. 123, the calculated compensation
expense in 1999, 1998 and 1997 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 since 1996.
1999 1998 1997
---- ---- ----
Weighted average remaining life 5 years 5 years 4.9 years
Risk-free interest rate 6.0% 5.3% 5.7% to 6.5%
Expected dividend yield 0% 0% 0%
Expected lives 5 years 5 years 3 to 5 years
Expected volatility 113.2% 87.5% 54.3%
14. OIL AND GAS PRODUCING ACTIVITIES:
---------------------------------
Major Customers
- ---------------
Sales to the following Companies represented 10% or more of the Company's
revenues (in thousands):
1999 1998 1997
---- ---- ----
Customer A $4,858 $ -- $ --
Customer B -- 10,370 12,320
Customer C -- -- 3,086
F-24
66
Cost Incurred in Oil and Gas Producing Activities (in thousands):
1999 1998 1997
------ ------- -------
Unproved property acquisition cost $ -- $ 303 $12,543
Proved property acquisition cost -- 105 56,989
Development cost 3,512 37,709 28,563
Exploration cost 155 153 61
------ ------- -------
Total $3,667 $38,270 $98,156
====== ======= =======
Net Capital Costs
- -----------------
Net capitalized costs related to the Company's oil and gas producing activities
are summarized as follows (in thousands).
1999 1998 1997
--------- --------- ---------
Unproved properties $ 4,410 $ 14,585 $ 13,806
Proved properties 160,889 161,472 127,500
Gas transportation facilities 4,918 4,481 2,523
--------- --------- ---------
Total 170,217 180,538 143,829
Accumulated depletion, depreciation and
amortization (27,805) (21,433) (10,009)
--------- --------- ---------
Total $ 142,412 $ 159,105 $ 133,820
========= ========= =========
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-25
67
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):
1999 1998 1997
----------- --------- ---------
Future cash inflows $ 1,127,531 $ 183,642 $ 694,065
Future production costs (259,022) (88,870) (251,434)
Future development costs (189,297) -- (232,087)
Future income tax provision (188,630) -- (33,394)
----------- --------- ---------
Future net cash flows 490,582 94,772 177,150
Less effect of 10% discount factor (292,270) (40,659) (98,528)
----------- --------- ---------
Standardized measure of discounted
future net cash flows $ 198,312 $ 54,113 $ 78,622
=========== ========= =========
The principal sources of changes in the standardized measure of discounted
future net cash flows are as follows for the years ended December 31, 1999, 1998
and 1997 (in thousands):
1999 1998 1997
--------- --------- --------
Standardized measure, beginning of year $ 54,113 $ 78,622 $ 52,983
Purchase of reserves in place -- 76 45,747
Sales of reserves in place (15,548) -- --
Sales of oil and gas produced, net of
production costs (9,047) (12,462) (13,019)
Net change in prices, net production cost 123,905 (96,051) (42,277)
Extensions, discoveries and improved
recovery, net -- 7,910 12,922
Revisions of previous quantity estimates 349,080 (58,104) 12,351
Change in future development costs (111,348) 232,087 9,557
Net change in income taxes (55,855) 15,200 3,706
Accretion of discount 5,411 9,384 7,190
Changes in production rates and other (142,399) (122,549) (10,538)
--------- --------- --------
Standardized measure, end of year $ 198,312 $ 54,113 $ 78,622
========= ========= ========
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-26
68
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, 1999, the Company used prices of $21.56 per Bbl
and $1.83 per Mcf which is reflective of the market price. Prices used by the
Company in 1998 were $7.60 per Bbl and $2.34 per Mcf.
Presented below is a summary of the changes in estimated proved reserves of the
Company, all of which are located in the United States, for the years ended
December 31, 1999, 1998 and 1997:
1999 1998 1997
----------------------- ------------------------ ------------------------
Oil (MBbl) Gas (MMcf) Oil (MBbl) Gas (MMcf) Oil (MBbl) Gas (MMcf)
---------- ---------- ---------- ---------- ---------- ----------
Proved reserves, beginning of year 18,602 18,063 37,135 75,483 7,312 10,188
Purchase of reserves in place -- -- 21 14 15,071 26,387
Sales of reserves in place (2,487) (3,100) -- -- -- --
Extensions and discoveries -- -- -- -- 12,836 34,744
Improved recoveries -- -- 3,145 2,814 1,723 (1,870)
Production (1,165) (2,901) (1,501) (3,006) (855) (1,637)
Revisions of previous estimates 32,179 48,873 (20,198) (57,242) 1,048 7,671
------- ------- ------- ------- ------- -------
Proved reserves, end of year 47,129 60,935 18,602 18,063 37,135 75,483
======= ======= ======= ======= ======= =======
Proved developed reserves,
end of year 16,634 15,476 18,394 18,030 12,980 15,224
======= ======= ======= ======= ======= =======
15. QUARTERLY EARNINGS (UNAUDITED):
Summarized unaudited quarterly financial data for 1999 and 1998 is as follows
(in thousands, except per share data):
Quarter Ended
---------------------------------------------------
March 31, June 30, September 30, December 31,
1999 1999 1999 1999
--------- -------- ------------- ------------
Revenues $ 4,034 $ 4,381 $ 4,359 $ 3,625
Operating loss (1,298) (634) (1,678) (516)
Net loss before extraordinary item (6,016) (4,622) (6,929) (18,750)
Net loss (6,016) (4,622) (7,485) (18,750)
Basic and diluted loss per share
before extraordinary item (7.35) (5.76) (6.59) (15.92)
Basic and diluted earnings (loss)
per share (7.35) (5.76) (7.11) (15.92)
F-27
69
Quarter Ended
----------------------------------------------------
March 31, June 30, September 30, December 31,
1998 1998 1998 1998
--------- -------- ------------- ------------
Revenues $ 5,277 $ 5,199 $ 5,395 $ 5,407
Operating income (loss) (30) 295 (255) (3,133)
Net loss (3,870) (2,348) (4,224) (13,010)
Basic and diluted loss per share (4.93) (3.14) (5.34) (15.88)
F-28
70
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
December 14, 1999 (filed as Exhibit 3.1 to Inland's Current Report on
Form 8-K dated September 21, 1999, and incorporated herein by
reference).
3.2 By-Laws of Inland (filed as Exhibit 3.2 to Inland's Registration
Statement on Form S-18, Registration No. 33-11870-F, and incorporated
herein by reference).
3.2.1 Amendment to Article IV, Section 1 of the Bylaws of Inland adopted
February 23, 1993 (filed as Exhibit 3.2.1 to Inland's Annual Report on
Form 10-K for the year ended December 31, 1992, and incorporated herein
by reference).
3.2.2 Amendment to the Bylaws of Inland adopted April 8, 1994 (filed as
Exhibit 3.2.2 to Inland's Registration Statement on Form S-4,
Registration No. 33-80392, and incorporated herein by reference).
3.2.3 Amendment to the Bylaws of Inland adopted April 27, 1994 (filed as
Exhibit 3.2.3 to Inland's Registration Statement on Form S-4,
Registration No. 33-80392, and incorporated herein by reference).
71
Item
Number Description
- ------ -----------
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 (filed as Exhibit 4.1.2 to Inland's
Annual Report on Form 10-K for the year ended December 31, 1998, and
incorporated herein by reference).
4.1.3 First Amendment to Amended and Restated Credit Agreement dated as of
March 5, 1999 amending Exhibit 4.1.2 (filed as Exhibit 4.1.3 to
Inland's Annual Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).
4.1.4 Second Amended and Restated Credit Agreement dated September 15, 1999,
but effective as of September 21, 1999, amending and restating Exhibit
4.1 (without exhibits or schedules) (filed as Exhibit 4.1 to Inland's
Current Report on Form 8-K dated September 21, 1999, and incorporated
herein by reference).
4.2 Credit Agreement dated September 23, 1997, among IPC, Inland, Trust
Company of the West, and TCW Asset Management Company, in the
capacities described therein (filed as Exhibit 4.2 to Inland's Current
Report on Form 8-K dated September 23, 1997, and incorporated herein by
reference).
4.2.1 Second Amendment to Credit Agreement entered into as of April 22, 1998,
amending Exhibit 4.2 (filed as Exhibit 4.2.1 to Inland's Quarterly
Report on Form 10-Q for the quarter ended March 31, 1998, and
incorporated herein by reference).
4.2.2 Amended and Restated Credit Agreement dated as of September 11, 1998,
amending and restating Exhibit 4.2 (filed as Exhibit 4.2.2 to Inland's
Annual Report on Form 10-K for the year ended December 31, 1998, and
incorporated herein by reference).
4.2.3 First Amendment to Amended and Restated Credit Agreement dated as of
March 5, 1999, amending Exhibit 4.2.2 (filed as Exhibit 4.2.3 to
Inland's Annual Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).
4.2.4 Exchange Agreement dated as of September 21, 1999 by and between
Inland, IPC, Refining, Trust Company of the West, a California trust
72
Item
Number Description
- ------ -----------
company, as Sub-Custodian for Mellon Bank for the benefit of Account
No. CPFF 873-3032, Inland Holdings LLC, TCW Portfolio No. 1555 DR V
Sub-Custody Partnership, L.P. and Joint Energy Development Investments
II Limited Partnership (without exhibits or schedules), terminating
Exhibits 4.2 and 4.3, as previously amended, and Exhibits 4.4, 4.5,
10.10 and 10.11 (filed as Exhibit 10.1 to Inland's Current Report on
Form 8-K dated September 21, 1999, and incorporated herein by
reference).
4.3 Intercreditor Agreement dated September 23, 1997, between IPC, TCW
Asset Management Company, Trust Company of the West and ING (U.S.)
Capital Corporation (filed as Exhibit 4.3 to Inland's Current Report on
Form 8-K dated September 23, 1997, and incorporated herein by
reference).
4.3.1 Third Amendment to Intercreditor Agreement entered into as of April 22,
1998, amending Exhibit 4.3 (filed as Exhibit 4.3.1 to Inland's
Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, and
incorporated herein by reference).
4.3.2 Amended and Restated Intercreditor Agreement dated as of September 11,
1998, amending and restating Exhibit 4.3 (filed as Exhibit 4.3.2 to
Inland's Annual Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).
4.3.3 First Amendment to Amended and Restated Intercreditor Agreement dated
as of March 5, 1999, amending Exhibit 4.3.2 (filed as Exhibit 4.3.3 to
Inland's Annual Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).
4.4 Warrant Agreement by and between Inland and TCW Portfolio No. 1555 DR V
Sub-Custody Partnership, L.P. dated September 23, 1997 (filed as
Exhibit 4.4 to Inland's Current Report on Form 8-K dated September 23,
1997, and incorporated herein by reference).
4.5 Warrant issued by Inland pursuant to the Warrant Agreement, dated
September 23, 1997, representing the right to purchase 100,000 shares
of Inland's Common Stock (filed as Exhibit 4.5 to Inland's Current
Report on Form 8-K dated September 23, 1997, and incorporated herein by
reference).
10.1 1988 Option Plan of Inland Gold and Silver Corp. (filed as Exhibit
10(15) to Inland's Annual Report on Form 10-K for the year ended
December 31, 1988, and incorporated herein by reference).
10.1.1 Amended 1988 Option Plan of Inland Gold and Silver Corp. (filed as
Exhibit 10.10.1 to Inland's Annual Report on Form 10-K for the year
ended December 31, 1992, and incorporated herein by reference).
10.1.2 Amended 1988 Option Plan of Inland, as amended through August 29, 1994
(including amendments increasing the number of shares to
73
Item
Number Description
- ------ -----------
212,800 and changing "formula award") (filed as Exhibit 10.1.2 to
Inland's Annual Report on Form 10- KSB for the year ended December 31,
1994, and incorporated herein by reference).
10.1.3 "Automatic Adjustment to Number of Shares Covered by Amended 1988
Option Plan" executed effective June 3, 1996 (filed as Exhibit 10.1 to
Inland's Quarterly Report on Form 10-QSB for the quarter ended June 30,
1996, and incorporated herein by reference).
10.2 Letter agreement dated October 30, 1996 between Inland and Johnson
Water District (filed as Exhibit 10.41 to Inland's Annual Report on
Form 10-KSB for the year ended December 31, 1996, and incorporated
herein by reference).
10.3 Interest Rate Cap Agreement dated April 30, 1998 between IPC and Enron
Capital and Trade Resources Corp. (filed as Exhibit 10.4 to Inland's
Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, and
incorporated herein by reference).
10.4 Farmout Agreement between Inland and Smith Management LLC dated
effective as of June 1, 1998 (filed as Exhibit 10.1 to Inland's Current
Report on Form 8-K dated June 1, 1998, and incorporated herein by
reference).
10.5 Warrant Agreement dated as of March 5, 1999 between Inland Resources
Inc. and TCW Portfolio No. 1555 DR V Sub-Custody Partnership, L.P.
(filed as Exhibit 10.20 to Inland's Annual Report on Form 10-K for the
year ended December 31, 1998, and incorporated herein by reference).
10.6 Warrant Certificate dated March 5, 1999 between Inland and TCW
Portfolio No. 1555 DR V Sub-Custody Partnership, L.P. representing
5,852 shares (filed as Exhibit 10.21 to Inland's Annual Report on Form
10-K for the year ended December 31, 1998, and incorporated herein by
reference).
*10.7 Employment Agreement between Inland and Bill I. Pennington dated
effective as of October 1, 1999.
*10.8 Employment Agreement between Inland and Michael J. Stevens dated
effective as of October 1, 1999.
*10.9 Stock Option Agreement between Inland and Bill I. Pennington dated
effective as of October 1, 1999 representing 87,500 post-split shares
of Common Stock.
*10.10 Stock Option Agreement between Inland and Michael J. Stevens dated
October 1, 1999 representing 29,200 post-split shares of Common Stock.
74
Item
Number Description
- ------ -----------
10.11 Shareholders Agreement dated as of September 21, 1999 between Inland,
Holdings, Fund V, JEDI and Pengo Securities Corp., Smith Energy
Partnership, Randall D. Smith, Jeffrey A. Smith, Barbara Stovall Smith,
John W. Adams and Arthur J. Pasmas (collectively, the "Smith Group")
(filed as Exhibit 10.2 to Inland's Current Report on Form 8-K dated
September 21, 1999, and incorporated herein by reference).
10.12 Registration Rights Agreement dated as of September 21, 1999 between
Inland, Holdings, Portfolio, JEDI and the Smith Group filed as Exhibit
10.3 to Inland's Current Report on Form 8-K dated September 21, 1999,
and incorporated herein by reference).
*10.13 Severance Agreement between Inland and John E. Dyer dated November 18,
1999.
*10.14 Employment Agreement between Inland and William T. War dated effective
as of October 1, 1999.
*10.15 Stock Option Agreement between Inland and William T. War dated October
1, 1999 representing 25,000 post-split shares of Common Stock.
*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