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, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period ___ to ___
Commission File Number 0-16487
---------------
INLAND RESOURCES INC.
(Exact Name of Registrant as Specified in its Charter)
WASHINGTON 91-1307042
(State or Other Jurisdiction of (IRS Employer
Incorporation or Organization) Identification Number)
410 17th Street
Suite 700
Denver, Colorado
(303) 893-0102 80202
(Address of Principal Executive Offices) (Zip Code)
Issuer's telephone number, including area code: (303) 893-0102
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act: Common Stock, par
value $.001 per share
Check whether the issuer (1) filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12
months (or for such shorter period that the issuer was required to file such
reports), and (2) has been subject to such filing requirements for the past 90
days. YES X NO ___
Check if there is no disclosure of delinquent filers in response to Item
405 of Regulation S-K contained herein, and none will be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
At March 13, 2001, the registrant had outstanding 2,897,732 shares of par
value $.001 common stock. The aggregate value on such date of the common stock
of the Registrant held by non-affiliates was an estimated $700,000.
DOCUMENTS INCORPORATED BY REFERENCE
None
TABLE OF CONTENTS
PART I
Items 1. & 2. Business and Properties....................................................................... 2
Item 3. Legal Proceedings.............................................................................12
Item 4. Submission of Matters to a Vote of Security Holders...........................................12
PART II
Item 5. Market for Registrant's Common Stock and Related Stockholder Matters..........................13
Item 6. Selected Financial Data.......................................................................13
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.........15
Item 7A. Quantitative and Qualitative Disclosures About Market Risks...................................23
Item 8. Financial Statements and Supplementary Data...................................................24
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure..........24
PART III
Item 10. Directors and Executive Officers of the Registrant............................................25
Item 11. Executive Compensation........................................................................27
Item 12. Security Ownership of Certain Beneficial Owners and Management................................29
Item 13. Certain Relationships and Related Transactions................................................31
PART V
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K ..............................32
-i-
PART I
The following text is qualified in its entirety by reference to the more
detailed information and consolidated financial statements (including the notes
thereto) appearing elsewhere in this Annual Report on Form 10-K. Unless the
context otherwise requires, references to "Inland" shall mean Inland Resources
Inc., a Washington corporation, and references to the "Company" or its
operations shall mean Inland and its consolidated subsidiary, Inland Production
Company ("IPC"), a Texas corporation. For definitions of certain terms relating
to the oil and gas industry used in this section, see Items 1. and 2. "Business
and Properties - Certain Definitions."
All references to shares of Inland's common stock, par value $.001 per
share ("Common Stock"), and share prices in this Form 10-K have been adjusted to
give effect to the 1-for-10 reverse stock split effected December 14, 1999.
ITEMS 1. & 2. BUSINESS AND PROPERTIES
OVERVIEW
Inland Resources Inc. is an independent energy company engaged in the
acquisition, development, and enhancement of oil and gas properties in the
western United States. All of the Company's oil and gas reserves are located in
the Monument Butte Field (the "Field") within the Uinta Basin of northeastern
Utah. Until January 31, 2000, the Company was also engaged in the refining of
crude oil and wholesale marketing of refined petroleum products, including
various grades of gasoline, kerosene, diesel fuel, waxes and asphalt through a
former subsidiary, Inland Refining, Inc. ("Refining"). Inland conducts its
operations through its subsidiary, IPC. In 2001, IPC drilled 45 gross (35 net)
developmental wells. At December 31, 2001, the Company's estimated net proved
reserves totaled 68.3 MBOE, having a pre-tax present value discounted at 10%,
using constant prices, of $193 million. The constant prices used at December 31,
2001 were calculated on the basis of market prices in effect on that date and
were approximately $16.84 per barrel of oil and $2.23 per Mcf of gas.
The Company intends to pursue a strategy of development drilling, focusing
on enhancing operating efficiency and reducing capital costs through the
concentration of assets in selected geographic areas. Currently, the Company's
operations are focused on the full development of the Field, where the Company
operates 707 gross (523 net) oil wells, including 228 gross (184 net) injection
wells. Inland pioneered the secondary water flood recovery processes used in the
Field and currently operates 23 approved secondary recovery projects in the
area. Budgeted development expenditures for 2002 in the Field are estimated
to be $10-$12 million net to the Company.
Effective January 31, 2000, Inland sold all of its capital stock in
Refining to Silver Eagle Refining, Inc. ("Silver Eagle") for $500,000 and the
assumption of various refinery liabilities and obligations. Refining owned the
Wood Cross Refinery in Woods Cross, Utah and the Roosevelt Refinery in
Roosevelt, Utah (which was non-operating at the time of sale). Prior to the
sale, the existing cash, inventory, accounts receivable and a note receivable
were transferred to Inland Working Capital Corp ("IWCC"). IWCC agreed to satisfy
various accounts payable and liabilities not assumed as part of the purchase
price. As a result of the sale of Refining to Silver Eagle, the Company is no
longer engaged in the business of refining crude oil and marketing refined
petroleum products. IWCC subsidiary was formally dissolved in July of 2001.
Change of Control and Recapitalization.
In January 2002, the Company announced that it had hired Lehman Brothers
Inc. and Petroleum Place Energy Advisors to advise the Company regarding its
review of strategic alternatives, which may include a potential sale or merger
of the Company. The Company is engaged in various levels of negotiations
regarding such a transaction.
1999 Exchange Agreement - On September 21, 1999, the Company entered into
an Exchange Agreement (the "Exchange Agreement") with Trust Company of the West,
as Sub-Custodian for Mellon Bank for the benefit of Account No. CPFF 873-3032
("Fund V"), TCW Portfolio No. 1555 DR V Sub-Custody Partnership, L.P.
("Portfolio") (Portfolio and Fund V collectively being referred to as "TCW"),
Inland Holdings LLC ("Holdings") and Joint Energy Development
2
Investments II Limited Partnership ("JEDI"). Pursuant to the Exchange Agreement,
Fund V agreed to exchange $75 million in principal amount of subordinated
indebtedness of IPC plus accrued interest of $5.7 million and Portfolio agreed
to exchange warrants to purchase 15,852 shares of Common Stock for the following
securities of Inland issued to Holdings, whose members are Fund V and Portfolio:
(1) 10,757,747 shares of Series D Preferred Stock, (2) 5,882,901 shares of
Series Z Preferred Stock, which automatically converted into 588,291 shares of
Common Stock on December 14, 1999, and (3) 1,164,295 shares of Common Stock; and
JEDI agreed to exchange the 100,000 shares of Inland's Series C Cumulative
Convertible Preferred Stock ("Series C Preferred Stock") owned by JEDI, together
with $2.2 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.
March 2001 Transaction - On March 20, 2001, Hampton Investments LLC
("Hampton"), an affiliate of Smith Management LLC, ("Smith") purchased from JEDI
the 121,973 shares of Series E Preferred Stock and 292,098 shares of Common
Stock acquired by JEDI in the Exchange Agreement. Following closing of the
Exchange Agreement and the purchase by Hampton of JEDI's shares, Holdings owned
1,752,586 shares of Common Stock, representing approximately 60.5% of the
outstanding shares of Common Stock as of March 20, 2001. Hampton owned 292,098
shares of Common Stock, representing approximately 10.1% of the outstanding
shares of Common Stock as of March 20, 2001. TCW Asset Management Company has
the power to vote and dispose of the securities owned by Holdings.
August 2001 Transaction - On August 2, 2001, the Company closed two
subordinated debt transactions totaling $10 million in aggregate with SOLVation
Inc. ("SOLVation"), a company affiliated with Smith, and entered into other
restructuring transactions as described below. The first of the two debt
transactions with SOLVation was the issuance of a $5 million unsecured senior
subordinated note to SOLVation due July 1, 2007. The interest rate is 11% per
annum compounded quarterly. The interest payment is payable in arrears in cash
subject to the approval from the senior bank group and accumulates if not paid
in cash. The Company is not required to make any principal payments prior to the
July 1, 2007 maturity date. However, the Company is required to make payments of
principal and interest in the same amounts as any principal payment or interest
payments on the TCW Subordinated Note (described below). Prior to the July 1,
2007 maturity date, subject to the bank subordination agreement, the Company may
prepay the senior subordinated note in whole or in part with no penalty.
The Company also issued a second $5 million unsecured junior subordinated
note to SOLVation. The interest rate is 11% per annum compounded quarterly. The
maturity date is the earlier of (i) 120 days after payment in full of the TCW
subordinated debt or (ii) March 31, 2010. Interest is payable in arrears in cash
subject to the approval from the senior bank group and accumulates if not paid
in cash. The Company is not required to make any principal payments prior to the
March 31, 2010 maturity date. Prior to the March 31, 2010 maturity date, subject
to both bank and subordination agreements, the Company may prepay the junior
subordinated note in whole or in part with no penalty. A portion of the proceeds
from the senior and junior subordinated notes was used to fund a $2 million
payment to Holdings and other Company working capital needs.
In conjunction with the issuance of the two subordinated notes to
SOLVation, the Series D Preferred and Series E Preferred stock held by Holdings
were exchanged for an unsecured subordinated note due September 30, 2009 and $2
million in cash from the Company. Holdings had previously purchased the Series E
Preferred Stock from Hampton. The TCW Subordinated Note amount was for
$98,968,964 that represented the face value plus accrued dividends of the Series
D Preferred Stock as of August 2, 2001. The interest rate on this debt is 11%
per annum compounded quarterly. Interest is payable in arrears in cash subject
to the approval from the senior bank group and accumulates if not paid in cash.
Interest payments will be made quarterly, commencing on the earlier of September
30, 2005 or the end of the first calendar quarter after the senior bank debt has
been reduced to $40 million or less, subject to both bank and senior
subordination agreements. Beginning the earlier of two years prior to the
maturity date or the first December 30 after the repayment in full of the senior
bank debt, subject to both bank and senior subordination agreements, the Company
will make equal annual principal payments of one third of the aggregate
principal amount of the TCW Subordinated Note. Any unpaid principal or interest
amounts are due in full on the September 30, 2009 maturity date. Prior to the
September 30, 2009 maturity date, subject to both bank and senior subordination
agreements, the Company may prepay the TCW Subordinated Note in whole
3
or in part with no penalty. As a result of the exchange, the Company retired
both the Series D and Series E Preferred stock. Due to the related party nature
of this transaction, the difference between the aggregate subordinated note
balance and $2 million cash paid to Holdings and the aggregate liquidation value
of the Series D and E preferred stock plus accrued dividends of $13,083,000 was
recorded as an increase to additional paid-in capital.
As part of this restructuring, Holdings also sold to Hampton, 1,455,390
shares of their common stock in the Company. Consequently, Hampton now controls
approximately 80% of the issued and outstanding shares of the Company. Holdings
also terminated any existing option rights to the Company's common stock, and
relinquished the right to elect four persons to the Company's Board of Directors
to Hampton. However, Holdings has the right to nominate one person to the
Company's Board. Remaining board members will be nominated by the Company's
shareholders. As long as Hampton or its affiliates own at least a majority of
the common stock of the Company, Hampton has agreed with Holdings that Hampton
will have the right to appoint at least two members to the board.
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
707 wells, or 98% of the wells in which the Company has an interest. Certain
disclosures with respect to production, exploration and transportation
activities for Inland's fiscal years 1999, 2000 and 2001 are set forth in pages
F-24 and F-25 of this Annual Report.
Oil and Gas Reserves. The following table sets forth the Company's
estimated quantities of proved oil and gas reserves and the estimated future net
revenues (by reserve categories) without consideration of indirect costs such as
interest, administrative expenses or income taxes. These estimates were prepared
by the Company, with certain portions having been reviewed by Ryder Scott
Company, L.P., an independent reservoir engineer. The review by Ryder Scott
Company, L.P. consisted of properties which comprised approximately 80% of the
total present worth of future net revenue discounted at 10% as of December 31,
2001. The total proved net reserves estimated by the Company were within 10% of
those reviewed and estimated by Ryder Scott Company, L.P.; 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-24 through F-27 of
this Annual Report.
As of December 31, 2001
---------------------------------------------------------------------
Proved Proved Total
Developed Undeveloped Proved
--------------- ---------------------- ------------
(dollars in thousands)
Net Proved Reserves
Oil (MBls) 18,409 36,162 54,571
Gas (MMcf) 20,682 61,825 82,507
MBOE (6Mcf per Bbl) 21,856 46,466 68,322
Estimated Future Net Revenues(1) $182,495 $375,832 $558,327
Present Value of Future Net Revenues(2) $107,095 $85,999 $193,094
(1) Pre-tax and undiscounted.
(2) Pre-tax and discounted at 10%.
Future net revenues from reserves at December 31, 2001 were calculated on
the basis of market prices in effect on that date and were approximately $16.84
per barrel of oil and $2.23 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.
4
Petroleum engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact manner.
Estimates of economically recoverable oil and gas reserves and of future net
cash flows necessarily depend upon a number of variable factors and assumptions,
including the following:
o historical production from the area compared with production from other
producing areas;
o the assumed effects of regulations by governmental agencies;
o assumptions concerning future oil and gas prices; and
o assumptions concerning future operating costs, production taxes,
development costs and work over and remediation costs.
Because all reserve estimates are to some degree subjective, the quantities
of oil and gas that are ultimately recovered, the production and operating costs
incurred, the amount and timing of future development expenditures and future
oil and gas sales prices may differ materially from those assumed in estimating
reserves. Furthermore, different reserve engineers may make different estimates
of reserves and cash flows based on the same available data. Inland's actual
production, revenues and expenditures with respect to reserves will likely vary
from estimates, and the variances may be material.
No estimates of total proved net oil and gas reserves have been filed by
the Company with, or included in any report to, any United States authority or
agency pertaining to the Company's individual reserves since the beginning of
the Company's last fiscal year.
Production, Unit Prices and Costs. The following table sets forth certain
information regarding the production volumes of, average sale prices received
for, and average production costs for the sales of oil and gas by the Company.
See also, the Supplemental Oil and Gas Disclosures appearing on pages F-24
through F-27 of this Annual Report.
Year Ended December 31,
----------------------------------------------
2001 2000 1999
------ ------ ------
Net Production:
Oil (MBls)............................... 1,212 1,072 1,165
Gas (MMcf) (1)........................... 2,423 2,289 2,901
Total (MBOE)......................... 1,616 1,454 1,649
Average Sale Price(2):
Oil (per Bbl)............................ $22.31 $26.71 $14.38
Gas (per Mcf)(3)......................... $ 3.05 $ 2.60 $1.56
Average Production Cost:
($/BOE)(4)........................... $ 5.78 $ 5.23 $ 4.34
5
(1) Net of 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 during 2001, 2000 and 1999 in which the Company had an
interest.
2001 2000 1999
--------------------- ------------------------ ----------------------
Gross Net Gross Net Gross Net
------- ------- ------- ------- ------- -------
Development wells:
Oil(1) ......... 44 34.5 43(2) 34.5(2) 8 7.5
Dry............. 1 .5 1 1 - -
------ ------ ------ ------ ------ ------
Total....... 45 35.0 44 35.5 8 7.5
====== ====== ====== ====== ====== ======
(1) All of the completed wells have multiple completions, including both
oil completions and gas completions. Consequently, pursuant to the rules of
the Securities and Exchange Commission, each well is classified as an oil
well.
(2) Three of the wells (gross and net) were completed as water injection
wells.
The information contained in the foregoing table should not be considered
indicative of future drilling performance nor should it be assumed that there is
any necessary correlation between the number of productive wells drilled and the
amount of oil and gas that may ultimately be recovered by the Company. The
Company does not anticipate any acquisitions of properties or major equipment at
this time.
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, 2001:
Wells(1)
----------------------------------------------------------------------------
Gross(2) Net(2)
---------------------------- ----------------------------------
Water Water
Location Oil(1) Injection Oil(1) Injection
- -------- --- --------- --- ---------
Utah(3) 494 231 377 184
(1) The Company is an operator of 707 gross wells (558 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, 2001.
(3) All of the Company's wells are located in the Field.
6
Acreage Data. The following table reflects the developed and undeveloped
acreage that the Company held as of December 31, 2001:
Developed Acreage Undeveloped Acreage(1)
------------------------ --------------------------
Gross Net Gross Net
Location Acres Acres Acres Acres
---------- ------- ------- ------- -------
Utah(2) 28,300 22,700 103,300 78,700
(1) Undeveloped acreage includes 56,600 gross (44,700 net) acres held by
production at December 31, 2001.
(2) All of the Company's acreage is located in the Field.
As of December 31, 2001, the undeveloped acreage not held by production
involves 241 leases with remaining terms of up to 7 years. Leases covering
approximately 1,341 net acres have expiration dates in 2002. The Company intends
to renew expiring leases in areas considered to have good development potential.
The Company also intends to continue paying delay rentals and minimum royalties
necessary to maintain these leases (an expense of approximately $76,000 net to
the Company in 2001). 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 and displace
oil, resulting in greater crude oil production. Inland currently operates 23
approved water flood units or areas. At December 31, 2001, the Company had 231
wells injecting an aggregate of 12,400 BWPD. During 2001, the Company installed
42 miles of water pipelines to handle low pressure water delivery and high
pressure water injection. The Company also converted 33 gross (26 net) oil wells
into injection wells. At December 31, 2001, the Company owned and operated 182
miles of water pipelines and seven water injection plants with an injection
capacity of 20,000 BWPD. Inland has experienced stabilized or increasing
production in many wells offsetting its water injection operations. Inland
intends to continue aggressively developing secondary recovery water flood
operations by extending infrastructure and initiating injection in 35 wells in
the Field during 2002.
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. As of the 2001 year end, the
Company produced approximately 14 MMcf of natural gas per day and sold
approximately 11 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
361 miles of pipelines and 2 compression facilities using 5 compressors and
2 dehydration units with a throughput capacity of 22.5 MMcf per day.
Delivery Commitments. The Company has no material delivery commitments
under contracts.
Markets for Oil and Gas. The availability of a ready market and the prices
obtained for the Company's oil and gas depend on many factors beyond the
Company's control, including the extent of domestic production and imports of
oil and gas, the proximity and capacity of natural gas pipelines and other
transportation facilities, fluctuating demands for oil and gas, the marketing of
competitive fuels, and the effects of governmental regulation of oil and gas
production and sales.
7
The crude oil produced from the Field is called Black Wax. The Black Wax
produced from the Field is primarily transported by truck and refined in Salt
Lake City at one of four large refineries operated by Big West, BP, Chevron and
Phillips. Transportation of large quantities of Black Wax by pipeline is not
currently feasible, and transportation by truck or rail to refineries in
California or Colorado is not economical. Black Wax is a valuable commodity
since it is low in sulfur content and can be distilled and cracked into high
margin petroleum products such as gasoline, diesel and jet fuel; however, it
does not blend well with other crude oil feedstocks in the refining process.
Since Black Wax has limited compatibility in blending, the demand for Black Wax
tends to become inelastic as the supply of Black Wax reaches the cracking and
blending capacity of the Salt Lake City refineries. The Company estimates the
existing refining capacity for Black Wax in Salt Lake City to be higher than
local production. The Company is aware of refinery modifications at the Big
West refinery that should further increase the demand for Black Wax.
The Company has various contracts to sell its Black Wax crude oil to the
Salt Lake City refiners. The pricing mechanism under each contract is directly
related to the average monthly settlement prices of certain futures contracts
quoted on the New York Mercantile Exchange index ("NYMEX"). The negative basis
differential between NYMEX and the Company's wellhead price averaged $3.59
during year 2001. From January 2002 and through December 2005, the Company has a
contract with Big West to sell up to 7,000 barrels of oil per day at NYMEX less
$3.00. The NYMEX price ranged from $19.40 to $29.69 during 2001 and was $19.40
for December 2001. The NYMEX price ranged from $25.54 to $34.26 during 2000.
During 2001 and 2000, the Company sold 56% and 59%, respectively, of its oil
production to BP. During 2001 and 2000, the Company sold 35% and 41%,
respectively, of its oil production to Chevron.
Periodically, the Company enters into commodity contracts to hedge or
otherwise reduce the impact of oil price fluctuations. The amortized cost and
the monthly settlement gain or losses are reported as adjustments to revenue in
the period in which the related oil is sold. Hedging activities do not affect
the actual sales price for the Company's crude oil. The Company is subject to
the creditworthiness of its counterparties since the contracts are not
collateralized. The Company entered into all of its hedging contracts with Enron
North America Corp. ("ENAC"). On December 2, 2001, ENAC filed for Chapter 11
bankruptcy. The ENAC bankruptcy caused a default on all of the Company's hedging
contracts from November 2001 through September 30, 2003. The Company recorded a
loss of $5.5 million to the statement of operations to reflect ineffectiveness
of the derivative contracts following the filing of Chapter 11 bankruptcy of
ENAC. On January 30, 2002, the Company terminated all of its hedging contracts
with ENAC and determined a potential bankruptcy claim against ENAC in excess of
$7.5 million.
The Company markets substantially all of its operated gas production. The
Company had contracts to sell 3,400 Mcf per day from January 2001 through
October 2001 at $4.70 per Mcf. The Company currently has contracts to sell 5,042
Mcf per day from November 2001 through March 2002 at $2.89 per Mcf and 5,042 Mcf
per day from April 2002 through October of 2002 at $2.28 per Mcf. 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 $1.13
per Mcf to $10.21 per Mcf during 2001 and from $2.52 to $7.18 per Mcf during
2000, and was $2.40 per Mcf for December 2001. All spot market sales during 2001
and 2000 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.
On March 22, 2002, Questar Pipeline Company ("QPC") curtailed all gas
producers in the Monument Butte Field, including Inland, for not meeting certain
QPC specifications. After curtailment, Inland is producing and transporting
approximately 50% of its total gas capacity. The Company is in the process of
installing a gas liquid plant in the Field that would bring all of its gas up to
QPC's pipeline specifications. The gas liquid plant will be operational in
approximately 60 days. The Company believes that the current gas curtailment is
not significant to the Company's operations.
Regulation of Exploration and Production. The Company's oil and gas
exploration, production and related operations are subject to extensive rules
and regulations promulgated by federal and state agencies. Failure to comply
with such rules and regulations can result in substantial penalties. The
regulatory burden on the oil and gas industry increases the Company's cost of
doing business and affects its profitability. Because such rules and regulations
are frequently amended or interpreted differently by regulatory agencies, Inland
is unable to accurately predict the future cost or impact of complying with such
laws.
The Company's oil and gas exploration and production operations are
affected by state and federal regulation of oil and gas production, federal
regulation of gas sold in interstate and intrastate commerce, state and federal
regulations governing environmental quality and pollution control, state limits
on allowable rates of production by a well or proration unit and the amount of
oil and gas available for sale, state and federal regulations governing the
availability of adequate pipeline and other transportation and processing
facilities, and state and federal regulation governing the marketing of
competitive fuels. For example, a productive gas well may be "shut-in" because
of an over-supply of gas or lack of an available gas pipeline in the areas in
which Inland may conduct operations. State and federal regulations generally are
intended to prevent waste of oil and gas, protect rights to produce oil and gas
between owners in a common reservoir, control the amount of oil and gas produced
by assigning allowable rates of production and control contamination of the
environment. Pipelines are subject to the jurisdiction of various federal, state
and local agencies.
8
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 2002.
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 2001, and are expected to
continue to be significant in 2002:
Regulated Access to Public Lands. A substantial portion of the Company's
operations occur on federal leaseholds. During 1996, the Vernal, Utah office of
the Bureau of Land Management ("BLM") undertook the preparation of an
Environmental Assessment ("EA") to evaluate the environmental impacts of the
Company's proposed development plan within the Field. The Agency's Record of
Decision ("ROD") on the EA, which was issued on February 3, 1997, identified
surface stipulations and mitigation measures that the Company must implement to
protect various surface resources, including protected and sensitive plant and
wildlife species, archaeological and paleontological resources, soils and
watersheds. The Company has proven itself successful at continuing to develop
oil and gas resources in the Field while complying with the surface stipulations
and mitigation measures contained in the 1997 ROD. In 2002, the BLM will begin
evaluating the environmental impacts of 600 to 900 new wells proposed for
development by the Company over a five to ten year period beginning in 2004. An
Environmental Impact Statement ("EIS") will be prepared by BLM in 2002, and a
final ROD on the EIS should be issued in mid-2003.
On February 16, 1999, the United States Fish and Wildlife Service ("USFWS")
issued a Proposed Rule to list the mountain plover, a small ground-nesting bird,
as "threatened" under the Federal Endangered Species Act. The Field contains the
only known breeding population of mountain plover in Utah. The USFWS had not
issued a Final Rule to list the mountain plover as of December 31, 2001,
however, the USFWS and BLM are likely to implement additional restrictive
surface stipulations in the Field once a Final Rule to list the mountain plover
as threatened is issued. Based on preliminary discussions with the USFWS and
BLM, the Company believes it will be able to comply with any additional surface
stipulations without causing a material impact on its future drilling plans in
the Field.
Clean Water and Oil Pollution Regulatory Programs. The federal Clean Water
Act ("CWA") regulates discharges of pollutants to surface waters. The discharge
of crude oil and petroleum products to surface waters also is precluded by the
Oil Pollution Act ("OPA"). The Company's operations are inherently subject to
accidental spills and releases of crude oil and drilling fluids that may give
rise to liability to governmental entities or private parties under federal,
state or local environmental laws, as well as under common law. Minor spills
occur from time to time during the normal course of the Company's production
operations. The Company maintains spill prevention control and countermeasure
plans ("SPCC plans") for facilities that store large quantities of crude oil or
petroleum products to prevent the accidental discharge of these potential
pollutants to surface waters. As of December 31, 2001, 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.
9
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
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. The Company currently obtains construction and operating permits for
its compressor engines, and is not presently aware of any potential adverse
claims in this regard.
Waste Disposal Regulatory Programs. The Company's operations generate and
result in the transportation and disposal of large quantities of produced water
and other wastes classified by EPA as "nonhazardous solid wastes". The EPA is
currently considering the adoption of stricter disposal and clean-up standards
for nonhazardous solid wastes under the Resource Conservation and Recovery Act
("RCRA"). In some instances, EPA has already required the clean up of certain
nonhazardous solid waste reclamation and disposal sites under standards similar
to those typically found only for hazardous waste disposal sites. It also is
possible that wastes that are currently classified as "nonhazardous" by EPA,
including some wastes generated during the Company's drilling and production
operations, may in the future be reclassified as "hazardous wastes". Because
hazardous wastes require much more rigorous and costly treatment, storage,
transportation and disposal requirements, such changes in the interpretation and
enforcement of the current waste disposal regulations would result in
significant increases in waste disposal expenditures by the Company.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
who are considered to have caused or contributed to the release or threatened
release of a "hazardous substance" into the environment. These persons include
the current or past owner or operator of the disposal site or sites where the
release occurred and companies that transported disposed or arranged for the
disposal of the hazardous substances under CERCLA. These persons may be subject
to joint and several 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 well blowouts, cratering, explosions,
uncontrollable flows of oil, gas or well fluids, fires, formations with abnormal
pressures, pollution, releases of toxic gas and other environmental hazards and
risks. Any of these operating hazards could result in substantial losses to the
Company. In accordance with customary industry practices, the Company maintains
insurance against some, but not all, of these risks and losses. The Company is
also required under various operating agreements to maintain certain insurance
coverage on existing wells and all new wells drilled during drilling operations,
and name others as additional insureds under such insurance coverage. The
occurrence of an event that is not fully covered by insurance could have an
adverse impact on the Company's financial condition and results of operations.
10
Competition. Many companies and individuals are engaged in the oil and gas
business. Inland is faced with strong competition from major oil and gas
companies and other independent operators attempting to acquire prospective oil
and gas leases, producing oil and gas properties and other mineral interests.
Some competitors are very large, well-established companies with substantial
capabilities and long earnings records. Inland may be at a disadvantage in
acquiring oil and gas prospects since it must compete with individuals and
companies that have greater financial resources and larger technical staffs than
Inland.
With respect to Black Wax production, additional competitive pressure
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 "Overview", Inland sold its refinery
operations effective as of January 31, 2000 by selling all of its stock in
Refining to Silver Eagle. The Company's refining operations were conducted
through its wholly-owned subsidiary, Refining, at the Woods Cross Refinery, a
hydroskimming plant with an overall crude capacity of approximately 10,000 BPD.
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 to reflect the refining operations as discontinued operations.
Consequently, separate segment information and a separate discussion of refinery
operations, are not included in this Annual Report.
Environmental Regulations Associated with Discontinued Refining Operations.
As of December 31, 2001, the Company was not aware of any remaining liabilities
associated with any of its previously held refining properties. There remains,
however, the possibility that federal, state, or local governmental agencies, or
private parties could attempt to join the Company in clean-up efforts associated
with previously held refining properties should they be required.
EMPLOYEES
At February 19, 2002, the Company had 108 employees, consisting of three
executive officers, 20 technical, clerical and administrative employees and 85
field operations staff involved in the Company's oil and gas operations in Utah.
A sale or strategic alliance of the Company could affect a number of Company
employees.
OTHER PROPERTY
The Company's principal executive office is located in Denver, Colorado.
The Company leases approximately 16,500 square feet pursuant to a lease that
expires in December 2002 and provides for a rental rate of $25,000 per month.
Such space is adequate for the foreseeable future. The Company owns the
Roosevelt Utah field office (20,200 square feet) and land (40 acres).
CERTAIN DEFINITIONS
The following are abbreviations and words commonly used in the oil and gas
industry and in this Annual Report.
"bbl" or "barrel" means barrels, a standard measure of volume for oil,
condensate and natural gas liquids which equals 42 U.S. gallons.
"BOE" means equivalent barrels of oil. In reference to natural gas, natural gas
equivalents are determined using the ratio of six Mcf of natural gas to one Bbl
of crude oil, condensate or natural gas liquids.
"BPD" means barrels per day.
"BWPD" means barrels of water per day.
11
"development well" means a well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
"exploration well" means a well drilled to find commercially productive
hydrocarbons in an unproved area or to extend significantly a known oil or
natural gas reservoir.
"farm-in" or "farm-out" refers to an agreement whereunder the owner of a working
interest in an oil and gas lease delivers the contractual right to earn the
working interest or a portion thereof to another party who desires to drill on
the leased acreage. Generally, the assignee is required to drill one or more
wells in order to earn a working interest in the acreage. The assignor usually
retains a royalty or a working interest after payout in the lease. The assignor
is said to have "farmed-out" the acreage. The assignee is said to have
"farmed-in" the acreage.
"gathering system" means a pipeline system connecting a number of wells,
batteries or platforms to an interconnection with an interstate pipeline.
"gross" oil and natural gas wells or "gross" acres are the total number of wells
or acres, respectively, in which the Company has an interest, without regard to
the size of that interest.
"MBls" means one thousand barrels.
"MBOE" means one thousand equivalent barrels of oil.
"Mcf" means one thousand cubic feet, a standard measure of volume for gas.
"MMcf" means one million cubic feet.
"net" oil and natural gas wells or "net" acres are the total gross number of
wells or acres respectively in which the Company has an interest multiplied
times the Company's or other referenced party's working interest in such wells
or acres.
"posted field price" is an industry term for the fair market value of oil in a
particular field.
"productive wells" are producing wells or wells capable of production
In this Annual Report, natural gas volumes are stated at the legal pressure base
of the state or area in which the reserves are located and at 60 degrees
Fahrenheit.
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
[THIS SPACE INTENTIONALLY LEFT BLANK]
12
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK
Since July 29, 1999, Inland's Common Stock has been traded over-the-counter and
quoted from time to time in the OTC Bulletin Board and in the "Pink Sheets"
under the trading symbol "INLN". Prior to July 29, 1999, Inland's Common Stock
was quoted on the Nasdaq SmallCap Market under the symbol "INLN". As of March
13, 2002, there were approximately 513 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, 2001
First Quarter................................... $ 1.87 $ 1.03
Second Quarter.................................. 1.69 1.25
Third Quarter................................... 1.60 1.30
Fourth Quarter.................................. 2.10 1.32
YEAR ENDED DECEMBER 31, 2000
First Quarter................................... $ 7.00 $ 2.13
Second Quarter.................................. 7.00 3.00
Third Quarter................................... 5.75 4.25
Fourth Quarter.................................. 3.88 0.94
DIVIDEND POLICY
Inland has not paid cash dividends on Inland's Common Stock during the last five
years and does not intend to pay cash dividends on Common Stock in the
foreseeable future. The payment of future dividends will be determined by
Inland's Board of Directors in light of conditions then existing, including
Inland's earnings, financial condition, capital requirements, restrictions in
financing agreements, business conditions and other factors. The Fortis Credit
Agreement forbids the payment of dividends by Inland on its Common Stock.
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, 2001. 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 in this annual report.
13
Year Ended December 31,
-------------------------------------------------------
2001 2000 1999 1998 1997
-------- ------- ------ ------ ------
(dollars in thousands, except for unit amounts)
REVENUE AND EXPENSE DATA:
Revenues:
Oil and gas sales................................ $31,487 $28,497 $16,399 $21,278 $17,182
Operating expenses:
Lease operating expenses......................... 9,344 7,596 7,160 8,362 3,780
Production taxes................................. 479 483 192 454 383
Exploration...................................... 143 135 155 153 61
Impairment....................................... - - - 1,327 -
Depletion, depreciation and amortization......... 9,106 7,816 9,882 12,025 6,480
General and administrative, net.................. 1,486 2,128 3,136 2,061 2,118
-------- ------- ------- ------- -------
Total operating expenses...................... 20,558 18,158 20,525 24,382 12,822
-------- ------- ------- ------- -------
Operating income (loss)............................. 10,929 10,339 (4,126) (3,104) 4,360
Interest expense.................................... (12,031) (8,298) (15,989) (14,895) (4,759)
Unrealized derivative............................... (5,548) - - - -
Interest and other income........................... 626 103 72 107 380
-------- ------- ------- ------- -------
Net income (loss) from continuing operations (6,024) 2,144 (20,043) (17,892) (19)
Loss from discontinued operations............. - (250) (16,274) (5,560) -
-------- ------- ------- ------- -------
Net income (loss) before extraordinary loss and
cumulative effect of change in accounting
principle........................................ (6,024) 1,894 (36,317) (23,452) (19)
Extraordinary loss.................................. - (556) (1,160)
Cumulative effect of change in accounting principle. 45 - - - -
-------- ------- ------- ------- -------
Net income (loss) .................................. (5,979) 1,894 (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.......... (6,342) (9,732) (2,262) - -
Accrued Preferred Series E Stock dividends.......... (980) (1,506) (350) - -
Accretion of Preferred Series D Stock discount...... (3,318) (6,300) (1,473) - -
Accretion of Preferred Series E Stock discount...... (535) (900) (220) - -
Excess carrying value of Series E preferred
over redemption consideration ............. 13,083 - - - -
------- ------- -------- ------- -------
Net loss attributable to common stockholders.... $(4,071) $(16,544) $(41,841) $(24,536) $(2,209)
======= ======= ======== ======= =======
Net income (loss)............................... $(5,979) $ 1,894 $(36,873) $(23,452) $(1,179)
Change in fair value of derivative contracts 5,503 - - - -
-------- ------- ------- ------- -------
Comprehensive income (loss)..................... $ (476) $ 1,894 $(36,873) $(23,452) $(1,179)
======== ======= ======= ======= =======
Loss per common share from continuing operations
Basic...................................... $ (1.42) $ (5.62) $ (17.56) $ (22.62) $ (1.42)
Diluted.................................... (1.42) (5.62) (17.56) (22.62) (1.42)
Loss per common share before extraordinary loss and
cumulative effect of change in accounting
principle
Basic...................................... $ (1.40) $ (5.71) $ (28.99) $ (29.25) $ (1.42)
Diluted.................................... (1.40) (5.71) (28.99) (29.25) (1.42)
Loss per common share:
Basic...................................... $ (1.40) $ (5.71) $ (29.37) $ (29.25) $ (2.99)
Diluted.................................... (1.40) (5.71) (29.37) (29.25) (2.99)
14
Year Ended December 31,
-------------------------------------------------------
2001 2000 1999 1998 1997
------ ------ ------ ------ ------
(dollars in thousands, except for unit amounts)
BALANCE SHEET DATA (AT END OF PERIOD):
Oil and gas properties, net......................... $162,025 $148,955 $142,412 $159,105 $133,820
Total assets........................................ 173,376 160,065 153,402 187,781 175,953
Debt................................................ 197,456 83,500 79,082 156,973 123,111
Preferred stock..................................... - 91,243 72,805 11,102 10,018
Stockholders' equity (deficit)...................... (30,412) (20,210) (3,666) 7,039 30,672
OTHER FINANCIAL DATA:
Net cash provided by (used in) operating activities.... $ 16,663 $ 7,992 $(7,513) $ 6,822 $ 5,668
Net cash used in investing activities............... (22,289) (14,137) (3,772) (39,391) (99,272)
Net cash provided by financing activities........... 6,727 4,085 10,502 47,076 107,128
OPERATING DATA:
Sales volumes (net):
Oil (MBbls)................................ 1,212 1,072 1,165 1,501 855
Gas (MMcf)................................. 2,423 2,289 2,901 3,006 1,637
MBOE....................................... 1,616 1,454 1,649 2,002 1,128
BOEPD...................................... 4,427 3,973 4,518 5,485 3,090
Average prices (excluding hedging activities):
Oil (per Bbl).............................. $ 22.31 $ 26.71 $ 14.38 $ 9.82 $ 16.17
Gas (per Mcf).............................. 3.05 2.60 1.56 2.00 2.19
Per BOE.................................... 21.30 23.79 12.90 10.35 15.23
Production and operating costs (per BOE) (1).... $ 5.78 $ 5.23 $ 4.34 $ 4.18 $ 3.35
(1) Excludes production taxes.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion should be read in conjunction with the Company's
consolidated financial statements and notes thereto included elsewhere in this
Annual Report and the information set forth under the heading "Selected
Financial Data" and is intended to assist in the understanding of the Company's
financial position and results of operations for each of the years ended
December 31, 2001, 2000 and 1999.
GENERAL
Inland is a diversified and independent energy company engaged in the
acquisition, development and enhancement of oil and gas properties in the
western United States. All of the Company's oil and gas reserves are located in
the Monument Butte Field (the "Field") within the Uinta Basin of northeastern
Utah.
On January 31, 2000, the Company sold its 100% owned subsidiary, Inland
Refining, Inc. The subsidiary owned the Woods Cross Refinery and a nonoperating
refinery located in Roosevelt, Utah. The Woods Cross refinery was originally
purchased on December 31, 1997 for $22.9 million and the Roosevelt refinery was
originally purchased on September 16, 1998 for $2.25 million. Due to this sale,
the Company is no longer involved in the refining of crude oil or the sale of
refined products. As a result, all refining operations have been classified as
discontinued operations in the accompanying consolidated financial statements.
In January 2002, the Company announced that it had hired Lehman Brothers
Inc. and Petroleum Place Energy Advisors to advise the Company regarding its
review of strategic alternatives, which may include a potential sale or merger
of the Company. The Company is engaged in various levels of negotiations
regarding such a transaction.
15
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our discussion of financial condition and results of operation are based
upon the information reported in our consolidated financial statements. The
preparation of these financial statements requires us to make assumptions and
estimates that affect the reported amounts of assets, liabilities, revenues and
expenses as well as the disclosure of contingent assets and liabilities at the
date of our financial statements. We base our decisions on historical experience
and various other sources that are believed to be reasonable under the
circumstances. Actual results may differ from the estimates we calculated due to
changing business conditions or unexpected circumstances. Policies we believe
are critical to understanding our business operations and results of operations
are detailed below. For additional information on our significant accounting
policies you should see Note 1 in our accompanying consolidated financial
statements.
Revenue recognition. The Company is engaged in the acquisition,
development, and enhancement of oil and gas properties of crude oil and natural
gas. Our revenue recognition policy is significant because our revenue is a key
component of our results of operations and our forward looking statements
contained in Liquidity and Capital Resources. We derive our revenue primarily
from the sale of produced crude oil and natural gas. Revenue is recorded in the
month our production is delivered to the purchaser, but payment is generally
received between 30 and 60 days after the date of production. At the end of each
period we make estimates of the amount of production delivered to the purchaser
and the price we received. We use our knowledge of our properties, their
historical performance, NYMEX and local spot market prices and other factors as
the basis for these estimates. Variances between our estimates and the actual
amounts received are recorded in the month payment is received.
Oil and gas reserve quantities. Estimated reserve quantities and the
related estimates of future net cash flows affect our periodic calculations of
depletion, depreciation and impairment for our proved oil and gas properties.
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operation conditions. Future inflows and
future production and development costs are determined by applying benchmark
prices and costs, including transportation and basis differentials, in effect at
the end of each period to the estimated quantities of oil and gas remaining to
be produced at the end of that period. Expected cash flows are reduced to
present value using a discount rate that depends upon the calculation for which
the reserve estimates will be used. Reserve estimates are inherently imprecise.
Estimates of new discoveries are more imprecise that those of proved producing
oil and gas properties. We expect that periodic reserve estimates will change in
the future, as additional information becomes available or as oil and gas prices
and costs change. For any period, unknown circumstances could have caused us to
calculate more or less depletion, depreciation or impairment. Changes in these
calculations caused by changes in reserve quantities or net cash flows are
recorded in the period that the reserve estimates changed.
Valuation of long-lived and intangible assets. Our property and equipment
are recorded at cost. An impairment allowance is provided on unproved property
when we determine that the property will not be developed. We evaluate the
reliability of our proved producing and other long-lived assets whenever events
or changes in circumstances indicate that an impairment may have occurred. Our
impairment test compares the expected undiscounted future net revenues from a
property using escalated pricing with the related net capitalized costs of the
property at the end of each period. When the net capitalized costs exceed the
undiscounted future net revenue of a property, the cost of the property is
written down to our estimate of fair value, which is determined by applying a
10% discount rate to future net revenues. Each company has its own criteria for
acceptable internal rates of return, and those criteria can change over time.
Different pricing assumptions or discount rates would result in a different
calculated impairment.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2001 COMPARED WITH YEAR ENDED DECEMBER 31, 2000
Oil and Gas Sales. Crude oil and natural gas revenue for the year ended
December 31, 2001 increased $3 million, or 11% from the previous year. As shown
in the table below, the $3 million variance in 2001 was caused by higher crude
oil and natural gas volumes and, in the case of natural gas higher average
prices, offset by lower crude oil prices. The Company operates and is in control
of over 98% of its oil and gas production. Crude oil sales as a percentage of
total oil and gas sales were 79% and 83% during 2001 and 2000, respectively.
Crude oil will continue to be the predominant product produced from the Field.
16
The Company had entered into price protection agreements to hedge against
volatility in crude oil prices. The Company entered into all of its hedging
contracts with Enron North America Corp. ("ENAC"). On December 2, 2001, ENAC
filed for Chapter 11 bankruptcy. The ENAC bankruptcy caused default on all of
the Company's hedging contracts from November 2001 through September 30, 2003.
The Company recorded a loss of $5.5 million to the statement of operations to
reflect ineffectiveness of the derivative contracts following the filing of
Chapter 11 bankruptcy of ENAC. The amount that had been deferred in accumulated
other comprehensive income will be reclassified to earnings based on the
originally scheduled delivery period. Amounts expected to be reclassified to
earnings in 2002 and 2003 are $3,993,000 and $1,510,000, respectively. Although
hedging activities do not affect the Company's actual sales price for crude oil
in the Field, the financial impact of hedging transactions is reported as an
adjustment to crude oil revenue in the period in which the related oil is sold.
Crude oil sales were decreased by $2.9 million and $6.1 million during year 2001
and 2000, respectively, to recognize hedging contract settlement losses. See
Item 7A "Quantitative and Qualitative Disclosures About Market Risk".
On January 30, 2002, the Company terminated all of its hedging contracts
with ENAC and determined a potential bankruptcy unsecured claim against ENAC in
excess of $7.5 million.
Year Ended December 31, 2001 Year Ended December 31, 2000
----------------------------------------- --------------------------------------------
Net Volume Average Sales Net Volume Average Sales
(Bbls or Mcfs) Price (in 000's) (Bbls or Mcfs) Price (in 000's)
-------------- ------- ---------- -------------- ------- ----------
Crude Oil Sales 1,211,793 $22.31 $ 27,034 1,071,752 $26.71 $ 28,627
Natural Gas Sales 2,422,612 $ 3.05 7,394 2,289,059 $2.60 5,953
Hedging Loss (2,941) (6,083)
--------- --------
Total Revenue $ 31,487 $ 28,497
========= ========
Lease Operating Expenses. Lease operating expense for the year ended
December 31, 2001 increased $1,748,000, or 23% from the previous year. Lease
operating expense per BOE increased from $5.23 per BOE sold in 2000 to $5.78 per
BOE in 2001. The increase in year 2001 on a BOE basis is due to substantially
higher costs of materials and labor, due to increased demand for products,
services and employees in the Monument Butte region and neighboring areas.
Production Taxes. Production taxes as a percentage of sales were 1.4% in
2001 and 1.4% in 2000. Production tax expense consists of estimates of the
Company's yearly effective tax rate for Utah state severance tax and production
ad valorem tax. Changes in sales prices, tax rates, tax exemptions and the
timing, location and results of drilling activities can all affect the Company's
actual effective tax rate.
Exploration. Exploration expense in 2001 and 2000 represents the Company's
cost to retain unproved acreage including delay rentals.
Depletion, Depreciation and Amortization. Depletion, depreciation and
amortization for the year ended December 31, 2001 increased 16.5%, or $1.3
million, from the previous year. The increase resulted from increased sales
volumes and a higher average depletion rate. Depletion, which is based on the
units-of-production method, comprises the majority of the total charge. The
depletion rate is a function of capitalized costs and related underlying proved
reserves in the periods presented. The Company's average depletion rate was
$5.26 per BOE sold during 2001 compared to $4.95 per BOE sold during 2000. Based
on December 31, 2001 proved reserves, the Company's depletion rate entering 2002
is $5.25 per BOE.
General and Administrative, Net. General and administrative expense for the
year ended December 31, 2001 decreased $642,000, or 30% from the previous year.
General and administrative expense is reported net of operator fees and
reimbursements which were $7.5 million and $5.5 million during 2001 and 2000,
respectively. Gross general and administrative expense was $9 million in 2001
and $7.2 million in 2000. The lower net general and administrative expenses for
2001 was due to higher reimbursement from operating overhead, drilling and labor
due to the 2001 drilling program offset by higher labor and benefit costs.
17
Interest Expense. Interest expense for the year ended December 31, 2001
increased $3.7 million, or 45% from the previous year. The increase was the
result of the new issuance of subordinated debt on August 2, 2001 of $109
million at a rate of 11% per annum. Accrued interest on the subordinated debt
for 2001 was $5 million compared to none for 2000. Interest on the senior bank
debt decreased $1.5 million or 19% from the previous year. Borrowings during
2001 and 2000 were recorded at effective interest rates of 8.8% and 10.2%,
respectively.
Other Income. Other income in 2001 and 2000 primarily represents interest
earned on the investment of surplus cash balances and miscellaneous other
income.
Income Taxes. In 2001 and 2000, no income tax provision or benefit was
recognized due to net operating losses incurred and the establishment of a full
valuation allowance.
Preferred Series D Stock Dividends. Inland's Preferred Series D Stock
accrued dividends at 11.25% compounded quarterly. The amount accrued represented
those dividends earned through August 1, 2001 and during 2000, respectively. As
discussed under Note 5 to the Consolidated Financial Statements, the Company's
Preferred Series D Stock was cancelled in exchange for the TCW subordinated
notes and $2 million on August 2, 2001.
Preferred Series E Stock Dividends. Inland's Preferred Series E Stock
accrued dividends at 11.5% compounded quarterly. The amount accrued represented
those dividends earned through August 1, 2001 and during 2000, respectively. As
discussed under Note 5 to the Consolidated Financial Statements, the Company's
Preferred Series E Stock was cancelled on August 2, 2001.
Preferred Series D Stock Discount. Inland's Preferred Series D Stock was
initially recorded on the financial statements at a discount of $20.2 million
and was being accreted to face value ($80.7 million) over the minimum mandatory
redemption period, that started on April 1, 2002 and ended on April 1, 2004. As
discussed under Note 5 to the Consolidated Financial Statements, the Company's
Preferred Series D Stock was cancelled in exchange for TCW subordinated notes
and $2 million on August 2, 2001.
Preferred Series E Stock Discount. Inland's Preferred Series E Stock was
initially recorded on the financial statements at a discount of $4.2 million and
was being accreted to face value ($12.2 million) over the period to the minimum
mandatory redemption date of April 1, 2004. As discussed under Note 5 to the
Consolidated Financial Statements, the Company's Preferred Series E Stock was
cancelled on August 2, 2001.
YEAR ENDED DECEMBER 31, 2000 COMPARED WITH YEAR ENDED DECEMBER 31, 1999
Oil and Gas Sales. Crude oil and natural gas revenue for the year ended
December 31, 2000 increased $12.1 million, or 74% from the previous year. As
shown in the table below, the variance was caused by higher average crude oil
and natural gas prices offset by lower sales volumes. The Company operates and
is in control of over 99% of its oil and gas production. Crude oil sales as a
percentage of total oil and gas sales were 83% and 79% during 2000 and 1999,
respectively. Crude oil will continue to be the predominant product produced
from the Field.
The Company has entered into price protection agreements to hedge against
volatility in crude oil prices. Although hedging activities do not affect the
Company's actual sales price for crude oil in the Field, the financial impact of
hedging transactions is reported as an adjustment to crude oil revenue in the
period in which the related oil is sold. Crude oil sales were decreased by $6.1
million and $4.9 million during year 2000 and 1999, respectively, to recognize
hedging contract settlement losses. See Item 7A "Quantitative and Qualitative
Disclosures About Market Risk."
Year Ended December 31, 2000 Year Ended December 31, 1999
--------------------------------------- -------------------------------------------
Net Volume Average Sales Net Volume Average Sales
(Bbls or Mcfs) Price (in 000's) (Bbls or Mcfs) Price (in 000's)
-------------- ------- ---------- -------------- ------- ----------
Crude Oil Sales 1,071,752 $26.71 $ 28,627 1,165,117 $14.38 $ 16,754
Natural Gas Sales 2,289,059 $ 2.60 5,953 2,900,501 $ 1.56 4,517
Hedging Loss (6,083) (4,872)
---------- ----------
Total Revenue $ 28,497 $ 16,399
========== ==========
18
Lease Operating Expenses. Lease operating expense for the year ended
December 31, 2000 increased $436,000, or 6.1% from the previous year. Lease
operating expense per BOE increased from $4.34 per BOE sold in 1999 to $5.23 in
2000. The increase on a BOE basis is due to the lower volume produced and
general price increases throughout year 2000.
Production Taxes. Production taxes as a percentage of sales were 1.4% in
2000 and 1.0% in 1999. Production tax expense consists of estimates of the
Company's yearly effective tax rate for Utah state severance tax and production
ad valorem tax. Changes in sales prices, tax rates, tax exemptions and the
timing, location and results of drilling activities can all affect the Company's
actual effective tax rate.
Exploration. Exploration expense in 2000 and 1999 represents the Company's
cost to retain unproved acreage including delay rentals.
Depletion, Depreciation and Amortization. Depletion, depreciation and
amortization for the year ended December 31, 2000 decreased 21%, or $2.1
million, from the previous year. The decrease resulted from decreased sales
volumes and a lower average depletion rate. Depletion, which is based on the
units-of-production method, comprises the majority of the total charge. The
depletion rate is a function of capitalized costs and related underlying proved
reserves in the periods presented. The Company's average depletion rate was
$4.95 per BOE sold during 2000 compared to $5.59 per BOE sold during 1999.
General and Administrative, Net. General and administrative expense for the
year ended December 31, 2000 decreased $1.0 million, or 32% from the previous
year. The 2000 amount includes $430,000 related to an unsuccessful business
combination and employee severance costs. The 1999 amount includes $1.2 million
related to the Company's financial restructuring. After removal of these costs,
general and administrative expense was 12% lower between periods. General and
administrative expense is reported net of operator fees and reimbursements which
were $5.5 million and $4.7 million during 2000 and 1999, respectively. Gross
general and administrative expense was $7.2 million (net of one-time costs) in
2000 and $6.6 million (net of restructuring costs) in 1999. The increase in
reimbursements and expense is a function of operated field activity; which
decreased in 1999 when the Company suspended development activity until the
fourth quarter, then increased in year 2000 when the Company was active with
development activities throughout the year.
Interest Expense. Interest expense for the year ended December 31, 2000
decreased $7.7 million, or 48% from the previous year. The decrease was the
result of the financial restructuring performed in September 1999 when
approximately $80.0 million of debt was converted to preferred stock. Borrowings
during 2000 and 1999 were recorded at effective interest rates of 10.2% and
10.6%, respectively.
Other Income. Other income in 2000 and 1999 primarily represents interest
earned on the investment of surplus cash balances.
Income Taxes. In 2000 and 1999, no income tax provision or benefit was
recognized due to net operating losses incurred and the establishment of a full
valuation allowance.
Discontinued Operations. During 1999, the Company operated the Woods Cross
Refinery and incurred an operating loss of $1.8 million. On January 31, 2000,
the refinery along with certain other assets were sold to Silver Eagle. Although
the margins obtained for refined product sales in the Salt Lake City region were
strong for most of the year, the Company suffered from inefficient operations
since it was unable to secure sufficient quantities of feedstock due to its
financial condition. After the Company's financial restructuring in September
1999, increasing crude oil costs reduced margins on refined product sales to
unacceptable levels. These circumstances combined with the availability of
alternative buyers for the Company's crude oil caused the Company to discontinue
refinery operations in December 1999 and subsequently sell Refining on January
31, 2000. As a result of this activity, the accompanying consolidated financial
statements for the current period and all prior periods have been adjusted to
report refining operations as
19
discontinued operations. The Company recorded a charge of $14.5 million in 1999
to record the disposal of the refining business segment. The Company recorded an
additional loss of $250,000 during 2000 to reflect adjustments to the refinery
shut-down accruals.
Extraordinary Item. Effective September 21, 1999, the Company restructured
an existing obligation to TCW and amended the terms of its farmout arrangement
with Smith Energy Partnership. As a result of these transactions, unamortized
debt issue costs of $556,000 were written off as an extraordinary loss.
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.
Preferred Series D Stock Dividends. Inland's Preferred Series D Stock
accrued dividends at 11.25% compounded quarterly. The amount accrued represented
those dividends earned during 2000 and the fourth quarter of 1999, respectively.
As discussed under Note 5 to the Consolidated Financial Statements, the
Company's Preferred Series D Stock was cancelled in exchange for the TCW
subordinated notes and $2 million on August 2, 2001.
Preferred Series E Stock Dividends. Inland's Preferred Series E Stock
accrued dividends at 11.5% compounded quarterly. The amount accrued represented
those dividends earned during 2000 and the fourth quarter of 1999, respectively.
As discussed under Note 5 to the Consolidated Financial Statements, the
Company's Preferred Series E Stock was cancelled on August 2, 2001.
Preferred Series D Stock Discount. Inland's Preferred Series D Stock was
initially recorded on the financial statements at a discount of $20.2 million
and was being accreted to face value ($80.7 million) over the minimum mandatory
redemption period which started on April 1, 2002 and ended on April 1, 2004. As
discussed under Note 5 to the Consolidated Financial Statements, the Company's
Preferred Series D Stock was cancelled in exchange for TCW subordinated notes
and $2 million on August 2, 2001.
Preferred Series E Stock Discount. Inland's Preferred Series E Stock was
initially recorded on the financial statements at a discount of $4.2 million and
was being accreted to face value ($12.2 million) over the period to the minimum
mandatory redemption date of April 1, 2004. As discussed under Note 5 to the
Consolidated Financial Statements, the Company's Preferred Series E Stock was
cancelled on August 2, 2001.
LIQUIDITY AND CAPITAL RESOURCES
FORTIS CREDIT AGREEMENT
Effective September 21, 1999, the Company entered into a credit agreement
(the "Fortis Credit Agreement"). The current participants are Fortis Capital
Corp. and U.S. Bank National Association (the "Senior Lenders"). At December 31,
2001, the Company had advanced all funds under its current borrowing base of
$83.5 million. The borrowing base is calculated as the collateral value of
proved reserves and is subject to redetermination on or before March 31, 2002
and with subsequent determinations to be made on each subsequent October 1 and
April 1. If the borrowing base is lower than the outstanding principal balance
then drawn, the Company must immediately pay the difference. The borrowing base
was redetermined to be $83.5 million at March 26, 2002.
In conjunction with SOLVation financing, the Fortis Credit Agreement with
the senior bank group was amended to change the maturity date to June 30, 2007
from April 1, 2002, or potentially earlier if the borrowing base is determined
to be insufficient. Interest accrues under the Fortis Credit Agreement, at the
Company's option, at either (i) 2% above the prime rate or (ii) at various rates
above the LIBOR rate. The LIBOR rates will be determined by the senior debt to
EBITDA ratios starting August 2, 2001. If the senior debt to EBITDA ratio is
greater than 4.00 to 1.00, the rate is 3.25% above the LIBOR rate; if the senior
debt to EBITDA ratio is equal to or less than 4.00 to 1.00 but greater than 3.00
to 1.00, the rate is 2.75% above the LIBOR rate; if the senior debt to EBITDA
ratio is less than 3.00 to 1.00, the rate is 2.25% above the LIBOR rate. As of
December 31, 2001, $83 million and $500,000 were borrowed under the LIBOR option
at interest rates of 6.27% and 4.65%, respectively. The revolving termination
date is June 30, 2004 at which time the loan converts into a term loan payable
in 12 equal quarterly installments of principal, with accrued interest,
beginning September 30, 2004. The Fortis Credit Agreement has covenants that
restrict the payment of cash dividends, borrowings,
20
sale of assets, loans to others, investments, merger activity and hedging
contracts without the prior consent of the lenders and requires the Company to
maintain certain net worth, interest coverage and working capital ratios. The
Company was in compliance of its bank covenants as of December 31, 2001.
The Fortis Credit Agreement is secured by a first lien on substantially all
assets of the Company. The Fortis Credit Agreement was amended on March 25,
2002.
SUBORDINATED UNSECURED DEBT TO SOLVATION INC.
On August 2, 2001, the Company closed two subordinated debt transactions
totaling $10 million in aggregate with SOLVation Inc. The first of the two debt
transactions with SOLVation was the issuance of a $5 million unsecured senior
subordinated note to SOLVation due July 1, 2007. The interest rate is 11% per
annum compounded quarterly. The interest payment is payable in arrears in cash
subject to the approval from the senior bank group and accumulates if not paid
in cash. The Company is not required to make any principal payments prior to the
July 1, 2007 maturity date. However, the Company is required to make payments of
principal and interest in the same amounts as any principal payment or interest
payments on the TCW subordinated debt (described below). Prior to the July 1,
2007 maturity date, subject to the bank subordination agreement, the Company may
prepay the senior subordinated note in whole or in part with no penalty.
The Company also issued a second $5 million unsecured junior subordinated
note to SOLVation. The interest rate is 11% per annum compounded quarterly. The
maturity date is the earlier of (i) 120 days after payment in full of the TCW
subordinated debt or (ii) March 31, 2010. Interest is payable in arrears in cash
subject to the approval from the senior bank group and accumulates if not paid
in cash. The Company is not required to make any principal payments prior to the
March 31, 2010 maturity date. Prior to the March 31, 2010 maturity date, subject
to both bank and subordination agreements, the Company may prepay the junior
subordinated note in whole or in part with no penalty. A portion of the proceeds
from the senior and junior subordinated notes was used to fund a $2 million
payment to TCW and other Company working capital needs.
SUBORDINATED UNSECURED DEBT TO TCW
In conjunction with the issuance of the two subordinated notes to
SOLVation, the Series D Preferred and Series E Preferred stock held by Inland
Holdings LLC, a company controlled by TCW, were exchanged for an unsecured
subordinated note due September 30, 2009 and $2 million in cash from the
Company. The note amount was for $98,968,964 that represented the face value
plus accrued dividends of the Series D Preferred stock as of August 2, 2001. The
interest rate is 11% per annum compounded quarterly. Interest shall be payable
in arrears in cash subject to the approval from the senior bank group and
accumulates if not paid in cash. Interest payments will be made quarterly,
commencing on the earlier of September 30, 2005 or the end of the first calendar
quarter after the senior bank debt has been reduced to $40 million or less,
subject to both bank and senior subordination agreements. Beginning the earlier
of two years prior to the maturity date or the first December 30 after the
repayment in full of the senior bank debt, subject to both bank and senior
subordination agreements, the Company will make equal annual principal payments
of one third of the aggregate principal amount of the TCW subordinated note. Any
unpaid principal or interest amounts are due in full on the September 30, 2009
maturity date. Prior to the September 30, 2009 maturity date, subject to both
bank and senior subordination agreements, the Company may prepay the TCW
subordinated note in whole or in part with no penalty.
CASH FLOW AND CAPITAL PROJECTS
During the year 2001, the Company generated $20.6 million of EBITDA
(earnings before interest, taxes, depreciation and amortization) of which it
used $22.3 million to continue development of the Field and $6.4 million to
service interest on senior bank borrowings. Net proceeds of $8.7 million from
the issuance of subordinated debt was generated to provide working capital to
its operations and $2 million to retire the Series E preferred stock. Field
development in year 2001 consisted of drilling 45 gross wells (35 net wells),
converting 33 gross (25 net) wells to water injection and continued extension of
the gas gathering and water delivery infrastructures.
The Company's net capital budget for development of the Field in year 2002
is estimated to be $10 to $12 million. The Company plans to drill 25 wells (20
net wells), complete 25 workovers or recompletion wells and convert 35 producing
wells to water injection. Although there can be no assurance, the Company
believes that cash on hand along with future cash to be generated from
operations will be sufficient to implement its development plans for the next
year. The level of these and other capital expenditures is largely
discretionary, and the amount of funds devoted to any
21
particular activity may increase or decrease significantly depending on
available opportunities, commodity prices, operating cash flows and development
results, among other items. The Company's contractual cash obligations are
listed in the following table:
Contractual Less Than 1-3 4-5 After 5
Cash Obligations Total 1 Year Years Years Years
- ---------------- -------- --------- ------- ------- --------
(In thousands)
Long-term debt $197,456 $ - $13,918 $64,726 $118,812
Operating leases 299 299 - - -
-------- --------- ------- ------- --------
Total Contractual Cash $197,755 $ 299 $13,918 $64,726 $118,812
======== ========== ======= ======= ========
On March 22, 2002, Questar Pipeline Company ("QPC") curtailed all gas
producers in the Monument Butte Field, including Inland, for not meeting certain
QPC specifications. After curtailment, Inland is producing and transporting
approximately 50% of its total gas capacity. The Company is in the process of
installing a gas liquid plant in the Field that would bring all of its gas up to
QPC's pipeline specifications. The gas liquid plant will be operational in
approximately 60 days. The Company believes that the current gas curtailment is
not significant to the Company's operations.
RECENTLY ADOPTED ACCOUNTING STANDARDS
In June 1998, SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities" ("SFAS No. 133") was issued, which establishes accounting
and reporting standards for derivative instruments and hedging activity. SFAS
No. 133 requires recognition of all derivative instruments on the balance sheet
as either assets or liabilities measured at fair value. Changes in the
derivative's fair value will be recognized currently in earnings unless specific
hedge accounting criteria are met. Gains and losses on derivative hedging
instruments must be recorded in either other comprehensive income or current
earnings, depending on the nature and designation of the instrument. The impact
of adopting SFAS No. 133 on January 1, 2001 resulted in recording a current
liability of $1,927,000 and recording a cumulative effect of a change in
accounting principle as accumulated comprehensive loss in the equity section of
$1,972,000 and income recorded as a cumulative effect of a change in accounting
principle of $45,000.
In June 2001, SFAS No. 141 "Business Combination" and SFAS No. 142
"Goodwill and Other Intangible Assets" were issued, which requires all business
combinations to be accounted for using the purchase method and changes the
treatment of goodwill created in a business combination. The adoption of these
two statements did not have an impact on the Company.
Additionally, SFAS No. 143 "Accounting for Asset Retirement Obligations"
was issued in July 2001. This standard requires entities to record the fair
value of a liability for an asset retirement obligation in the period in which
it is incurred. When the liability is initially recorded, the entity capitalizes
the cost by increasing the carrying amount of the related long-lived asset. The
asset is then depreciated over the estimated useful life. The present value of
the retirement obligation is adjusted each reporting period. The Company has not
yet determined the impact of adopting this statement which becomes effective on
January 1, 2003.
In August 2001, SFAS No. 144 "Accounting for the Impairment or Disposal of
Long-Lived Assets" was issued. This Statement established a single accounting
model, based on the framework of SFAS No. 121 ("Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of"), for the
long-lived assets to be disposed of by sale. The statement was adopted on
January 1, 2002 and the Company did not have a material impact upon adoption.
DELISTING OF COMMON STOCK
Effective with the close of business July 28, 1999, the Company's Common
Stock was delisted from the Nasdaq SmallCap Market. The Company was no longer
able to satisfy the net tangible asset maintenance standard for continued
listing. The Company's Common Stock is now traded on the NASD over-the-counter
bulletin board under the same symbol "INLN".
INFLATION AND CHANGES IN PRICES
Inland's revenues and the value of its oil and gas properties have been and
will be affected by changes in oil and gas prices. Inland's ability to borrow
from traditional lending sources and to obtain additional capital on attractive
terms is also substantially dependent on oil and gas prices. Oil and gas prices
are subject to significant seasonal and other fluctuations that are beyond
Inland's ability to control or predict. Although the level of inflation affects
certain of Inland's costs and expenses, inflation did not have a significant
effect on Inland's result of operations during 2001 or 2000.
22
FORWARD LOOKING STATEMENTS
Certain statements in this report, including statements of the Company's
and management's expectation, intentions, plans and beliefs, including those
contained in or implied by "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Notes to Consolidated Financial
Statements, are "forward-looking statements", within the meaning of Section 21E
of the Securities Exchange Act of 1934, that are subject to certain events, risk
and uncertainties that may be outside the Company's control. These
forward-looking statements include statements of management's plans and
objectives for the Company's future operations and statements of future economic
performance, information regarding drilling schedules, expected or planned
production or transportation capacity, future production levels of fields,
marketing of crude oil and natural gas, the Company's capital budget and future
capital requirements, credit facilities, the Company's meeting its future
capital needs, the Company's realization of its deferred tax assets, the level
of future expenditures for environmental costs and the outcome of regulatory and
litigation matters, and the assumptions described in this report underlying such
forward-looking statements. Actual results and developments could differ
materially from those expressed in or implied by such statements due to a number
of factors, including, without limitation, those described in the context of
such forward-looking statements, fluctuations in the price of crude oil and
natural gas, the success rate of exploration efforts, timeliness of development
activities, risk incident to the drilling and completion for oil and gas wells,
future production and development costs, the strength and financial resources of
the Company's competitors, the Company's ability to find and retain skilled
personnel, climatic conditions, the results of financing efforts, the political
and economic climate in which the Company conducts operations and the risk
factors described from time to time in the Company's other documents and reports
filed with the SEC.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Market risk generally represents the risk that losses may occur in the
value of financial instruments as a result of movements in interest rates,
foreign currency exchange rates and commodity prices.
INTEREST RATE RISK. Inland is exposed to some market risk due to the
floating interest rate under the Fortis Credit Agreement. See Item 7. -
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources." All borrowings under the Fortis
Credit Agreement are due and payable in 12 equal quarterly installments of
principal with accrued interest, beginning September 30, 2004. As of December
31, 2001, the Fortis Credit Agreement had a principal balance of $83.5 million
locked in at various interest rates as described below:
Principle Amount Period Locked In Interest Rate
---------------- ---------------- -------------
$83 million January 1, 2002 - February 22, 2002 6.77%
$83 million February 22, 2002 - May 23, 2002 5.15%
$500,000 January 1, 2002 - June 3, 2002 5.28%
The Company's total subordinated debt of $114 million outstanding at
December 31, 2001 has a fixed interest rate of 11% per annum compounded
quarterly and is not subject to rate increases. 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
1% increase in 2% increase in
interest rates interest rates
-------------- --------------
Year 2002 $515,000 $1,030,000
Year 2003 $835,000 $1,670,000
Year 2004 $818,000 $1,635,000
Year 2005 $591,000 $1,183,000
Year 2006 $313,000 $ 626,000
January 1, 2007 through
June 30, 2007 $157,000 $313,000
23
COMMODITY RISKS. Inland hedges a portion of its oil production to reduce its
exposure to fluctuations in the market prices thereof. Inland uses various
financial instruments whereby monthly settlements are based on differences
between the prices specified in the instruments and the settlement prices of
certain futures contracts quoted on the NYMEX index. Gains or losses on hedging
activities are recognized as oil and gas sales in the period in which the hedged
production is sold.
On December 2, 2001, ENAC filed for Chapter 11 bankruptcy. The bankruptcy
caused ENAC to default on all of the Company's hedging contracts from November
2001 through September 30, 2003. The Company recorded a loss of $5.5 million to
the statement of operations to reflect ineffectiveness of the derivative
contracts following the filing of Chapter 11 bankruptcy of ENAC. The amount that
had been deferred in accumulated other comprehensive income will be reclassified
to earnings based on the originally scheduled delivery period. Amounts expected
to be reclassified to earnings in 2002 and 2003 are $3,993,000 and $1,510,000,
respectively. On January 30, 2002, the Company terminated all of its hedging
contracts with ENAC and determined a potential bankruptcy unsecured claim
against ENAC in excess of $7.5 million.
On March 11, 2002, the Company hedged 30,000 net barrels per month with
Equiva Trading Company for the April 2002 to December 2002 period using a swap
with a settlement amount of $23.90 per barrel. The potential gains or (losses)
on this contract based on a hypothetical average market price of equivalent
product for this period is as follows:
Average NYMEX Per Barrel Market Price for the Contract Period
$ 18.00 $ 20.00 $ 22.00 $ 24.00 $ 26.00 $ 28.00 $ 30.00
All Contracts - $1,593,000 $1,053,000 $513,000 $27,000 $(567,000) $(1,107,000) $(1,647,000)
2002
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]
24
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS AND EXECUTIVE OFFICERS
The following table provides information as of March 1, 2002, with
respect to each of the Company's directors and executive officers:
SERVED AS EXECUTIVE
OFFICER OR
NAME AGE POSITION DIRECTOR SINCE
---- --- -------- -------------------
DIRECTORS
Arthur J. Pasmas (1) 67 Director (Chairman) 2001
Marc MacAluso (1) 41 Director, Chief Executive 1999
Officer and Chief Operating
Officer
Bill I. Pennington 50 Director, President and 1994
Chief Financial Officer
Bruce M. Schnelwar (1) 60 Director 2001
Dewey A. Stringer III(1) 59 Director 2001
OTHER EXECUTIVE OFFICERS
William T. War 59 Vice President 1998
(1) Member of the Audit Committee.
ARTHUR J. PASMAS. Mr. Pasmas has served as Vice President of Smith
Management LLC (or affiliated entities), New York, New York, a private company
engaged in various businesses and investments, including oil and gas, since
1984. He currently manages oil and gas investments as Vice President for Smith
Management LLC from offices in Houston, Texas. He was appointed as a director
and Chairman of the Board on August 2, 2001. He was also a director of the
Company from 1994 until September 1999, and was Co-Chief Executive Officer of
the Company from November 1998 until September 1999.
MARC MACALUSO. Mr. MacAluso was appointed as Chief Executive Officer and
Chief Operating Officer on February 1, 2001, and has served as a director since
October 14, 1999. He was Senior Vice President of TCW Asset Management Company
in Houston, Texas from August 1994 through January 2001, where he was involved
in all aspects of mezzanine financing for TCW's Energy Group. He joined TCW
Asset Management Company after leading new business development at American
Exploration Company. Prior to American Exploration Company, his experience
includes various assignments with Shell Oil Company and Shell Western E&P, Inc.
25
BILL I. PENNINGTON. Mr. Pennington has served as Chief Financial Officer of
the Company since September 21, 1994 and as President since November 16, 2000.
He also served as Chief Executive Officer from September 23, 1999 until February
1, 2001 and as Vice President from March 22,1996 until September 23, 1999. He
was appointed as a director of the Company on September 23, 1999. He served as a
director of the Company from September 21, 1994 until September 25, 1996 and as
Treasurer of the Company from September 21, 1994 until March 22, 1996. He also
served as President, Chief Operating Officer and a Director of Lomax Exploration
Company, now known as IPC, from May 1987 until the Company's acquisition of IPC
on September 21, 1994. From March 1986 until May 1987, Mr. Pennington was a
manager with the accounting firm of Coopers & Lybrand in Houston, Texas. Mr.
Pennington is a certified public accountant.
BRUCE M. SCHNELWAR. Mr. Schnelwar has served as a director of the Company
since March 22, 2001. He also was a director of the Company from February 1998
until September 1999. He has served since August 1994 as Executive Vice
President and Chief Financial Officer of Smith Management LLC (or affiliated
entities).
DEWEY A. STRINGER III. Mr. Stringer has been President of Petro-Guard Co.,
Inc., a private oil and gas exploration company located in Houston, Texas since
July 1987.
WILLIAM T. WAR. Mr. War has served as Vice President of the Company since
October 5, 1998. From September 1992 until his association with the Company, Mr.
War was Project Manager for Louisiana Land & Exploration/Burlington Resource's
Lost Cabin Gas Plant.
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 2001.
26
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table. The following table sets forth the compensation
earned by the Company's Chief Executive Officer and each of its three other most
highly compensated executive officers for the year ended December 31, 2001
(collectively, the "Named Officers") in salary and bonus for services rendered
in all capacities to the Company for the fiscal years ended December 31, 2001,
2000 and 1999:
ANNUAL COMPENSATION LONG TERM COMPENSATION
------------------------- ------------------------
SECURITIES
UNDERLYING
OTHER ANNUAL OPTIONS OR ALL OTHER
Name/Principal Position YEAR SALARY BONUS COMPENSATION WARRANTS COMPENSATION
- ----------------------- ---- ------ ----- ------------ --------- ------------
Arthur J. Pasmas, 2001 $ -- $ -- $199,992(1) -- --
Chairman(1) 2000 $ -- -- $199,992(1) -- --
1999 $ -- -- $ 80,779(1) -- --
Marc MacAluso, Chief 2001 $235,537 $ -- $ 27,952(3) 150,000(4) --
Executive Officer and Chief 2000 $ -- -- $ -- -- --
Operating Officer(2) 1999 $ -- -- $ -- -- --
Bill I. Pennington, 2001 $250,000 -- $ -- 150,000(4) --
President and Chief 2000 $250,000 -- $ 10,200 -- --
Financial Officer(5) 1999 $201,000 -- $ 6,544 87,500(6) --
William T. War, 2001 $155,346 $ 75,000 $ -- -- --
Vice President 2000 $175,000 $ 50,000 $ 10,200 -- --
1999 $162,000 -- $ 5,020 25,000 --
(1) Mr. Pasmas was appointed as a director and Chairman on August 2, 2001.
He was also a director of the Company from 1994 until September 1999, and
was Co-Chief Executive Officer of the Company from November 1998 until
September 1999. The $199,992 represents total compensation paid to Mr.
Pasmas during 2001 for his consulting agreement terminated on August 2,
2001 and his compensation as the Chairman of the Board. The $199,992 and
$80,779 for the years 2000 and 1999, respectively, were for consulting
fees paid to Mr. Pasmas as a non officer and director.
(2) Mr. MacAluso was appointed Chief Executive Officer and Chief Operating
Officer on February 1, 2001. He was not an officer of the Company prior to
his appointment as Chief Executive Officer and Chief Operating Officer on
February 1, 2001.
(3) Moving expenses in 2001 for Mr. MacAluso.
(4) Options issued to Mr. MacAluso and Mr. Pennington on February 1, 2001.
(5) Mr. Pennington was Chief Executive Officer until from September 23,
1999 until February 1, 2001.
(6) These options were mutually terminated by
the Company and Mr. Pennington effective February 1, 2001.
Option/Warrant/SAR Grants. The following table sets forth certain
information regarding options, warrants and SARs granted during 2001:
INDIVIDUAL GRANTS POTENTIAL
- ------------------------------------------------------------------- REALIZABLE VALUE AT
ASSUMED ANNUAL
NUMBER OF PERCENT OF TOTAL RATES OF STOCK
SECURITIES UNDERLYING OPTIONS/WARRANTS/SARS EXERCISE OR PRICE APPRECIATION
OPTIONS/WARRANTS/SARS GRANTED TO EMPLOYEES BASE PRICE EXPIRATION FOR OPTION TERM
NAME GRANTED (#) IN FISCAL YEAR ($/SH) DATE 5%($) 10%($)
- ---- ---------------------- --------------------- ----------- ---------- ----- ------
Marc MacAluso 90,000 100% $ 1.63 2/1/09 $ 70,000 $168,000
60,000 100% $ 2.84 2/1/09 $ 81,000 $195,000
Bill I. Pennington 90,000 100% $ 1.63 8/2/06 $ 41,000 $ 90,000
60,000 100% $ 2.84 8/2/06 $ 47,000 $104,000
William T. War -- -- -- -- -- --
27
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, 2001:
NUMBER OF SECURITIES VALUE OF UNEXERCISED
UNDERLYING UNEXERCISED IN-THE-MONEY OPTIONS
NUMBER OF SHARES OPTIONS AT FISCAL YEAR END AT FISCAL YEAR END (1)
ACQUIRED OR REALIZED
NAME EXERCISE VALUE EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ---- -------- ----- ----------- ------------- ----------- -------------
Marc MacAluso -- -- 50,000 100,000 -- --
Bill I .Pennington -- -- 150,000 -- -- --
William T. War -- -- 25,000 -- -- --
(1) Value is based on the closing bid price of $1.35 per share on December
31, 2001.
Long-Term Incentive Plans. The following table sets forth certain
information regarding long-term incentive awards granted during 2001 to the
Named Officers:
PERFORMANCE OR ESTIMATED FUTURE PAYMENTS UNDER
NUMBER OF SHARES, OTHER PERIOD NON-STOCK PRICE-BASED PLANS
UNITS OR OTHER RIGHTS UNTIL MATURATION THRESHOLD TARGET MAXIMUM
NAME # OR PAYOUT ($ OR #) ($ OR #) ($OR #)
- ---- --------------------- ---------------- -------- -------- -------
Marc MacAluso -- 12/31/03(1) $50,000 $50,000 $50,000
Bill I. Pennington -- 12/31/03(1) $50,000 $50,000 $50,000
William T. War -- -- -- -- --
(1) The Employment Agreements of Messrs. MacAluso and Pennington provide
for a performance bonus of $50,000 and $50,000, respectively, for the
December 31, 2001 year based on meeting or exceeding actual 2001 oil and
gas net equivalent production barrels and either completing a merger with
another company acceptable to the Board or a public offering of the
Company's common stock. However, the 2001 performance goals were not met
and no bonuses were paid.
Compensation of Directors. The members of the Board of Directors of the
Company are entitled to reimbursement for their reasonable expenses in
connection with their travel to and from, and attendance at, meetings of the
Board of Directors or committees thereof. Effective September 23, 1999, members
of the Board who are not employees of the Company are paid an annual fee of
$25,000 and no additional meeting fees for meetings of the Board or any
committee. The Board of Directors may grant discretionary options to directors.
Employment Agreements. Effective February 1, 2001, the Company entered into
an employment agreement with Mr. MacAluso. The Company entered into new
employment agreement with Mr. Pennington effective February 1, 2001, pursuant to
which the Company and Mr. Pennington agreed to terminate his prior employment
agreement. Mr. Pennington also agreed to cancel all outstanding options granted
to him.
Pursuant to their employment agreements, dated effective February 1, 2001,
the Company agreed to pay Messrs. MacAluso and Pennington base salaries of
$250,000 and annual bonuses of up to $50,000 contingent upon the Company
reaching or exceeding certain performance targets to be set by the Board for
each year. Their employment agreements have an initial term of three years and
automatically are extended for additional one year periods unless either party
terminates the agreement prior to the end of the current term. The Company also
agreed to grant each of them options to purchase 90,000 shares of the Company's
Common Stock at an exercise price of $1.625 per share and options to purchase
60,000 shares of the Company's Common Stock at an exercise price of $2.84 per
share, with such options vesting ratably over twelve fiscal quarters, with the
first one-twelfth vesting on March 1, 2001. However, Mr. Pennington is fully
vested in his 150,000 options due to change of control of the Company. The
options for 90,000 shares are also subject to automatic increase upon the
issuance of additional shares by the Company in a pro rata amount based on the
percentage increase in the number of outstanding shares of the Company. The
exercise price for such new
28
options would be the same as the issue price of the new shares issued by the
Company. Their new employment agreements also entitle them to participate in all
employee benefit plans and programs of the Company. Each agreement also provides
that if the employee is permanently disabled during the term of the Agreement,
he will continue to be employed at 50% of his base salary until the first to
occur of his death, expiration of 12 months, or expiration of the employment
agreement. Upon termination of employment by the Company without cause or after
a subsequent change of control of the Company, any unvested portion of their
options immediately vest. Upon termination of employment by the Company or the
employee following a change of control of the Company, the Company agrees to pay
the employee an amount equal to the greater of $250,000 or the remaining unpaid
base salary for the remaining term of the employment agreement and agrees to
continue all employee benefits for a period of one year. Additionally, they will
be entitled to severance payments in accordance with the Company's severance
policy which provide for a severance payment if the employee is terminated due
to a change in control in an amount determined based on the number of years of
employment, ranging from two weeks' base salary for one years' employment up to
six months base salary for employment of five years or more. The Company also
agreed to pay various temporary housing, commuting, moving and relocation
expenses of Mr. MacAluso in connection with his transfer from Houston, Texas to
Denver, Colorado. These expenses were $27,952. In addition, the Company agreed
to purchase the equity in Mr. MacAluso's house in Houston for $141,000 (based on
appraised value) and assumed the financial responsibility for its ultimate sale
which was completed in April of 2001.
Mr. War's employment agreement was also amended effective November 16, 2000
to eliminate the $75,000 termination payment payable by the Company if his
employment was terminated by the Company without cause or following a change in
control, and the $75,000 severance payment if he was terminated without cause.
Under the amended employment agreement, Mr. War was paid a bonus of $50,000 in
January 2001 upon execution of the amendment and paid another $25,000 in
December 2001. Additionally, he will be entitled to six months' base salary
($70,000) pursuant to the Company's severance policy if his employment is
terminated following a change in control prior to expiration of the term of his
employment agreement.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
The Company has no compensation committee and the full Board of Directors
determines the compensation to be paid to executive officers of the Company,
subject to approval by TCW Asset Management Company. Messrs. MacAluso and
Pennington participated in deliberations by the Board of Directors concerning
executive officer compensation during 2001.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information regarding the ownership of
Common Stock as of March 13, 2002, by each stockholder known to the Company to
own beneficially more than five percent of the outstanding Common Stock, each
current director, each Named Officer, and all executive officers and directors
of the Company as a group, based on information provided to the Company by such
persons. Except as otherwise stated, each such person has sole investment and
voting power with respect to the shares set forth in the table:
Number
Name and Address Of
of Beneficial Owner Shares Percent
------------------- ------ -------
Hampton Investments LLC (1) 2,318,186 71.7
885 Third Avenue, 34th Floor
New York, New York 10022
Inland Holdings LLC (2) 297,196 9.2
TCW Asset Management Company
865 S. Figuero, Suite 1800
Los Angeles, California 90017
Marc MacAluso(3) 150,000 4.6
410 17th Street
Suite 700
Denver, Colorado 80202
Bill I. Pennington (3) 152,168 4.7
410 17th Street
Suite 700
Denver, Colorado 80202
29
Arthur J. Pasmas (4) -- --
5858 Westheimer, Suite 400
Houston, Texas 77057
Bruce M. Schnelwar (4)
885 Third Avenue, 34th Floor -- --
New York, New York 10022
Dewey A. Stringer III 1,990 *
5858 Westheimer, Suite 400
Houston, Texas 77057
William T. War (3) 25,000 *
410 17th Street
Suite 700
Denver, Colorado 80202
All executive officers and 329,158 10.2
directors as a group
(4 persons) (3)
* Less than 1%
(1) JWA Investments IV LLC is the managing member of Hampton Investments
and may be deemed to also beneficially own these shares and John W.
Adams is the sole member of JWA Investments and may be deemed to
beneficially own these shares.
(2) Inland Holdings LLC ("Holdings") owns these shares of record and
beneficially. The members of Holdings are Trust Company of the West,
as Sub-Custodian for Mellon Bank for the benefit of Account No. CPFF
873-3032 ("Fund V"), and TCW Portfolio No. 1555 DR V Sub-Custody
Partnership, L.P. ("Portfolio"). TCW Asset Management Company has the
power to vote and dispose of the shares owned by Holdings and may be
deemed to beneficially own such shares.
(3) Includes shares issuable under outstanding stock options and warrants
granted to Messrs. MacAluso, Pennington and War and all executive
officers and directors appointees as a group for 150,000, 152,167,
25,000 and 329,158 shares, respectively.
(4) Each of Messrs. Pasmas and Schnelwar are officers of Smith Management
LLC, an affiliate of Hampton Investments, but each of them disclaims
beneficial ownership of any of the shares owned by Hampton
Investments.
In connection with Items 1 and 2 "Business and Properties - Recent Developments
- - Change of Control and Recapitalization", Holdings and Hampton Investments with
their respective affiliates have agreed to vote to ensure that (i) the Company
and Subsidiary Boards each consist of six members, subject to certain
exceptions, (ii) as long as Hampton Investments and its affiliates hold at least
a majority of the Common Stock of the Company, Hampton Investments and its
affiliates have the right to appoint at least two members to the Company and
Subsidiary Boards or, if greater, at least one-third of the members of the
Board, and (iii) as long as the provisions in the Exchange and Note Issuance
Agreement relating to Board representation are applicable, the Requisite Holders
have the right to have one or
30
more individuals designated for election to, and be elected to, the Company and
Subsidiary Boards, as provided in the Exchange and Note Issuance Agreement and
discussed above. Hampton Investments have appointed Messrs. Pasmas and Stringer
as representatives on the Board.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Exchange of Preferred Stock for Subordinated Debt. As discussed in Items 1 and 2
"Business and Properties - Recent Developments - Change of Control and
Recapitalization," the Company exchanged its Series D Preferred Stock and Series
E Preferred Stock with Inland Holdings for the TCW Subordinated Notes in the
principal amount of $98,968,964 and for a $2 million payment by the Company to
Inland Holdings.
$10 million of Subordinated Debt. As discussed in Items 1 and 2 "Business and
Properties - Recent Developments - Change of Control and Recapitalization,"
SOLVation entered into the Senior Subordinated Note Agreement ($5 million) and
the Junior Subordinated Note Agreement ($5 million) and loaned the Company $10
million.
Amended and Restated Registration Rights Agreement. In connection with the
Exchange Agreement discussed under Items 1 and 2 "Business and Properties -
Recent Developments - Change of Control and Recapitalization," pursuant to an
Amended and Restated Registration Rights Agreement (the "Registration Rights
Agreement"), dated August 2, 2001, by and among Inland Holdings, the Company and
Hampton Investments, the Company granted certain demand and piggyback
registration rights to Hampton Investments and Inland Holdings in respect of
Common Stock held by them. Under the Registration Rights Agreement, Hampton
Investments may require the Company to effect three demand registrations and
Inland Holdings may require the Company to effect one demand registration. Each
of Inland Holdings and Hampton Investments is entitled to include their shares
on any registration statement filed by the Company under the Securities Act of
1933, subject to standard underwriters' kick-out clauses and other conditions.
The Company will be responsible for paying the costs and expenses associated
with all registration statements, including the fees of one law firm acting as
counsel to the holders requesting registration but excluding underwriting
discounts and commissions and any other expenses of the party requesting
registration.
Farmout Agreement. The Company entered into a Farmout Agreement with Smith
Management LLC ("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 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 was to
receive $200,000 annually for consulting services to be provided to the Company
until September 21, 2002. The Company mutually terminated this Consulting
Agreement on August 2, 2001 with Mr. Pasmas when he was appointed Chairman of
the Board of the Company. The Company has agreed to pay Mr. Pasmas $200,000
annually for serving as Chairman of the Board. Mr. Pasmas has been Vice
President of Smith Management (or affiliated entities) since 1985.
All transactions set forth above have been approved by disinterested members of
the Board of Directors of Inland, and are considered to be fair and reasonable
to the Company.
[THIS SPACE INTENTIONALLY LEFT BLANK.]
31
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this Annual Report or
incorporated by reference:
1. Financial Statements
See "Index to Consolidated Financial Statements" on page F-1 of this Annual
Report.
2. Financial Statement Schedules
None. All financial statement schedules are omitted because the
information is not required, is not material or is otherwise included
in the consolidated financial statements or notes thereto included
elsewhere in this Annual Report.
3. (a) Exhibits
Item
Number Description
- ------ -----------
2.1 Agreement and Plan of Merger between Inland Resources Inc.
("Inland"), IRI Acquisition Corp. and Lomax Exploration
Company (exclusive of all exhibits) (filed as Exhibit 2.1 to
Inland's Registration Statement on Form S-4, Registration
No. 33-80392, and incorporated herein by this reference).
3.1 Amended and Restated Articles of Incorporation, as amended
through December 14, 1999 (filed as Exhibit 3.1 to Inland's
Current Report on Form 8-K dated September 21, 1999, and
incorporated herein by reference).
3.2 By-Laws of Inland (filed as Exhibit 3.2 to Inland's
Registration Statement on Form S-18, Registration No.
33-11870-F, and incorporated herein by reference).
3.2.1 Amendment to Article IV, Section 1 of the Bylaws of Inland
adopted February 23, 1993 (filed as Exhibit 3.2.1 to
Inland's Annual Report on Form 10-K for the year ended
December 31, 1992, and incorporated herein by reference).
3.2.2 Amendment to the Bylaws of Inland adopted April 8, 1994
(filed as Exhibit 3.2.2 to Inland's Registration Statement
on Form S-4, Registration No. 33-80392, and incorporated
herein by reference).
3.2.3 Amendment to the Bylaws of Inland adopted April 27, 1994
(filed as Exhibit 3.2.3 to Inland's Registration Statement
on Form S-4, Registration No. 33-80392, and incorporated
herein by reference).
4.1 Credit Agreement dated September 23, 1997 between Inland
Production Company ("IPC"), Inland, ING (U.S.) Capital
Corporation, as Agent, and Certain Financial Institutions,
as banks (filed as Exhibit 4.1 to Inland's Current Report on
Form 8-K dated September 23, 1997, and incorporated herein
by reference).
4.1.1 Third Amendment to Credit Agreement entered into as of April
22, 1998, amending Exhibit 4.1 (filed as Exhibit 4.1.1 to
Inland's Quarterly Report on Form 10-Q for the quarter ended
March 31, 1998, and incorporated herein by reference).
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).
32
4.1.3 First Amendment to Amended and Restated Credit Agreement
dated as of March 5, 1999 amending Exhibit 4.1.2 (filed as
Exhibit 4.1.3 to Inland's Annual Report on Form 10-K for the
year ended December 31, 1998, and incorporated herein by
reference).
4.1.4 Second Amended and Restated Credit Agreement dated September
15, 1999, but effective as of September 21, 1999, amending
and restating Exhibit 4.1 (without exhibits or schedules)
(filed as Exhibit 4.1 to Inland's Current Report on Form 8-K
dated September 21, 1999, and incorporated herein by
reference).
4.2 Credit Agreement dated September 23, 1997, among IPC,
Inland, Trust Company of the West, and TCW Asset Management
Company, in the capacities described therein (filed as
Exhibit 4.2 to Inland's Current Report on Form 8-K dated
September 23, 1997, and incorporated herein by reference).
4.2.1 Second Amendment to Credit Agreement entered into as of
April 22, 1998, amending Exhibit 4.2 (filed as Exhibit 4.2.1
to Inland's Quarterly Report on Form 10-Q for the quarter
ended March 31, 1998, and incorporated herein by reference).
4.2.2 Amended and Restated Credit Agreement dated as of September
11, 1998, amending and restating Exhibit 4.2 (filed as
Exhibit 4.2.2 to Inland's Annual Report on Form 10-K for the
year ended December 31, 1998, and incorporated herein by
reference).
4.2.3 First Amendment to Amended and Restated Credit Agreement
dated as of March 5, 1999, amending Exhibit 4.2.2 (filed as
Exhibit 4.2.3 to Inland's Annual Report on Form 10-K for the
year ended December 31, 1998, and incorporated herein by
reference).
4.2.4 Exchange Agreement dated as of September 21, 1999 by and
between Inland, IPC, Refining, Trust Company of the West, a
California trust company, as Sub-Custodian for Mellon Bank
for the benefit of Account No. CPFF 873-3032, Inland
Holdings LLC, TCW Portfolio No. 1555 DR V Sub-Custody
Partnership, L.P. and Joint Energy Development Investments
II Limited Partnership (without exhibits or schedules),
terminating Exhibits 4.2 and 4.3, as previously amended, and
Exhibits 4.4, 4.5, 10.10 and 10.11 (filed as Exhibit 10.1 to
Inland's Current Report on Form 8-K dated September 21,
1999, and incorporated herein by reference).
4.3 Intercreditor Agreement dated September 23, 1997, between
IPC, TCW Asset Management Company, Trust Company of the West
and ING (U.S.) Capital Corporation (filed as Exhibit 4.3 to
Inland's Current Report on Form 8-K dated September 23,
1997, and incorporated herein by reference).
4.3.1 Third Amendment to Intercreditor Agreement entered into as
of April 22, 1998, amending Exhibit 4.3 (filed as Exhibit
4.3.1 to Inland?s Quarterly Report on Form 10-Q for the
quarter ended March 31, 1998, and incorporated herein by
reference).
4.3.2 Amended and Restated Intercreditor Agreement dated as of
September 11, 1998, amending and restating Exhibit 4.3
(filed as Exhibit 4.3.2 to Inland's Annual Report on Form
10-K for the year ended December 31, 1998, and incorporated
herein by reference).
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
33
Inland's Current Report on Form 8-K dated September 23,
1997, and incorporated herein by reference).
4.5 Warrant issued by Inland pursuant to the Warrant Agreement,
dated September 23, 1997, representing the right to purchase
100,000 shares of Inland's Common Stock (filed as Exhibit
4.5 to Inland's Current Report on Form 8-K dated September
23, 1997, and incorporated herein by reference). 10.1 1988
Option Plan of Inland Gold and Silver Corp. (filed as
Exhibit 10(15) to Inland's Annual Report on Form 10-K for
the year ended December 31, 1988, and incorporated herein by
reference).
10.1.1 Amended 1988 Option Plan of Inland Gold and Silver Corp.
(filed as Exhibit 10.10.1 to Inland's Annual Report on Form
10-K for the year ended December 31, 1992, and incorporated
herein by reference).
10.1.2 Amended 1988 Option Plan of Inland, as amended through
August 29, 1994 (including amendments increasing the number
of shares to 212,800 and changing "formula award") (filed as
Exhibit 10.1.2 to Inland's Annual Report on Form 10-KSB for
the year ended December 31, 1994, and incorporated herein by
reference).
10.1.3 Automatic Adjustment to Number of Shares Covered by Amended
1988 Option Plan executed effective June 3, 1996 (filed as
Exhibit 10.1 to Inland's Quarterly Report on Form 10-QSB for
the quarter ended June 30, 1996, and incorporated herein by
reference).
10.2 Letter agreement dated October 30, 1996 between Inland and
Johnson Water District (filed as Exhibit 10.41 to Inland's
Annual Report on Form 10-KSB for the year ended December 31,
1996, and incorporated herein by reference).
10.3 Interest Rate Cap Agreement dated April 30, 1998 between IPC
and Enron Capital and Trade Resources Corp. (filed as
Exhibit 10.4 to Inland?s Quarterly Report on Form 10-Q for
the quarter ended March 31, 1998, and incorporated herein by
reference).
10.4 Farmout Agreement between Inland and Smith Management LLC
dated effective as of June 1, 1998 (filed as Exhibit 10.1 to
Inland?s Current Report on Form 8-K dated June 1, 1998, and
incorporated herein by reference).
10.5 Warrant Agreement dated as of March 5, 1999 between Inland
Resources Inc. and TCW Portfolio No. 1555 DR V Sub-Custody
Partnership, L.P. (filed as Exhibit 10.20 to Inland's Annual
Report on Form 10-K for the year ended December 31, 1998,
and incorporated herein by reference).
10.6 Warrant Certificate dated March 5, 1999 between Inland and
TCW Portfolio No. 1555 DR V Sub-Custody Partnership, L.P.
representing 5,852 shares (filed as Exhibit 10.21 to
Inland's Annual Report on Form 10-K for the year ended
December 31, 1998, and incorporated herein by reference).
10.7 Shareholders Agreement dated as of September 21, 1999
between Inland, Holdings, Fund V, JEDI and Pengo Securities
Corp., Smith Energy Partnership, Randall D. Smith, Jeffrey
A. Smith, Barbara Stovall Smith, John W. Adams and Arthur J.
Pasmas (collectively, the "Smith Group") (filed as Exhibit
10.2 to Inland's Current Report on Form 8-K dated September
21, 1999, and incorporated herein by reference).
10.8 Registration Rights Agreement dated as of September 21, 1999
between Inland, Holdings, Portfolio, JEDI and the Smith
Group filed as Exhibit 10.3 to Inland's Current Report on
Form 8-K dated September 21, 1999, and (incorporated herein
by reference).
34
10.9 Severance Agreement between Inland and John E. Dyer dated
November 18, 1999 (filed as Exhibit 10.13 to Inland?s Annual
Report on Form 10-K for the year ended December 31, 1999,
and incorporated herein by reference).
10.10 Employment Agreement between Inland and William T. War dated
effective as of October 1, 1999 (filed as Exhibit 10.14 to
Inland?s Annual Report on Form 10-K for the year ended
December 31, 1999, and incorporated herein by reference).
10.11 Stock Option Agreement between Inland and William T. War
dated October 1, 1999 10.11 representing 25,000 post-split
shares of Common Stock (filed as Exhibit 10.15 to Inland?s
Annual Report on Form 10-K for the year ended December 31,
1999, and incorporated herein by reference).
10.12 Amendment to Employment Agreement between Inland and William
T. War, amending the Employment Agreement filed as Exhibit
10.10.
10.13 Employment Agreement between Inland and Michael J. Stevens
dated effective as of February 1, 2001.
10.14 Employment Agreement between Inland and Marc MacAluso dated
effective as of February 1, 2001.
10.15 Stock Option Agreement between Inland and Marc MacAluso
dated effective as of February 1, 2001 representing 150,000
post-split shares of Common Stock.
10.16 Employment Agreement between Inland and Bill I. Pennington
dated effective as of February 1, 2001.
10.17 Stock Option Agreement between Inland and Bill I. Pennington
dated effective as of February 1, 2001 representing 150,000
post-split shares of Common Stock.
10.18 Oil Purchase and Delivery Agreement dated November 7, 2000.
10.19 Common Stock Purchase Agreement dated August 2, 2001 by and
between Inland Holdings, LLC ("Inland Holdings") and Hampton
Investments LLC ("Hampton Investments")(without exhibits or
schedules)(filed as Exhibit 10.1 to the Company's Current
Report on Form 8-K dated August 2, 2001, and incorporated
herein by reference).
10.20 Contribution Agreement dated August 2, 2001 by and among
Park Hampton Holdings LLC ("Hampton Holdings"), Pengo
Securities Corp. ("Pengo"), Smith Energy Partnership
("SEP"), the five individuals and Hampton Investments (filed
as Exhibit 10.2 to the Company's Current Report on Form 8-K
dated August 2, 2001, and incorporated herein by reference).
10.21 Series E Preferred Stock Purchase Agreement dated as of
August 2, 2001 by and between Hampton Investments and Inland
Holdings (without exhibits or schedules)(filed as Exhibit
10.3 to the Company's Current Report on Form 8-K dated
August 2, 2001, and incorporated herein by reference).
10.22 Termination Agreement dated as of August 2, 2001 by and
between Hampton Investments and Inland (without exhibits or
schedules)(filed as Exhibit 10.4 to the Company's Current
Report on Form 8-K dated August 2, 2001, and incorporated
herein by reference).
35
10.23 Exchange and Note Issuance Agreement dated August 2, 2001 by
and among Inland, Production and Inland Holdings (without
exhibits or schedules)(filed as Exhibit 10.5 to the
Company's Current Report on Form 8-K dated August 2, 2001,
and incorporated herein by reference).
10.24 Termination Agreement dated as of August 2, 2001 by and
among Inland and Inland Holdings (without exhibits or
schedules)(filed as Exhibit 10.6 to the Company's Current
Report on Form 8-K dated August 2, 2001, and incorporated
herein by reference).
10.25 Amended and Restated Registration Rights Agreement dated as
of August 2, 2001 by and among Inland, Inland Holdings and
Hampton Investments (without exhibits or schedules)(filed as
Exhibit 10.7 to the Company's Current Report on Form 8-K
dated August 2, 2001, and incorporated herein by reference).
10.26 Amended and Restated Shareholders Agreement dated as of
August 2, 2001 by and among Inland, Inland Holdings and
Hampton Investments (without exhibits or schedules)(filed as
Exhibit 10.8 to the Company's Current Report on Form 8-K
dated August 2, 2001, and incorporated herein by reference).
10.27 Senior Subordinated Note Purchase Agreement dated as of
August 2, 2001 by and among Inland, Production and SOLVation
(without exhibits or schedules)(filed as Exhibit 10.9 to the
Company's Current Report on Form 8-K dated August 2, 2001,
and incorporated herein by reference).
10.28 Junior Subordinated Note Purchase Agreement dated as of
August 2, 2001 by and among Inland, Production and SOLVation
(without exhibits or schedules)(filed as Exhibit 10.10 to
the Company's Current Report on Form 8-K dated August 2,
2001, and incorporated herein by reference).
*21.1 Subsidiaries of Inland.
*23.1 Consent of Arthur Andersen LLP.
*23.2 Consent of Ryder Scott Company, L.P.
*99.1 Letter to Securities and Exchange Commission dated March 26,
2002 concerning Arthur Andersen LLP.
* Filed herewith
36
(b) Reports on Form 8-K
None.
[THIS SPACE INTENTIONALLY LEFT BLANK]
37
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 26, 2002
By: /s/ MARC MACALUSO
--------------------------------------------
Marc MacAluso
Chief Executive Officer
POWER OF ATTORNEY
Each person whose signature appears below hereby appoints Bill I. Pennington as
his attorney-in-fact to sign on his behalf and in the capacity stated below and
to file all amendments to this Annual Report, which amendment or amendments may
make such changes and additions thereto as such attorney-in-fact may deem
necessary or appropriate.
March 26, 2002 /s/ ARTHUR J. PASMAS
Arthur J. Pasmas
Chairman of the Board
March 26, 2002 /s/ MARC MACALUSO
Marc MacAluso
Director, Chief Executive Officer
and Chief Operating Officer
(Principal Executive Officer)
March 26, 2002 /s/ BILL I. PENNINGTON
Bill I. Pennington
Director, President and Chief Financial Officer
(Principal Financial Officer)
March 26, 2002 /s/ BRUCE M. SCHNELWAR
Bruce M. Schnelwar
Director
March 26, 2002 /s/ DEWEY A. STRINGER III
Dewey A. Stringer III
Director
38
INDEX TO FINANCIAL STATEMENTS
Page
-----
Report of Independent Public Accountants F-2
Consolidated Balance Sheets, December 31, 2001 and 2000 F-3
Consolidated Statements of Operations for the years ended
December 31, 2001, 2000 and 1999 F-5
Consolidated Statements of Stockholders' Equity for the
years ended December 31, 2001, 2000 and 1999 F-7
Consolidated Statements of Cash Flows for the years ended
December 31, 2001, 2000 and 1999 F-8
Notes to Consolidated Financial Statements F-9
F-1
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
Inland Resources Inc.:
We have audited the accompanying consolidated balance sheets of Inland Resources
Inc. (a Washington corporation) and subsidiaries as of December 31, 2001 and
2000, and the related consolidated statements of operations, stockholders'
deficit and cash flows for each of the three years in the period ended December
31, 2001. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Inland Resources Inc. and
subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
As explained in Note 3 to the consolidated financial statements, the Company
changed its method of accounting for derivative instruments and hedging
activities on January 1, 2001.
/S/ ARTHUR ANDERSEN LLP
Denver, Colorado,
March 26, 2002.
F-2
Page 1 of 2
INLAND RESOURCES INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
December 31,
--------------------------
ASSETS 2001 2000
------ ---------- ----------
CURRENT ASSETS:
Cash and cash equivalents $ 1,949 $ 848
Accounts receivable and accrued sales 3,320 5,284
Inventory 1,192 835
Other current assets 443 381
----- -----
Total current assets 6,904 7,348
----- -----
PROPERTY AND EQUIPMENT, AT COST:
Oil and gas properties (successful efforts method) 205,535 183,959
Accumulated depletion, depreciation and amortization (43,510) (35,004)
-------- --------
Total oil and gas properties, net 162,025 148,955
Other property and equipment, net 2,230 1,997
----- -----
Total property and equipment, net 164,255 150,952
OTHER LONG-TERM ASSETS 2,217 1,765
----- -----
Total assets $173,376 $160,065
======== ========
The accompanying notes are an integral part
of the consolidated balance sheets.
F-3
Page 2 of 2
INLAND RESOURCES INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
December 31,
--------------------------
LIABILITIES AND STOCKHOLDERS' DEFICIT 2001 2000
------------------------------------- ---------- ----------
CURRENT LIABILITIES:
Accounts payable $ 4,011 $ 2,141
Accrued expenses 2,321 3,391
----- -----
Total current liabilities 6,332 5,532
LONG-TERM DEBT 83,500 83,500
SENIOR SUBORDINATED UNSECURED DEBT INCLUDING
ACCRUED INTEREST 5,228 --
SUBORDINATED UNSECURED DEBT INCLUDING
ACCRUED INTEREST 103,500 --
JUNIOR SUBORDINATED UNSECURED DEBT INCLUDING
ACCRUED INTEREST 5,228 --
------- ------
Total long term liabilities 197,456 83,500
COMMITMENTS AND CONTINGENCIES
MANDATORILY REDEEMABLE PREFERRED STOCK:
Series D Stock, 0 and 10,757,747 shares issued and outstanding,
respectively, liquidation preference of $80.7 million -- 68,273
Accrued Preferred Series D dividends -- 11,994
Series E Stock, 0 and 121,973 shares issued and outstanding, respectively,
liquidation preference of $12.2 million -- 9,120
Accrued Preferred Series E dividends -- 1,856
STOCKHOLDERS' DEFICIT:
Common stock, par value $.001; 25,000,000 shares authorized,
2,897,732 issued and outstanding 3 3
Additional paid-in capital 41,431 51,157
Accumulated other comprehensive income 5,503 --
Accumulated deficit (77,349) (71,370)
-------- --------
Total stockholders' deficit (30,412) (20,210)
-------- --------
Total liabilities and stockholders' deficit $173,376 $160,065
======== ========
The accompanying notes are an integral part
of the consolidated balance sheets.
F-4
Page 1 of 2
INLAND RESOURCES INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
For the Years Ended December 31,
----------------------------------------
2001 2000 1999
--------- -------- ---------
REVENUES:
Oil and gas sales $ 31,487 $ 28,497 $ 16,399
OPERATING EXPENSES:
Lease operating expenses 9,344 7,596 7,160
Production taxes 479 483 192
Exploration 143 135 155
Depletion, depreciation and amortization 9,106 7,816 9,882
General and administrative, net 1,486 2,128 3,136
-------- -------- --------
Total operating expenses 20,558 18,158 20,525
-------- -------- --------
OPERATING INCOME (LOSS): 10,929 10,339 (4,126)
Interest expense (12,031) (8,298) (15,989)
Unrealized derivative loss due to time value (5,548) - -
Interest and other income 626 103 72
-------- -------- --------
NET INCOME (LOSS) FROM CONTINUING OPERATIONS (6,024) 2,144 (20,043)
LOSS FROM DISCONTINUED OPERATIONS -- -- (1,774)
LOSS ON SALE OF DISCONTINUED OPERATIONS -- (250) (14,500)
-------- -------- --------
NET INCOME (LOSS) BEFORE EXTRAORDINARY LOSS
AND CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE (6,024) 1,894 (36,317)
EXTRAORDINARY LOSS ON EARLY EXTINGUISHMENT
OF DEBT -- -- (556)
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE 45 -- --
-------- -------- --------
NET INCOME (LOSS): (5,979) 1,894 (36,873)
Accrued Preferred Series C dividends -- -- (663)
Accrued Preferred Series D dividends (6,342) (9,732) (2,262)
Accrued Preferred Series E dividends (980) (1,506) (350)
Accretion of Preferred Series D discount (3,318) (6,300) (1,473)
Accretion of Preferred Series E discount (535) (900) (220)
Excess carrying value of Series E preferred over
redemption consideration 13,083 -- --
-------- -------- --------
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS $ (4,071) $(16,544) $(41,841)
======== ======== ========
The accompanying notes are an integral part
of the consolidated financial statements.
F-5
Page 2 of 2
INLAND RESOURCES INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
For the Years Ended December 31,
-----------------------------------------
2001 2000 1999
------- ------ --------
NET INCOME (LOSS) $ (5,979) $ 1,894 $ (36,873)
BASIC AND DILUTED NET LOSS PER SHARE:
Continuing operations $ (1.42) $ (5.62) $ (17.56)
Discontinued operations -- -- (1.25)
Sale of discontinued operations -- (0.09) (10.18)
Extraordinary loss -- -- (0.38)
Cumulative effect of change in accounting principle 0.02 -- --
--------- ---------- ---------
BASIC AND DILUTED NET LOSS PER SHARE $ (1.40) $ (5.71) $ (29.37)
========= ========== =========
BASIC AND DILUTED WEIGHTED AVERAGE
COMMON SHARES OUTSTANDING 2,897,732 2,897,732 1,424,439
========= ========== =========
The accompanying notes are an integral part
of the consolidated financial statements.
F-6
INLAND RESOURCES INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' DEFICIT
(In thousands, except share amounts)
Accumulated
Common Stock Additional Other
-------------------- Paid-In Comprehensive Accumulated
Shares Amount Capital Income Deficit
------ ------ ------- ------ -------
BALANCES, December 31, 1998 852,977 $1 $42,766 $ - $(35,728)
Accrued Preferred Series C dividends - - - - (663)
Common stock including Preferred Series Z
stock issued in exchange of TCW debt 1,164,295 1 21,698 - -
Common stock issued in exchange of JEDI
Preferred Series C stock 292,098 - 3,600 - -
Other 71 - - - -
Net gain under related party transaction - - 5,836 - -
Accretion of Preferred Series D discount - - (1,473) - -
Accretion of Preferred Series E discount - - (220) - -
Accrued Preferred Series D dividends - - (2,262) - -
Accrued Preferred Series E dividends - - (350) - -
Conversion of Preferred Series Z stock to common stock 588,291 1 - - -
Net loss - - - - (36,873)
--------- --- ------ ----- -------
BALANCES, December 31, 1999 2,897,732 3 69,595 - (73,264)
Accretion of Preferred Series D discount - - (6,300) - -
Accretion of Preferred Series E discount - - (900) - -
Accrued Preferred Series D dividends - - (9,732) - -
Accrued Preferred Series E dividends - - (1,506) - -
Net income - - - 1,894
--------- --- ------ ----- -------
BALANCES, December 31, 2000 2,897,732 3 51,157 - (71,370)
Accretion of Preferred Series D discount - - (3,318) - -
Accretion of Preferred Series E discount - - (535) - -
Accrued Preferred Series D dividends - - (6,342) - -
Accrued Preferred Series E dividends - - (980) - -
Series D liquidation amount upon redemption - - (9,092) - -
Series E liquidation amount upon redemption - - (2,542) - -
Excess carrying value of Series E preferred over
redemption consideration - - 13,083 - -
Comprehensive income from value of derivative contracts - - - 5,503 -
Net loss - - - - (5,979)
--------- --- ------ ----- -------
BALANCES, December 31, 2001 2,897,732 $3 $41,431 $5,503 $(77,349)
========= === ====== ===== =======
The accompanying notes are an integral part of the
consolidated financial statements.
F-7
INLAND RESOURCES INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(See Note 10)
(In thousands)
For the Years Ended December 31,
-----------------------------------
2001 2000 1999
------- ------- -------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (5,979) $ 1,894 $(36,873)
Adjustments to reconcile net income (loss) to net cash
provided (used) by operating activities
Loss from discontinued operations - 250 16,274
Depletion, depreciation and amortization 9,106 7,816 9,882
Amortization of debt issuance costs and debt discount 615 480 762
Loss on disposition of assets - 51 -
Loss on early extinguishment of debt - - 556
Noncash interest consideration - - 8,592
Cumulative effect of change in accounting principle (45) - -
Non cash changes related to derivatives 5,548 - -
Interest expense converted into debt 4,987 - -
Effect of changes in assets and liabilities-
Accounts receivable and accrued sales 1,964 (3,118) (800)
Inventory (357) 452 128
Other assets 24 (184) 16
Accounts payable and accrued expenses 800 351 (6,050)
--------- --------- ---------
Net cash provided (used) by operating activities 16,663 7,992 (7,513)
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Development expenditures and equipment purchases (22,289) (14,137) (3,772)
--------- --------- ---------
Net cash used in investing activities (22,289) (14,137) (3,772)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt 10,000 4,585 11,581
Retirement of preferred stock (2,000) - -
Payments of long-term debt - - (86)
Debt issuance costs (1,273) (500) (493)
Restructuring costs related to Series D and Series E - - (500)
--------- --------- ---------
Net cash provided by financing activities 6,727 4,085 10,502
--------- --------- ---------
NET CASH AND CASH EQUIVALENTS PROVIDED (USED)
BY CONTINUING OPERATIONS 1,101 (2,060) (783)
NET CASH AND CASH EQUIVALENTS PROVIDED
BY DISCONTINUED OPERATIONS - 1,890 526
CASH AND CASH EQUIVALENTS, at beginning of period 848 1,018 1,275
--------- --------- ---------
CASH AND CASH EQUIVALENTS, at end of period $ 1,949 $ 848 $ 1,018
========= ========== =========
The accompanying notes are an integral part
of the consolidated financial statements.
F-8
INLAND RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2001
1. BUSINESS AND SUMMARY OF SIGNIFICANT
ACCOUNTING POLICIES:
Business
Inland Resources Inc. ("Inland" or the "Company") is an independent energy
company with substantially all of its producing oil and gas property interests
located in the Monument Butte Field within the Uinta Basin of Northeastern Utah.
During the period from December 31, 1997 to January 31, 2000, the Company also
operated a crude oil refinery located in Woods Cross, Utah (the "Woods Cross
Refinery"). The refinery had a processing capacity of approximately 10,000
barrels per day and tankage capacity of 485,000 barrels. On December 10, 1999,
the Company's board of directors voted to sell the Woods Cross Refinery
operations and a nonoperating refinery pursuant to a plan of dissolution. The
sale of the Woods Cross Refinery and the nonoperating refinery closed on January
31, 2000. Certain current assets were excluded from the sale and were liquidated
pursuant to the plan of dissolution in 2000.
Consolidation
The accompanying consolidated financial statements include the accounts of the
Company and its subsidiaries, all of which are wholly-owned. All significant
intercompany accounts and transactions of continuing operations have been
eliminated in consolidation.
Reverse Split
On December 10, 1999, the Company's stockholders 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 stockholders 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' deficit have been calculated based on
post-reverse split share amounts.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States, 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 and production rates directly affect
the economics of estimated oil and gas reserves. These economics have
significant effects upon predicted reserve quantities and valuations. These
estimates are the basis for the calculation of depletion, depreciation and
amortization for the Company's oil and gas properties and the need for an
assessment as
F-9
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 held by a single financial institution, that
exceeds depository insurance limits. The Company places such deposits with
institutions that management believes are of high credit quality. The Company
has not experienced any credit losses. Substantially all of the Company's
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.
Fair Value of Financial Instruments
The Company's financial instruments consist of cash, trade receivables, trade
payables, accrued liabilities, long-term debt and derivative instruments. The
carrying value of cash and cash equivalents, trade receivables and trade
payables are considered to be representative of their fair market value, due to
the short maturity of these instruments. The fair value of variable interest
rate long-term debt approximates fair value. The fixed rate debt is unique to
the Company, as such, the fair value is not readily determinable. The estimated
fair value of derivative contracts are estimated based on market conditions in
effect at the end of each reporting period.
Inventories
Inventories consist of tubular goods valued at the lower of average cost or
market. Materials and supplies inventories are stated at cost and are charged to
capital or expense, as appropriate, when used.
Accounting for Oil and Gas Operations
The Company follows the successful efforts method of accounting for oil and gas
operations. The use of this method results in the capitalization of those costs
associated with the acquisition, exploration and development of properties that
produce revenue or are anticipated to produce future revenue. The Company does
not capitalize general and administrative expenses directly identifiable with
such activities or lease operating expenses associated with secondary recovery
startup projects. Costs of unsuccessful exploration efforts are expensed in the
period it is determined that such costs are not recoverable through future
revenues. Geological and geophysical costs are expensed as incurred. The cost of
development wells are capitalized whether productive or nonproductive. Upon the
sale of proved properties, the cost and accumulated depletion are removed from
the accounts. Any gain or loss is recorded in the results of operations.
Interest is capitalized during the drilling and completion period of wells and
on other major projects.
The provision for depletion, depreciation and amortization of developed oil and
gas properties is based on the units of production method. This method utilizes
proved oil and gas reserves determined using market prices at the end of each
reporting period. Dismantlement, restoration and abandonment costs are, in
management's opinion, offset by residual values of lease and well equipment. As
a result, no accrual for such costs is provided.
F-10
Impairment Review
The Company reviews and evaluates its long-lived assets for impairment when
events or changes in circumstances indicate that the related carrying amounts
may not be recoverable. An impairment loss is measured as the amount by which
asset carrying value exceeds fair value. A calculation of the aggregate
before-tax undiscounted future net revenues is performed for the oil and gas
properties. The Company utilizes an estimated price scenario based on its budget
and future estimates of oil and gas prices from industry projections and quoted
futures prices. The assumptions used at December 31, 2001 were based on an
average oil price of $16.84 per barrel and $2.23 per Mcf over the remaining
estimated life of the properties.
The Company also periodically assesses unproved oil and gas properties for
impairment. Impairment represents management's estimate of the decline in
realizable value experienced during the period for leases not expected to be
utilized by the Company.
In August 2001, SFAS No. 144 "Accounting for the Impairment or Disposal of
Long-Lived Assets" was issued. The statement established a single accounting
model, based on the framework of SFAS No. 121 ("Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of"), for the
long-lived assets to be disposed of by sale. The statement was adopted on
January 1, 2002 and the Company did not have any material impact upon adoption.
Property and Equipment
Property and equipment is recorded at cost. Replacements and major improvements
are capitalized, while maintenance and repairs are charged to expense as
incurred. Upon sale or retirement, the asset cost and accumulated depreciation
are removed from the accounts and any resulting gain or loss is reflected in
operations. Depreciation is calculated using the straight-line method over the
estimated useful lives of the related assets, generally ranging from three to
thirty years. Maintenance and repairs are expensed as incurred. Major
improvements are capitalized and the assets replaced are retired.
Income Taxes
The Company uses the liability method of accounting for income taxes. Under the
liability method, deferred income taxes are recorded for differences between the
book and tax basis of assets and liabilities at tax rates in effect when the
balances are expected to reverse. A valuation allowance against deferred tax
assets is recorded when the conclusion by Company management is reached that the
tax benefits, based on available evidence, are not expected to be realized.
Revenue Recognition
Sales of crude oil and natural gas are recorded upon delivery to purchasers.
Loss Per Share
Net loss per share is presented for basic and diluted net loss and, if
applicable, for net loss from discontinued operations and extraordinary losses.
Basic earnings per share is computed by dividing net loss attributable to common
stockholders by the weighted-average number of common shares for the period. The
computation of diluted earnings per share includes the effects of additional
common shares that would have been outstanding if potentially dilutive common
shares had been issued. As the Company was in a net loss available to common
stockholders position for each of the periods presented, all outstanding options
were considered antidilutive.
F-11
Comprehensive Income (Loss)
In addition to net income (loss), comprehensive loss includes all changes in
equity during a period, except those resulting from investments by and
distributions to owners. Beginning January 1, 2001, with the adoption of SFAS
No. 133, the portion of changes in fair value of derivative instruments that
qualify or had qualified for cash flow hedges is included in accumulated
comprehensive income (loss).
Recently Adopted Accounting Standards
In June 2001, SFAS No. 141 "Business Combination" and SFAS No. 142 "Goodwill and
Other Intangible Assets" were issued, which requires all business combinations
to be accounted for using the purchase method and also changes the treatment of
goodwill created in a business combination to discontinue amortization of
goodwill. The adoption of these two statements did not have an impact on the
Company's financial position or results of operations.
Additionally, SFAS No. 143 "Accounting for Asset Retirement Obligations" was
issued in July 2001. This standard requires entities to record the discounted
fair value of a liability for an asset retirement obligation as a liability.
When the liability is initially recorded, the entity capitalizes the cost by
increasing the carrying amount of the related long-lived asset. The carrying
amount of the liability is accreted to its full liability as interest expense,
and the asset previously recorded is then depreciated over the estimated useful
life. The present value of the retirement obligation is adjusted each reporting
period. The Company has not yet determined the impact of adopting this
statement, which will be required on January 1, 2003.
2. COMPREHENSIVE INCOME (LOSS):
Comprehensive loss of the Company for the year ended December 31, 2001 is as
follows:
Net loss $(5,979)
Components of other comprehensive income-
Cumulative effect of change in accounting principle $(1,972)
Change in the fair value of derivative contracts 4,534
Derivative contract settlements 2,941
-------
Ending accumulated other comprehensive income 5,503
-------
Comprehensive loss $ (476)
=======
For years ended December 31, 2000 and 1999, comprehensive income (loss) was
equal to net income (loss).
Reclassifications
Certain amounts in prior years have been reclassified to conform to the 2001
presentation.
3. FINANCIAL INSTRUMENTS:
Periodically, the Company enters into commodity contracts to hedge or otherwise
reduce the impact of oil price fluctuations. The amortized cost and the monthly
settlement gain or loss are reported as adjustments to revenue in the period in
which the related oil is sold. Hedging activities do not affect the actual sales
price for the Company's crude oil. The Company is subject to the
creditworthiness of its counterparties
F-12
since the contracts are not collateralized. The Company entered into all of its
hedging contracts with Enron North America Corp. ("ENAC").
In June 1998, SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS No. 133") was issued. This statement establishes accounting
and reporting standards for derivative instruments and hedging activity. SFAS
No. 133 requires recognition of all derivative instruments on the balance sheet
as either assets or liabilities measured at fair value. Changes in the
derivative's fair value are recognized currently in earnings unless specific
hedge accounting criteria are met. Gains and losses on derivative hedging
instruments must be recorded in either other comprehensive income or current
earnings, depending on the nature and designation of the instrument. The impact
of adopting SFAS No. 133 on January 1, 2001 resulted in recording a current
liability of $1,927,000 and recording a cumulative effect of a change in
accounting principle as accumulated comprehensive loss in the equity section of
$1,972,000 and income recorded as a cumulative effect of a change in accounting
principle of $45,000.
On December 2, 2001, ENAC filed for Chapter 11 bankruptcy . The ENAC bankruptcy
caused a default on all of the Company's hedging contracts from November 2001
through September 30, 2003. The Company recorded a non-cash loss of $5.5 million
to the statement of operations to reflect ineffectiveness of the derivative
contracts following the filing of Chapter 11 bankruptcy of ENAC. The amount that
had been deferred in accumulated other comprehensive income will be reclassified
to earnings based on the originally scheduled settlement periods of the
contracts. Non-cash amounts expected to be reclassified to earnings in 2002 and
2003 are $3,993,000 and $1,510,000, respectively. On January 30, 2002, the
Company terminated all of its hedging contracts with ENAC and determined a
potential bankruptcy claim against ENAC in excess of $7.5 million.
Crude Oil Hedging Activities
As mentioned above, the Company terminated all of its hedging contracts with
ENAC on January 30, 2002 for the years 2002 and 2003.
During the year 2001, the Company hedged 990,000 net barrels of crude oil
production under various collars and swaps from ENAC. The Company recorded a
reduction of revenue of $2.9 million under these contracts upon settlement.
During the year 2000, the Company hedged 720,000 net barrels of crude oil
production under various collars from ENAC. The Company recorded a reduction of
revenue of $6.1 million under these contracts. During the period April 1, 1999
to December 31, 1999, the Company hedged oil production under two contracts from
ENAC. The contracts were structured as swaps covering 80,000 net barrels per
month at an average strike price of $14.28. The Company recorded a reduction to
revenue of $4.9 million under these contracts during 1999.
On March 11, 2002, the Company hedged 30,000 net barrels per month with Equiva
Trading Company for the April 2002 to December 2002 period using a swap with a
settlement amount of $23.90 per barrel.
F-13
4. LOSS PER SHARE:
The calculation of loss per share for the years ended December 31, 2001, 2000
and 1999 is as follows (in thousands, except per share data):
2001 2000 1999
-------------------------- ------------------------ -------------------------
Income Per Share Per Share Per Share
(Loss) Shares Amount Loss Shares Amount Loss Shares Amount
------ ------ ------ ---- ------ ------ ---- ------ ------
Income (loss) from continuing
operations $(6,024) $ 2,144 $(20,043)
Accrued Preferred Series C dividends -- -- (663)
Accrued Preferred Series D dividends (6,342) (9,732) (2,262)
Accrued Preferred Series E dividends (980) (1,506) (350)
Accretion of Series D discount (3,318) (6,300) (1,473)
Accretion of Series E discount (535) (900) (220)
Excess carrying value of Series E
Preferred over redemption
consideration 13,083 -- --
------- ------- -------
BASIC AND DILUTED LOSS
PER SHARE:
Loss from continuing operations
attributable to common
stockholders $(4,116) 2,898 $(1.42) $(16,294) 2,898 $(5.62) $(25,011) 1,424 $(17.56)
======== ======= ======== ===== ======= ======
5. RESTRUCTURING TRANSACTIONS:
1999 Exchange Agreement
On September 21, 1999, the Company entered into an Exchange Agreement (the
"Exchange Agreement") with Trust Company of the West and affiliated entities
("TCW") and Joint Energy Development Investments II Limited Partnership ("JEDI")
pursuant to which TCW agreed to exchange certain indebtedness and warrants to
purchase Common Stock, for shares of Common Stock and two new series of
Preferred Stock of the Company, and JEDI agreed to exchange 100,000 shares of
Series C Preferred Stock of the Company for shares of Common Stock and a third
new series of Preferred Stock of the Company.
Pursuant to the Exchange Agreement, TCW agreed to exchange $75.0 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.
The Series D Preferred Stock accrued dividends at a rate of $0.16875 per share
per quarter (9% annual rate) if paid in cash on a current basis or $0.2109375
per share per quarter (11.25% annual rate compounded quarterly) if accumulated
and not paid on a current basis. No dividends were paid on Common Stock or any
other series of preferred stock as there were accrued and unpaid dividends on
the Series D Preferred Stock. The Series D Preferred Stock also had liquidation
preference over all other classes and series of stock, in an amount equal to
$7.50 per share ($80.7 million). The difference between the book value and the
liquidation value of the Series D Preferred Stock at the exchange date ($20.2
F-14
million) was being accreted over the minimum redemption period beginning on
April 1, 2002, and resulted in a charge against earnings available for common
stockholders until it was exchanged on August 2, 2001 as discussed below.
The Series E Preferred Stock accrued dividends at a rate of $2.3125 per share
per quarter (9.25% annual rate) if paid in cash on a current basis or $2.875 per
share per quarter (11.5% annual rate compounded quarterly) if accumulated and
not paid on a current basis. No dividends were paid on Common Stock as there
were accrued and unpaid dividends on the Series E Preferred Stock. The Series E
Preferred Stock also had liquidation preference over all other classes and
series of stock, except the Series D Preferred Stock, in an amount equal to
$100.00 per share ($12.2 million). The difference between the book value and the
liquidation value of the Series E Preferred Stock at the exchange date ($4.2
million) was being accreted over the minimum redemption period to April 1, 2004,
and resulted in a charge against earnings available for common stockholders
until exchanged on August 2, 2001, as discussed below.
One of the conditions to closing the Exchange Agreement in 1999 was that
Inland's senior lenders would enter into a restructuring of the senior credit
facility acceptable to TCW, JEDI and the Company. As a result, effective as of
September 21, 1999, the Company entered into the Second Amended and Restated
Credit Agreement (the "Fortis Credit Agreement") whose current participants are
Fortis Capital Corp. and U.S. Bank National Association (the "Senior Lenders")
pursuant to which the Senior Lenders agreed to increase the borrowing base from
$73.25 million to $83.5 million, inclusive of a sublimit for letters of credit
of $4.0 million.
The Company also amended its Farmout Agreement with Smith Energy Partnership
("Smith") in conjunction with the financial restructuring on September 21, 1999.
As a result of this Amendment, and the fact that the Company has no further
obligations in relation to these properties, the production loan previously
recorded by the Company was no longer considered outstanding. 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.
March 2001 Transaction
On March 20, 2001, Hampton Investments LLC ("Hampton") an affiliate of Smith
Management LLC, purchased from JEDI the 121,973 shares of Series E Preferred
Stock and 292,098 shares of Common Stock acquired by JEDI in the Exchange
Agreement. Following closing of the Exchange Agreement and the purchase by
Hampton of JEDI's shares, TCW owned at that time 1,752,586 shares of Common
Stock, representing approximately 60.5% of the outstanding shares of Common
Stock, and Hampton owned at that time 292,098 shares of Common Stock,
representing approximately 10.1% of the outstanding shares of Common Stock.
Various persons and entities that may be considered related to Hampton owned an
additional 548,338 shares of Common Stock, so that together with Hampton such
persons, entities and Hampton, owned an aggregate of 840,436 shares of Common
Stock at the time of the March 2001 transaction.
August 2001 Transaction
On August 2, 2001, the Company closed two subordinated debt transactions
totaling $10 million in aggregate with SOLVation Inc. ("SOLVation"), a company
affiliated with Smith Management LLC, and entered into other restructuring
transactions as described below. The first of the two debt transactions with
SOLVation was the issuance of a $5 million unsecured senior subordinated note to
SOLVation due July 1, 2007. The interest rate is 11% per annum compounded
quarterly.
F-15
The Company also issued a second $5 million unsecured junior subordinated note
to SOLVation. The interest rate is 11% per annum compounded quarterly. The
maturity date is the earlier of (i) 120 days after payment in full of the TCW
subordinated debt or (ii) March 31, 2010. Interest is payable in arrears in cash
subject to the approval from the senior bank group and accumulates if not paid
in cash.
In conjunction with the issuance of the two subordinated notes to SOLVation, the
Series D Preferred and Series E Preferred stock held by Inland Holdings LLC, a
company controlled by TCW were exchanged for an unsecured subordinated note due
September 30, 2009 and $2 million in cash from the Company. The note amount was
for $98,968,964 that represented the face value plus accrued dividends of the
Series D Preferred stock as of August 2, 2001. The interest rate on this debt is
11% per annum compounded quarterly. As a result of the exchange, the Company
retired both the Series D and Series E Preferred stock. Due to the related party
nature of this transaction, the difference between the aggregate subordinated
note balance and $2 million cash paid to TCW, and the aggregate liquidation
value of the Series D and Series E Preferred Stock plus accrued dividends, was
recorded as an increase of $13,083,000 to additional paid-in capital.
As part of this restructuring, TCW also sold to Hampton 1,455,390 shares of
common stock in the Company held by TCW (consequently, Hampton now controls
approximately 80% of the issued and outstanding shares of the Company),
terminated any existing option rights to the Company's common stock, and
relinquished the right to elect four persons to the Company's Board of
Directors. However, TCW has the right to nominate one person to the Company's
Board. Remaining Board members will be nominated by the Company's stockholders.
As long as Hampton or its affiliates own at least a majority of the common stock
of the Company, Hampton has agreed with TCW that Hampton will have the right to
appoint at least two members to the Board.
6. 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 assets and liabilities were disposed of during 2000.
As a result of this sale, the Company is no longer involved in the refining of
crude oil or the sale of refined products. As a result, all refining operations
have been classified as discontinued operations in the accompanying consolidated
financial statements. To account for the sale, the Company recorded a loss on
sale of discontinued operations of $14.5 million at December 31, 1999. The
Company recorded an additional loss of $250,000 to reflect adjustments to the
final disposal costs associated with the refinery. In addition, certain prior
year amounts were reclassified as discontinued operations, with no net effect on
net loss or accumulated deficit as previously reported. Revenue from
discontinued operations was $70.3 million during the year ended December 31,
1999.
F-16
7. OTHER PROPERTY AND EQUIPMENT:
December 31,
---------------------------
2001 2000
--------- -------
(in thousands)
Estimated
Useful Lives
------------
Vehicles 3 Years $ 1,554 $ 1,599
Buildings 20-30 Years 1,013 967
Furniture and fixtures 3 Years 1,326 1,258
Leasehold improvements 5 Years 86 86
Land 36 36
----- -----
4,015 3,946
Less: accumulated depreciation (1,785) (1,949)
----- -----
Total $ 2,230 $ 1,997
======== =======
8. LONG-TERM DEBT (See Note 5):
Fortis Credit Agreement
Effective September 21, 1999, the Company entered into a credit agreement (the
"Fortis Credit Agreement") whose current participants are Fortis Capital Corp.
and U.S. Bank National Association (the "Senior Lenders").
In conjunction with the August 2, 2001 SOLVation financing, the Senior Lenders
amended the Fortis Credit Agreement to change the maturity date to June 30, 2007
from April 1, 2002, or potentially earlier if the borrowing base is determined
to be insufficient. Interest accrues under the Fortis Credit Agreement, at the
Company's option, at either (i) 2% above the prime rate or (ii) at various rates
above the London Interbank Offering Rate ("LIBOR") rate. The LIBOR rates will be
determined by the senior debt to EBITDA ratios starting August 2, 2001. If the
senior debt to EBITDA ratio is greater than 4.00 to 1.00, the rate is 3.25%
above the LIBOR rate; if the senior debt to EBITDA ratio is equal to or less
than 4.00 to 1.00 but greater than 3.00 to 1.00, the rate is 2.75% above the
LIBOR rate; if the senior debt to EBITDA ratio is less than 3.00 to 1.00, the
rate is 2.25% above the LIBOR rate. As of December 31, 2001, $83 million and
$500,000 were borrowed under the LIBOR option at interest rates of 6.27% and
4.65%, respectively. The revolving termination date is June 30, 2004 at which
time the loan converts into a term loan payable in 12 equal quarterly
installments of principal, with accrued interest, beginning September 30, 2004.
The Fortis Credit Agreement has covenants that restrict the payment of cash
dividends, borrowings, sale of assets, loans to others, investments, merger
activity and hedging contracts without the prior consent of the lenders and
requires the Company to maintain certain net worth, interest coverage and
working capital ratios. The borrowing base is calculated as the collateral value
of proved reserves. The borrowing base is subject to ongoing redeterminations on
or before March 31, 2002 and with subsequent determinations to be made on each
subsequent October 1 and April 1. The April 1, 2002 determination was received
on March 26, 2002 and was $83.5 million. If the borrowing base is lower than the
outstanding principal balance then drawn, the Company must immediately pay the
difference. The Company was in compliance of its bank covenants as December 31,
2001. The Fortis Credit Agreement is secured by a first lien on substantially
all assets of the Company. At December 31, 2001, the Company had advanced all
funds under its current borrowing base of $83.5 million. The Fortis Credit
Agreement was amended on March 25, 2002.
F-17
Subordinated Unsecured Debt to
SOLVation Inc.
As discussed in Note 5, on August 2, 2001, the Company closed two subordinated
debt transactions totaling $10 million in aggregate with SOLVation Inc. The
first of the two debt transactions with SOLVation was the issuance of a $5
million unsecured senior subordinated note to SOLVation due July 1, 2007. The
interest rate is 11% per annum compounded quarterly. The interest payment is
payable in arrears in cash subject to the approval from the senior bank group
and accumulates if not paid in cash. The Company is not required to make any
principal payments prior to the July 1, 2007 maturity date. However, the Company
is required to make payments of principal and interest in the same amounts as
any principal payment or interest payments on the TCW subordinated debt
(described below). Prior to the July 1, 2007 maturity date, subject to the bank
subordination agreement, the Company may prepay the senior subordinated note in
whole or in part with no penalty.
The Company also issued a second $5 million unsecured junior subordinated note
to SOLVation. The interest rate is 11% per annum compounded quarterly. The
maturity date is the earlier of (i) 120 days after payment in full of the TCW
subordinated debt or (ii) March 31, 2010. Interest is payable in arrears in cash
subject to the approval from the senior bank group and accumulates if not paid
in cash. The Company is not required to make any principal payments prior to the
March 31, 2010 maturity date. Prior to the March 31, 2010 maturity date, subject
to both bank and subordination agreements, the Company may prepay the junior
subordinated note in whole or in part with no penalty. A portion of the proceeds
from the senior and junior subordinated notes was used to fund a $2 million
payment to TCW and other Company working capital needs.
Subordinated Unsecured Debt to TCW
As discussed in Note 5, in conjunction with the issuance of the two subordinated
notes to SOLVation, the Series D Preferred and Series E Preferred stock held by
Inland Holdings LLC, a company controlled by TCW, were exchanged for an
unsecured subordinated note due September 30, 2009 and $2 million in cash from
the Company. The note amount was for $98,968,964 that represented the face value
plus accrued dividends of the Series D Preferred stock as of August 2, 2001. The
interest rate is 11% per annum compounded quarterly. Interest shall be payable
in arrears in cash subject to the approval from the senior bank group and
accumulates if not paid in cash. Interest payments will be made quarterly,
commencing on the earlier of September 30, 2005 or the end of the first calendar
quarter after the senior bank debt has been reduced to $40 million or less,
subject to both bank and senior subordination agreements. Beginning the earlier
of two years prior to the maturity date or the first December 30 after the
repayment in full of the senior bank debt, subject to both bank and senior
subordination agreements, the Company will make equal annual principal payments
of one third of the aggregate principal amount of the TCW subordinated note. Any
unpaid principal or interest amounts are due in full on the September 30, 2009
maturity date. Prior to the September 30, 2009 maturity date, subject to both
bank and senior subordination agreements, the Company may prepay the TCW
subordinated note in whole or in part with no penalty.
F-18
A summary of the Company's long-term debt (including accrued unpaid interest)
follows (in thousands):
December 31,
----------------------
2001 2000
------- -------
Fortis Credit Agreement $83,500 $83,500
Senior Subordinated Unsecured Debt including accrued interest 5,228 -
Subordinated Unsecured Debt including accrued interest 103,500 -
Junior Subordinated Unsecured Debt including accrued interest 5,228 -
------- ------
Total long-term debt $197,456 $83,500
======= ======
Outstanding debt at December 31, 2001 is payable as follows (in thousands):
2002 $ -
2003 -
2004 13,918
2005 36,894
2006 27,832
Thereafter 118,812
-------
Total long-term debt $197,456
=======
9. INCOME TAXES:
In 2001, 2000 and 1999, 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, 2001 and 2000 is as follows
(in thousands):
December 31, December 31,
2001 2000
----------- ------------
Deferred tax assets:
Net operating loss carryforwards $ 32,158 $ 29,051
Derivative loss 2,052 -
Valuation allowance (21,608) (19,397)
-------- --------
Deferred tax assets 12,602 9,654
-------- --------
Deferred tax liabilities:
Depletion, depreciation and amortization
of property and equipment (12,602) (9,654)
-------- --------
Deferred tax liabilities (12,602) (9,654)
-------- --------
Net deferred tax assets $ - $ -
======== ========
F-19
A valuation allowance is to be provided if it is more likely than not that some
portion or all of a deferred tax asset will not be realized. The Company's
ability to realize the benefit of its tax assets depends on the generation of
future taxable income through profitable operations and expansion of the
Company's oil and gas producing properties. The market, capital and
environmental risks associated with that growth requirement caused the Company
to conclude that a valuation allowance should be provided, except to the extent
that the benefit of operating loss carryforwards can be used to offset future
reversals of existing deferred tax liabilities. The Company will continue to
monitor the need for the valuation allowance that has been provided.
Income tax expense for 2001, 2000 and 1999 differed from amounts computed by
applying the statutory federal income tax rate as follows (in thousands):
For the Year December 31,
-----------------------------------------
2001 2000 1999
------ ------- -------
Expected statutory tax expenses at 34% $(2,032) $ 644 $(12,537)
Change in valuation allowance, net 2,211 (492) 12,514
Other (179) (152) 23
------ ------- -------
Net tax expense $ - $ - $ -
====== ======= =======
No state or federal income taxes are payable at December 31, 2001 or 2000, and
the Company did not pay any income taxes in 2001, 2000 or 1999. At December 31,
2001, the Company had tax basis net operating loss carryforwards available to
offset future regular and alternative taxable income of $86 million that expire
from 2002 to 2021. Utilization of the net operating loss carryforwards are
limited under the change of ownership tax rules.
10. SUPPLEMENTAL DISCLOSURE OF
CASH FLOW INFORMATION:
Cash paid for interest during 2001, 2000 and 1999 was approximately $6,428,000,
$7,857,000 and $6,112,000, respectively.
As a result of the restructuring discussed in Note 5, the Company converted
Preferred Stock to debt in the amount of $98,968,964, during 2001.
In 2000, the Company sold surface land to a former officer of the Company for
the assumption of a note payable of $167,000, by the former officer, that had
previously been recorded on the Company's financial statements.
As part of the Smith Farmout restructuring described in Note 5, the following
accounts were impacted in 1999:
Oil and gas properties $(13,833)
Accumulated depletion, depreciation and amortization 2,837
Deferred debt offering costs (233)
Smith Farmout loan 15,085
Smith Farmout accrued interest 2,792
Additional paid-in capital (5,837)
F-20
11. COMMITMENTS AND CONTINGENCIES:
Lease Commitments
The Company leases 16,500 square feet of office space under a noncancellable
operating lease that expires in 2002. Future payments under this lease are
estimated at $300,000 for 2002. Total lease expense during 2001, 2000 and 1999
was $299,000, $300,000 and $264,000, respectively.
401(k) Plan
The Company provides a voluntary 401(k) employee savings plan which covers all
full-time employees who meet certain eligibility requirements. Voluntary
contributions are made to the 401(k) plan by participants. In addition, the
Company matches 100% of the first 6% of salary contributed by each employee.
During the period January 1, 1999 to September 30, 1999, the Company match was
reduced to 100% of the first 2% of salary contributed. Matching contributions of
$224,000, $191,000 and $104,000 were made by the Company during 2001, 2000 and
1999, respectively.
Legal Proceedings
The Company is from time to time involved in various legal proceedings
characterized as normally incidental to the business. Management believes its
defenses to any existing litigation will be meritorious and any adverse
decisions in any pending or threatened proceedings or any amounts which it may
be required to pay by reason thereof will not have a material adverse effect on
its financial condition or results of operations.
Consulting and Employment Agreements
The Company entered into a consulting agreement on September 21, 1999 with a
former director of the Company 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. The consulting agreement was terminated as part of the
SOLVation transaction as described in Note 5.
The Company has employment agreement with certain employees of the Company which
provide for payment to the employees upon termination following a change in
control.
12. STOCK OPTIONS:
1988 Stock Option Plan
On August 25, 1988, the Company's Board of Directors adopted an incentive stock
option plan (the "1988 Plan") for the benefit of key employees and directors of
the Company. A total of 21,280 shares of common stock are reserved for issuance
under the 1988 Plan. All options under the 1988 Plan are granted, exercisable
and expire 10 years from the date of grant.
1997 Stock Option Plan
On April 30, 1997, the Company's Board of Directors adopted an incentive stock
option plan (the "1997 Plan") for the benefit of key employees and directors of
the Company. Options under the 1997 Plan vest based upon the determination made
by the Company's Compensation Committee at the time of grant, and expire 10
years from the date of grant. The Company reserved 50,000 shares for grant under
the 1997 Plan of which 41,850 options were granted through December 31, 2001 at
prices equal to the market
F-21
value of the Company's stock on the date of grant. All granted options are
vested. There are 8,150 shares available for grant as of December 31, 2001.
A summary of option grants, exercises and average prices under both the 1988
Plan and the 1997 Plan is presented below:
Weighted Option Weighted
Average Exercise Fair Value
Number of Exercise Price of Options
Options Price Range Granted
--------- --------- ---------------- -----------
Balance, December 31, 1998 24,590 $76.40 $25.00 - $115.00
Granted 30,000 10.00 10.00 - 10.00 $ 8.23
=====
Cancelled (4,474) 39.10 25.00 - 68.70
Expired (1,800) 115.00 115.00 - 115.00
-------- ------ -----------------
Balance, December 31, 1999 48,316 37.20 10.00 - 110.00
Cancelled (26,580) 29.50 10.00 - 110.00
-------- ------ -----------------
Balance, December 31, 2000 21,736 46.88 10.00 - 110.00
Cancelled (11,340) 47.94 10.00 - 110.00
Expired (1,156) 51.27 10.00 - 110.00
-------- ------ -----------------
Balance, December 31, 2001 9,240 $ 45.02 $10.00 - $110.00
======= ======== ================
Plan options exercisable as of
December 31, 2001 9,240 $ 45.02
======= ========
Non-Plan Grants
From time to time the Company grants nonqualified ("Non-Plan") options to
purchase common stock to its executive officers. The grants have vesting periods
of three to five years. These grants were made at fair value. The grants' lives
are six to eight years. The table below summarizes the activities associated
with these grants to executive officers:
Weighted Option Weighted
Average Exercise Fair Value
Number of Exercise Price of Options
Options Price Range Granted
--------- -------- ---------------- ------------
Balance, December 31, 1998 94,692 $82.10 $ 31.30 - $110.00
Granted 141,700 9.38 9.38 - 9.38 $7.22
=====
Cancelled (90,192) 82.60 31.25 - 110.00
-------- ------ -----------------
Balance, December 31, 1999 146,200 10.42 9.38 - 100.00
Cancelled (4,500) 95.56 90.00 - 100.00
-------- ------ -----------------
Balance, December 31, 2000 141,700 9.38 9.38 - 9.38
Granted 300,000 2.11 1.63 - 2.84 $1.49
=====
Cancelled (116,700) 9.38 9.38 - 9.38
-------- ------ -----------------
Balance, December 31, 2001 325,000 $ 2.67 $ 1.63 - 9.38
======== ====== =================
Non-Plan options exercisable
as of December 31, 2001 225,000 $ 2.92
======== ======
F-22
The following table summarizes information for options outstanding as of
December 31, 2001 for all Plan and Non-Plan options.
Options Outstanding Options Exercisable
----------------------------------------------- ------------------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Range of Contractual Life Exercise Exercise
Exercise Price Number (Years) Price Number Price
-------------- ------ ---------------- --------- --------- ---------
$ 1.68 - $ 2.84 300,000 6.3 $ 2.11 200,000 $ 2.11
$ 9.38 - $ 10.00 29,000 7.9 9.46 29,000 9.46
$ 25.00 - $ 37.50 1,160 2.5 32.97 1,160 32.97
$ 40.63 - $ 50.00 880 2.9 45.99 880 45.99
$ 84.40 - $ 90.00 2,400 5.9 87.20 2,400 87.20
$110.00 800 6.9 110.00 800 110.00
------- --- --------- ------- ---------
334,240 6.4 $ 3.84 234,240 $ 4.58
======= === ========= ======= =========
All options cancelled and reissued are subject to the criteria of the FASB
Interpretation No. 44 "Accounting for Certain Transactions Involving Stock
Compensation - an Interpretation of APB Opinion No. 25" ("FIN 44"). In 1999,
33,500 options were cancelled and reissued at market price. These options are
being accounted for as a variable option grant based on the market price on July
1, 2000. These options have been marked-to-market with gains and losses recorded
in income for each reporting period subsequent to July 1, 2000 to the extent
there are increases in the Company's stock price above the market rate value of
the stock on July 1, 2000. There was no adjustment made for these options in the
years ended December 31, 2001 and 2000 as the stock price has not exceeded the
stock price in effect on July 1, 2000. During 2001, 116,700 Non-Plan options at
an exercise price of $9.38 were cancelled and 300,000 new Non-Plan options were
granted. The grant price for the new options was $1.63 for 180,000 and $2.84 for
120,000. These options are accounted for as variable option grants. There were
no adjustments made for these options in the year ended December 31, 2001, as
the market rate of the Company's stock has not exceeded the grant price of the
options.
The Company has elected to account for grants of stock options and warrants
granted to employees and non-employee directors of the Company under APB Opinion
No. 25 and its interpretations. If compensation expense for grants of stock
options and warrants had been determined consistent with Statement of Financial
Accounting Standards No. 123, "Accounting for Stock-Based Compensation," the
Company's net loss and loss per share ("LPS") would have been the following pro
forma amounts (in thousands, except per share data):
2001 2000 1999
---- ---- ----
Net loss, attributable
to common stockholders As reported $(4,071) $(16,544) $(41,841)
Pro forma (4,419) (16,991) (42,376)
Basic and Diluted LPS As reported $ (1.40) $ (5.71) $ (29.37)
Pro forma (1.53) (5.86) (29.76)
F-23
The pro forma adjustments are calculated using an estimate of the fair value of
each option on the date of grant. The options granted in 2001 and 1999 were
estimated using the following weighted average assumptions. No options were
granted during 2000.
2001 1999
------- -------
Weighted average remaining life 5 years 5 years
Risk-free interest rate 4.7% 6.0%
Expected dividend yield 0% 0%
Expected lives 5 years 5 years
Expected volatility 152.4% 113.2%
13. OIL AND GAS PRODUCING ACTIVITIES:
Major Customers
Sales to the following companies represented 10% or more of the Company's
revenues, not including effects of hedging, (in thousands):
2001 2000 1999
------- ------- ------
Crude Oil:
BP $15,101 $17,016 $4,858
Chevron 9,497 11,611 -
Gas:
Wasatch 7,622 5,556 -
Cost Incurred in Oil and Gas Producing Activities (in thousands):
2001 2000 1999
------ ------ ------
Unproved property acquisition cost $ - $ 33 $ -
Development cost 21,576 13,709 3,512
Exploration cost 143 135 155
------ ------ -----
Total $21,719 $13,877 $3,667
====== ====== =====
F-24
Net Capital Costs
Net capitalized costs related to the Company's oil and gas producing activities
are summarized as follows (in thousands):
2001 2000 1999
------ ------ ------
Unproved properties $ 2,894 $ 3,797 $ 4,410
Proved properties 195,769 174,348 160,889
Gas transportation facilities 6,872 5,814 4,918
-------- -------- --------
Total 205,535 183,959 170,217
Accumulated depletion, depreciation and
amortization (43,510) (35,004) (27,805)
-------- -------- --------
Total $162,025 $148,955 $142,412
======== ======== ========
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% ("PV10%") annual discount factor.
The assumptions used to compute the standardized measure are those prescribed by
the Financial Accounting Standards Board and, as such, do not necessarily
reflect the Company's expectations of actual revenues to be derived from those
reserves nor their present worth. The limitations inherent in the reserve
quantity estimation process are equally applicable to the standardized measure
computations since these estimates are the basis for the valuation process.
The following summary sets forth the Company's future net cash flows relating to
proved oil and gas reserves based on the standardized measure prescribed in SFAS
No. 69 (in thousands):
December 31,
------------------------------------------
2001 2000 1999
---------- --------- ---------
Future cash inflows $ 1,102,973 $1,633,382 $1,127,531
Future production costs (351,973) (292,305) (259,022)
Future development costs (192,672) (202,071) (189,297)
Future income tax provision (145,950) (369,220) (188,630)
---------- --------- ---------
Future net cash flows 412,378 769,786 490,582
Less effect of 10% discount factor (254,683) (445,360) (292,270)
---------- --------- ---------
Standardized measure of discounted
future net cash flows $ 157,695 $ 324,426 $ 198,312
========== ========== ==========
F-25
The principal sources of changes in the standardized measure of discounted
future net cash flows are as follows for the years ended December 31, 2001, 2000
and 1999 (in thousands):
2001 2000 1999
------ ------ ------
Standardized measure, beginning of year $324,426 $198,312 $ 54,113
Sales of reserves in place - - (15,548)
Sales of oil and gas produced excluding
hedging, net of production costs (24,276) (26,501) (13,919)
Net change in sales prices and production costs (271,039) 168,192 123,905
Extensions, discoveries and improved
recovery, net 5,566 12,269 -
Revisions of previous quantity estimates 44,898 8,667 349,080
Change in future development costs 12,176 (7,396) (111,348)
Net change in income taxes 87,208 (66,753) (55,855)
Accretion of discount 44,703 25,417 5,411
Changes in production rates and other (65,967) 12,219 (137,527)
-------- -------- ---------
Standardized measure, end of year $157,695 $324,426 $ 198,312
======== ======== =========
Oil and Gas Reserve Quantities (Unaudited)
The reserve information presented below is based upon reports prepared by the
Company's in-house petroleum engineer. The independent petroleum engineering
firm of Ryder Scott Company, L.P. reviewed 80% of the PV10% value of the
reserves. The Company emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of producing
oil and gas properties. As a result, revisions to previous estimates are
expected to occur as additional production data becomes available or economic
factors change.
Proved oil and gas reserves are estimated quantities of crude oil, natural gas
and natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Proved developed oil and gas
reserves are those expected to be recovered through existing wells with existing
equipment and operating methods. The fluctuation of oil and gas prices has a
significant impact on the standardized measure. Future increases or decreases in
oil or gas prices increase or decrease the value of the standardized measure
accordingly. As of December 31, 2001, the Company used prices of $16.84 per Bbl
and $2.23 per Mcf which is reflective of the market price at yearend. Prices
used by the Company in 2000 were $23.78 per Bbl and $7.73 per Mcf. Prices used
by the Company in 1999 were $21.56 per Bbl and $1.83 per Mcf.
F-26
Presented below is a summary of the changes in estimated proved reserves of the
Company, all of which are located in the United States, for the years ended
December 31, 2001, 2000 and 1999:
2001 2000 1999
------------------------- ------------------------ ------------------------
Oil (MBbl) Gas (MMcf) Oil (MBbl) Gas (MMcf) Oil (MBbl) Gas (MMcf)
---------- ---------- ---------- ---------- ---------- ----------
Proved reserves, beginning of year 47,159 66,187 47,129 60,935 18,602 18,063
Sales of reserves in place - - - - (2,487) (3,100)
Extensions and discoveries - - 660 1,584 - -
Improved recoveries 1,324 629 400 200 - -
Production (1,212) (2,423) (1,072) (2,289) (1,165) (2,901)
Revisions of previous estimates 7,300 18,114 42 5,757 32,179 48,873
------ ------ ------ ------ ------ ------
Proved reserves, end of year 54,571 82,507 47,159 66,187 47,129 60,935
====== ====== ====== ====== ====== ======
Proved developed reserves,
end of year 18,409 20,682 17,531 13,647 16,634 15,476
====== ====== ====== ====== ====== ======
14. QUARTERLY EARNINGS (UNAUDITED):
Summarized unaudited quarterly financial data for 2001 and 2000 is as follows
(in thousands, except per share data):
Quarter Ended
-------------------------------------------------------------------
March 31, June 30, September 30, December 31,
2001 2001 2001 2001
------------- --------- -------- -------------
Revenues $ 8,169 $8,572 $8,103 $ 6,643
Operating income 3,287 (1) 3,384 2,772 1,486
Net income (loss) 867 (1) 1,720 (310) (8,256) (2)
Basic and diluted loss
per share attributable to
common stockholders $(1.42) (1) $(1.01) $ 3.87 $ (2.84)
Quarter Ended
----------------------------------------------------------------
March 31, June 30, September 30, December 31,
2000 2000 2000 2000
-------- -------- ------------ -----------
Revenues $ 6,094 $ 7,063 $ 7,461 $ 7,879
Operating income 2,059 2,878 2,638 2,764
Net income 77 847 209 761
Basic and diluted loss
per share attributable to
common stockholders $(1.56) $(1.30) $(1.52) $(1.33)
(1) Operating income and net income for the quarter ended March 31, 2001 were
adjusted for the reversal of a non-cash charge related to the stock option
repricing discussed in Note 12.
(2) Includes a non-cash loss of $5.5 million related to the loss of
effectiveness of derivative contracts following the filing of Chapter 11
bankruptcy of ENAC, as discussed in Note 3.
15. SUBSEQUENT EVENT (UNAUDITED):
On March 22, 2002, Questar Pipeline Company ("QPC") curtailed all gas
producers in the Monument Butte Field, including Inland, for not meeting certain
QPC specifications. After curtailment, Inland is producing and transporting
approximately 50% of its total gas capacity. The Company is in the process of
installing a gas liquid plant in the Field that would bring all of its gas up to
QPC's pipeline specifications. The gas liquid plant will be operational in
approximately 60 days. The Company believes that the current gas curtailment is
not significant to the Company's operations.
F-27
Exhibit Index
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).
4.1.2 Amended and Restated Credit Agreement dated as of September
11, 1998 amending and restating Exhibit 4.1 (filed as
Exhibit 4.1.2 to Inland's Annual Report on Form 10-K for the
year ended December 31, 1998, and incorporated herein by
reference).
4.1.3 First Amendment to Amended and Restated Credit Agreement
dated as of March 5, 1999 amending Exhibit 4.1.2 (filed as
Exhibit 4.1.3 to Inland's Annual Report on Form 10-K for the
year ended December 31, 1998, and incorporated herein by
reference).
4.1.4 Second Amended and Restated Credit Agreement dated September
15, 1999, but effective as of September 21, 1999, amending
and restating Exhibit 4.1 (without exhibits or schedules)
(filed as Exhibit 4.1 to Inland's Current Report on Form 8-K
dated September 21, 1999, and incorporated herein by
reference).
4.2 Credit Agreement dated September 23, 1997, among IPC,
Inland, Trust Company of the West, and TCW Asset Management
Company, in the capacities described therein (filed as
Exhibit 4.2 to Inland's Current Report on Form 8-K dated
September 23, 1997, and incorporated herein by reference).
4.2.1 Second Amendment to Credit Agreement entered into as of
April 22, 1998, amending Exhibit 4.2 (filed as Exhibit 4.2.1
to Inland's Quarterly Report on Form 10-Q for the quarter
ended March 31, 1998, and incorporated herein by reference).
4.2.2 Amended and Restated Credit Agreement dated as of September
11, 1998, amending and restating Exhibit 4.2 (filed as
Exhibit 4.2.2 to Inland's Annual Report on Form 10-K for the
year ended December 31, 1998, and incorporated herein by
reference).
4.2.3 First Amendment to Amended and Restated Credit Agreement
dated as of March 5, 1999, amending Exhibit 4.2.2 (filed as
Exhibit 4.2.3 to Inland's Annual Report on Form 10-K for the
year ended December 31, 1998, and incorporated herein by
reference).
4.2.4 Exchange Agreement dated as of September 21, 1999 by and
between Inland, IPC, Refining, Trust Company of the West, a
California trust company, as Sub-Custodian for Mellon Bank
for the benefit of Account No. CPFF 873-3032, Inland
Holdings LLC, TCW Portfolio No. 1555 DR V Sub-Custody
Partnership, L.P. and Joint Energy Development Investments
II Limited Partnership (without exhibits or schedules),
terminating Exhibits 4.2 and 4.3, as previously amended, and
Exhibits 4.4, 4.5, 10.10 and 10.11 (filed as Exhibit 10.1 to
Inland's Current Report on Form 8-K dated September 21,
1999, and incorporated herein by reference).
4.3 Intercreditor Agreement dated September 23, 1997, between
IPC, TCW Asset Management Company, Trust Company of the West
and ING (U.S.) Capital Corporation (filed as Exhibit 4.3 to
Inland's Current Report on Form 8-K dated September 23,
1997, and incorporated herein by reference).
4.3.1 Third Amendment to Intercreditor Agreement entered into as
of April 22, 1998, amending Exhibit 4.3 (filed as Exhibit
4.3.1 to Inland?s Quarterly Report on Form 10-Q for the
quarter ended March 31, 1998, and incorporated herein by
reference).
4.3.2 Amended and Restated Intercreditor Agreement dated as of
September 11, 1998, amending and restating Exhibit 4.3
(filed as Exhibit 4.3.2 to Inland's Annual Report on Form
10-K for the year ended December 31, 1998, and incorporated
herein by reference).
4.3.3 First Amendment to Amended and Restated Intercreditor
Agreement dated as of March 5, 1999, amending Exhibit 4.3.2
(filed as Exhibit 4.3.3 to Inland's Annual Report on Form
10-K for the year ended December 31, 1998, and incorporated
herein by reference).
4.4 Warrant Agreement by and between Inland and TCW Portfolio
No. 1555 DR V Sub-Custody Partnership, L.P. dated September
23, 1997 (filed as Exhibit 4.4 to
Inland's Current Report on Form 8-K dated September 23,
1997, and incorporated herein by reference).
4.5 Warrant issued by Inland pursuant to the Warrant Agreement,
dated September 23, 1997, representing the right to purchase
100,000 shares of Inland's Common Stock (filed as Exhibit
4.5 to Inland's Current Report on Form 8-K dated September
23, 1997, and incorporated herein by reference). 10.1 1988
Option Plan of Inland Gold and Silver Corp. (filed as
Exhibit 10(15) to Inland's Annual Report on Form 10-K for
the year ended December 31, 1988, and incorporated herein by
reference).
10.1.1 Amended 1988 Option Plan of Inland Gold and Silver Corp.
(filed as Exhibit 10.10.1 to Inland's Annual Report on Form
10-K for the year ended December 31, 1992, and incorporated
herein by reference).
10.1.2 Amended 1988 Option Plan of Inland, as amended through
August 29, 1994 (including amendments increasing the number
of shares to 212,800 and changing "formula award") (filed as
Exhibit 10.1.2 to Inland's Annual Report on Form 10-KSB for
the year ended December 31, 1994, and incorporated herein by
reference).
10.1.3 Automatic Adjustment to Number of Shares Covered by Amended
1988 Option Plan executed effective June 3, 1996 (filed as
Exhibit 10.1 to Inland's Quarterly Report on Form 10-QSB for
the quarter ended June 30, 1996, and incorporated herein by
reference).
10.2 Letter agreement dated October 30, 1996 between Inland and
Johnson Water District (filed as Exhibit 10.41 to Inland's
Annual Report on Form 10-KSB for the year ended December 31,
1996, and incorporated herein by reference).
10.3 Interest Rate Cap Agreement dated April 30, 1998 between IPC
and Enron Capital and Trade Resources Corp. (filed as
Exhibit 10.4 to Inland?s Quarterly Report on Form 10-Q for
the quarter ended March 31, 1998, and incorporated herein by
reference).
10.4 Farmout Agreement between Inland and Smith Management LLC
dated effective as of June 1, 1998 (filed as Exhibit 10.1 to
Inland?s Current Report on Form 8-K dated June 1, 1998, and
incorporated herein by reference).
10.5 Warrant Agreement dated as of March 5, 1999 between Inland
Resources Inc. and TCW Portfolio No. 1555 DR V Sub-Custody
Partnership, L.P. (filed as Exhibit 10.20 to Inland's Annual
Report on Form 10-K for the year ended December 31, 1998,
and incorporated herein by reference).
10.6 Warrant Certificate dated March 5, 1999 between Inland and
TCW Portfolio No. 1555 DR V Sub-Custody Partnership, L.P.
representing 5,852 shares (filed as Exhibit 10.21 to
Inland's Annual Report on Form 10-K for the year ended
December 31, 1998, and incorporated herein by reference).
10.7 Shareholders Agreement dated as of September 21, 1999
between Inland, Holdings, Fund V, JEDI and Pengo Securities
Corp., Smith Energy Partnership, Randall D. Smith, Jeffrey
A. Smith, Barbara Stovall Smith, John W. Adams and Arthur J.
Pasmas (collectively, the "Smith Group") (filed as Exhibit
10.2 to Inland's Current Report on Form 8-K dated September
21, 1999, and incorporated herein by reference).
10.8 Registration Rights Agreement dated as of September 21, 1999
between Inland, Holdings, Portfolio, JEDI and the Smith
Group filed as Exhibit 10.3 to Inland's Current Report on
Form 8-K dated September 21, 1999, and (incorporated herein
by reference).
10.9 Severance Agreement between Inland and John E. Dyer dated
November 18, 1999 (filed as Exhibit 10.13 to Inland?s Annual
Report on Form 10-K for the year ended December 31, 1999,
and incorporated herein by reference).
10.10 Employment Agreement between Inland and William T. War dated
effective as of October 1, 1999 (filed as Exhibit 10.14 to
Inland?s Annual Report on Form 10-K for the year ended
December 31, 1999, and incorporated herein by reference).
10.11 Stock Option Agreement between Inland and William T. War
dated October 1, 1999 10.11 representing 25,000 post-split
shares of Common Stock (filed as Exhibit 10.15 to Inland?s
Annual Report on Form 10-K for the year ended December 31,
1999, and incorporated herein by reference).
10.12 Amendment to Employment Agreement between Inland and William
T. War, amending the Employment Agreement filed as Exhibit
10.10.
10.13 Employment Agreement between Inland and Michael J. Stevens
dated effective as of February 1, 2001.
10.14 Employment Agreement between Inland and Marc MacAluso dated
effective as of February 1, 2001.
10.15 Stock Option Agreement between Inland and Marc MacAluso
dated effective as of February 1, 2001 representing 150,000
post-split shares of Common Stock.
10.16 Employment Agreement between Inland and Bill I. Pennington
dated effective as of February 1, 2001.
10.17 Stock Option Agreement between Inland and Bill I. Pennington
dated effective as of February 1, 2001 representing 150,000
post-split shares of Common Stock.
10.18 Oil Purchase and Delivery Agreement dated November 7, 2000.
10.19 Common Stock Purchase Agreement dated August 2, 2001 by and
between Inland Holdings, LLC ("Inland Holdings") and Hampton
Investments LLC ("Hampton Investments")(without exhibits or
schedules)(filed as Exhibit 10.1 to the Company's Current
Report on Form 8-K dated August 2, 2001, and incorporated
herein by reference).
10.20 Contribution Agreement dated August 2, 2001 by and among
Park Hampton Holdings LLC ("Hampton Holdings"), Pengo
Securities Corp. ("Pengo"), Smith Energy Partnership
("SEP"), the five individuals and Hampton Investments (filed
as Exhibit 10.2 to the Company's Current Report on Form 8-K
dated August 2, 2001, and incorporated herein by reference).
10.21 Series E Preferred Stock Purchase Agreement dated as of
August 2, 2001 by and between Hampton Investments and Inland
Holdings (without exhibits or schedules)(filed as Exhibit
10.3 to the Company's Current Report on Form 8-K dated
August 2, 2001, and incorporated herein by reference).
10.22 Termination Agreement dated as of August 2, 2001 by and
between Hampton Investments and Inland (without exhibits or
schedules)(filed as Exhibit 10.4 to the Company's Current
Report on Form 8-K dated August 2, 2001, and incorporated
herein by reference).
10.23 Exchange and Note Issuance Agreement dated August 2, 2001 by
and among Inland, Production and Inland Holdings (without
exhibits or schedules)(filed as Exhibit 10.5 to the
Company's Current Report on Form 8-K dated August 2, 2001,
and incorporated herein by reference).
10.24 Termination Agreement dated as of August 2, 2001 by and
among Inland and Inland Holdings (without exhibits or
schedules)(filed as Exhibit 10.6 to the Company's Current
Report on Form 8-K dated August 2, 2001, and incorporated
herein by reference).
10.25 Amended and Restated Registration Rights Agreement dated as
of August 2, 2001 by and among Inland, Inland Holdings and
Hampton Investments (without exhibits or schedules)(filed as
Exhibit 10.7 to the Company's Current Report on Form 8-K
dated August 2, 2001, and incorporated herein by reference).
10.26 Amended and Restated Shareholders Agreement dated as of
August 2, 2001 by and among Inland, Inland Holdings and
Hampton Investments (without exhibits or schedules)(filed as
Exhibit 10.8 to the Company's Current Report on Form 8-K
dated August 2, 2001, and incorporated herein by reference).
10.27 Senior Subordinated Note Purchase Agreement dated as of
August 2, 2001 by and among Inland, Production and SOLVation
(without exhibits or schedules)(filed as Exhibit 10.9 to the
Company's Current Report on Form 8-K dated August 2, 2001,
and incorporated herein by reference).
10.28 Junior Subordinated Note Purchase Agreement dated as of
August 2, 2001 by and among Inland, Production and SOLVation
(without exhibits or schedules)(filed as Exhibit 10.10 to
the Company's Current Report on Form 8-K dated August 2,
2001, and incorporated herein by reference).
*21.1 Subsidiaries of Inland.
*23.1 Consent of Arthur Andersen LLP.
*23.2 Consent of Ryder Scott Company Petroleum Engineers.
*99.1 Letter to Securities and Exchange Commission dated March 26,
2002 concerning Arthur Andersen LLP.
* Filed herewith