<PAGE>
F O R M 1 0 - K/A
A M E N D M E N T N O. 1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ________ to _________
[Commission File Number 1-9260]
U N I T C O R P O R A T I O N
(Exact Name of Registrant as Specified in its Charter)
Delaware 73-1283193
(State of Incorporation) (I.R.S. Employer Identification No.)
1000 Kensington Tower
7130 South Lewis
Tulsa, Oklahoma 74136
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, Including Area Code (918) 493-7700
++++++++++++++++++++++++++++++++
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange
Title of each class on which registered
Common Stock, par value New York Stock Exchange
$.20 per share
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Warrants to Purchase Shares of Common Stock
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K (Section 229.405 of this chapter) is not contained
herein, and will not 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
Aggregate Market Value of the Voting Stock Held By
Non-affiliates on March 15, 1995 - $44,446,596
Number of Shares of Common Stock
Outstanding on March 15, 1995 - 20,933,190
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the Annual
Meeting of Stockholders to be held May 3, 1995 are incorporated by
reference in Part III.
Exhibit Index - See Page 66
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Item 8. Financial Statements and Supplementary Data
-----------------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
ASSETS 1994 1993
---------- ----------
(In thousands)
Current Assets:
Cash and cash equivalents $ 2,749 $ 3,756
Short-term investments - 41
Accounts receivable (less allowance for
doubtful accounts of $289 and $411) 16,369 14,099
Materials and supplies 1,498 1,424
Prepaid expenses and other 1,222 736
--------- ---------
Total current assets 21,838 20,056
--------- ---------
Property and Equipment:
Drilling equipment 75,746 75,528
Oil and natural gas properties, on the full
cost method 157,393 132,704
Transportation equipment 3,341 2,851
Other 7,925 8,541
--------- ---------
244,405 219,624
Less accumulated depreciation, depletion,
amortization and impairment 153,862 144,099
--------- ---------
Net property and equipment 90,543 75,525
--------- ---------
Other Assets 40 181
--------- ---------
Total Assets $112,421 $ 95,762
========= =========
The accompanying notes are an integral part of the
consolidated financial statements
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UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31,
LIABILITIES AND SHAREHOLDERS' EQUITY 1994 1993
---------- ----------
(In thousands)
Current Liabilities:
Current portion of long-term debt $ 496 $ 481
Current portion of natural gas
purchaser prepayments (Note 4) 1,580 1,170
Accounts payable 14,593 14,008
Accrued liabilities 3,014 1,983
Contract advances 158 10
---------- ----------
Total current liabilities 19,841 17,652
---------- ----------
Natural Gas Purchaser Prepayments (Note 4) 2,149 4,417
---------- ----------
Long-Term Debt 37,824 25,919
---------- ----------
Commitments and Contingencies (Note 9)
Shareholders' Equity:
Preferred stock, $1.00 par value, 5,000,000
shares authorized, none issued - -
Common stock, $.20 par value, 40,000,000
shares authorized, 20,910,190 and
20,861,505 shares issued, respectively 4,182 4,172
Capital in excess of par value 50,086 49,977
Accumulated deficit (1,581) (6,375)
Treasury stock, at cost (25,100 shares) (80) -
---------- ----------
Total shareholders' equity 52,607 47,774
---------- ----------
Total Liabilities and Shareholders' Equity $ 112,421 $ 95,762
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
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UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
1994 1993 1992
-------- -------- --------
(In thousands except per share amounts)
Revenues:
Contract drilling $16,952 $14,676 $ 9,732
Oil and natural gas 26,001 24,073 23,464
Natural gas marketing
and processing 44,171 32,104 21,970
Other 834 88 661
-------- -------- --------
Total revenues 87,958 70,941 55,827
-------- -------- --------
Expenses:
Contract drilling:
Operating costs 14,909 13,269 9,901
Depreciation and impairment 2,030 1,713 1,284
Oil and natural gas:
Operating costs 8,799 8,098 7,538
Depreciation, depletion
and amortization 8,281 7,018 7,128
Natural gas marketing
and processing 43,897 32,325 22,627
General and administrative 3,574 3,302 3,114
Interest 1,654 1,324 1,633
Provision for litigation - - 1,500
-------- -------- --------
Total expenses 83,144 67,049 54,725
-------- -------- --------
Income Before Income Taxes 4,814 3,892 1,102
Income Tax Expense 20 21 15
-------- -------- --------
Net Income $ 4,794 $ 3,871 $ 1,087
======== ======== ========
Net Income Per Common Share $ .23 $ .19 $ .05
======== ======== ========
Weighted Average Shares Outstanding 20,900 20,860 20,781
(Both Primary and Fully Diluted) ======== ======== ========
The accompanying notes are an integral part of the
consolidated financial statements
27
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UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Year Ended December 31, 1992, 1993 and 1994
Capital
In Excess Treasury
Common Of Par Accumulated
Stock Value Deficit Stock Total
-------- -------- --------- -------- --------
(In thousands)
Balances,
January 1, 1992 $ 4,143 $49,733 $(11,333) $ - $42,543
Net income - - 1,087 - 1,087
Activity in employee
compensation plans
(67,755 shares) 14 108 - - 122
-------- -------- --------- -------- --------
Balances,
December 31, 1992 4,157 49,841 (10,246) - 43,752
Net income - - 3,871 - 3,871
Activity in employee
compensation plans
(78,706 shares) 15 136 - - 151
-------- -------- --------- -------- --------
Balances,
December 31, 1993 4,172 49,977 (6,375) - 47,774
Net income - - 4,794 - 4,794
Activity in employee
compensation plans
(48,685 shares) 10 109 - - 119
Purchase of treasury
stock (25,100
shares) - - - (80) (80)
-------- -------- --------- -------- --------
Balances,
December 31, 1994 $ 4,182 $50,086 $ (1,581) $ (80) $52,607
======== ======== ========= ======== ========
The accompanying notes are an integral part of the
consolidated financial statements
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UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
1994 1993 1992
-------- -------- --------
(In thousands)
Cash Flows From Operating Activities:
Net income $ 4,794 $ 3,871 $ 1,087
Adjustments to reconcile net income
to net cash provided by
operating activities:
Depreciation, depletion,
amortization and impairment 10,774 9,256 8,772
Gain on disposition of assets (813) (49) (463)
Employee stock compensation plans 119 151 122
Bad debt expense - - 200
Provision for litigation - - 1,500
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable (939) (1,257) 2,493
Materials and supplies (74) (99) 121
Prepaid expenses and other (486) 83 191
Accounts payable 735 634 (747)
Accrued liabilities 760 (947) (151)
Contract advances 148 8 (876)
Natural gas purchaser prepayments (1,858) (1,743) (2,319)
-------- -------- --------
Net cash provided
by operating activities 13,160 9,908 9,930
-------- -------- --------
The accompanying notes are an integral part of the
consolidated financial statements
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UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31,
1994 1993 1992
--------- --------- ---------
(In thousands)
Cash Flows From Investing Activities:
Capital expenditures (including
producing property acquisitions) $(28,227) $(11,946) $(10,768)
Proceeds from disposition of assets 2,038 709 1,146
Decrease in short-term investments 41 664 170
(Acquisition) disposition
of other assets 141 (45) 60
--------- --------- ---------
Net cash used in
investing activities (26,007) (10,618) (9,392)
Cash Flows From Financing Activities:
Borrowings under line of credit 63,700 43,400 23,900
Payments under line of credit (51,300) (40,600) (24,700)
Proceeds from notes payable
and other long-term debt - 911 710
Payments on notes payable and
other long-term debt (480) (367) (80)
Acquisition of treasury stock (80) - -
--------- --------- ---------
Net cash provided by
(used in) financing
activities 11,840 3,344 (170)
--------- --------- ---------
Net Increase (Decrease) in Cash
and Cash Equivalents (1,007) 2,634 368
Cash and Cash Equivalents,
Beginning of Year 3,756 1,122 754
--------- --------- ---------
Cash and Cash Equivalents, End of Year $ 2,749 $ 3,756 $ 1,122
========= ========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Interest $ 1,548 $ 1,326 $ 1,673
Income taxes $ 2 $ 2 $ 63
The accompanying notes are an integral part of the
consolidated financial statements
30
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UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
---------------------------------------------------
Principles of Consolidation
The consolidated financial statements include the accounts of Unit
Corporation and its directly and indirectly wholly owned subsidiaries (the
"Company"). The Company's investment in limited partnerships is accounted
for on the proportionate consolidation method, whereby its share of the
partnerships' assets, liabilities, revenues and expenses is included in the
appropriate classification in the accompanying consolidated financial
statements.
Drilling Contracts
The Company accounts for "footage" and "turnkey" drilling contracts,
in which the Company assumes the risks associated with drilling the well,
under the completed-contract method and for "daywork" drilling contracts
under the percentage-of-completion method. The entire amount of the loss,
if any, is recorded when the loss is determinable.
The costs of uncompleted drilling contracts include expenses incurred
to date on "footage" or "turnkey" drilling contracts which are still in
process.
Cash Equivalents and Short-Term Investments
The Company includes as cash equivalents, certificates of deposits and
all investments with original maturities at date of purchase of three
months or less which are readily convertible into known amounts of cash.
Property and Equipment
Drilling equipment, transportation equipment and other property and
equipment are carried at cost. The Company provides for depreciation of
drilling equipment on the units-of-production method based on estimated
useful lives, including a minimum provision of 20 percent of the active
rate when the equipment is idle. At December 31, 1993, one of the
Company's rigs was retired and certain components of the rig were written
down by $160,000 to their estimated market value. The Company uses the
composite method of depreciation for drill pipe and collars and calculates
the depreciation by footage actually drilled compared to total estimated
remaining footage. Depreciation of other property and equipment is comput-
ed using the straight-line method over the estimated useful lives of the
assets ranging from 3 to 15 years.
When property and equipment components are disposed of, the cost and
the related accumulated depreciation are removed from the accounts and any
resulting gain or loss is generally reflected in operations. For dispo-
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sitions of drill pipe and drill collars, an average cost for the
appropriate feet of drill pipe and drill collars is removed from the asset
account and charged to accumulated depreciation and proceeds, if any, are
credited to accumulated depreciation.
Oil and Natural Gas Operations
The Company accounts for its oil and natural gas exploration and
development activities on the full cost method of accounting prescribed by
the Securities and Exchange Commission ("SEC"). Accordingly, all produc-
tive and non-productive costs incurred in connection with the acquisition,
exploration and development of oil and natural gas reserves are capitalized
and amortized on a composite units-of-production method based on proved oil
and natural gas reserves. The Company's determination of its oil and
natural gas reserves are reviewed annually by independent petroleum
engineers. The average composite rates used for depreciation, depletion and
amortization ("DD&A") were $4.08, $4.13 and $4.67 per equivalent barrel in
1994, 1993 and 1992, respectively. The Company's calculation of DD&A
includes estimated future expenditures to be incurred in developing proved
reserves and estimated dismantlement and abandonment costs, net of
estimated salvage values. In the event the unamortized cost of oil and
natural gas properties being amortized exceeds the full cost ceiling, as
defined by the SEC, the excess is charged to expense in the period during
which such excess occurs.
No gains or losses are recognized upon the sale, conveyance or other
disposition of oil and natural gas properties unless a significant reserve
amount is involved.
The SEC's full cost accounting rules prohibit recognition of income in
current operations for services performed on oil and natural gas properties
in which the Company has an interest or on properties in which a part-
nership, of which the Company is a general partner, has an interest.
Accordingly, in 1994 the Company recorded $14,000 of contract drilling
profits as a reduction of the carrying value of its oil and natural gas
properties rather than including these profits in current operations. No
contract drilling profits were realized on such interests in 1993 and 1992.
Limited Partnerships
The Company, through its wholly owned subsidiary, Unit Petroleum
Company, is a general partner in eleven oil and natural gas limited part-
nerships sold privately and publicly. Certain of the Company's officers
and directors own interests in some of these partnerships. Their interests
were acquired generally on the same basis as other outside investors.
Prior to December 31, 1993, the Company also was general partner of seven
additional employee limited partnerships. However, pursuant to the terms
of an agreement and plan of merger, these seven limited partnerships were
consolidated into one new employee limited partnership effective December
31, 1993.
The Company shares in partnership revenues and costs in accordance
with formulas prescribed in each limited partnership agreement. The
32
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partnerships also reimburse the Company for certain administrative costs
incurred on behalf of the partnerships.
Income Taxes
Income taxes are accounted for in accordance with Statement of
Financial Accounting Standards (SFAS) No. 109, "Accounting for Income
Taxes". SFAS No. 109 requires the measurement of deferred tax assets for
deductible temporary differences and operating loss carryforwards, and of
deferred tax liabilities for taxable temporary differences. Measurement of
current and deferred tax liabilities and assets is based on provisions of
enacted tax law; the effects of future changes in tax laws or rates are not
included in the measurement. Deferred tax assets primarily result from net
operating loss carryforwards, and deferred tax liabilities result from the
recognition of depreciation, depletion and amortization in different
periods for financial reporting and tax purposes. Valuation allowances are
established where necessary to reduce deferred tax assets to the amount
expected to be realized. Income tax expense is the tax payable for the
year and the change during that year in deferred tax assets and
liabilities.
Natural Gas Balancing
The Company uses the sales method for recording natural gas sales.
This method allows for recognition of revenue which may be more or less
than the Company's share of pro-rata production from certain wells. Based
upon the Company's 1994 average spot market natural gas price of $1.65 per
Mcf, the Company estimates its balancing position to be approximately $5.5
million on under-produced properties and approximately $3.1 million on
over-produced properties.
The Company's policy is to expense its pro-rata share of lease oper-
ating costs from all wells as incurred. Such expenses relating to the
Company's balancing position on wells on which the Company has imbalances
are not material.
Financial Instruments and Concentrations of Credit Risk
At December 31, 1994, the Company had natural gas price swaps, related
to its marketing of natural gas, which qualify as hedges of the Company's
future purchase and sales commitments. Gains or losses on these swaps are
recognized in the consolidated statement of operations and included in
operating cash flows in the same period as the associated sale of natural
gas occurs. At December 31, 1994, the Company had price swap agreements
for 380,000 Mcf totaling $525,000 related to purchase commitments and
358,000 Mcf totaling $694,000 related to sales commitments for the period
of January through March of 1995.
Financial instruments which potentially subject the Company to
concentrations of credit risk consist primarily of trade receivables with a
variety of national and international oil and natural gas companies. The
Company does not generally require collateral related to receivables. Such
credit risk is considered by management to be limited due to the large
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number of customers comprising the Company's customer base. The Company
had one customer in its natural gas marketing operation at December 31,
1993, with an accounts receivable balance of $4.1 million which was
subsequently paid in January 1994. In addition, at December 31, 1994 and
1993, the Company had a concentration of cash of $2.3 and $3.4 million,
respectively, with one bank.
RECLASSIFICATIONS
Certain reclassifications have been made in the 1992 and 1993
consolidated financial statements to conform them to classifications used
in 1994.
NOTE 2 - PRODUCING PROPERTY ACQUISITION
---------------------------------------
On December 15, 1994, Unit Petroleum Company, a wholly owned
subsidiary of Unit Corporation, acquired interests in approximately 700 oil
and natural gas wells located primarily in Oklahoma, Texas, New Mexico and
Louisiana. Financing for the transaction was provided under the Company's
bank credit agreement. The acquisition is summarized as follows:
Current assets net of current liabilities $ 976,000
Producing oil and natural gas properties 12,261,000
-----------
Net assets acquired $13,237,000
===========
Unaudited summary pro forma results of operations for the Company,
reflecting the above described acquisition as if it had occurred at the
beginning of the years ended December 31, 1994 and December 31, 1993, are
as follows, respectively; revenues, $94,373,000 and $79,807,000; net
income, $5,068,000 and $7,259,000; and net income per common share, $.24
and $.35. The pro forma results of operations are not necessarily
indicative of the actual results of operations that would have occurred had
the purchase actually been made at the beginning of the respective periods
nor of the results which may occur in the future.
NOTE 3 - WARRANTS
-----------------
In 1987, the Company issued 2.873 million units, consisting of three
shares of the Company's common stock and one warrant, at a price of $10.375
per unit. Each warrant entitles the holder to purchase one share of the
Company's common stock at a price of $4.375 anytime prior to the warrant's
expiration on August 30, 1996. The warrants, subject to certain
restrictions, are callable by the Company, in whole or in part, at $.50 per
warrant. As of December 31, 1994 no warrants have been exercised.
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NOTE 4 - NATURAL GAS PURCHASER PREPAYMENTS
-------------------------------------------
In March 1988, the Company entered into a settlement agreement with a
natural gas purchaser. During early 1991, the Company and the natural gas
purchaser superseded the original agreement with a new settlement agreement
effective retroactively to January 1, 1991. Under these settlement
agreements, the Company has a prepayment balance of $3.7 million at
December 31, 1994 representing proceeds received from the purchaser as
prepayment for natural gas. This amount is net of natural gas recouped and
net of certain amounts disbursed to other owners (such owners, collectively
with the Company are referred to as the "Committed Interest") for their
proportionate share of the prepayments. The December 31, 1994 prepayment
balance is subject to recoupment in volumes of natural gas for a period
ending the earlier of recoupment or December 31, 1997 (the "Recoupment
Period"). Additionally, the purchaser is obligated to make monthly
payments on behalf of the Committed Interest in an amount calculated as a
percentage of the Committed Interest's share of the deliverability of the
wells subject to the settlement agreement, up to a maximum of $211,000 or a
minimum of $110,000 per month for the year 1995. Both the maximum and
minimum monthly payments decline annually through the Recoupment Period.
At December 31, 1997, the Committed Interest's prepayment balance, if any,
that has not been fully recouped in natural gas is subject to a cash
repayment limited to a maximum of $3 million to be made in equal payments
over a five year period. The prepayment amounts subject to recoupment from
future production by the purchaser are being recorded as liabilities and
are reflected in revenues as recoupment occurs. The portion of the prepay-
ments that are estimated to be recouped in the next twelve months has been
included in current liabilities. At the end of the Recoupment Period, the
terms of the settlement agreement and the natural gas purchase contracts
which are subject to the settlement agreement will terminate.
NOTE 5 - LONG-TERM DEBT
------------------------
Long-term debt consisted of the following as of December 31, 1994 and
1993:
1994 1993
--------- ---------
Revolving credit and term loan, (In thousands)
with interest at December 31,
1994 and 1993 of 8.5%
and 6%, respectively $ 37,300 $ 24,900
Other 1,020 1,500
--------- ---------
38,320 26,400
Less current portion 496 481
--------- ---------
Total long-term debt $ 37,824 $ 25,919
========= =========
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At December 31, 1994, the Company's credit agreement ("Agreement")
provided for a total loan commitment of $50 million consisting of a revolv-
ing credit facility through January 1, 1997 and a term loan thereafter,
maturing on January 1, 2001. Borrowings under the Agreement are limited to
a semi-annual borrowing base computation which as of December 31, 1994 is
$42 million.
The principal of the revolving credit facility is due in 48 equal
monthly payments commencing February 1, 1997 and continuing on the first
day of each month thereafter through maturity. The outstanding principal
amount of the revolving credit facility which is less than or equal to the
loan value of the mineral interest then in effect shall bear interest at
the Chase Manhattan Bank, N.A. prime rate ("Prime Rate") and that portion
of the outstanding balance exceeding such loan value shall bear interest at
the Prime Rate plus 1 and 1/2 percent through January 1, 1997. Subsequent to
January 1, 1997 and continuing through January 1, 2001, the portion of the
outstanding amount under the Agreement which is less than or equal to the
loan value of the mineral interests then in effect shall bear interest at
the Prime Rate plus 1/4 of 1 percent and any portion of the outstanding
principal balance exceeding such loan value shall bear interest equal to
the Prime Rate plus 1 and 1/2 percent. The Agreement also provides for a
commitment fee of 1/2 of 1 percent of the unused portion of the borrowing
base. Virtually all of the Company's drilling rigs are collateral for such
indebtedness and the balance of the Company's assets are subject to a
negative pledge.
The Agreement includes prohibitions against (i) the payment of divi-
dends (other than stock dividends) during any fiscal year in excess of 25
percent of the consolidated net income of the Company during the preceding
fiscal year, (ii) the incurrence by the Company or any of its subsidiaries
of additional debt with certain very limited exceptions and (iii) the
creation or existence of mortgages or liens, other than those in the
ordinary course of business, on any property of the Company or any of its
subsidiaries, except in favor of its banks. The Agreement also requires
that the Company maintain consolidated net worth of at least $45 million, a
modified current ratio of not less than 1 to 1, a ratio of long-term debt,
as defined in the Agreement, to consolidated tangible net worth not greater
than 1 to 1 and a ratio of total liabilities, as defined in the Agreement,
to consolidated tangible net worth not greater than 1.25 to 1. In
addition, working capital provided by operations, as defined in the
Agreement, cannot be less than $13 million in any year.
Estimated annual principal payments under the terms of all long-term
debt from 1995 through 1999 are $496,000, $200,000, $200,000, $8,671,000
and $9,325,000.
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NOTE 6 - INCOME TAXES
---------------------
A reconciliation of the income tax expense, computed by applying the
federal statutory rate to pre-tax income, to the Company's effective income
tax expense is as follows:
1994 1993 1992
-------- -------- --------
(In thousands)
Income tax expense computed by
applying the statutory rate $ 1,637 $ 1,323 $ 375
Tax benefit of net operating
loss carryforward (1,652) (1,308) (396)
Alternative minimum tax - - 2
State income tax 6 1 7
Other 29 5 27
-------- -------- --------
Income tax expense $ 20 $ 21 $ 15
======== ======== ========
Deferred tax assets and liabilities are comprised of the following at
December 31, 1994 and 1993:
1994 1993
-------- --------
Deferred tax assets: (In thousands)
Allowance for losses $ 521 $ 580
Gas purchaser prepayments - 149
Net operating loss carryforwards 18,190 18,118
Statutory depletion carryforward 2,500 2,500
Investment tax credit carryforward 3,530 3,530
-------- --------
Gross deferred tax assets 24,741 24,877
-------- --------
Deferred tax liabilities:
Depreciation, depletion and amortization 18,318 16,659
-------- --------
Gross deferred tax liabilities 18,318 16,659
-------- --------
Net deferred tax asset 6,423 8,218
Valuation allowance 6,423 8,218
-------- --------
$ - $ -
======== ========
The net deferred tax asset valuation allowance reflects that the tax
carryforwards above may not be utilized before the expiration dates as
itemized below due in part to the effects of anticipated future exploratory
and development drilling costs.
At December 31, 1994, the Company has net operating loss carryforwards
for regular tax purposes of approximately $47,868,000 and net operating
loss carryforwards for alternative minimum tax purposes of approximately
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$38,260,000 which expire in various amounts from 1999 to 2007. The Company
has investment tax credit carryforwards of approximately $3,530,000 which
expire from 1995 to 2000. In addition, a statutory depletion carryforward
of approximately $6,579,000 is available to reduce future taxable income,
subject to statutory limitations. Statutory depletion may be carried
forward indefinitely.
In 1987, the Company completed an equity offering which constituted an
ownership change as that term is used in the Internal Revenue Code. As a
result of the ownership change, the amount of taxable income in future
years which may be offset by the Company's net operating loss carryovers
prior to the ownership change is limited. Tax losses of $45,950,000 at
December 31, 1994 are not subject to these limitations. The remaining tax
net operating loss carryforward will become available for utilization by
the Company at a rate of $3,500,000 per year. Similar limitations apply to
investment tax credits.
NOTE 7 - BENEFIT AND COMPENSATION PLANS
---------------------------------------
In December 1984, the Board of Directors approved the adoption of an
Employee Stock Bonus Plan ("the Plan") whereby 330,950 shares of common
stock were authorized for issuance under the Plan. Under the terms of the
Plan, bonuses may be granted to employees in either cash or stock or a
combination thereof, and are payable in a lump sum or in annual in-
stallments subject to certain restrictions. The Company issued 38,354 and
50,788 shares under the Plan in 1993 and 1992, respectively. No shares
were issued under the Plan in 1994.
The Company has a Stock Option Plan which provides for the granting of
options for up to 1,000,000 shares of common stock to officers and
employees. The plan permits the issuance of qualified or nonqualified
stock options. Stock options granted in 1986 became exercisable at the
rate of 20 percent per year through 1990. Options granted subsequent to
1986 become exercisable at the rate of 20 percent per year one year after
being granted.
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Activity pertaining to the Stock Option Plan is as follows:
NUMBER
OF OPTION PRICE
SHARES -----------------------------
--------- PER SHARE AGGREGATE
Outstanding at -----------------------------
January 1, 1992 752,000 $1.50 to 3.375 $1,476,995
Granted 10,000 1.875 18,750
Cancelled (10,000) 2.37 to 2.875 (26,225)
--------- -------------- ----------
Outstanding at
December 31, 1992 752,000 1.50 to 3.375 1,469,520
Granted 89,000 2.75 244,750
Exercised (12,000) 1.50 to 2.37 (19,740)
--------- -------------- -----------
Outstanding at
December 31, 1993 829,000 1.50 to 3.375 1,694,530
Granted 102,500 3.00 307,500
Exercised (16,000) 1.50 to 2.37 (24,870)
--------- -------------- -----------
Outstanding at
December 31, 1994 915,500 $1.50 to 3.375 $ 1,977,160
========= ============== ===========
Options for 676,400, 610,500 and 556,400 shares were exercisable at
prices ranging from $1.50 to $3.375 at December 31, 1994, 1993 and 1992,
respectively.
In February and May 1992, the Board of Directors and shareholders,
respectively, approved the Unit Corporation Non-Employee Directors' Stock
Option Plan (the "Directors' Plan"). An aggregate of 100,000 shares of the
Company's common stock may be issued or delivered upon exercise of the
stock options. On the first business day following each annual meeting of
stockholders of the Company, each person who is then a member of the Board
of Directors of the Company and who is not then an employee of the Company
or any of its subsidiaries will be granted an option to purchase 2,500
shares of common stock. The option price for each stock option is the fair
market value of the common stock on the date the stock options are granted.
No stock options may be exercised during the first six months of its term
except in case of death and no stock options are exercisable after ten
years from the date of grant.
39
<PAGE>
Activity pertaining to the Directors' Plan is as follows:
NUMBER
OF OPTION PRICE
SHARES --------------------------
------- PER SHARE AGGREGATE
1992: -------------- ---------
Granted 10,000 $ 1.75 $ 17,500
------- -------------- ---------
Outstanding at
December 31, 1992 10,000 1.75 17,500
Granted 10,000 3.75 37,500
------- -------------- ---------
Outstanding at
December 31, 1993 20,000 1.75 to 3.75 55,000
Granted 10,000 2.875 28,750
------- -------------- ---------
Outstanding at
December 31, 1994 30,000(1) $1.75 to 3.75 $ 83,750
======= ============== =========
-------------
(1) All 30,000 options were exercisable at December 31, 1994.
Under the Company's 401(k) Employee Thrift Plan, employees who meet
specified service requirements may contribute a percentage of their total
compensation, up to a specified maximum, to the plan. Each employee's
contribution, up to a specified maximum, may be matched by the Company in
full or on a partial basis. The Company made discretionary contributions
under the plan of 32,685, 28,352 and 16,967 shares of common stock and
recognized expense of $130,000, $162,000 and $33,000 in 1994, 1993 and
1992, respectively.
Effective March 1, 1993, the Company adopted a salary deferral plan
("Deferral Plan"). The Deferral Plan allows participants to defer the
recognition of salary for income tax purposes until actual distribution of
benefits which occurs at either termination of employment, death or certain
defined unforeseeable emergency hardships. Funds set aside in a trust to
satisfy the Company's obligation under the Deferral Plan at December 31,
1994 and 1993 totaled $108,000 and $41,000, respectively. The Company
recognizes payroll expense and records a deferred liability at the time of
deferral.
NOTE 8 - TRANSACTIONS WITH RELATED PARTIES
------------------------------------------
The Company formed private limited partnerships (the "Partnerships")
with certain qualified employees, officers and directors from 1984 through
1994, with a subsidiary of the Company serving as General Partner. The
Partnerships were formed for the purpose of conducting oil and natural gas
acquisition, drilling and development operations and serving as co-general
partner with the Company in any additional limited partnerships formed
during that year. The Partnerships participated on a proportionate basis
with the Company in most drilling operations and most producing property
40
<PAGE>
acquisitions commenced by the Company for its own account during the period
from the formation of the Partnership through December 31 of each year.
Pursuant to the terms of an agreement and plan of merger, seven limited
partnerships, in which the Company was general partner, were consolidated
into one new employee limited partnership effective December 31, 1993.
Amounts received in the following years ended December 31 from both
public and private Partnerships for which the Company is a general partner
are as follows:
1994 1993 1992
-------- -------- --------
(In thousands)
Contract drilling $ 53 $ 60 $ 38
Well supervision and other fees $ 226 $ 278 $ 277
General and administrative
expense reimbursement $ 209 $ 231 $ 294
A subsidiary of the Company paid the Partnerships, for which the
Company or a subsidiary is the general partner, $38,000, $65,000 and
$58,000 during the years ended December 31, 1994, 1993 and 1992,
respectively, for purchases of natural gas production.
During 1993 and 1992, the Company received legal services from a law
firm of which one of the Company's directors was a partner. Total payments
to the law firm during 1993 and 1992 were $164,000 and $130,000,
respectively. The Company did not receive such services from the law firm
in 1994.
During 1994, a bank owned by one of the Company's Directors became a
participant in the Company's loan agreement. The bank's total pro rata
share of the Company's line of credit is not to exceed $1.5 million.
NOTE 9 - COMMITMENTS AND CONTINGENCIES
--------------------------------------
The Company is currently negotiating a new operating lease agreement
to remain in its current office space until February 1, 2000. Future
minimum rental payments under the proposed terms of the lease would be
approximately $205,000, $224,000, $244,000, $246,000 and $246,000 in 1995,
1996, 1997, 1998 and 1999, respectively. Total rent expense incurred by
the Company was $210,000, $208,000 and $205,000 in 1994, 1993 and 1992,
respectively.
The Company had letters of credit totaling $835,600 outstanding at
December 31, 1994.
The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy
Income Limited Partnership agreements along with the employee oil and gas
limited partnerships require, upon the election of a limited partner, that
the Company repurchase the limited partner's interest at amounts to be
determined by appraisal in the future. Such repurchases in any one year
are limited to 20 percent of the units outstanding. The Company made
41
<PAGE>
repurchases of $38,000, $56,000 and $70,000 in 1994, 1993 and 1992,
respectively, for such limited partner's interest.
The Company is a party to a settlement agreement dated January 31,
1991 with a natural gas purchaser which superseded a settlement agreement
entered into during March of 1988. Under the agreements the purchaser made
certain prepayments to the Company for natural gas to be delivered to the
purchaser in the future. As of December 31, 1994, this prepayment balance
for natural gas yet to be delivered was $3.7 million. The Company has
learned that the Oklahoma Tax Commission (the "Commission"), based on four
assessments, one in 1988, one in 1992 and two in 1994, is seeking to hold
the purchaser liable for certain taxes, interests and penalties that the
Commission contends are due and owing with respect to the prepayment
amounts made by the purchaser under the agreements on the grounds that the
prepayments are solely attributable to the settlement of past claims for
take-or-pay obligations. To date, the Company is not a party to the
Commission's proceedings, but may in the future, seek to intervene in these
proceedings. The purchaser has denied the claims made by the Commission
and is contesting the assessments. The purchaser and the Commission have
settled the 1988 assessment for approximately $51,000 and the remaining
three assessments have been consolidated and set for a hearing before an
administrative law judge on or before May 10, 1995. The purchaser has
notified the Company of the proceedings and has indicated its intention to
assert claims against the Company to recover the amount it paid in
settlement of the 1988 assessment (including its attorney fees) as well as
any amounts it might have to pay by virtue of the remaining assessments.
The Company is aware that the purchaser has made such claims against other
companies which also received prepayments from the purchaser, although the
type of agreements and the facts involved in those cases are not known by
the Company. At this time, the Company is unable to determine what the
outcome of the remaining Commission's proceedings will be, the amount of
taxes, if any, plus interest and penalties that may ultimately be assessed
against the purchaser and the claims, if any, that the purchaser might seek
to assert against the Company in the event an unfavorable result is
incurred by the purchaser. The Company has advised the purchaser that it
believes the responsibility for the payment of the taxes, interest and
penalty sought by the Commission, should it be ultimately determined that
any such amounts are in fact owed, is the responsibility of the purchaser
and not the Company.
The Company is a party to various legal proceedings arising in the
ordinary course of its business none of which, in the Company's opinion,
should result in judgements which would have a material adverse effect on
the Company.
42
<PAGE>
NOTE 10 - INDUSTRY SEGMENT INFORMATION
--------------------------------------
The Company operates in the United States in three industry segments
which are contract drilling, oil and natural gas exploration and production
and natural gas marketing and processing. The Company also has natural gas
production in Canada which is not significant. Selected financial
information by industry segment is as follows:
<TABLE>
<CAPTION>
Depreciation,
Depletion,
Operating Amortization
Operating Profit Total Capital and Impairment
Revenues (Loss)(1) Assets(2) Expenditures Expense
---------- -------- --------- ---------- ----------
(In thousands)
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1994:
Drilling $ 16,952 $ 13 $ 14,771 $ 1,115 $ 2,030
Oil and natural gas 26,001 8,921 83,082 25,110 8,281
Natural gas marketing
and processing 44,171 274 10,619 56 331
---------- -------- --------- ---------- ----------
87,124 $ 9,208 108,472 26,281 10,642
Other 834 ======== 3,949 708 132
---------- --------- ---------- ----------
Total $ 87,958 $112,421 $ 26,989 $ 10,774
========== ========= ========== ==========
Year ended December 31, 1993:
Drilling $ 14,676 $ (306) $ 15,738 $ 936 $ 1,713
Oil and natural gas 24,073 8,957 64,845 11,422 7,018
Natural gas marketing
and processing 32,104 (221) 10,099 1,049 418
---------- -------- --------- ---------- ----------
70,853 $ 8,430 90,682 13,407 9,149
Other 88 ======== 5,080 323 107
---------- --------- ---------- ----------
Total $ 70,941 $ 95,762 $ 13,730 $ 9,256
========== ========= ========== ==========
Year ended December 31, 1992:
Drilling $ 9,732 $(1,453) $ 16,382 $ 266 $ 1,284
Oil and natural gas 23,464 8,798 61,694 7,951 7,128
Natural gas marketing
and processing 21,970 (657) 7,628 541 250
---------- -------- --------- ---------- ----------
55,166 $ 6,688 85,704 8,758 8,662
Other 661 ======== 3,006 137 110
---------- --------- ---------- ----------
Total $ 55,827 $ 88,710 $ 8,895 $ 8,772
========== ========= ========== ==========
</TABLE>
---------------------
(1) Operating profit is total operating revenues, less operating expenses,
depreciation, depletion, amortization and impairment and does not include
non-operating revenues, general corporate expenses, interest expense,
income taxes or provision for litigation.
(2) Identifiable assets are those used in the Company's operations in each
industry segment. Corporate assets are principally cash and cash
equivalents, short-term investments, corporate leasehold improvements and
furniture and equipment.
43
<PAGE>
NOTE 11 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
--------------------------------------------------------------
Summarized quarterly financial information for 1994 and 1993 is as
follows:
Three Months Ended
-------------------------------------------------
March 31 June 30 September 30 December 31
--------- --------- ----------- ----------
(In thousands except per share amounts)
Year ended December 31, 1994:
Revenues $ 23,005 $ 19,926 $ 21,166 (2) $ 23,861
========= ========= ========= =========
Gross Profit(1) $ 2,396 $ 2,726 $ 2,090 $ 1,996
========= ========= ========= =========
Income before
income taxes $ 1,215 $ 1,430 $ 1,595 (2) $ 574
========= ========= ========= =========
Net income $ 1,211 $ 1,425 $ 1,590 (2) $ 568
========= ========= ========= =========
Net income per
common share $ .06 $ .07 $ .07 (2) $ .03
========= ========= ========= =========
Year ended December 31, 1993:
Revenues $ 15,574 $ 17,881 $ 16,935 $ 20,551
========= ========= ========= =========
Gross Profit(1) $ 2,357 $ 1,982 $ 1,920 $ 2,171
========= ========= ========= =========
Income before
income taxes $ 1,163 $ 884 $ 890 $ 955
========= ========= ========= =========
Net income $ 1,156 $ 878 $ 886 $ 951
========= ========= ========= =========
Net income per
common share $ 0.06 $ 0.04 $ 0.04 $ 0.05
========= ========= ========= =========
-------------
(1) Gross Profit excludes other revenues, general and administrative
expense and interest expense.
(2) Includes $742,000 net gain on sale of natural gas gathering system.
44
<PAGE>
NOTE 12 - OIL AND NATURAL GAS INFORMATION (UNAUDITED)
-----------------------------------------------------
The capitalized costs at year end and costs incurred during the year
were as follows:
USA Canada Total
--------- -------- --------
(In thousands)
1994:
Capitalized costs:
Proved properties $ 154,688 $ 455 $155,143
Unproved properties 2,250 - 2,250
--------- -------- --------
156,938 455 157,393
Less accumulated depreciation,
depletion, amortization
and impairment 81,583 368 81,951
--------- -------- --------
Net capitalized costs $ 75,355 $ 87 $ 75,422
========= ======== ========
Cost incurred:
Unproved properties $ 460 $ - $ 460
Producing properties 13,108 - 13,108
Exploration 1,825 - 1,825
Development 9,716 1 9,717
--------- -------- --------
Total costs incurred $ 25,109 $ 1 $ 25,110
========= ======== ========
1993:
Capitalized costs:
Proved properties $ 129,612 $ 454 $130,066
Unproved properties 2,638 - 2,638
--------- -------- --------
132,250 454 132,704
Less accumulated depreciation,
depletion, amortization
and impairment 73,419 314 73,733
--------- -------- --------
Net capitalized costs $ 58,831 $ 140 $ 58,971
========= ======== ========
Cost incurred:
Unproved properties $ 732 $ - $ 732
Producing properties 1,241 - 1,241
Exploration 1,359 - 1,359
Development 8,084 6 8,090
--------- -------- --------
Total costs incurred $ 11,416 $ 6 $ 11,422
========= ======== ========
45
<PAGE>
USA Canada Total
--------- -------- --------
1992: (In thousands)
Capitalized costs:
Proved properties $ 117,721 $ 448 $ 118,169
Unproved properties 3,680 - 3,680
--------- -------- --------
121,401 448 121,849
Less accumulated depreciation,
depletion, amortization
and impairment 66,544 233 66,777
--------- -------- --------
Net capitalized costs $ 54,857 $ 215 $ 55,072
========= ======== ========
Cost incurred:
Unproved properties $ 504 $ - $ 504
Producing properties 3,629 - 3,629
Exploration 900 - 900
Development 2,918 - 2,918
--------- -------- --------
Total costs incurred $ 7,951 $ - $ 7,951
========= ======== ========
The results of operations before income taxes for producing activities
are provided below. Due to the Company's utilization of net operating loss
carryforwards, income taxes are not significant and have not been included.
USA Canada Total
--------- -------- --------
(In thousands)
1994:
Revenues $ 23,964 $ 67 $ 24,031
Production costs 7,011 19 7,030
Depreciation, depletion
and amortization 8,165 53 8,218
--------- -------- --------
Results of operations for
producing activities
before income taxes
(excluding corporate
overhead and financing
costs) $ 8,788 $ (5) $ 8,783
========= ======== ========
46
<PAGE>
USA Canada Total
--------- -------- --------
(In thousands)
1993:
Revenues $ 22,040 $ 67 $ 22,107
Production costs 6,439 15 6,454
Depreciation, depletion
and amortization 6,875 81 6,956
--------- -------- --------
Results of operations for
producing activities
before income taxes
(excluding corporate
overhead and financing costs) $ 8,726 $ (29) $ 8,697
========= ======== ========
1992:
Revenues $ 21,816 $ 75 $ 21,891
Production costs 6,159 10 6,169
Depreciation, depletion
and amortization 6,961 94 7,055
--------- -------- --------
Results of operations for
producing activities
before income taxes
(excluding corporate
overhead and financing costs) $ 8,696 $ (29) $ 8,667
========= ======== ========
47
<PAGE>
Estimated quantities of proved developed oil and natural gas reserves
and changes in net quantities of proved developed and undeveloped oil and
natural gas reserves were as follows:
USA Canada Total
----------------- ------------- ----------------
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
Bbls Mcf Bbls Mcf Bbls Mcf
------- -------- ------ ----- ------- --------
1994: (In thousands)
Proved developed and
undeveloped reserves:
Beginning of year 3,304 71,379 - 861 3,304 72,240
Revision of previous
estimates (97) (571) - (14) (97) (585)
Extensions, discoveries
and other additions 601 17,426 - - 601 17,426
Purchases of minerals
in place 910 14,075 - - 910 14,075
Sales of minerals in place (4) (137) - - (4) (137)
Production (406) (9,606) - (53) (406) (9,659)
------- -------- ----- ----- ------- --------
End of Year 4,308 92,566 - 794 4,308 93,360
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year 3,187 65,395 - 426 3,187 65,821
End of year 3,521 80,110 - 359 3,521 80,469
1993:
Proved developed and
undeveloped reserves:
Beginning of year 3,308 63,761 - 931 3,308 64,692
Revision of previous
estimates (132) 4,662 - - (132) 4,662
Extensions, discoveries
and other additions 549 9,169 - - 549 9,169
Purchases of minerals
in place 18 1,369 - - 18 1,369
Sales of minerals in place (42) (147) - - (42) (147)
Production (397) (7,435) - (70) (397) (7,505)
------- -------- ----- ----- ------- --------
End of Year 3,304 71,379 - 861 3,304 72,240
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year 3,245 58,809 - 468 3,245 59,277
End of year 3,187 65,395 - 426 3,187 65,821
48
<PAGE>
USA Canada Total
----------------- ------------- ----------------
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
Bbls Mcf Bbls Mcf Bbls Mcf
------- -------- ------ ------ ------- --------
1992: (In Thousands)
Proved developed and
undeveloped reserves:
Beginning of year 2,943 52,853 - 964 2,943 53,817
Revision of previous
estimates 235 7,679 - 47 235 7,726
Extensions, discoveries
and other additions 190 1,655 - - 190 1,655
Purchases of minerals
in place 316 8,327 - - 316 8,327
Sales of minerals in place (1) (23) - - (1) (23)
Production (375) (6,730) - (80) (375) (6,810)
------- -------- ----- ----- ------- --------
End of Year 3,308 63,761 - 931 3,308 64,692
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year 2,778 44,936 - 499 2,278 45,435
End of year 3,245 58,809 - 468 3,245 59,277
Oil and natural gas reserves cannot be measured exactly. Estimates of
oil and natural gas reserves require extensive judgments of reservoir
engineering data and are generally less precise than other estimates made
in connection with financial disclosures. The Company utilizes Ryder Scott
Company, independent petroleum consultants, to review the Company's
reserves as prepared by the Company's reservoir engineers.
Proved reserves are those quantities which, upon analysis of geolog-
ical and engineering data, appear with reasonable certainty to be recov-
erable in the future from known oil and natural gas reservoirs under exist-
ing economic and operating conditions. Proved developed reserves are those
reserves which can be expected to be recovered through existing wells with
existing equipment and operating methods. Proved undeveloped reserves are
those reserves which are expected to be recovered from new wells on
undrilled acreage or from existing wells where a relatively major expendi-
ture is required.
Estimates of oil and natural gas reserves require extensive judgments
of reservoir engineering data as explained above. Assigning monetary
values to such estimates does not reduce the subjectivity and changing
nature of such reserve estimates. Indeed the uncertainties inherent in the
disclosure are compounded by applying additional estimates of the rates and
timing of production and the costs that will be incurred in developing and
producing the reserves. The information set forth herein is therefore
subjective and, since judgments are involved, may not be comparable to
estimates submitted by other oil and natural gas producers. In addition,
since prices and costs do not remain static and no price or cost escala-
tions or de-escalations have been considered, the results are not neces-
sarily indicative of the estimated fair market value of estimated proved
reserves nor of estimated future cash flows.
49
<PAGE>
The standardized measure of discounted future net cash flows ("SMOG")
was calculated using year-end prices and costs, and year-end statutory tax
rates, adjusted for permanent differences, that relate to existing proved
oil and natural gas reserves. SMOG as of December 31 is as follows:
USA Canada Total
--------- -------- --------
1994: (In thousands)
Future cash flows $234,171 $ 1,255 $235,426
Future production and
development costs 105,876 311 106,187
Future income tax expenses 20,161 524 20,685
--------- -------- --------
Future net cash flows 108,134 420 108,554
10% annual discount for
estimated timing of cash flows 30,116 170 30,286
--------- -------- --------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 78,018 $ 250 $ 78,268
========= ======== =========
1993:
Future cash flows $214,800 $ 861 $215,661
Future production and
development costs 90,177 229 90,406
Future income tax expenses 17,097 244 17,341
--------- -------- --------
Future net cash flows 107,526 388 107,914
10% annual discount for
estimated timing of cash flows 34,374 157 34,531
--------- -------- --------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 73,152 $ 231 $ 73,383
======== ======== ========
1992
Future cash flows $208,964 $ 931 $209,895
Future production and
development costs 86,417 361 86,778
Future income tax expenses 19,634 194 19,828
--------- -------- --------
Future net cash flows 102,913 376 103,289
10% annual discount for
estimated timing of cash flows 32,653 120 32,773
--------- -------- --------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 70,260 $ 256 $ 70,516
======== ======== ========
50
<PAGE>
The principal sources of changes in the standardized measure of
discounted future net cash flows were as follows:
USA Canada Total
--------- -------- ---------
(In thousands)
1994:
Sales and transfers of oil and
natural gas produced,
net of production costs $(16,953) $ (48) $(17,001)
Net changes in prices and
production costs (14,941) 206 (14,735)
Revisions in quantity estimates
and changes in production timing (482) (5) (487)
Extensions, discoveries and improved
recovery, less related costs 17,050 - 17,050
Purchases of minerals in place 13,426 - 13,426
Sales of minerals in place (138) - (138)
Accretion of discount 7,915 35 7,950
Net change in income taxes (457) (177) (634)
Other - net (554) 8 (546)
--------- -------- ---------
Net change 4,866 19 4,885
Beginning of year 73,152 231 73,383
--------- -------- ---------
End of year $ 78,018 $ 250 $ 78,268
========= ======== =========
1993:
Sales and transfers of oil and
natural gas produced,
net of production costs $(15,359) $ (52) $(15,411)
Net changes in prices and
production costs (4,997) 73 (4,924)
Revisions in quantity estimates
and changes in production timing 483 (70) 413
Extensions, discoveries and improved
recovery, less related costs 12,886 - 12,886
Purchases of minerals in place 1,440 - 1,440
Sales of minerals in place (284) - (284)
Accretion of discount 7,619 36 7,655
Net change in income taxes (74) (8) (82)
Other - net 1,178 (4) 1,174
--------- -------- --------
Net change 2,892 (25) 2,867
Beginning of year 70,260 256 70,516
--------- -------- --------
End of year $ 73,152 $ 231 $ 73,383
========= ======== =========
51
<PAGE>
USA Canada Total
--------- -------- --------
(In Thousands)
1992:
Sales and transfers of oil
and natural gas produced,
net of production costs $(14,693) $ (65) $(14,758)
Net changes in prices and
production costs (1,081) (117) (1,198)
Revisions in quantity estimates
and changes in production timing 4,113 2 4,115
Extensions, discoveries and improved
recovery, less related costs 3,677 - 3,677
Purchases of minerals in place 9,488 - 9,488
Sales of minerals in place (47) - (47)
Accretion of discount 6,602 49 6,651
Net change in income taxes (2,870) 95 (2,775)
Other - net 2,104 5 2,109
--------- -------- ---------
Net change 7,293 (31) 7,262
Beginning of year 62,967 287 63,254
--------- -------- ---------
End of year $ 70,260 $ 256 $ 70,516
========= ======== =========
The Company's SMOG and changes therein were determined in accordance
with Statement of Financial Accounting Standards No. 69. Certain infor-
mation concerning the assumptions used in computing SMOG and their inherent
limitations are discussed below. Management believes such information is
essential for a proper understanding and assessment of the data presented.
The assumptions used to compute SMOG do not necessarily reflect
management's expectations of actual revenues to be derived from those
reserves nor their present worth. Assigning monetary values to the reserve
quantity estimation process does not reduce the subjective and ever-changing
nature of such reserve estimates. Additional subjectivity occurs
when determining present values because the rate of producing the reserves
must be estimated. In addition to errors inherent in predicting the
future, variations from the expected production rate could result from
factors outside of management's control, such as unintentional delays in
development, environmental concerns or changes in prices or regulatory
controls. Also, the reserve valuation assumes that all reserves will be
disposed of by production. However, other factors such as the sale of
reserves in place could affect the amount of cash eventually realized.
Future cash flows are computed by applying year-end prices of oil and
natural gas relating to proved reserves to the year-end quantities of those
reserves. Future price changes are considered only to the extent provided
by contractual arrangements in existence at year-end.
Future production and development costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and
natural gas reserves at the end of the year, based on continuation of
existing economic conditions.
52
<PAGE>
Future income tax expenses are computed by applying the appropriate
year-end statutory tax rates to the future pretax net cash flows relating
to proved oil and natural gas reserves less the tax basis of the Company's
properties. The future income tax expenses also give effect to permanent
differences and tax credits and allowances relating to the Company's proved
oil and natural gas reserves.
Care should be exercised in the use and interpretation of the above
data. As production occurs over the next several years, the results shown
may be significantly different as changes in production performance,
petroleum prices and costs are likely to occur.
As disclosed in Note 4, the Company is receiving payments from a
natural gas purchaser which are subject to recoupment from future natural
gas production. The amounts received will be reflected in revenues and the
reserves and future net cash flows will be reduced as recoupment occurs.
Subsequent to December 31, 1994, the natural gas industry experienced
a significant downturn in natural gas prices. The Company's reserves were
determined at December 31, 1994 using a natural gas price of approximately
$1.70 per Mcf for natural gas not subject to long-term contracts. At
February 21, 1995, the natural gas prices received by the Company fell to
approximately $1.41 per Mcf for natural gas not subject to long-term
contracts. This decrease in natural gas prices would have had a
significant effect on the SMOG value of the Company's reserves at December
31, 1994 and would have resulted in a provision to reduce the carrying
value of oil and natural gas properties of approximately $3.5 million.
53
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
The Shareholders and Board of Directors
Unit Corporation
We have audited the accompanying consolidated balance sheets of Unit
Corporation and subsidiaries as of December 31, 1994 and 1993 and the
related consolidated statements of operations, changes in shareholders'
equity and cash flows and the related financial statement schedule for each
of the three years in the period ended December 31, 1994. These financial
statements and financial statement schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Unit
Corporation and subsidiaries as of December 31, 1994 and 1993, and the con-
solidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1994 in conformity with
generally accepted accounting principles. In addition, in our opinion, the
financial statement schedule referred to above, when considered in relation
to the basic financial statements taken as a whole, presents fairly, in all
material respects, the information required to be included therein.
COOPERS & LYBRAND L.L.P.
Tulsa, Oklahoma
February 22, 1995
54
<PAGE>
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
UNIT CORPORATION
DATE: March 30, 1995 By: /s/ Larry D. Pinkston
-------------- ---------------------------
LARRY D. PINKSTON
Vice President and Chief Financial
Officer and Treasurer
<PAGE>
EXHIBIT 24.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statements
of Unit Corporation on Form S-8 (File No.'s 33-19652, 33-44103 and 33-49724)
and Form S-3 (File No. 33-16116) of our report dated February 22, 1995, on
our audits of the consolidated financial statements and financial statement
schedule of Unit Corporation as of December 31, 1994 and 1993, and for the
years ended December 31, 1994, 1993 and 1992, which report is included in
this Form 10-K/A Amendment No. 1.
COOPERS & LYBRAND L.L.P.
Tulsa, Oklahoma
March 30, 1995
