F O R M 1 0-K/A
Amendment No. 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, 2003
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:
Title of each class Name of each exchange
------------------- on which registered
Common Stock, par value -------------------
$.20 per share New York Stock Exchange
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. ___
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2).
Yes _X_ No ___
Aggregate Market Value of the Voting Stock Held By
Non-affiliates on June 30, 2003 - $669,121,359
Number of Shares of Common Stock
Outstanding on March 11, 2004 - 45,709,568
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the Annual
Meeting of Stockholders to be held May 5, 2004 are incorporated by reference in
Part III.
Exhibit Index - See Page 113
Unit Corporation
Form 10-K/A
Amendment No. 1
Explanatory Note
----------------
This Amendment No. 1 on Form 10-K/A to Unit Corporation's Annual Report on
Form 10-K for the year ended December 31, 2003 is being filed solely to correct
a typographical error contained in Item 8, Financial Statements and
Supplementary Data, Note 13. Total proved developed natural gas reserves are
182,853 MMcf rather than 128,853 MMcf as originally filed. This Amendment also
includes updated Exhibits 31.1 and 31.2 as contemplated by Rule 12b-15
promulgated under the Securities Exchange Act of 1934, as amended. In all other
respects, the text of this Amendment remains unchanged from the previously filed
Annual Report on Form 10-K.
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this amendment to be signed on its behalf by the
undersigned, thereunto duly authorized.
UNIT CORPORATION
(Registrant)
By: /s/ David T. Merrill
----------------------------
David T. Merrill
Chief Financial Officer and
Treasurer
Date: March 17, 2004
Item 8. Financial Statements and Supplementary Data
------- --------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
------------------------
2002 2003
---------- ----------
(In thousands)
ASSETS
------
Current Assets:
Cash and cash equivalents $ 497 $ 598
Accounts receivable (less allowance for
doubtful accounts of $1,203 and $1,223) 33,912 58,807
Materials and supplies 8,794 8,023
Income tax receivable 3,602 112
Prepaid expenses and other 4,594 5,202
---------- ----------
Total current assets 51,399 72,742
---------- ----------
Property and Equipment:
Drilling equipment 369,777 424,321
Oil and natural gas properties, on
the full cost method:
Proved Properties 449,226 528,110
Undeveloped Leasehold not being
amortized 16,024 17,486
Transportation equipment 6,856 9,828
Other 9,906 14,535
---------- ----------
851,789 994,280
Less accumulated depreciation, depletion,
amortization and impairment 341,031 385,219
---------- ----------
Net property and equipment 510,758 609,061
---------- ----------
Goodwill 12,794 23,722
Other Assets 3,212 7,400
---------- ----------
Total Assets $ 578,163 $ 712,925
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
48
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31,
------------------------
2002 2003
---------- ----------
(In thousands)
LIABILITIES AND SHAREHOLDERS' EQUITY
-----------------------------------
Current Liabilities:
Current portion of long-term
debt and other liabilities (Note 4) $ 1,465 $ 1,015
Accounts payable 21,119 32,871
Accrued liabilities 11,921 15,921
Contract advances 27 2,004
---------- ----------
Total current liabilities 34,532 51,811
---------- ----------
Long-Term Debt (Note 4) 30,500 400
---------- ----------
Other Long-Term Liabilities (Note 4) 5,439 17,893
---------- ----------
Deferred Income Taxes (Note 5) 86,320 127,053
---------- ----------
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,
75,000,000 shares authorized,
43,339,400 and 45,592,012
shares issued, respectively 8,668 9,117
Capital in excess of par value 264,180 307,938
Retained earnings 148,524 198,713
---------- ----------
Total shareholders' equity 421,372 515,768
---------- ----------
Total Liabilities and Shareholders' Equity $ 578,163 $ 712,925
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
49
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
--------------------------------------
2001 2002 2003
---------- ---------- ----------
(In thousands except per share amounts)
Revenues:
Contract drilling $ 167,042 $ 118,173 $ 183,146
Oil and natural gas 90,237 67,959 116,609
Other 1,900 1,504 2,829
---------- ---------- ----------
Total revenues 259,179 187,636 302,584
---------- ---------- ----------
Expenses:
Contract drilling:
Operating costs 91,006 91,338 138,762
Depreciation 13,888 14,684 23,644
Oil and natural gas:
Operating costs 22,196 20,795 25,169
Depreciation, depletion,
amortization and
impairment 22,116 23,338 27,343
General and administrative 8,476 8,712 9,222
Interest 2,818 973 693
---------- ---------- ----------
Total expenses 160,500 159,840 224,833
---------- ---------- ----------
Income Before Income Taxes and
Change in Accounting Principle 98,679 27,796 77,751
---------- ---------- ----------
Income Tax Expense:
Current 5,609 (3,469) --
Deferred 30,304 13,021 28,887
---------- ---------- ----------
Total income taxes 35,913 9,552 28,887
---------- ---------- ----------
Income Before Change in
Accounting Principle 62,766 18,244 48,864
Cumulative Effect of Change
in Accounting Principle (Net
of Income Tax of $811) -- -- 1,325
---------- ---------- ----------
Net Income $ 62,766 $ 18,244 $ 50,189
========== ========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
50
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME - CONTINUED
Year Ended December 31,
--------------------------------------
2001 2002 2003
---------- ---------- ----------
(In thousands except per share amounts)
Basic Earnings Per Common
Share:
Income before change in
accounting principle $ 1.75 $ 0.47 $ 1.12
Cumulative effect of change
in accounting principle
net of income tax -- -- 0.03
---------- ---------- ----------
Net income $ 1.75 $ 0.47 $ 1.15
========== ========== ==========
Diluted Earnings Per Common
Share:
Income before change in
accounting principle $ 1.73 $ 0.47 $ 1.12
Cumulative effect of change
in accounting principle
net of income tax -- -- 0.03
---------- ---------- ----------
Net income $ 1.73 $ 0.47 $ 1.15
========== ========== ==========
Pro Forma Amounts Assuming
Retroactive Application of
Change in Accounting
Principle:
Net income $ 62,662 $ 18,115
========== ==========
Basic earnings per share $ 1.74 $ 0.47
========== ==========
Diluted earnings per share $ 1.73 $ 0.46
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
51
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Year Ended December 31, 2001, 2002 and 2003
Accumulated
Capital Other
In Excess Comprehen-
Common of Par Retained sive Treasury
Stock Value Earnings Income Stock Total
-------- ---------- --------- --------- -------- ----------
(In thousands except share amounts)
Balances,
January 1, 2001 $ 7,154 $ 139,872 $ 67,514 $ -- $ -- $ 214,540
Net Income -- -- 62,766 -- -- 62,766
Activity in
employee
compensation
plans
(237,923
shares) 47 2,105 -- -- -- 2,152
Purchase of
treasury
shares
(30,000
shares) -- -- -- -- (296) (296)
Other
comprehen-
sive income
(net of
tax of $771
and $771):
Change in
value of
cash flow
deriva-
tive
instru-
ments
used as
cash
flow hedges -- -- -- 1,258 -- 1,258
Adjustment
reclas-
ification -
deriva-
tive
settle-
ments -- -- -- (1,258) -- (1,258)
-------- ---------- --------- --------- -------- ----------
Balances,
December 31, 2001 $ 7,201 $ 141,977 $130,280 $ -- $ (296) $ 279,162
======== ========== ========= ========= ======== ==========
The accompanying notes are an integral part of the
consolidated financial statements
52
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY - CONTINUED
Year Ended December 31, 2001, 2002 and 2003
Accumulated
Capital Other
In Excess Comprehen-
Common of Par Retained sive Treasury
Stock Value Earnings Income Stock Total
-------- ---------- --------- --------- -------- ----------
(In thousands except share amounts)
Balances,
January 1, 2002 $ 7,201 $ 141,977 $130,280 $ -- $ (296) $ 279,162
Net Income -- -- 18,244 -- -- 18,244
Activity in
employee
compensation
plans
(113,133
shares) 23 1,156 -- -- 296 1,475
Issuance of
stock
for
acquisition
(7,220,000
shares) 1,444 121,047 -- -- -- 122,491
Other
comprehen-
sive income
(net of tax
of $15
and $15):
Change in
value of
cash flow
deriva-
tive
instr-
uments
used as
cash flow
hedges -- -- -- 25 -- 25
Adjustment
reclas-
ification -
deriva-
tive
settle-
ments -- -- -- (25) -- (25)
-------- ---------- --------- --------- -------- ----------
Balances,
December 31, 2002 $ 8,668 $ 264,180 $148,524 $ -- $ -- $ 421,372
======== ========== ========= ========= ======== ==========
The accompanying notes are an integral part of the
consolidated financial statements
53
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY - CONTINUED
Year Ended December 31, 2001, 2002 and 2003
Accumulated
Capital Other
In Excess Comprehen-
Common of Par Retained sive Treasury
Stock Value Earnings Income Stock Total
-------- ---------- --------- --------- -------- ----------
(In thousands except share amounts)
Balances,
January 1, 2003 $ 8,668 $ 264,180 $148,524 $ -- $ -- $ 421,372
Net Income -- -- 50,189 -- -- 50,189
Activity in
employee
compensation
plans
(252,612
shares) 49 2,018 -- -- -- 2,067
Issuance of
2,000,000
shares
of common
stock) 400 41,740 -- -- -- 42,140
Other
comprehen-
sive income
(net of
tax of $3
and $3):
Change in
value of
cash flow
deriva-
tive
instru-
ments
used as
cash
flow hedges -- -- -- (4) -- (4)
Adjustment
reclas-
ifica-
tion -
deriva-
tive
settle-
ments -- -- -- 4 -- 4
-------- ---------- --------- --------- -------- ----------
Balances,
December 31, 2003 $ 9,117 $ 307,938 $198,713 $ -- $ -- $ 515,768
======== ========== ========= ========= ======== ==========
The accompanying notes are an integral part of the
consolidated financial statements
54
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
------------------------------------
2001 2002 2003
---------- ---------- ----------
(In thousands)
Cash Flows From Operating
Activities:
Net Income $ 62,766 $ 18,244 $ 50,189
Adjustments to reconcile
net income to net cash
provided (used) by
operating activities:
Depreciation, depletion,
amortization and
impairment 36,642 38,657 51,783
Equity in net earnings of
unconsolidated investments (1,148) (745) (1,516)
Loss (gain) on disposition
of assets (56) (69) 51
Employee stock compensation
plans 2,873 1,165 1,415
Bad debt expense -- 603 645
Plugging liability -
cumulative effect -
net of accretion -- -- (1,624)
Deferred tax expense 30,304 13,021 28,887
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable 6,334 (43) (25,540)
Materials and supplies (1,556) (3,436) 771
Prepaid expenses and other (3,533) 2,365 4,240
Accounts payable (155) 1,784 6,148
Accrued liabilities 929 (350) 4,286
Contract advances 61 (213) 1,977
Other liabilities (440) (436) --
---------- ---------- ----------
Net cash provided by
operating activities 133,021 70,547 121,712
---------- ---------- ----------
The accompanying notes are an integral part of the
consolidated financial statements
55
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31,
------------------------------------
2001 2002 2003
---------- ---------- ----------
(In thousands)
Cash Flows From Investing
Activities:
Capital expenditures (including
producing property and
contract drilling
acquisitions) $(108,339) $ (75,225) $(131,162)
Proceeds from disposition of
property and equipment 2,631 1,949 1,625
(Acquisition) disposition
of other assets 17 540 (2,562)
---------- ---------- ----------
Net cash used in
investing activities (105,691) (72,736) (132,099)
---------- ---------- ----------
Cash Flows From Financing
Activities:
Borrowings under line of credit 57,200 36,700 65,200
Payments under line of credit (79,200) (36,200) (95,300)
Net payments on notes payable
and other long-term debt (1,000) (1,161) (1,105)
Proceeds from exercise of
stock options 609 413 452
Proceeds from sale of common
stock -- -- 42,140
Book overdrafts (Note 1) (4,978) 2,543 (899)
Acquisition of treasury stock (296) -- --
---------- ---------- ----------
Net cash provided by
(used in) financing
activities (27,665) 2,295 10,488
---------- ---------- ----------
Net Increase (Decrease) in Cash
and Cash Equivalents (335) 106 101
Cash and Cash Equivalents,
Beginning of Year 726 391 497
---------- ---------- ----------
Cash and Cash Equivalents,
End of Year $ 391 $ 497 $ 598
========== ========== ==========
Supplemental Disclosure of Cash
Flow Information:
Cash paid (received) during
the year for:
Interest $ 2,807 $ 1,053 $ 660
Income taxes $ 7,779 $ (4,585) $ (3,495)
See Note 2 for non-cash investing activities.
The accompanying notes are an integral part of the
consolidated financial statements
56
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 ("Unit"). The investment in limited partnerships is accounted for
on the proportionate consolidation method, whereby Unit's share of the
partnerships' assets, liabilities, revenues and expenses is included in the
appropriate classification in the accompanying consolidated financial
statements.
Nature of Business. Unit is engaged in the land contract drilling of natural gas
and oil wells and the exploration, development, acquisition and production of
oil and natural gas properties. Unit's current contract drilling operations are
focused primarily in the natural gas producing provinces of the Oklahoma and
Texas areas of the Anadarko and Arkoma Basins, the Texas Gulf Coast and the
Rocky Mountain regions. Unit's primary exploration and production operations are
also conducted in the Anadarko and Arkoma Basins and in the Texas Gulf Coast
area with additional properties in the Permian Basin. The majority of its
contract drilling and exploration and production activities are oriented toward
drilling for and producing natural gas. At December 31, 2003, Unit had an
interest in a total of 3,393 wells and served as operator of 753 of those wells.
Unit provides land contract drilling services for a wide range of customers
using the drilling rigs, which it owns and operates. In 2003, 84 of Unit's 88
rigs performed contract drilling services.
Drilling Contracts. Unit recognizes revenues and expenses generated from
"daywork" drilling contracts as the services are performed, since the Company
does not bear the risk of completion of the well. Under "footage" and "turnkey"
contracts, Unit bears the risk of completion of the well therefore, revenues and
expenses are recognized when the well is substantially completed. Under this
method, substantial completion is determined when the well bore reaches the
negotiated depth as stated in the contract. The duration of all three types of
contracts range typically from 20 to 90 days, but some of our daywork contracts
in the Rocky Mountains can range up to one year. The entire amount of a 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"
contracts, which are still in process at the end of the period, and are included
in other current assets.
57
Cash Equivalents and Book Overdrafts. Unit includes as cash equivalents,
certificates of deposits and all investments with maturities at date of purchase
of three months or less which are readily convertible into known amounts of
cash. Book overdrafts are checks that have been issued prior to the end of the
period, but not presented to Unit's bank for payment prior to the end of the
period. At December 31, 2002 and 2003, book overdrafts of $3.6 million and $2.7
million have been included in accounts payable.
Property and Equipment. Drilling equipment, transportation equipment and other
property and equipment are carried at cost. Renewals and improvements are
capitalized while repairs and maintenance are expensed. Depreciation of drilling
equipment is recorded using the units-of-production method based on estimated
useful lives, including a minimum provision of 20% of the active rate when the
equipment is idle. Unit 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 computed using the straight-line method over the estimated useful
lives of the assets ranging from 3 to 15 years.
Realization of the carrying value of property and equipment is reviewed for
possible impairment whenever events or changes in circumstances indicate that
the carrying amount may not be recoverable. Assets are determined to be impaired
if a forecast of undiscounted estimated future net operating cash flows directly
related to the asset including disposal value if any, is less than the carrying
amount of the asset. If any asset is determined to be impaired, the loss is
measured as the amount by which the carrying amount of the asset exceeds its
fair value. An estimate of fair value is based on the best information
available, including prices for similar assets. Changes in such estimates could
cause Unit to reduce the carrying value of property and equipment.
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 dispositions 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.
58
Goodwill. Goodwill represents the excess of the cost of the acquisition of
Hickman Drilling Company, CREC Rig Equipment Company, CDC Drilling Company and
SerDrilco Incorporated over the fair value of the net assets acquired. Prior to
January 1, 2002 goodwill was amortized on the straight-line method using a 25
year life. Unit expensed $243,000 annually for the amortization of goodwill. On
July 20, 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 142, "Goodwill and Other
Intangible Assets" ("FAS 142"). For goodwill and intangible assets recorded in
the financial statements, FAS 142 ends the amortization of goodwill and certain
intangible assets and subsequently requires, at least annually, that an
impairment test be performed on such assets to determine whether the fair value
has decreased. FAS 142 became effective for the fiscal years starting after
December 15, 2001 (January 1, 2002 for Unit). Goodwill is all related to the
drilling segment. The 2002 increase in the carrying amount of goodwill of
$7,706,000 came from the goodwill acquired in the acquisition of CREC Rig
Equipment Company and CDC Drilling Company and the 2003 increase in the carrying
amount of goodwill of $10,928,000 came from the goodwill acquired in the
acquisition of SerDrilco Incorporated. Both acquisitions are more fully
discussed in Note 2. Goodwill of $7,009,000 is expected to be deductible for tax
purposes. The following table shows the adjusted net income and earnings per
share resulting from the removal of the amortization expense (net of income tax)
recognized in the prior periods:
2001 2002 2003
--------- --------- ---------
(In thousands except per
share amounts)
Adjusted Net Income:
Reported net income $ 62,766 $ 18,244 $ 50,189
Add back: goodwill amortized - net
of income tax 88 -- --
--------- --------- ---------
Adjusted net income $ 62,854 $ 18,244 $ 50,189
========= ========= =========
Basic Earnings per Share:
Reported net income $ 1.75 $ 0.47 $ 1.15
Add back: goodwill amortized - net
of income tax -- -- --
--------- --------- ---------
Adjusted net income $ 1.75 $ 0.47 $ 1.15
========= ========= =========
Diluted Earnings per Share:
Reported net income $ 1.73 $ 0.47 $ 1.15
Add back: goodwill amortized - net
of income tax -- -- --
--------- --------- ---------
Adjusted net income $ 1.73 $ 0.47 $ 1.15
========= ========= =========
59
Oil and Natural Gas Operations. Unit 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
productive 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. Unit capitalizes internal costs that can be directly
identified with its acquisition, exploration and development activities.
Independent petroleum engineers annually review Unit's determination of its oil
and natural gas reserves. The average composite rates used for depreciation,
depletion and amortization ("DD&A") were $0.91, $1.04 and $1.14 per Mcfe in
2001, 2002 and 2003, respectively. The 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. Unit's
unproved properties totaling $17.5 million are excluded from the DD&A
calculation. 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. The full
cost ceiling is based principally on the estimated future discounted net cash
flows from Unit's oil and natural gas properties. As discussed in Note 13, such
estimates are imprecise.
No gains or losses are recognized on the sale, conveyance or other
disposition of oil and natural gas properties unless a significant reserve
amount is involved.
Unit's contract drilling subsidiary provides drilling services for its
exploration and production subsidiary. The contracts for these services are
issued under the same conditions and rates as the contracts entered into with
unrelated third parties. During 2003, the contract drilling subsidiary drilled
43 wells for our exploration and production subsidiary. As required by the
Securities and Exchange Commission, the profit received by our contract drilling
segment of $2,259,000, $841,000 and $1,883,000 during 2001, 2002 and 2003,
respectively, was used to reduce the carrying value of our oil and natural gas
properties rather than being included in our profits in current operations.
Limited Partnerships. Unit's wholly owned subsidiary, Unit Petroleum Company, is
a general partner in 10 oil and natural gas limited partnerships sold privately
and publicly. Some of Unit's officers, directors and employees own the interests
in most of these partnerships. Unit shares partnership revenues and costs in
accordance with formulas prescribed in each limited partnership agreement. The
partnerships also reimburse Unit for certain administrative costs incurred on
behalf of the partnerships.
Income Taxes. Measurement of current and deferred income 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. 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.
60
Natural Gas Balancing. Unit uses the sales method for recording natural gas
sales. This method allows for recognition of revenue, which may be more or less
than our share of pro-rata production from certain wells. Unit estimates its
December 31, 2003 balancing position to be approximately 1.8 Bcf on
under-produced properties and approximately 2.3 Bcf on over-produced properties.
Unit has recorded a receivable of $562,000 on certain wells where we estimated
that insufficient reserves are available for Unit to recover the
under-production from future production volumes. Unit has also recorded a
liability of $1,191,000 on certain properties where we believe there is
insufficient reserves available to allow the under-produced owners to recover
their under-production from future production volumes. Unit's policy is to
expense the pro-rata share of lease operating costs from all wells as incurred.
Such expenses relating to the balancing position on wells in which Unit has
imbalances are not material.
Investments. Unit owns a 40% equity interest in Superior Pipeline Company LLC, a
natural gas gathering and processing company. The investment, including Unit's
share of the equity in the earnings of this company, totaled $3.0 million at
December 31, 2003 and is reported in other assets.
Unit also owns a 16.7% interest carried at cost in Eagle Energy Partnership
I, L.P. ("Eagle") for $2.5 million. Eagle is engaged in the purchase and sale of
natural gas, electricity (or similar electricity based products), future
commodities, and the performance of scheduling and nomination services for both
energy related commodities and similar energy management functions.
Employee and Director Stock Based Compensation. Unit's stock-based compensation
plans, which are explained more fully in Note 6, are accounted for under the
recognition and measurement principles of APB Opinion 25 "Accounting for Stock
Issued to Employees," and related interpretations. Under this standard, no
compensation expense is recognized for grants of options, which include an
exercise price equal to or greater than the market price of the stock on the
date of grant. Accordingly, based on Unit's grants in 2001, 2002 and 2003 no
compensation expense has been recognized. Compensation expense included in
reported net income is Unit's matching 401(k) contribution which was made in
Unit common stock. The following table illustrates the effect on net income and
earnings per share if Unit had applied the fair value recognition provisions of
FASB Statement No. 123, "Accounting for Stock-Based Compensation," to
stock-based employee compensation.
61
2001 2002 2003
--------- --------- ---------
Net Income, as Reported
(In Thousands) $ 62,766 $ 18,244 $ 50,189
Add Stock Based Employee Compensation
Expense Included in Reported Net
Income - Net of Tax 671 669 858
Less Total Stock Based Employee
Compensation Expense Determined
Under Fair Value Based Method
For All Awards (1,615) (1,488) (2,114)
--------- --------- ---------
Pro Forma Net Income $ 61,822 $ 17,425 $ 48,933
========= ========= =========
Basic Earnings per Share:
As reported $ 1.75 $ 0.47 $ 1.15
========= ========= =========
Pro forma $ 1.72 $ 0.45 $ 1.12
========= ========= =========
Diluted Earnings per Share:
As reported $ 1.73 $ 0.47 $ 1.15
========= ========= =========
Pro forma $ 1.71 $ 0.45 $ 1.12
========= ========= =========
The fair value of each option granted is estimated using the Black-Scholes
model. Unit's estimate of stock volatility in 2001, 2002 and 2003 was 0.55, 0.53
and 0.52, respectively, based on previous stock performance. Dividend yield was
estimated to remain at zero with a risk free interest rate of 5.41% in 2001 and
4.24% in 2002 and 2003. Expected life ranged from 1 to 10 years based on prior
experience depending on the vesting periods involved and the make up of
participating employees. The aggregate fair value of options granted during 2002
and 2003 under the Stock Option Plan were $1,669,000 and $1,617,000,
respectively. No options were issued under the Stock Option Plan in 2001. Under
the Non-Employee Directors' Stock Option Plan the aggregate fair value of
options granted during 2001 was $201,000 and $262,000 in 2002 and 2003.
Self Insurance. Unit utilizes self insurance programs for employee group health
and worker's compensation. Self insurance costs are accrued based upon the
aggregate of estimated liabilities for reported claims and claims incurred but
not yet reported. Accrued liabilities include $3,632,000 and $7,990,000 for
employer group health insurance and worker's compensation at December 31, 2002
and 2003, respectively. Unit's exposure (i.e. deductible or retention) per
occurrence ranged from $200,000 for general liability to $1 million for rig
physical damage. Unit has purchased stop-loss coverage
62
in order to limit, to the extent feasible, its per occurrence and aggregate
exposure to certain claims. Following the acquisition of SerDrilco, Unit
continued to use SerDrilco's ERISA governed occupational injury benefit plan to
cover the SerDrilco employees in lieu of covering them under an insured Texas
workers' compensation plan.
Treasury Stock. On August 30, 2001, Unit's Board of Directors authorized the
purchase of up to one million shares of Unit's common stock. The timing of stock
purchases are made at the discretion of management. During 2001, 30,000 shares
were repurchased for $296,000. These shares were used for a portion of the
company match to the 401(k) Employee Thrift Plan. No treasury stock was owned by
Unit at December 31, 2002 and 2003.
Financial Instruments and Concentrations of Credit Risk. Financial instruments,
which potentially subject Unit to concentrations of credit risk, consist
primarily of trade receivables with a variety of national and international oil
and natural gas companies. Unit does not generally require collateral related to
receivables. Such credit risk is considered by management to be limited due to
the large number of customers comprising Unit's customer base. During 2003,
Chesapeake Operating, Inc. was our largest drilling customer and provided 15% of
our total contract drilling revenues. Purchases by Cinergy Marketing & Trading
LP accounted for approximately 17% of Unit's oil and natural gas revenues in
2003 while purchases by Centerpoint Energy Gas accounted for approximately 16%
of Unit's oil and natural gas revenues. Unit owns a 16.7% in Eagle Energy
Partners I LP, whose purchases accounted for 6% of Unit's oil and natural gas
revenues in 2003. In addition, at December 31, 2002 and 2003, Unit had a
concentration of cash of $3.0 million and $3.5 million, respectively, with one
bank.
Hedging Activities. On January 1, 2001, Unit adopted Statement of Financial
Accounting Standard No. 133 (subsequently amended by Financial Accounting
Standard No.'s 137 and 138), "Accounting for Derivative Instruments and Hedging
Activities" ("FAS 133"). This statement requires all derivatives to be
recognized on the balance sheet and measured at fair value. If a derivative is
designated as a cash flow hedge, Unit is required to measure the effectiveness
of the hedge, or the degree that the gain (loss) for the hedging instrument
offsets the loss (gain) on the hedged item, at each reporting period. The
effective portion of the gain (loss) on the derivative instrument is recognized
in other comprehensive income as a component of equity and subsequently
reclassified into earnings when the forecasted transaction affects earnings. The
ineffective portion of a derivative's change in fair value is required to be
recognized in earnings immediately. Derivatives that do not qualify for hedge
treatment under FAS 133 must be recorded at fair value with gains (losses)
recognized in earnings in the period of change.
Unit periodically enters into derivative commodity instruments to hedge its
exposure to price fluctuations on oil and natural gas production. Such
instruments include regulated natural gas and crude oil futures contracts traded
on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps and basic
hedges with major energy derivative product specialists. Initial adoption of
this standard was not material.
63
Unit entered into a collar contract for approximately 25% of its daily
production for January and February of 2001. The collar had a floor of $26.00
and a ceiling of $33.00 and Unit received $0.86 per barrel for entering into the
collar transaction. During the first quarter of 2001, the net effect of this
hedging transaction yielded an increase in oil revenues of $17,200.
During the second quarter of 2001, Unit entered into a natural gas collar
contract for approximately 36% of its June and July 2001 natural gas production,
at a floor price of $4.50 and a ceiling price of $5.95. During the third quarter
of 2001, Unit entered into two natural gas collar contracts for approximately
38% of its September through November 2001 natural gas production. Both
contracts had a floor price of $2.50. One contract had a ceiling price of $3.68
and the other contract had a ceiling price of $4.25. During 2001 natural gas
collar contracts added $2,030,000 to Unit's natural gas revenues.
On April 30, 2002, Unit entered into a collar contract covering
approximately 19% of its natural gas production for the periods of April 1, 2002
through October 31, 2002. The collar had a floor of $3.00 and a ceiling of
$3.98. During the year of 2002, the natural gas hedging transactions increased
natural gas revenues by $40,300. At December 31, 2002, Unit was not holding any
natural gas or oil derivative contracts.
During the first quarter of 2003, Unit entered into two collar contracts
covering approximately 40% of its natural gas production for the periods of
April 1, 2003 through September 30, 2003. One collar had a floor of $4.00 and a
ceiling of $5.75 and the other collar had a floor of $4.50 and a ceiling of
$6.02. Unit also entered into two collar contracts covering approximately 25% of
its oil production for the periods of May 1, 2003 through December 31, 2003. One
collar had a floor of $25.00 and a ceiling of $32.20 and the other collar had a
floor of $26.00 and a ceiling of $31.40. During the year 2003, the collar
contracts decreased natural gas revenues by $6,000 and oil revenues by $5,000.
We did not have any hedging transactions outstanding at December 31, 2003.
Accounting Estimates. The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Impact of Financial Accounting Pronouncements.
On January 1, 2003 the company adopted Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS 143
establishes an accounting standard requiring the recording of the fair value of
liabilities associated with the retirement of long-lived assets. The company
owns oil and natural gas properties which require expenditures to plug and
abandon the wells when the oil and natural gas reserves in the wells are
depleted. These expenditures under FAS 143 are recorded in the
64
period in which the liability is incurred (at the time the wells are
drilled or acquired). The company does not have any assets restricted for the
purpose of settling the plugging liabilities.
The following table shows the activity for the year ending December 31,
2003 relating to the company's retirement obligation for plugging liability:
Short-Term Long-Term
Plugging Plugging
Liability Liability
------------- -------------
(In Thousands)
Plugging Liability 1/1/03 $ 203 $ 10,632
Accretion of Discount 8 505
Liability Incurred in the Period -- 719
Liability Settled in the Period (65) (120)
Liability Sold (36) (10)
Reclassification of Liability
From Long- to Short-Term 193 (193)
Revision of Estimate -- 158
------------- -------------
Plugging Liability 12/31/03 $ 303 $ 11,691
============= =============
The effect of this change increased net property, plant and equipment by
$13.0 million and liabilities, including deferred tax liabilities, by $11.7
million at January 1, 2003 and decreased net income for the year ended December
31, 2003 by $148,000 ($0.00 per share). The financial statements for the year
ended December 31, 2002 have not been restated and the cumulative effect of the
change of $1.3 million net of tax ($0.03 per share) is shown as a one-time
addition to income in the first quarter of 2003.
65
The following table shows the adjusted net income and earnings per share
resulting from the accretion of the discount and change in the depreciation,
depletion and amortization (both net of income tax) as if the plugging liability
had been recognized in the prior year ended periods:
2000 2001 2002
------------ ------------ ------------
(In thousands except per share amounts)
Adjusted Net Income:
Reported net income $ 34,344 $ 62,766 $ 18,244
Add back:
Decrease in depreciation,
depletion and amortiza-
tion - net of income
tax 80 156 167
Deduct:
Accretion of discount -
net of income tax (231) (260) (296)
------------ ------------ ------------
Adjusted net income $ 34,193 $ 62,662 $ 18,115
============ ============ ============
Basic Earnings per Share:
Reported net income $ 0.96 $ 1.75 $ 0.47
Net adjustment to income
from change in accounting
principle -- (0.01) --
------------ ------------ ------------
Adjusted basic earnings
per share $ 0.96 $ 1.74 $ 0.47
============ ============ ============
Diluted Earnings per Share:
Reported net income $ 0.95 $ 1.73 $ 0.47
Net adjustment to income
from change in accounting
principle -- -- (0.01)
------------ ------------ ------------
Adjusted diluted earnings
per share $ 0.95 $ 1.73 $ 0.46
============ ============ ============
If FAS 143 had been applied at January 1, 2000 and December 31, 2000, 2001
and 2002, the plugging liability would have been $8.0 million, $8.7 million,
$9.7 million and $10.8 million, respectively, assuming the liability was
measured using the information, assumptions and interest rates used as of the
adoption date of January 1, 2003.
On January 17, 2003, the FASB issued FASB Interpretation No. 46,
"Consolidation of Variable Interest Entities, an interpretation of ARB 51" ("FIN
46"). The primary objectives of FIN 46 are to provide guidance on the
identification of entities for which control is achieved through means other
than through voting rights ("variable interest entities" or "VIEs") and how to
determine when and which business enterprise should consolidate
66
the VIE. This new model for consolidation applies to an entity which either
(1) the equity investors (if any) do not have a controlling financial interest
or (2) the equity investment at risk is insufficient to finance that entity's
activities without receiving additional subordinated financial support from
other parties. FIN 46, as amended, was effective for Unit in the fourth quarter
of 2003 as it applies to entities created after February 1, 2003. The adoption
of FIN 46 with respect to these entities, did not have an impact on Unit's
financial position or results of operations. For entities created prior to
February 1, 2003, which are not special purpose entities, as defined in FIN 46,
Unit will have to adopt FIN 46, as amended, in the quarter ending March 31,
2004. Unit is still evaluating FIN 46 with regard to these types of entities in
which it has an ownership interest, primarily oil and gas partnerships and its
equity investment in Superior pipeline. FIN 46 may require full consolidation of
these entities which would increase total assets with an offsetting minority
interest for the percentage not owned by Unit. There will be no net impact to
results of operations from the adoption of FIN 46.
Statement of Financial Accounting Standards No. 141, "Business
Combinations" (FAS 141) and Statement of Financial Accounting Standards, No.
142, "Goodwill and Intangible Assets" (FAS 142) were issued by the FASB in June
2001 and became effective for Unit on July 1, 2001 and January 1, 2002,
respectively. FAS 141 requires all business combinations initiated after June
30, 2001 to be accounted for using the purchase method. Additionally, FAS 141
requires companies to disaggregate and report separately from goodwill certain
intangible assets. FAS 142 establishes new guidelines for accounting for
goodwill and other intangible assets. Under FAS 142, goodwill and certain other
intangible assets are not amortized, but rather are reviewed annually for
impairment. Depending on how the accounting and disclosure literature is
applied, oil and gas mineral rights held under lease and other contractual
arrangements representing the right to extract oil and natural gas reserves for
both undeveloped and developed leaseholds may be classified separately from oil
and gas properties, as intangible assets on our balance sheets. In addition, the
notes to the Unit's financial statements would include the disclosures required
by FAS 141 and 142 regarding intangibles. To date, Unit, like many other oil and
gas companies, has included oil and gas extraction rights as part of the oil and
gas properties, even after FAS 141 and 142 became effective.
Unit's results of operations and cash flows would not be affected, since
these oil and gas mineral extraction rights would continue to be amortized in
accordance with full cost accounting rules.
At December 31, 2002 and 2003, Unit had undeveloped leaseholds of
approximately $13.2 million and $14.8 million, respectively that would be
classified on its balance sheet as "intangible undeveloped leasehold" and
developed leaseholds of an estimated $18.1 million and $24.6 million,
respectively that would be classified as "intangible developed leasehold" if the
interpretations were applied. This classification would require Unit to make the
disclosures set forth under FAS 142 related to these interests.
67
Unit intends to continue to classify its oil and gas mineral extraction
rights as tangible oil and gas properties until further guidance is provided.
NOTE 2 - ACQUISITIONS
---------------------
On December 8, 2003, Unit acquired SerDrilco Incorporated and its
subsidiary, Service Drilling Southwest LLC, for $35.0 million in cash. The terms
of the acquisition include an earn-out provision allowing the sellers to obtain
one-half of the cash flow in excess of $10 million for each of the three years
following the acquisition. The assets of SerDrilco Incorporated included 12
drilling rigs, spare drilling equipment, a fleet of 12 larger trucks and
trailers, various other vehicles and a district office and equipment yard in and
near Borger, Texas. The results of operations for the acquired entity are
included in the statement of operations for the period beginning December 8,
2003 and continuing through December 31, 2003.
Total consideration given in the acquisition was determined based on the
depth capacity of the rigs, the working condition of the rigs and the ability of
the rigs to enhance Unit's ability to provide services and equipment required by
our customers on a timely basis within the Anadarko Basin of Western Oklahoma
and the Texas Panhandle. Unit acquired SerDrilco Incorporated's tax basis in the
property acquired, so a deferred tax liability and goodwill of $10.9 million was
recognized in the recording of the acquisition. The allocation of the total
consideration paid and goodwill recognized for the acquisition is as follows (in
thousands):
Allocation of Total Consideration Paid and
Goodwill Recognized:
Drilling rigs including tubulars $ 31,012
Spare drilling equipment 904
Office, yard & yard equipment 1,200
Trucking fleet 1,486
Other vehicles 398
----------
Total cash consideration 35,000
Goodwill recognized 10,928
----------
Total consideration paid and recognized $ 45,928
==========
68
On August 15, 2002, Unit completed the acquisition of CREC Rig Equipment
Company and CDC Drilling Company ("Cactus Acquisition"). Both of these
acquisitions were stock purchase transactions. Unit issued 6,819,748 shares of
common stock and paid $3,813,053 for all the outstanding shares of CREC Rig
Equipment Company and issued 400,252 shares of common stock and paid $686,947
for all the outstanding shares of CDC Drilling Company. The assets of the
acquired companies included 20 drilling rigs, spare drilling equipment and
vehicles. What we paid in both transactions was determined through arms-length
negotiations between the parties and only the cash portion of the transaction
appears in the investing and financing activities of Unit's Consolidated
Statement of Cash Flows. The results of operations for the acquired entities are
included in the statement of operations for the period beginning August 15, 2002
and continuing through December 31, 2003.
Total consideration given in both the acquisitions was determined based on
the equipment purchased, depth capacity of the rigs, the working condition of
the rigs and the ability of the rigs to enhance Unit's ability to provide
services and equipment required by our customers on a timely basis within the
Anadarko and Gulf Coast areas where the rigs are located. The calculation and
allocation of the total consideration paid for the acquisition are as follows
(in thousands):
Calculation of Consideration Paid:
Unit Corporation common stock
(7,220,000 shares at $16.96556 per share) $ 122,491
Cash 4,500
----------
Total consideration $ 126,991
==========
Allocation of Total Consideration Paid:
Drilling rigs $ 112,994
Spare drilling equipment 3,500
Vehicles 636
Deferred tax asset 2,155
Goodwill 7,706
----------
Total consideration $ 126,991
==========
69
Unaudited summary pro forma results of operations for Unit, reflecting the
Cactus Acquisition as if it had occurred at the beginning of the year ended
December 31, 2001 are as follow:
Year Ended Year Ended
December 31, December 31,
2001 2002
-------------- --------------
(In thousands except per
Per share amounts)
Revenues $ 311,104 $ 215,805
============== ==============
Net Income $ 70,457 $ 15,320
============== ==============
Net Income per
Common Share
(Diluted) $ 1.62 $ 0.34
============== ==============
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.
70
NOTE 3 - EARNINGS PER SHARE
---------------------------
The following data shows the amounts used in computing earnings per share.
Weighted
Income Shares Per-Share
(Numerator) (Denominator) Amount
------------- ------------- ----------
(In thousands except per share amounts)
For the Year Ended
December 31, 2001:
Basic earnings per
common share $ 62,766 35,967 $ 1.75
==========
Effect of dilutive
stock options 291
------------- -------------
Diluted earnings per
common share $ 62,766 36,258 $ 1.73
============= ============= ==========
For the Year Ended
December 31, 2002:
Basic earnings per
common share $ 18,244 38,844 $ 0.47
==========
Effect of dilutive
stock options 268
------------- -------------
Diluted earnings per
common share $ 18,244 39,112 $ 0.47
============= ============= ==========
71
Weighted
Income Shares Per-Share
(Numerator) (Denominator) Amount
------------- ------------- ----------
(In thousands except)
per share amounts)
For the Year Ended
December 31, 2003:
Basic earnings per
common share:
Income before
change in
accounting
principle $ 48,864 43,616 $ 1.12
Cumulative effect
of change in
accounting
principle net
of income tax 1,325 43,616 0.03
----------- ----------
Net Income $ 50,189 43,616 $ 1.15
=========== ==========
Diluted earnings per
common share:
Weighted average
number of common
shares used in
basic earnings
per common share 43,616
Effect of dilutive
stock options 157
-------------
Weighted average
number of common
shares and
dilutive potential
common shares used
in diluted earnings
per share 43,773
=============
Income before change
in accounting
principle $ 48,864 43,773 $ 1.12
Cumulative effect of
change in
accounting
principle net
of income tax 1,325 43,773 0.03
----------- ----------
Net Income $ 50,189 43,773 $ 1.15
=========== ==========
72
The following options and their average exercise prices were not included
in the computation of diluted earnings per share because the option exercise
prices were greater than the average market price of common shares for the years
ended December 31,:
2001 2002 2003
---------- ---------- ----------
Options 153,000 198,500 137,850
========== ========== ==========
Average Exercise Price $ 16.79 $ 19.01 $ 22.52
========== ========== ==========
NOTE 4 - LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
-------------------------------------------------------
Long-term debt consisted of the following as of December 31, 2002 and 2003:
2002 2003
---------- ----------
(In thousands)
Revolving Credit and Term Loan,
with Interest at December 31,
2002 and 2003 of 2.5% and 4.0%,
Respectively $ 30,500 $ 400
Notes Payable for Hickman
Drilling Company Acquisition
with Interest at December 31,
2002 of 4.25% 1,000 --
---------- ----------
31,500 400
Less Current Portion 1,000 --
---------- ----------
Total Long-Term Debt $ 30,500 $ 400
========== ==========
At December 31, 2003, Unit had a $100 million bank loan agreement
consisting of a revolving credit facility through May 1, 2005 and a term loan
thereafter, maturing on May 1, 2008. On January 30, 2004, in conjunction with
Unit's acquisition of PetroCorp Incorporated, Unit replaced its loan agreement
with a revolving credit facility totaling $150 million having a four year term
ending January 30, 2008. Borrowings under the new credit facility are limited to
a commitment amount. Although, the current value of Unit's assets under the
latest loan value computation supported a full $150 million, Unit elected to set
the loan commitment at
73
$120 million in order to reduce financing costs. Unit pays a commitment fee of
..375 of 1% for any unused portion of the commitment amount. Unit paid
origination, agency and syndication fees of $515,000 at the inception of the new
agreement $40,000 of which will be paid annually and the remainder of the fees
will be amortized over the 4 year life of the loan.
The borrowing base under the current credit facility is subject to a
semi-annual re-determination on May 10 and November 10 of each year, beginning
May 10, 2004. The calculation is based primarily on the sum of a percentage of
the discounted future value of Unit's oil and natural gas reserves, as
determined by the banks. In addition, an amount representing a part of the value
of Unit's drilling rig fleet, limited to $20 million, is added to the borrowing
base. Provisions are also in the agreement which allow for one requested special
re-determination of the borrowing base by either the lender or Unit between each
scheduled re-determination date if conditions warrant such a request.
At Unit's election, any portion of the debt outstanding may be fixed at a
Eurodollar Rate for 30, 60, 90 or 180 day terms. During any Eurodollar Rate
funding period the outstanding principal balance of the note to which such
Eurodollar Rate option applies may be repaid upon three days prior notice to the
Administrative Agent. Interest on the Eurodollar Rate is computed at the
Eurodollar Base Rate applicable for the interest period plus 1.00% tp 1.50%
depending on the level of debt as a percentage of the total loan value and
payable at the end of each term or every 90 days whichever is less. Borrowings
not under the Eurodollar Rate bear interest at the JPMorgan Chase Prime Rate
payable at the end of each month and the principal borrowed may be paid anytime
in part or in whole without premium or penalty.
The loan agreement includes prohibitions against:
. the payment of dividends (other than stock dividends) during any fiscal
year in excess of 25% of our consolidated net income for the preceding
fiscal year,
. the incurrence of additional debt with certain very limited exceptions
and
. the creation or existence of mortgages or liens, other than those in the
ordinary course of business, on any of our property, except in favor of
Unit's banks.
The loan agreement also requires that at the end of each quarter:
. consolidated net worth of at least $350 million,
. a current ratio (as defined in the loan agreement) of not less than 1 to
1 and
. a leverage ratio of long-term debt to consolidated EBITDA (as defined in
the loan agreement) for the most recently ended rolling four fiscal
quarters of no greater than 3.25 to 1.0.
74
Other long-term liabilities consisted of the following as of December 31,
2002 and 2003:
2002 2003
---------- ----------
(In thousands)
Separation Benefit Plan $ 2,081 $ 2,545
Deferred Compensation Plan 1,391 1,829
Retirement Agreement 1,412 1,349
Gas Balancing Liability 1,020 1,191
Plugging Liability -- 11,994
---------- ----------
5,904 18,908
Less Current Portion 465 1,015
---------- ----------
Total Other Long-Term Liabilities $ 5,439 $ 17,893
========== ==========
Estimated annual principal payments under the terms of long-term debt and
other long-term liabilities from 2004 through 2008 are $1,015,000, $606,000,
$686,000, $841,000 and $679,000. Based on the borrowing rates currently
available to Unit for debt with similar terms and maturities, long-term debt at
December 31, 2003 approximates its fair value.
75
NOTE 5 - INCOME TAXES
---------------------
A reconciliation of the income tax expense, computed by applying the
federal statutory rate to pre-tax income to Unit's effective income tax expense
is as follows:
2001 2002 2003
---------- ---------- ----------
(In thousands)
Income Tax Expense Computed by
Applying the Statutory Rate $ 34,538 $ 9,739 $ 27,213
State Income Tax, Net of
Federal Benefit 2,859 834 2,333
Statutory Depletion and Other (1,484) (1,021) (659)
---------- ---------- ----------
Income tax expense $ 35,913 $ 9,552 $ 28,887
========== ========== ==========
Deferred tax assets and liabilities are comprised of the following at
December 31, 2002 and 2003:
2002 2003
----------- -----------
(In thousands)
Deferred Tax Assets:
Allowance for losses
and nondeductible accruals $ 3,942 $ 9,972
Net operating loss carryforward 17,752 20,745
Statutory depletion carryforward 4,231 4,476
Alternative minimum tax credit
carryforward 395 395
----------- -----------
Gross deferred tax assets 26,320 35,588
Deferred Tax Liability:
Depreciation, depletion and
amortization (110,598) (159,990)
----------- -----------
Net deferred tax liability (84,278) (124,402)
Current Deferred Tax Asset 2,042 2,651
----------- -----------
Non-Current - Deferred Tax Liability $ (86,320) $ (127,053)
=========== ===========
76
Realization of the deferred tax asset is dependent on generating sufficient
future taxable income. Although realization is not assured, management believes
it is more likely than not that the deferred tax asset will be realized. The
amount of the deferred tax asset considered realizable, however, could be
reduced in the near-term if estimates of future taxable income are reduced.
At December 31, 2003, Unit has an excess statutory depletion carryforward
of approximately $11,778,000, which may be carried forward indefinitely and is
available to reduce future taxable income, subject to statutory limitations. At
December 31, 2003, Unit has net operating loss carryforwards of approximately
$54,591,000 which expire from 2019 to 2022.
NOTE 6 - EMPLOYEE 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. On May 3, 1995, Unit's shareholders
approved and amended the Plan to increase by 250,000 shares the aggregate number
of shares of common stock that could be issued 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 installments
subject to certain restrictions. No shares were issued under the Plan in 2001,
2002 and 2003.
Unit also has a Stock Option Plan (the "Option Plan"), which provides for
the granting of options for up to 2,700,000 shares of common stock to officers
and employees. The Option Plan permits the issuance of qualified or nonqualified
stock options. Options granted typically become exercisable at the rate of 20%
per year one year after being granted and expire after 10 years from the
original grant date. The exercise price for options granted under this plan is
the fair market value of the common stock on the date of the grant.
77
Activity pertaining to the Stock Option Plan is as follows:
Weighted
Number Average
of Exercise
Shares Price
----------- ----------
Outstanding at January 1, 2001 719,700 $ 6.87
Exercised (177,200) 3.13
Cancelled (10,400) 10.26
----------- ----------
Outstanding at December 31, 2001 532,100 8.09
Granted 160,000 19.03
Exercised (59,400) 5.67
----------- ----------
Outstanding at December 31, 2002 632,700 11.08
Granted 116,850 22.89
Exercised (202,900) 5.94
Cancelled (9,900) 15.41
----------- ----------
Outstanding at December 31, 2003 536,750 $ 15.52
=========== ==========
Outstanding Options
at December 31, 2003
---------------------------------------
Weighted
Average Weighted
Number Remaining Average
Exercise of Contractual Exercise
Prices Shares Life Price
----------------------- ----------- ----------- -----------
$ 3.00 - $ 4.00 99,600 3.8 years $ 3.52
$ 7.25 - $10.00 45,700 3.2 years $ 8.52
$11.31 - $14.06 3,500 5.8 years $ 13.28
$16.69 - $22.95 387,950 8.6 years $ 19.44
78
Exercisable Options
At December 31, 2003
------------------------
Weighted
Number Average
Exercise of Exercise
Prices Shares Price
------------------------------------ ----------- -----------
$ 2.75 - $ 4.00 99,600 $ 3.52
$ 7.25 - $10.00 45,700 $ 8.52
$11.31 - $14.06 2,500 $ 12.96
$16.69 - $19.04 108,500 $ 17.49
Options for 329,300, 355,100 and 256,300 shares were exercisable with
weighted average exercise prices of $6.25, $7.28 and $5.32 at December 31, 2001,
2002 and 2003, respectively.
In February and May 1992, the Board of Directors and shareholders,
respectively, approved the Unit Corporation Non-Employee Directors' Stock Option
Plan (the "Old Plan") and in February and May 2000, the Board of Directors and
shareholders, respectively, approved the Unit Corporation 2000 Non-Employee
Directors' Stock Option Plan (the "Directors' Plan"). Under the Directors' Plan,
which replaced the Old Plan, an aggregate of 300,000 shares of Unit's common
stock may be issued upon exercise of the stock options. Under the Old Plan, on
the first business day following each annual meeting of stockholders of Unit,
each person who was then a member of the Board of Directors of Unit and who was
not then an employee of Unit or any of its subsidiaries was granted an option to
purchase 2,500 shares of common stock. Under the Directors' Plan, commencing
with the year 2000 annual meeting, the amount granted has been increased to
3,500 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 10 years from the date
of grant.
79
Activity pertaining to the Directors' Plan is as follows:
Weighted
Number Average
of Exercise
Shares Price
----------- ----------
Outstanding at January 1, 2001 95,000 $ 7.03
Granted 17,500 17.54
Exercised (37,000) 6.80
----------- ----------
Outstanding at December 31, 2001 75,500 9.58
Granted 21,000 20.10
Exercised (2,500) 1.75
----------- ----------
Outstanding at December 31, 2002 94,000 12.14
Granted 21,000 20.46
Exercised (34,500) 7.73
----------- ----------
Outstanding at December 31, 2003 80,500 $ 8.94
=========== ==========
Outstanding and
Exercisable Options
at December 31, 2003
---------------------------------------
Weighted
Average Weighted
Number Remaining Average
Exercise of Contractual Exercise
Prices Shares Life Price
----------------------- ----------- ----------- -----------
$ 2.88 - $ 3.75 2,500 0.4 years $ 2.88
$ 6.87 - $ 9.00 15,000 3.8 years $ 7.58
$12.19 - $17.54 21,000 7.0 years $ 15.76
$20.10 - $20.46 42,000 8.8 years $ 20.28
80
Under Unit'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. Unit may match each employee's
contribution, up to a specified maximum, in full or on a partial basis. Unit
made discretionary contributions under the plan of 35,016, 87,452 and 61,175
shares of common stock and recognized expense of $1,082,000, $1,079,000 and
$1,365,000 in 2001, 2002 and 2003, respectively.
Unit provides a salary deferral plan ("Deferral Plan") which 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 Unit's obligation under the Deferral Plan at
December 31, 2001, 2002 and 2003 totaled $1,277,000, $1,391,000 and $1,829,000,
respectively. Unit recognizes payroll expense and records a liability at the
time of deferral.
Effective January 1, 1997, Unit adopted a separation benefit plan
("Separation Plan"). The Separation Plan allows eligible employees whose
employment with Unit is involuntarily terminated or, in the case of an employee
who has completed 20 years of service, voluntarily or involuntarily terminated,
to receive benefits equivalent to 4 weeks salary for every whole year of service
completed with Unit up to a maximum of 104 weeks. To receive payments the
recipient must waive any claims against Unit in exchange for receiving the
separation benefits. On October 28, 1997, Unit adopted a Separation Benefit Plan
for Senior Management ("Senior Plan"). The Senior Plan provides certain officers
and key executives of Unit with benefits generally equivalent to the Separation
Plan. The Compensation Committee of the Board of Directors has absolute
discretion in the selection of the individuals covered in this plan. Unit
recognized expense of $589,000, $619,000 and $707,000 in 2001, 2002 and 2003,
respectively, for benefits associated with anticipated payments from both
separation plans.
Unit has entered into key employee change of control contracts with six of
its current executive officers. These severance contracts have an initial
three-year term that is automatically extended for one year upon each
anniversary, unless a notice not to extend is given by Unit. If a change of
control of the company, as defined in the contracts, occurs during the term of
the severance contract, then the contract becomes operative for a fixed
three-year period. The severance contracts generally provide that the
executive's terms and conditions for employment (including position, work
location, compensation and benefits) will not be adversely changed during the
three-year period after a change of control. If the executive's employment is
terminated (other than for cause, death or disability), the executive terminates
for good reason during such three-year period, or the executive terminates
employment for any reason during the 30-day period following the first
anniversary of the change of control, and upon certain terminations prior to a
change of control or in connection with or in anticipation of a change of
control, the executive is generally entitled to receive, in addition to certain
other benefits, any earned but unpaid compensation; up to 2.9 times the
executive's base salary
81
plus annual bonus (based on historic annual bonus); and the company matching
contributions that would have been made had the executive continued to
participate in the company's 401(k) plan for up to an additional three years.
The severance contract provides that the executive is entitled to receive a
payment in an amount sufficient to make the executive whole for any excise tax
on excess parachute payments imposed under Section 4999 of the Code. As a
condition to receipt of these severance benefits, the executive must remain in
the employ of the company prior to change of control and render services
commensurate with his position.
NOTE 7 - TRANSACTIONS WITH RELATED PARTIES
------------------------------------------
Unit Petroleum Company serves as the general partner of 10 oil and gas
limited partnerships. Four were formed for investment by third parties and six
(the employee partnerships) were formed to allow employees of Unit and its
subsidiaries and directors of Unit to participate in Unit Petroleum's oil and
gas exploration and production operations. The partnerships for the third party
investments were formed in 1984, 1985 and 1986. An additional third party
partnership, the 1979 Oil and Gas Limited Partnership was dissolved on July 1,
2003. Employee partnerships have been formed for each year beginning with 1984.
Interests in the employee partnerships were offered to the employees of Unit and
its subsidiaries whose annual base compensation was at least a specified amount
($22,680 for 2002 and 2003 and $36,000 for 2004) and to the directors of Unit.
The employee partnerships formed in 1984 through 1990 were consolidated
into a single consolidating partnership in 1993 and the employee partnerships
formed in 1991 through 1999 were also consolidated into the consolidating
partnership in 2002. The consolidation of the 1991 through the 1999 employee
partnerships at the end of last year was done by the general partners under the
authority contained in the respective partnership agreements and did not involve
any vote, consent or approval by the limited partners. The employee partnerships
have each had a set percentage (ranging from 1% to 15%) of our interest in most
of the oil and natural gas wells we drill or acquire for our own account during
the particular year for which the partnership was formed. The total interest the
employees have in our oil and natural gas wells by participating in these
partnerships does not exceed one percent.
82
Amounts received in the years ended December 31 from both public and
private Partnerships for which Unit is a general partner are as follows:
2001 2002 2003
--------- --------- ---------
(In thousands)
Contract Drilling $ 416 $ 209 $ 428
Well Supervision and Other Fees $ 498 $ 510 $ 236
General and Administrative
Expense Reimbursement $ 193 $ 210 $ 209
Related party transactions for contract drilling and well supervision fees
are the related party's share of such costs. These costs are billed to related
parties on the same basis as billings to unrelated parties for such services.
General and administrative reimbursements are both direct general and
administrative expense incurred on the related party's behalf and indirect
expenses allocated to the related parties. Such allocations are based on the
related party's level of activity and are considered by management to be
reasonable.
A subsidiary of Unit paid the Partnerships, for which Unit or a subsidiary
is the general partner, $3,000, $1,000 and $2,000 during the years ended
December 31, 2001, 2002 and 2003, respectively, for purchases of natural gas
production.
Unit owns a 40% equity interest in Superior Pipeline Company LLC, an
Oklahoma Limited Liability Company. Superior is a natural gas gathering and
processing company. The investment, including Unit's share of the equity in the
earnings of this company, totaled $3.0 million at December 31, 2003 and is
reported in other assets in Unit's consolidated balance sheet. During 2003,
Superior Pipeline Company LLC purchased $3.3 million of our natural gas
production and paid $64,000 for our natural gas liquids. We paid this company
$39,000 for gathering and compression services.
Unit also owns a 16.7% limited partnership interest in Eagle Energy
Partnership I, L.P. ("Eagle"), carried at cost, for $2.5 million. Eagle is
engaged in the purchase and sale of natural gas, electricity (or similar
electricity based products), future commodities, and the performance of
scheduling and nomination services for both energy related commodities and
similar energy management functions. Total purchases by Eagle Energy Partnership
I, L.P., which are competitively marketed, accounted for 6% of Unit's oil and
natural gas revenues in 2003. Unit increased its sales to Eagle Energy Partners
I LP since it first starting selling natural gas to them in August, 2003. For
the period August through December 2003 Eagle has purchased 16% of Unit's oil
and natural gas revenues.
83
NOTE 8 - SHAREHOLDER RIGHTS PLAN
--------------------------------
Unit maintains a Shareholder Rights Plan (the "Plan") designed to deter
coercive or unfair takeover tactics, to prevent a person or group from gaining
control of Unit without offering fair value to all shareholders and to deter
other abusive takeover tactics, which are not in the best interest of
shareholders.
Under the terms of the Plan, each share of common stock is accompanied by
one right, which given certain acquisition and business combination criteria,
entitles the shareholder to purchase from Unit one one-hundredth of a newly
issued share of Series A Participating Cumulative Preferred Stock at a price
subject to adjustment by Unit or to purchase from an acquiring company certain
shares of its common stock or the surviving company's common stock at 50% of its
value.
The rights become exercisable 10 days after Unit learns that an acquiring
person (as defined in the Plan) has acquired 15% or more of the outstanding
common stock of Unit or 10 business days after the commencement of a tender
offer, which would result in a person owning 15% or more of such shares. Unit
can redeem the rights for $0.01 per right at any date prior to the earlier of
(i) the close of business on the 10th day following the time Unit learns that a
person has become an acquiring person or (ii) May 19, 2005 (the "Expiration
Date"). The rights will expire on the Expiration Date, unless redeemed earlier
by Unit.
NOTE 9 - COMMITMENTS AND CONTINGENCIES
--------------------------------------
Unit leases office space in Tulsa and Woodward Oklahoma and Houston Texas
under the terms of operating leases expiring through January 31, 2010. Future
minimum rental payments under the terms of the leases are approximately
$719,000, $710,000, $714,000, $531,000 and $423,000 in 2004, 2005, 2006, 2007
and 2008, respectively. Total rent expense incurred by the Company was $582,000,
$678,000 and $752,000 in 2001, 2002 and 2003, respectively.
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 Unit
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% of
the units outstanding. Unit made repurchases of $1,000 and $106,000 in 2002 and
2003, respectively, for such limited partners' interests. No repurchases were
made in 2001. In 2001, Unit paid $15,000 for interests in two of the Questa
limited partnerships and subsequently dissolved one of the Questa partnerships.
Unit manages its exposure to environmental liabilities on properties to be
acquired by identifying existing problems and assessing the potential liability.
The Company also conducts periodic reviews, on a company-wide basis, to identify
changes in its environmental risk profile. These reviews
84
evaluate whether there is a probable liability, its amount, and the
likelihood that the liability will be incurred. The amount of any potential
liability is determined by considering, among other matters, incremental direct
costs of any likely remediation and the proportionate cost of employees who are
expected to devote a significant amount of time directly to any possible
remediation effort. As it relates to evaluations of purchased properties,
depending on the extent of an identified environmental problem, the Company may
exclude a property from the acquisition, require the seller to remediate the
property to Unit's satisfaction, or agree to assume liability for the
remediation of the property.
We have not historically experienced any environmental liability while
being a contract driller since the greatest portion of risk is borne by the
operator. Any liabilities we have incurred have been small and have been
resolved while the rig is on the location and the cost has been included in the
direct cost of drilling the well.
Unit is a party to various legal proceedings arising in the ordinary course
of its business none of which, in management's opinion, will result in judgments
which would have a material adverse effect on Unit's financial position,
operating results or cash flows.
85
NOTE 10 - INDUSTRY SEGMENT INFORMATION
--------------------------------------
Unit has two business segments: Contract Drilling and Oil and Natural Gas,
representing its two main business units offering different products and
services. The Contract Drilling segment provides land contract drilling of oil
and natural gas wells and the Oil and Natural Gas segment is engaged in the
development, acquisition and production of oil and natural gas properties.
The accounting policies of the segments are the same as those described in
the Summary of Significant Accounting Policies (Note 1). Management evaluates
the performance of Unit's operating segments based on operating income, which is
defined as operating revenues less operating expenses and depreciation,
depletion and amortization. Unit has natural gas production in Canada, which is
not significant.
86
2001 2002 2003
---------- ---------- ----------
(In thousands)
Revenues:
Contract drilling $ 169,301 $ 119,014 $ 188,832
Elimination of intersegment
revenue 2,259 841 5,686
---------- ---------- ----------
Contract drilling net of
intersegment revenue 167,042 118,173 183,146
Oil and natural gas 90,237 67,959 116,609
Other 1,900 1,504 2,829
---------- ---------- ----------
Total revenues $ 259,179 $ 187,636 $ 302,584
========== ========== ==========
Operating Income (1):
Contract drilling $ 62,148 $ 12,151 $ 20,740
Oil and natural gas 45,925 23,826 64,097
---------- ---------- ----------
Total operating income 108,073 35,977 84,837
General and administrative
expense (8,476) (8,712) (9,222)
Interest expense (2,818) (973) (693)
Other income (expense)- net 1,900 1,504 2,829
---------- ---------- ----------
Income before income taxes $ 98,679 $ 27,796 $ 77,751
========== ========== ==========
Identifiable Assets (2):
Contract drilling $ 183,471 $ 299,655 $ 364,855
Oil and natural gas 220,476 261,440 327,172
---------- ---------- ----------
Total identifiable assets 403,947 561,095 692,027
Corporate assets 13,306 17,068 20,898
---------- ---------- ----------
Total assets $ 417,253 $ 578,163 $ 712,925
========== ========== ==========
87
2001 2002 2003
---------- ---------- ----------
(In thousands)
Capital Expenditures:
Contract drilling $ 51,280 $ 139,298 (3) $ 71,899 (4)
Oil and natural gas 56,933 58,778 80,883 (5)
Other 539 516 3,940
---------- ---------- ----------
Total capital
expenditures $ 108,752 $ 198,592 $ 156,722
========== ========== ==========
Depreciation, Depletion,
Amortization and
Impairment:
Contract drilling $ 13,888 $ 14,684 $ 23,644
Oil and natural gas 22,116 23,338 27,343
Other 638 635 796
---------- ---------- ----------
Total depreciation,
depletion,
amortization
and impairment $ 36,642 $ 38,657 $ 51,783
========== ========== ==========
----------------------
(1) Operating income is total operating revenues less operating expenses,
depreciation, depletion, amortization and impairment and does not include
non-operating revenues, general corporate expenses, interest expense or
income taxes.
(2) Identifiable assets are those used in Unit's operations in each industry
segment. Corporate assets are principally cash and cash equivalents,
short-term investments, corporate leasehold improvements, furniture and
equipment.
(3) Includes $7.7 million for goodwill and $2.2 million for deferred tax
assets.
(4) Includes $10.9 million for goodwill.
(5) Includes $7.6 million for capitalized cost relating to plugging liability
recorded in 2003.
88
NOTE 11 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
--------------------------------------------------------------
Summarized quarterly financial information for 2002 and 2003 is as follows:
Three Months Ended
---------------------------------------------------
March 31 June 30 September 30 December 31
----------- ----------- ------------ -----------
(In thousands except per share amounts)
Year Ended
December 31, 2002:
Revenues $ 38,730 $ 44,753 $ 48,272 $ 55,881
=========== =========== ============ ===========
Gross profit(1) $ 6,515 $ 10,295 $ 8,107 $ 11,060
=========== =========== ============ ===========
Income before
income taxes $ 4,254 $ 8,297 $ 6,022 $ 9,223
=========== =========== ============ ===========
Net income(2) $ 2,642 $ 5,108 $ 3,708 $ 6,786
=========== =========== ============ ===========
Earnings per
common share:
Basic (3) $ 0.07 $ 0.14 $ 0.09 $ 0.16
=========== =========== ============ ===========
Diluted (4) $ 0.07 $ 0.14 $ 0.09 $ 0.16
=========== =========== ============ ===========
Year Ended
December 31, 2003:
Revenues $ 68,446 $ 72,980 $ 78,201 $ 82,957
=========== =========== ============ ===========
Gross profit(1) $ 22,447 $ 20,214 $ 22,251 $ 19,925
=========== =========== ============ ===========
Income before
income taxes
and change in
accounting
principle $ 20,418 $ 18,857 $ 20,598 $ 17,878
=========== =========== ============ ===========
Income before
change in
accounting
principle $ 12,659 $ 11,691 $ 12,763 $ 11,751
=========== =========== ============ ===========
Net Income(2) $ 13,984 $ 11,691 $ 12,763 $ 11,751
=========== =========== ============ ===========
89
Three Months Ended
---------------------------------------------------
March 31 June 30 September 30 December 31
----------- ----------- ------------ -----------
(In thousands except per share amounts)
Earnings Before
Change in
Accounting
Principle per
Common Share:
Basic $ 0.29 $ 0.27 $ 0.29 $ 0.27
=========== =========== ============ ===========
Diluted $ 0.29 $ 0.27 $ 0.29 $ 0.27
=========== =========== ============ ===========
Net Income per
Common Share:
Basic $ 0.32 $ 0.27 $ 0.29 $ 0.27
=========== =========== ============ ===========
Diluted $ 0.32 $ 0.27 $ 0.29 $ 0.27
=========== =========== ============ ===========
------------------
(1) Gross profit excludes other revenues, general and administrative expense
and interest expense.
(2) The net income for the three months ended December 31, 2002 and 2003
includes a tax benefit of $1.1 million and $0.8 million, respectively,
relating primarily to an increase in the estimated amount of statutory
depletion carryforward.
(3) Due to the effect of rounding basic earnings per share for the year's four
quarters does not equal the annual earnings per share.
(4) Due to the effect of price changes of Unit's stock, diluted earnings per
share for the year's four quarters, which includes the effect of potential
dilutive common shares calculated during each quarter, does not equal the
annual diluted earnings per share, which includes the effect of such
potential dilutive common shares calculated for the entire year.
90
NOTE 12 - SUBSEQUENT EVENT
--------------------------
On January 30, 2004 Unit acquired the outstanding common stock of PetroCorp
Incorporated for $182.1 million in cash. PetroCorp Incorporated explored and
developed oil and natural gas properties primarily in Texas and Oklahoma.
Approximately 84% of the oil and natural gas properties acquired in the
acquisition are located in the Mid-Continent and Permian basins, while 6% are
located in the Rocky Mountains and 10% are located in the Gulf Coast basin. The
acquired properties increased Unit's reserve base by approximately 56.7 billion
equivalent cubic feet of natural gas and provide additional locations for
development drilling in the future. With the acquisition of PetroCorp
Incorporated, Unit also entered into a new $150 million credit facility to
replace its existing loan agreement as more fully discussed in Note 4.
The preliminary allocation of the total consideration paid for the
acquisition is as follows (in thousands):
Working Capital $ 93,668
Undeveloped Oil and Natural Gas Properties 6,557
Proved Oil and Natural Gas Properties 114,518
Property and Equipment - Other 401
Other Assets 1,499
Other Long-Term Liabilities (5,557)
Deferred Income Taxes (net) (28,966)
----------
Total consideration $ 182,120
==========
Unaudited summary pro forma results of operations for Unit, reflecting the
above described acquisition as if it had occurred at the beginning of the year
ended December 31, 2002 and December 31, 2003, are as follows, respectively;
revenues, $217.0 million and $339.6 million; income from continuing operations
of $19.5 million and $55.2 million; net income of $19.5 million and $53.5
million; income from continuing operations per common share (diluted) of $0.50
and $1.26 and net income per common shares (diluted) of $0.50 and $1.22. 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 period nor of the results which may occur in the
future.
91
NOTE 13 - OIL AND NATURAL GAS INFORMATION
-----------------------------------------
The capitalized costs at year end and costs incurred during the year were
as follows:
USA Canada Total
----------- --------- -----------
(In thousands)
2001:
Capitalized costs:
Proved properties $ 391,216 $ 888 $ 392,104
Unproved properties 14,207 180 14,387
----------- --------- -----------
405,423 1,068 406,491
Accumulated depreciation,
depletion, amortization
and impairment (196,270) (475) (196,745)
----------- --------- -----------
Net capitalized costs $ 209,153 $ 593 $ 209,746
=========== ========= ===========
Cost incurred:
Unproved properties acquired $ 7,503 $ 21 $ 7,524
Proved properties acquired 1,419 -- 1,419
Exploration 9,336 -- 9,336
Development 38,359 295 38,654
----------- --------- -----------
Total costs incurred $ 56,617 $ 316 $ 56,933
=========== ========= ===========
2002:
Capitalized costs:
Proved properties $ 448,331 $ 895 $ 449,226
Unproved properties 15,692 332 16,024
----------- --------- -----------
464,023 1,227 465,250
Accumulated depreciation,
depletion, amortization
and impairment (218,956) (520) (219,476)
----------- --------- -----------
Net capitalized costs $ 245,067 $ 707 $ 245,774
=========== ========= ===========
Cost incurred:
Unproved properties acquired $ 5,330 $ 152 $ 5,482
Proved properties acquired 13,379 -- 13,379
Exploration 6,591 -- 6,591
Development 33,319 7 33,326
----------- --------- -----------
Total costs incurred $ 58,619 $ 159 $ 58,778
=========== ========= ===========
92
USA Canada Total
----------- --------- -----------
(In thousands)
2003:
Capitalized costs:
Proved properties $ 527,196 $ 914 $ 528,110
Unproved properties 17,149 337 17,486
----------- --------- -----------
544,345 1,251 545,596
Accumulated depreciation,
depletion, amortization
and impairment (240,047) (540) (240,587)
----------- --------- -----------
Net capitalized costs $ 304,298 $ 711 $ 305,009
=========== ========= ===========
Cost incurred:
Unproved properties acquired $ 8,611 $ 19 $ 8,630
Proved properties acquired 2,557 -- 2,557
Exploration 7,071 -- 7,071
Development(1) 62,620 5 62,625
----------- --------- -----------
Total costs incurred $ 80,859 $ 24 $ 80,883
=========== ========= ===========
----------------
(1) Includes $7.0 million of capitalized cost for plugging liability recorded
in the first quarter of 2003 for wells drilled in prior years.
The following table shows a summary of the oil and natural gas property
costs not being amortized at December 31, 2003, by the year in which such costs
were incurred.
2000
and
Prior 2001 2002 2003 Total
--------- --------- --------- --------- ---------
(In thousands)
Undeveloped
Leasehold
Acquired $ 3,341 $ 3,272 $ 3,187 $ 7,686 $ 17,486
========= ========= ========= ========= =========
93
The results of operations for producing activities are provided below.
USA Canada Total
----------- --------- -----------
(In thousands)
2001:
Revenues $ 86,810 $ 190 $ 87,000
Production costs (18,636) (23) (18,659)
Depreciation, depletion
and amortization (19,756) (40) (19,796)
----------- --------- -----------
48,418 127 48,545
Income tax expense (17,621) (40) (17,661)
----------- --------- -----------
Results of operations for
producing activities
(excluding corporate
overhead and financing costs) $ 30,797 $ 87 $ 30,884
=========== ========= ===========
2002:
Revenues $ 64,534 $ 87 $ 64,621
Production costs (17,300) (25) (17,325)
Depreciation, depletion
and amortization (22,685) (45) (22,730)
----------- --------- -----------
24,549 17 24,566
Income tax expense (8,436) (5) (8,441)
----------- --------- -----------
Results of operations for
producing activities
(excluding corporate
overhead and financing costs) $ 16,113 $ 12 $ 16,125
=========== ========= ===========
2003:
Revenues $ 114,398 $ 171 $ 114,569
Production costs (21,366) (21) (21,387)
Depreciation, depletion
and amortization (27,059) (20) (27,079)
----------- --------- -----------
65,973 130 66,103
Income tax expense (24,508) (41) (24,549)
----------- --------- -----------
Results of operations for
producing activities
(excluding corporate
overhead and financing costs) $ 41,465 $ 89 $ 41,554
=========== ========= ===========
94
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 (unaudited):
USA Canada Total
---------------- ---------------- ----------------
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
Bbls Mcf Bbls Mcf Bbls Mcf
------- -------- ------- -------- ------- --------
(In thousands)
2001:
Proved developed and
undeveloped reserves:
Beginning of year 4,183 215,196 -- 441 4,183 215,637
Revision of previous
estimates (214) (24,253) -- (7) (214) (24,260)
Extensions, discoveries
and other additions 861 54,521 -- -- 861 54,521
Purchases of minerals
in place 8 1,246 -- -- 8 1,246
Sales of minerals in
place (3) (26) -- -- (3) (26)
Production (492) (18,819) -- (45) (492) (18,864)
------- -------- ------- -------- ------- --------
End of Year 4,343 227,865 -- 389 4,343 228,254
======= ======== ======= ======== ======= ========
Proved developed reserves:
Beginning of year 3,222 162,718 -- 389 3,222 163,107
End of year 2,753 150,419 -- 338 2,753 150,757
2002:
Proved developed and
undeveloped reserves:
Beginning of year 4,343 227,865 -- 389 4,343 228,254
Revision of previous
estimates (166) (10,543) -- (31) (166) (10,574)
Extensions, discoveries
and other additions 230 29,541 -- -- 230 29,541
Purchases of minerals
in place 192 16,558 -- -- 192 16,558
Sales of minerals in
place (30) -- -- -- (30) --
Production (473) (18,927) -- (41) (473) (18,968)
------- -------- ------- -------- ------- --------
End of Year 4,096 244,494 -- 317 4,096 244,811
======= ======== ======= ======== ======= ========
Proved developed reserves:
Beginning of year 2,753 150,419 -- 338 2,753 150,757
End of year 2,951 168,049 -- 317 2,951 168,366
95
USA Canada Total
---------------- ---------------- ----------------
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
Bbls(1) Mcf Bbls Mcf Bbls Mcf
------- -------- ------- -------- ------- --------
(In thousands)
2003:
Proved developed and
undeveloped reserves:
Beginning of year 4,096 244,494 -- 317 4,096 244,811
Revision of previous
estimates 629 (10,510) -- 371 629 (10,139)
Extensions, discoveries
and other additions 1,000 39,762 -- -- 1,000 39,762
Purchases of minerals
in place 8 437 -- -- 8 437
Sales of minerals
in place (76) (31) -- -- (76) (31)
Production (516) (20,610) -- (38) (516) (20,648)
------- -------- ------- -------- ------- --------
End of Year 5,141 253,542 -- 650 5,141 254,192
======= ======== ======= ======== ======= ========
Proved developed reserves:
Beginning of year 2,951 168,049 -- 317 2,951 168,366
End of year 3,984 182,203 -- 650 3,984 182,853
----------------------
(1) Oil includes natural gas liquids in barrels.
96
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. Unit utilizes Ryder Scott Company, independent petroleum
consultants, to review its reserves as prepared by its reservoir engineers.
Proved oil and gas reserves, as defined in SEC Rule 4-10(a), 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
operating conditions, i.e., prices and costs as of the date the estimate is
made. Prices include consideration of changes in existing prices provided only
by contractual arrangements, but not on escalations based upon future
conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes:
. that portion delineated by drilling and defined by gas-oil and/or
oil-water contacts, if any; and
. the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons
controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following:
. oil that may become available from known reservoirs but is classified
separately as "indicated additional reserves";
. crude oil, natural gas, and natural gas liquids, the recovery of which
is subject to reasonable doubt because of uncertainty as to geology,
reservoir characteristics, or economic factors;
. crude oil, natural gas, and natural gas liquids, that may occur in
undrilled prospects; and
. crude oil, natural gas, and natural gas liquids, that may be recovered
from oil shales, coal, gilsonite and other such sources.
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Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
Proved undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
Estimates of oil and natural gas reserves require extensive judgments of
reservoir engineering data as previously explained. 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 escalations or de-escalations have been considered,
the results are not necessarily indicative of the estimated fair market value of
estimated proved reserves nor of estimated future cash flows.
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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 (unaudited):
USA Canada Total
----------- --------- -----------
(In thousands)
2001:
Future cash flows $ 676,051 $ 975 $ 677,026
Future production costs (220,590) (311) (220,901)
Future development costs (58,909) (30) (58,939)
Future income tax expenses (94,037) (134) (94,171)
----------- --------- -----------
Future net cash flows 302,515 500 303,015
10% annual discount for
estimated timing of cash flows (125,238) (194) (125,432)
----------- --------- -----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 177,277 $ 306 $ 177,583
=========== ========= ===========
2002:
Future cash flows $1,256,434 $ 1,400 $1,257,834
Future production costs (320,940) (309) (321,249)
Future development costs (65,266) -- (65,266)
Future income tax expenses (250,413) (233) (250,646)
----------- --------- -----------
Future net cash flows 619,815 858 620,673
10% annual discount for
estimated timing of cash flows (275,015) (344) (275,359)
----------- --------- -----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 344,800 $ 514 $ 345,314
=========== ========= ===========
2003:
Future cash flows $1,548,785 $ 3,500 $1,552,285
Future production costs (418,007) (581) (418,588)
Future development costs (72,891) -- (72,891)
Future income tax expenses (313,827) (805) (314,632)
----------- --------- -----------
Future net cash flows 744,060 2,114 746,174
10% annual discount for
estimated timing of cash flows (325,182) (738) (325,920)
----------- --------- -----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 418,878 $ 1,376 $ 420,254
=========== ========= ===========
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The principal sources of changes in the standardized measure of discounted
future net cash flows were as follows (unaudited):
USA Canada Total
----------- --------- -----------
(In thousands)
2001:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (68,174) $ (167) $ (68,341)
Net changes in prices and
production costs (768,295) (1,600) (769,895)
Revisions in quantity
estimates and changes in
production timing (32,705) 13 (32,692)
Extensions, discoveries and
improved recovery, less
related costs 54,127 -- 54,127
Changes in estimated future
development cost 2,673 -- 2,673
Previously estimated cost
incurred during the period 7,361 -- 7,361
Purchases of minerals in place 1,217 -- 1,217
Sales of minerals in place (220) -- (220)
Accretion of discount 99,953 205 100,158
Net change in income taxes 271,421 524 271,945
Other - net (64,668) (108) (64,776)
----------- --------- -----------
Net change (497,310) (1,133) (498,443)
Beginning of year 674,587 1,439 676,026
----------- --------- -----------
End of year $ 177,277 $ 306 $ 177,583
=========== ========= ===========
2002:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (47,230) $ (62) $ (47,292)
Net changes in prices and
production costs 230,934 363 231,297
Revisions in quantity
estimates and changes in
production timing (49,000) (110) (49,110)
Extensions, discoveries and
improved recovery, less
related costs 60,957 -- 60,957
Changes in estimated future
development cost 1,743 -- 1,743
Previously estimated cost
incurred during the period 9,911 30 9,941
Purchases of minerals in place 23,334 -- 23,334
Sales of minerals in place (150) -- (150)
Accretion of discount 23,080 39 23,119
Net change in income taxes (84,843) (59) (84,902)
Other - net (1,213) 7 (1,206)
----------- --------- -----------
Net change 167,523 208 167,731
Beginning of year 177,277 306 177,583
----------- --------- -----------
End of year $ 344,800 $ 514 $ 345,314
=========== ========= ===========
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USA Canada Total
----------- --------- -----------
(In thousands)
2003:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (93,948) $ (150) $ (94,098)
Net changes in prices and
production costs 65,611 195 65,806
Revisions in quantity
estimates and changes in
production timing (14,637) 1,007 (13,630)
Extensions, discoveries and
improved recovery, less
related costs 113,421 -- 113,421
Changes in estimated future
development cost (5,356) -- (5,356)
Previously estimated cost
incurred during the period 15,664 -- 15,664
Purchases of minerals in place 881 -- 881
Sales of minerals in place (837) -- (837)
Accretion of discount 48,317 66 48,383
Net change in income taxes (38,950) (386) (39,336)
Other - net (16,088) 130 (15,958)
----------- --------- -----------
Net change 74,078 862 74,940
Beginning of year 344,800 514 345,314
----------- --------- -----------
End of year $ 418,878 $ 1,376 $ 420,254
=========== ========= ===========
Unit's SMOG and changes therein were determined in accordance with
Statement of Financial Accounting Standards No. 69. Certain information
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 difficulty 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 spot prices of oil
$32.52 and natural gas $5.67 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.
101
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.
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 Unit's properties. The
future income tax expenses also give effect to permanent differences and tax
credits and allowances relating to Unit'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.
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REPORT OF INDEPENDENT AUDITORS
The Shareholders and Board of Directors
Unit Corporation
In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of income, changes in shareholders' equity and
cash flows present fairly in all material respects, the financial position of
Unit Corporation and its subsidiaries at December 31, 2002 and 2003, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2003, in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
the financial statement schedule listed in the index appearing under item
15(a)(2), presents fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial
statements. 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 of these financial statements in accordance
with auditing standards generally accepted in the United States of America which
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, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, effective
January 1, 2003, the Company adopted the requirements of Statement of Financial
Accounting Standards No. 143, "Accounting for Asset Retirement Obligations."
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 18, 2004
103