Back to GetFilings.com
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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 or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1000 Kensington Tower I,
7130 South Lewis,
Tulsa, Oklahoma 74136
--------------- -----
(Address of principal executive offices) (Zip Code)
(918) 493-7700
--------------
(Registrant's telephone number, including area code)
None
----
(Former name, former address and former fiscal year,
if changed since last report)
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 the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
Common Stock, $.20 par value 43,528,910
---------------------------- ----------
Class Outstanding at August 8, 2003
FORM 10-Q
UNIT CORPORATION
TABLE OF CONTENTS
Page
Number
PART I. Financial Information
Item 1. Financial Statements (Unaudited)
Consolidated Condensed Balance Sheets
December 31, 2002 and June 30, 2003. . . . . . . . . . 2
Consolidated Condensed Statements of Operations
Three and Six Months Ended June 30, 2002 and 2003. . . 4
Consolidated Condensed Statements of Cash Flows
Six Months Ended June 30, 2002 and 2003. . . . . . . . 6
Consolidated Condensed Statements of Comprehensive
Income Three and Six Months Ended
June 30, 2002 and 2003. . . . . . . . . . . . . . . . . 7
Notes to Consolidated Condensed Financial Statements. . 8
Report of Independent Accountants . . . . . . . . . . . 22
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . 23
Item 3. Quantitative and Qualitative Disclosure about
Market Risk . . . . . . . . . . . . . . . . . . . . . . 40
Item 4. Controls and Procedures . . . . . . . . . . . . . . . . 40
PART II. Other Information
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . 41
Item 2. Changes in Securities and Use of Proceeds . . . . . . . 41
Item 3. Defaults Upon Senior Securities. . . . . . . . . . . . 41
Item 4. Submission of Matters to a Vote of Security Holders . . 41
Item 5. Other Information . . . . . . . . . . . . . . . . . . . 42
Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . 42
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
1
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
- -----------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS (UNAUDITED)
December 31, June 30,
2002 2003
----------- -----------
(In thousands)
ASSETS
------
Current Assets:
Cash and cash equivalents $ 497 $ 1,326
Accounts receivable 33,912 47,453
Materials and supplies 8,794 7,183
Income tax receivable 3,602 705
Other 4,594 3,834
----------- -----------
Total current assets 51,399 60,501
----------- -----------
Property and Equipment:
Drilling equipment 369,777 376,662
Oil and natural gas properties, on the
full cost method
Proved properties 449,226 482,617
Undeveloped leasehold not being
amortized 16,024 19,008
Transportation equipment 6,856 7,403
Other 9,906 12,044
----------- -----------
851,789 897,734
Less accumulated depreciation, depletion
amortization and impairment 341,031 357,222
----------- -----------
Net property and equipment 510,758 540,512
----------- -----------
Goodwill 12,794 12,794
Other Assets 3,212 6,442
----------- -----------
Total Assets $ 578,163 $ 620,249
=========== ===========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
2
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS - CONTINUED (UNAUDITED)
December 31, June 30,
2002 2003
----------- -----------
(In thousands)
LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------
Current Liabilities:
Current portion of long-term
liabilities and debt $ 1,465 $ 736
Accounts payable 21,119 19,545
Accrued liabilities 11,948 13,381
----------- -----------
Total current liabilities 34,532 33,662
----------- -----------
Long-Term Debt 30,500 19,000
----------- -----------
Other Long-Term Liabilities 5,439 17,399
----------- -----------
Deferred Income Taxes 86,320 101,713
----------- -----------
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
43,525,310 shares issued, respectively 8,668 8,705
Capital in excess of par value 264,180 265,645
Accumulated other comprehensive income - (74)
Retained earnings 148,524 174,199
----------- -----------
Total shareholders' equity 421,372 448,475
----------- -----------
Total Liabilities and Shareholders' Equity $ 578,163 $ 620,249
=========== ===========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
3
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2002 2003 2002 2003
---------- ---------- ---------- ----------
(In thousands except per share amounts)
Revenues:
Contract drilling $ 25,841 $ 45,221 $ 52,555 $ 79,787
Oil and natural gas 18,668 26,871 30,629 60,119
Other 244 888 299 1,520
---------- ---------- ---------- ----------
Total revenues 44,753 72,980 83,483 141,426
---------- ---------- ---------- ----------
Expenses:
Contract drilling:
Operating costs 20,137 33,641 39,269 61,452
Depreciation
and amortization 2,928 5,899 5,739 10,793
Oil and natural gas:
Operating costs 5,161 5,893 10,109 12,508
Depreciation,
depletion and
amortization 5,988 6,445 11,257 12,492
General and
administrative 2,013 2,070 4,042 4,520
Interest 229 175 516 386
---------- ---------- ---------- ----------
Total expenses 36,456 54,123 70,932 102,151
---------- ---------- ---------- ----------
Income Before Income
Taxes and Change in
Accounting Principle 8,297 18,857 12,551 39,275
---------- ---------- ---------- ----------
Income Tax Expense:
Current 238 144 360 299
Deferred 2,951 7,022 4,441 14,626
---------- ---------- ---------- ----------
Total income
taxes 3,189 7,166 4,801 14,925
---------- ---------- ---------- ----------
Income Before Change in
Accounting Principle 5,108 11,691 7,750 24,350
Cumulative Effect of
Change in Accounting
Principle (Net of Income
Tax of $811,000) - - - 1,325
---------- ---------- ---------- ----------
Net Income $ 5,108 $ 11,691 $ 7,750 $ 25,675
========== ========== ========== ==========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
4
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS - CONTINUED
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2002 2003 2002 2003
---------- ---------- ---------- ----------
(In thousands except per share amounts)
Basic Earnings Per Common
Share:
Income before change
in accounting
principle $ 0.14 $ 0.27 $ 0.21 $ 0.56
Cumulative effect of
change in accounting
principle net of
income tax - - - 0.03
---------- ---------- ---------- ----------
Net Income $ 0.14 $ 0.27 $ 0.21 $ 0.59
========== ========== ========== ==========
Diluted Earnings Per
Common Share:
Income before change
in accounting
principle $ 0.14 $ 0.27 $ 0.21 $ 0.56
Cumulative effect of
change in accounting
principle net of
income tax - - - 0.03
---------- ---------- ---------- ----------
Net Income $ 0.14 $ 0.27 $ 0.21 $ 0.59
========== ========== ========== ==========
Pro Forma Amounts Assuming
Retroactive Application
of Change in Accounting
Principle:
Net income $ 5,081 $ 7,693
========== ==========
Basic earnings per
share $ 0.14 $ 0.21
========== ==========
Diluted earnings per
share $ 0.14 $ 0.21
========== ==========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
5
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended
June 30,
-------------------------
2002 2003
---------- ----------
(In thousands)
Cash Flows From Operating Activities:
Net income $ 7,750 $ 25,675
Adjustments to reconcile net income
to net cash provided (used) by
operating activities:
Depreciation, depletion,
and amortization 17,313 23,621
Deferred tax expense 4,441 14,626
Other 198 (372)
Changes in operating assets and
liabilities increasing (decreasing)
cash:
Accounts receivable 6,069 (13,788)
Accounts payable 4,050 3,417
Material and supplies inventory (1,550) 1,611
Prepaid expenses 3,059 3,748
Contract advances (91) 2,271
Other - net (428) (154)
---------- ----------
Net cash provided by
operating activities 40,811 60,655
---------- ----------
Cash Flows From (Used In) Investing
Activities:
Capital expenditures (29,188) (42,104)
Proceeds from disposition of assets 907 520
Other-net 459 (2,498)
---------- ----------
Net cash used in
investing activities (27,822) (44,082)
---------- ----------
Cash Flows From (Used In) Financing
Activities:
Net borrowings (payments) under
line of credit (11,000) (11,500)
Net payments of notes payable
and other long-term debt (22) (1,020)
Proceeds from exercise of stock options 204 423
Book overdrafts (1,104) (3,647)
---------- ----------
Net cash used in financing
activities (11,922) (15,744)
---------- ----------
Net Increase in Cash and
Cash Equivalents 1,067 829
Cash and Cash Equivalents, Beginning
of Year 391 497
---------- ----------
Cash and Cash Equivalents, End of Period $ 1,458 $ 1,326
========== ==========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
6
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2002 2003 2002 2003
---------- ---------- ---------- ----------
(In thousands)
Net Income $ 5,108 $ 11,691 $ 7,750 $ 25,675
Other Comprehensive Income,
Net of Taxes:
Change in value of cash
flow derivative
instruments used as
cash flow hedges - (233) - (78)
Reclassification
of derivative
settlements - 4 - 4
---------- ---------- ---------- ----------
Comprehensive Income $ 5,108 $ 11,462 $ 7,750 $ 25,601
========== ========== ========== ==========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
7
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 1 - BASIS OF PREPARATION AND PRESENTATION
- ----------------------------------------------
The accompanying unaudited consolidated condensed financial statements
include the accounts of Unit Corporation and its wholly owned subsidiaries (the
"Company") and have been prepared pursuant to the rules and regulations of the
Securities and Exchange Commission. As applicable under these regulations,
certain information and footnote disclosures have been condensed or omitted and
the consolidated condensed financial statements do not include all disclosures
required by generally accepted accounting principles. In the opinion of the
Company, the unaudited consolidated condensed financial statements contain all
adjustments necessary (all adjustments are of a normal recurring nature) to
present fairly the interim financial information.
Results for the three and six months ended June 30, 2003 are not
necessarily indicative of the results to be realized during the full year. The
condensed financial statements should be read in conjunction with the Company's
Annual Report on Form 10-K for the year ended December 31, 2002. Our independent
accountants have performed a review of these interim financial statements in
accordance with standards established by the American Institute of Certified
Public Accountants. Pursuant to Rule 436(c) under the Securities Act of 1933,
their report of that review should not be considered as part of any registration
statements prepared or certified by them within the meaning of Section 7 and 11
of that Act and the independent accountants' liability under Section 11 does not
extend to it.
Because the Company does not bear the risk of completion of wells drilled
under daywork drilling contracts, it recognizes revenues and expenses generated
from those contracts as the services are performed (i.e. daily). Under "footage"
and "turnkey" contracts, revenues and expenses are recognized when the company
has satisfied certain requirements as detailed in the applicable contracts. If
it has been determined that a well is going to incur a loss, the entire amount
of the estimated loss is recorded when the loss can be reasonably determined,
however, any profit is recorded only at the time the terms of the contract are
completed. 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.
Unit's stock based compensation plans are accounted for under the
recognition and measurement principles of APB 25, "Accounting for Stock Issued
to Employees," and related Interpretations. No stock-based employee compensation
cost related to stock options is reflected in net income, as all options granted
under the plan had an exercise price equal to the market value of the underlying
common stock on the date of grant. Compensation expense included in reported net
income is Unit's matching 401(k) contribution. The following table illustrates
8
the effect on net income and earnings per share if the company had applied the
fair value recognition provisions of Financial Accounting Standards Board
Statement No. 123, "Accounting for Stock Based Compensation," to stock-based
employee compensation.
Three Months Ended Six Months Ended
-------------------- --------------------
2002 2003 2002 2003
--------- --------- --------- ---------
(In thousands except per share amounts)
Net Income, as Reported $ 5,108 $ 11,691 $ 7,750 $ 25,675
Add Stock Based Employee
Compensation Expense
Included in Reported
Net Income - Net of Tax 160 168 320 335
Less Total Stock Based
Employee Compensation
Expense Determined Under
Fair Value Based Method
For All Awards (333) (471) (599) (875)
--------- --------- --------- ---------
Pro Forma Net Income $ 4,935 $ 11,388 $ 7,471 $ 25,135
========= ========= ========= =========
Basic Earnings per Share:
As reported $ 0.14 $ 0.27 $ 0.21 $ 0.59
========= ========= ========= =========
Pro forma $ 0.14 $ 0.26 $ 0.21 $ 0.58
========= ========= ========= =========
Diluted Earnings per Share:
As reported $ 0.14 $ 0.27 $ 0.21 $ 0.59
========= ========= ========= =========
Pro forma $ 0.14 $ 0.26 $ 0.21 $ 0.58
========= ========= ========= =========
The fair value of each option granted is estimated using the Black-Scholes
model. In the second quarter of 2002 and 2003 options were granted for 26,000
and 21,000 shares, respectively with an estimated fair value of approximately
$320,000 and $262,000, respectively. For options granted in fiscal 2002 and in
the second quarter of 2003, Unit's estimate of stock volatility was 0.53, based
on previous stock performance. Dividend yield was estimated to remain at zero
with a risk free interest rate of 4.24 and 3.6 percent in 2002 and the second
quarter of 2003, respectively.
9
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.
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 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.
To date, Unit has not experienced any substantial environmental liability.
Any liabilities Unit has incurred have been small and have been timely resolved.
On August 15, 2002, Unit completed the acquisition of CREC Rig Equipment
Company and CDC Drilling Company. 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 twenty drilling
rigs, spare drilling equipment and vehicles. The purchase price for 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 Condensed Statement of Cash Flows.
The results of operations for the acquired entities are included in the
statement of operations for the periods beginning after August 15, 2002 and
continuing through June 30, 2003.
10
NOTE 2 - EARNINGS PER SHARE
- ---------------------------
The following data shows the amounts used in computing earnings per share
for the Company.
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------- ------------- ----------
For the Three Months Ended
June 30, 2002:
Basic earnings per common share $ 5,108,000 36,109,000 $ 0.14
==========
Effect of dilutive stock options - 296,000
------------- -------------
Diluted earnings per common share $ 5,108,000 36,405,000 $ 0.14
============= ============= ==========
For the Three Months Ended
June 30, 2003:
Basic earnings per common share $ 11,691,000 43,521,000 $ 0.27
==========
Effect of dilutive stock options - 228,000
------------- -------------
Diluted earnings per common share $ 11,691,000 43,749,000 $ 0.27
============= ============= ==========
All options and their average exercise prices for the three months ended
June 30, 2003 were included in the computation of diluted earnings per share.
The following options and their average exercise prices were not included in the
computation of diluted earnings per share for the three months ended June 30,
2002 because the option exercise prices were greater than the average market
price of common shares:
2002
----------
Options 21,000
==========
Average exercise price $ 20.10
==========
11
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------- ------------- ----------
For the Six Months Ended
June 30, 2002:
Basic earnings per common share $ 7,750,000 36,072,000 $ 0.21
==========
Effect of dilutive stock options - 264,000
------------- -------------
Diluted earnings per common share $ 7,750,000 36,336,000 $ 0.21
============= ============= ==========
For the Six Months Ended
June 30, 2003:
Basic earnings per common share:
Income before change in
accounting principle $ 24,350,000 43,477,000 $ 0.56
Cumulative effect of change
in accounting principle
net of income tax 1,325,000 43,477,000 0.03
------------- ----------
Net Income $ 25,675,000 43,477,000 $ 0.59
============= ==========
Diluted earnings per common share:
Weighted average number of
common shares used in basic
earnings per common share 43,477,000
Effect of dilutive stock
options 213,000
-------------
Weighted average number of
common shares and dilutive
potential common shares
used in diluted earnings
per share 43,690,000
=============
Income before change in
accounting principle $ 24,350,000 43,690,000 $ 0.56
Cumulative effect of change
in accounting principle
net of income tax 1,325,000 43,690,000 0.03
------------- ----------
Net Income $ 25,675,000 43,690,000 $ 0.59
============= ==========
12
The following options and their average exercise prices were not included
in the computation of diluted earnings per share for the six months ended June
30, 2002 and 2003 because the option exercise prices were greater than the
average market price of common shares:
2002 2003
---------- ----------
Options 174,000 21,000
========== ==========
Average exercise price $ 17.19 $ 20.10
========== ==========
NOTE 3 - NEW ACCOUNTING PRONOUNCEMENTS
- --------------------------------------
Goodwill represents the excess of the cost of the acquisition of Hickman
Drilling Company, CREC Rig Equipment Company and CDC Drilling Company 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 ended 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 changed. 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. In 2002 the carrying
amount of Goodwill increased by $7,706,000 from the goodwill acquired in the
acquisition of CREC Rig Equipment Company and CDC Drilling Company. Goodwill of
$7,009,000 is expected to be deductible for tax purposes.
13
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 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:
Goodwill amortized
- net of income tax 92 88 -
----------- ----------- -----------
Adjusted net income $ 34,436 $ 62,854 $ 18,244
=========== =========== ===========
Basic Earnings per Share:
Reported net income $ 0.96 $ 1.75 $ 0.47
Add back:
Goodwill amortized
- net of income tax - - -
----------- ----------- -----------
Adjusted basic earnings
per share $ 0.96 $ 1.75 $ 0.47
=========== =========== ===========
Diluted Earnings per Share:
Reported net income $ 0.95 $ 1.73 $ 0.47
Add back:
Goodwill amortized
- net of income tax - - -
----------- ----------- -----------
Adjusted diluted earnings
per share $ 0.95 $ 1.73 $ 0.47
=========== =========== ===========
On January 1, 2003 we 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. Unit 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 period in which the liability is incurred (at the
time the wells are drilled or acquired). Unit does not have any assets
restricted for the purpose of settling the plugging liabilities.
14
The following table shows the activity relating to our 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 8 244
Liability Incurred in the Period 53 226
Liability Settled in the Period - (79)
Reclassification of Liability
From Long to Short Term 37 (37)
------------- -------------
Plugging Liability 6/30/03 $ 301 $ 10,986
============= =============
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 before change in accounting
principle for the three and six month periods of 2003 by $37,000 ($0.00 per
share) and $75,000 ($0.00 per share), respectively. The financial statements for
the first three months of 2002 have not been restated and the cumulative effect
of the change of $1,325,000 net of tax ($0.03 per share) is shown as a one-time
addition to income in the first quarter of 2003.
15
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:
Change 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
=========== =========== ===========
At January 1, 2000 and December 31, 2000, 2001 and 2002 the plugging
liability would have been $8,039,000, $8,673,000, $9,675,000 and $10,836,000,
respectively, if FAS 143 had been applied during all the periods affected
assuming the liability was measured using the information, assumptions and
interest rates used as of the adoption date of January 1, 2003.
16
On January 1, 2003, we adopted Financial Accounting Standards No. 145,
"Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement 13,
and Technical Corrections" (FAS 145). This statement eliminates an inconsistency
between the required accounting for sale-leaseback transactions and the required
accounting for certain lease modifications that have economic effects that are
similar to sale-leaseback transactions. This statement also amends other
existing authoritative pronouncements to make various technical corrections,
clarify meanings, or describe their applicability under changed conditions. The
adoption of FAS 145 did not have a material effect on our financial position,
results of operations or cashflows.
In July 2002, the FASB issued Statement of Financial Accounting Standards
No. 146, "Accounting for Cost Associated with Exit or Disposal Activities" (FAS
146). FAS 146 is effective for exit or disposal activities that are initiated
after December 31, 2002. The Statement addresses financial accounting and
reporting for costs associated with exit or disposal activities and requires
companies to recognize costs associated with exit or disposal activities when
they are incurred rather than at the date of a commitment to an exit or disposal
plan. FAS 146 nullifies Emerging Issues Task Force Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring)." During the
first six months of 2003, we did not have any exit or disposal activities.
In April 2003, the FASB issued Statement of Financial Accounting Standards
No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities" (FAS 149). FAS 149 amends and clarifies financial accounting and
reporting for derivative instruments, including certain derivative instruments
embedded in other contracts (collectively referred to as derivatives) and for
hedging activities under FAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities". Unit is currently evaluating the impact of FAS 149 on its
financial position and results of operations.
In May 2003, the FASB issued Statement on Financial Accounting Standards
No. 150, "Accounting for Certain Financial Instruments with Characteristics of
both Liabilities and Equity" (FAS 150). FAS 150 establishes standards regarding
the classification and measurement of certain financial instruments with
characteristics of both liabilities and equity. It requires that an issuer
classify a financial instrument that is within its scope as a liability (or an
asset in some circumstances). Many of those instruments were previously
classified as equity. FAS 150 will be effective for us starting in the quarter
ended September 30, 2003. We do not expect the application of SFAS 150 to have a
material effect on our financial position, results of operations or cashflow.
17
NOTE 4 - INTANGIBLE UNDEVELOPED LEASEHOLD AND INTANGIBLE DEVELOPED
LEASEHOLD
- ------------------------------------------------------------------
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 Financial
Accounting Standards Board (FASB) in June 2001 and became effective for us 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, these oil and gas mineral rights held under
lease and other contractual arrangements representing the right to extract such
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 disclosures required by FAS 141 and 142 relative to
intangibles would be included in the notes to financial statements.
Historically, we, like many other oil and gas companies, have included these oil
and gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves as part of the oil and gas
properties, even after FAS 141 and 142 became effective.
Our results of operations and cash flows would not be affected, since these
oil and gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves would continue to be amortized
in accordance with full cost accounting rules.
At June 30, 2003, we had undeveloped leaseholds of approximately
$15,811,000 that would be classified on our balance sheet as "intangible
undeveloped leasehold" and developed leaseholds of an estimated $20,163,000 that
would be classified as "intangible developed leasehold" if we applied the
interpretations. This classification would require us to make the disclosure set
forth under FAS 142 related to these interests.
We will continue to classify our oil and gas mineral rights held under
lease and other contractual rights representing the right to extract such
reserves as tangible oil and gas properties until further guidance is provided.
18
NOTE 5 - HEDGING ACTIVITY
- -------------------------
Periodically Unit hedges the price it will receive for a portion of its
future natural gas and oil production. The hedge is made in an attempt to reduce
the impact and uncertainty that price variations have on Unit's cash flow.
During the first quarter of 2003, Unit entered into two natural gas collar
contracts for approximately 37 percent of its April thru September 2003
production. One contract has a floor price of $4.00 and a ceiling price of $5.75
and the other contract has a floor price of $4.50 and a ceiling price of $6.02.
During the first quarter of 2003, Unit also entered into two oil collar
contracts for approximately 26 percent of its May thru December 2003 oil
production. One contract has a floor price of $25.00 and a ceiling price of
$32.20 and the other contact has a floor price of $26.00 and a ceiling price of
$31.40. Unit had a $6,000 reduction in natural gas revenues as a result of the
natural gas hedges settled in the second quarter of 2003. The fair value of the
collar contracts still outstanding was recognized on the June 30, 2003 balance
sheet as a derivative liability of $119,000 and as a $74,000 loss, net of tax,
in accumulated other comprehensive income. These hedges were fully effective.
Unit did not have any hedging contracts in place in the first six months of
2002.
NOTE 6 - INDUSTRY SEGMENT INFORMATION
- -------------------------------------
The company has two business segments: Contract Drilling, and Oil and
Natural Gas, representing its two strategic 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 company evaluates the performance of its operating segments
based on operating income, which is defined as operating revenues less operating
expenses and depreciation, depletion and amortization. The company has natural
gas production in Canada, which is not significant. Information regarding the
company's operations by industry segment for the three and six month periods
ended June 30, 2002 and 2003 is as follows:
19
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2002 2003 2002 2003
---------- ---------- ---------- ----------
(In thousands)
Revenues:
Contract drilling $ 25,841 $ 45,221 $ 52,555 $ 79,787
Oil and natural gas 18,668 26,871 30,629 60,119
Other 244 888 299 1,520
---------- ---------- ---------- ----------
$ 44,753 $ 72,980 $ 83,483 $ 141,426
========== ========== ========== ==========
Operating Income (1):
Contract drilling $ 2,776 $ 5,681 $ 7,547 $ 7,542
Oil and natural gas 7,519 14,533 9,263 35,119
---------- ---------- ---------- ----------
Total operating
income 10,295 20,214 16,810 42,661
General and
administrative
expense (2,013) (2,070) (4,042) (4,520)
Interest expense (229) (175) (516) (386)
Other income - net 244 888 299 1,520
---------- ---------- ---------- ----------
Income before
income taxes
and change in
accounting
principle $ 8,297 $ 18,857 $ 12,551 $ 39,275
========== ========== ========== ==========
(1) Operating income is total operating revenues less operating
expenses, depreciation, depletion and amortization and does not include
non-operating revenues, general corporate expenses, interest expense or
income taxes.
The cumulative effect of change in accounting principle recorded in the
first quarter of 2003 of $1,325,000, net of $811,000 in income tax, is all
related to the oil and natural gas segment.
20
NOTE 7 - SUBSEQUENT EVENT
- -------------------------
On August 14, 2003 Unit signed a definitive agreement with PetroCorp
Incorporated (AMEX - PEX) to acquire all the outstanding shares of PetroCorp.
The purchase price under the agreement is approximately $182,000,000 and will be
paid all in cash. The purchase price is subject to certain adjustments including
$6,500,000 which will be place in escrow to settle or satisfy certain contingent
tax and litigation liabilities if not resolved prior to closing. Consummation of
the transaction is subject to several conditions typical of transactions of this
nature including regulatory review and the approval by two-thirds of PetroCorp's
shareholders. PetroCorp shareholders representing approximately 50% of the
outstanding shares of PetroCorp have agreed to support the merger. PetroCorp is
a Tulsa-based company that explores and develops oil and natural gas properties
primarily in Texas and Oklahoma.
21
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders
Unit Corporation
We have reviewed the accompanying consolidated condensed balance sheet of Unit
Corporation and subsidiaries as of June 30, 2003, and the related consolidated
condensed statements of operations and comprehensive income for each of the
three and six month periods ended June 30, 2003 and 2002 and the statement of
cash flows for the six month periods ended June 30, 2003 and 2002. These
financial statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures and making
inquiries of persons responsible for financial and accounting matters. It is
substantially less in scope than an audit conducted in accordance with generally
accepted auditing standards, the objective of which is the expression of an
opinion regarding the financial statements taken as a whole. Accordingly, we do
not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the accompanying condensed consolidated interim financial statements
for them to be in conformity with accounting principles generally accepted in
the United States of America.
We previously audited, in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet as of December
31, 2002, and the related consolidated statements of operations, stockholder's
equity and of cash flows for the year then ended (not presented herein), and in
our report, dated February 19, 2003, we expressed an unqualified opinion on
those consolidated financial statements. In our opinion, the information set
forth in the accompanying consolidated balance sheet information as of December
31, 2002, is fairly stated in all material respects in relation to the
consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers L L P
Tulsa, Oklahoma
July 23, 2003
22
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
- ---------------------------------------------------------------------------
FINANCIAL CONDITION
- -------------------
Summary. Our financial condition and liquidity depends on the cash flow
from our two principal subsidiaries (Unit Drilling Company and Unit Petroleum
Company) and borrowings under our bank loan agreement. At June 30, 2003, we had
cash totaling $1.3 million and we had borrowed $19.0 million of the $40.0
million we have elected to have available under our loan agreement.
The following is a summary of certain financial information on June 30,
2002 and 2003 and for the six months ended June 30, 2002 and 2003:
June 30, June 30, Percent
2002 2003 Change
-------------- -------------- -------
Income Before Change in
Accounting Principle $ 7,750,000 $ 24,350,000 214%
Net Income $ 7,750,000 $ 25,675,000 231%
Net Cash Provided by
Operating Activities $ 40,811,000 $ 60,655,000 49%
Net Cash Used in Investing
Activities $ 27,822,000 $ 44,082,000 58%
Net Cash Used in Financing
Activities $ 11,922,000 $ 15,744,000 32%
Working Capital $ 12,361,000 $ 26,839,000 117%
Long-Term Debt $ 20,000,000 $ 19,000,000 (5%)
Shareholders' Equity $ 288,179,000 $ 448,475,000 56%
Ratio of Long-Term debt to
Total Capitalization 6% 4%
The following table summarizes certain operating information for the first
six months of 2002 and 2003:
Percent
2002 2003 Change
------------ ------------ --------
Oil Production (Bbls) 227,000 238,000 5%
Natural Gas Production (Mcf) 9,653,000 9,810,000 2%
Average Oil Price Received $ 19.83 $ 27.86 40%
Average Natural Gas Price
Received $ 2.53 $ 5.34 111%
Average Number of Our
Drilling Rigs in Use
During the Period 33.0 57.0 73%
Total Number of Our Drilling
Rigs Available at the End
of the Period 55 75 36%
23
Our Bank Loan Agreement. On July 24, 2001, we signed a $100 million bank
loan agreement. At our election, the amount currently available for us to borrow
is $40 million. Although the current value of our assets would have allowed us
to have access to the full $100 million, we elected to set the loan commitment
at $40 million to reduce our financing costs since we are charged a facility fee
of .375 of 1 percent on the amount available but not borrowed.
Each year, on April 1 and October 1, our banks redetermine the loan value
of our assets. At the April 1, 2003 redetermination date, the banks confirmed
that the value of our assets would allow us to have access to the full $100
million. This value is mainly based on an amount equal to a percentage of the
discounted future value of our oil and natural gas reserves, as determined by
the banks. In addition, an amount representing a part of the value of our
drilling rig fleet, limited to $20 million, is added to the loan value. Our loan
agreement provides for a revolving credit facility, which ends on May 1, 2005
followed by a three-year term loan. Borrowing under our loan agreement totaled
$19.0 million at June 30, 2003 and July 23, 2003 our second quarter earnings
release date.
Borrowings under the revolving credit facility bear interest at the Chase
Manhattan Bank, N.A. prime rate ("Prime Rate") or the London Interbank Offered
Rates ("Libor Rate") plus 1.00 to 1.50 percent depending on the level of debt as
a percentage of the total loan value. After May 1, 2005, borrowings under the
loan agreement bear interest at the Prime Rate or the Libor Rate plus 1.25 to
1.75 percent depending on the level of debt as a percentage of the total loan
value. In addition, the loan agreement allows us to select, between the date of
the agreement and 3 days before the start of the term loan, a fixed rate for the
amount outstanding under the credit facility. Our ability to select the fixed
rate option is subject to several conditions, all of which are set out in the
loan agreement.
The interest rate on our bank debt was 2.28 percent at June 30, 2003 and
July 23, 2003. At our election, any portion of our outstanding bank debt may be
fixed at the Libor Rate, as adjusted depending on the level of our debt as a
percentage of the amount available for us to borrow. The Libor Rate may be fixed
for periods of up to 30, 60, 90 or 180 days with the balance of our bank debt
being subject to the Prime Rate. During any Libor Rate funding period, we may
not pay any part of the outstanding principal balance which is subject to the
Libor Rate. Borrowings subject to the Libor Rate were $19.0 million at June 30,
2003 and July 23, 2003.
The loan agreement also requires us to maintain:
. consolidated net worth of at least $125 million;
. a current ratio of not less than 1 to 1;
. a ratio of long-term debt, as defined in the loan agreement, to
consolidated tangible net worth not greater than 1.2 to 1;
. a ratio of total liabilities, as defined in the loan agreement,
to consolidated tangible net worth not greater than 1.65 to 1; and
. working capital provided by operations, as defined in the loan
agreement, cannot be less than $40 million in any year.
24
We are restricted from paying dividends (other than stock dividends) during
any fiscal year in excess of 25 percent of our consolidated net income from the
preceding fiscal year and we can pay dividends only if our working capital
provided from our operations during the preceding year is equal to or greater
than 175 percent of current maturities of long-term debt at the end of the
preceding year. We also cannot incur additional debt except in certain 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 is prohibited unless
it is in favor of our banks.
Contractual Commitments. We have the following contractual obligations at
June 30, 2003:
Payments Due by Period
--------------------------------------------------
Less
Contractual Than 1 2-3 4-5 After 5
Obligations Total Year Years Years Years
------------- --------- -------- -------- --------- --------
(In thousands)
Bank Debt(1) $ 19,000 $ - $ 6,861 $ 12,139 $ -
Retirement
Agreement(2) 1,444 300 600 544 -
Operating
Leases(3) 3,999 748 1,439 1,123 689
--------- -------- -------- --------- --------
Total
Contractual
Obligations $ 24,443 $ 1,048 $ 8,900 $ 13,806 $ 689
========= ======== ======== ========= ========
-------------------
(1) See Previous Discussion in Management Discussion and Analysis regarding
bank debt.
(2) In the second quarter of 2001, we recorded $1.3 million in additional
employee benefit expenses for the present value of a separation
agreement made in connection with the retirement of King Kirchner from
his position as Chief Executive Officer. The liability associated with
this expense, including accrued interest, will be paid in monthly
payments of $25,000 starting in July 2003 and continuing through June
2009.
(3) We lease office space in Tulsa and Woodward Oklahoma and Houston and
Booker Texas under the terms of operating leases expiring through
January 31, 2010 along with leasing space on short term commitments to
stack excess rig equipment and production inventory. In the first
quarter of 2003, we renegotiated our rental agreement for the Tulsa
office reducing the price per square foot while adding additional space
and lengthening the term of the agreement to January 31, 2010.
25
At June 30, 2003, we also have the following commitments and contingencies
that could create, increase or accelerate our liabilities:
Amount of Commitment Expiration
Per Period
--------------------------------------
Total
Amount
Committed Less
Other Or Than 1 2-3 4-5 After 5
Commitments Accrued Year Years Years Years
--------------- --------- -------- -------- -------- --------
(In thousands)
Deferred
Compensation
Agreement(1) $ 1,603 Unknown Unknown Unknown Unknown
Separation
Benefit
Agreement(2) $ 2,781 $ 135 Unknown Unknown Unknown
Plugging
Liability(3) $ 11,287 $ 301 $ 2,047 $ 662 $ 8,277
Gas Balancing
Liability(4) $ 1,020 Unknown Unknown Unknown Unknown
Repurchase
Obliga-
tions(5) Unknown Unknown Unknown Unknown Unknown
(1) We provide a salary 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. We recognize payroll
expense and record a liability, included in other long-term liabilities
in our Consolidated Balance Sheet, at the time of deferral.
(2) Effective January 1, 1997, we adopted a separation benefit plan
("Separation Plan"). The Separation Plan allows eligible employees whose
employment with us 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 us in exchange for receiving the separation benefits. On
October 28, 1997, we 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.
(3) On January 1, 2003 we adopted Financial Accounting Standards No. 143,
"Accounting for Asset Retirement Obligations" (FAS 143). FAS 143
26
establishes an accounting standard requiring the recording of the fair
value of liabilities associated with the retirement of long-lived assets
(mainly plugging and abandonment costs for our depleted wells) in the
period in which the liability is incurred (at the time the wells are
drilled or acquired).
(4) We have recorded a liability 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.
(5) We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986
Energy Income Limited Partnership along with private limited
partnerships (the "Partnerships") with certain qualified employees,
officers and directors from 1984 through 2003, with a subsidiary of ours
serving as General Partner. The Partnerships were formed for the purpose
of conducting oil and natural gas acquisition, drilling and development
operations and serving as co-general partner with us in any additional
limited partnerships formed during that year. The Partnerships
participated on a proportionate basis with us in most drilling
operations and most producing property acquisitions commenced by us for
our own account during the period from the formation of the Partnership
through December 31 of each year. These partnership agreements require,
upon the election of a limited partner, that we repurchase the limited
partner's interest at amounts to be determined by appraisal in the
future. Such repurchases in any one year are limited to 20 percent of
the units outstanding. We made repurchases of $1,000 in 2002 for such
limited partners' interests. We made repurchases for $17,000 in the
second quarter of 2003.
Hedging. Periodically we hedge the prices we will receive for a portion of
our future natural gas and oil production. We do so in an attempt to reduce the
impact and uncertainty that price variations have on our cash flow.
During the first quarter of 2003, we entered into two natural gas collar
contracts for approximately 37 percent of our April thru September 2003
production. One contract has a floor price of $4.00 and a ceiling price of $5.75
and the other contract has a floor price of $4.50 and a ceiling price of $6.02.
During the first quarter of 2003, we also entered into two oil collar contracts
for approximately 26 percent of our May thru December 2003 oil production. One
contract has a floor price of $25.00 and a ceiling price of $32.20 and the other
contact has a floor price of $26.00 and a ceiling price of $31.40. We had a
$6,000 reduction in natural gas revenues as a result of the natural gas hedges
settled in the second quarter of 2003. The fair value of the collar contracts
still outstanding was recognized on the June 30, 2003 balance sheet as a
derivative liability of $119,000 and as a $74,000 loss, net of tax, in
accumulated other comprehensive income. These hedges were fully effective. We
did not have any hedging contracts in place in the first six months of 2002.
27
Self-Insurance. Unit is self-insured for certain losses relating to
workers' compensation, general liability, property damage and employee medical
benefits. Given the tightening in the insurance market our self-insurance levels
have significantly increased. Effective August 1, 2002, our exposure (i.e. our
deductible or retention), per occurrence, ranges from $200,000 for general
liability to $1 million for rig physical damage. We have purchased stop-loss
coverage in order to limit, to the extent feasible, our per occurrence and
aggregate exposure to certain claims. There is no assurance that such coverage
will adequately protect us against liability from all potential consequences.
Our Oil and Natural Gas Operations. Natural gas comprises 91 percent of our
total oil and natural gas reserves. Any significant change in natural gas prices
has a material affect on our revenues, cash flow and the value of our oil and
natural gas reserves.
Based on our 2003 first six month production, a $.10 per Mcf change in what
we are paid for our natural gas production would result in a corresponding
$152,000 per month ($1,824,000 annualized) change in our pre-tax cash flow. Our
first six month 2003 average natural gas price was $5.34 compared to an average
natural gas price of $2.53 received in the first six months of 2002. We sell
most of our natural gas production to third parties under month-to-month
contracts. A $1.00 per barrel change in our oil price would have a $37,000 per
month ($444,000 annualized) change in our pre-tax cash flow. Our first six
months 2003 average oil price was $27.86 compared with an average oil price of
$19.83 received in the first six months of 2002.
Because natural gas prices have such a significant affect on the value of
our oil and natural gas reserves declines in these prices can result in a
decline in the carrying value of our oil and natural gas properties. Also, price
declines can adversely affect the semi-annual determination of the amount
available for us to borrow under our bank loan agreement since that
determination is based mainly on the value of our oil and natural gas reserves.
Such a reduction could limit our ability to carry out our planned capital
projects.
Our decision to increase our oil and natural gas reserves through
acquisitions or through drilling depends on the prevailing or expected market
conditions, potential return on investment, future drilling potential and
opportunities to obtain acceptable financing under the circumstances involved,
all of which provide us with a large degree of flexibility in deciding when to
incur these costs. We drilled 62 wells in the first six months of 2003 compared
to 33 wells in the first six months of 2002. Through the first six months of
2003 we incurred $29.4 million of the $70 to $75 million in capital expenditures
we expect to make for exploration, development drilling and acquisition of oil
and natural gas properties in 2003. Based on current oil and natural gas prices,
we plan to drill and or participate in an estimated 140 to 150 wells in 2003.
28
Contract Drilling. Our drilling work is subject to many factors that
influence the number of rigs we have working as well as the costs and revenues
associated with such work. These factors include competition from other drilling
contractors, the prevailing prices for natural gas and oil, availability and
cost of labor to run our rigs and our ability to supply the equipment needed. We
have not encountered major difficulty in hiring and keeping rig crews, but such
shortages have occurred periodically in the past. If demand for drilling rigs
continues to increase, we may well incur shortages of experienced personnel
which would limit our ability to increase the number of rigs we could operate.
Through the first six months of 2003 we incurred $9.1 million in capital
expenditures for our drilling operation. For the year 2003, we anticipate
spending approximately $30 million on our drilling operations.
Low oil and natural gas prices during most of the 1980's and 1990's reduced
demand for domestic land contract drilling rigs. However, in the last half of
1999 and throughout 2000, as oil and natural gas prices increased, we
experienced a big increase in demand for our rigs. Demand continued to increase
until the end of the third quarter of 2001 and reached a high when 52 of our
rigs were working in July 2001. Because of declining natural gas prices
throughout 2001, demand for our rigs dropped significantly in the fourth quarter
of 2001 and carried over into the first quarter of 2002. Average use of our rigs
in the first six months of 2002 was 33.0 rigs compared with 56.8 rigs for the
first six months of 2003. Natural gas prices began increasing in the fourth
quarter of 2002 and they increased substantially in the first quarter of 2003.
The increase in commodity prices along with our acquisition of 20 rigs in the
third quarter of 2002, caused the rise in 2003 utilization.
As demand for our rigs increased during 2001 so did the dayrates we
received. Our average dayrate reached $11,142 by September of 2001. However, as
demand began to decrease, so did our rates. Our average dayrate in the first six
months of 2002 was $8,055 and our average dayrate for the first six months of
2003 was $7,476. Increases in dayrates typically lag behind increases in
utilization. We saw dayrates start to improve in the second quarter of 2003 and
we think they will continue a gradual increase into the third quarter of 2003.
Based on the average utilization of our rigs in the first six months of 2003, a
$100 per day change in dayrates has a $5,700 per day ($2,081,000 annualized)
change in our pre-tax operating cash flow.
Our contract drilling segment provides drilling services for our
exploration and production segment. The contracts for these services are issued
under the same conditions and rates as the contracts we have entered into with
unrelated third parties. The profit received by our contract drilling segment of
$542,000 and $702,000 in the first six months of 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.
29
Oil and Natural Gas Limited Partnerships and Other Entity Relationships. We
are the general partner for ten oil and natural gas partnerships which were
formed privately and publicly. The partnership's revenues and costs are shared
under formulas prescribed in each limited partnership agreement. The
partnerships repay us for contract drilling, well supervision and general and
administrative expense. Related party transactions for contract drilling and
well supervision fees are the related party's share of such costs. These costs
are billed on the same basis as billings to unrelated third parties for similar
services. General and administrative reimbursements consist of direct general
and administrative expense incurred on the related party's behalf as well as
indirect expenses assigned to the related parties. Allocations are based on the
related party's level of activity and are considered by management to be
reasonable. During 2002, the total paid to us for all of these fees was
approximately $232,000 per quarter and during the first six months of 2003 the
amount paid has been 8 percent above last years quarterly average. Our
proportionate share of assets, liabilities and net income relating to the oil
and natural gas partnerships is included in our consolidated financial
statements.
Interests in the employee partnerships were offered to the employees of
Unit and its subsidiaries whose annual base compensation were at least a
specified amount ($22,680 for 2002 and 2003) and to the directors of Unit. The
general partner of each of these partnerships is Unit Petroleum Company. Each
employee partnership is named the Unit (year) Employee Oil and Gas Limited
Partnership. The interests in these programs issued to the directors and named
executive officers of Unit are disclosed in our proxy statements for each year's
annual meeting of shareholders.
At June 30, 2003, we owned a 40 percent equity interest in Superior
Pipeline Company, a natural gas gathering and processing company. Our investment
including our share of the equity in the earnings of this company totaled $2.3
million at June 30, 2003. From time to time we may guarantee the debt of this
company. However, as of June 30, 2003 and July 23, 2003, we were not
guaranteeing any of the debt of this company.
On June 25, 2003, we acquired a 26.04 percent interest in Eagle Energy
Partners I, L.P., ("Eagle") a Texas limited partnership for $2.5 million. Unit's
percentage interest in the partnership is subject to change. During the next six
months, Eagle will be attempting to acquire $2 million of additional capital
from other investors. This newly formed partnership is engaged in the purchase
and sale of natural gas, electricity (or similar electricity based products), or
any future commodities, and the performance of scheduling and nomination
services for energy related commodities and similar energy management functions.
In addition to our investment in this partnership, the partnership has the
right, subject to being the successful bidder, to buy, each month, a certain
percentage of our natural gas during the six month period starting August 1,
2003. For August 2003, Eagle will buy approximately 26% of the natural gas we
sell on a monthly basis for ourselves and other working interest owners.
30
Outlook. Both of our operating segments are extremely dependent on natural
gas prices. These prices affect not only our production revenues, but also the
demand and rates for our contract drilling services. Over the first six months
of 2003 our average natural gas price received for each month excluding hedging
ranged from $4.18 in January to a high of $8.38 in March and the average Nymex
Henry Hub daily price for the same time period ranged from $4.55 to $6.72. On
our second quarter earnings release date of July 23, 2003, the Nymex Henry Hub
average contract settle price for the next twelve months was $4.96 and, we
anticipate that if natural gas prices continue at that level, there will be
increased demand for our rigs and upward movement on the rates we receive for
our contract drilling services.
Critical Accounting Policies. We account for our oil and natural gas
exploration and development activities using the full cost method of accounting.
Under this method, all costs incurred in the acquisition, exploration and
development of oil and natural gas properties are capitalized. At the end of
each quarter, the net capitalized costs of our oil and natural gas properties is
limited to the lower of unamortized cost or a ceiling. The ceiling is defined as
the sum of the present value (10 percent discount rate) of estimated future net
revenues from proved reserves, based on period-end oil and natural gas prices,
plus the lower of cost or estimated fair value of unproved properties included
in the costs being amortized less related income taxes. If the net capitalized
costs of our oil and natural gas properties exceed the ceiling, we are subject
to a write-down to the extent of such excess. A ceiling test write-down is a
non-cash charge to earnings. If required, it reduces earnings and impacts
stockholders' equity in the period of occurrence and results in lower
depreciation, depletion and amortization expense in future periods. Once
incurred, a write-down cannot be reversed even if prices subsequently recover.
The risk that we will be required to write-down the carrying value of our
oil and natural gas properties increases when oil and natural gas prices are
depressed or if we have large downward revisions in our estimated proved
reserves. Application of these rules during periods of relatively low oil or
natural gas prices, even if temporary, increases the chance of a ceiling test
write-down. Based on oil and natural gas prices in effect on June 30, 2003
($5.00 per Mcf for natural gas and $28.44 per barrel for oil), the unamortized
cost of our domestic oil and natural gas properties did not exceed the ceiling
of our proved oil and natural gas reserves. Natural gas prices remain erratic
and any significant declines below quarter-end prices used in the reserve
evaluation could result in a ceiling test write-down in following quarterly
reporting periods.
The value of our oil and natural gas reserves is used to determine most of
the loan value under our loan agreement. This value is affected by both price
changes and the measurement of reserve volumes. Oil and natural gas reserves
cannot be measured exactly. Our estimate of oil and natural gas reserves require
extensive judgments of our reservoir engineering data and are less precise than
other estimates made in connection with financial disclosures. Assigning
monetary values to our estimates does not reduce the subjectivity and changing
nature of our reserve estimates. Indeed, the uncertainties inherent in the
31
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.
We use 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. Our policy is to expense our pro-rata share of
lease operating costs from all wells as incurred. Such expenses relating to the
natural gas balancing position on wells in which we have an imbalance are not
material.
Drilling equipment, transportation equipment and other property and
equipment are carried at cost. Renewals and betterments are capitalized while
repairs and maintenance are expensed. Realization of the carrying value of
property and equipment is reviewed for possible impairment whenever events or
changes in circumstances suggest 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 us to reduce the carrying value of our
property and equipment.
Because the Company does not bear the risk of completion of wells drilled
under "daywork" drilling contracts, it recognizes revenues and expenses
generated from those contracts as the services are performed (i.e. daily). Under
"footage" and "turnkey" contracts, revenues and expenses are recognized when the
company has satisfied certain requirements as detailed in the applicable
contracts. If it has been determined that a well is going to incur a loss, the
entire amount of the estimated loss is recorded when the loss can be reasonably
determined, however, any profit is recorded only at the time terms of the
contract are completed. 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.
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 Financial
Accounting Standards Board (FASB) in June 2001 and became effective for us 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, these oil and gas mineral rights
32
held under lease and other contractual arrangements representing the right
to extract such 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 disclosures required by FAS 141 and 142
relative to intangibles would be included in the notes to financial statements.
Historically, we, like many other oil and gas companies, have included these oil
and gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves as part of the oil and gas
properties, even after FAS 141 and 142 became effective.
Our results of operations and cash flows would not be affected, since these
oil and gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves would continue to be amortized
in accordance with full cost accounting rules.
At June 30, 2003, we had undeveloped leaseholds of approximately
$15,811,000 that would be classified on our balance sheet as "intangible
undeveloped leasehold" and developed leaseholds of an estimated $20,163,000 that
would be classified as "intangible developed leasehold" if we applied the
interpretations. This classification would require us to make the disclosures
set forth under FAS 142 related to these interests.
We will continue to classify our oil and gas mineral rights held under
lease and other contractual rights representing the right to extract such
reserves as tangible oil and gas properties until further guidance is provided.
Acquisitions. On August 14, 2003 Unit signed a definitive agreement with
PetroCorp Incorporated (AMEX - PEX) to acquire all the outstanding shares of
PetroCorp. The purchase price under the agreement is approximately $182,000,000
and will be paid all in cash. The purchase price is subject to certain
adjustments including $6,500,000 which will be place in escrow to settle or
satisfy certain contingent tax and litigation liabilities if not resolved prior
to closing. Consummation of the transaction is subject to several conditions
typical of transactions of this nature including regulatory review and the
approval by two-thirds of PetroCorp's shareholders. PetroCorp shareholders
representing approximately 50% of the outstanding shares of PetroCorp have
agreed to support the merger. PetroCorp is a Tulsa-based company that explores
and develops oil and natural gas properties primarily in Texas and Oklahoma.
Change in Board of Directors and Officers. On June 18, 2003 we announced
that King Kirchner, an original founder of Unit Corporation, will retire as
Chairman of the Board of Directors of Unit Corporation effective August 1, 2003.
Mr. Kirchner will remain on the Board. Effective with Mr. Kirchner's retirement,
our Board of Directors elected John G. Nikkel to succeed Mr. Kirchner as
Chairman of the Board of Directors. Mr. Nikkel will continue to serve as the
Company's Chief Executive Officer. Mr. Nikkel
33
served as our President for almost 20 years and has served as our Chief
Executive Officer since July of 1999. Effective August 1, 2003, Mr. Larry
Pinkston, our current Executive Vice President will assume the office of
President in addition to his current role as Treasurer and Chief Financial
Officer. Mr. Pinkston has been employed by us for 22 years.
SAFE HARBOR STATEMENT
- ---------------------
Statements in this document as well as information contained in written
material, press releases and oral statements issued by or for us contain, or may
contain, certain "forward-looking statements" within the meaning of federal
securities laws. All statements, other than statements of historical facts,
included in this document which address activities, events or developments which
we expect or expect will or may occur in the future are forward-looking
statements. The words "believes," "intends," "expects," "anticipates,"
"projects," "estimates," "predicts" and similar expressions are also intended to
identify forward-looking statements. These forward-looking statements include,
among others, such things as:
. the amount and nature of future capital expenses;
. wells to be drilled or reworked;
. oil and natural gas prices to be received and demand for
oil and natural gas;
. exploitation and exploration prospects;
. estimates of proved oil and natural gas reserves;
. reserve potential;
. development and infill drilling potential;
. drilling prospects;
. expansion and other development trends of the oil and
natural gas industry;
. our business strategy;
. production of our oil and natural gas reserves;
. expansion and growth of our business and operations;
. availability of drilling rigs and rig related equipment;
. drilling rig use, revenues and costs; and
. availability of qualified labor.
These statements are based on certain assumptions and analyses made by us
in light of our experience and our view of historical trends, current conditions
and expected future developments as well as other factors we believe are proper
in the circumstances. However, whether actual results and developments will
conform to our expectations and predictions is subject to many risks and
uncertainties which could cause actual results to differ materially from our
expectations, including:
. the risk factors discussed in this document;
. general economic, market or business conditions;
. the nature or lack of business opportunities that may be
presented to and pursued by us;
. demand for land drilling services;
34
. changes in laws or regulations; and
. other reasons, most of which are beyond our control.
A more thorough discussion of forward-looking statements with the possible
impact of some of these risks and uncertainties is provided in our Annual Report
on Form 10-K filed with the Securities and Exchange Commission. We encourage you
to get and read that document.
35
RESULTS OF OPERATIONS
- ---------------------
Second Quarter 2003 versus Second Quarter 2002
- ----------------------------------------------
Provided below is a comparison of selected operating and financial data for
the second quarter of 2003 verses the second quarter of 2002:
Second Second Percent
Quarter 2002 Quarter 2003 Change
--------------- --------------- ---------
Total Revenue $ 44,753,000 $ 72,980,000 63%
Net Income $ 5,108,000 $ 11,691,000 129%
Oil and Natural Gas:
Revenue $ 18,668,000 $ 26,871,000 44%
Average natural gas price (Mcf) $ 3.00 $ 4.74 58%
Average oil price (Bbl) $ 22.59 $ 25.51 13%
Natural gas production (Mcf) 5,097,000 4,955,000 (3%)
Oil production (Bbl) 110,000 123,000 12%
Operating profit
(revenue less operating costs) $ 13,507,000 $ 20,978,000 55%
Operating margin 72% 78%
Depreciation, depletion and
amortization rate (Mcfe) $ 1.03 $ 1.12 8%
Depreciation, depletion and
amortization $ 5,988,000 $ 6,445,000 8%
Drilling:
Revenue $ 25,841,000 $ 45,221,000 75%
Percentage of revenue from
daywork contracts 85% 97%
Average number of rigs in use 33.2 62.4 88%
Average dayrate on daywork
contracts $ 7,698 $ 7,601 (1%)
Operating profit
(revenue less operating costs) $ 5,704,000 $ 11,580,000 (11%)
Operating margin 22% 26%
Depreciation $ 2,928,000 $ 5,899,000 101%
General and Administrative Expense $ 2,013,000 $ 2,070,000 3%
Interest Expense $ 229,000 $ 175,000 (24%)
Average Interest Rate 3.00% 2.17% (28%)
Average Long-Term Debt Outstanding $ 23,470,000 $ 22,968,000 (2%)
36
Oil and natural gas revenues, operating profits and operating profit
margins were all positively affected by higher oil and natural gas prices and
increased oil production between the second quarter of 2003 and the second
quarter of 2002. We continue to focus our drilling program on the development of
natural gas reserves, but natural gas production was down between the
comparative quarters due to delays in placing new natural gas production on line
early in the year and production from older wells declined. Total operating cost
increased in the second quarter of 2003 when compared with the second quarter of
2002 due mainly to higher gross production taxes which are based on a percentage
of revenues which were generated by higher commodity prices. Our total
depreciation, depletion and amortization ("DD&A) increased due an increase in
our DD&A rate per Mcfe. During 2002 and continuing into the first half of 2003,
we experienced higher cost per Mcfe for the discovery of new reserves through
our development drilling program resulting in an increase in the DD&A rate
between the comparative quarters.
Reduced natural gas prices in the fourth quarter of 2001 and the first half
of 2002, caused decreases in operator demand for contract drilling rigs within
our working area throughout most of 2002. Natural gas prices increased once
again into the first quarter of 2003 and along with the acquisition of 20 rigs
in the third quarter of 2002 our second quarter 2003 utilization recovered and
was 88 percent higher than the second quarter of 2002. In the second quarter of
2003 dayrates for our rigs also increased from our first quarter lows and were
only one percent lower than in the second quarter of 2002. Operating margins
increased between the comparative periods, since we had higher rig utilization
to cover our fixed operating costs. Approximately 3 percent of our total
drilling revenues in the second quarter of 2003 came from footage and turnkey
contracts, which had profit margins lower than our daywork contracts. Contract
drilling depreciation increased due to the acquisition of 20 rigs in August of
2002 and the increase in rigs used between the comparative quarters.
General and administrative expense was higher in the first quarter of 2003
due to increases in insurance expense. Our total interest expense is lower due
to lower interest rates and decreased average debt outstanding. Income tax
expense increased primarily due to the increase in income from continuing
operations.
37
Six Months 2003 versus Six Months 2002
- --------------------------------------
Provided below is a comparison of selected operating and financial data for
the first six months of 2003 verses the first six months of 2002:
First Six First Six Percent
Months 2002 Months 2003 Change
--------------- --------------- ---------
Total Revenue $ 83,483,000 $ 141,426,000 69%
Income Before Change in Accounting
Principle $ 7,750,000 $ 24,350,000 214%
Net Income $ 7,750,000 $ 25,675,000 231%
Oil and Natural Gas:
Revenue $ 30,629,000 $ 60,119,000 96%
Average natural gas price (Mcf) $ 2.53 $ 5.34 111%
Average oil price (Bbl) $ 19.83 $ 27.86 40%
Natural gas production (Mcf) 9,653,000 9,810,000 2%
Oil production (Bbl) 227,000 238,000 5%
Operating profit
(revenue less operating costs) $ 20,520,000 $ 47,611,000 280%
Operating margin 67% 79%
Depreciation, depletion and
amortization rate (Mcfe) $ 1.01 $ 1.10 9%
Depreciation, depletion and
amortization $ 11,257,000 $ 12,492,000 11%
Drilling:
Revenue $ 52,555,000 $ 79,787,000 52%
Percentage of revenue from
daywork contracts 91% 96%
Average number of rigs in use 33.0 56.8 72%
Average dayrate on daywork
contracts $ 8,055 $ 7,476 (7%)
Operating profit
(revenue less operating costs) $ 13,286,000 $ 18,335,000 38%
Operating margin 25% 23%
Depreciation $ 5,739,000 $ 10,793,000 88%
General and Administrative Expense $ 4,042,000 $ 4,520,000 12%
Interest Expense $ 516,000 $ 386,000 (25%)
Average Interest Rate 3.00% 2.13% (29%)
Average Long-Term Debt Outstanding $ 26,075,000 $ 27,266,000 5%
38
Oil and natural gas revenues, operating profits and operating profit
margins were all positively affected by higher prices received for both oil and
natural gas between the first six months of 2003 and the first six months of
2002. We continue to focus our drilling program on the development of natural
gas reserves and we experienced an increase in both our oil and natural gas
production volumes between the comparative six month periods. Total operating
cost increased in the first six months of 2003 when compared with the first six
months of 2002 due mainly to higher gross production taxes which are based on a
percentage of revenues which were generated by higher commodity prices and to a
lesser extent from increased costs associated with adding personnel to support
the growth in this segment of our business. Our total depreciation, depletion
and amortization ("DD&A) increased due to the increase in equivalent volumes
produced and an increase in our DD&A rate per Mcfe. During 2002 and into the
first six months of 2003, we experienced higher cost per Mcfe for the discovery
of new reserves through our development drilling program resulting in an
increase in the DD&A rate between the comparative six month periods.
Reduced natural gas prices in the fourth quarter of 2001 and the first half
of 2002, caused decreases in operator demand for contract drilling rigs within
our working area throughout most of 2002. Demand recovered in the first half of
2003 and the average number of rigs in use was 24 more than during the first six
months of 2002. We also had more rigs available due to the 20 rig acquisition we
completed in August of 2002. Since utilization typically increases before
dayrates our dayrates did not start to improve until the second quarter of 2003,
so the average dayrate for the first six months of 2003 was lower than the
average dayrate received for the same period in 2002. As a result, operating
margins declined between the comparative periods. Approximately four percent of
our total drilling revenues in the first six months of 2003 came from footage
and turnkey contracts, which had profit margins lower than our daywork
contracts. Nine percent of our total drilling revenues came from footage and
turnkey contracts in the first six months of 2002. Contract drilling
depreciation increased due to the acquisition of 20 rigs in August of 2002 and
the increase in rigs used between the comparative quarters.
General and administrative expense was higher in the first six months of
2003 due to increases in insurance expense. Our total interest expense is lower
due to lower interest rates and was partially offset by an increase in average
debt outstanding. Income tax expense increased primarily due to the increase in
income from continuing operations.
39
Item 3. Quantitative and Qualitative Disclosures about Market Risk
- ------- ----------------------------------------------------------
Our operations are exposed to market risks due to changes in commodity
prices. The price we receive is primarily driven by the prevailing worldwide
price for crude oil and market prices applicable to our natural gas production.
Historically, the prices we have received for our oil and natural gas production
have been volatile and such volatility is expected to continue.
In an effort to try and reduce the impact of price fluctuations, over the
past several years we periodically have used hedging strategies to hedge the
price we will receive for a portion of our future oil and natural gas
production. A detailed explanation of those transactions has been included under
hedging in the financial condition portion of management's discussion and
analysis of financial condition and results of operations included above under
Item 2.
Item 4. Controls and Procedures
- --------------------------------
Within the 90 days prior to the date of this report, we carried out an
evaluation, under the supervision and with the participation of our management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Exchange Act Rule 13a-14. Based on that evaluation, our
Chief Executive Officer and Chief Financial Officer concluded that the company's
disclosure controls and procedures are effective in timely alerting them to
material information required to be included in our periodic SEC filings
relating to the company (including its consolidated subsidiaries).
There were no significant changes in the company's internal controls or in
other factors that could significantly affect these internal controls subsequent
to the date of our most recent evaluation.
40
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
- --------------------------
Not applicable
Item 2. Changes in Securities and Use of Proceeds
- --------------------------------------------------
Not applicable
Item 3. Defaults Upon Senior Securities
- ----------------------------------------
Not applicable
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
On May 7, 2003 we held our Annual Meeting of Stockholders. At the
meeting the following matters were voted on, with each receiving
the votes indicated:
I. Election of Nominees John G. Nikkel and John S. Zink
to serve as directors.
Numbers of Against or
Nominee Votes For Withheld
---------------------- ------------ ------------
John G. Nikkel 39,352,332 186,334
John S. Zink 39,338,361 200,305
The following directors, whose term of office did not expire
at the annual meeting, continue as directors of the Company:
Earle Lamborn, William B. Morgan, John H. Williams, King P.
Kirchner, Don Cook and J. Michael Adcock.
II. Ratification of the appointment of PricewaterhouseCoopers
L L P as the Company's independent certified public
accountants for the fiscal year 2003.
For - 38,930,857
Against - 592,482
Abstain - 15,327
41
Item 5. Other Information
- --------------------------
In accordance with Section 10A(i)(2) of the Securities Exchange Act of
1934, as added by Section 202 of the Sarbanes-Oxley Act of 2002, we are
responsible for disclosing any non-audit services approved by our Audit
Committee (the "Committee") to be performed by PricewaterhouseCoopers
LLP, who is our external auditor. Non-audit services are defined in the
Act as services other than those provided in connection with an audit or
a review of the financial statements of Unit. The Committee has approved
the engagement of PricewaterhouseCoopers LLP to provide non-audit
services assisting in (i) reviewing our internal control procedures,
(ii)our pending acquisition of PetroCorp Incorporated and (iii)
responding to the SEC's comments in connection with the SEC's review of
the recent S-3 Registration Statement we filed on March 31, 2003.
Item 6. Exhibits and Reports on Form 8-K
- -----------------------------------------
(a) Exhibits:
15 Letter re: Unaudited Interim Financial Information.
31.1 SEC Certification Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 by the Principal Executive
Officer, John G. Nikkel of Unit Corporation.
31.2 SEC Certification Pursuant to Section 906 of the
Sarbanex-Oxley Act of 2002 by the Principal Financial
Officer, Larry D. Pinkston, of Unit Corporation.
32 Certification Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.
(b) On April 23, 2003, we filed a report on Form 8-K under Item 7 and 9.
This report furnished as an exhibit the press release announcing our
results of operations and financial condition for the quarter ended
March 31, 2003.
On July 1, 2003, we filed a report on Form 8-K under Item 5 and 7.
This report announced that we had entered into a letter of intent to
acquire PetroCorp Incorporated ("PetroCorp") (AMEX:PEX) and
furnished as an exhibit the press release of the announcement.
42
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
UNIT CORPORATION
Date: August 14, 2003 By: /s/ John G. Nikkel
--------------------------- ------------------------------
JOHN G. NIKKEL
Chairman of the Board,
Chief Executive Officer,
Chief Operating Officer
and Director
Date: August 14, 2003 By: /s/ Larry D. Pinkston
--------------------------- ------------------------------
LARRY D. PINKSTON
President, Chief
Financial Officer
and Treasurer
43