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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 September 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 by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).
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 43,575,245
------------------------------ ------------
Class Outstanding at November 4, 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 September 30, 2003 . . . . . . . 2
Consolidated Condensed Statements of Income
Three and Nine Months Ended September 30,
2002 and 2003. . . . . . . . . . . . . . . . . . . . . 4
Consolidated Condensed Statements of Cash Flows
Nine Months Ended September 30, 2002 and 2003. . . . . 6
Consolidated Condensed Statements of Comprehensive
Income Three and Nine Months Ended
September 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 . . . . . . . . . . . . . . . . . . . . . . 39
Item 4. Controls and Procedures . . . . . . . . . . . . . . . . 39
PART II. Other Information
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . 40
Item 2. Changes in Securities and Use of Proceeds . . . . . . . 40
Item 3. Defaults Upon Senior Securities. . . . . . . . . . . . 40
Item 4. Submission of Matters to a Vote of Security Holders . . 40
Item 5. Other Information . . . . . . . . . . . . . . . . . . . 40
Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . 41
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 42
1
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
- ------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS (UNAUDITED)
December 31, September 30,
2002 2003
----------- -----------
(In thousands)
ASSETS
------
Current Assets:
Cash and cash equivalents $ 497 $ 1,765
Accounts receivable 33,912 52,734
Materials and supplies 8,794 8,510
Income tax receivable 3,602 107
Other 4,594 4,840
----------- -----------
Total current assets 51,399 67,956
----------- -----------
Property and Equipment:
Drilling equipment 369,777 383,732
Oil and natural gas properties, on the
full cost method:
Proved properties 449,226 503,510
Undeveloped leasehold not being
amortized 16,024 19,845
Transportation equipment 6,856 7,532
Other 9,906 12,653
----------- -----------
851,789 927,272
Less accumulated depreciation, depletion,
amortization and impairment 341,031 370,709
----------- -----------
Net property and equipment 510,758 556,563
----------- -----------
Goodwill 12,794 12,794
Other Assets 3,212 6,955
----------- -----------
Total Assets $ 578,163 $ 644,268
=========== ===========
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, September 30,
2002 2003
----------- -----------
(In thousands)
LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------
Current Liabilities:
Current portion of long-term
liabilities and debt $ 1,465 $ 741
Accounts payable 21,119 25,346
Accrued liabilities 11,948 14,795
----------- -----------
Total current liabilities 34,532 40,882
----------- -----------
Long-Term Debt 30,500 15,000
----------- -----------
Other Long-Term Liabilities 5,439 17,609
----------- -----------
Deferred Income Taxes 86,320 109,436
----------- -----------
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 43,569,227 shares
issued, respectively 8,668 8,714
Capital in excess of par value 264,180 265,666
Retained earnings 148,524 186,961
----------- -----------
Total shareholders' equity 421,372 461,341
----------- -----------
Total Liabilities and Shareholders' Equity $ 578,163 $ 644,268
=========== ===========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
3
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- --------------------
2002 2003 2002 2003
--------- --------- --------- ---------
(In thousands)
Revenues:
Contract drilling $ 31,589 $ 50,052 $ 84,144 $129,839
Oil and natural gas 16,357 27,402 46,986 87,521
Other 326 747 625 2,267
--------- --------- --------- ---------
Total revenues 48,272 78,201 131,755 219,627
--------- --------- --------- ---------
Expenses:
Contract drilling:
Operating costs 24,350 35,653 63,619 97,105
Depreciation
and amortization 4,178 6,318 9,917 17,111
Oil and natural gas:
Operating costs 5,169 6,260 15,278 18,768
Depreciation,
depletion and
amortization 6,142 6,972 17,399 19,464
General and
administrative 2,180 2,246 6,222 6,766
Interest 231 154 747 540
--------- --------- --------- ---------
Total expenses 42,250 57,603 113,182 159,754
--------- --------- --------- ---------
Income Before Income
Taxes and Change in
Accounting Principle 6,022 20,598 18,573 59,873
--------- --------- --------- ---------
Income Tax Expense:
Current (285) 157 75 456
Deferred 2,599 7,678 7,040 22,304
--------- --------- --------- ---------
Total income
taxes 2,314 7,835 7,115 22,760
--------- --------- --------- ---------
Income Before Change in
Accounting Principle 3,708 12,763 11,458 37,113
Cumulative Effect of
Change in Accounting
Principle (Net of Income
Tax of $811) - - - 1,325
--------- --------- --------- ---------
Net Income $ 3,708 $ 12,763 $ 11,458 $ 38,438
========= ========= ========= =========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
4
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME - CONTINUED
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- --------------------
2002 2003 2002 2003
--------- --------- --------- ---------
(In thousands except per share amounts)
Basic Earnings Per Common
Share:
Income before change
in accounting
principle $ 0.09 $ 0.29 $ 0.31 $ 0.85
Cumulative effect of
change in accounting
principle net of
income tax - - - 0.03
--------- --------- --------- ---------
Net Income $ 0.09 $ 0.29 $ 0.31 $ 0.88
========= ========= ========= =========
Diluted Earnings Per
Common Share:
Income before change
in accounting
principle $ 0.09 $ 0.29 $ 0.30 $ 0.85
Cumulative effect of
change in accounting
principle net of
income tax - - - 0.03
--------- --------- --------- ---------
Net Income $ 0.09 $ 0.29 $ 0.30 $ 0.88
========= ========= ========= =========
Pro Forma Amounts Assuming
Retroactive Application
of Change in Accounting
Principle:
Net income $ 3,678 $ 11,371
========= =========
Basic earnings per
share $ 0.09 $ 0.30
========= =========
Diluted earnings per
share $ 0.09 $ 0.30
========= =========
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)
Nine Months Ended
September 30,
-------------------------
2002 2003
---------- ----------
(In thousands)
Cash Flows From Operating Activities:
Net income $ 11,458 $ 38,438
Adjustments to reconcile net income
to net cash provided (used) by
operating activities:
Depreciation, depletion,
and amortization 27,789 37,135
Deferred tax expense 7,040 22,304
Other 373 237
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable 1,347 (19,417)
Accounts payable 6,548 3,098
Material and supplies inventory (4,259) 284
Prepaid expenses 1,470 3,056
Contract advances (163) 1,228
Other - net 2,671 2,049
---------- ----------
Net cash provided by
operating activities 54,274 88,412
---------- ----------
Cash Flows From (Used In) Investing
Activities:
Capital expenditures (48,825) (65,780)
Proceeds from disposition of assets 1,630 960
Other-net 523 (2,555)
---------- ----------
Net cash used in
investing activities (46,672) (67,375)
---------- ----------
Cash Flows From (Used In) Financing
Activities:
Net borrowings (payments) under
line of credit (6,500) (15,500)
Net payments of notes payable
and other long-term debt (22) (1,074)
Proceeds from exercise of stock options 213 452
Book overdrafts (1,104) (3,647)
---------- ----------
Net cash used in financing
activities (7,413) (19,769)
---------- ----------
Net Increase in Cash and
Cash Equivalents 189 1,268
Cash and Cash Equivalents, Beginning
of Year 391 497
---------- ----------
Cash and Cash Equivalents, End of
Period $ 580 $ 1,765
========== ==========
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 Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2002 2003 2002 2003
---------- ---------- ---------- ----------
(In thousands)
Net Income $ 3,708 $ 12,763 $ 11,458 $ 38,438
Other Comprehensive Income,
Net of Taxes:
Change in value of cash
flow derivative
instruments used as
cash flow hedges - 74 - (4)
Reclassification
of derivative
settlements - - - 4
---------- ---------- ---------- ----------
Comprehensive Income $ 3,708 $ 12,837 $ 11,458 $ 38,438
========== ========== ========== ==========
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
(company) and have been prepared under 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 nine months ended September 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. Under Rule 436(c) of 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 them.
Because the company does not bear the risk of completion of wells drilled
under daywork drilling contracts, it recognizes revenues and expenses 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 detailed in the contracts. If it is determined
that a well is going to incur a loss, the entire amount of the estimated loss is
recorded when the loss can be 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.
The company'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 the company's matching 401(k) contribution. The following table
illustrates the effect on net income and earnings per share if the company had
applied the fair
8
value recognition provisions of Financial Accounting Standards
Board Statement No. 123, "Accounting for Stock-Based Compensation," to
stock-based employee compensation.
Three Months Ended Nine Months Ended
-------------------- --------------------
2002 2003 2002 2003
--------- --------- --------- ---------
(In thousands except per share amounts)
Net Income, as Reported $ 3,708 $ 12,763 $ 11,458 $ 38,438
Add Stock-Based Employee
Compensation Expense
Included in Reported
Net Income - Net of Tax 160 238 480 573
Less Total Stock-Based
Employee Compensation
Expense Determined Under
Fair Value Based Method
For All Awards (370) (578) (969) (1,453)
--------- --------- --------- ---------
Pro Forma Net Income $ 3,498 $ 12,423 $ 10,969 $ 37,558
========= ========= ========= =========
Basic Earnings per Share:
As reported $ 0.09 $ 0.29 $ 0.31 $ 0.88
========= ========= ========= =========
Pro forma $ 0.09 $ 0.29 $ 0.29 $ 0.86
========= ========= ========= =========
Diluted Earnings per Share:
As reported $ 0.09 $ 0.29 $ 0.30 $ 0.88
========= ========= ========= =========
Pro forma $ 0.09 $ 0.28 $ 0.29 $ 0.86
========= ========= ========= =========
The fair value of each option is estimated using the Black-Scholes model.
In the third quarter of 2003, options were granted for 5,000 shares and for each
of the nine month periods ended September 30, 2002 and 2003 options were granted
for 26,000 shares. No options were granted in the third quarter of 2002. The
options granted in the third quarter of 2003 have a fair value of approximately
$67,000. The total options granted during the nine month periods ended September
30, 2002 and 2003 have fair values of approximately $320,000 and $329,000,
respectively. For options granted in fiscal 2002 and 2003, the company's
estimate of stock volatility was 0.53, based on previous stock performance.
Dividend yield
9
was estimated to remain at zero with a risk free interest rate of
4.24 percent in 2002 and interest rates ranging from 3.60 to 4.72 percent in
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 company 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, the company has not experienced any substantial environmental
liability. All liabilities incurred to date have been small and have been
resolved in a timely manner.
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
----------- ------------- ----------
(In thousands except)
per share amounts)
For the Three Months Ended
September 30, 2002:
Basic earnings per common share $ 3,708 39,804 $ 0.09
==========
Effect of dilutive stock options - 267
----------- -------------
Diluted earnings per common share $ 3,708 40,071 $ 0.09
=========== ============= ==========
For the Three Months Ended
September 30, 2003:
Basic earnings per common share $ 12,763 43,556 $ 0.29
==========
Effect of dilutive stock options - 180
----------- -------------
Diluted earnings per common share $ 12,763 43,736 $ 0.29
=========== ============= ==========
The following options and their average exercise prices were not included
in the computation of diluted earnings per share for the three months ended
September 30, 2002 and September 30, 2003 because the option exercise prices
were greater than the average market price of common shares:
2002 2003
---------- ----------
Options 179,000 5,000
========== ==========
Average exercise price $ 17.23 $ 21.50
========== ==========
11
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ----------
(In thousands except)
per share amounts)
For the Nine Months Ended
September 30, 2002:
Basic earnings per common share $ 11,458 37,330 $ 0.31
==========
Effect of dilutive stock options - 264
----------- -------------
Diluted earnings per common share $ 11,458 37,594 $ 0.30
=========== ============= ==========
For the Nine Months Ended
September 30, 2003:
Basic earnings per common share:
Income before change in
accounting principle $ 37,113 43,503 $ 0.85
Cumulative effect of change
in accounting principle
net of income tax 1,325 43,503 0.03
----------- ----------
Net Income $ 38,438 43,503 $ 0.88
=========== ==========
Diluted earnings per common share:
Weighted average number of
common shares used in basic
earnings per common share 43,503
Effect of dilutive stock
options 174
-------------
Weighted average number of
common shares and dilutive
potential common shares used
in diluted earnings
per share 43,677
=============
Income before change in
accounting principle $ 37,113 43,677 $ 0.85
Cumulative effect of change
in accounting principle
net of income tax 1,325 43,677 0.03
----------- ----------
Net Income $ 38,438 43,677 $ 0.88
=========== ==========
12
The following options and their average exercise prices were not included
in the computation of diluted earnings per share for the nine months ended
September 30, 2002 and 2003 because the option exercise prices were greater than
the average market price of common shares:
2002 2003
---------- ----------
Options 179,000 26,000
========== ==========
Average exercise price $ 17.23 $ 20.37
========== ==========
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. The company 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 declined to a level below
the carrying value. FAS 142 became effective for the fiscal years starting after
December 15, 2001 (January 1, 2002 for the company). 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 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 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.
14
The following table shows the activity for the nine months ending September
30, 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 8 369
Liability Incurred in the Period - 529
Liability Settled in the Period - (106)
Reclassification of Liability
From Long- to Short-Term 181 (181)
------------- -------------
Plugging Liability 9/30/03 $ 392 $ 11,243
============= =============
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 three and nine month
periods ended September 30, 2003 by $36,000 ($0.00 per share) and $111,000
($0.00 per share), respectively. The financial statements for the three and nine
months ended September 30, 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.
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:
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, $8.7, $9.7 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.
16
On January 1, 2003, the company 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 the
company's financial position, results of operations or cash flows.
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 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 nine months of 2003, the company 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). The Statement is effective for contracts entered into or
modified after June 30, 2003 for hedging contracts like the company's. 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". The company does not expect the application of SFAS 149 to have a
material effect on its financial position, results of operations or cash flows.
During 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 became effective for the company
starting in the quarter ended September 30, 2003. The company's financial
position, results of operations or cash flows were not materially effected by
the application of SFAS 150.
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
17
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 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 is effective for periods ending after December 15, 2003 (December 31,
2003 for the company). The company is currently evaluating the impact of FIN 46
on its financial position and results of operations.
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 the FASB in
June 2001 and became effective for the company 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 company's financial statements would include the disclosures
required by FAS 141 and 142 regarding intangibles. To date, the company, 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.
The company'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 September 30, 2003, the company had undeveloped leaseholds of
approximately $16.6 million that would be classified on our balance sheet as
"intangible undeveloped leasehold" and developed leaseholds of an estimated
$21.3 million that would be classified as "intangible developed leasehold" if
the interpretations were applied. This classification would require the company
to make the disclosures set forth under FAS 142 related to these interests.
The company intends to continue to classify our oil and gas mineral
extraction rights as tangible oil and gas properties until further guidance is
provided.
18
NOTE 5 - HEDGING ACTIVITY
- -------------------------
Periodically the company 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, the company entered into two natural gas
collar contracts for approximately 37 percent of its April through September
2003 production. One contract had a floor price of $4.00 and a ceiling price of
$5.75. The other contract had a floor price of $4.50 and a ceiling price of
$6.02. During the first quarter of 2003, the company also entered into two oil
collar contracts for approximately 26 percent of its May through December 2003
oil production. One contract has a floor price of $25.00 and a ceiling price of
$32.20. The other contract has a floor price of $26.00 and a ceiling price of
$31.40. The company had a $6,000 reduction in natural gas revenues because of
the natural gas hedges settled in the second quarter of 2003 and a $1,000
reduction in oil revenues because of the oil hedges settled in the third quarter
of 2003. Since the amount was immaterial, no fair value was recognized on the
September 2003 balance sheet or in accumulated other comprehensive income for
the oil collar contracts which remained outstanding at the end of the period.
These hedges were fully effective. The company did not have any hedging
contracts in place in the first nine months of 2002.
NOTE 6 - INDUSTRY SEGMENT INFORMATION
- -------------------------------------
The company has two business segments: Contract Drilling (Unit Drilling
Company), and Oil and Natural Gas (Unit Petroleum Company), 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 nine month periods ended September 30, 2002
and 2003 is as follows:
19
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2002 2003 2002 2003
---------- ---------- ---------- ----------
(In thousands)
Revenues:
Contract drilling $ 31,589 $ 50,052 $ 84,144 $ 129,839
Oil and natural gas 16,357 27,402 46,986 87,521
Other 326 747 625 2,267
---------- ---------- ---------- ----------
$ 48,272 $ 78,201 $ 131,755 $ 219,627
========== ========== ========== ==========
Operating Income (1):
Contract drilling $ 3,061 $ 8,081 $ 10,608 $ 15,623
Oil and natural gas 5,046 14,170 14,309 49,289
---------- ---------- ---------- ----------
Total operating
income 8,107 22,251 24,917 64,912
General and
administrative
expense (2,180) (2,246) (6,222) (6,766)
Interest expense (231) (154) (747) (540)
Other income - net 326 747 625 2,267
---------- ---------- ---------- ----------
Income before
income taxes
and change in
accounting
principle $ 6,022 $ 20,598 $ 18,573 $ 59,873
========== ========== ========== ==========
(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 $1.3 million, net of $811,000 in income tax, is all
related to the oil and natural gas segment.
20
NOTE 7 - ACQUISITIONS
- ---------------------
On August 14, 2003 the company 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 $182.1 million and will
be paid in cash. The purchase price is subject to certain adjustments including
up to $6.5 million which may be placed 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.
On August 15, 2002, the company completed the acquisition of CREC Rig
Equipment Company and CDC Drilling Company. Both of these acquisitions were
stock purchase transactions. The company 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.
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 September 30, 2003, and the related
consolidated condensed statements of income and comprehensive income for each of
the three and nine month periods ended September 30, 2003 and 2002 and the
statement of cash flows for the nine month periods ended September 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, shareholder'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
October 22, 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 September 30, 2003,
we had cash totaling $1.8 million and we had borrowed $15.0 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 September
30, 2002 and 2003 and for the nine months ended September 30, 2002 and 2003:
September 30, September 30, Percent
2002 2003 Change
-------------- -------------- -------
(In thousands except percent amounts)
Income Before Change in
Accounting Principle $ 11,458 $ 37,113 224%
Net Income $ 11,458 $ 38,438 235%
Net Cash Provided by
Operating Activities $ 54,274 $ 88,412 63%
Net Cash Used in Investing
Activities $ 46,672 $ 67,375 44%
Net Cash Used in Financing
Activities $ 7,413 $ 19,769 167%
Working Capital $ 16,093 $ 27,074 68%
Long-Term Debt $ 24,500 $ 15,000 (39%)
Shareholders' Equity $ 414,386 $ 461,341 11%
Ratio of Long-Term debt to
Total Capitalization 6% 3%
The following table summarizes certain operating information for the first
nine months of 2002 and 2003:
Percent
2002 2003 Change
---------- ---------- --------
Oil Production (MBbls) 347 372 7%
Natural Gas Production (MMcf) 14,360 15,043 5%
Average Oil Price Received $ 20.92 $ 27.02 29%
Average Natural Gas Price
Received $ 2.59 $ 5.05 95%
Average Number of Our
Drilling Rigs in Use
During the Period 36.2 60.6 67%
Total Number of Our Drilling
Rigs Available at the End
of the Period 75 75 -
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 allow us to have
access to the full $100 million, we elected to set the loan commitment at $40
million. We did this 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 October 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
$15.0 million at September 30, 2003 and on October 22, 2003 our third quarter
earnings release date.
Borrowings under the revolving credit facility bear interest at the JP
Morgan Chase 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 2.16 percent at September 30, 2003
and October 22, 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 $15.0 million at
September 30, 2003 and October 22, 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
24
. working capital provided by operations, as defined in the loan
agreement, cannot be less than $40 million in any year.
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.
We are negotiating with our lead bank under our current loan agreement to
establish a new loan agreement. The new agreement would replace our current
agreement and we anticipate the new agreement would provide for a maximum loan
commitment of $150,000,000. Currently, we anticipate that the effective date for
the new loan agreement would be contingent on the closing of our pending
acquisition of PetroCorp which is discussed above.
Contractual Commitments. We have the following contractual obligations at
September 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) $ 15,000 $ - $ 6,667 $ 8,333 $ -
Retirement
Agreement(2) 1,392 300 600 492 -
Operating
Leases(3) 3,811 728 1,441 1,062 580
--------- -------- -------- --------- --------
Total
Contractual
Obligations $ 20,203 $ 1,028 $ 8,708 $ 9,887 $ 580
========= ======== ======== ========= ========
-------------------
(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.
25
(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.
At September 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) $ 1,685 Unknown Unknown Unknown Unknown
Separation
Benefit
Agreement(2) $ 2,617 $ 49 Unknown Unknown Unknown
Plugging
Liability(3) $ 11,635 $ 392 $ 2,049 $ 644 $ 8,550
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
26
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 by
this plan. The accrued liability for the separation benefit plans is
determined by an actuary consultant hired by us.
(3) 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 (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 are 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 total
repurchases of $18,000 during the second and third quarters 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 through September 2003
production. One contract had a floor price of $4.00 and a ceiling price of
$5.75. The other contract had 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 through December 2003 oil
production. One contract has a floor price of $25.00 and a ceiling price of
$32.20. The other contract has a floor price
27
of $26.00 and a ceiling price of $31.40. We had a $6,000 reduction in natural
gas revenues because of the natural gas hedges settled in the second quarter of
2003 and a $1,000 reduction in oil revenues because of the oil hedges settled in
the third quarter of 2003. Since the amount was immaterial, no fair value was
recognized on the September 2003 balance sheet or in accumulated other
comprehensive income for the oil collar contracts which remained outstanding at
the end of the period. These hedges were fully effective. We did not have any
hedging contracts in place in the first nine months of 2002.
Self-Insurance. We are self-insured for certain losses relating to workers'
compensation, general liability, property damage and employee medical benefits.
Due to increases in premium prices in the insurance market, by our election, 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 effect on our revenues, cash flow and the value of our oil and
natural gas reserves.
Based on our 2003 first nine month production, a $.10 per Mcf change in the
price we are paid for our natural gas production would result in a corresponding
$156,000 per month ($1.9 million annualized) change in our pre-tax cash flow.
Our first nine month 2003 average natural gas price was $5.05 compared to an
average natural gas price of $2.59 received in the first nine 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 $38,000 per
month ($456,000 annualized) change in our pre-tax cash flow. Our first nine
months 2003 average oil price was $27.02 compared with an average oil price of
$20.92 received in the first nine months of 2002.
Because natural gas prices have such a significant effect on the value of
our oil and natural gas reserves, declines in those prices can result in a
decline in the carrying value of our oil and natural gas properties. Also, price
declines can adversely effect 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 give us a large degree of flexibility in deciding when to incur
these costs. We drilled 98 wells in the first
28
nine months of 2003 compared to 62 wells in the first nine months of 2002.
Through the first nine months of 2003 we incurred $51.1 million of the $70 to
$75 million in capital expenditures we expect to make for exploration and
development drilling 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.
Contract Drilling. There are many things that influence the number of rigs
we are able to work, as well as, the costs and revenues associated with that
work. These things 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 needed equipment. We have not encountered
major difficulty in hiring and keeping rig crews, but shortages have occurred
periodically in the past. If demand for drilling rigs continues to increase, we
would incur shortages of experienced personnel which would limit our ability to
increase our operating rigs. Through the first nine months of 2003 we incurred
$16.8 million in capital expenditures for our drilling operation. For the year
2003, we anticipate spending approximately $25 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 nine months of 2002 was 36.2 rigs compared with 60.6 rigs for the
first nine 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
nine months of 2002 was $7,847 and our average dayrate for the first nine months
of 2003 was $7,684. Increases in dayrates typically lag behind increases in
utilization. We saw dayrates start to improve in the second quarter of 2003 and
they continued a gradual increase in the third quarter of 2003. We anticipate
dayrates to remain fairly constant in the fourth quarter of 2003. Based on the
average utilization of our rigs in the first nine months of 2003, a $100 per day
change in dayrates has a $6,100 per day ($2.2 million 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
29
drilling segment of $677,000 and $1,411,000 in the first nine 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.
Oil and Natural Gas Limited Partnerships and Other Entity Relationships. We
are the general partner of nine privately and publicly held oil and natural gas
partnerships. 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 nine months of 2003 the amount paid has been 4
percent below last year's 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 certain employees
whose annual base compensation meet a specified amount ($22,680 for 2002 and
2003) and to our directors. The general partner of each partnership is Unit
Petroleum Company. Each employee partnership is named the Unit (year) Employee
Oil and Gas Limited Partnership. The interests issued in these programs to our
directors and executive officers are disclosed in our proxy statements for each
year's annual meeting of shareholders.
At September 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 $2.7
million at September 30, 2003. From time to time we may guarantee a portion of
the debt of this company. However, as of September 30, 2003 and October 22,
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. In the
third quarter an additional partner was added to the partnership reducing our
interest in Eagle to 16.668 percent. 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 at competitive prices during the six month
period starting
30
August 1, 2003. For October 2003, Eagle will buy approximately 45% of the
natural gas we sell on a monthly basis for ourselves and other working interest
owners.
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 nine 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 $4.39 to $6.70. On
our third quarter earnings release date of October 22, 2003, the Nymex Henry Hub
average contract settle price for the next twelve months was $4.93 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
shareholders' 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 September 30, 2003
($4.44 per Mcf for natural gas and $28.17 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.
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 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
31
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. Reserve estimates effect many areas of accounting for oil and natural
gas operations including the carrying value and depreciation, depletion and
amortization of our oil and gas properties.
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 improvements 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 for
these contracts as the services are performed (i.e. daily). Under "footage" and
"turnkey" contracts, revenues and expenses are recognized when we have satisfied
certain contractual requirements. If it is determined that a well is going to
incur a loss, the entire amount of the estimated loss is recorded when the loss
is determined, however, any profit is recorded only at the time the terms of the
contract are satisfied. 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 held under
lease and other contractual arrangements representing the right to extract such
reserves
32
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 September 30, 2003, we had undeveloped leaseholds of approximately $16.6
million that would be classified on our balance sheet as "intangible undeveloped
leasehold" and developed leaseholds of an estimated $21.3 million that would be
classified as "intangible developed leasehold" if we applied the
interpretations. This classification would require us to make 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 we 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 $182.1
million and will be paid in cash. The purchase price is subject to certain
adjustments including up to $6.5 million which will be placed 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. We announced on October 27, 2003 that our
Board of Directors elected Mr. Mark E. Monroe to the Company's Board of
Directors. Mr. Monroe recently served as the President, Chief Executive Officer
and a director of Louis Dreyfus Natural Gas Corp until that company was sold in
2001. He currently serves as a member of the Board of Directors for Continental
Resources, Inc. He has served as President of the Oklahoma Independent Petroleum
Association, on the Board of the Independent Petroleum Association of America,
and as a member of the Domestic Petroleum Council and the National Petroleum
Council. Mr. Monroe holds a Bachelor's degree in Business Administration from
the University of Texas and is a Certified Public Accountant.
33
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;
. 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.
34
RESULTS OF OPERATIONS
- ---------------------
Third Quarter 2003 versus Third Quarter 2002
- --------------------------------------------
Provided below is a comparison of selected operating and financial data for
the third quarter of 2003 versus the third quarter of 2002:
Third Third Percent
Quarter 2002 Quarter 2003 Change
--------------- --------------- ---------
Total Revenue $ 48,272,000 $ 78,201,000 62%
Net Income $ 3,708,000 $ 12,763,000 244%
Oil and Natural Gas:
Revenue $ 16,357,000 $ 27,402,000 68%
Average natural gas price (Mcf) $ 2.71 $ 4.50 66%
Average oil price (Bbl) $ 22.99 $ 25.51 11%
Natural gas production (Mcf) 4,707,000 5,233,000 11%
Oil production (Bbl) 120,000 134,000 12%
Operating profit
(revenue less operating costs) $ 11,188,000 21,142,000 89%
Operating margin 68% 77%
Depreciation, depletion and
amortization rate (Mcfe) $ 1.06 $ 1.15 8%
Depreciation, depletion and
amortization $ 6,142,000 $ 6,972,000 14%
Drilling:
Revenue $ 31,589,000 $ 50,052,000 58%
Percentage of revenue from
daywork contracts 92% 99%
Average number of rigs in use 42.5 68.2 60%
Average dayrate on daywork
contracts $ 7,529 $ 8,015 6%
Operating profit
(revenue less operating costs) $ 7,239,000 $ 14,399,000 99%
Operating margin 23% 29%
Depreciation $ 4,178,000 $ 6,318,000 51%
General and Administrative Expense $ 2,180,000 $ 2,246,000 3%
Interest Expense $ 231,000 $ 154,000 (33%)
Average Interest Rate 3.1% 2.3% (74%)
Average Long-Term Debt Outstanding $ 22,610,000 $ 16,763,000 (26%)
35
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 and natural gas production between the third quarter of 2003 and
the third quarter of 2002. We continue to focus our drilling program on the
development of natural gas reserves. Total operating cost increased in the third
quarter of 2003 when compared with the third quarter of 2002 due mainly to
higher gross production taxes and, to a lesser extent, from 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 an increase
in our DD&A rate per Mcfe and increased production volumes. During 2002 and
continuing into the first nine 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 quarters.
Reduced natural gas prices in the fourth quarter of 2001 and the first half
of 2002, reduced the demand for our contract drilling rigs throughout most of
2002. Along with our acquisition of 20 rigs in the third quarter of 2002,
natural gas prices increased once again into the first quarter of 2003. Our
second and third quarter 2003 utilization increased and the third quarter rig
use was 60 percent higher than the third quarter of 2002. In the second and
third quarter of 2003 dayrates for our rigs also increased from our first
quarter lows and were six percent higher in the third quarter of 2003 than in
the third quarter of 2002. Operating margins increased between the comparative
periods, since we had higher rig utilization and dayrates to cover our fixed
operating costs. Approximately one percent of our third quarter 2003 drilling
revenues 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 third quarter of 2003
because of increases in our 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 pre-tax income.
36
Nine Months 2003 versus Nine Months 2002
- ----------------------------------------
Provided below is a comparison of selected operating and financial data for
the first nine months of 2003 versus the first nine months of 2002:
First Nine First Nine Percent
Months 2002 Months 2003 Change
--------------- --------------- ---------
Total Revenue $ 131,755,000 $ 219,627,000 67%
Income Before Change in Accounting
Principle $ 11,458,000 $ 37,113,000 224%
Net Income $ 11,458,000 $ 38,438,000 235%
Oil and Natural Gas:
Revenue $ 46,986,000 $ 87,521,000 86%
Average natural gas price (Mcf) $ 2.59 $ 5.05 95%
Average oil price (Bbl) $ 20.92 $ 27.02 29%
Natural gas production (Mcf) 14,360,000 15,043,000 5%
Oil production (Bbl) 347,000 372,000 7%
Operating profit
(revenue less operating costs) $ 31,708,000 $ 68,753,000 117%
Operating margin 67% 79%
Depreciation, depletion and
amortization rate (Mcfe) $ 1.03 $ 1.12 9%
Depreciation, depletion and
amortization $ 17,399,000 $ 19,464,000 12%
Drilling:
Revenue $ 84,144,000 $ 129,839,000 54%
Percentage of revenue from
daywork contracts 91% 97%
Average number of rigs in use 36.2 60.6 67%
Average dayrate on daywork
contracts $ 7,847 $ 7,684 (2%)
Operating profit
(revenue less operating costs) $ 20,525,000 $ 32,734,000 59%
Operating margin 24% 25%
Depreciation $ 9,917,000 $ 17,111,000 73%
General and Administrative Expense $ 6,222,000 $ 6,766,000 9%
Interest Expense $ 747,000 $ 540,000 (28%)
Average Interest Rate 3.1% 2.2% (71%)
Average Long-Term Debt Outstanding $ 24,907,000 $ 23,727,000 (5%)
37
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 nine months of 2003 and the first nine 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 nine month periods. Total operating
cost increased in the first nine months of 2003 when compared with the first
nine months of 2002 due mainly to higher gross production taxes and, to a lesser
extent, from 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 nine 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 nine month periods.
Reduced natural gas prices in the fourth quarter of 2001 and the first half
of 2002, reduced the demand for our contract drilling rigs throughout most of
2002. Demand recovered in the nine months of 2003 and the average number of rigs
in use was 24 more than during the first nine 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 nine months of 2003 was lower than the average dayrate received for the
same period in 2002. Our operating margins was one percentage point higher than
the first nine months of 2002. Approximately 3 percent of our first nine month
2003 drilling revenues 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 nine 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 nine
month periods.
General and administrative expense was higher in the first nine months of
2003 because of increases in our insurance expense. Our total interest expense
is lower due to lower interest rates and average debt outstanding. Income tax
expense increased primarily due to the increase in pre-tax income.
38
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 the domestic prices established for natural gas.
Historically, the prices we have received for our oil and natural gas production
have been volatile and such volatility is expected to continue.
Over the past several years we have tried to reduce the impact of price
fluctuations, by using 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
- --------------------------------
As of the end of the period covered by 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.
39
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
- ------------------------------------------------------------
Not applicable
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.
40
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 302 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 302 of the Sarbanes-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 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.
On July 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
June 30, 2003.
41
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: November 6, 2003 By: /s/ John G. Nikkel
--------------------------- ------------------------------
JOHN G. NIKKEL
Chairman of the Board,
Chief Executive Officer,
Chief Operating Officer
and Director
Date: November 6, 2003 By: /s/ Larry D. Pinkston
--------------------------- ------------------------------
LARRY D. PINKSTON
President, Chief
Financial Officer
and Treasurer
42