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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 March 31, 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 43,519,617
---------------------------- ---------
Class Outstanding at May 1, 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 March 31, 2003. . . . . . . . . . 2
Consolidated Condensed Statements of Operations
Three Months Ended March 31, 2002 and 2003. . . . . . . 3
Consolidated Condensed Statements of Cash Flows
Three Months Ended March 31, 2002 and 2003. . . . . . . 5
Consolidated Condensed Statements of Comprehensive
Income Three Months Ended March 31, 2002 and 2003 . . . 6
Notes to Consolidated Condensed Financial Statements. . 7
Report of Review by Independent Accountants . . . . . . 14
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . 15
Item 3. Quantitative and Qualitative Disclosure about
Market Risk . . . . . . . . . . . . . . . . . . . . . . 28
Item 4. Controls and Procedures . . . . . . . . . . . . . . . . 28
PART II. Other Information
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . 29
Item 2. Changes in Securities and Use of Proceeds . . . . . . . 29
Item 3. Defaults Upon Senior Securities. . . . . . . . . . . . 29
Item 4. Submission of Matters to a Vote of Security Holders . . 29
Item 5. Other Information . . . . . . . . . . . . . . . . . . . 29
Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . 30
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Certifications . . . . . . . . . . . . . . . . . . . . . . . . . 32
1
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
- ------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS (UNAUDITED)
December 31, March 31,
2002 2003
----------- -----------
(In thousands)
ASSETS
------
Current Assets:
Cash and cash equivalents $ 497 $ 228
Accounts receivable 33,912 43,137
Materials and supplies 8,794 7,777
Income tax receivable 3,602 3,602
Other 4,594 4,656
----------- -----------
Total current assets 51,399 59,400
----------- -----------
Property and Equipment:
Total cost 851,789 874,293
Less accumulated depreciation, depletion,
amortization and impairment 341,031 344,932
----------- -----------
Net property and equipment 510,758 529,361
----------- -----------
Goodwill 12,794 12,794
Other Assets 3,212 3,388
----------- -----------
Total Assets $ 578,163 $ 604,943
=========== ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------
Current Liabilities:
Current portion of long-term
liabilities and debt $ 1,465 $ 737
Accounts payable 21,119 17,781
Accrued liabilities 11,948 12,311
----------- -----------
Total current liabilities 34,532 30,829
----------- -----------
Long-Term Debt 30,500 26,000
----------- -----------
Other Long-Term Liabilities 5,439 16,303
----------- -----------
Deferred Income Taxes 86,320 94,827
----------- -----------
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
43,516,617 shares issued, respectively 8,668 8,704
Capital in excess of par value 264,180 265,617
Accumulated other comprehensive income - 155
Retained earnings 148,524 162,508
----------- -----------
Total shareholders' equity 421,372 436,984
----------- -----------
Total Liabilities and Shareholders' Equity $ 578,163 $ 604,943
=========== ===========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
2
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)
Three Months Ended
March 31,
----------------------
2002 2003
--------- ---------
(In thousands except per
share amounts)
Revenues:
Contract drilling $ 26,714 $ 34,566
Oil and natural gas 11,961 33,248
Other 55 632
--------- ---------
Total revenues 38,730 68,446
--------- ---------
Expenses:
Contract drilling:
Operating costs 19,132 27,811
Depreciation
and amortization 2,811 4,894
Oil and natural gas:
Operating costs 4,948 6,615
Depreciation,
depletion and
amortization 5,269 6,047
General and administrative 2,029 2,450
Interest 287 211
--------- ---------
Total expenses 34,476 48,028
--------- ---------
Income Before Income Taxes and Change in
Accounting Principle 4,254 20,418
--------- ---------
Income Tax Expense:
Current 122 155
Deferred 1,490 7,604
--------- ---------
Total income taxes 1,612 7,759
--------- ---------
Income Before Change in Accounting
Principle 2,642 12,659
Cumulative Effect of Change in Accounting
Principle (Net of Income Tax of $811,000) - 1,325
--------- ---------
Net Income $ 2,642 $ 13,984
========= =========
Basic Earnings per Common Share:
Income before change in accounting
principle $ 0.07 $ 0.29
Cumulative effect of change in
accounting principle net of income tax - 0.03
--------- ---------
Net income $ 0.07 $ 0.32
========= =========
Diluted Earnings per Common Share:
Income before change in accounting
principle $ 0.07 $ 0.29
Cumulative effect of change in
accounting principle net of income tax - 0.03
--------- ---------
Net income $ 0.07 $ 0.32
========= =========
3
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)
(CONTINUED)
Three Months Ended
March 31,
----------------------
2002 2003
--------- ---------
(In thousands except per
share amounts)
Pro Forma Amounts Assuming Retroactive
Application of Change in Accounting
Principle:
Net income $ 2,612 $ 12,659
========= =========
Basic earnings per share $ 0.07 $ 0.29
========= =========
Diluted earnings per share $ 0.07 $ 0.29
========= =========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
4
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended
March 31,
------------------------
2002 2003
---------- ----------
(In thousands)
Cash Flows From Operating Activities:
Net income $ 2,642 $ 13,984
Adjustments to reconcile net income
to net cash provided (used) by
operating activities:
Depreciation, depletion,
and amortization 8,235 11,103
Deferred tax expense 1,490 7,604
Other 185 (1,028)
Changes in operating assets and
liabilities increasing (decreasing)
cash:
Accounts receivable 3,336 (8,979)
Accounts payable 3,173 (434)
Other - net 3,578 2,185
---------- ----------
Net cash provided by
operating activities 22,639 24,435
---------- ----------
Cash Flows From (Used In) Investing
Activities:
Capital expenditures (14,967) (18,663)
Proceeds from disposition of assets 658 141
Other-net (78) 31
---------- ----------
Net cash used in
Investing activities (14,387) (18,491)
---------- ----------
Cash Flows From (Used In) Financing
Activities:
Net borrowings (payments) under
line of credit (7,000) (4,500)
Net payments of notes payable
and other long-term debt (1,000) (1,000)
Proceeds from exercise of stock options 96 393
Book overdrafts (529) (1,106)
---------- ----------
Net cash used in financing
activities (8,433) (6,213)
---------- ----------
Net Decrease in Cash and
Cash Equivalents (181) (269)
Cash and Cash Equivalents, Beginning
of Year 391 497
---------- ----------
Cash and Cash Equivalents, End of Period $ 210 $ 228
========== ==========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
5
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
Three Months Ended
March 31,
-----------------------
2002 2003
--------- ---------
(In thousands)
Net Income $ 2,642 $ 13,984
Other Comprehensive Income,
Net of Taxes:
Change in value of cash
flow derivative
instruments used as
cash flow hedges - 155
--------- ---------
Comprehensive Income $ 2,642 $ 14,139
========= =========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
6
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 months ended March 31, 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.
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
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.
7
Three Three
Months Months
Ended Ended
2002 2003
--------- ---------
(In thousands except
per share amounts)
Net Income, as Reported $ 2,642 $ 13,984
Add Stock Based Employee Compensation
Expense Included in Reported Net
Income - Net of Tax 160 167
Less Total Stock Based Employee
Compensation Expense Determined
Under Fair Value Based Method
For All Awards (266) (404)
--------- ---------
Pro Forma Net Income $ 2,536 $ 13,747
========= =========
Basic Earnings per Share:
As reported $ 0.07 $ 0.32
========= =========
Pro forma $ 0.07 $ 0.32
========= =========
Diluted Earnings per Share:
As reported $ 0.07 $ 0.32
========= =========
Pro forma $ 0.07 $ 0.32
========= =========
The fair value of each option granted is estimated using the Black-Scholes
model. There were no options granted in the first quarter of 2002 and 2003. For
options granted in fiscal 2001 and 2002, Unit's estimate of stock volatility was
0.55 and 0.53, respectively, based on previous stock performance. Dividend yield
was estimated to remain at zero with a risk free interest rate of 5.41 and 4.24
percent in 2001 and 2002, respectively. 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.
8
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
March 31, 2002:
Basic earnings per common share:
Income before change in
accounting principle $ 2,642,000 36,035,000 $ 0.07
Cumulative effect of change
in accounting principle
net of income tax - 36,035,000 -
------------- ----------
Net Income $ 2,642,000 36,035,000 $ 0.07
============= ==========
Diluted earnings per common share:
Weighted average number of
common shares used in basic
earnings per common share 36,035,000
Effect of dilutive stock
options 258,000
-------------
Weighted average number of
common shares and dilutive
potential common shares
used in diluted earnings
per share 36,293,000
=============
Income before change in
accounting principle $ 2,642,000 36,293,000 $ 0.07
Cumulative effect of change
in accounting principle
net of income tax - 36,293,000 -
------------- ----------
Net Income $ 2,642,000 36,293,000 $ 0.07
============= ==========
9
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------- ------------- ----------
For the Three Months Ended
March 31, 2003:
Basic earnings per common share:
Income before change in
accounting principle $ 12,659,000 43,432,000 $ 0.29
Cumulative effect of change
in accounting principle
net of income tax 1,325,000 43,432,000 0.03
------------- ----------
Net Income $ 13,984,000 43,432,000 $ 0.32
============= ==========
Diluted earnings per common share:
Weighted average number of
common shares used in basic
earnings per common share 43,432,000
Effect of dilutive stock
options 205,000
-------------
Weighted average number of
common shares and dilutive
potential common shares
used in diluted earnings
per share 43,637,000
=============
Income before change in
accounting principle $ 12,659,000 43,637,000 $ 0.29
Cumulative effect of change
in accounting principle
net of income tax 1,325,000 43,637,000 0.03
------------- ----------
Net Income $ 13,984,000 43,637,000 $ 0.32
============= ==========
The following options and their average exercise prices were not included
in the computation of diluted earnings per share for the three months ended
March 31, 2002 and 2003 because the option exercise prices were greater than the
average market price of common shares:
2002 2003
---------- ----------
Options 158,500 176,000
========== ==========
Average exercise price $ 16.69 $ 19.17
========== ==========
10
NOTE 3 - NEW ACCOUNTING PRONOUNCEMENTS
- --------------------------------------
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). The effect of this
change increased net property, plant and equipment by $13.0 million and
liabilities by $11.7 million at January 1, 2003 and decreased net income before
change in accounting principle for the first three months of 2003 by $38,000
($0.00 per share). 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.
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 quarter of 2003, we did not have any exit or disposal activities and we do
not expect any application of FAS 146 to have a material effect on our financial
position, results of operations or cashflow.
11
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.
NOTE 4 - 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. The fair value of the collar contracts was recognized on the March 31,
2003 balance sheet as a derivative asset of $246,000 and at $155,000, net of
tax, in accumulated other comprehensive income. These hedges were fully
effective and thus did not effect net income. Unit did not have any hedging
contracts in place in the first quarter of 2002.
NOTE 5 - INDUSTRY SEGMENT INFORMATION
- -------------------------------------
Unit 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.
Management 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. Unit has natural gas production in
Canada, which is not significant. Information regarding Unit's operations by
industry segment for the three month periods ended March 31, 2002 and 2003 is as
follows:
12
Three Months Ended
March 31,
2002 2003
---------- ----------
(In thousands)
Revenues:
Contract drilling $ 26,714 $ 34,566
Oil and natural gas 11,961 33,248
Other 55 632
---------- ----------
Total revenues $ 38,730 $ 68,446
========== ==========
Operating Income (1):
Contract drilling $ 4,771 $ 1,861
Oil and natural gas 1,744 20,586
---------- ----------
Total operating income 6,515 22,447
General and administrative
expense (2,029) (2,450)
Interest expense (287) (211)
Other income - net 55 632
---------- ----------
Income before income taxes
and change in accounting
principle $ 4,254 $ 20,418
========== ==========
(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.
13
REPORT OF REVIEW BY 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 March 31, 2003, and the related consolidated
condensed statements of operations, comprehensive income and cash flows for the
three month periods ended March 31, 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 review procedures to
financial data 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 financial statements for them
to be in conformity with accounting principles generally accepted in the United
States of America.
We have previously audited, in accordance with generally accepted auditing
standards, the consolidated balance sheet as of December 31, 2002, and the
related consolidated statements of operations, stockholder's equity and 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 condensed consolidated balance sheet 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 LLP
Tulsa, Oklahoma
April 23, 2003
14
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 and borrowings under our bank loan
agreement. At March 31, 2003, we had cash totaling $228,000 and we had borrowed
$26.0 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 March 31,
2002 and March 31, 2003 and for the three months ended March 31, 2002 and March
31, 2003:
March 31, March 31, Percent
2002 2003 Change
-------------- -------------- -------
Working Capital $ 13,935,000 $ 28,571,000 105%
Income Before Change in
Accounting Principle $ 2,642,000 $ 12,659,000 379%
Net Income $ 2,642,000 $ 13,984,000 429%
Net Cash Provided by
Operating Activities $ 22,639,000 $ 24,435,000 8%
Net Cash Used in Investing
Activities $ 14,387,000 $ 18,491,000 29%
Net Cash Used in Financing
Activities $ 8,433,000 $ 6,213,000 (26%)
Long-Term Debt $ 23,000,000 $ 26,000,000 13%
Shareholders' Equity $ 282,963,000 $ 436,984,000 54%
Ratio of Long-Term debt to
Total Capitalization 8% 6%
The following table summarizes certain operating information for the first
three months of 2002 and 2003:
Percent
2002 2003 Change
------------ ------------ --------
Oil Production (Bbls) 117,000 114,000 (3%)
Natural Gas Production (Mcf) 4,556,000 4,855,000 7%
Average Oil Price Received $ 17.24 $ 30.40 76%
Average Natural Gas Price
Received $ 2.00 $ 5.96 198%
Average Number of Our
Drilling Rigs in Use
During the Period 32.8 50.8 55%
Total Number of Our Drilling
Rigs Available at the End
of the Period 55 75 36%
15
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
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 $26.0 million
at March 31, 2003 and $19.0 million on May 1, 2003.
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 2.36 percent and 2.38 percent at
March 31, 2003 and May 1, 2003, respectively. 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 $26.0 million at March 31, 2003 and $19.0 on May 1, 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
16
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.
Contractual Commitments. We have the following contractual obligations at
March 31, 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) $ 26,000 $ - $ 7,222 $ 17,333 $ 1,445
Retirement
Agreement(2) 1,439 245 600 594 -
Operating
Leases(3) 4,162 742 1,439 1,183 798
--------- ------- -------- --------- --------
Total
Contractual
Obligations $ 31,601 $ 987 $ 9,261 $ 19,110 $ 2,243
========= ======= ======== ========= ========
- -------------------
(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.
17
At March 31, 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) $ 1,462 Unknown Unknown Unknown Unknown
Separation
Benefit
Agreement(2) $ 2,097 $ 223 Unknown Unknown Unknown
Plugging
Liability(3) $ 11,022 $ 269 $ 2,047 $ 662 $ 8,044
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
establishes an accounting standard requiring the recording of the fair
value of liabilities associated with the retirement of long-lived assets
18
(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) In December 2002, we 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. No repurchases were
made in the first 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. The fair
value of the collar contracts was recognized on our March 31, 2003 balance sheet
as a derivative asset of $246,000 and at $155,000, net of tax, in accumulated
other comprehensive income. These hedges were fully effective and thus did not
effect net income. We did not have any hedging contracts in place in the first
quarter of 2002.
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 range from $200,000 for general
19
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 three month production, a $.10 per Mcf change in
what we are paid for our natural gas production would result in a corresponding
$151,000 per month ($1,812,000 annualized) change in our pre-tax cash flow. Our
first three month 2003 average natural gas price was $5.96 compared to an
average natural gas price of $2.00 received in the first three 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 $35,000 per
month ($420,000 annualized) change in our pre-tax cash flow. Our first three
months 2003 average oil price was $30.40 compared with an average oil price of
$17.24 received in the first three 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 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 18 wells in the first three months of 2003 compared to 11
wells in the first three months of 2002. Through the first three months of 2003
we incurred $12.6 million of the $65 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.
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
was to increase rapidly in the future, shortages of experienced personnel would
20
limit our ability to increase the number of rigs we could operate. Through the
first three months of 2003 we incurred $3.6 million in capital expenditures for
our drilling operation. For the year 2003, we anticipate spending approximately
$35 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 three months of 2002 was 32.8 rigs compared with 50.8 rigs for the
first three 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
three months of 2002 was $8,401 and continued to drop to our average dayrate of
$7,317 for the first three months of 2003. Increases in dayrates typically lag
behind increases in utilization and we are beginning to see signs that dayrates
may start to improve in the second quarter of 2003. Based on the average
utilization of our rigs in the first three months of 2003, a $100 per day change
in dayrates has a $5,080 per day ($1,854,000 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
$319,000 and $330,000 in the first three 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 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
21
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 we expect the fees to be about the same
in 2003. Our proportionate share of assets, liabilities and net income relating
to the oil and natural gas partnerships is included in our consolidated
financial statements.
At March 31, 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 $1.9
million at March 31, 2003. From time to time we may guarantee the debt of this
company. However, as of March 31, 2003 and May 1, 2003, we were not guaranteeing
any of the debt of this company.
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. On May 1, 2003, the Nymex
Henry Hub average contract settle price for the next twelve months was $5.45
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 March 31, 2003
($4.87 per Mcf for natural gas and $31.98 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.
22
The value of our oil and natural gas reserves is used to determine 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 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.
We recognize revenues and expenses generated from "daywork" drilling
contracts as the services are performed (i.e. daily), since the Company does not
bear the risk of completion of the well . Under "footage" and "turnkey"
contracts, we recognize revenues and expenses when the well is completed as
provided for by terms included in the contracts. Under this method, substantial
completion is determined when the well bore reaches the negotiated depth as
stated in the contract. The entire amount of a loss, if any, is recorded when
the loss can be reasonably determined, however, any profit is recorded only at
the time the well is finished. 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.
23
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
24
on Form 10-K filed with the Securities and Exchange Commission. We encourage you
to get and read that document.
25
RESULTS OF OPERATIONS
- ---------------------
First Quarter 2003 versus First Quarter 2002
- --------------------------------------------
Provided below is a comparison of selected operating and financial data for
the first quarter of 2003 verses the first quarter of 2002:
First First Percent
Quarter 2002 Quarter 2003 Change
--------------- --------------- ---------
Total Revenue $ 38,730,000 $ 68,446,000 77%
Income Before Change in Accounting
Principle $ 2,642,000 $ 12,659,000 379%
Net Income $ 2,642,000 $ 13,984,000 429%
Oil and Natural Gas:
Revenue $ 11,961,000 $ 33,248,000 178%
Average natural gas price (Mcf) $ 2.00 $ 5.96 198%
Average oil price (Bbl) $ 17.24 $ 30.40 76%
Natural gas production (Mcf) 4,556,000 4,855,000 7%
Oil production (Bbl) 117,000 114,000 (3%)
Operating profit (revenue
less operating costs) $ 7,013,000 $ 26,633,000 280%
Operating margin 59% 80%
Depreciation, depletion and
amortization rate (Mcfe) $ 0.99 $ 1.08 9%
Depreciation, depletion and
amortization $ 5,269,000 $ 6,047,000 15%
Drilling:
Revenue $ 26,714,000 $ 34,566,000 29%
Percentage of revenue from
daywork contracts 96% 95%
Average number of rigs in use 32.8 50.8 55%
Average dayrate on daywork
contracts $ 8,401 $ 7,317 (13%)
Operating profit (revenue
less operating costs) $ 7,582,000 $ 6,755,000 (11%)
Operating margin 28% 20%
Depreciation $ 2,811,000 $ 4,894,000 74%
General and Administrative Expense $ 2,029,000 $ 2,450,000 21%
Interest Expense $ 287,000 $ 211,000 (26%)
Average Interest Rate 3.07% 2.10% (32%)
Average Long-Term Debt Outstanding $ 28,708,000 $ 31,612,000 10%
26
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 quarter of 2003 and the first quarter of 2002.
Since our drilling program is focused on the development of natural gas
reserves, we experienced an increase in our natural gas production volumes
between the comparative quarters and our oil volumes decreased. Total operating
cost increased in the first quarter of 2003 when compared with the first 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 to the
increase in equivalent volumes produced and an increase in our DD&A rate per
Mcfe. During 2002, 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 resulting in lower rig dayrates for our
rigs between the first quarter of 2002 and the first quarter of 2003. As a
result, operating margins declined between the comparative periods. Natural gas
prices increased in the fourth quarter of 2002 and into the first quarter of
2003 causing an increase in demand for our rigs. Utilization rates typically
increase before dayrates when demand for our rigs increases, so we did not
experience a corresponding increase in dayrates during the first quarter of
2003. Approximately 5 percent of our total drilling revenues in the first
quarter of 2003 came from footage and turnkey contracts, which had profit
margins lower than our daywork contracts. Four percent of our total drilling
revenues came from footage and turnkey contracts in the first quarter 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 quarter of 2003
due to increases in insurance expense. Our total interest expense is lower due
to lower interest rates partially offset by an increase in the average debt
outstanding.
27
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.
28
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 reviewing our internal control procedures.
On March 31, 2003, we filed a universal shelf registration statement on
Form S-3. In connection with this filing, we have been notified by the
Securities and Exchange Commission that it is giving this registration
statement along with the reports incorporated by reference a full review.
As a result, we may file an amendment to our annual report on Form 10-K for
the year ended December 31, 2002 and possibly an amendment to this report
in response to comments we receive from the Commission.
29
Item 6. Exhibits and Reports on Form 8-K
- -----------------------------------------
(a) Exhibits:
15 Letter re: Unaudited Interim Financial Information.
99.1 Certification Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
(b) On March 13, 2003, we filed a report on Form 8-K under item 9. This
report disclosed that the Principal Executive Officer, John G. Nikkel,
and Principal Financial Officer, Larry D. Pinkston, of Unit
Corporation, had filed with the SEC certifications pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
30
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: May 14, 2003 By: /s/ John G. Nikkel
--------------------------- ------------------------------
JOHN G. NIKKEL
President, Chief Executive
Officer, Chief Operating
Officer and Director
Date: May 14, 2003 By: /s/ Larry D. Pinkston
--------------------------- ------------------------------
LARRY D. PINKSTON
Executive Vice President,
Chief Financial Officer and
Treasurer
31
CERTIFICATIONS
--------------
I, John G. Nikkel, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Unit Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the registrant's auditors and
the audit committee of registrant's board of directors (or persons performing
the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether there were significant changes in internal controls or
in other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
32
Date: May 14, 2003 By: /s/ John G. Nikkel
--------------------------- ------------------------------
JOHN G. NIKKEL
President, Chief Executive
Officer, Chief Operating
Officer and Director
33
CERTIFICATIONS
--------------
I, Larry D. Pinkston, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Unit Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether there were significant changes in internal controls or
in other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
34
Date: May 14, 2003 By: /s/ Larry D. Pinkston
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LARRY D. PINKSTON
Executive Vice President,
Chief Financial Officer and
Treasurer
35