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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, 2002
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 43,336,700
---------------------------- --------------
Class Outstanding at November 4, 2002
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, 2001 and September 30, 2002. . . . . . . . 2
Consolidated Condensed Statements of Operations
Three and Nine Months Ended September 30, 2001
and 2002. . . . . . . . . . . . . . . . . . . . . . . 3
Consolidated Condensed Statements of Cash Flows
Nine Months Ended September 30, 2001 and 2002 . . . . . 4
Consolidated Condensed Statements of Comprehensive
Income Three and Nine Months Ended September 30,
2001 and 2002 . . . . . . . . . . . . . . . . . . . . 5
Notes to Consolidated Condensed Financial Statements. . 6
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, September 30,
2001 2002
----------- -----------
(In thousands)
ASSETS
------
Current Assets:
Cash and cash equivalents $ 391 $ 580
Accounts receivable 33,886 32,236
Materials and supplies 5,358 9,617
Income tax receivable 3,198 -
Other 3,761 5,080
----------- -----------
Total current assets 46,594 47,513
----------- -----------
Property and Equipment:
Total cost 666,861 821,213
Less accumulated depreciation, depletion,
amortization and impairment 304,643 330,903
----------- -----------
Net property and equipment 362,218 490,310
----------- -----------
Other Assets 8,441 17,882
----------- -----------
Total Assets $ 417,253 $ 555,705
=========== ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------
Current Liabilities:
Current portion of long-term
liabilities and debt $ 1,893 $ 1,356
Accounts payable 16,292 17,374
Accrued liabilities 10,856 12,690
----------- -----------
Total current liabilities 29,041 31,420
----------- -----------
Long-Term Debt 31,000 24,500
----------- -----------
Other Long-Term Liabilities 4,110 4,419
----------- -----------
Deferred Income Taxes 73,940 80,980
----------- -----------
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, 36,006,267 and
43,336,700 shares issued, respectively 7,201 8,667
Capital in excess of par value 141,977 263,981
Accumulated other comprehensive income - -
Retained earnings 130,280 141,738
Treasury Stock, at cost, 30,000 shares (296) -
----------- -----------
Total shareholders' equity 279,162 414,386
----------- -----------
Total Liabilities and Shareholders' Equity $ 417,253 $ 555,705
=========== ===========
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 Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2001 2002 2001 2002
---------- ---------- ---------- ----------
(In thousands except per share amounts)
Revenues:
Contract drilling $ 50,690 $ 31,589 $131,026 $ 84,144
Oil and natural gas 17,410 16,357 77,652 46,986
Other 299 326 1,251 625
--------- --------- --------- ---------
Total revenues 68,399 48,272 209,929 131,755
--------- --------- --------- ---------
Expenses:
Contract drilling:
Operating costs 24,978 24,350 71,405 63,619
Depreciation
and amortization 3,872 4,178 10,693 9,917
Oil and natural gas:
Operating costs 5,332 5,169 17,337 15,278
Depreciation,
depletion and
amortization 6,641 6,142 16,461 17,399
General and
administrative 1,731 2,180 6,565 6,222
Interest 675 231 2,366 747
--------- --------- --------- ---------
Total expenses 43,229 42,250 124,827 113,182
--------- --------- --------- ---------
Income Before Income
Taxes 25,170 6,022 85,102 18,573
--------- --------- --------- ---------
Income Tax Expense:
Current 3,251 (285) 10,990 75
Deferred 6,288 2,599 21,261 7,040
--------- --------- --------- ---------
Total income
taxes 9,539 2,314 32,251 7,115
--------- --------- --------- ---------
Net Income $ 15,631 $ 3,708 $ 52,851 $ 11,458
========= ========= ========= =========
Net Income Per Common
Share:
Basic $ .43 $ 0.09 $ 1.47 $ 0.31
========= ========= ========= =========
Diluted $ .43 $ 0.09 $ 1.46 $ 0.30
========= ========= ========= =========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
3
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended
September 30,
-------------------------
2001 2002
---------- ----------
(In thousands)
Cash Flows From Operating Activities:
Net income $ 52,851 $ 11,458
Adjustments to reconcile net income
to net cash provided (used) by
operating activities:
Depreciation, depletion,
and amortization 27,642 27,789
Deferred tax expense 21,261 7,040
Other 1,816 373
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable (6,652) 1,347
Accounts payable 7,118 6,548
Other - net 72 (281)
---------- ----------
Net cash provided by
operating activities 104,108 54,274
---------- ----------
Cash Flows From (Used In) Investing
Activities:
Capital expenditures (Note 3) (83,824) (48,825)
Proceeds from disposition of assets 2,125 1,630
Other-net (498) 523
---------- ----------
Net cash used in
investing activities (82,197) (46,672)
---------- ----------
Cash Flows From (Used In) Financing
Activities:
Net borrowings (payments) under
line of credit (16,000) (6,500)
Net payments of notes payable
and other long-term debt - (22)
Proceeds from stock sales (Note 3) 606 213
Acquisition of treasury stock (175) -
Book overdrafts (6,082) (1,104)
---------- ----------
Net cash used in financing
Activities (21,651) (7,413)
---------- ----------
Net Increase in Cash and
Cash Equivalents 260 189
Cash and Cash Equivalents, Beginning
of Year 726 391
---------- ----------
Cash and Cash Equivalents, End of Period $ 986 $ 580
========== ==========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
4
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2001 2002 2001 2002
---------- ---------- ---------- ----------
(In thousands)
Net Income $ 15,631 $ 3,708 $ 52,851 $ 11,458
Other Comprehensive Income,
Net of Taxes:
Change in value of cash
flow derivative
instruments used as
cash flow hedges 549 - 1,100 -
Adjustment
Reclassification -
Derivative
Settlements (652) - (652) -
---------- ---------- ---------- ----------
Comprehensive Income $ 15,528 $ 3,708 $ 53,299 $ 11,458
========== ========== ========== ==========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
5
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 1 - BASIS OF PREPARATION AND PRESENTATION
- ----------------------------------------------
The accompanying unaudited consolidated condensed financial statements
include the accounts of Unit Corporation and its wholly owned subsidiaries (the
"Company") and have been prepared pursuant to the rules and regulations of the
Securities and Exchange Commission. As applicable under these regulations,
certain information and footnote disclosures have been condensed or omitted and
the consolidated condensed financial statements do not include all disclosures
required by generally accepted accounting principles. In the opinion of the
Company, the unaudited consolidated condensed financial statements contain all
adjustments necessary (all adjustments are of a normal recurring nature) to
present fairly the interim financial information.
Results for the three and nine months ended September 30, 2002 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, 2001. 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.
6
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
September 30, 2001:
Basic earnings per
common share $ 15,631,000 35,999,000 $ 0.43
==========
Effect of dilutive
stock options - 236,000
------------- -------------
Diluted earnings per
common share $ 15,631,000 36,235,000 $ 0.43
============= ============= ==========
For the Three Months Ended
September 30, 2002:
Basic earnings per
common share $ 3,708,000 39,804,000 $ 0.09
==========
Effect of dilutive
stock options - 267,000
------------- -------------
Diluted earnings per
common share $ 3,708,000 40,071,000 $ 0.09
============= ============= ==========
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, 2001 and 2002 because the option exercise prices were greater than
the average market price of common shares:
2001 2002
---------- ----------
Options 170,000 179,000
========== ==========
Average exercise price $ 16.38 $ 17.23
========== ==========
7
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------- ------------- ----------
For the Nine Months Ended
September 30, 2001:
Basic earnings per
common share $ 52,851,000 35,961,000 $ 1.47
==========
Effect of dilutive
stock options - 295,000
------------- -------------
Diluted earnings per
common share $ 52,851,000 36,256,000 $ 1.46
============= ============= ==========
For the Nine Months Ended
September 30, 2002:
Basic earnings per
common share $ 11,458,000 37,330,000 $ 0.31
==========
Effect of dilutive
stock options - 264,000
------------- -------------
Diluted earnings per
common share $ 11,458,000 37,594,000 $ 0.30
============= ============= ==========
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, 2001 and 2002 because the option exercise prices were greater than
the average market price of common shares:
2001 2002
---------- ----------
Options 153,000 179,000
========== ==========
Average exercise price $ 16.79 $ 17.23
========== ==========
8
NOTE 3 - ACQUISITION OF EQUIPMENT AND DRILLING COMPANIES
- --------------------------------------------------------
On August 15, 2002, we completed the acquisition of CREC Rig Equipment
Company and CDC Drilling Company. Both of these acquisitions were stock purchase
transactions. Unit issued 6,819,748 shares of common stock and paid $3,813,053
for all the outstanding shares of CREC Rig Acquisition 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. What we paid in both
transactions was determined through arms-length negotiations between the parties
and only the cash portion of the transaction appears in the investing and
financing activities of Unit's Consolidated Condensed Statement of Cash Flows.
The calculation and allocation of the total consideration paid for the
acquisition are as follows (in thousands):
Calculation of Consideration Paid:
Unit Corporation common stock
(7,220,000 shares at $16.96556 per share) $ 122,491
Cash 4,500
----------
Total consideration $ 126,991
==========
Allocation of Total Consideration Paid:
Drilling Rigs $ 112,994
Spare Drilling Equipment 3,500
Vehicles 636
Goodwill 9,861
----------
Total consideration $ 126,991
==========
9
Unaudited summary pro forma results of operations for the Company,
reflecting the above acquisitions as if they had occurred at the beginning of
the year ended December 31, 2001 are as follow:
Nine Months Nine Months
Year Ended Ended Ended
December 31, September 30, September 30,
2001 2001 2002
-------------- -------------- --------------
Revenues $ 311,104,000 $ 246,650,000 $ 159,924,000
============== ============== ==============
Net Income $ 70,457,000 $ 58,928,000 $ 8,534,000
============== ============== ==============
Net Income per
Common Share
(Diluted) $ 1.62 $ 1.36 $ 0.20
============== ============== ==============
The pro forma results of operations are not necessarily indicative of the
actual results of operations that would have occurred had the purchase actually
been made at the beginning of the respective periods nor of the results which
may occur in the future.
10
NOTE 4 - NEW ACCOUNTING PRONOUNCEMENTS
- --------------------------------------
On January 1, 2002, we adopted Statement of Financial Accounting Standards
No. 142, "Goodwill and Other Intangible Assets" (FAS 142). For goodwill and
intangible assets already recorded in the financial statements, FAS 142 ends the
amortization of goodwill and certain intangible assets and subsequently
requires, at least annually, that an impairment test be performed on such assets
to determine whether the fair value has changed. The unamortized balance of
goodwill, all of which relates to our drilling segment, was $5,088,000 at
January 1, 2002 and $14,950,000 at September 30, 2002. Goodwill increased in the
third quarter of 2002 as a result of the acquisitions discussed in Note 3. We
previously expensed $243,000 annually for the amortization of goodwill. The
impact from the adoption of FAS 142 on our financial position or results of
operations was not material to the current and prior periods.
On January 1, 2002, we adopted Statement of Financial Accounting Standards
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (FAS
144). This statement supersedes Statement of Financial Accounting Standards No.
121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of" and amends Accounting Principles Board Opinion No. 30
for the accounting and reporting of discontinued operations, as it relates to
long-lived assets. The impact from the adoption of FAS 144 on our financial
position or results of operations was not material.
In July 2001, the FASB issued Statement of Financial Accounting Standards
No. 143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS 143 is
effective for fiscal years beginning after June 15, 2002 (January 1, 2003 for
us) and 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). We are currently
evaluating our oil and natural gas properties to determine the impact of the
adoption of FAS 143 on our financial position and results of operations.
In April 2002, the FASB issued Statement of Financial Accounting Standards
No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB
Statement 13, and Technical Corrections" (FAS 145). FAS 145 is effective for
fiscal years beginning after May 15, 2002. 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. We do not expect the adoption of FAS 145 to have a material effect
on our financial position, results of operations or cashflows.
11
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)." We do not
expect the adoption of FAS 146 to have a material effect on our financial
position, results of operations or cashflow.
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 and nine month periods ended September 30, 2001
and 2002 is as follows:
12
Three Months Ended Nine Months Ended
September 30, September 30,
2001 2002 2001 2002
---------- ---------- ---------- ----------
(In thousands)
Revenues:
Contract drilling $ 50,690 $ 31,589 $ 131,026 $ 84,144
Oil and natural gas 17,410 16,357 77,652 46,986
Other 299 326 1,251 625
---------- ---------- ---------- ----------
$ 68,399 $ 48,272 $ 209,929 $ 131,755
========== ========== ========== ==========
Operating Income (1):
Contract drilling $ 21,840 $ 3,061 $ 48,928 $ 10,608
Oil and natural gas 5,437 5,046 43,854 14,309
---------- ---------- ---------- ----------
27,277 8,107 92,782 24,917
General and
administrative
expense (1,731) (2,180) (6,565) (6,222)
Interest expense (675) (231) (2,366) (747)
Other income - net 299 326 1,251 625
---------- ---------- ---------- ----------
$ 25,170 6,022 $ 85,102 $ 18,573
========== ========== ========== ==========
(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.
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 September 30, 2002, and the related
consolidated condensed statements of operations and comprehensive income for the
three and nine month periods ended September 30, 2002 and 2001 and cash flows
for the nine month period ended September 30, 2002 and 2001. 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, 2001, 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 20, 2002, 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, 2001, is
fairly stated in all material respects in relation to the consolidated balance
sheet from which it has been derived.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
October 23, 2002
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 September 30, 2002, we had cash totaling $580,000 and we had
borrowed $24.5 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 for the nine months ended September 30, 2002:
Working capital $ 16,093,000
Net income $ 11,458,000
Net cash provided by
operating activities $ 54,274,000
Long-term debt $ 24,500,000
Shareholders' equity $ 414,386,000
Ratio of long-term debt to
total capitalization 6%
The following table summarizes certain operating information for the first
nine months of 2001 and 2002:
Percent
2001 2002 Change
------------ ------------ --------
Oil production (Bbls) 374,000 347,000 (7%)
Natural gas production (Mcf) 14,437,000 14,360,000 (1%)
Average oil price received $ 25.59 $ 20.92 (18%)
Average natural gas price
received $ 4.54 $ 2.59 (43%)
Average number of our
drilling rigs in use
during the period 48.8 36.2 (26%)
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. 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.
15
Borrowing under our loan agreement totaled $30.0 million at December 31, 2001
and $24.9 million on October 23, 2002.
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 2.94 percent and 2.96 percent at
September 30, 2002 and October 23, 2002, 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 $23.0 million at September 30, 2002 and October 23, 2002.
The loan agreement also requires us to maintain:
. consolidated net worth of at least $125 million;
. a current ratio of not less than 1 to 1;
. a ratio of long-term debt, as defined in the loan agreement, to
consolidated tangible net worth not greater than 1.2 to 1;
. a ratio of total liabilities, as defined in the loan agreement, to
consolidated tangible net worth not greater than 1.65 to 1; and
. working capital provided by operations, as defined in the loan
agreement, cannot be less than $40 million in any year.
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.
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. We entered
into a collar contract covering approximately 25 percent of our daily oil
production from November 1, 2000 through February 28, 2001. The collar had a
floor of $26.00 per barrel and a ceiling of
16
$33.00 per barrel and we received $0.86 per barrel for entering into the
transaction. During the first quarter of 2001, our oil hedging transaction
yielded an increase in our oil revenues of $17,200.
During the second quarter of 2001, we entered into a natural gas collar
contract for approximately 36 percent of our June and July 2001 production, at a
floor price of $4.50 and a ceiling price of $5.95. During the third quarter of
2001, we entered into two natural gas collar contracts for approximately 38
percent of our September thru November 2001 natural gas production. Both
contracts had a floor price of $2.50. One contract had a ceiling of $ 3.68 and
the other contract had a ceiling of $4.25. During the third quarter of 2001, the
collar contract increased natural gas revenues by $1,049,000 and for the nine
months ended September 30, 2001 the collar contract increased natural gas
revenues by $1,565,000. The October and November 2001 collar was recognized on
our September 30, 2001 balance sheet at $448,000, net of tax, in accumulated
other comprehensive income. On April 30, 2002, we entered into a collar contract
covering approximately 19 percent of our natural gas production for the periods
of April 1, 2002 thru October 31, 2002. The collar has a floor of $3.00 and a
ceiling of $3.98. During the third quarter of 2002, our natural gas hedging
transactions increased natural gas revenues by $40,300 and the remaining month
contract had no value at September 30, 2002.
Self-Insurance. Unit is self-insured for certain losses relating to
workers' compensation, general liability, property damage and employee medical
benefits. Given the recent 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 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 Unit 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 2002 first nine month production, a $.10 per Mcf change in
what we are paid for our natural gas production would result in a corresponding
$149,000 per month ($1,788,000 annualized) change in our pre-tax cash flow. Our
first nine month 2002 average natural gas price was $2.59 compared to an average
natural gas price of $4.54 received in the first nine months of 2001. A $1.00
per barrel change in our oil price would have a $36,000 per month ($432,000
annualized) change in our pre-tax cash flow. Our first nine months 2002 average
oil price was $20.92 compared with an average oil price of $25.59 received in
the first nine months of 2001.
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
17
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.
We sell most of our natural gas production to third parties under
month-to-month contracts. Several of these buyers have experienced financial
complications resulting from the recent investigations into the energy trading
industry. The long-term implications to the energy trading business as well as
to oil and natural gas producers because of these investigations remains to be
determined. Presently we believe that our buyers will be able to perform their
commitments to us. However, we will continue to evaluate the information
available to us about these buyers in an effort to reduce any possible future
adverse impact to us.
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 such
costs. We drilled 62 wells in the first nine months of 2002 compared to 94 wells
in the first nine months of 2001. Through the first nine months of 2002 we
incurred $31.2 million of the $45 million in capital expenditures we expect to
make for exploration, development drilling and acquisition of oil and natural
gas properties in 2002. Based on current prices, we plan to drill an estimated
100 wells in 2002
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
limit our ability to increase the number of rigs we could operate. Through the
first nine months of 2002 we incurred $8.7 million in capital expenditures for
our drilling operation. For the year 2002, we anticipate spending approximately
$12 million on our drilling operations excluding the acquisition discussed
below.
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. Average use of our rigs in the first nine months of 2002 was 36.2 rigs
compared with 48.8 rigs for the first nine months of 2001.
18
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 compared to $10,011 for the first nine months of
2001. Based on the average utilization of our rigs in the first nine months of
2002, a $100 per day change in dayrates has a $3,600 per day ($1,314,000
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
$1,617,000 and $677,000 in the first nine months of 2001 and 2002, 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.
Acquisitions. On August 15, 2002 we completed the acquisition of CREC Rig
Equipment Company and CDC Drilling Company, which included twenty drilling rigs,
spare drilling equipment and vehicles, for 7.22 million shares of our common
stock and $4.5 million in cash. All of the rigs are operational and range in
horsepower from 650 to 2,000 with 15 having a horsepower rating of 1,000 or
more. Depth capacities range from 12,000 to 25,000 feet and twelve of the rigs
are SCR electric. These agreements also give us the exclusive first option to
purchase any additional rigs constructed by one of the sellers within the next
three years. The addition of these twenty rigs brought our fleet to 75, 74 of
which are capable of operating.
Oil and Natural Gas Limited Partnerships and Other Entity Relationships. We
are the general partner for eighteen oil and natural gas partnerships which were
formed privately and publicly. The partnership's revenues and costs are shared
under formulas prescribed in each limited partnership agreement. The
partnerships repay us for contract drilling, well supervision and general and
administrative expense. Related party transactions for contract drilling and
well supervision fees are the related party's share of such costs. These costs
are billed on the same basis as billings to unrelated third parties for similar
services. General and administrative reimbursements consist of direct general
and administrative expense incurred on the related party's behalf as well as
indirect expenses assigned to the related parties. Allocations are based on the
related party's level of activity and are considered by management to be
reasonable. During 2001, the total paid to us for all of these fees was
$1,107,000 and we expect the fees to be about the same in 2002. 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 September 30, 2002, we owned a 40 percent equity interest in a natural
gas gathering and processing company. Our investment including our share of the
equity in the earnings of this company totaled $1.5 million at September 30,
2002. From time to time we may guarantee the debt of this
19
company. However, as of September 30, 2002 and October 23, 2002, we were not
guaranteeing any of the debt of this company.
One of our subsidiaries owns 4,949,500 shares of common stock and 1,800,000
warrants of Shenandoah Resources Ltd. ("Shenandoah"), a Canadian oil and natural
gas exploration and production company. In the second quarter of 2002 Shenandoah
obtained an order under Canadian Law protecting it from its creditors while it
worked out a financial restructuring plan. On July 17, 2002, Longbow Energy
Corporation ("LongBow") and Shenandoah jointly announced that they have executed
a Letter of Intent whereby LongBow would acquire all of the issued and
outstanding shares of Shenandoah and settle the outstanding claims of
Shenandoah's secured and unsecured creditors. In August the assets of Shenandoah
were foreclosed and the anticipated merger with LongBow was cancelled. As a
result of the foreclosure, our investment of $346,000 in Shenandoah was written
off.
Outlook. Both of our operating segments are extremely dependent on natural
gas prices, since the prices affect not only our production revenues, but also
the future demand and rates for our contract drilling services. On October 23,
2002, the Nymex Henry Hub average contract settle price for the next twelve
months was $4.14 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 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 September 30, 2002
($3.39 per Mcf for natural gas and $28.26 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
20
reserves. Natural gas prices remain erratic and any significant declines below
quarter-end prices used in the reserve evaluation could result in a ceiling
test write-down in following quarterly reporting periods.
The value of our oil and natural gas reserves is used to decide 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 such estimates does not reduce the subjectivity and changing nature of
such reserve estimates. Indeed the uncertainties inherent in the disclosure are
compounded by applying additional estimates of the rates and timing of
production and the costs that will be incurred in developing and producing the
reserves.
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 generated for "daywork" drilling contracts as the
services are performed, which is similar to the percentage of completion method.
Under "footage" and "turnkey" contracts, we bear the risk of completion of the
well, so revenues and expenses are recognized using the completed contract
method. 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.
21
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
22
Annual Report on Form 10-K filed with the Securities and Exchange Commission.
We encourage you to get and read that document.
23
RESULTS OF OPERATIONS
- ---------------------
Third Quarter 2002 versus Third Quarter 2001
- --------------------------------------------
Provided below is a comparison of selected operating and financial data for
the third quarter of 2002 verses the third quarter of 2001:
Third Third Percent
Quarter 2001 Quarter 2002 Change
--------------- --------------- ---------
Total Revenue $ 68,399,000 $ 48,272,000 (29%)
Net Income $ 15,631,000 $ 3,708,000 (76%)
Oil and Natural Gas:
Revenue $ 17,410,000 $ 16,357,000 (6%)
Average natural gas price (Mcf) $ 2.79 $ 2.71 (3%)
Average oil price (Bbl) $ 23.92 $ 22.99 (4%)
Natural gas production (Mcf) 4,929,000 4,707,000 (5%)
Oil production (Bbl) 122,000 120,000 (1%)
Operating profit
(revenue less operating costs) $ 12,078,000 $ 11,188,000 (7%)
Operating margin 69% 68%
Depreciation, depletion and
amortization rate (Mcfe) $ 0.88 $ 1.06 20%
Depreciation, depletion and
amortization $ 6,641,000 $ 6,142,000 8%
Drilling:
Revenue $ 50,690,000 $ 31,589,000 (38%)
Percentage of revenue from
daywork contracts 100% 92%
Average number of rigs in use 50.6 42.5 (16%)
Average dayrate on daywork
contracts $ 10,964 $ 7,529 (31%)
Operating profit
(revenue less operating costs) $ 25,712,000 $ 7,239,000 (72%)
Operating margin 51% 23%
Depreciation $ 3,872,000 $ 4,178,000 8%
General and Administrative Expense $ 1,731,000 $ 2,180,000 26%
Interest Expense $ 675,000 $ 231,000 (66%)
Average Interest Rate 5.0% 3.1% (38%)
Average Long-Term Debt Outstanding $ 45,965,000 $ 22,610,000 (51%)
24
Oil and natural gas revenues, operating profits and operating profit
margins were all negatively affected by lower prices received for both oil and
natural gas between the third quarter of 2002 and the third quarter of 2001. We
also experienced a decrease in our oil and natural gas production volumes as
declines on wells previously drilled have exceeded production from new wells
drilled in the current year. Total operating cost decreased due mainly to lower
workover expense in the third quarter of 2002 when compared to 2001. In the
third quarter of 2001, we wrote down our investment in Shenandoah Resources,
Inc. by $1.6 million so, depreciation, depletion and amortization ("DD&A") of
our oil and natural gas properties decreased in the third quarter of 2002. The
decrease was partially offset by a write down of the remaining amount we had
invested in Shenandoah Resources, Inc. of $346,000 in the third quarter of 2002
and an increase in our DD&A rate per Mcfe. We are experiencing higher cost per
Mcfe for the discovery of new reserves through our development drilling program
resulting in an increase in the DD&A rate.
Reduced natural gas prices, especially in the fourth quarter of 2001 and
the first quarter of 2002, caused decreases in operator demand for contract
drilling rigs within our working area and resulted in lower rig use and dayrates
for our rigs. As a result, operating margins declined between the third quarter
of 2002 and the third quarter of 2001. Approximately 8 percent of our total
drilling revenues in the third quarter of 2002 came from footage and turnkey
contracts, which had profit margins lower than our daywork contracts. Less than
one percent of our total drilling revenues came from footage and turnkey
contracts in the third quarter of 2001. Contract drilling depreciation increased
due to the acquisition of 20 rigs in August of 2002. The increase was partially
offset by lower rig use.
General and administrative expense was higher in the third quarter of 2002
due to increases in insurance expense and higher labor costs. Our total interest
expense is lower due to lower interest rates along with a substantial reduction
in our long-term debt.
25
Nine Months 2002 versus Nine Months 2001
- ----------------------------------------
Provided below is a comparison of selected operating and financial data for
the first nine months of 2002 verses the first nine months of 2001:
First Nine First Nine Percent
Months of 2001 Months of 2002 Change
--------------- --------------- ---------
Total Revenue $ 209,929,000 $ 131,755,000 (37%)
Net Income $ 52,851,000 $ 11,458,000 (78%)
Oil and Natural Gas:
Revenue $ 77,652,000 $ 46,986,000 (39%)
Average natural gas price (Mcf) $ 4.54 $ 2.59 (43%)
Average oil price (Bbl) $ 25.59 $ 20.92 (18%)
Natural gas production (Mcf) 14,437,000 14,360,000 (1%)
Oil production (Bbl) 374,000 347,000 (7%)
Operating profit
(revenue less operating costs) $ 60,315,000 $ 31,708,000 (47%)
Operating margin 78% 67%
Depreciation, depletion and
amortization rate (Mcfe) $ 0.88 $ 1.03 17%
Depreciation, depletion and
amortization $ 16,461,000 $ 17,399,000 6%
Drilling:
Revenue $ 131,026,000 $ 84,144,000 (36%)
Percentage of revenue from
daywork contracts 100% 91%
Average number of rigs in use 48.8 36.2 (26%)
Average dayrate on daywork
contracts $ 10,011 $ 7,847 (22%)
Operating profit
(revenue less operating costs) $ 59,621,000 $ 20,525,000 (66%)
Operating margin 46% 24%
Depreciation $ 10,693,000 $ 9,917,000 (7%)
General and Administrative Expense $ 6,565,000 $ 6,222,000 (5%)
Interest Expense $ 2,366,000 $ 747,000 (68%)
Average Interest Rate 6.1% 3.1% (49%)
Average Long-Term Debt Outstanding $ 48,184,000 $ 24,907,000 (48%)
26
Oil and natural gas revenues, operating profits and operating profit
margins were all negatively affected by lower prices received for both oil and
natural gas between the first nine months of 2002 and the first nine months of
2001. Both natural gas and oil production also had declines between the
comparative nine month period as production declines from wells previously
drilled have not been completely replaced by production from new wells drilled
over the past year. Total operating cost decreased primarily from lower gross
production taxes, since the tax is based on a percentage of oil and natural gas
revenues. Depreciation, depletion and amortization ("DD&A") of our oil and
natural gas properties increased due to an increase in our DD&A rate per Mcfe.
We are experiencing higher cost per Mcfe for the discovery of new reserves
through our development drilling program, resulting in an increase in the DD&A
rate. The increase in our DD&A expense was partially offset by a $1.6 million
write down of our investment in Shenandoah Resources, Inc. recorded in the third
quarter of 2001.
Reduced natural gas prices, especially in the fourth quarter of 2001 and
the first quarter of 2002, caused decreases in operator demand for contract
drilling rigs within our working area and resulted in lower rig use and dayrates
for our rigs. As a result, operating margins and total operating cost both
declined between the first nine months of 2002 and the first nine months of
2001. Approximately 9 percent of our total drilling revenues in the first nine
months of 2002 came from footage and turnkey contracts, which had profit margins
less than our daywork contracts. Less than one percent of our total drilling
revenues came from footage and turnkey contracts in the first nine months of
2001. Contract drilling depreciation decreased due to lower rig use, but the
decrease was partially offset by additional depreciation incurred from the 20
rigs acquired in August of 2002.
General and administrative expense declined for the first nine months of
2002 when compared with the first nine months of 2001. The 2001 General and
administrative expense was higher because we recorded $1.3 million in additional
employee benefit expenses for the present value of the separation agreement made
in connection with the retirement of King Kirchner from his position as Chief
Executive Officer. This decline was partially offset by increased insurance and
employment cost incurred. Our total interest expense is lower due to lower
interest rates along with a substantial reduction in our long-term debt.
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.
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
for due diligence related to any potential acquisitions.
29
Item 6. Exhibits and Reports on Form 8-K
- -----------------------------------------
(a) Exhibits:
15 Letter re: Unaudited Interim Financial Information.
(b) On August 15, 2002, 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.
On August 27, 2002, we filed a report on Form 8-K under items 2 and 7.
This report announced that on August 15, 2002, Unit Corporation
completed the acquisition of CREC Rig Equipment Company and
CDC Drilling Company.
On September 20, 2002, we filed a report on Form 8-K/A under item 7.
This report included the combined financial statements of the
CREC Rig Equipment Company and CDC Drilling Company and the pro forma
financial information required with the Form 8-K filed on
August 27, 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: November 5, 2002 By: /s/ John G. Nikkel
--------------------------- ------------------------------
JOHN G. NIKKEL
President, Chief Executive
Officer, Chief Operating
Officer and Director
Date: November 5, 2002 By: /s/ Larry D. Pinkston
--------------------------- ------------------------------
LARRY D. PINKSTON
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: November 5, 2002 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: November 5, 2002 By: /s/ Larry D. Pinkston
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LARRY D. PINKSTON
Vice President, Chief
Financial Officer
and Treasurer
35