SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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 36,114,700
---------------------------- ----------
Class Outstanding at August 9, 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 June 30, 2002. . . . . . . . . . 2
Consolidated Condensed Statements of Operations
Three and Six Months Ended June 30, 2001 and 2002. . . 3
Consolidated Condensed Statements of Cash Flows
Six Months Ended June 30, 2001 and 2002. . . . . . . . 4
Consolidated Condensed Statements of Comprehensive
Income Three and Six Months Ended
June 30, 2001 and 2002. . . . . . . . . . . . . . . . . 5
Notes to Consolidated Condensed Financial Statements. . 6
Report of Review by Independent Accountants . . . . . . 12
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . 13
PART II. Other Information
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . 25
Item 2. Changes in Securities and Use of Proceeds . . . . . . . 25
Item 3. Defaults Upon Senior Securities. . . . . . . . . . . . 25
Item 4. Submission of Matters to a Vote of Security Holders . . 25
Item 5. Other Information . . . . . . . . . . . . . . . . . . . 26
Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . 26
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
1
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
- ------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS (UNAUDITED)
December 31, June 30,
2001 2002
----------- -----------
(In thousands)
ASSETS
------
Current Assets:
Cash and cash equivalents $ 391 $ 1,458
Accounts receivable 33,886 27,817
Materials and supplies 5,358 6,908
Income tax receivable 3,198 -
Other 3,761 3,745
----------- -----------
Total current assets 46,594 39,928
----------- -----------
Property and Equipment:
Total cost 666,861 691,425
Less accumulated depreciation, depletion,
amortization and impairment 304,643 321,123
----------- -----------
Net property and equipment 362,218 370,302
----------- -----------
Other Assets 8,441 8,261
----------- -----------
Total Assets $ 417,253 $ 418,491
=========== ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------
Current Liabilities:
Current portion of long-term
liabilities and debt $ 1,893 $ 1,375
Accounts payable 16,292 16,265
Accrued liabilities 10,856 9,927
----------- -----------
Total current liabilities 29,041 27,567
----------- -----------
Long-Term Debt 31,000 20,000
----------- -----------
Other Long-Term Liabilities 4,110 4,364
----------- -----------
Deferred Income Taxes 73,940 78,381
----------- -----------
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
36,114,300 shares issued, respectively 7,201 7,223
Capital in excess of par value 141,977 142,926
Accumulated other comprehensive income - -
Retained earnings 130,280 138,030
Treasury Stock, at cost, 30,000 shares (296) -
----------- -----------
Total shareholders' equity 279,162 288,179
----------- -----------
Total Liabilities and Shareholders' Equity $ 417,253 $ 418,491
=========== ===========
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 Six Months Ended
June 30, June 30,
-------------------- --------------------
2001 2002 2001 2002
--------- --------- --------- ---------
(In thousands except per share amounts)
Revenues:
Contract drilling $ 44,836 $ 25,841 $ 80,336 $ 52,555
Oil and natural gas 25,522 18,668 60,242 30,629
Other 729 244 952 299
--------- --------- --------- ---------
Total revenues 71,087 44,753 141,530 83,483
--------- --------- --------- ---------
Expenses:
Contract drilling:
Operating costs 23,997 20,137 46,427 39,269
Depreciation
and amortization 3,602 2,928 6,821 5,739
Oil and natural gas:
Operating costs 5,526 5,161 12,005 10,109
Depreciation,
depletion and
amortization 5,142 5,988 9,820 11,257
General and
administrative 3,031 2,013 4,834 4,042
Interest 719 229 1,691 516
--------- --------- --------- ---------
Total expenses 42,017 36,456 81,598 70,932
--------- --------- --------- ---------
Income Before Income
Taxes 29,070 8,297 59,932 12,551
--------- --------- --------- ---------
Income Tax Expense:
Current 3,342 238 7,739 360
Deferred 7,680 2,951 14,973 4,441
--------- --------- --------- ---------
Total income
taxes 11,022 3,189 22,712 4,801
--------- --------- --------- ---------
Net Income $ 18,048 $ 5,108 $ 37,220 $ 7,750
========= ========= ========= =========
Net Income Per Common
Share:
Basic $ .50 $ 0.14 $ 1.04 $ 0.21
========= ========= ========= =========
Diluted $ .50 $ 0.14 $ 1.03 $ 0.21
========= ========= ========= =========
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)
Six Months Ended
June 30,
------------------------
2001 2002
---------- ----------
(In thousands)
Cash Flows From Operating Activities:
Net income $ 37,220 $ 7,750
Adjustments to reconcile net income
to net cash provided (used) by
operating activities:
Depreciation, depletion,
and amortization 16,970 17,313
Deferred tax expense 14,973 4,441
Other 1,851 198
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable (11,621) 6,069
Accounts payable 7,268 4,050
Other - net (3,532) 990
---------- ----------
Net cash provided by
operating activities 63,129 40,811
---------- ----------
Cash Flows From (Used In) Investing
Activities:
Capital expenditures (57,873) (29,188)
Proceeds from disposition of assets 1,147 907
Other-net (812) 459
---------- ----------
Net cash used in
investing activities (57,538) (27,822)
---------- ----------
Cash Flows From (Used In) Financing
Activities:
Net borrowings (payments) under
line of credit (4,500) (11,000)
Net payments of notes payable
and other long-term debt - (22)
Proceeds from stock sales 540 204
Book overdrafts (1,590) (1,104)
---------- ----------
Net cash used in financing
activities (5,550) (11,922)
---------- ----------
Net Increase in Cash and
Cash Equivalents 41 1,067
Cash and Cash Equivalents, Beginning
of Year 726 391
---------- ----------
Cash and Cash Equivalents, End of Period $ 767 $ 1,458
========== ==========
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 Six Months Ended
June 30, June 30,
-------------------- --------------------
2001 2002 2001 2002
--------- --------- --------- ---------
(In thousands)
Net Income $ 18,048 $ 5,108 $ 37,220 $ 7,750
Other Comprehensive Income,
Net of Taxes:
Change in value of cash
flow derivative
instruments used as
cash flow hedges 551 - 551 -
--------- --------- --------- ---------
Comprehensive Income $ 18,599 $ 5,108 $ 37,771 $ 7,750
========= ========= ========= =========
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 six months ended June 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
June 30, 2001:
Basic earnings per
common share $ 18,048,000 35,972,000 $ 0.50
==========
Effect of dilutive
stock options - 370,000
------------- ------------
Diluted earnings per
common share $ 18,048,000 36,342,000 $ 0.50
============= ============ ==========
For the Three Months Ended
June 30, 2002:
Basic earnings per
common share $ 5,108,000 36,109,000 $ 0.14
==========
Effect of dilutive
stock options - 296,000
------------- ------------
Diluted earnings per
common share $ 5,108,000 36,405,000 $ 0.14
============= ============ ==========
All options and their average exercise prices for the three months ended
June 30, 2001 were included in the computation of diluted earnings per share.
The following options and their average exercise prices were not included in the
computation of diluted earnings per share for the three months ended June 30,
2002 because the option exercise prices were greater than the average market
price of common shares:
2002
----------
Options 21,000
==========
Average exercise price $ 20.10
==========
7
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------- ------------ ----------
For the Six Months Ended
June 30, 2001:
Basic earnings per
common share $ 37,220,000 35,942,000 $ 1.04
==========
Effect of dilutive
stock options - 368,000
------------- ------------
Diluted earnings per
common share $ 37,220,000 36,310,000 $ 1.03
============= ============ ==========
For the Six Months Ended
June 30, 2002:
Basic earnings per
common share $ 7,750,000 36,072,000 $ 0.21
==========
Effect of dilutive
stock options - 264,000
------------- ------------
Diluted earnings per
common share $ 7,750,000 36,336,000 $ 0.21
============= ============ ==========
All options and their average exercise prices for the six months ended June
30, 2001 were included in the computation of diluted earnings per share. The
following options and their average exercise prices were not included in the
computation of diluted earnings per share for the six months ended June 30, 2002
because the option exercise prices were greater than the average market price of
common shares:
2002
----------
Options 174,000
==========
Average exercise price $ 17.19
==========
8
NOTE 3 - 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 June 30, 2002. 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. 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 and disposal activities initiated after December 31, 2002. We have not yet
determined the effect of the adoption of FAS 145 and FAS 146 on our financial
position, results of operations or cashflows.
9
NOTE 4 - INDUSTRY SEGMENT INFORMATION
- -------------------------------------
The company has two business segments: Contract Drilling, and Oil and
Natural Gas, representing its two strategic business units offering different
products and services. The Contract Drilling segment provides land contract
drilling of oil and natural gas wells and the Oil and Natural Gas segment is
engaged in the development, acquisition and production of oil and natural gas
properties. The company evaluates the performance of its operating segments
based on operating income, which is defined as operating revenues less operating
expenses and depreciation, depletion and amortization. The company has natural
gas production in Canada, which is not significant. Information regarding the
company's operations by industry segment for the three and six month periods
ended June 30, 2001 and 2002 is as follows:
Three Months Ended Six Months Ended
June 30, June 30,
2001 2002 2001 2002
---------- ---------- ---------- ----------
(In thousands)
Revenues:
Contract drilling $ 44,836 $ 25,841 $ 80,336 $ 52,555
Oil and natural gas 25,522 18,668 60,242 30,629
Other 729 244 952 299
---------- ---------- ---------- ----------
$ 71,087 $ 44,753 $ 141,530 $ 83,483
========== ========== ========== ==========
Operating Income (1):
Contract drilling $ 17,237 $ 2,776 $ 27,088 $ 7,547
Oil and natural gas 14,854 7,519 38,417 9,263
---------- ---------- ---------- ----------
32,091 10,295 65,505 16,810
General and
administrative
expense (3,031) (2,013) (4,834) (4,042)
Interest expense (719) (229) (1,691) (516)
Other income - net 729 244 952 299
---------- ---------- ---------- ----------
$ 29,070 8,297 $ 59,932 $ 12,551
========== ========== ========== ==========
10
(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.
11
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 June 30, 2002, and the related consolidated
condensed statements of operations and comprehensive income for the three and
six month periods ended June 30, 2002 and 2001 and cash flows for the six month
period ended June 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, 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 L L P
Tulsa, Oklahoma
July 23, 2002
12
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 June 30, 2002, we had cash totaling $1,458,000 and we had borrowed
$20.0 million of the $40.0 million we have elected to have available under our
loan agreement.
The following summarizes certain financial information on June 30, 2002 and
for the six months ended June 30, 2002:
Working capital $ 12,361,000
Net income $ 7,750,000
Net cash provided by
operating activities $ 40,811,000
Long-term debt $ 20,000,000
Shareholders' equity $ 288,179,000
Ratio of long-term debt to
total capitalization 6%
The following table summarizes certain operating information for the first
six months of 2001 and 2002:
Percent
2001 2002 Change
----------- ----------- --------
Oil production (Bbls) 253,000 227,000 (10%)
Natural gas production (Mcf) 9,509,000 9,653,000 2%
Average oil price received $ 26.39 $ 19.83 (25%)
Average natural gas price
received $ 5.45 $ 2.53 (54%)
Average number of our drilling
rigs in use during the
period 48.0 33.0 (31%)
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.
13
Borrowing under our loan agreement totaled $30.0 million at December 31, 2001
and $18.3 million on July 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 more fully set
out in the loan agreement.
The interest rate on our bank debt was 2.88 percent and 2.89 percent at
June 30, 2002 and July 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 $20.0 million and $18.0 million at June 30, 2002 and July 23, 2002,
respectively.
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 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.
14
The collar had a floor of $26.00 per barrel and a ceiling of $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 second quarter of
2001, the June collar contract increased natural gas revenues by $516,000. The
July collar was recognized on our June 30, 2001 balance sheet at $551,000, 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 second quarter of 2002,
our natural gas hedging transactions had no effect on our natural gas revenues
and the value of the remaining months contracts was not material at June 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 about 89 percent
of our total oil and natural gas reserves. Any noticeable change in natural gas
prices has a significant affect on our revenues, cash flow and the value of our
oil and natural gas reserves.
Based on our 2002 first six month production, a $.10 per Mcf change in what
we are paid for our natural gas production would result in a corresponding
$150,000 per month ($1,800,000 annualized) change in our pre-tax cash flow. Our
first six month 2002 average natural gas price was $2.53 compared to an average
natural gas price of $5.45 received in the first six months of 2001. 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 six months 2002 average
oil price was $19.83 compared with an average oil price of $26.39 received in
the first six 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 of the carrying value of our oil and natural gas properties. Also, price
declines can also 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.
15
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 check the information available
to us about these buyers in an effort to reduce any possible future adverse
impact to us.
Our decisions on whether we try 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 33 wells in the first six months of 2002
compared to 64 wells in the first six months 2001. Based on current prices, we
plan to drill an estimated 125 wells and expect to make total capital
expenditures of about $55 million for exploration, development drilling and
acquisition of oil and natural gas properties 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, 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.
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 six months of 2002 was 33.0 rigs
compared with 48.0 rigs for the first six months of 2001.
As demand for our rigs increased during 2001 so did the dayrates we
received. Our average dayrate reached $11,142 by September of 2001. However, as
demand began to decrease, so did our rates. Our average dayrate in the first six
months of 2002 was $8,055 compared to $9,486 for the first six months of 2001.
Based on the average utilization of our rigs in the first six months of 2002, a
$100 per day change in dayrates has a $3,300 per day ($1,205,000 annualized)
change in our pre-tax operating cash flow.
16
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 parties. The profit received by our contract drilling segment of
$1,101,000 and $542,000 in the first six 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 June 24, 2002 we signed definitive agreements to acquire
twenty drilling rigs and related equipment for 7.22 million shares of our common
stock and $4.5 million in cash. 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. These acquisitions should be completed by the
middle of the third quarter. 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. The addition of these twenty rigs will bring our fleet to 75,
74 of which will be capable of operating. For 2002, we anticipate spending
approximately $20 million on our drilling operations excluding the twenty-rig
acquisition detailed above.
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 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 June 30, 2002, we owned a 40 percent equity interest in a natural gas
gathering and processing company. Our balance sheet investment and equity in the
company totaled $1.3 million at June 30, 2002. From time to time we may
guarantee the debt of this company. However, as of June 30, 2002 and July 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
17
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 will
acquire all of the issued and outstanding shares of Shenandoah and settle the
outstanding claims of Shenandoah's secured and unsecured creditors. The business
of LongBow and Shenandoah is to be combined upon the implementation of a Plan of
Arrangement conducted in accordance with the provisions of the Companies'
Creditors Arrangement Act (Canada) and, if required, the Business Corporations
Act (Alberta). Our investment of $346,000 in Shenandoah is part of other assets
in our consolidated balance sheet.
Outlook. We expect that for the balance of 2002 the number of our rigs
working will remain at second quarter levels and that dayrates should stay just
above $7,500 per day depending mainly on the price of natural gas for the
remainder of 2002 and beyond.
Critical Accounting Policies. We account for our oil and natural gas
exploration and development activities using the full cost method of accounting.
Under this method, all costs incurred in the acquisition, exploration and
development of oil and natural gas properties are capitalized. At the end of
each quarter, the net capitalized costs of our oil and natural gas properties is
limited to the lower of unamortized cost or a ceiling. The ceiling is defined as
the sum of the present value (10 percent discount rate) of estimated future net
revenues from proved reserves, based on period-end oil and natural gas prices,
plus the lower of cost or estimated fair value of unproved properties included
in the costs being amortized less related income taxes. If the net capitalized
costs of our oil and natural gas properties exceed the ceiling, we are subject
to a write-down to the extent of such excess. A ceiling test write-down is a
non-cash charge to earnings. If required, it reduces earnings and impacts
stockholders' equity in the period of occurrence and results in lower
depreciation, depletion and amortization expense in future periods. Once
incurred, a write-down cannot be reversed even if prices subsequently recover.
The risk that we will be required to write-down the carrying value of our
oil and natural gas properties increases when oil and natural gas prices are
depressed or if we have large downward revisions in our estimated proved
reserves. Application of these rules during periods of relatively low oil or
natural gas prices, even if temporary, increases the chance of a ceiling test
write-down. Based on oil and natural gas prices in effect on June 30, 2002
($3.01 per Mcf for natural gas and $24.40 per barrel for oil), the unamortized
cost of our domestic oil and natural gas properties did not exceed the ceiling
of our proved oil and natural gas reserves. Natural gas prices remain erratic
and any significant declines below quarter-end prices used in the reserve
evaluation could result in a ceiling test write-down in following quarterly
reporting periods.
The value of our oil and natural gas reserves is used to 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
18
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.
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.
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. 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.
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;
19
. expansion and other development trends of the oil and natural gas
industry;
. our business strategy;
. production of our oil and natural gas reserves;
. expansion and growth of our business and operations;
. availability of drilling rigs and rig related equipment;
. drilling rig use, revenues and costs; and
. availability of qualified labor.
These statements are based on certain assumptions and analyses made by us
in light of our experience and our view of historical trends, current conditions
and expected future developments as well as other factors we believe are proper
in the circumstances. However, whether actual results and developments will
conform to our expectations and predictions is subject to many risks and
uncertainties which could cause actual results to differ materially from our
expectations, including:
. the risk factors discussed in this document;
. general economic, market or business conditions;
. the nature or lack of business opportunities that may be presented to
and pursued by us;
. demand for land drilling services;
. changes in laws or regulations; and
. other reasons, most of which are beyond our control.
A more thorough discussion of forward-looking statements with the possible
impact of some of these risks and uncertainties is provided in our Annual Report
on Form 10-K filed with the Securities and Exchange Commission. We encourage you
to get and read that document.
20
RESULTS OF OPERATIONS
- ---------------------
Second Quarter 2002 versus Second Quarter 2001
- ----------------------------------------------
Provided below is a comparison of selected operating and financial data for
the second quarter of 2002 verses the second quarter of 2001:
Second Second Percent
Quarter 2001 Quarter 2002 Change
--------------- --------------- ---------
Total Revenue $ 71,087,000 $ 44,753,000 (37%)
Net Income $ 18,048,000 $ 5,108,000 (72%)
Oil and Natural Gas:
Revenue $ 25,522,000 $ 18,668,000 (27%)
Average natural gas price (Mcf) $ 4.37 $ 3.00 (31%)
Average oil price (Bbl) $ 25.69 $ 22.59 (12%)
Natural gas production (Mcf) 4,871,000 5,097,000 5%
Oil production (Bbl) 129,000 110,000 (15%)
Operating profit
(revenue less operating costs) $ 19,996,000 $ 13,507,000 (32%)
Operating margin 78% 72%
Depreciation, depletion and
amortization rate (Mcfe) $ 0.90 $ 1.03 14%
Depreciation, depletion and
amortization $ 5,142,000 $ 5,988,000 16%
Drilling:
Revenue $ 44,836,000 $ 25,841,000 (42%)
Percentage of revenue from
daywork contracts 100% 85% (15%)
Average number of rigs in use 50.0 33.2 (34%)
Average dayrate on daywork
contracts $ 10,202 $ 7,698 (25%)
Operating profit
(revenue less operating costs) $ 20,839,000 $ 5,704,000 (73%)
Operating margin 46% 22%
Depreciation $ 3,602,000 $ 2,928,000 (19%)
General and Administrative Expense $ 3,031,000 $ 2,013,000 (34%)
Interest Expense $ 719,000 $ 229,000 (68%)
Average Interest Rate 5.9% 3.0% (49%)
Average Long-Term Debt Outstanding $ 45,644,000 $ 23,470,000 (49%)
21
Significantly lower oil and natural gas prices, which led to lower demand
for our drilling rigs and decreases in contract drilling dayrates all
contributed to decreases in our revenues and net income in the second quarter of
2002 as compared to the second quarter of 2001.
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 second quarter of 2002 and the second quarter of 2001.
Increased natural gas production partially offset the decrease in natural gas
prices. Total operating cost decreased due to 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 higher equivalent production between the comparative
quarters and an increase in our DD&A rate per Mcfe. We are experiencing higher
cost per Mcfe for the discovery of new reserves resulting in an increase in the
DD&A rate.
Reduced natural gas prices 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 second quarter of 2002 and the second quarter of 2001.
Approximately 15 percent of our total drilling revenues in the second quarter of
2002 came from footage and turnkey contracts, which had profit margins lower
than our daywork contracts. We did not drill any footage or turnkey wells in the
second quarter of 2001. Contract drilling depreciation decreased due to lower
rig use.
General and administrative expense was higher in the second quarter of 2001
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. The liability
associated with this expense will be paid in monthly payments starting in July
2003 and continuing through June 2009. Our total interest expense is lower due
to lower interest rates along with a substantial reduction in our long-term
debt.
22
Six Months 2002 versus Six Months 2001
- --------------------------------------
Provided below is a comparison of selected operating and financial data for
the first six months of 2002 verses the first six months of 2001:
First Six First Six Percent
Months of 2001 Months of 2002 Change
--------------- --------------- ---------
Total Revenue $ 141,530,000 $ 83,483,000 (41%)
Net Income $ 37,220,000 $ 7,750,000 (79%)
Oil and Natural Gas:
Revenue $ 60,242,000 $ 30,629,000 (49%)
Average natural gas price (Mcf) $ 5.45 $ 2.53 (54%)
Average oil price (Bbl) $ 26.39 $ 19.83 (25%)
Natural gas production (Mcf) 9,509,000 9,653,000 2%
Oil production (Bbl) 253,000 227,000 (10%)
Operating profit
(revenue less operating costs) $ 48,237,000 $ 20,520,000 (57%)
Operating margin 80% 67%
Depreciation, depletion and
amortization rate (Mcfe) $ 0.88 $ 1.01 15%
Depreciation, depletion and
amortization $ 9,820,000 $ 11,257,000 15%
Drilling:
Revenue $ 80,336,000 $ 52,555,000 (35%)
Percentage of revenue from
daywork contracts 100% 91% (9%)
Average number of rigs in use 48.0 33.0 (31%)
Average dayrate on daywork
contracts $ 9,486 $ 8,055 (15%)
Operating profit
(revenue less operating costs) $ 33,909,000 $ 13,286,000 (61%)
Operating margin 42% 25%
Depreciation $ 6,821,000 $ 5,739,000 (16%)
General and Administrative Expense $ 4,834,000 $ 4,042,000 (16%)
Interest Expense $ 1,691,000 $ 516,000 (69%)
Average Interest Rate 6.6% 3.0% (55%)
Average Long-Term Debt Outstanding $ 49,311,000 $ 26,075,000 (47%)
23
Significantly lower oil and natural gas prices, which led to lower demand
for our drilling rigs and decreases in contract drilling dayrates all
contributed to decreases in our revenues and net income in the first six months
of 2002 as compared to the first six months of 2001.
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 six months of 2002 and the first six months of
2001. On an Mcfe basis, production declines in oil were offset by increased
natural gas production between the comparative periods. Total operating cost
decreased due to 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 resulting in an increase in the DD&A rate.
Reduced natural gas prices 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 six months of 2002 and the first six months of 2001.
Approximately 9 percent of our total drilling revenues in the first six months
of 2002 came from footage and turnkey contracts, which had profit margins less
than our daywork contracts. We did not drill any footage or turnkey wells in the
first half of 2001. Contract drilling depreciation decreased due to lower rig
use.
General and administrative expense was higher in the first six months of
2001 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. Our
total interest expense is lower due to lower interest rates along with a
substantial reduction in our long-term debt.
24
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
- --------------------------
Not applicable
Item 2. Changes in Securities and Use of Proceeds
- --------------------------------------------------
Not applicable
Item 3. Defaults Upon Senior Securities
- ----------------------------------------
Not applicable
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
On May 1, 2002 we held our Annual Meeting of Stockholders. At the
meeting the following matters were voted on, with each receiving the
votes indicated:
I. Election of Nominees King P. Kirchner, Don Cook and
J. Michael Adcock to serve as directors.
Numbers of Against or
Nominee Votes For Withheld
---------------------- ------------ ------------
King P. Kirchner 30,601,598 686,072
Don Cook 30,939,363 348,307
J. Michael Adcock 30,942,331 345,339
The following directors, whose term of office did not expire
at the annual meeting, continue as directors of the Company:
John G. Nikkel, John S. Zink, Earle Lamborn, William B.
Morgan and John H. Williams.
II. Ratification of the appointment of
PricewaterhouseCoopers L L P as the Company's
independent certified public accountants for
the fiscal year 2002.
For - 30,976,301
Against - 267,596
Abstain - 43,773
25
Item 5. Other Information
- --------------------------
Not applicable
Item 6. Exhibits and Reports on Form 8-K
- -----------------------------------------
(a) Exhibits:
15 Letter re: Unaudited Interim Financial Information.
(b) No reports on Form 8-K were filed during the quarter ended
June 30, 2002.
26
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
UNIT CORPORATION
Date: August 9, 2002 By: /s/ John G. Nikkel
--------------------------- ------------------------------
JOHN G. NIKKEL
President, Chief Executive
Officer, Chief Operating
Officer and Director
Date: August 9, 2002 By: /s/ Larry D. Pinkston
--------------------------- ------------------------------
LARRY D. PINKSTON
Vice President, Chief
Financial Officer
and Treasurer
27