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, 2001
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 35,985,367
---------------------------- ----------
Class Outstanding at October 23, 2001
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, 2000 and September 30, 2001 . . . . . . . . 2
Consolidated Condensed Statements of Operations
Three and Nine Months Ended September 30, 2000 and 2001 . 3
Consolidated Condensed Statements of Cash Flows
Nine Months Ended September 30, 2000 and 2001 . . . . . . 4
Consolidated Condensed Statements of Comprehensive
Income Three and Nine Months Ended
September 30, 2000 and 2001 . . . . . . . . . . . . . . . 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
Item 3. Quantitative and Qualitative Disclosures about
Market Risk . . . . . . . . . . . . . . . . . . . . . . . 19
PART II. Other Information
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . . 21
Item 2. Changes in Securities and Use of Proceeds . . . . . . . . 21
Item 3. Defaults Upon Senior Securities. . . . . . . . . . . . . 21
Item 4. Submission of Matters to a Vote of Security Holders . . . 21
Item 5. Other Information . . . . . . . . . . . . . . . . . . . . 21
Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . . 21
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
1
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS (UNAUDITED)
December 31, September 30,
2000 2001
----------- -----------
(In thousands)
ASSETS
------
Current Assets:
Cash and cash equivalents $ 726 $ 986
Accounts receivable 40,220 47,593
Other 5,071 9,125
----------- -----------
Total current assets 46,017 57,704
----------- -----------
Property and Equipment:
Total cost 561,047 640,606
Less accumulated depreciation, depletion,
amortization and impairment 270,690 296,247
----------- -----------
Net property and equipment 290,357 344,359
----------- -----------
Other Assets 9,914 8,630
----------- -----------
Total Assets $ 346,288 $ 410,693
=========== ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------
Current Liabilities:
Current portion of long-term
liabilities and debt $ 1,627 $ 1,850
Accounts payable 21,012 20,088
Accrued liabilities 10,033 14,834
----------- -----------
Total current liabilities 32,672 36,772
----------- -----------
Long-Term Debt 54,000 38,000
----------- -----------
Other Long-Term Liabilities 3,597 4,073
----------- -----------
Deferred Income Taxes 41,479 62,920
----------- -----------
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, 35,768,344 and
36,005,367 shares issued, respectively 7,154 7,200
Capital in excess of par value 139,872 141,090
Retained earnings 67,514 120,365
Accumulated other comprehensive income - 448
Treasury stock, at cost, (0 and 20,000
shares, respectively) - (175)
----------- -----------
Total shareholders' equity 214,540 268,928
----------- -----------
Total Liabilities and Shareholders' Equity $ 346,288 $ 410,693
=========== ===========
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,
---------------------- ----------------------
2000 2001 2000 2001
---------- ---------- ---------- ----------
(In thousands except per share amounts)
Revenues:
Contract drilling $ 29,890 $ 50,690 $ 76,234 $ 131,026
Oil and natural gas 24,584 17,410 58,234 77,652
Other 314 299 1,134 1,251
---------- ---------- ---------- ----------
Total revenues 54,788 68,399 135,602 209,929
---------- ---------- ---------- ----------
Expenses:
Contract drilling:
Operating costs 23,024 24,978 60,957 71,405
Depreciation
and amortization 3,286 3,872 8,595 10,693
Oil and natural gas:
Operating costs 5,121 5,332 13,759 17,337
Depreciation,
depletion,
amortization and
impairment 4,889 6,641 13,474 16,461
General and
administrative 1,534 1,731 4,558 6,565
Interest 1,312 675 3,913 2,366
---------- ---------- ---------- ----------
Total expenses 39,166 43,229 105,256 124,827
---------- ---------- ---------- ----------
Income Before Income
Taxes 15,622 25,170 30,346 85,102
---------- ---------- ---------- ----------
Income Tax Expense:
Current 532 3,251 610 10,990
Deferred 5,405 6,288 10,846 21,261
---------- ---------- ---------- ----------
Total income
taxes 5,937 9,539 11,456 32,251
---------- ---------- ---------- ----------
Net Income $ 9,685 $ 15,631 $ 18,890 $ 52,851
========== ========== ========== ==========
Net Income Per Common
Share:
Basic $ 0.27 $ 0.43 $ 0.53 $ 1.47
========== ========== ========== ==========
Diluted $ 0.27 $ 0.43 $ 0.52 $ 1.46
========== ========== ========== ==========
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,
-----------------------
2000 2001
---------- ----------
(In thousands)
Cash Flows From Operating Activities:
Net income $ 18,890 $ 52,851
Adjustments to reconcile net income
to net cash provided (used) by
operating activities:
Depreciation, depletion,
amortization
and impairment 22,373 27,642
Deferred tax expense 10,846 21,261
Other (528) 1,816
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable (14,214) (6,652)
Accounts payable (1,266) 7,118
Other - net 1,274 72
---------- ----------
Net cash provided by
operating activities 37,375 104,108
---------- ----------
Cash Flows From (Used In) Investing
Activities:
Capital expenditures (36,091) (83,824)
Proceeds from disposition of assets 4,170 2,125
Other-net (2,753) (498)
---------- ----------
Net cash used in
investing activities (34,674) (82,197)
---------- ----------
Cash Flows From (Used In) Financing
Activities:
Net borrowings (payments) under
line of credit (7,039) (16,000)
Net payments of notes payable
and other long-term debt (308) -
Proceeds from stock 185 606
Acquisition of treasury stock - (175)
Book overdrafts 2,586 (6,082)
---------- ----------
Net cash used in financing
activities (4,576) (21,651)
---------- ----------
Net Increase (Decrease) in Cash
and Cash Equivalents (1,875) 260
Cash and Cash Equivalents, Beginning
of Year 2,647 726
---------- ----------
Cash and Cash Equivalents, End of Period $ 772 $ 986
========== ==========
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,
---------------------- ----------------------
2000 2001 2000 2001
---------- ---------- ---------- ----------
(In thousands)
Net Income $ 9,685 $ 15,631 $ 18,890 $ 52,851
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 $ 9,685 $ 15,528 $ 18,890 $ 53,299
========== ========== ========== ==========
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, 2001 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, 2000. 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 a report within the meaning
of Section 7 and 11 of that Act and the independent accountant's 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, 2000:
Basic earnings per
common share $ 9,685,000 35,733,000 $ 0.27
==========
Effect of dilutive
stock options - 457,000
------------- -------------
Diluted earnings per
common share $ 9,685,000 36,190,000 $ 0.27
============= ============= ==========
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
============= ============= ==========
All options and their average exercise prices for the three months ended
September 30, 2000 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
September 30, 2001 because the option exercise prices were greater than the
average market price of common shares:
2001
----------
Options 170,000
==========
Average exercise price $ 16.38
==========
7
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------- ------------- ----------
For the Nine Months Ended
September 30, 2000:
Basic earnings per
common share $ 18,890,000 35,711,000 $ 0.53
==========
Effect of dilutive
stock options - 405,000
------------- -------------
Diluted earnings per
common share $ 18,890,000 36,116,000 $ 0.52
============= ============= ==========
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
============= ============= ==========
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, 2000 and 2001 because the option exercise prices were greater than
the average market price of common shares:
2000 2001
---------- ----------
Options 17,500 153,000
========== ==========
Average exercise price $ 12.19 $ 16.79
========== ==========
8
NOTE 3 - NEW ACCOUNTING PRONOUNCEMENTS
--------------------------------------
On January 1, 2001, the Company adopted Statement of Financial Accounting
Standard No. 133 (subsequently amended by Financial Accounting Standard No.'s
137 and 138), Accounting for Derivative Instruments and Hedging Activities ("FAS
133"). This statement requires all derivatives to be recognized on the balance
sheet and measured at fair value. If a derivative is designated as a cash flow
hedge, the Company is required to measure the effectiveness of the hedge, or the
degree that the gain (loss) for the hedging instrument offsets the loss (gain)
on the hedged item, at each reporting period. The effective portion of the gain
(loss) on the derivative instrument is recognized in other comprehensive income
as a component of equity and subsequently reclassified into earnings when the
forecasted transaction affects earnings. The ineffective portion of a
derivative's change in fair value is required to be recognized in earnings
immediately. Derivatives that do not qualify for hedge treatment under FAS 133
must be recorded at fair value with gains (losses) recognized in earnings in the
period of change. The Company periodically enters into derivative commodity
instruments to hedge its exposure to price fluctuations on oil and natural gas
production. Such instruments include regulated natural gas and crude oil
futures contracts traded on the New York Mercantile Exchange (NYMEX) and over-
the-counter swaps and basic hedges with major energy derivative product
specialists. At September 30, 2001, the Company was holding two natural gas
derivatives, which qualify as cash flow hedges under FAS 133. The collar
contracts were for approximately 38 percent of the Company's daily natural gas
production. Both contracts have a floor of $2.50 and one has a ceiling of $3.68
and the other a ceiling of $4.25. In the third quarter of 2001, natural gas
derivatives used by the Company added an additional $1,049,000 to the Company's
natural gas revenues and for the nine months ended September 30, 2001, natural
gas derivatives used by the Company added an additional $1,565,000 to the
Company's natural gas revenues. The effective portion of the derivative also
increased accumulated other comprehensive income in the equity section of the
Company's balance sheet by $448,000, net of tax, at September 30, 2001.
During January and February of 2001, the Company had a collar contract for
approximately 25 percent of its daily oil production. The collar had a floor of
$26.00 and a ceiling of $33.00. The Company received $0.86 per barrel for
entering into the collar transaction. During the first quarter of 2001, the sum
of these hedging transactions yielded an increase in oil revenues of $17,200.
In the first quarter of 2000, the Company entered into swap transactions in
an effort to lock in a portion of its oil production at higher oil prices. These
transactions applied to approximately 50 percent of the Company's daily oil
production covering the period from April 1, 2000 to July 31, 2000 and 25
percent of the Company's daily oil production for August and September of 2000,
9
at prices ranging from $24.42 to $27.01. In the third quarter of 2000, the oil
swaps resulted in a reduction in oil revenues of $265,000 and for the nine
months ended September 30, 2000 the oil swaps resulted in a $464,000 reduction
in oil revenues.
On July 20, 2001, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 142, "Goodwill and Other
Intangible Assets" (FAS 142). For goodwill and intangible assets already on the
books, FAS 142 is effective for the fiscal years starting after December 15,
2001 (January 1, 2002 for Unit). 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 Company currently expenses $243,000 annually for the
amortization of goodwill.
In July 2001, the FASB issued Statement of Financial Accounting Standards
No. 143, Accounting for Asset Retirement Obligations ("SFAS 143"). SFAS 143, is
effective for fiscal years beginning after June 15, 2002 (January 1, 2003 for
Unit), and establishes an accounting standard requiring the recording of the
fair value of liabilities associated with the retirement of long-lived assets in
the period in which they are incurred. We do not believe the future impact from
the adoption of FAS 143 on our earnings and financial position will be material.
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, amortization and impairment. The Company
has natural gas production in Canada which is not significant. Information
regarding the Company's operations by industry segment for the three and nine
month periods ended September 30, 2000 and 2001 is as follows:
10
Three Months Ended Nine Months Ended
September 30, September 30,
2000 2001 2000 2001
---------- ---------- ---------- ----------
(In thousands)
Revenues:
Contract drilling $ 29,890 $ 50,690 $ 76,234 $ 131,026
Oil and natural gas 24,584 17,410 58,234 77,652
Other 314 299 1,134 1,251
---------- ---------- ---------- ----------
Total revenues $ 54,788 $ 68,399 $ 135,602 $ 209,929
========== ========== ========== ==========
Operating Income (1):
Contract drilling $ 3,580 $ 21,840 $ 6,682 $ 48,928
Oil and natural gas 14,574 5,437 31,001 43,854
---------- ---------- ---------- ----------
Total operating
income 18,154 27,277 37,683 92,782
General and
administrative
expense (1,534) (1,731) (4,558) (6,565)
Interest expense (1,312) (675) (3,913) (2,366)
Other income - net 314 299 1,134 1,251
---------- ---------- ---------- ----------
Income before
income taxes $ 15,622 $ 25,170 $ 30,346 $ 85,102
========== ========== ========== ==========
(1) Operating income is total operating revenues less operating expenses,
depreciation, depletion, amortization and impairment and does not include
non-operating revenues, general corporate expenses, interest expense or
income taxes.
11
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders
Unit Corporation
We have reviewed the accompanying consolidated condensed balance sheet of Unit
Corporation and subsidiaries as of September 30, 2001, and the related
consolidated condensed statements of operations for the three and nine month
periods ended September 30, 2001 and 2000 and cash flows for the nine month
period ended September 30, 2001 and 2000. 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 interim 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 auditing standards generally
accepted in the United States of America, the consolidated balance sheet as
of December 31, 2000, and the related consolidated statements of operations,
stockholders' equity and cash flows for the year then ended (not presented
herein); and in our report, dated February 7, 2001, 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, 2000, is fairly stated in all material respects in relation
to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers L L P
Tulsa, Oklahoma
October 23, 2001
12
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
---------------------------------------------------------------------------
FINANCIAL CONDITION
-------------------
On July 24, 2001, we signed a $100 million bank loan agreement. The
current commitment has been set, at our election, at $60 million. Although, the
current value of our assets under the latest loan value computation supported
the full $100 million, we elected to set the loan commitment at $60 million in
order to reduce costs. Each year on April 1 and October 1 our banks redetermine
the loan value. This value is primarily determined to be 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
terminates on May 1, 2005 followed by a three-year term loan. At September 30,
2001 and October 23, 2001, borrowings under our loan agreement totaled $37.0
million. We are charged a facility fee of .375 of 1 percent on any unused
portion of the available borrowing value.
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. Subsequent to 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, at any time
between the date of the agreement and 3 days prior to the conversion date 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 a number of conditions
all as more fully set out in the loan agreement.
The interest rate on our bank debt was 4.7 percent at September 30, 2001
and October 23, 2001. 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 available borrowing value. The Libor Rate may be fixed
for periods of up to 30, 60, 90 or 180 days with the remainder of our bank debt
being subject to the Chase Manhattan Bank, N. A. 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 $37.0 million at September 30, 2001 and October 23, 2001.
13
The loan agreement also contains a number of covenants including the
requirements that we maintain:
. consolidated tangible 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.
Our shareholders' equity at September 30, 2001 was $268.9 million giving us
a ratio of long-term debt-to-total capitalization of 12 percent. Our primary
source of funds consists of the cash flow from our operating activities and
borrowings under our bank loan agreement. Net cash provided by our operating
activities in the first nine months of 2001 was $104.1 million compared to $37.4
million in 2000. We had working capital of $20.9 million at September 30, 2001.
Our first nine month 2001 capital expenditures were $81.9 million (excludes $1.9
million from previous year's accounts payable) of which $39.7 million was spent
on our oil and natural gas operations and $42.2 million on our contract drilling
operations.
Our oil and natural gas operations drilled 94 wells in the first nine
months of 2001. We anticipate that we will participate in the drilling of
approximately 125 total wells during 2001 and spend approximately $50 million
drilling or buying oil and natural gas properties in 2001.
In January 2001, we purchased a 750 horse power diesel electric rig with a
13,000 foot depth capacity for $3.2 million. This new rig is working in the Gulf
Coast region. In February 2001, we purchased a 1,000 horse power, winterized,
mechanical, rig, with a 16,000 foot depth capacity, for $2.5 million. This rig
is working in the Rocky Mountain region. In May we acquired two diesel electric
rigs with depth capacities of 18,000 and 20,000 feet, for $7.8 million. These
two rigs began rigging up in the gulf coast region late in the second quarter
and are now working in that region. We have also acquired a 16,000 foot depth
capacity, diesel electric, rig from Indonesia. This rig will, depending on
industry conditions, be placed in service when conditions warrant. The
completion of the addition of these five rigs brings our fleet to 55, 54 of
which are currently capable of operating. We anticipate that we will have total
capital expenditures of approximately $50 million for the year for the purchase
of the new drilling rigs, additional drilling rig components and refurbishments
to existing rigs.
Most of our capital expenditures are discretionary and directed toward
future growth in both segments of our operations. Current operations do not
depend on our ability to obtain funds outside of our loan agreement. Future
decisions to acquire or drill on oil and natural gas properties will depend on
prevailing or anticipated market conditions, potential return on investment,
14
future drilling potential and the availability of financing, thus providing us
with a large degree of flexibility in determining when and if to incur such
costs.
The prices we received for the sale of our natural gas in the first nine
months of 2001 increased 40 percent above the prices we received during the
first nine months of 2000. Average oil prices over the same periods decreased 2
percent. For the first nine months of 2001, our average natural gas price was
$4.54 per Mcf and our average oil price was $25.59 per barrel. Natural gas
prices are influenced by weather conditions and supply and demand imbalances,
particularly in the domestic market, and by world wide oil price levels.
Domestic oil price levels continue to be primarily influenced by world market
developments. Since natural gas comprises approximately 89 percent of our total
oil and natural gas reserves, large drops in spot market natural gas prices have
a significant adverse effect on the value of our oil and natural gas reserves.
Natural gas prices dropped substantially in the third quarter of 2001, but
rebounded shortly after the end of the quarter. Cash prices at the end of the
third quarter did not cause us to reduce the carrying value of our oil and
natural gas properties, but any further price declines below the end of the
quarter cash price, could cause us to reduce the carrying value of our oil and
natural gas properties. We experienced a 78 percent decline in natural gas
prices received in January, 2001 as compared to September, 2001. This decrease
has adversely affected our cash flow by reducing oil and natural gas revenues
and has reduced the rates we receive for our contract drilling rigs and the
demand for our rigs. This price decline and any additional price decreases, if
sustained, will adversely affect our future cash flow and, if extended over a
long period, will lessen not only the demand for our contract drilling rigs but
also the rates we will receive even further. Such declines in natural gas and
oil prices could also adversely affect the semi-annual determination of the loan
value under our bank loan agreement since this determination is primarily based
on the value of our oil and natural gas reserves and, to a lesser extent, on the
value of a part of our drilling rigs. Such a reduction would reduce the amount
available to us under our loan agreement which, in turn, would affect our
ability to carry out our planned capital projects.
In an attempt to reduce the impact of price fluctuations, we periodically
use hedging strategies to hedge the price we will receive for a portion of our
future oil and natural gas production. We entered into a collar contract for
approximately 25 percent of our daily oil production for the period covering
November 1, 2000 to February 28, 2001. 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 collar transaction. During the first quarter of 2001, the sum
of this 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 natural gas 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 have a floor price of $2.50. One contract has a
ceiling price of $3.68 and the other contract has a ceiling price of $4.25.
During the third quarter our natural gas collar contracts increased natural gas
revenues by $1,049,000 and for the nine months ended September 30, 2001 the
15
collar contracts have increased natural gas revenues by $1,565,000. The October
and November collar was recognized on our September 30, 2001 balance sheet at
$448,000, net of tax, in accumulated other comprehensive income.
Generally, during the past 17 years, our contract drilling operations have
encountered significant competition. Starting in the last half of 1999 and
continuing through the first nine months of 2001, we experienced significant
improvement in rig utilization and dayrates. However, despite this recent
improvement in rig demand, and especially with the recent downturn in natural
gas prices in the third quarter of 2001, we anticipate that the use of our
drilling rigs will continue to be significantly influenced by the prevailing
price for oil and natural gas as well as from competition within our industry.
In addition, our ability to work our drilling rigs at any given time is also
influenced by a number of other factors including the availability of labor and
our ability to supply the type of equipment required.
Although we have not encountered major difficulty in hiring and retaining
rig crews, such shortages have in the past occurred in the industry. Should
industry conditions improve, we may experience shortages of qualified personnel
to operate our rigs, which would limit our ability to increase the number of our
rigs working and could have an adverse effect on our financial condition and
results of operations.
SAFE HARBOR STATEMENT
---------------------
Statements in this document as well as information contained in written
material, press releases and oral statements issued by or on behalf of 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 anticipate 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 expenditures;
. 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;
16
. expansion and growth of our business and operations;
. availability of drilling rigs and rig related equipment;
. drilling rig utilization, 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 perception of historical trends, current
conditions and expected future developments as well as other factors we believe
are appropriate in the circumstances. However, whether actual results and
developments will conform to our expectations and predictions is subject to a
number of 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 factors, 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 obtain and read that document.
RESULTS OF OPERATIONS
---------------------
Third Quarter 2001 versus Third Quarter 2000
--------------------------------------------
Our net income for the third quarter of 2001 was $15,631,000, as compared
to $9,685,000 for the same period in 2000. Increases in the number of our
drilling rigs utilized and the dayrates we received for the operation of our
drilling rigs contributed to the growth in our net income.
Revenue from the sale of our oil and natural gas decreased 29 percent in
the third quarter of 2001 as compared to the third quarter of 2000 primarily due
to a 31 percent and 11 percent decrease in the average prices we received for
natural gas and oil, respectively. Natural gas production decreased 2 percent
and oil production decreased 5 percent when compared to the third quarter of
2000.
In the third quarter of 2001, revenues from our contract drilling
operations increased by 70 percent as the average number of drilling rigs being
used increased from 43.1 in the third quarter of 2000 to 50.6 in 2001.
Increased rig utilization resulted from increases in demand for our rigs as
natural gas prices increased during the first six months of 2001. Revenues per
rig per day increased 46 percent in the third quarter of 2001 as compared to the
same period in 2000.
17
Operating margins (revenues less operating costs) for our oil and natural
gas operations were 69 percent in the third quarter of 2001 compared to 79
percent for the same period in 2000. This decrease resulted primarily from the
decrease in the average natural gas prices we received. Total operating costs
increased 4 percent due to increases in the net number of wells owned.
Our contract drilling operating margins increased from 23 percent in the
third quarter of 2000 to 51 percent in the third quarter of 2001. This increase
was generally due to increases in rig utilization and revenue per rig per day.
Total contract drilling operating costs were up 8 percent in 2001 versus 2000
primarily due to increased utilization.
Depreciation, depletion, amortization and impairment ("DD&A") of our oil
and natural gas properties increased 36 percent due primarily to a $1.6 million
impairment of our investment in a company which has oil and natural gas
properties located in Canada. Our average DD&A rate per Mcfe also increased to
$0.88 in the third quarter of 2001 compared to $0.84 for the same period in
2000. Contract drilling depreciation increased 18 percent due to the increase in
the number of rigs and the increase in rig utilization.
General and administrative expenses increased 13 percent in the third
quarter of 2001 when compared to the third quarter of 2000. Interest expense
decreased 49 percent between the comparative periods. The average interest rate
on all long-term debt decreased from 8.1 percent in the third quarter of 2000 to
5.0 percent in the third quarter of 2001 while our average outstanding debt
decreased 25 percent.
Nine Months 2001 versus Nine Months 2000
----------------------------------------
Our net income for the first nine months of 2001 was $52,851,000, compared
to $18,890,000 for the same period in 2000. Increases in natural gas prices,
production volumes, the number of our drilling rigs utilized and the dayrates we
received for the operation of our drilling rigs all contributed to the growth in
our net income.
Revenue from the sale of our oil and natural gas increased 33 percent in
the first nine months of 2001 as compared to the first nine months of 2000 due
to a 40 percent increase in average prices we received for natural gas. The
average oil price received decreased 2 percent in the first nine months of 200l
compared to the first nine months of 2000. Natural gas and oil production
increased 3 percent and 2 percent, respectively when compared to the first nine
months of 2000. Production increases from both our oil and natural gas were due
to the acceleration of our development drilling program as a result of rising
prices in the last half of 1999 into the first six months of 2001.
In the first nine months of 2001, revenues from our contract drilling
operations increased by 72 percent as the average number of drilling rigs being
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used increased from 38.5 in the first nine months of 2000 to 48.8 in 2001.
Increased rig utilization resulted from increases in demand for our rigs as
natural gas prices increased in the first six months of 2001. Revenues per rig
per day increased 37 percent in the first nine months of 2001 as compared to the
same period in 2000.
Operating margins (revenues less operating costs) for our oil and natural
gas operations were 78 percent in the first nine months of 2001 compared to 76
percent for the same period in 2000. This increase resulted primarily from the
increase in the average natural gas price we received. Total operating costs
increased 26 percent due to increases in the net number of wells owned and
workover expenses.
Our contract drilling operating margins increased from 20 percent in the
first nine months of 2000 to 46 percent in the first nine months of 2001. This
increase was generally due to increases in rig utilization and revenue per rig
per day. Total contract drilling operating costs were up 17 percent in 2001
versus 2000 due to increased utilization.
Depreciation, depletion, amortization and impairment ("DD&A") of our oil
and natural gas properties increased 22 percent due to increases in the average
DD&A rate, natural gas production volumes and a $1.6 million impairment of our
investment in a company which has oil and natural gas properties located in
Canada. The average DD&A rate per Mcfe increased to $0.88 in first nine months
of 2001 compared to $0.82 in the first nine months of 2000. Contract drilling
depreciation increased 24 percent due to the increase in the number of rigs
owned and higher rig utilization.
General and administrative expenses increased 44 percent. In the second
quarter of 2001, 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. Interest
expense decreased 40 percent between the comparative periods. The average
interest rate on all long-term debt decreased from 7.9 percent in the first nine
months of 2000 to 6.1 percent in the first nine months of 2001 while our average
outstanding debt decreased 24 percent.
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, we
periodically use hedging strategies to hedge the price we will receive for a
portion of our future oil and natural gas production. We entered into a collar
19
contract for approximately 25 percent of our daily oil production for the period
covering November 1, 2000 to February 28, 2001. 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 collar transaction. During the first quarter of
2001, the sum of these hedging transactions 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 production. Both
contracts have a floor price of $2.50. One contract has a ceiling price of $3.68
and the other contract has a ceiling price of $4.25. During the third quarter
our natural gas collar contracts increased natural gas revenues by $1,049,000
and for the nine months ended September 30, 2001 the collar contracts have
increased natural gas revenues by $1,565,000. The October and November collar
was recognized on our September 30, 2001 balance sheet at $448,000, net of tax,
in accumulated other comprehensive income. During the second and third quarters
of 2000 we had swap transactions covering from approximately 25 to 50 percent of
our daily oil production, at prices ranging from $24.42 to $27.01. These
transactions resulted in a reduction in our oil revenues of $265,000 and
$464,000 in the third quarter and first nine months of 2000, respectively.
20
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
--------------------------
Not applicable
Item 6. Exhibits and Reports on Form 8-K
-----------------------------------------
(a) Exhibits:
15 Letter re: Unaudited Interim Financial Information.
(b) On August 28, 2001, we filed a report on Form 8-K under Items 5 and
7. This Form 8-K reported that on April 19, 2001, the Company's
Board of Directors approved certain amendments to the Company's
Amended and Restated Certificate of Incorporation, By-laws, the
Rights Agreement, dated May 19, 1995, between the Company and
Chemical Bank, as Rights Agent, as well as the form of
Indemnification Agreement entered into between the Company and its
executive officers and directors. Copies of these various documents
and agreements, as amended, were filed as exhibits to the Form 8-K.
On September 5, 2001, we filed a report on Form 8-K under
Items 5 and 7. This Form 8-K reported that on August 30, 2001,
the Company announced that it's Board of Directors authorized
the purchase of up to one million shares of its common stock
with the share purchases to be made from time to time,
depending on market conditions. The shares may be purchased
21
either in the open market or through privately negotiated
transactions. The repurchase program does not obligate the
Company to acquire any specific number of shares and may be
discontinued at any time.
22
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: October 26, 2001 By: /s/ John G. Nikkel
--------------------------- ------------------------------
JOHN G. NIKKEL
President, Chief Executive
Officer, Chief Operating
Officer and Director
Date: October 26, 2001 By: /s/ Larry D. Pinkston
--------------------------- ------------------------------
LARRY D. PINKSTON
Vice President, Chief
Financial Officer
and Treasurer
23