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, 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 36,005,367
---------------------------- ----------
Class Outstanding at August 6, 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 June 30, 2001. . . . . . . . . . 2
Consolidated Condensed Statements of Operations
Three and Six Months Ended June 30, 2000 and 2001. . . 3
Consolidated Condensed Statements of Cash Flows
Six Months Ended June 30, 2000 and 2001. . . . . . . . 4
Consolidated Condensed Statements of Comprehensive
Income Three and Six Months Ended
June 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 . . . . . . . . . . . . . . . . . . . 22
Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . 22
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
1
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
- ------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS (UNAUDITED)
December 31, June 30,
2000 2001
---------- ----------
(In thousands)
ASSETS
- ------
Current Assets:
Cash and cash equivalents $ 726 $ 767
Accounts receivable 40,220 52,728
Other 5,071 9,850
---------- ---------
Total current assets 46,017 63,345
---------- ---------
Property and Equipment:
Total cost 561,047 618,127
Less accumulated depreciation, depletion,
amortization and impairment 270,690 287,305
---------- ----------
Net property and equipment 290,357 330,822
---------- ----------
Other Assets 9,914 10,605
---------- ----------
Total Assets $ 346,288 $ 404,772
========== ==========
LIABILITIES AND SHAREHOLDERS' EQUITY
- ------------------------------------
Current Liabilities:
Current portion of long-term liabilities
and debt $ 1,627 $ 1,890
Accounts payable 21,012 27,190
Accrued liabilities 10,033 11,516
----------- ----------
Total current liabilities 32,672 40,596
---------- ----------
Long-Term Debt 54,000 49,500
---------- ----------
Other Long-Term Liabilities 3,597 4,493
---------- ----------
Deferred Income Taxes 41,479 56,674
---------- ----------
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
35,977,367 shares issued, respectively 7,154 7,194
Capital in excess of par value 139,872 141,030
Accumulated other comprehensive income - 551
Retained earnings 67,514 104,734
---------- ----------
Total shareholders' equity 214,540 253,509
---------- ----------
Total Liabilities and Shareholders' Equity $ 346,288 $ 404,772
========== ==========
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,
---------------------- ----------------------
2000 2001 2000 2001
---------- ---------- ---------- ----------
(In thousands except per share amounts)
Revenues:
Contract drilling $ 24,596 $ 44,836 $ 46,344 $ 80,336
Oil and natural gas 18,921 25,522 33,650 60,242
Other 70 729 820 952
---------- ---------- ---------- ----------
Total revenues 43,587 71,087 80,814 141,530
---------- ---------- ---------- ----------
Expenses:
Contract drilling:
Operating costs 19,864 23,997 37,933 46,427
Depreciation
and amortization 2,768 3,602 5,309 6,821
Oil and natural gas:
Operating costs 4,662 5,526 8,638 12,005
Depreciation,
depletion and
amortization 4,413 5,142 8,585 9,820
General and
administrative 1,545 3,031 3,024 4,834
Interest 1,259 719 2,601 1,691
---------- ---------- ---------- ----------
Total expenses 34,511 42,017 66,090 81,598
---------- ---------- ---------- ----------
Income Before Income Taxes 9,076 29,070 14,724 59,932
---------- ---------- ---------- ----------
Income Tax Expense:
Current 46 3,342 78 7,739
Deferred 3,403 7,680 5,441 14,973
---------- ---------- ---------- ----------
Total income
taxes 3,449 11,022 5,519 22,712
---------- ---------- ---------- ----------
Net Income $ 5,627 $ 18,048 $ 9,205 $ 37,220
========== ========== ========== ==========
Net Income Per Common
Share:
Basic $ .16 $ .50 $ .26 $ 1.04
========== ========== ========== ==========
Diluted $ .16 $ .50 $ .26 $ 1.03
========== ========== ========== ==========
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,
----------------------
2000 2001
---------- ----------
(In thousands)
Cash Flows From Operating Activities:
Net income $ 9,205 $ 37,220
Adjustments to reconcile net income
to net cash provided (used) by
operating activities:
Depreciation, depletion, 14,081 16,970
and amortization
Deferred tax expense 5,441 14,973
Other (187) 1,851
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable (6,802) (11,621)
Accounts payable 3,439 7,268
Other - net (90) (3,532)
---------- ----------
Net cash provided by
operating activities 25,087 63,129
---------- ----------
Cash Flows From (Used In) Investing
Activities:
Capital expenditures (20,939) (57,873)
Proceeds from disposition of assets 1,421 1,147
Other-net (364) (812)
---------- ----------
Net cash used in
investing activities (19,882) (57,538)
---------- ----------
Cash Flows From (Used In) Financing
Activities:
Net borrowings (payments) under
line of credit (6,539) (4,500)
Net payments of notes payable
and other long-term debt (308) -
Proceeds from stock 133 540
Book overdrafts (450) (1,590)
---------- ----------
Net cash used in financing
activities (7,164) (5,550)
---------- ----------
Net Increase (Decrease) in Cash
and Cash Equivalents (1,959) 41
Cash and Cash Equivalents, Beginning
of Year 2,647 726
---------- ----------
Cash and Cash Equivalents, End of Period $ 688 $ 767
========== ==========
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,
---------------------- ----------------------
2000 2001 2000 2001
---------- ---------- ---------- ----------
(In thousands)
Net Income $ 5,627 $ 18,048 $ 9,205 $ 37,220
Other Comprehensive Income,
Net of Taxes:
Change in value of cash
flow derivative
instruments used as
cash flow hedges - 551 - 551
---------- ---------- ---------- ----------
Comprehensive Income $ 5,627 $ 18,599 $ 9,205 $ 37,771
========== ========== ========== ==========
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, 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 extent 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, 2000:
Basic earnings per
common share $ 5,627,000 35,719,000 $ 0.16
==========
Effect of dilutive
stock options - 431,000
------------- -------------
Diluted earnings per
common share $ 5,627,000 36,150,000 $ 0.16
============= ============= ==========
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
============= ============= ==========
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,
2000 because the option exercise prices were greater than the average market
price of common shares:
2000
----------
Options 17,500
==========
Average exercise price $ 12.19
==========
7
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------- ------------- ----------
For the Six Months Ended
June 30, 2000:
Basic earnings per
common share $ 9,205,000 35,722,000 $ 0.26
==========
Effect of dilutive
stock options - 364,000
------------- -------------
Diluted earnings per
common share $ 9,205,000 36,086,000 $ 0.26
============= ============= ==========
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
============= ============= ==========
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, 2000
because the option exercise prices were greater than the average market price of
common shares:
2000
----------
Options 20,000
==========
Average exercise price $ 12.08
==========
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 June 30, 2001, the Company was holding a natural gas derivative
which qualifies as a cash flow hedge under FAS 133. The collar contract was
for approximately 36 percent of the Company's daily natural gas production and
has a floor of $4.50 and a ceiling of $5.95. In the second quarter of 2001, the
natural gas derivative yielded an additional $516,000 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 $551,000, net of tax, at June 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 and 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,
at prices ranging from $24.42 to $27.01. In the second quarter of 2000, the oil
swaps yielded a reduction in oil revenues of $199,000.
9
On July 29, 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.
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, 2000 and 2001 is as follows:
10
Three Months Ended Six Months Ended
June 30, June 30,
2000 2001 2000 2001
---------- ---------- ---------- ----------
(In thousands)
Revenues:
Contract drilling $ 24,596 $ 44,836 $ 46,344 $ 80,336
Oil and natural gas 18,921 25,522 33,650 60,242
Other 70 729 820 952
---------- ---------- ---------- ----------
Total revenues $ 43,587 $ 71,087 $ 80,814 $ 141,530
========== ========== ========== ==========
Operating Income (1):
Contract drilling $ 1,964 $ 17,237 $ 3,102 $ 27,088
Oil and natural gas 9,846 14,854 16,427 38,417
---------- ---------- ---------- ----------
Total operating
income 11,810 32,091 19,529 65,505
General and
administrative
expense (1,545) (3,031) (3,024) (4,834)
Interest expense (1,259) (719) (2,601) (1,691)
Other income - net 70 729 820 952
---------- ---------- ---------- ----------
Income before
income taxes $ 9,076 $ 29,070 $ 14,724 $ 59,932
========== ========== ========== ==========
(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, 2001, and the related consolidated
condensed statements of operations for the three and six month periods ended
June 30, 2001 and 2000 and cash flows for the six month period ended June 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 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,
stockholder's 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
July 25, 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 by 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 June 30, 2001
and July 25, 2001, borrowings under our loan agreement totaled $48.5 million and
$46.0 million, respectively. 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 bank's notes. 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 5.1 percent at June 30, 2001 and 5.0
percent at July 25, 2001. At our election, any portion of our outstanding bank
debt may be fixed at the London Interbank Offered Rate ("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 $46.0 million at June 30,
2001 and July 25, 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 June 30, 2001 was $253.5 million giving us a
ratio of long-term debt-to-total capitalization of 16 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 six months of 2001 was $63.1 million compared to $25.1
million in 2000. We had working capital of $22.7 million at June 30, 2001. Our
first six month 2001 capital expenditures were $58.4 million ($500,000 net in
accounts payable) of which $26.6 million was spent on our oil and natural gas
operations and $31.8 million on our contract drilling operations.
Our oil and natural gas operations drilled 64 wells in the first six months
of 2001. If oil and natural gas prices are favorable, we anticipate that we will
participate in the drilling of approximately 130 total wells during 2001 and
spend approximately $55 million drilling or buying oil and natural gas
properties during the year.
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.
We have also acquired a 16,000 depth capacity, diesel electric, rig from
Indonesia and plan to move it to the Anadarko Basin. The completion of the
addition of these five rigs brings our fleet to 55 rigs. We anticipate that we
will have capital expenditures of approximately $45 million this year for new
drilling rigs, additional drilling rig components and refurbishments to existing
rigs.
Most of our capital expenditures are discretionary and directed toward
increasing oil and natural gas reserves and future growth. 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, 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.
14
The prices we received for the sale of our natural gas in the first six
months of 2001 increased 93 percent above the prices we received during the
first six months of 2000. Average oil prices over the same periods increased 2
percent. For the first six months of 2001, our average natural gas price was
$5.45 per Mcf and our average oil price was $26.39 per barrel. Natural gas
prices are influenced by weather conditions and supply 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 and price
declines could cause us to reduce the carrying value of our oil and natural gas
properties. We experienced a 61 percent decline in natural gas prices received
from January, 2001 to June, 2001. This decrease plus any additional price
decreases, if sustained, would also adversely affect our future cash flow by
reducing our oil and natural gas revenues and, if continued over an extended
period, could lessen not only the demand for our contract drilling rigs but also
the rates we would receive. Any 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 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 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 second quarter
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.
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 six months of 2001, we experienced significant
improvement in rig utilization and dayrates. However, despite this recent
improvement in rig demand, 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.
15
Although we have not encountered major difficulty in hiring and retaining
rig crews, such shortages have in the past occurred in the industry. 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;
. 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;
16
. 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
- ---------------------
Second Quarter 2001 versus Second Quarter 2000
- ----------------------------------------------
Our net income for the second quarter of 2001 was $18,048,000, as compared
to $5,627,000 for the same period in 2000. Increases in natural gas and oil
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 35 percent in
the second quarter of 2001 as compared to the second quarter of 2000 primarily
due to a 35 percent and 4 percent increase in the average prices we received for
natural gas and oil, respectively. Natural gas production increased 5 percent
and oil production increased 3 percent when compared to the second quarter of
2000. Due to rising prices since the last half of 1999 and into the first
quarter of 2001, we accelerated our development drilling program, improving
production volumes in both our oil and natural gas.
In the second quarter of 2001, revenues from our contract drilling
operations increased by 82 percent as the average number of drilling rigs being
used increased from 37.4 in the second quarter of 2000 to 50.0 in 2001.
Increased rig utilization resulted from increases in demand for our rigs as
natural gas prices increased. Revenues per rig per day increased 36 percent in
the second quarter 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 second quarter of 2001 compared to 75
percent for the same period in 2000. This increase resulted primarily from the
increase in the average natural gas prices we received. Total operating costs
increased 19 percent due to increases in the net number of wells owned.
17
Our contract drilling operating margins increased from 19 percent in the
second quarter of 2000 to 46 percent in the second 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 21 percent in 2001
versus 2000 primarily due to increased utilization.
Depreciation, depletion and amortization ("DD&A") of our oil and natural
gas properties increased 17 percent due to increases in the DD&A rate and
production. The average DD&A rate per Mcfe increased to $.90 in the second
quarter of 2001 compared to $.81 for the same period in 2000. Contract drilling
depreciation increased 30 percent due to the increase in the number of rigs and
the increase in rig utilization.
General and administrative expenses increased 96 percent in the second
quarter of 2001 when compared to the second quarter of 2000. 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 43 percent between the comparative periods. The average
interest rate on all long-term debt decreased from 7.8 percent in the second
quarter of 2000 to 5.9 percent in the second quarter of 2001 while our average
outstanding debt decreased 26 percent.
Six Months 2001 versus Six Months 2000
- --------------------------------------
Our net income for the first six months of 2001 was $37,220,000, compared
to $9,205,000 for the same period in 2000. Increases in natural gas and oil
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 79 percent in
the first six months of 2001 as compared to the first six months of 2000 due to
a 93 percent and 2 percent increase in average prices we received for natural
gas and oil, respectively. Both natural gas and oil production increased 5
percent when compared to the first six 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 quarter of 2001.
In the first six months of 2001, revenues from our contract drilling
operations increased by 73 percent as the average number of drilling rigs being
used increased from 36.1 in the first six months of 2000 to 48.0 in 2001.
Increased rig utilization resulted from increases in demand for our rigs as
natural gas prices increased. Revenues per rig per day increased 31 percent in
the first six months of 2001 as compared to the same period in 2000.
18
Operating margins (revenues less operating costs) for our oil and natural
gas operations were 80 percent in the first six months of 2001 compared to 74
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 39 percent due to increases in the net number of wells owned.
Our contract drilling operating margins increased from 18 percent in the
first six months of 2000 to 42 percent in the first six 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 22 percent in 2001
versus 2000 due to increased utilization.
Depreciation, depletion and amortization ("DD&A") of our oil and natural
gas properties increased 14 percent due to increases in the average DD&A rate
and production. The average DD&A rate per Mcfe increased to $0.88 in first six
months of 2001 compared to $0.81 in the first six months of 2000. Contract
drilling depreciation increased 28 percent due to the increase in the number of
rigs owned and higher rig utilization.
General and administrative expenses increased 60 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 35
percent between the comparative periods. The average interest rate on all long-
term debt decreased from 7.8 percent in the first six months of 2000 to 6.6
percent in the first six months of 2001 while our average outstanding debt
decreased 23 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 productio
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
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
19
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 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. During the second quarter of 2000 we had swap
transactions applying to approximately 50 percent of our daily oil production,
at prices ranging from $24.42 to $27.01. These transactions yielded a reduction
in our oil revenues of $199,000 in the second quarter of 2000.
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
- ------------------------------------------------------------
On May 2, 2001 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 Earle Lamborn, William B. Morgan and
John H. Williams to serve as directors.
Numbers of Against or
Nominee Votes For Withheld
---------------------- ------------ ------------
Earle Lamborn 26,792,822 2,470,272
William B. Morgan 29,138,353 124,741
John H. Williams 29,104,295 158,799
The following directors, whose term of office did not expire
at the annual meeting, continue as directors of the Company:
King P. Kirchner, Don Cook, J. Michael Adcock,
John G. Nikkel and John S. Zink.
II. Ratification of the appointment of PricewaterhouseCoopers L L P
as the Company's independent certified public accountants for
the fiscal year 2001.
For - 28,981,018
Against - 263,608
Abstain - 18,468
21
Item 5. Other Information
- --------------------------
Not applicable
Item 6. Exhibits and Reports on Form 8-K
- -----------------------------------------
(a) Exhibits:
10.1.25 Loan Agreement dated July 24, 2001.
15 Letter re: Unaudited Interim Financial Information.
(b) On May 18, 2001, we filed a report on Form 8-K under Items 5
and 7. This report announced the retirement of Mr. King Kirchner
from his position as Chief Executive Officer effective June 30, 2001
and filed as an exhibit the Press Release announcing his retirement
and the Separation Agreement, dated May 11, 2001, between the
Registrant and Mr. King Kirchner.
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: August 8, 2001 By: /s/ John G. Nikkel
--------------------------- ------------------------------
JOHN G. NIKKEL
President, Chief Executive
Officer, Chief Operating
Officer and Director
Date: August 8, 2001 By: /s/ Larry D. Pinkston
--------------------------- ------------------------------
LARRY D. PINKSTON
Vice President, Chief
Financial Officer
and Treasurer
23