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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[x] QUARTERLY REPORT PURSUANT TO SECTION13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2004
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.)
7130 South Lewis,
Suite 1000
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 by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).
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 45,731,999
---------------------------- ----------
Class Outstanding at July 29, 2004
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, 2003 and June 30, 2004 . . . . . . . . . . 2
Consolidated Condensed Statements of Income
Three and Six Months Ended June 30, 2003 and 2004 . . . 4
Consolidated Condensed Statements of Cash Flows
Six Months Ended June 30, 2003 and 2004 . . . . . . . . 5
Consolidated Condensed Statements of Comprehensive
Income Three and Six Months Ended
June 30, 2003 and 2004. . . . . . . . . . . . . . . . . 6
Notes to Consolidated Condensed Financial Statements. . 7
Report of Independent Registered Public Accounting
Firm . . . . . . . . . . . . . . . . . . . . . . . . . 23
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . 24
Item 3. Quantitative and Qualitative Disclosures about
Market Risk . . . . . . . . . . . . . . . . . . . . . . 43
Item 4. Controls and Procedures . . . . . . . . . . . . . . . . 43
PART II. Other Information
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . 45
Item 2. Changes in Securities, Use of Proceeds and
Issuer Purchases of Equity Securities . . . . . . . . . 45
Item 3. Defaults Upon Senior Securities. . . . . . . . . . . . 45
Item 4. Submission of Matters to a Vote of Security Holders . . 45
Item 5. Other Information . . . . . . . . . . . . . . . . . . . 45
Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . 46
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
1
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
- ------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
June 30,
December 31, 2004
2003 (Unaudited)
----------- -----------
(In thousands)
ASSETS
- ------
Current Assets:
Cash and cash equivalents $ 598 $ 5,779
Restricted cash -- 5,265
Accounts receivable 58,807 67,050
Materials and supplies 8,023 12,247
Other 5,314 5,240
----------- -----------
Total current assets 72,742 95,581
----------- -----------
Property and Equipment:
Drilling equipment 424,321 450,617
Oil and natural gas properties, on the
full cost method:
Proved properties 528,110 679,940
Undeveloped leasehold not being
amortized 17,486 26,248
Transportation equipment 9,828 10,852
Other 14,535 16,556
----------- -----------
994,280 1,184,213
Less accumulated depreciation, depletion,
amortization and impairment 385,219 422,772
----------- -----------
Net property and equipment 609,061 761,441
----------- -----------
Goodwill 23,722 23,722
Other Assets 7,400 8,743
----------- -----------
Total Assets $ 712,925 $ 889,487
=========== ===========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
2
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS - CONTINUED
June 30,
December 31, 2004
2003 (Unaudited)
----------- -----------
(In thousands)
LIABILITIES AND SHAREHOLDERS' EQUITY
- ------------------------------------
Current Liabilities:
Current portion of long-term liabilities
and debt $ 1,015 $ 949
Accounts payable 32,871 37,363
Accrued liabilities 17,925 30,299
----------- -----------
Total current liabilities 51,811 68,611
----------- -----------
Long-Term Debt 400 70,000
----------- -----------
Other Long-Term Liabilities 17,893 24,146
----------- -----------
Deferred Income Taxes 127,053 173,616
----------- -----------
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, 45,592,012 and
45,730,568 shares issued, respectively 9,117 9,145
Capital in excess of par value 307,938 309,695
Accumulated other comprehensive income -- (131)
Retained earnings 198,713 234,405
----------- -----------
Total shareholders' equity 515,768 553,114
----------- -----------
Total Liabilities and Shareholders' Equity $ 712,925 $ 889,487
=========== ===========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
3
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME (UNAUDITED)(NOTE 1)
Three Months Ended Six Months Ended
June 30, June 30,
----------------------- -----------------------
2003 2004 2003 2004
---------- ---------- ---------- ----------
(In thousands except per share amounts)
Revenues:
Contract drilling $ 45,221 $ 67,110 $ 79,787 $ 130,324
Oil and natural gas 26,871 46,334 60,119 84,324
Other 572 999 1,317 1,695
---------- ---------- ---------- ----------
Total revenues 72,664 114,443 141,223 216,343
---------- ---------- ---------- ----------
Expenses:
Contract drilling:
Operating costs 33,641 48,364 61,452 94,920
Depreciation 5,899 7,754 10,793 15,218
Oil and natural gas:
Operating costs 5,893 10,662 12,508 20,394
Depreciation
depletion and
amortization 6,445 11,535 12,492 21,712
General and
administrative 2,070 3,103 4,520 5,874
Other 209 290 529 512
Interest 175 514 386 931
---------- ---------- ---------- ----------
Total
expenses 54,332 82,222 102,680 159,561
---------- ---------- ---------- ----------
Income Before Income Taxes 18,332 32,221 38,543 56,782
---------- ---------- ---------- ----------
Income Tax Expense:
Current 144 1,556 299 2,127
Deferred 6,824 10,751 14,350 19,514
---------- ---------- ---------- ----------
Total income
taxes 6,968 12,307 14,649 21,641
---------- ---------- ---------- ----------
Equity in Earnings of
Unconsolidated
Investments, Net of
Income Tax 327 270 456 550
---------- ---------- ---------- ----------
Income Before Change in
Accounting Principle 11,691 20,184 24,350 35,691
Cumulative Effect of
Change in Accounting
Principle (Net of
Income Tax of $811) -- -- 1,325 --
---------- ---------- ---------- ----------
Net Income $ 11,691 $ 20,184 $ 25,675 $ 35,691
========== ========== ========== ==========
Basic Earnings per Common
Share:
Income before change in
accounting principle $ 0.27 $ 0.44 $ 0.56 $ 0.78
Cumulative effect of
change in accounting
principle, net of
income tax -- -- 0.03 --
---------- ---------- ---------- ----------
Net income $ 0.27 $ 0.44 $ 0.59 $ 0.78
========== ========== ========== ==========
Diluted Earnings per Common
Share:
Income before change in
accounting principle $ 0.27 $ 0.44 $ 0.56 $ 0.78
Cumulative effect of
change in accounting
principle, net of
income tax -- -- 0.03 --
---------- ---------- ---------- ----------
Net income $ 0.27 $ 0.44 $ 0.59 $ 0.78
========== ========== ========== ==========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
4
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended
June 30,
------------------------
2003 2004
---------- ----------
(In thousands)
Cash Flows From Operating Activities:
Net income $ 25,675 $ 35,691
Adjustments to reconcile net income
to net cash provided (used) by
operating activities:
Depreciation, depletion,
and amortization 23,621 37,446
Deferred tax expense 14,626 19,851
Other (372) (139)
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable (13,788) 416
Accounts payable 3,417 (1,335)
Material and supplies 1,611 (4,224)
Prepaid expenses 3,748 (19)
Contract advances 2,271 1,091
Other - net (154) 5,396
---------- ----------
Net cash provided by
operating activities 60,655 94,174
---------- ----------
Cash Flows From (Used In) Investing
Activities:
Capital expenditures (including producing
property acquisitions) (42,104) (167,620)
Proceeds from disposition of assets 520 1,475
Other-net (2,498) 1,735
---------- ----------
Net cash used in
investing activities (44,082) (164,410)
---------- ----------
Cash Flows From (Used In) Financing
Activities:
Net borrowings (payments) under
line of credit (11,500) 69,600
Net payments of notes payable
and other long-term debt (1,020) (33)
Proceeds from exercise of stock options 423 380
Book overdrafts (3,647) 5,470
---------- ----------
Net cash from (used in) financing
activities (15,744) 75,417
---------- ----------
Net Increase in Cash and
Cash Equivalents 829 5,181
Cash and Cash Equivalents, Beginning
of Year 497 598
---------- ----------
Cash and Cash Equivalents, End of Period $ 1,326 $ 5,779
========== ==========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
5
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
--------------------- --------------------
2003 2004 2003 2004
--------- --------- --------- ---------
(In thousands)
Net Income $ 11,691 $ 20,184 $ 25,675 $ 35,691
Other Comprehensive Income,
Net of Taxes:
Change in value of cash
flow derivative
instruments used as
cash flow hedges (233) (252) (78) (556)
Adjustment
reclassification -
derivative settlements 4 347 4 425
--------- --------- --------- ---------
Comprehensive Income $ 11,462 $ 20,279 $ 25,601 $ 35,560
========= ========= ========= =========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
6
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 1 - BASIS OF PREPARATION AND PRESENTATION
- ----------------------------------------------
The accompanying unaudited consolidated condensed financial statements
include the accounts of Unit Corporation and its wholly owned subsidiaries
("company") and have been prepared under 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. Certain reclassifications have
been made to prior year financial information to conform to the current period
presentation.
Results for the three and six months ended June 30, 2004 are not
necessarily indicative of the results to be realized during the full year. The
consolidated condensed financial statements should be read with the company's
Annual Report on Form 10-K for the year ended December 31, 2003. The company's
independent auditors performed a review of these interim financial statements in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Under 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 auditor's liability under Section 11 does not
extend to it.
The company's stock-based compensation plans are accounted for under the
recognition and measurement principles of APB 25, "Accounting for Stock Issued
to Employees," and related Interpretations. No stock-based employee compensation
cost related to stock options is reflected in net income, as all options granted
under the plan had an exercise price equal to the market value of the underlying
common stock on the date of grant. Compensation expense included in reported net
income is the company's matching 401(k) contribution. The following table
illustrates the effect on net income and earnings per share if the company had
applied the fair value recognition provisions of Financial Accounting Standards
Board Statement No. 123, "Accounting for Stock-Based Compensation," to
stock-based employee compensation.
7
Three Months Ended Six Months Ended
June 30, June 30,
--------------------- ---------------------
2003 2004 2003 2004
--------- --------- --------- ---------
(In thousands except per share amounts)
Net Income, as Reported $ 11,691 $ 20,184 $ 25,675 $ 35,691
Add Stock-Based Employee
Compensation Expense
Included in Reported
Net Income, Net of Tax 168 219 335 438
Less Total Stock-Based
Employee Compensation
Expense Determined
Under Fair Value
Based Method
For All Awards (471) (627) (875) (1,140)
--------- --------- --------- ---------
Pro Forma Net Income $ 11,388 $ 19,776 $ 25,135 $ 34,989
========= ========= ========= =========
Basic Earnings per Share:
As reported $ 0.27 $ 0.44 $ 0.59 $ 0.78
========= ========= ========= =========
Pro forma $ 0.26 $ 0.43 $ 0.58 $ 0.77
========= ========= ========= =========
Diluted Earnings per
Share:
As reported $ 0.27 $ 0.44 $ 0.59 $ 0.78
========= ========= ========= =========
Pro forma $ 0.26 $ 0.43 $ 0.58 $ 0.76
========= ========= ========= =========
The fair value of each option granted is estimated using the Black-Scholes
model. There were no options granted in the first quarter of 2003 and 2004. In
the second quarter of 2003 and 2004 options were granted of 21,000 and 31,500
shares, respectively with an estimated fair value of approximately $262,000 and
$538,000, respectively. For options granted in the second quarter of 2003 and
2004, the company's estimate of stock volatility was 0.53 and 0.52,
respectively, based on previous stock performance. Dividend yield was estimated
to remain at zero with a risk free interest rate of 3.6% in the second quarter
of 2003 and 4.7% in the second quarter of 2004. Expected life ranged from 1 to
8
10 years based on prior experience depending on the vesting periods involved and
the make up of participating employees.
NOTE 2 - EARNINGS PER SHARE
- ---------------------------
The following data shows the amounts used in computing earnings per share
for the company.
Weighted
Net Average
Income Shares Per-Share
(Numerator) (Denominator) Amount
------------- ------------- ----------
(In thousands except per share amounts)
For the Three Months Ended
June 30, 2003:
Basic earnings per common share $ 11,691 43,521 $ 0.27
==========
Effect of dilutive stock options -- 228
------------- -------------
Diluted earnings per common share $ 11,691 43,749 $ 0.27
============= ============= ==========
For the Three Months Ended
June 30, 2004:
Basic earnings per common share $ 20,184 45,723 $ 0.44
==========
Effect of dilutive stock options -- 208
------------- -------------
Diluted earnings per common share $ 20,184 45,931 $ 0.44
============= ============= ==========
All options and their average exercise prices for the three month periods
ended June 30, 2003 and 2004 were included in the computation of diluted
earnings per share.
9
Weighted
Net Average
Income Shares Per-Share
(Numerator) (Denominator) Amount
------------- ------------- ----------
(In thousands except per share amounts)
For the Six Months Ended
June 30, 2003:
Basic earnings per common share:
Income before change in
accounting principle $ 24,350 43,477 $ 0.56
Cumulative effect of change
in accounting principle
net of income tax 1,325 43,477 0.03
------------- ----------
Net Income $ 25,675 43,477 $ 0.59
============= ==========
Diluted earnings per common share:
Weighted average number of
common shares used in basic
earnings per common share 43,477
Effect of dilutive stock
options 213
-------------
Weighted average number of
common shares and
dilutive potential
common shares used in
diluted earnings per
share 43,690
=============
Income before change in
accounting principle $ 24,350 43,690 $ 0.56
Cumulative effect of change
in accounting principle
net of income tax 1,325 43,690 0.03
------------- ----------
Net Income $ 25,675 43,690 $ 0.59
============= ==========
10
Weighted
Net Average
Income Shares Per-Share
(Numerator) (Denominator) Amount
------------- ------------- ----------
(In thousands except per share amounts)
For the Six Months Ended
June 30, 2004:
Basic earnings per common share:
Income before change in
accounting principle $ 35,691 45,697 $ 0.78
============= ==========
Net Income $ 35,691 45,697 $ 0.78
============= ==========
Diluted earnings per common share:
Weighted average number of
common shares used in basic
earnings per common share 45,697
Effect of dilutive stock
options 190
-------------
Weighted average number of
common shares and dilutive
potential common shares
used in diluted earnings
per share 45,887
=============
Income before change in
accounting principle $ 35,691 45,887 $ 0.78
============= ==========
Net Income $ 35,691 45,887 $ 0.78
============= ==========
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, 2003 and 2004 because the option exercise prices were greater than the
average market price of common shares:
2003 2004
---------- ----------
Options 21,000 24,500
========== ==========
Average exercise price $ 20.10 $ 28.23
========== ==========
11
NOTE 3 - ACQUISITIONS
- ---------------------
On May 4, 2004, the company acquired two drilling rigs and related
equipment for $5.5 million. The rigs are rated at 850 and 1,000 horsepower,
respectively, with depth capacities from 12,000 to 15,000 feet. The rigs are
being added into our Rocky Mountain division and will be available in August and
September of 2004.
On January 30, 2004, the company acquired the outstanding common stock of
PetroCorp Incorporated for $182.1 million in cash ($92.2 million net of cash
acquired). PetroCorp Incorporated explores and develops oil and natural gas
properties primarily in Texas and Oklahoma. Approximately 84% of the oil and
natural gas properties acquired in the acquisition are located in the
Mid-Continent and Permian basins, while 6% are located in the Rocky Mountains
and 10% are located in the Gulf Coast basin. The acquired properties increased
the company's oil and natural gas reserve base by approximately 56.7 billion
equivalent cubic feet of natural gas and provide additional locations for future
development drilling. The results of operations for this acquired company are
included in the statement of income for the period subsequent to January 30,
2004.
The amount paid for PetroCorp was allocated as follows (in thousands):
Working Capital $ 97,051
Undeveloped Oil and Natural Gas Properties 6,321
Proved Oil and Natural Gas Properties 108,984
Property and Equipment - Other 382
Other Assets 1,445
Other Long-Term Liabilities (5,271)
Deferred Income Taxes (net) (26,792)
----------
Total consideration $ 182,120
==========
The amount paid was determined through arms-length negotiations between the
parties and only the cash portion of the transaction appears in the investing
and financing activities sections of the company's consolidated condensed
financial statements of cash flows.
At the closing of this acquisition, $5.5 million, otherwise payable
to the shareholders of PetroCorp Incorporated, was transferred to an escrow
account to reserve for certain liabilities and related costs that may be
incurred by PetroCorp Incorporated after the closing of the acquisition. As of
June 30, 2004, $5.3 million remained in escrow and is reflected as restricted
cash.
12
Unaudited summary pro forma results of operations for the company,
reflecting the above acquisition as if it occurred at January 1, 2003 are as
follow:
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2003 2004 2003 2004
---------- ---------- ---------- ----------
(In thousands except per share amounts)
Revenues $ 85,098 $ 114,443 $ 164,091 $ 219,523
========== ========== ========== ==========
Income Before Change
In Accounting
Principle $ 15,244 $ 20,184 $ 30,489 $ 36,253
========== ========== ========== ==========
Net Income $ 15,244 $ 20,184 $ 28,845 $ 36,253
========== ========== ========== ==========
Diluted Earnings per
Share:
Income before
change in
accounting
principle $ 0.35 $ 0.44 $ 0.70 $ 0.79
========== ========== ========== ==========
Net income $ 0.35 $ 0.44 $ 0.66 $ 0.79
========== ========== ========== ==========
The pro forma results of operations are not necessarily indicative of the
actual results of operations that would have occurred had the purchase actually
been made at the beginning of the respective periods nor of the results which
may occur in the future.
13
On December 8, 2003, the company acquired SerDrilco Incorporated and its
subsidiary, Service Drilling Southwest LLC, for $35.0 million in cash. The terms
of the acquisition include an earn-out provision allowing the sellers to obtain
one-half of the cash flow in excess of $10 million for each of the three years
following the acquisition. The assets of SerDrilco Incorporated included 12
drilling rigs, spare drilling equipment, a fleet of 12 larger trucks and
trailers, various other vehicles and a district office and equipment yard in and
near Borger, Texas. The results of operations for the acquired entity are
included in the statement of income for the periods after December 7, 2003.
The amount paid in this acquisition was determined based on the depth
capacity of the rigs, the working condition of the rigs and the ability of the
rigs to enhance the company's ability to provide services and equipment required
by its customers on a timely basis within the Anadarko Basin of Western Oklahoma
and the Texas Panhandle. The company acquired SerDrilco Incorporated's tax basis
in the assets acquired resulting in the recording of a deferred tax liability
and goodwill of $10.9 million. The allocation of the amount paid and goodwill
recognized for the acquisition is as follows (in thousands):
Allocation of Total Consideration Paid and
Goodwill Recognized:
Drilling rigs including tubulars $ 31,012
Spare drilling equipment 904
Office, yard & yard equipment 1,200
Trucking fleet 1,486
Other vehicles 398
----------
Total cash consideration 35,000
Goodwill recognized 10,928
----------
Total consideration paid and
recognized $ 45,928
==========
14
NOTE 4 - CREDIT AGREEMENT
- -----------------------
On January 30, 2004, in conjunction with the company's acquisition of
PetroCorp Incorporated, the company replaced its credit agreement with a
revolving $150 million credit facility having a four year term ending
January 30, 2008. Borrowings under the new credit facility are limited to a
commitment amount. At June 30, 2004, the company had elected a commitment amount
of only $100 million in order to reduce financing costs. The company pays a
commitment fee of .375 of 1% for any unused portion of the commitment amount.
The company incurred origination, agency and syndication fees of $515,000 at the
inception of the new agreement, $40,000 of which will be paid annually and the
remainder of the fees will be amortized over the 4 year life of the loan. At
June 30, 2004 the company had $70.0 million borrowed all of which was subject to
the Eurodollar Rate. The average interest rate for the first six months of 2004
was 2.20%.
The borrowing base under the current credit facility is re-determined twice
each year on May 10 and November 10. This determination is based primarily on
the sum of a percentage of the discounted future value of the company's oil and
natural gas reserves, as determined by the banks. In addition, an amount
representing a part of the value of the company's drilling rig fleet, limited to
$20 million, is added to the borrowing base. The agreement also allows for one
requested special re-determination of the borrowing base (by either the lender
or the company) between each scheduled re-determination date if conditions
warrant such a request.
At the company's election, any part of the outstanding debt may be fixed at
a Eurodollar Rate for a 30, 60, 90 or 180 day term. During any Eurodollar Rate
funding period the outstanding principal balance of the note to which such
Eurodollar Rate option applies may be repaid on three days prior notice to the
administrative agent and subject to the payment of any applicable funding
indemnification amounts. Interest on the Eurodollar Rate is computed at the
Eurodollar Base Rate applicable for the interest period plus 1.00% to 1.50%
depending on the level of debt as a percentage of the total loan value and
payable at the end of each term or every 90 days whichever is less. Borrowings
not under the Eurodollar Rate bear interest at the JPMorgan Chase Prime Rate
payable at the end of each month and the principal borrowed may be paid anytime
in part or in whole without premium or penalty.
The credit agreement includes prohibitions against:
. the payment of dividends (other than stock dividends) during any
fiscal year in excess of 25% of our consolidated net income for
the preceding fiscal year,
. the incurrence of additional debt with 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,
except in favor of the company's banks.
15
The credit agreement also requires that the company have at the end of each
quarter:
. consolidated net worth of at least $350 million,
. a current ratio (as defined in the credit agreement) of not less
than 1 to 1, and
. a leverage ratio of long-term debt to consolidated EBITDA (as
defined in the credit agreement) for the most recently ended
rolling four fiscal quarters of no greater than 3.25 to 1.0.
On June 30, 2004 the company was in compliance with the covenants of its
credit agreement.
NOTE 5 - NEW ACCOUNTING PRONOUNCEMENTS
- --------------------------------------
On January 1, 2003 the company adopted Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS 143
establishes an accounting standard requiring the recording of the fair value of
liabilities associated with the retirement of long-lived assets. The company
owns oil and natural gas properties which require expenditures to plug and
abandon the wells when the oil and natural gas reserves in the wells are
depleted. These expenditures under FAS 143 are recorded in the period in which
the liability is incurred (at the time the wells are drilled or acquired). The
company does not have any assets restricted for the purpose of settling the
plugging liabilities.
The following table shows the activity for the six months ending June 30,
2003 and 2004 relating to the company's retirement obligation for plugging
liability:
16
Six Months Ended
------------------------------
2003 2004
------------- -------------
(In Thousands)
Short-Term Plugging Liability:
Liability at beginning of period $ 203 $ 303
Accretion of discount 8 5
Liability incurred in the period 53 --
Liability settled in the period -- (62)
Sold -- (21)
Reclassification of liability
from long- to short-term 37 --
------------- -------------
Plugging liability at end of
period $ 301 $ 225
============= =============
Long-Term Plugging Liability:
Liability at beginning of period $ 10,632 $ 11,691
Accretion of discount 244 393
Liability incurred in the period 226 5,745
Liability settled in the period (79) (5)
Sold -- (63)
Reclassification of liability
from long- to short-term (37) --
------------- -------------
Plugging liability at end of
period $ 10,986 $ 17,761
============= =============
On January 17, 2003, the Financial Accounting Standards Board (FASB) issued
FASB Interpretation No. 46, "Consolidation of Variable Interest Entities, an
interpretation of ARB 51" ("FIN 46"). The primary objectives of FIN 46 are to
provide guidance on the identification of entities for which control is achieved
through means other than through voting rights ("variable interest entities" or
"VIEs") and how to determine when and which business enterprise should
consolidate the VIE. This new model for consolidation applies to an entity which
either (1) the equity investors (if any) do not have a controlling financial
interest or (2) the equity investment at risk is insufficient to finance that
entity's activities without receiving additional subordinated financial support
17
from other parties. FIN 46, as amended, was effective for the company in the
fourth quarter of 2003 as it applies to entities created after February 1, 2003.
The adoption of FIN 46 with respect to these entities, primarily Eagle Energy
Partnership I, L.P., did not have an impact on the company's financial position
or results of operations or cash flows. For entities created prior to February
1, 2003, which are not special purpose entities, as defined in FIN 46, FIN 46
and the amendment of FIN 46 were effective for the company, as amended, in the
quarter ending March 31, 2004. The company evaluated FIN 46 and FIN 46(R) with
regard to these types of entities in which it has an ownership interest and
there was no material impact to the financial position, results of operations or
cash flows from the adoption of FIN 46 and FIN 46(R).
NOTE 6 - INTANGIBLE UNDEVELOPED LEASEHOLD AND INTANGIBLE DEVELOPED LEASEHOLD
- ----------------------------------------------------------------------------
Statement of Financial Accounting Standards No. 141, "Business
Combinations" (FAS 141) and Statement of Financial Accounting Standards, No.
142, "Goodwill and Intangible Assets" (FAS 142) were issued by the Financial
Accounting Standards Board (FASB) in June 2001 and became effective for the
company on July 1, 2001 and January 1, 2002, respectively. FAS 141 requires all
business combinations initiated after June 30, 2001 to be accounted for using
the purchase method. Additionally, FAS 141 requires companies to disaggregate
and report separately from goodwill certain intangible assets. FAS 142
establishes new guidelines for accounting for goodwill and other intangible
assets. Under FAS 142, goodwill and certain other intangible assets are not
amortized, but rather are reviewed annually for impairment. Depending on how the
accounting and disclosure literature is applied, oil and gas mineral rights held
under lease and other contractual arrangements representing the right to extract
oil and natural gas reserves for both undeveloped and developed leaseholds may
be classified separately from oil and gas properties, as intangible assets on
our balance sheets. In addition, the notes to the company's financial statements
would include the disclosures required by FAS 141 and 142 regarding intangibles.
The company, like many other oil and gas companies, has included oil and gas
extraction rights as part of the oil and gas properties, even after FAS 141 and
142 became effective. The company's results of operations and cash flows would
not be affected, since these oil and gas mineral extraction rights would
continue to be amortized in accordance with full cost accounting rules.
The FASB has issued a proposed FASB Staff Position 142-b "Goodwill and
Other Intangible Assets, to Oil- and Gas-Producing Entities" (FSP 142-b) to
address the application of FAS 141 to the oil and natural gas industry. If
adopted as written, the proposed FSP 142-b would confirm the company's
historical treatment of these costs. The company will continue to monitor the
FASB's treatment of this issue.
18
NOTE 7 - HEDGING ACTIVITY
- -------------------------
Periodically the company hedges the prices it will receive for a portion of
its future natural gas and oil production. The hedge is made in an attempt to
reduce the impact and uncertainty that price variations have on cash flow.
During the first quarter of 2003, the company entered into two natural gas
collar contracts. Each contract was for 10,000 MMBtu's of production per day and
covered the period of April through September 2003. One contract had a floor
price of $4.00 and a ceiling price of $5.75 and the other contract has a floor
price of $4.50 and a ceiling price of $6.02. During the first quarter of 2003,
the company also entered into two oil collar contracts. Each contract was for
5,000 barrels of production per month and covered the period of May through
December 2003. One contract had a floor price of $25.00 and a ceiling price of
$32.20 and the other contact had a floor price of $26.00 and a ceiling price of
$31.40. The fair value of the collar contracts was recognized on the June 30,
2003 balance sheet as a derivative liability of $119,000 and at a loss of
$74,000, net of tax, in accumulated other comprehensive income. These hedges
were fully effective. Natural gas revenues were reduced by $6,000 in the second
quarter of 2003 due to the settlement of the June natural gas collar contract.
During the first quarter of 2004, the company entered into a natural gas
collar covering 10,000 MMBtu's per day of its natural gas production. The
transaction covers the periods of April through October of 2004 and has a floor
of $4.50 and a ceiling of $6.76. In the first quarter of 2004, the company also
entered into an oil hedge covering 1,000 barrels per day of its oil production.
The transaction covers the periods of February through December of 2004 and has
an average price of $31.40. In April 2004, the company entered into a natural
gas collar covering an additional 10,000 MMBtu's per day of its natural gas
production. The transaction covers the periods of May through October of 2004
and has a floor of $5.00 and a ceiling of $7.00. The fair value of the collar
contracts and the oil hedge was recognized on the June 30, 2004 balance sheet as
a derivative liability of $211,000 and at a loss of $131,000, net of tax, in
accumulated other comprehensive income. These hedges were fully effective. The
natural gas collar contracts have not changed natural gas revenues during the
first six months of 2004. Oil revenues were reduced by $561,000 in the second
quarter of 2004 due to the settlement of the oil hedge and oil revenues have
been reduced by $687,000 for the six months ended June 30, 2004.
19
NOTE 8 - COMMITMENTS AND CONTINGENCIES
- --------------------------------------
Because of increasing cost of steel and the potential for limited
availability of new drill pipe, in the first quarter of 2004 the company
committed to purchase by the end of 2004 approximately 275,000 feet of drill
pipe for $9.3 million. At June 30, 2004, 217,000 feet (or approximately $7.4
million) of this commitment remained outstanding.
NOTE 9 - INDUSTRY SEGMENT INFORMATION
- -------------------------------------
The company has two primary business segments: Contract Drilling, and Oil
and Natural Gas, representing its two strategic business units offering
different products and services. The Contract Drilling segment provides land
contract drilling of oil and natural gas wells and the Oil and Natural Gas
segment is engaged in the development, acquisition and production of oil and
natural gas properties.
Management evaluates the performance of its operating segments based on
operating income, which is defined as operating revenues less operating expenses
and depreciation, depletion and amortization. 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, 2003 and 2004 is as follows:
20
Three Months Ended Six Months Ended
June 30, June 30,
----------------------- -----------------------
2003 2004 2003 2004
---------- ---------- ---------- ----------
(In thousands)
Revenues:
Contract drilling $ 46,528 $ 70,581 $ 83,041 $ 136,161
Elimination of
inter-segment
revenue 1,307 3,471 3,254 5,837
---------- ---------- ---------- ----------
Contract drilling
net of inter-
segment revenue 45,221 67,110 79,787 130,324
Oil and natural gas 26,871 46,334 60,119 84,324
Other 572 999 1,317 1,695
---------- ---------- ---------- ----------
Total revenues $ 72,664 $ 114,443 $ 141,223 $ 216,343
========== ========== ========== ==========
Operating Income (1):
Contract drilling $ 5,681 $ 10,992 $ 7,542 $ 20,186
Oil and natural gas 14,533 24,137 35,119 42,218
---------- ---------- ---------- ----------
Total operating
income 20,214 35,129 42,661 62,404
General and admini-
strative expense (2,070) (3,103) (4,520) (5,874)
Interest expense (175) (514) (386) (931)
Other income - net 363 709 788 1,183
---------- ---------- ---------- ----------
Income before
income taxes $ 18,332 $ 32,221 $ 38,543 $ 56,782
========== ========== ========== ==========
(1) Operating income is total operating revenues less operating
expenses, depreciation, depletion and amortization and does not
include non-operating revenues, general corporate expenses,
interest expense or income taxes.
The cumulative effect of change in accounting principle recorded in the
first quarter of 2003 of $1,325,000, net of $811,000 in income tax, is all
related to the oil and natural gas segment.
21
NOTE 10 - SUBSEQUENT EVENTS
- --------------------------
On July 29, 2004, the company closed its acquisition of the 60% of Superior
Pipeline Company LLC ("Superior") we did not own for $19.8 million, resulting in
the company owning 100% of Superior. Superior is a mid-stream company engaged
primarily in the gathering, processing and treating of natural gas and owns one
natural gas treatment plant, two processing plants, 12 active gathering systems
and 375 miles of pipeline. Superior operates in western Oklahoma and the Texas
Panhandle and has been in business for 8 years. This acquisition will give the
company additional alternatives for it to increase its ability to gather and
market its natural gas and third party natural gas and construct or acquire
existing natural gas gathering and processing facilities. In the third quarter
of 2004, the company will fully consolidate Superior in its financial
statements.
On July 30 ,2004, the company's wholly-owned subsidiary, Unit Drilling
Company, closed its acquisition of Sauer Drilling Company, a Casper-based
drilling company and a wholly-owned subsidiary of Tom Brown, Inc., for $34.7
million in cash paid at closing. An additional amount equal to Sauer's working
capital will be determined and paid after closing. The amount of the working
capital will be settled within 90 days of the closing of the agreement. The
acquisition includes 9 drilling rigs, a fleet of trucks, and an equipment and
repair yard with associated inventory, located in Casper, Wyoming. Of the 9
rigs, 8 are currently operating under contract in the Wind River Basin in
Wyoming and the Paradox Basin in Colorado. The rigs range from 500 horsepower to
1,000 horsepower with depth capacities rated from 5,000 feet to 16,000 feet. The
fleet of trucks consists of 4 vacuum trucks and 11 rig-up trucks used to move
the rigs to new drilling locations. The trucks also have the capacity to move
third-party rigs. This acquisition will increase the company's market share in
the Rocky Mountains in the medium to smaller drilling rig depth ranges. The
equipment yard, located in Casper, Wyoming, will continue to provide service
space for the nine newly acquired rigs and trucks as well as for the company's
existing Rocky Mountain rig fleet.
On August 2, 2004, Unit completed the sale of its investment in Eagle
Energy Partners I LP for $6.2 million. In the third quarter of 2004, a gain
before income taxes of $3.8 million will be recognized from this sale.
On July 15, 2004, the company increased its loan commitment from $100
million to $150 million. On August 4, 2004, the company's total borrowings under
its credit agreement was $113 million.
22
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Unit Corporation:
We have reviewed the accompanying condensed consolidated balance sheet of Unit
Corporation and its subsidiaries as of June 30, 2004, and the related condensed
consolidated statements of income and comprehensive income for each of the
three-month and six-month periods ended June 30, 2004 and 2003 and the condensed
consolidated statements of cash flows for the six-month periods ended June 30,
2004 and 2003. These interim financial statements are the responsibility of the
Company's management.
We conducted our review in accordance with the standards of the Public Company
Accounting Oversight Board (United States). A review of interim financial
information consists principally of applying analytical procedures and making
inquiries of persons responsible for financial and accounting matters. It is
substantially less in scope than an audit conducted in accordance with the
standards of the Public Company Accounting Oversight Board, 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 previously audited in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated balance sheet as of
December 31, 2003, and the related consolidated statements of income,
shareholder's equity and cash flows for the year then ended (not presented
herein), and in our report dated February 18, 2004 we expressed an unqualified
opinion on those consolidated financial statements in a report that also
included an explanatory paragraph referring to a change in accounting principle
discussed in Note 1 to the financial statements. In our opinion, the information
set forth in the accompanying condensed consolidated balance sheet as of
December 31, 2003, is fairly stated in all material respects in relation to the
consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
August 4, 2004
23
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
generated from our two principal business segments (and our subsidiaries that
carry out those operations) and borrowings under our bank credit agreement. Our
cash flow is influenced mainly by the prices we receive for our natural gas
production, the demand for and the dayrates we receive for our drilling rigs
and, to a lesser extent, the prices we receive for our oil production.
At June 30, 2004, we had cash totaling $5.8 million and we had borrowed
$70.0 million of the $100.0 million we had elected to have available under our
credit agreement. As of July 15, 2004, we elected at that time to increase our
credit commitment to $150 million. On August 4, 2004, after the acquisition of
Superior Pipeline Company LLC, Sauer Drilling Company and the sale of our
investment in Eagle Energy Partners I LP, our borrowings under our credit
agreement were $113 million.
Our two principal business segments are (i) contract drilling carried out
by our subsidiaries Unit Drilling Company, Service Drilling Southwest, L.L.C.
and Sauer Drilling Company and (ii) oil and natural gas exploration, carried out
by our subsidiaries Unit Petroleum Company and PetroCorp Incorporated.
The following is a summary of certain financial information on June 30,
2003 and June 30, 2004 and for the six months ended June 30, 2003 and June 30,
2004:
June 30, June 30, Percent
2003 2004 Change
-------------- -------------- -------
(In thousands except percent amounts)
Working Capital $ 26,839 $ 26,970 --
Long-Term Bank Debt $ 19,000 $ 70,000 268%
Shareholders' Equity $ 448,475 $ 553,114 23%
Ratio of Long-Term Debt to
Total Capitalization 4% 11%
Income Before Change in
Accounting Principle $ 24,350 $ 35,691 47%
Net Income $ 25,675 $ 35,691 39%
Net Cash Provided by
Operating Activities $ 60,655 $ 94,174 55%
Net Cash Used in Investing
Activities $ (44,082) $ (164,410) 273%
Net Cash Provided by (Used
in) Financing Activities $ (15,744) $ 75,417 --
24
The following table summarizes certain operating information for the first
six months of 2003 and 2004:
Percent
2003 2004 Change
------------ ------------ --------
Oil Production (MBbls) 238 494 108%
Natural Gas Production (MMcf) 9,810 12,908 32%
Average Oil Price Received $ 27.86 $ 30.91 11%
Average Oil Price Received
Excluding Hedge $ 27.86 $ 32.30 16%
Average Natural Gas Price
Received $ 5.34 $ 5.24 (2%)
Average Number of Our
Drilling Rigs in Use
During the Period 56.8 82.6 45%
Total Number of Our Drilling
Rigs Available at the End
of the Period 75 89 19%
Our Bank Credit Agreement. On January 30, 2004, in conjunction with our
acquisition of PetroCorp Incorporated, we replaced our credit agreement with a
revolving credit facility totaling $150 million having a four year term ending
January 30, 2008. Borrowings under the new credit facility are limited to a
commitment amount. Although the current value of our assets under the latest
loan value computation on May 10, 2004 supported the full $150 million, we
elected, on June 1, 2004, to reduce the loan commitment from $120 million to
$100 million in order to reduce financing costs since we are charged a
commitment fee of .375 of 1% on the amount available but not borrowed. On July
15, 2004, we increased the loan commitment to $150 million. We incurred
origination, agency and syndication fees of $515,000 at the inception of the new
agreement, $40,000 of which will be paid annually and the remainder of the fees
amortized over the four year life of the loan. The average interest rate for the
first six months of 2004 was 2.20%. At June 30, 2004 and July 21, 2004 our
borrowings were $70.0 million and at August 4, 2004, after the acquisition of
Superior Pipeline Company LLC and Sauer Drilling Company and the sale of our
investment in Eagle Energy Partners I LP, our borrowings were $113 million.
The loan value under our current credit facility is subject to a
semi-annual re-determination on May 10 and November 10 of each year. This
determination is based primarily on the sum of 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. The agreement allows for one
requested special re-determination of the borrowing base by either the lender or
us between each scheduled re-determination date if conditions warrant such a
request.
At our election, any part of the outstanding debt may be fixed at a
Eurodollar Rate for a 30, 60, 90 or 180 day term. During any Eurodollar Rate
funding period the outstanding principal balance of the note to which such
Eurodollar Rate option applies may be repaid on three days prior notice to the
25
administrative agent subject to the payment of any applicable funding
indemnification amounts. Interest on the Eurodollar Rate is computed at the
Eurodollar Base Rate applicable for the interest period plus 1.00% to 1.50%
depending on the level of debt as a percentage of the total loan value and is
payable at the end of each term or every 90 days whichever is less. Borrowings
not under the Eurodollar Rate bear interest at the JPMorgan Chase Prime Rate
payable at the end of each month and the principal borrowed may be paid anytime
in part or in whole without premium or penalty. At June 30, 2004, all of our
$70.0 million debt was subject to the Eurodollar Rate.
The credit agreement includes prohibitions against:
. the payment of dividends (other than stock dividends) during any
fiscal year in excess of 25% of our consolidated net income for
the preceding fiscal year,
. the incurrence of additional debt with 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,
except in favor of our banks.
The credit agreement also requires that we have at the end of each quarter:
. consolidated net worth of at least $350 million,
. a current ratio (as defined in the credit agreement) of not less than
1 to 1, and
. a leverage ratio of long-term debt to consolidated EBITDA (as
defined in the credit agreement) for the most recently ended
rolling four fiscal quarters of no greater than 3.25 to 1.0.
26
Contractual Commitments. We have the following contractual obligations at June
30, 2004:
Payments Due by Period
------------------------------------------
Less
Contractual Than 1 2-3 4-5 After 5
Obligations Total Year Years Years Years
- ------------- --------- -------- -------- --------- --------
(In thousands)
Bank Debt(1) $ 70,000 $ -- $ -- $ 70,000 $ --
Retirement
Agreement(2) 1,214 300 600 314 --
Operating
Leases(3) 4,153 1,056 1,960 881 256
Drill Pipe
Acquisi-
tions(4) 7,440 7,440 -- -- --
--------- -------- -------- --------- --------
Total
Contractual
Obligations $ 82,807 $ 8,796 $ 2,560 $ 71,195 $ 256
========= ======== ======== ========= ========
- -------------------
(1) See Previous Discussion in Management Discussion and Analysis regarding
bank debt.
(2) The retirement agreement represents a contractual obligation made in the
second quarter of 2001 for a separation agreement made in connection with
the retirement of King Kirchner from his position as Chief Executive
Officer. The liability, including accrued interest, is being paid monthly
in $25,000 installments continuing through June 2009. The discounted
liability is on our consolidated condensed balance sheet as part of other
long-term liabilities and is presented above undiscounted.
(3) We lease office space in Tulsa and Woodward, Oklahoma and Houston and
Midland, Texas under the terms of operating leases expiring through January
31, 2010 along with leasing space on short-term commitments to stack excess
rig equipment and production inventory.
(4) Because of the increasing cost of steel and the potential for limited
availability of new drill pipe, in the first quarter of 2004 we made a
commitment to purchase approximately 275,000 feet of drill pipe by the end
of 2004. At June 30, 2004 approximately 217,000 of that commitment remained
outstanding.
27
At June 30, 2004, we have the following commitments and contingencies that
could create, increase or accelerate our liabilities:
Amount of Commitment Expiration
Per Period
------------------------------------------
Total
Amount
Committed Less
Other Or Than 1 2-3 4-5 After 5
Commitments Accrued Year Years Years Years
- ----------------- --------- -------- -------- -------- ---------
(In thousands)
Deferred
Compensation
Agreement(1) $ 2,023 Unknown Unknown Unknown Unknown
Separation
Benefit
Agreement(2) $ 2,682 $ 424 Unknown Unknown Unknown
Plugging
Liability(3) $ 17,986 $ 225 $ 500 $ 859 $ 16,402
Gas Balancing
Liability(4) $ 1,191 Unknown Unknown Unknown Unknown
Repurchase
Obliga-
tions(5) Unknown Unknown Unknown Unknown Unknown
(1) We provide a salary deferral plan which allows participants to defer the
recognition of salary for income tax purposes until actual distribution of
benefits, which occurs at either termination of employment, death or
certain defined unforeseeable emergency hardships. We recognize payroll
expense and record a liability, included in other long-term liabilities in
our Consolidated Balance Sheet, at the time of deferral.
(2) Effective January 1, 1997, we adopted a separation benefit plan
("Separation Plan"). The Separation Plan allows eligible employees whose
employment with us is involuntarily terminated or, in the case of an
employee who has completed 20 years of service, voluntarily or
involuntarily terminated, to receive benefits equivalent to 4 weeks salary
for every whole year of service completed with Unit up to a maximum of 104
weeks. To receive payments the recipient must waive any claims against us
in exchange for receiving the separation benefits. On October 28, 1997, we
adopted a Separation Benefit Plan for Senior Management ("Senior Plan").
The Senior Plan provides certain officers and key executives of Unit with
benefits generally equivalent to the Separation Plan. The Compensation
Committee of the Board of Directors has absolute discretion in the
selection of the individuals covered in this plan.
(3) On January 1, 2003 we adopted Financial Accounting Standards No. 143,
"Accounting for Asset Retirement Obligations" (FAS 143). FAS 143
establishes an accounting standard requiring the recording of the fair
value of liabilities associated with the retirement of long-lived assets
28
(mainly plugging and abandonment costs for our depleted wells) in the
period in which the liability is incurred (at the time the wells are
drilled or acquired).
(4) We have a liability recorded for certain properties where we believe there
are insufficient natural gas reserves available to allow the under-produced
owners to recover their under-production from future production volumes.
(5) We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy
Income Limited Partnership along with private limited partnerships (the
"Partnerships") with certain qualified employees, officers and directors
from 1984 through 2004, with a subsidiary of ours serving as General
Partner. The Partnerships were formed for the purpose of conducting oil and
natural gas acquisition, drilling and development operations and serving as
co-general partner with us in any additional limited partnerships formed
during that year. The Partnerships participated on a proportionate basis
with us in most drilling operations and most producing property
acquisitions commenced by us for our own account during the period from the
formation of the Partnership through December 31 of that year. These
partnership agreements require, on the election of a limited partner, that
we repurchase the limited partner's interest at amounts to be determined by
appraisal in the future. Such repurchases in any one year are limited to
20% of the units outstanding. We made repurchases of $106,000 in 2003 for
limited partners' interests. Repurchases of $14,000 were made in the first
six months of 2004.
Hedging. Periodically we hedge the prices we will receive for a portion of our
future natural gas and oil production. We do so in an attempt to reduce the
impact and uncertainty that price variations have on our cash flow.
During the first quarter of 2003, we entered into two natural gas collar
contracts. Each collar contract was for 10,000 MMBtu's of production per day and
covered the period of April through September 2003. One contract had a floor
price of $4.00 and a ceiling price of $5.75 and the other contract has a floor
price of $4.50 and a ceiling price of $6.02. During the first quarter of 2003,
we also entered into two oil collar contracts. Each contract was for 5,000
barrels of production per month and covered the period of May through December
2003. One contract had a floor price of $25.00 and a ceiling price of $32.20 and
the other contact had a floor price of $26.00 and a ceiling price of $31.40. The
fair value of the collar contracts was recognized on the June 30, 2003 balance
sheet as a derivative liability of $119,000 and at a loss of $74,000, net of
tax, in accumulated other comprehensive income. These hedges were fully
effective. Natural gas revenues were reduced by $6,000 in the second quarter of
2003 due to the settlement of the June natural gas collar contract.
During the first and second quarters of 2004, we entered into two natural
gas collar contracts. Each collar contract was for 10,000 MMBtu's of production
per day. One contract covers the period of April through October of 2004 and has
a floor of $4.50 and a ceiling of $6.76. The other contract covers the period of
May through October of 2004 and has a floor of $5.00 and a ceiling of $7.00. We
also entered into an oil hedge covering 1,000 barrels per day of oil production.
29
The transaction covers the periods of February through December of 2004 and has
an average price of $31.40. The fair value of the collar contracts and the oil
hedge was recognized on the June 30, 2004 balance sheet as a derivative
liability of $211,000 and at a loss of $131,000, net of tax, in accumulated
other comprehensive income. These hedges were fully effective. The natural gas
collar contracts have not changed natural gas revenues during the first six
months of 2004. Oil revenues were reduced by $561,000 in the second quarter of
2004 due to the settlement of the oil hedge and oil revenues have been reduced
by $687,000 for the six months ended June 30, 2004.
Self-Insurance or Retentions. We are self-insured (or have a retention) for
certain losses relating to workers' compensation, general liability, property
damage and employee medical benefits. The exposure (i.e. our deductible or
retention) per occurrence is generally $1 million for general liability and $1
million for rig physical damage. We have purchased stop-loss coverage in order
to limit, to the extent feasible, our per occurrence and aggregate exposure to
certain claims. There is no assurance that such coverage will adequately protect
us against liability from all potential consequences. Following the acquisition
of SerDrilco we have continued to use its ERISA governed occupational injury
benefit plan to cover its employees in lieu of covering them under an insured
Texas workers' compensation plan.
Impact of Prices for Our Oil and Natural Gas. With the acquisition of PetroCorp
Incorporated (as previously discussed in Note 3 of the Notes to Consolidated
Condensed Financial Statements), natural gas comprises 86% of our total oil and
natural gas reserves. Any significant change in natural gas prices has a
material affect on our revenues, cash flow and the value of our oil and natural
gas reserves. Generally, prices and demand for domestic natural gas are
influenced by weather conditions, supply imbalances, the amount and timing of
liquid natural gas imports and by world wide oil price levels. Domestic oil
prices are primarily influenced by world oil market developments. All of these
factors are beyond our control and we can not predict nor measure their future
influence on the prices we will receive.
Based on our production in 2004, after the acquisition of PetroCorp
Incorporated, a $.10 per Mcf change in what we are paid for our natural gas
production would result in a corresponding $205,000 per month ($2,460,000
annualized) change in our pre-tax operating cash flow. Our first six month 2004
average natural gas price was $5.24 compared to an average natural gas price of
$5.34 for the first six months of 2003. A $1.00 per barrel change in our oil
price would have a $83,000 per month ($996,000 annualized) change in our pre-tax
operating cash flow based on our production in 2004 after the acquisition of
PetroCorp Incorporated. Our first six month 2004 average oil price was $30.91
compared with an average oil price of $27.86 received in the first six months of
2003.
Because natural gas prices have such a significant affect on the value of
our oil and natural gas reserves, declines in these prices can result in a
decline in the carrying value of our oil and natural gas properties. Price
declines can also adversely affect the semi-annual determination of the amount
30
available for us to borrow under our bank credit agreement since that
determination is based mainly on the value of our oil and natural gas reserves.
Such a reduction could limit our ability to carry out our planned capital
projects.
We sell most of our natural gas production to third parties under
month-to-month contracts. Several of these buyers have experienced financial
complications resulting from the recent investigations into the energy trading
industry. The long-term implications to the energy trading business, as well as
to oil and natural gas producers because of these investigations, remains to be
determined. We continue to evaluate the information available to us about our
buyers and try to reduce any possible future adverse impact to us. Presently we
believe that our buyers will be able to perform their commitments to us. At June
30, 2004, we owned a 16.7% limited partner interest in Eagle Energy Partners I
LP, whose purchases, which are competitively marketed, accounted for 26% of our
oil and natural gas revenues in the first six months of 2004. They marketed
approximately 56% of the natural gas volumes we sold for ourselves and third
parties during the same period. On August 2, 2004 we sold our investment in
Eagle Energy Partner I LP for $6.2 million.
Oil and Natural Gas Acquisitions and Capital Expenditures. Most of our capital
expenditures are discretionary and directed toward future growth. Any decision
to increase our oil and natural gas reserves through acquisitions or through
drilling depends on the prevailing or expected market conditions, potential
return on investment, future drilling potential and opportunities to obtain
financing under the circumstances involved, all of which provide us with a large
degree of flexibility in deciding when and if to incur these costs. We drilled
73 wells (34.62 net wells) in the first six months of 2004 compared to 62 wells
(24.94 net wells) in the first six months of 2003. Our total capital
expenditures for oil and natural gas exploration and acquisitions in the first
six months of 2004 totaled $160.7 million with $115.3 million relating to the
PetroCorp Incorporated acquisition. Included in the PetroCorp Incorporated
acquisition was a plugging liability and deferred tax liability of $32.1
million. Based on current prices, we plan to drill an estimated total of 165 to
175 wells in 2004 and total capital expenditures for oil and natural gas
exploration and acquisitions is planned to be approximately $105 million
excluding the PetroCorp Incorporated acquisition. Due to the anticipated upward
trend in costs resulting from a shortage in steel, we increased our inventory of
production casing and tubing from $3.1 million to $7.3 million in the first six
months of 2004. This inventory will be used to meet our continued demand for
such items as we complete wells in our development drilling program.
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 that work. These factors include competition from other drilling
contractors, the prevailing prices for natural gas and oil, availability and
cost of labor to run our rigs and our ability to supply the equipment needed. We
have not encountered major difficulty in hiring and keeping rig crews, but
shortages have occurred periodically in the past. At the end of the first
31
quarter of 2004, we increased wages in some of our drilling areas and
implemented longevity pay incentives to help maintain our contract drilling
labor base. If demand for drilling rigs increases rapidly in the future,
shortages of experienced personnel may limit our ability to increase the number
of rigs we could operate.
We currently do not have a shortage of drill pipe. Because of increasing
steel costs and the potential for future shortages of new drill pipe, we
committed in the first quarter of 2004 to purchase by the end of 2004
approximately 275,000 feet of drill pipe for $9.3 million. At June 30, 2004,
217,000 feet (or approximately $7.4 million) of this commitment remains
outstanding.
Most of our contract drilling fleet is targeted to the drilling of natural
gas wells, so changes in natural gas prices heavily influence the demand for our
drilling rigs and the prices we can charge for our contract drilling services.
The average rates we received for our drilling rigs during 2003 and 2004 reached
a low of $7,275 per day in February of 2003. Natural gas and oil prices began to
rise since the second quarter of 2003 through the first six months of 2004 and
both demand for our drilling rigs and dayrates have continued to improve. In the
first six months of 2004, the average dayrate we received was $8,507 per day.
The average use of our drilling rigs in the first six months of 2004 was 82.6
rigs (94%) compared with 56.8 rigs (76%) for the first six months of 2003. Based
on the average utilization of our drilling rigs in the first six months of 2004,
a $100 per day change in dayrates has a $8,260 per day ($3,015,000 annualized)
change in our pre-tax operating cash flow. Utilization and dayrates for our
drilling rigs will depend mainly on the price of natural gas.
Our contract drilling subsidiaries provide drilling services for our
exploration and production subsidiaries. The contracts for these services are
issued under the same conditions and rates as the contracts we have entered into
with unrelated third parties for comparable type projects. During the first six
months of 2003 and 2004, we drilled 20 and 17 wells, respectively, for our
exploration and production subsidiaries. The profit received by our contract
drilling segment of $702,000 and $2,017,000 during the first six months of 2003
and 2004, 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.
Drilling Acquisitions and Capital Expenditures. On December 8, 2003, we acquired
SerDrilco Incorporated and its subsidiary, Service Drilling Southwest LLC, for
$35.0 million in cash. The terms of the acquisition include an earn-out
provision allowing the sellers to obtain one-half of the cash flow in excess of
$10 million for each of the three years following the acquisition. The assets of
SerDrilco Incorporated included 12 drilling rigs, spare drilling equipment, a
fleet of 12 larger trucks and trailers, various other vehicles and a district
office and an equipment yard in and near Borger, Texas.
On May 4, 2004, we acquired two drilling rigs and related equipment for
$5.5 million. The rigs are rated at 850 and 1,000 horsepower, respectively, with
depth capacities from 12,000 to 15,000 feet. The rigs are being added into our
32
Rocky Mountain division and will be available to market in August and September
of 2004.
On July 30 ,2004, Unit acquired Sauer Drilling Company, a Casper-based
drilling company and a wholly-owned subsidiary of Tom Brown, Inc., for $34.7
million in cash and an amount equal to Sauer's working capital at closing. The
amount of the working capital will be settled within 90 days of the closing.
This acquisition includes 9 drilling rigs, a fleet of trucks, and an equipment
and repair yard with associated inventory, located in Casper, Wyoming. Of the 9
rigs, 8 are currently operating under contract in the Wind River Basin in
Wyoming and the Paradox Basin in Colorado. The rigs range from 500 horsepower to
1,000 horsepower with depth capacities rated from 5,000 feet to 16,000 feet. The
fleet of trucks consists of 4 vacuum trucks and 11 rig-up trucks used to move
the rigs to new drilling locations. The trucks also have the capacity to move
third-party rigs. This acquisition will increase our market share within medium
to shallower drilling depth ranges in our areas of operation in our Rocky
Mountain Division. The equipment yard, located in Casper, Wyoming, will not only
provide service space for the nine newly acquired rigs and trucks but also for
our existing Rocky Mountain rig fleet.
The 2 rigs acquired on May 4 and the Sauer Drilling Company rigs are to be
added into our Rocky Mountain division bringing the total rigs in that division
to 19. With these two acquisitions and the completion of the construction of
another rig in June 2004, our total rig fleet now consists of 100 drilling rigs.
For our contract drilling operations during the first six months of 2004,
we incurred $28.9 million in capital expenditures. For the year 2004, we have
budgeted capital expenditures of approximately $45 million for our contract
drilling operations (excluding the $34.7 million and related costs associated
with our acquisition of Sauer Drilling Company).
Oil and Natural Gas Limited Partnerships and Other Entity Relationships. One of
our wholly-owned subsidiaries is the general partner for 10 oil and natural gas
limited partnerships which were formed either privately or publicly. Each
partnership's revenues and costs are shared under formulas prescribed in the
applicable limited partnership agreement. The partnerships repay us for contract
drilling, well supervision and general and administrative expense. Related party
transactions for contract drilling and well supervision fees are the related
party's share of such costs. These costs are billed on the same basis as
billings to unrelated third parties for similar services. General and
administrative reimbursements consist of direct general and administrative
expense incurred on the related party's behalf as well as indirect expenses
assigned to the related parties. Allocations are based on the related party's
level of activity and are considered by management to be reasonable. During
2003, the total amount paid to us for all of these fees was $873,000. We expect
the fees to be approximately the same in 2004. Our proportionate share of
assets, liabilities and net income relating to the oil and natural gas
partnerships is included in our consolidated financial statements.
33
At June 30, we owned a 40% equity interest in Superior Pipeline Company LLC
("Superior"), an Oklahoma Limited Liability Company. Superior is a mid-stream
company engaged primarily in the gathering, processing and treating of natural
gas and owns one natural gas treatment plant, two processing plants, 12 active
gathering systems and 375 miles of pipeline. Superior operates in western
Oklahoma and the Texas Panhandle and has been in business for 8 years. Our
investment, including our share of the equity in the earnings of that company,
totaled $3.6 million at June 30, 2004 and is reported in other assets in our
balance sheet. During the first six months of 2004, Superior Pipeline Company
LLC purchased $2.0 million of our natural gas production and paid $19,000 for
our natural gas liquids. We paid this company $15,000 for gathering and
compression services in the first six months of 2004.
On July 29, 2004, we acquired the remaining 60% of Superior that we did not
own for $19.8 million. This acquisition will provide us with additional
alternatives to increase our ability to gather and market our (as well as third
parties) natural gas and construct or acquire existing natural gas gathering and
processing facilities.
On June 30, 2004, we owned a 16.7% limited partnership investment in Eagle
Energy Partnership I, L.P. ("Eagle") carried at cost of $2.4 million. Eagle is
engaged in the purchase and sale of natural gas, electricity (or similar
electricity based products), future commodities, and the performance of
scheduling and nomination services for both energy related commodities and
similar energy management functions. Eagle marketed approximately 56% of the
natural gas volumes we sold for ourselves and third parties in the first six
months of 2004. On August 2, 2004 we sold our investment in Eagle Energy Partner
I LP for $6.2 million.
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 are limited to the
lower of unamortized cost or a ceiling. The ceiling is defined as the sum of the
present value (10% discount rate) of estimated future net revenues from proved
reserves, based on period-end oil and natural gas prices adjusted for hedging,
plus the lower of cost or estimated fair value of unproved properties not
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 shareholders' 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
34
natural gas prices, even if temporary, increases the chance of a ceiling test
write-down. Based on oil and natural gas prices on June 30, 2004 ($5.78 per Mcf
for natural gas and $37.05 per barrel for oil), the unamortized cost of our 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 prices used in the reserve evaluation could result in a ceiling
test write-down in following quarterly reporting periods.
The value and quantity of our oil and natural gas reserves is used to
determine the borrowing base under our credit agreement with our banks. This
amount is affected by both price changes and the measurement of oil and natural
gas reserve volumes. Oil and natural gas reserves cannot be measured exactly.
Our estimates of oil and natural gas reserves requires extensive judgments of
our reservoir engineering data and are less precise than other estimates made in
connection with financial disclosures. Assigning monetary values to these
estimates does not reduce the subjectivity and changing nature of oil and
natural gas 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. The value and quantity of our oil and natural gas
reserves are determined by our company engineers and are reviewed annually by an
outside engineering firm.
We use the sales method for recording natural gas sales. This method allows
for recognition of revenue, which may be more or less than our share of pro-rata
production from certain wells. Our policy is to expense our pro-rata share of
lease operating costs from all wells as incurred. Such expenses relating to the
natural gas balancing position on wells in which we have an imbalance are not
material.
On January 1, 2003 the company adopted Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS 143
establishes an accounting standard requiring the recording of the fair value of
liabilities associated with the retirement of long-lived assets. The company
owns oil and natural gas properties which require expenditures to plug and
abandon the wells when the oil and natural gas reserves in the wells are
depleted. These expenditures under FAS 143 are recorded in the period in which
the liability is incurred (at the time the wells are drilled or acquired). The
company does not have any assets restricted for the purpose of settling the
plugging liabilities.
Drilling equipment, transportation equipment and other property and
equipment are carried at cost. Renewals and enhancements 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 these estimates could cause us to reduce the carrying value
of property and equipment.
35
We recognize revenues and expense generated from "daywork" drilling
contracts as the services are performed, since we do not bear the risk of
completion of the well. Under "footage" and "turnkey" contracts, we bear the
risk of completion of the well, so revenues and expenses are recognized when the
well is substantially completed. Under this method, substantial completion is
determined when the well bore reaches the negotiated depth as stated in the
contract. The entire amount of a loss, if any, is recorded when the loss can be
reasonably determined, however, any profit is recorded only at the time the well
is finished. The costs of uncompleted drilling contracts include expenses
incurred to date on "footage" or "turnkey" contracts, which are still in process
at the end of the period, and are included in other current assets.
NEW ACCOUNTING PRONOUNCEMENTS
- -----------------------------
On January 17, 2003, the FASB issued FASB Interpretation No. 46,
"Consolidation of Variable Interest Entities, an interpretation of ARB 51" ("FIN
46"). The primary objectives of FIN 46 are to provide guidance on the
identification of entities for which control is achieved through means other
than through voting rights ("variable interest entities" or "VIEs") and how to
determine when and which business enterprise should consolidate the VIE. This
new model for consolidation applies to an entity which either (1) the equity
investors (if any) do not have a controlling financial interest or (2) the
equity investment at risk is insufficient to finance that entity's activities
without receiving additional subordinated financial support from other parties.
FIN 46, as amended, was effective for us in the fourth quarter of 2003 as
it applies to entities created after February 1, 2003. The adoption of FIN 46
with respect to these entities, primarily Eagle Energy Partnership I, L.P., did
not have an impact on our financial position or results of operations or cash
flows. For entities created prior to February 1, 2003, which are not special
purpose entities, as defined in FIN 46, FIN 46 and the amendment of FIN 46 were
effective for us, as amended, in the quarter ending March 31, 2004. We evaluated
FIN 46 and FIN 46(R) with regard to these types of entities in which we have an
ownership interest and there was no material impact to the financial position,
results of operations or cash flows from the adoption of FIN 46 and FIN 46(R).
Statement of Financial Accounting Standards No. 141, "Business
Combinations" (FAS 141) and Statement of Financial Accounting Standards, No.
142, "Goodwill and Intangible Assets" (FAS 142) were issued by the FASB in June
2001 and became effective for us on July 1, 2001 and January 1, 2002,
respectively. FAS 141 requires all business combinations initiated after June
30, 2001 to be accounted for using the purchase method. Additionally, FAS 141
requires companies to disaggregate and report separately from goodwill certain
intangible assets. FAS 142 establishes new guidelines for accounting for
goodwill and other intangible assets. Under FAS 142, goodwill and certain other
intangible assets are not amortized, but rather are reviewed annually for
impairment. Depending on how the accounting and disclosure literature is
36
applied, oil and gas mineral rights held under lease and other contractual
arrangements representing the right to extract oil and natural gas reserves for
both undeveloped and developed leaseholds may be classified separately from oil
and gas properties, as intangible assets on our balance sheets. In addition, the
notes to our financial statements would include the disclosures required by FAS
141 and 142 regarding intangibles. To date, we, like many other oil and gas
companies, have included oil and gas extraction rights as part of the oil and
gas properties, even after FAS 141 and 142 became effective. Our results of
operations and cash flows would not be affected, since these oil and gas mineral
extraction rights would continue to be amortized in accordance with full cost
accounting rules.
The FASB has issued a proposed FASB Staff Position 142-b "Goodwill and
Other Intangible Assets, to Oil- and Gas-Producing Entities" (FSP 142-b) to
address the application of FAS 141 to the oil and natural gas industry. If
adopted as written, the proposed FSP 142-b would confirm our historical
treatment of these costs. We will continue to monitor the FASB's treatment of
this issue.
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 and value of proved oil and natural gas reserves;
. reserve potential;
. development and infill drilling potential;
. drilling prospects;
. expansion and other development trends of the oil and natural gas
industry;
. our business strategy;
. production of our oil and natural gas reserves;
. expansion and growth of our business and operations;
. availability of drilling rigs and rig related equipment;
. drilling rig use, revenues and costs; and
. availability of qualified labor.
These statements are based on certain assumptions and analyses made by us
in light of our experience and our view of historical trends, current conditions
37
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.
38
RESULTS OF OPERATIONS
- ---------------------
Second Quarter 2004 versus Second Quarter 2003
- ----------------------------------------------
Provided below is a comparison of selected operating and financial data for
the second quarter of 2004 versus the second quarter of 2003:
Second Second Percent
Quarter 2003 Quarter 2004 Change
--------------- --------------- ---------
Total Revenue $ 72,664,000 $ 114,443,000 57%
Net Income $ 11,691,000 $ 20,184,000 73%
Oil and Natural Gas:
Revenue $ 26,871,000 $ 46,334,000 72%
Operating costs $ 5,893,000 $ 10,662,000 81%
Average natural gas price (Mcf) $ 4.74 $ 5.57 18%
Average oil price (Bbl) $ 25.51 $ 31.12 22%
Natural gas production (Mcf) 4,955,000 6,614,000 33%
Oil production (Bbl) 123,000 278,000 126%
Depreciation, depletion and
amortization rate (Mcfe) $ 1.12 $ 1.38 23%
Depreciation, depletion and
amortization $ 6,445,000 $ 11,535,000 79%
Drilling:
Revenue $ 45,221,000 $ 67,110,000 48%
Operating costs $ 33,641,000 $ 48,364,000 44%
Percentage of revenue from
daywork contracts 97% 100%
Average number of rigs in use 62.4 83.7 34%
Average dayrate on daywork
contracts $ 7,601 $ 8,751 15%
Depreciation $ 5,899,000 $ 7,754,000 31%
General and Administrative Expense $ 2,070,000 $ 3,103,000 50%
Interest Expense $ 175,000 $ 514,000 194%
Average Interest Rate 2.17% 2.21% 2%
Average Long-Term Debt Outstanding $ 22,968,000 $ 75,211,000 227%
Oil and natural gas revenues increased due to increases in both oil and
natural gas produced and from increases in oil and natural prices between the
second quarter of 2004 and the second quarter of 2003. PetroCorp Incorporated
was acquired on January 30, 2004 and its production is included in our operating
results subsequent to the acquisition date. Oil production was up 126% between
the comparative quarters. Approximately 54% of the increase was from the
39
production added through the PetroCorp Incorporated acquisition. Natural gas
production was up 33% between the comparative quarters. Approximately 58% of the
increase in natural gas production was from wells acquired through the PetroCorp
Incorporated acquisition. The remainder of the increase in production for both
oil and natural gas came from wells added through our development drilling
program. Total operating cost increased in the second quarter of 2004 when
compared with the second quarter of 2003 due mainly from the acquisition of
PetroCorp Incorporated and to a lesser extent from costs associated with the
addition of new wells from our drilling program. PetroCorp Incorporated has
historically experienced higher operating cost per equivalent barrel due to the
types of wells under production and the reserve base being more oil. Gross
production taxes which are based on a percentage of revenues were also higher.
Our total depreciation, depletion and amortization ("DD&A) increased due to the
increase in equivalent volumes produced and an increase in our DD&A rate per
Mcfe. The acquisition of PetroCorp Incorporated was made at a higher cost per
equivalent volumes than we have previously experienced through both our drilling
program and from other acquisitions on average. During 2003 and the first six
months of 2004, we also experienced higher cost per Mcfe for the discovery of
new reserves through our development drilling program.
Contract drilling revenues increased between the comparative quarters due
to increases in demand for our drilling rigs and increases in dayrates. Natural
gas prices remained between $4.00 and $5.50 through most of 2003 and continued
at that level into the first six months of 2004 causing an increase in demand
for our rigs. Dayrates, which typically increase after the increase in demand
for rigs, also started increasing in the second quarter of 2003 and have
continued to steadily increase throughout the first six months of 2004. Along
with the increase in demand we also added 12 drilling rigs with the acquisition
of SerDrilco, Inc. in December of 2003 contributing to the increase in total
drilling revenues and operating cost. We did not drill any turnkey or footage
wells in the second quarter of 2004. Approximately 3% of our total drilling
revenues in the second quarter of 2003 came from footage and turnkey contracts,
which had profit margins lower than our daywork contracts. Contract drilling
depreciation increased due to the acquisition of 12 rigs in the fourth quarter
of 2003 and increased rig utilization.
General and administrative expense was higher in the second quarter of 2004
due to increases in employee, insurance and audit related costs. Our total
interest expense was higher due to the additional debt incurred from the
PetroCorp Incorporated acquisition. Income tax expense increased primarily due
to the increase in income before income taxes. Current income tax expense
increased in the second quarter of 2004 due to an increase in the provision for
alternative minimum tax which was based on higher estimates of total taxable
income for the year.
40
First Six Months 2004 versus First Six Months 2003
- --------------------------------------------------
Provided below is a comparison of selected operating and financial data for
the first six months of 2004 versus the first six months of 2003:
First Six First Six Percent
Months 2003 Months 2004 Change
--------------- --------------- ---------
Total Revenue $ 141,223,000 $ 216,343,000 53%
Income Before Change in Accounting
Principle $ 24,350,000 $ 35,691,000 47%
Net Income $ 25,675,000 $ 35,691,000 39%
Oil and Natural Gas:
Revenue $ 60,119,000 $ 84,324,000 40%
Operating costs $ 12,508,000 $ 20,394,000 63%
Average natural gas price (Mcf) $ 5.34 $ 5.24 (2%)
Average oil price (Bbl) $ 27.86 $ 30.91 11%
Natural gas production (Mcf) 9,810,000 12,908,000 32%
Oil production (Bbl) 238,000 494,000 108%
Depreciation, depletion and
amortization rate (Mcfe) $ 1.10 $ 1.36 24%
Depreciation, depletion and
amortization $ 12,492,000 $ 21,712,000 74%
Drilling:
Revenue $ 79,787,000 $ 130,324,000 63%
Operating costs $ 61,452,000 $ 94,920,000 54%
Percentage of revenue from
daywork contracts 96% 100%
Average number of rigs in use 56.8 82.6 45%
Average dayrate on daywork
contracts $ 7,476 $ 8,507 14%
Depreciation $ 10,793,000 $ 15,218,000 41%
General and Administrative Expense $ 4,520,000 $ 5,874,000 30%
Interest Expense $ 386,000 $ 931,000 141%
Average Interest Rate 2.13% 2.20% 3%
Average Long-Term Debt Outstanding $ 27,266,000 $ 65,615,000 141%
Oil and natural gas revenues increased due to increases in both oil and
natural gas produced and to a lesser extent from an increase in oil prices
between the first six months of 2004 and the first six months of 2003. A
reduction in natural gas prices partially offset the increases. PetroCorp
Incorporated was acquired on January 30, 2004 and its production is included in
our operating results subsequent to the acquisition date. Oil production was up
41
108% with approximately 61% of the increase from the production added through
the PetroCorp Incorporated acquisition. Natural gas production was up 32% with
approximately 53% of the increase in natural gas production from wells
acquired through the PetroCorp Incorporated acquisition. The remainder of the
increase in production for both oil and natural gas came from wells added
through our development drilling program. Total operating cost increased in the
first six months of 2004 when compared with the first six months of 2003 due
mainly from the acquisition of PetroCorp Incorporated and to a lesser extent
from costs associated with the addition of new wells from our drilling program.
PetroCorp Incorporated has historically experienced higher operating cost per
equivalent barrel due to the types of wells under production and the reserve
base being more toward oil. Gross production taxes which are based on a
percentage of revenues were also higher. Our total depreciation, depletion and
amortization ("DD&A) increased due to the increase in equivalent volumes
produced and an increase in our DD&A rate per Mcfe. The acquisition of PetroCorp
Incorporated was made at a higher cost per equivalent volumes than we have
previously experienced through both our drilling program and from other
acquisitions on average. During 2003 and the first six months of 2004, we also
experienced higher cost per Mcfe for the discovery of new reserves through our
development drilling.
Contract drilling revenues increased due to increases in demand for our
drilling rigs and increases in dayrates. Natural gas prices remained between
$4.00 and $5.50 through most of 2003 and continued at that level into the first
six months of 2004 causing an increase in demand for our rigs. Dayrates, which
typically increase after the increase in demand for rigs, also started
increasing in the second quarter of 2003 and have continued to steadily increase
throughout the first six months of 2004. Along with the increase in demand we
also added 12 drilling rigs with the acquisition of SerDrilco, Inc. in December
of 2003 contributing to the increase in total drilling revenues and operating
cost. We did not drill any turnkey or footage wells in the first six months of
2004. Approximately 4% of our total drilling revenues in the first six months of
2003 came from footage and turnkey contracts, which had profit margins lower
than our daywork contracts. Contract drilling depreciation increased due to the
utilization associated with the 12 rigs acquired in the fourth quarter of 2003
and increases in utilization from the remainder of our rigs.
General and administrative expense was higher in the six months of 2004 due
to increases in employee, insurance and auditing costs. Our total interest
expense was higher due to the additional debt incurred from the PetroCorp
Incorporated acquisition. Income tax expense increased primarily due to the
increase in income before income taxes. Current income tax expense increased in
the first six months of 2004 due to an increase in the provision for alternative
minimum tax which was based on higher estimates of total taxable income for the
year.
Net income in the first six months of 2003 includes $1.3 million of income
due to a change in accounting principle for the implementation of Financial
Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (FAS
143).
42
Item 3. Quantitative and Qualitative Disclosures about Market Risk
- ------- ----------------------------------------------------------
Our operations are exposed to market risks primarily as a result of changes
in commodity prices and interest rates. We do not use derivative financial
instruments for speculative or trading purposed.
Commodity Price Risk
We produce, purchase and sell crude oil, natural gas, condensate and
natural gas liquids. As a result, our financial results can be significantly
impacted as these commodity prices fluctuate widely in response to changing
market forces. Relatively modest changes in gas prices significantly impact our
results of operations and cash flows.
In an effort to try and reduce the impact of price fluctuations, over the
past several years we periodically have used hedging strategies to hedge the
prices we will receive for a portion of our future oil and natural gas
production. A detailed explanation of those transactions has been included under
hedging in the financial condition portion of management's discussion and
analysis of financial condition and results of operations included above under
Item 2.
Interest Rate Risk
Our interest rate risk exposure results primarily from short-term rates,
mainly LIBOR-based, on borrowings from our banks. At June 30, 2004, all of our
bank debt was at LIBOR-based rates. In the past, we have not entered into
financial instruments such as interest rate swaps or interest rate lock
agreements.
Item 4. Controls and Procedures
- --------------------------------
We maintain a set of disclosure controls and procedures that are designed
to provide reasonable assurance that information required to be disclosed in our
reports filed under the Securities and Exchange Act of 1934, as amended, is
recorded, processed, summarized, and reported within the time periods specified
in the U.S. Securities and Exchange Commission's rules and forms. We have
investments in certain unconsolidated entities that we do not control or manage.
As we do not control or manage these entities, our disclosure controls and
procedures with respect to such entities are necessarily more limited than those
we maintain with respect to our consolidated subsidiaries.
43
As of the end of the period covered by this report, we carried out an
evaluation, under the supervision and with the participation of our management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of the design and operation of our disclosure controls and
procedures under Exchange Act Rule 13a-15. Based on that evaluation, our Chief
Executive Officer and Chief Financial Officer concluded that the company's
disclosure controls and procedures are effective in timely alerting them to
material information required to be included in our periodic SEC filings
relating to the company (including its consolidated subsidiaries).
There has been no change in our internal control over financial reporting
during the quarter ended June 30, 2004 that has materially affected, or is
reasonably likely to materially affect, our internal control over financial
reporting.
44
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
- --------------------------
Not applicable
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of
Equity Securities
- ------------------------------------------------------------------------
Not applicable
Item 3. Defaults Upon Senior Securities
- ----------------------------------------
Not applicable
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
On May 5, 2004 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 William B. Morgan, John H. Williams
and Larry D. Pinkston to serve as directors.
Numbers of Against or
Nominee Votes For Withheld
---------------------- ------------ ------------
William B. Morgan 41,042,218 591,593
John H. Williams 41,067,199 566,612
Larry D. Pinkston 40,646,900 986,911
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,
John S. Zink and Mark E. Monroe.
II. Ratification of the appointment of PricewaterhouseCoopers L L P
as the Company's independent certified public accountants for the
fiscal year 2004.
For - 41,222,799
Against - 397,721
Abstain - 13,291
Item 5. Other Information
- --------------------------
Not applicable
45
Item 6. Exhibits and Reports on Form 8-K
- -----------------------------------------
(a) Exhibits:
15 Letter re: Unaudited Interim Financial Information.
31.1 Certification of Chief Executive Officer under Rule 13a - 14(a)
of the Exchange Act.
31.2 Certification of Chief Financial Officer under Rule 13a - 14(a)
of the Exchange Act.
32 Certification of Chief Executive Officer and Chief Financial
Officer under Rule 13a - 14(a) of the Exchange Act and 18
U.S.C. Section 1350, as adopted under Section 906 of the
Sarbanes-Oxley Act of 2002.
(b) On April 19, 2004, we filed a report on Form 8-K under item 7, 9 and
12. This report announced our earnings for the quarter ended
March 31, 2004 in an attached exhibit.
On April 20, 2004, we filed a report on Form 8-K under item 7 and 9.
This report announced that we have reached an agreement to buy two
drilling rigs and related equipment for $5.5 million.
On June 29, 2004, we filed a report on Form 8-K under item 7 and 9.
This report announced that we had signed an agreement to acquire Sauer
Drilling Company, a Casper-based drilling company and a wholly-owned
subsidiary of Tom Brown, Inc., for $34.7 million in cash and an amount
equal to Sauer's working capital at closing.
On July 21, 2004, we filed a report on Form 8-K under item 7, 9 and
12. This report announced our earnings for the quarter ended June 30,
2004 in an attached exhibit and also announced that we had reached an
agreement to acquire the 60% of Superior Pipeline Company LLC that we
did not previously own for $19.8 million.
On August 4, 2004, we filed a report on Form 8-K under item 7 and 9.
This report announced that our wholly-owned subsidiary, Unit Drilling
Company, had completed the acquisition of Sauer Drilling Company, a
Casper-based drilling company and a wholly-owned subsidiary of Tom
Brown, Inc. The report also announced that we had completed the
acquisition of the 60% of Superior Pipeline Company LLC that we did
not already own.
46
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 6, 2004 By: /s/ John G. Nikkel
--------------------------- ------------------------------
JOHN G. NIKKEL
Chief Executive Officer,
and Director
Date: August 6, 2004 By: /s/ David T. Merrill
--------------------------- ------------------------------
DAVID T. MERRILL
Chief Financial Officer and
Treasurer
47