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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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 45,737,599
---------------------------- ----------
Class Outstanding at November 8, 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 September 30, 2004 . . . . . . . . . 2
Consolidated Condensed Statements of Income
Three and Nine Months Ended September 30, 2003 and 2004. . 4
Consolidated Condensed Statements of Cash Flows
Nine Months Ended September 30, 2003 and 2004. . . . . . . 6
Consolidated Condensed Statements of Comprehensive
Income Three and Nine Months Ended
September 30, 2003 and 2004. . . . . . . . . . . . . . . . 7
Notes to Consolidated Condensed Financial Statements . . . 8
Report of Independent Registered Public Accounting
Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations. . . . . . . . . . . . 27
Item 3. Quantitative and Qualitative Disclosures about
Market Risk. . . . . . . . . . . . . . . . . . . . . . . . 52
Item 4. Controls and Procedures. . . . . . . . . . . . . . . . . . 52
PART II. Other Information
Item 1. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . 54
Item 2. Unregistered Sales of Equity Securities and
Use of Proceeds. . . . . . . . . . . . . . . . . . . . . . 54
Item 3. Defaults Upon Senior Securities. . . . . . . . . . . . . . 54
Item 4. Submission of Matters to a Vote of Security Holders. . . . 54
Item 5. Other Information. . . . . . . . . . . . . . . . . . . . . 54
Item 6. Exhibits . . . . . . . . . . . . . . . . . . . . . . . . . 54
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
1
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
- ------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
September 30,
December 31, 2004
2003 (Unaudited)
----------- -----------
(In thousands)
ASSETS
- ------
Current Assets:
Cash and cash equivalents $ 598 $ 1,540
Restricted cash -- 5,259
Accounts receivable 58,807 83,632
Materials and supplies 8,023 11,499
Other 5,314 7,243
----------- -----------
Total current assets 72,742 109,173
----------- -----------
Property and Equipment:
Drilling equipment 424,321 496,037
Oil and natural gas properties, on the
full cost method:
Proved properties 528,110 705,343
Undeveloped leasehold not being
amortized 17,486 28,584
Gas gathering & processing equipment 6,686 35,236
Transportation equipment 9,828 12,562
Other 7,849 10,207
----------- -----------
994,280 1,287,969
Less accumulated depreciation, depletion,
amortization and impairment 385,219 444,663
----------- -----------
Net property and equipment 609,061 843,306
----------- -----------
Goodwill 23,722 28,420
Other Assets 7,400 2,531
----------- -----------
Total Assets $ 712,925 $ 983,430
=========== ===========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
2
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS - CONTINUED
September 30,
December 31, 2004
2003 (Unaudited)
----------- -----------
(In thousands)
LIABILITIES AND SHAREHOLDERS' EQUITY
- ------------------------------------
Current Liabilities:
Current portion of long-term
liabilities and debt $ 1,015 $ 941
Accounts payable 32,871 41,906
Accrued liabilities 17,925 44,752
----------- -----------
Total current liabilities 51,811 87,599
----------- -----------
Long-Term Debt 400 107,500
----------- -----------
Other Long-Term Liabilities 17,893 24,727
----------- -----------
Deferred Income Taxes 127,053 186,742
----------- -----------
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
45,734,099 shares issued, respectively 9,117 9,146
Capital in excess of par value 307,938 309,739
Accumulated other comprehensive income -- (1,077)
Retained earnings 198,713 259,054
----------- -----------
Total shareholders' equity 515,768 576,862
----------- -----------
Total Liabilities and Shareholders' Equity $ 712,925 $ 983,430
========== ==========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
3
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2003 2004 2003 2004
---------- ---------- ---------- ----------
(In thousands except per share amounts)
Revenues:
Contract drilling $ 50,052 $ 80,887 $ 129,839 $ 211,211
Oil and natural gas 27,402 46,394 87,521 130,718
Gas gathering & processing 148 11,474 566 11,562
Other 198 4,595 832 5,497
---------- ---------- ---------- ----------
Total revenues 77,800 143,350 218,758 358,988
---------- ---------- ---------- ----------
Expenses:
Contract drilling:
Operating costs 35,653 57,816 97,105 152,736
Depreciation 6,318 8,903 17,111 24,121
Oil and natural gas:
Operating costs 6,207 9,746 18,655 29,871
Depreciation depletion
and amortization 6,972 12,316 19,464 34,028
Gas gathering & processing:
Operating costs 50 10,480 307 10,515
Depreciation 58 451 125 489
General and administrative 2,246 3,081 6,766 8,955
Interest 154 820 540 1,751
---------- ---------- ---------- ----------
Total expenses 57,658 103,613 160,073 262,466
---------- ---------- ---------- ----------
Income Before Income Taxes 20,142 39,737 58,685 96,522
---------- ---------- ---------- ----------
Income Tax Expense:
Current 157 1,470 456 3,597
Deferred 7,506 13,673 21,856 33,187
---------- ---------- ---------- ----------
Total income taxes 7,663 15,143 22,312 36,784
---------- ---------- ---------- ----------
Equity in Earnings of
Unconsolidated Investments,
Net of Income Tax 284 53 740 603
---------- ---------- ---------- ----------
Income Before Change in
Accounting Principle 12,763 24,647 37,113 60,341
Cumulative Effect of Change in
Accounting Principle (Net of
Income Tax of $811) -- -- 1,325 --
---------- ---------- ---------- ----------
Net Income $ 12,763 $ 24,647 $ 38,438 $ 60,341
========== ========== ========== ==========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
4
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME - CONTINUED (UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2003 2004 2003 2004
---------- ---------- ---------- ----------
(In thousands except per share amounts)
Basic Earnings per Common Share:
Income before change in
accounting principle $ 0.29 $ 0.54 $ 0.85 $ 1.32
Cumulative effect of change
in accounting principle,
net of income tax -- -- 0.03 --
---------- ---------- ---------- ----------
Net income $ 0.29 $ 0.54 $ 0.88 $ 1.32
========== ========== ========== ==========
Diluted Earnings per Common
Share:
Income before change in
accounting principle $ 0.29 $ 0.54 $ 0.85 $ 1.31
Cumulative effect of change
in accounting principle,
net of income tax -- -- 0.03 --
---------- ---------- ---------- ----------
Net income $ 0.29 $ 0.54 $ 0.88 $ 1.31
========== ========== ========== ==========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
5
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended
September 30,
------------------------
2003 2004
---------- ----------
(In thousands)
Cash Flows From Operating Activities:
Net income $ 38,438 $ 60,341
Adjustments to reconcile net income
to net cash provided (used) by
operating activities:
Depreciation, depletion,
and amortization 37,135 59,327
Deferred tax expense 22,304 33,559
Gain on sale of investment -- (3,783)
Other 237 319
Changes in operating assets and
liabilities increasing (decreasing)
cash:
Accounts receivable (19,417) (4,968)
Accounts payable 3,098 (2,627)
Material and supplies 284 (3,476)
Accrued liabilities 1,886 15,241
Prepaid expenses 3,056 (1,874)
Contract advances 1,228 (305)
Other - net 163 17
---------- ----------
Net cash provided by
operating activities 88,412 151,771
---------- ----------
Cash Flows From (Used In) Investing
Activities:
Capital expenditures (including producing
property acquisitions and other
acquisitions net of acquired assets
and liabilities) (65,780) (269,103)
Proceeds from disposition of assets
and investments 960 8,395
Other-net (2,555) 2,132
---------- ----------
Net cash used in
investing activities (67,375) (258,576)
---------- ----------
Cash Flows From (Used In) Financing
Activities:
Net borrowings (payments) under
line of credit (15,500) 107,100
Net payments of notes payable
and other long-term debt (1,074) (1,833)
Proceeds from exercise of stock options 452 424
Book overdrafts (3,647) 2,056
---------- ----------
Net cash from (used in) financing
activities (19,769) 107,747
---------- ----------
Net Increase in Cash and
Cash Equivalents 1,268 942
Cash and Cash Equivalents, Beginning
of Year 497 598
---------- ----------
Cash and Cash Equivalents, End of Period $ 1,765 $ 1,540
========== ==========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
6
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- --------------------
2003 2004 2003 2004
--------- --------- --------- ---------
(In thousands)
Net Income $ 12,763 $ 24,647 $ 38,438 $ 60,341
Other Comprehensive Income,
Net of Taxes:
Change in value of cash
flow derivative
instruments used as
cash flow hedges 74 (1,663) (4) (2,219)
Adjustment
reclassification -
derivative settlements -- 717 4 1,142
--------- --------- --------- ---------
Comprehensive Income $ 12,837 $ 23,701 $ 38,438 $ 59,264
========= ========= ========= =========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
7
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 nine months ended September 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.
8
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------- ---------------------
2003 2004 2003 2004
--------- --------- --------- ---------
(In thousands except per share amounts)
Net Income, as Reported $ 12,763 $ 24,647 $ 38,438 $ 60,341
Add Stock-Based Employee
Compensation Expense
Included in Reported
Net Income, Net of Tax 238 318 573 756
Less Total Stock-Based
Employee Compensation
Expense Determined
Under Fair Value
Based Method
For All Awards (578) (784) (1,453) (1,924)
--------- --------- --------- ---------
Pro Forma Net Income $ 12,423 $ 24,181 $ 37,558 $ 59,173
========= ========= ========= =========
Basic Earnings per Share:
As reported $ 0.29 $ 0.54 $ 0.88 $ 1.32
========= ========= ========= =========
Pro forma $ 0.29 $ 0.53 $ 0.86 $ 1.29
========= ========= ========= =========
Diluted Earnings per
Share:
As reported $ 0.29 $ 0.54 $ 0.88 $ 1.31
========= ========= ========= =========
Pro forma $ 0.28 $ 0.53 $ 0.86 $ 1.29
========= ========= ========= =========
The fair value of each option granted is estimated using the Black-Scholes
model. There were no options granted in the first and third quarters 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
9
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
September 30, 2003:
Basic earnings per common share $ 12,763 43,556 $ 0.29
==========
Effect of dilutive stock options -- 180
------------- -------------
Diluted earnings per common share $ 12,763 43,736 $ 0.29
============= ============= ==========
For the Three Months Ended
September 30, 2004:
Basic earnings per common share $ 24,647 45,733 $ 0.54
==========
Effect of dilutive stock options -- 239
------------- -------------
Diluted earnings per common share $ 24,647 45,972 $ 0.54
============= ============= ==========
The following options and their average exercise prices were not included
in the computation of diluted earnings per share for the three months ended
September 30, 2003 and September 30, 2004 because the option exercise prices
were greater than the average market price of common shares:
2003 2004
---------- ----------
Options 5,000 --
========== ==========
Average exercise price $ 21.50 $ --
========== ==========
10
Weighted
Net Average
Income Shares Per-Share
(Numerator) (Denominator) Amount
------------- ------------- ----------
(In thousands except per share amounts)
For the Nine Months Ended
September 30, 2003:
Basic earnings per common share:
Income before change in
accounting principle $ 37,113 43,503 $ 0.85
Cumulative effect of change
in accounting principle
net of income tax 1,325 43,503 0.03
------------- ----------
Net Income $ 38,438 43,503 $ 0.88
============= ==========
Diluted earnings per common share:
Weighted average number of
common shares used in basic
earnings per common share 43,503
Effect of dilutive stock
options 174
-------------
Weighted average number of
common shares and dilutive
potential common shares
used in diluted earnings
per share 43,677
=============
Income before change in
accounting principle $ 37,113 43,677 $ 0.85
Cumulative effect of change
in accounting principle
net of income tax 1,325 43,677 0.03
------------- ----------
Net Income $ 38,438 43,677 $ 0.88
============= ==========
11
Weighted
Net Average
Income Shares Per-Share
(Numerator) (Denominator) Amount
------------- ------------- ----------
(In thousands except per share amounts)
For the Nine Months Ended
September 30, 2004:
Basic earnings per common share:
Income before change in
accounting principle $ 60,341 45,709 $ 1.32
============= ==========
Net Income $ 60,341 45,709 $ 1.32
============= ==========
Diluted earnings per common share:
Weighted average number of
common shares used in basic
earnings per common share 45,709
Effect of dilutive stock
options 206
-------------
Weighted average number of
common shares and dilutive
potential common shares
used in diluted earnings
per share 45,915
=============
Income before change in
accounting principle $ 60,341 45,915 $ 1.31
============= ==========
Net Income $ 60,341 45,915 $ 1.31
============= ==========
The following options and their average exercise prices were not included
in the computation of diluted earnings per share for the nine months ended
September 30, 2003 and September 30, 2004 because the option exercise prices
were greater than the average market price of common shares:
2003 2004
---------- ----------
Options 26,000 --
========== ==========
Average exercise price $ 20.37 $ --
========== ==========
12
NOTE 3 - ACQUISITIONS
- ---------------------
On July 30, 2004, the company's wholly-owned subsidiary, Unit Drilling
Company, completed its acquisition of Sauer Drilling Company, a Casper-based
drilling company, for $34.7 million in cash paid at closing. In addition, the
agreement provides that there will be a post closing settlement adjustment for
the working capital of Sauer Drilling Company. Currently the seller has
estimated this cost to be $6.2 million and the company has estimated this cost
to be $5.3 million. In the event the parties can not resolve this discrepancy,
the issue will be settled by arbitration. This acquisition includes 9 drilling
rigs, a fleet of trucks, and an equipment and repair yard with associated
inventory, located in Casper, Wyoming. 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 increased 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. The results of operations for this acquired
company are included in the statement of income for the period after July 31,
2004.
The $34.7 million paid for Sauer was allocated as follows (in thousands):
Drilling Rigs Including Tubulars $ 26,428
Spare Drilling Equipment 1,498
Trucking Fleet 1,433
Land and Buildings 510
Other Vehicles 182
Goodwill Recognized 4,698
----------
Total consideration $ 34,749
==========
The amount paid was determined through arms-length negotiations between the
parties.
On July 29, 2004, the company completed its acquisition of the 60% of
Superior Pipeline Company LLC ("Superior") it did not already own for $19.8
million, resulting in the company's 100% ownership of Superior. Prior to this
acquisition, the company's 40% interest in the operations of Superior was shown
as equity in earnings of unconsolidated investments, net of income tax. Superior
is a mid-stream company engaged primarily in the gathering, processing and
13
treating of natural gas and owns one natural gas treatment plant, two processing
plants, 12 active gathering systems and 400 miles of pipeline. Superior operates
in western Oklahoma and the Texas Panhandle and has been in business since 1996.
This acquisition will increase the company's ability to gather and market its
natural gas (as well as third party natural gas) and construct or acquire
existing natural gas gathering and processing facilities. The results of
operations for this acquired company are included in the statement of income for
the period after July 31, 2004 and intercompany revenue from services and
purchases of production between the company's subsidiaries has been eliminated.
The $19.8 million paid for Superior was allocated as follows (in
thousands):
Gas Gathering and Processing Facilities $ 20,886
Other Long-Term Liabilities (1,080)
Working Capital (6)
----------
Total consideration $ 19,800
==========
The amount paid was determined through arms-length negotiations between the
parties.
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 company
refurbished the rigs for approximately $4.0 million. One rig was placed into
service at the beginning of August 2004 and the other rig was placed into
service in the middle of September 2004. Both rigs are working in the area
covered by the Rocky Mountain division.
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 after January 30, 2004.
14
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 September 30,
2004, $5.3 million is in escrow and is reflected as restricted cash.
15
Unaudited summary pro forma results of operations for the company,
reflecting the PetroCorp acquisition as if it occurred at January 1, 2003 are as
follow:
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2003 2004 2003 2004
---------- ---------- ---------- ----------
(In thousands except per share amounts)
Revenues $ 86,913 $ 143,350 $ 251,004 $ 362,873
========== ========== ========== ==========
Income Before Change
In Accounting
Principle $ 14,056 $ 24,647 $ 44,545 $ 60,900
========== ========== ========== ==========
Net Income $ 14,056 $ 24,647 $ 42,901 $ 60,900
========== ========== ========== ==========
Basic Earnings per
Share:
Income before
change in
accounting
principle $ 0.32 $ 0.54 $ 1.02 $ 1.33
========== ========== ========== ==========
Net income $ 0.32 $ 0.54 $ 0.99 $ 1.33
========== ========== ========== ==========
Diluted Earnings per
Share:
Income before
change in
accounting
principle $ 0.32 $ 0.54 $ 1.02 $ 1.33
========== ========== ========== ==========
Net income $ 0.32 $ 0.54 $ 0.98 $ 1.33
========== ========== ========== ==========
16
The pro forma results of operations are not necessarily indicative of the
actual results of operations that would have occurred for the respective periods
or of the results which may occur in the future.
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 a number of
factors including the depth capacity of the rigs, the working condition of the
rigs, the active nature of the acquired company's operations 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
==========
For the first nine months ending September 30, 2004, the rigs included in
the Service acquisition have achieved cash flow of approximately $10.0 million.
Based on the cash flow of these rigs in the second and third quarter of 2004 the
company is estimated to owe the sellers of Service an earn-out payment of
approximately $1.8 million for the year ended December 31, 2004.
17
NOTE 4 - Goodwill
- -----------------
Goodwill represents the excess of the cost of the acquisition of Hickman
Drilling Company, CREC Rig Equipment Company, CDC Drilling Company, SerDrilco
Incorporated and Sauer Drilling Company over the fair value of the net assets
acquired. Financial Accounting Standards No. 142, "Goodwill and Other Intangible
Assets" ("FAS 142") requires, at least annually, that an impairment test be
performed on such assets to determine whether the fair value has decreased.
Goodwill is all related to the drilling segment. The increase in the carrying
amount of goodwill of $4,698,000 during the third quarter of 2004 came from the
goodwill acquired in the acquisition of Sauer Drilling Company. The acquisition
is more fully discussed in Note 3.
Note 5 - SALE OF ASSETS
- -----------------------
On August 2, 2004, the company completed the sale of its investment in
Eagle Energy Partners I, L.P. for $6.2 million. In the third quarter of 2004, a
gain before income taxes of $3.8 million was recognized in other revenues from
this sale.
NOTE 6 - 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. On July 15, 2004, the company increased its loan commitment from $100
million to $150 million. 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 September 30, 2004, the company
had $107.5 million borrowed with $103.0 million subject to the Eurodollar Rate.
The average interest rate for the first nine months of 2004 was 2.54%.
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
18
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.
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 September 30, 2004, the company was in compliance with the covenants of
its credit agreement.
NOTE 7 - 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.
19
The following table shows the activity for the nine months ending September
30, 2003 and 2004 relating to the company's retirement obligation for plugging
liability:
Nine Months Ended
-----------------------------
2003 2004
------------- -------------
(In Thousands)
Short-Term Plugging Liability:
Liability at beginning of period $ 203 $ 303
Accretion of discount 8 6
Liability settled in the period -- (62)
Sold -- (21)
Reclassification of liability
from long- to short-term 181 --
------------- -------------
Plugging liability at end of
period $ 392 $ 226
============= =============
Long-Term Plugging Liability:
Liability at beginning of period $ 10,632 $ 11,691
Accretion of discount 369 619
Liability incurred in the period 529 6,048
Liability settled in the period (106) (16)
Sold -- (63)
Reclassification of liability
from long- to short-term (181) --
------------- -------------
Plugging liability at end of
Period $ 11,243 $ 18,279
============= =============
On September 28, 2004 the Security and Exchange Commission issued Staff
Accounting Bulletin No. 106 (SAB No. 106). The interpretations in SAB No. 106
express the staff's views regarding the application of FASB Statement No. 143,
"Accounting for Asset Retirement Obligations", by oil and gas producing
companies following the full cost accounting method.
Under Statement 143, the company must recognize a liability for an asset
retirement obligation at fair value in the period in which the obligation is
incurred, if a reasonable estimate of fair value can be made. The company also
20
must initially capitalize the associated asset retirement costs by increasing
its full cost pool by the same amount as the liability. Under the full cost
method of accounting, the company calculates quarterly a limitation on
capitalized costs, i.e., the full cost ceiling of our oil and natural gas
properties and any asset retirement costs capitalized pursuant to Statement 143
are subject to the full cost ceiling limitation. SAB No. 106 provides that after
adoption of Statement 143, the future cash outflows associated with settling
AROs that have been accrued on the balance sheet should be excluded from the
computation of the present value of estimated future net revenues for purposes
of the full cost ceiling calculation. The effect of this interpretation will
increase the ceiling the company has currently calculated on its full cost pool.
Subsequent to the adoption of Statement 143, the estimated dismantlement
and abandonment costs for the company's oil and natural gas properties that have
been capitalized have been included in the costs used when calculating the
depreciation, depletion and amortization (DD&A) rate used to amortize the
properties. Future development activities on proved reserves may result in
additional asset retirement obligations when such activities are performed and
the associated asset retirement costs will be capitalized at that time. Under
the interpretations in SAB No. 106 to the extent that estimated dismantlement
and abandonment costs, net of estimated salvage values, have not been
capitalized for future development activity, the company will be required to
estimate the amount of dismantlement and abandonment costs that will be incurred
and include those amounts in the costs to be amortized. The company has not yet
determined the full impact this will have on the DD&A rate used by it in the
fourth quarter of 2004, but it is not expected to be material.
The company will be required to apply the accounting and disclosures
described in SAB No. 106 prospectively as of the beginning of the fourth quarter
of 2004. The company has not yet determined the full impact this will have on
the DD&A rate used by it in the fourth quarter of 2004.
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
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. (which we sold in August 2004, See Note 5), 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
21
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 8 - 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. The company
previously reported that an interpretation of FAS 141 and 142 was being
considered as to whether mineral interest use rights in oil and natural gas
properties are intangible assets and would be classified as such, separate from
oil and natural gas properties.
On September 2, 2004, the FASB issued FASB Staff Position 142-2
"Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to
Oil- and Gas-Producing Entities" (FSP 142-2) to address the application of FAS
142 to the oil and natural gas industry. In FSP 142-2 the FASB staff
acknowledges that the accounting framework in Statement 19 for oil- and
gas-producing entities is based on the level of established reserves - not
whether an asset is tangible or intangible. Accordingly, the FASB staff believes
that the scope exception in paragraph 8(b) of FAS 142 extends to its disclosure
for drilling and mineral rights of oil- and gas-producing entities. FSP 142-2
confirms the company's historical treatment of these costs.
NOTE 9 - 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 company had a $6,000 reduction in natural gas revenues because of
the natural gas hedges settled in the second quarter of 2003 and a $1,000
reduction in oil revenues because of the oil hedges settled in the third quarter
22
of 2003. Since the amount was immaterial, no fair value was recognized on the
September 2003 balance sheet or in accumulated other comprehensive income for
the oil collar contracts which remained outstanding at the end of the period.
These hedges were cash flow hedges and there was no material amount of
ineffectiveness.
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 oil hedge
was recognized on the September 30, 2004 balance sheet as a derivative liability
of $1,739,000 and at a loss of $1,077,000, net of tax, in accumulated other
comprehensive income. These hedges were cash flow hedges and there was no
material amount of ineffectiveness. The natural gas collar contracts increased
natural gas revenues by $48,000 during the first nine months of 2004. Oil
revenues were reduced by $1,207,000 in the third quarter of 2004 due to the
settlement of the oil hedge and oil revenues have been reduced by $1,894,000 for
the nine months ended September 30, 2004.
NOTE 10 - 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 September 30, 2004, 50,000 feet (or approximately $1.6
million) of this commitment remained outstanding.
NOTE 11 - INDUSTRY SEGMENT INFORMATION
- -------------------------------------
With the acquisition of Superior Pipeline Company (See Note 3), the company
has three primary business segments: Contract Drilling; Oil and Natural Gas; and
Gas Gathering and Processing, each offering different products and services. The
Contract Drilling segment provides land contract drilling of oil and natural gas
wells, the Oil and Natural Gas segment is engaged in the development,
acquisition and production of oil and natural gas properties and the Gas
Gathering and Processing segment is engaged in the gathering, processing and
treating of natural gas.
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 nine month periods
ended September, 2003 and 2004 is as follows:
23
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- -----------------------
2003 2004 2003 2004
---------- ---------- ---------- ----------
(In thousands)
Revenues:
Contract drilling $ 53,191 $ 83,486 $ 136,232 $ 219,647
Elimination of
inter-segment
revenue 3,139 2,599 6,393 8,436
---------- ---------- ---------- ----------
Contract drilling
net of inter-
segment revenue 50,052 80,887 129,839 211,211
---------- ---------- ---------- ----------
Oil and natural gas 27,402 46,394 87,521 130,718
---------- ---------- ---------- ----------
Gas gathering and
processing 379 12,658 970 13,495
Elimination of
inter-segment
revenue 231 1,184 404 1,933
---------- ---------- ---------- ----------
Gas gathering and
processing net of
inter-segment
revenue 148 11,474 566 11,562
---------- ---------- ---------- ----------
Other(1) 198 4,595 832 5,497
---------- ---------- ---------- ----------
Total revenues $ 77,800 $ 143,350 $ 218,758 $ 358,988
========== ========== ========== ==========
24
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- -----------------------
2003 2004 2003 2004
---------- ---------- ---------- ----------
(In thousands)
Operating Income (2):
Contract drilling $ 8,081 $ 14,168 $ 15,623 $ 34,354
Oil and natural gas 14,223 24,332 49,402 66,819
Gas gathering and
processing 40 543 134 558
---------- ---------- ---------- ----------
Total operating
Income 22,344 39,043 65,159 101,731
General and admini-
strative expense (2,246) (3,081) (6,766) (8,955)
Interest expense (154) (820) (540) (1,751)
Other income - net 198 4,595 832 5,497
---------- ---------- ---------- ----------
Income before
income taxes $ 20,142 $ 39,737 $ 58,685 $ 96,522
========== ========== ========== ==========
- -----------------
(1) Other in 2004 includes a $3.8 million gain on the sale of the
investment in Eagle Energy Partners I, L.P.
(2) 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.
25
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Unit Corporation:
We have reviewed the accompanying consolidated condensed balance sheet of Unit
Corporation and its subsidiaries as of September 30, 2004, and the related
consolidated condensed statements of income and comprehensive income for each of
the three-month and nine-month periods ended September 30, 2004 and 2003 and the
consolidated condensed statements of cash flows for the nine-month periods ended
September 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 consolidated condensed 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,
shareholders' 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 consolidated condensed 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
November 5, 2004
26
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 three 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 quantity of natural gas produced, 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 and the prices received from gas gathering and
processing fees. At September 30, 2004, we had cash totaling $1.5 million and we
had borrowed $107.5 million of the $150.0 million we had elected to have
available under our credit agreement.
Our three 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, (ii) oil and natural gas exploration, carried out by
our subsidiaries Unit Petroleum Company and PetroCorp Incorporated and (iii) gas
gathering and processing carried out by our subsidiary Superior Pipeline
Company.
The following is a summary of certain financial information on September
30, 2003 and September 30, 2004 and for the nine months ended September 30, 2003
and September 30, 2004:
September 30, September 30, Percent
2003 2004 Change
-------------- -------------- -------
(In thousands except percent amounts)
Working Capital $ 27,074 $ 21,574 (20%)
Long-Term Bank Debt $ 15,000 $ 107,500 617%
Shareholders' Equity $ 461,341 $ 576,862 25%
Ratio of Long-Term Debt to
Total Capitalization 3% 16%
Income Before Change in
Accounting Principle $ 37,113 $ 60,341 63%
Net Income $ 38,438 $ 60,341 57%
Net Cash Provided by
Operating Activities $ 88,412 $ 151,771 72%
Net Cash Used in Investing
Activities $ (67,375) $ (258,576) 284%
Net Cash Provided by (Used
in) Financing Activities $ (19,769) $ 107,747 --
27
The following table summarizes certain operating information for the first
nine months of 2003 and 2004:
Percent
2003 2004 Change
------------ ------------ --------
Oil Production (MBbls) 372 767 106%
Natural Gas Production (MMcf) 15,043 19,855 32%
Average Oil Price Received $ 27.02 $ 32.17 19%
Average Oil Price Received
Excluding Hedge $ 27.02 $ 34.64 28%
Average Natural Gas Price
Received $ 5.05 $ 5.23 4%
Average Number of Our
Drilling Rigs in Use
During the Period 60.6 85.8 42%
Total Number of Our Drilling
Rigs Available at the End
of the Period 75 100 33%
Gas Gathered - MMBtu/day 11,200 26,090 133%
Gas Processed - MMBtu/day -- 26,669 --
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. On July 15, 2004, the company increased its loan commitment
from $100 million to $150 million. We are charged a commitment fee of .375 of 1%
on the amount available but not borrowed. 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 nine months
of 2004 was 2.54%. At September 30, 2004 and October 27, 2004 our borrowings
were $107.5 million and $103.0 million, respectively.
The borrowing base 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
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
28
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 September 30, 2004, $103.0
million of our $107.5 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.
On September 30, 2004, we were in compliance with the covenants of the
credit agreement.
29
Contractual Commitments. We have the following contractual obligations at
September 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) $107,500 $ -- $ -- $107,500 $ --
Retirement
Agreement(2) 1,158 300 600 258 --
Operating
Leases(3) 4,467 1,168 2,031 1,094 174
Drill Pipe
Acquisi-
tions(4) 1,600 1,600 -- -- --
Hedging
Liability(5) 1,739 1,739 -- -- --
--------- -------- -------- --------- --------
Total
Contractual
Obligations $116,464 $ 4,807 $ 2,631 $108,852 $ 174
========= ======== ======== ========= ========
-------------------
(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 a few office machines and 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 September 30, 2004 approximately 50,000 feet of that
commitment remained outstanding.
(5) The fair value of our oil hedge is recognized as a derivative liability
at September 30, 2004. See subsequent discussion in Management Discussion
and Analysis regarding hedging.
30
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. For the first nine months ending September 30, 2004,
the rigs included in the Service acquisition have achieved cash flow of
approximately $10.0 million. Based on the cash flow of these rigs in the second
and third quarter of 2004 the company is estimated to owe the sellers of Service
an earn-out payment of approximately $1.8 million for the year ended December
31, 2004.
On October 19, 2004, Mr. John Nikkel, the Company's Chairman of the Board
of Directors and Chief Executive Officer, announced that he plans to retire as
an employee and as the Company's Chief Executive Officer effective April 1,
2005. Mr. Nikkel intends to continue as a director of the Company. In connection
with the retirement, the Board of Directors of Unit Corporation and Mr. Nikkel
have reached an agreement providing for the following:
a. Mr. Nikkel would serve as a consultant to the Company, on an annual
basis, for $70,000 per year; and
b. The Company would provide office space and secretarial service for Mr.
Nikkel for the time he serves as a consultant to the Company.
At September 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) $ 2,079 Unknown Unknown Unknown Unknown
Separation
Benefit
Agreement(2) $ 2,735 $ 415 Unknown Unknown Unknown
Plugging
Liability(3) $ 18,505 $ 226 $ 602 $ 841 $ 16,836
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
31
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 us 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
(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 nine months of 2004.
32
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. We
had a $6,000 reduction in natural gas revenues because of the natural gas hedges
settled in the second quarter of 2003 and a $1,000 reduction in oil revenues
because of the oil hedges settled in the third quarter of 2003. Since the amount
was immaterial, no fair value was recognized on the September 2003 balance sheet
or in accumulated other comprehensive income for the oil collar contracts which
remained outstanding at the end of the period. These hedges were cash flow
hedges and there was no material amount of ineffectiveness.
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.
The transaction covers the periods of February through December of 2004 and has
an average price of $31.40. The fair value of the oil hedge was recognized on
the September 30, 2004 balance sheet as a derivative liability of $1,739,000 and
at a loss of $1,077,000, net of tax, in accumulated other comprehensive income.
These hedges were cash flow hedges and there was no material amount of
ineffectiveness. The natural gas collar contracts increased natural gas revenues
by $48,000 during the first nine months of 2004. Oil revenues were reduced by
$1,207,000 in the third quarter of 2004 due to the settlement of the oil hedge
and oil revenues have been reduced by $1,894,000 for the nine months ended
September 30, 2004.
33
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 $235,000 per month ($2,820,000
annualized) change in our pre-tax operating cash flow. Our first nine month 2004
average natural gas price was $5.23 compared to an average natural gas price of
$5.05 for the first nine months of 2003. A $1.00 per barrel change in our oil
price would have a $92,800 per month ($1,114,000 annualized) change in our
pre-tax operating cash flow based on our production in 2004 after the
acquisition of PetroCorp Incorporated. Our first nine month 2004 average oil
price was $32.17 compared with an average oil price of $27.02 received in the
first nine 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
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. Presently we believe that our buyers will be able to
perform their commitments to us. On August 2, 2004, we completed the sale of our
16.7% limited partner interest in Eagle Energy Partners I, L.P., whose
purchases, which are competitively marketed, accounted for 29% of our oil and
34
natural gas revenues in the first nine months of 2004. They marketed
approximately 56% of the natural gas volumes we sold for ourselves and third
parties during the same period.
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
110 wells (47.02 net wells) in the first nine months of 2004 compared to 98
wells (38.04 net wells) in the first nine months of 2003. Our total capital
expenditures for oil and natural gas exploration and acquisitions in the first
nine months of 2004 totaled $187.8 million with $115.6 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 nine
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
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 in the future, shortages of
experienced personnel may well 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 in the availability 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 September 30,
2004, 50,000 feet (or approximately $1.6 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
35
rise since the second quarter of 2003 and have continued to remain strong
through the first nine months of 2004 and both demand for our drilling rigs and
dayrates have continued to improve. In the first nine months of 2004, the
average dayrate we received was $8,722 per day compared to $7,684 per day in the
first nine months of 2003. The average use of our drilling rigs in the first
nine months of 2004 was 85.8 rigs (95%) compared with 60.6 rigs (81%) for the
first nine months of 2003. Based on the average utilization of our drilling rigs
in the first nine months of 2004, a $100 per day change in dayrates has an
$8,580 per day ($3,132,000 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 nine
months of 2003 and 2004, we drilled 34 and 30 wells, respectively, for our
exploration and production subsidiaries. The profit received by our contract
drilling segment of $1,411,000 and $2,760,000 during the first nine 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 July 30, 2004, we acquired 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. In addition, the agreement provides that there
will be a post closing settlement adjustment for the working capital of Sauer
Drilling Company. Currently the seller has estimated this cost to be $6.2
million and the company has estimated this cost to be $5.3 million. In the event
the parties can not resolve this discrepancy, the issue will be settled by
arbitration. 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 increased 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.
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. We refurbished the rigs for
36
approximately $4.0 million. One rig was placed into service at the beginning of
August 2004 and the other rig was placed into service in the middle of September
2004. Both rigs are working in the area covered by the Rocky Mountain division.
The 2 rigs acquired on May 4, 2004 and the Sauer Drilling Company rigs were
added to the area covered by the Rocky Mountain division bringing the total rigs
in that area to 19. With these two acquisitions and the completion of
construction of another rig in June 2004, our total rig fleet now consists of
100 drilling rigs. We are currently constructing our 101st rig which is
contracted and should be ready to enter the market in December 2004.
Our contract drilling operations, during the first nine months of 2004,
incurred $82.1 million in capital expenditures including the $34.7 million paid
for the Sauer Drilling Company acquisition and the $9.5 million paid for the 2
rigs acquired on May 4, 2004 and their subsequent refurbishment. For the year
2004, we have budgeted capital expenditures of approximately $50 million for our
contract drilling operations (excluding our acquisition of Sauer Drilling
Company and the capital expenditures on the two rigs acquired on May 4, 2004).
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. For the first nine months ending September 30, 2004, the
rigs included in the Service acquisition have achieved cash flow of
approximately $10.0 million. Based on the cash flow of these rigs in the second
and third quarter of 2004 the company is estimated to owe the sellers of Service
an earn-out payment of approximately $1.8 million for the year ended December
31, 2004.
Acquisition of Gas Gathering and Processing Company
On July 29, 2004, we completed the acquisition of the 60% of Superior
Pipeline Company LLC ("Superior") we did not already own for $19.8 million.
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 400 miles of pipeline.
Superior operates in western Oklahoma and the Texas Panhandle and has been in
business since 1996. This acquisition will 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. During the first nine
months of 2004, Superior purchased $3.1 million of our natural gas production
and paid $30,000 for our natural gas liquids. We paid this company $300,000 for
gathering and compression services in the first nine months of 2004. The results
of operations for this acquired company are included in the statement of income
for the period after July 31, 2004 and intercompany revenue from services and
purchases of production between subsidiaries has been eliminated.
37
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 and during
the first nine months of 2004 the amount paid has been 15 percent below last
year's nine month comparable amount. Our proportionate share of assets,
liabilities and net income relating to the oil and natural gas partnerships is
included in our consolidated financial statements.
On August 2, 2004, we completed the sale of our investment in Eagle Energy
Partners I, L.P. for $6.2 million. In the third quarter of 2004, a gain before
income taxes of $3.8 million was recognized in other revenues from this sale.
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 nine
months of 2004.
Critical Accounting Policies.
Summary
In this section, we have identified the critical accounting policies we
follow in preparing our financial statements and related disclosures. Many of
these policies require us to make difficult, subjective and complex judgments in
the course of making estimates of matters that are inherently imprecise. We will
explain the nature of these estimates, assumptions and judgments, and the
likelihood that materially different amounts would be reported in our financial
statements under different conditions or using different assumptions.
38
The following table lists our critical accounting policies, the estimates
and assumptions that can have a significant impact on the application of these
accounting policies, and the financial statement accounts affected by these
estimates and assumptions.
Accounting Policies Estimates or Accounts Affected
Assumptions
- --------------------- -------------------- --------------------
Full cost method of . Reserve . Oil and gas
accounting for oil estimates and properties
and gas properties related present . Accumulated DD&A
value of future . Provision for
net revenues DD&A
. Valuation of . Impairment of
unproved proved and
properties unproved
properties
. Long-term debt
and interest
expense
Accounting for . Cost estimates . Oil and gas
asset retirement related to the properties
obligations for oil plugging and . Accumulated DD&A
and gas properties abandonment of . Provision for
depleted wells DD&A
. Current and non-
current
liabilities
. Operating expense
Accounting for . Forecast of . Drilling property
impairment of undiscounted and equipment
drilling property estimated future . Accumulated
and equipment net operating cash depreciation
flows . Provision for
depreciation
. Impairment of
drilling property
and equipment
Turnkey and footage . Estimates of costs . Revenue and
drilling contracts to complete turnkey operating expense
and footage . Current assets and
contracts liabilities
39
Significant Estimates and Assumptions
Reserve engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact manner. The
accuracy of a reserve estimate depends on the quality of available geological
and engineering data, the precision of the interpretations of that data, and
judgment based on experience and training. Annually, we engage an independent
petroleum engineering firm to evaluate our oil and gas reserves.
The techniques used in estimating reserves annually depend on the nature
and extent of available data and the accuracy of the estimates accordingly. As a
general rule, the degree of accuracy of reserve estimates varies with the
reserve classification and the related accumulation of available data, as shown
in the following table.
Type of Reserves Nature of Available Degree of Accuracy
Data
------------------ --------------------- --------------------
Proved undeveloped Data from offsetting Least accurate
wells, seismic data
Proved developed Logs, core samples, More accurate
Non-producing well tests, pressure
data
Proved developed Production history, Most accurate
Producing pressure data over
time
Assumptions as to future commodity prices and operating and capital costs
also play a significant role in estimating oil and gas reserves and the
estimated present value of the cash flows to be received from the future
production of those reserves. Volumes of recoverable reserves are affected by
the assumed prices and costs due to what is known as the economic limit (that
point in the future when the projected costs and expenses of producing
recoverable reserves exceed the projected revenues from the reserves). But more
significantly, the estimated present value of future cash flows from the
reserves is extremely sensitive to prices and costs, and may vary materially
based on different assumptions. SEC financial accounting and reporting standards
require that pricing parameters be tied to the price received for oil and
natural gas on the last day of the reporting period. This requirement can
result in significant changes from period to period given the volatile nature of
oil and natural gas prices.
We compute our provision for DD&A on a units-of-production method. Each
quarter, we use the following formulas to compute the provision for DD&A for our
producing properties:
. DD&A Rate = Unamortized Cost / Beginning of Period Reserves
. Provision for DD&A = DD&A Rate x Current Period Production
40
Reserve estimates have a significant impact on the DD&A rate. If reserve
estimates for a property or group of properties are revised downward in future
periods, the DD&A rate will increase as a result of the revision. Alternatively,
if reserve estimates are revised upward, the DD&A rate will decrease.
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
natural gas prices, even if temporary, increases the chance of a ceiling test
write-down. Based on oil and natural gas prices on September 30, 2004 ($5.74 per
Mcf for natural gas and $49.64 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 and oil 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.
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.
41
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.
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.
42
NEW ACCOUNTING PRONOUNCEMENTS
- -----------------------------
On September 28, 2004 the Security and Exchange Commission issued Staff
Accounting Bulletin No. 106 (SAB No. 106). The interpretations in SAB No. 106
express the staff's views regarding the application of FASB Statement No. 143,
"Accounting for Asset Retirement Obligations", by oil and gas producing
companies following the full cost accounting method.
Under Statement 143, we must recognize a liability for an asset retirement
obligation at fair value in the period in which the obligation is incurred, if a
reasonable estimate of fair value can be made. We also must initially capitalize
the associated asset retirement costs by increasing our full cost pool by the
same amount as the liability. Under the full cost method of accounting, we
calculate quarterly a limitation on capitalized costs, i.e., the full cost
ceiling of our oil and natural gas properties and any asset retirement costs
capitalized pursuant to Statement 143 are subject to the full cost ceiling
limitation. SAB No. 106 provides that after adoption of Statement 143, the
future cash outflows associated with settling AROs that have been accrued on the
balance sheet should be excluded from the computation of the present value of
estimated future net revenues for purposes of the full cost ceiling calculation.
The effect of this interpretation will increase the ceiling we currently
calculated on our full cost pool.
Subsequent to the adoption of Statement 143, the estimated dismantlement
and abandonment costs for our oil and natural gas properties that have been
capitalized have been included in the costs used when calculating the
depreciation, depletion and amortization (DD&A) rate used to amortize the
properties. Future development activities on proved reserves may result in
additional asset retirement obligations when such activities are performed and
the associated asset retirement costs will be capitalized at that time. Under
the interpretations in SAB No. 106 to the extent that estimated dismantlement
and abandonment costs, net of estimated salvage values, have not been
capitalized for future development activity, we will be required to estimate the
amount of dismantlement and abandonment costs that will be incurred and include
those amounts in the costs to be amortized. We have not yet determined the full
impact this will have on the DD&A rate used by us in the fourth quarter of 2004,
but it is not expected to be material.
We are required to apply the accounting and disclosures described in SAB
No. 106 prospectively as of the beginning of the fourth quarter of 2004. We have
not yet determined the full impact this will have on the DD&A rate used by us in
the fourth quarter of 2004.
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
43
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. We previously reported that an interpretation of FAS 141 and 142
was being considered as to whether mineral interest use rights in oil and
natural gas properties are intangible assets and would be classified as such,
separate from oil and natural gas properties.
On September 2, 2004, the FASB issued FASB Staff Position 142-2
"Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to
Oil- and Gas-Producing Entities" (FSP 142-2) to address the application of FAS
142 to the oil and natural gas industry. In FSP 142-2 the FASB staff
acknowledges that the accounting framework in Statement 19 for oil- and
gas-producing entities is based on the level of established reserves - not
whether an asset is tangible or intangible. Accordingly, the FASB staff believes
that the scope exception in paragraph 8(b) of FAS 142 extends to its disclosure
for drilling and mineral rights of oil- and gas-producing entities. FSP 142-2
confirms our historical treatment of these costs.
44
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
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.
45
RESULTS OF OPERATIONS
- ---------------------
Third Quarter 2004 versus Third Quarter 2003
- --------------------------------------------
Provided below is a comparison of selected operating and financial data for
the third quarter of 2004 versus the third quarter of 2003:
Third Third Percent
Quarter 2003 Quarter 2004 Change
--------------- --------------- ---------
Total Revenue $ 77,800,000 $ 143,350,000 84%
Net Income $ 12,763,000 $ 24,647,000 93%
Oil and Natural Gas:
Revenue $ 27,402,000 $ 46,394,000 69%
Operating costs $ 6,207,000 $ 9,746,000 57%
Average natural gas price (Mcf) $ 4.50 $ 5.21 16%
Average oil price (Bbl) $ 25.51 $ 34.46 35%
Natural gas production (Mcf) 5,233,000 6,947,000 33%
Oil production (Bbl) 134,000 274,000 104%
Depreciation, depletion and
amortization rate (Mcfe) $ 1.14 $ 1.43 25%
Depreciation, depletion and
amortization $ 6,972,000 $ 12,316,000 77%
Drilling:
Revenue $ 50,052,000 $ 80,887,000 62%
Operating costs $ 35,653,000 $ 57,816,000 62%
Percentage of revenue from
daywork contracts 99% 100%
Average number of rigs in use 68.2 92.0 35%
Average dayrate on daywork
Contracts $ 8,015 $ 9,103 14%
Depreciation $ 6,318,000 $ 8,903,000 41%
Gas Gathering and Processing:
Revenues $ 148 $ 11,474 7,652%
Operating costs $ 50 $ 10,480 20,860%
Gas gathered - MMBtu/day 14,758 28,356 92%
Gas processed - MMBtu/day -- 26,669 --
Depreciation $ 58 $ 451 678%
General and Administrative Expense $ 2,246,000 $ 3,081,000 37%
Interest Expense $ 154,000 $ 820,000 432%
Average Interest Rate 2.26% 2.99% 32%
Average Long-Term Debt Outstanding $ 16,763,000 $ 98,749,000 489%
46
Oil and natural gas revenues increased 69% due to increases in both oil and
natural gas production and from increases in oil and natural gas prices between
the third quarter of 2004 and the third 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 104% between
the comparative quarters. Oil production from PetroCorp wells contributed 61% of
the increase while the remaining wells owned by us contributed 43% of the
increase. Natural gas production was up 33% between the comparative quarters.
Natural gas production from PetroCorp wells contributed 13% of the increase
while the remaining wells owned by us contributed 20% of the increase. The
increase in production for both oil and natural gas over that contributed from
the PetroCorp acquisition came from wells added through our development drilling
program. We will continue to grow production primarily in natural gas through
development drilling and acquisition of producing oil and natural gas properties
when economical. Increases or decreases in future revenues, however are largely
determined by the prices we receive for our natural gas production. Based on the
Nymex futures prices for the fourth quarter of 2004 and the first quarter of
2005, we anticipate prices for natural gas to increase from prices received
during the third quarter of 2004.
Total operating cost increased 57% in the third quarter of 2004 when
compared with the third 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 concentrated
toward oil. Operating cost from PetroCorp wells contributed to 35% of the
increase while the remaining wells owned by us contributed 22% of the increase.
We anticipate that there will continue to be upward pressure on the amount we
pay for services associated with operating our wells throughout the coming year.
Gross production taxes which are based on a percentage of revenues were also
higher, since they are a percentage of total revenues received. Our total
depreciation, depletion and amortization ("DD&A) increased 77% due to an
increase in both the equivalent volumes produced and our DD&A rate per Mcfe. The
increase in volumes produced increased total DD&A by 41% while the increase in
the DD&A rate increased total DD&A by 36%. 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 previous
acquisitions. During 2003 and the first nine 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 62% between the comparative quarters
due to increases in demand for our drilling rigs and increases in dayrates.
Dayrates increased revenue by 15% with the remainder of the increase coming from
increased utilization. Utilization increased by 23.8 rigs with 16.6 of the
increase in rigs utilized coming from the 12 Service Drilling Company and 9
Sauer Drilling Company rigs acquired in December 2003 and July 2004,
respectively. Natural gas prices remained between $4.00 and $5.50 through most
of 2003 and continued at that level into the first nine months of 2004 causing
an increase in demand for our rigs. Dayrates, which typically increase after the
47
increase in demand for rigs, also started increasing in the second quarter of
2003 and have continued to steadily increase throughout the first nine months of
2004. With the increase in demand and the rigs added through our acquisitions,
total operating cost increased along with our revenues. We did not drill any
turnkey or footage wells in the third quarter of 2004. Approximately 1% of our
total drilling revenues in the third quarter of 2003 came from footage and
turnkey contracts, which had profit margins lower than our daywork contracts.
Dayrates for our contract drilling services are anticipated to increase over
levels achieved in the third quarter of 2004 and utilization is anticipated to
remain high through 2005 as long as commodity prices remain at the levels
achieved in 2004. Contract drilling depreciation increased 41% due to the
acquisition of 12 rigs in the fourth quarter of 2003 and 9 rigs in the third
quarter of 2004 and increased rig utilization from rigs previously owned.
On July 29, 2004, we completed the acquisition of the 60% of Superior
Pipeline Company LLC ("Superior") we did not already own for $19.8 million.
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 400 miles of pipeline.
Superior operates in western Oklahoma and the Texas Panhandle and has been in
business since 1996. This acquisition will increase our ability to gather and
market our (as well as third party's) natural gas and construct or acquire
existing natural gas gathering and processing facilities. The results of
operations for this acquired company are included in the statement of income for
the period after July 31, 2004. Gas gathering and processing revenues increased
by $11.3 million and gas gathering and processing operating costs increased by
$10.4 million between the comparative quarters as a result of the acquisition.
General and administrative expense increased 37% in the third quarter of
2004 due primarily to increases in employee cost of $362,000, outside audit
related costs and other third party costs primarily associated with compliance
of the Sarbanes-Oxley Act of approximately $170,000, and general corporate cost
of $160,000. Increases in general and administrative expenses are anticipated in
the remainder of 2004 and into 2005. Our total interest expense was higher due
to the additional debt incurred from the PetroCorp Incorporated, Superior
Pipeline Company and Sauer Drilling Company acquisitions. In the absence of
further acquisitions, we intend to pay down this debt in 2005 through cash flow
from our operating activity. Income tax expense increased primarily due to the
increase in income before income taxes. Current income tax expense increased in
the third 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.
On August 2, 2004, the company completed the sale of its investment in
Eagle Energy Partners I, L.P. for $6.2 million. In the third quarter of 2004, a
gain before income taxes of $3.8 million was recognized in other revenues from
this sale.
48
First Nine Months 2004 versus First Nine Months 2003
- ----------------------------------------------------
Provided below is a comparison of selected operating and financial data for
the first nine months of 2004 versus the first nine months of 2003:
First Nine First Nine Percent
Months 2003 Months 2004 Change
--------------- --------------- ---------
Total Revenue $ 218,758,000 $ 358,988,000 64%
Income Before Change in Accounting
Principle $ 37,113,000 $ 60,341,000 63%
Net Income $ 38,438,000 $ 60,341,000 57%
Oil and Natural Gas:
Revenue $ 87,521,000 $ 130,718,000 49%
Operating costs $ 18,655,000 $ 29,871,000 60%
Average natural gas price (Mcf) $ 5.05 $ 5.23 4%
Average oil price (Bbl) $ 27.02 $ 32.17 19%
Natural gas production (Mcf) 15,043,000 19,855,000 32%
Oil production (Bbl) 372,000 767,000 106%
Depreciation, depletion and
amortization rate (Mcfe) $ 1.12 $ 1.38 23%
Depreciation, depletion and
amortization $ 19,464,000 $ 34,028,000 75%
Drilling:
Revenue $ 129,839,000 $ 211,211,000 63%
Operating costs $ 97,105,000 $ 152,736,000 57%
Percentage of revenue from
daywork contracts 97% 100%
Average number of rigs in use 60.6 85.8 42%
Average dayrate on daywork
contracts $ 7,684 $ 8,722 14%
Depreciation $ 17,111,000 $ 24,121,000 41%
Gas Gathering and Processing:
Revenue $ 566 $ 11,562 1,943%
Operating costs $ 307 $ 10,515 3,325%
Gas gathered - MMBtu/day 11,200 26,090 133%
Gas processed - MMBtu/day -- 26,669 --
Depreciation $ 125 $ 489 291%
General and Administrative Expense $ 6,766,000 $ 8,955,000 32%
Interest Expense $ 540,000 $ 1,751,000 224%
Average Interest Rate 2.16% 2.54% 18%
Average Long-Term Debt Outstanding $ 23,727,000 $ 76,740,000 223%
49
Oil and natural gas revenues increased 49% due to increases in both oil and
natural gas production and to a lesser extent from an increase in oil and
natural gas prices between the first nine months of 2004 and the first nine
months 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 106% compared to the first nine months of 2003. Oil
production from PetroCorp wells contributed 64% of the increase while the
remaining wells owned by us contributed 42% of the increase. Natural gas
production was up 32% compared to the first nine months of 2003. Natural gas
production from PetroCorp wells contributed 18% of the increase while the
remaining wells owned by us contributed 14% of the increase. The increase in
production for both oil and natural gas over that contributed from the PetroCorp
acquisition came from wells added through our development drilling program. We
will continue to grow production primarily in natural gas through development
drilling and acquisition of producing oil and natural gas properties when
economical. Increases or decreases in future revenues, however are largely
determined by the prices we receive for our natural gas production. Based on the
Nymex futures prices for the fourth quarter of 2004 and the first quarter of
2005, we anticipate prices for natural gas to increase from prices received
during the first nine months of 2004.
Total operating cost increased 60% in the first nine months of 2004 when
compared with the first nine 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 concentrated
toward oil. Operating cost from PetroCorp wells contributed to 35% of the
increase while the remaining wells owned by us contributed 25% of the increase.
We anticipate that there will continue to be upward pressure on the amount we
pay for services associated with operating our wells throughout the coming year.
Gross production taxes which are based on a percentage of revenues were also
higher. Our total depreciation, depletion and amortization ("DD&A) increased 75%
due to the increase in equivalent volumes produced and an increase in our DD&A
rate per Mcfe. The increase in volumes produced increased total DD&A by 42%
while the increase in the DD&A rate increased total DD&A by 33%.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 nine months of 2004, we also
experienced higher cost per Mcfe for the discovery of new reserves through our
development drilling.
Contract drilling revenues increased 63% due to increases in demand for our
drilling rigs and increases in dayrates. Dayrates increased revenue by 16% with
the remainder of the increase coming from increased utilization. Utilization
increased by 25.2 rigs with 13.2 of the increase in rigs utilized coming from
the 12 Service Drilling Company and 9 Sauer Drilling Company rigs acquired in
December 2003 and July 2004, respectively. Natural gas prices remained between
$4.00 and $5.50 through most of 2003 and continued at that level into the first
nine months of 2004 causing an increase in demand for our rigs. Dayrates, which
50
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 nine months of 2004. With the increase in demand and the
rigs added through our acquisitions total operating cost increased along with
our revenues. We did not drill any turnkey or footage wells in the first nine
months of 2004. Approximately 3% of our total drilling revenues in the first
nine months of 2003 came from footage and turnkey contracts, which had profit
margins lower than our daywork contracts. Dayrates for our contract drilling
services are anticipated to increase over the 2004 year-to-date levels and
utilization is anticipated to remain high through 2005 as long as commodity
prices remain at the levels achieved in 2004. Contract drilling depreciation
increased due to the utilization associated with the 12 rigs acquired in the
fourth quarter of 2003 and the 9 rigs acquired in the third quarter of 2004 and
increases in utilization from the remainder of our rigs.
On July 29, 2004, we completed the acquisition of the 60% of Superior
Pipeline Company LLC ("Superior") we did not own for $19.8 million. 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 400 miles of pipeline. Superior operates in
western Oklahoma and the Texas Panhandle and has been in business since 1996.
This acquisition will increase our ability to gather and market our (as well as
third party's) natural gas and construct or acquire existing natural gas
gathering and processing facilities. The results of operations for this acquired
company are included in the statement of income for the period after to July 31,
2004. Gas gathering and processing revenues increased by $11.0 million and
operating costs by $10.2 million in the comparative nine month periods as a
result of this acquisition.
General and administrative expense increased 32% in the nine months of 2004
primarily due to increases in employee cost of $1.2 million, outside audit
related costs and other third party costs primarily associated with compliance
of the Sarbanes-Oxley Act of approximately $365,000, insurance cost of $238,000
and general corporate cost of $165,000. Increases in general and administrative
expenses are anticipated in the remainder of 2004 and into 2005. Our total
interest expense was higher due to the additional debt incurred from the
PetroCorp Incorporated, Superior Pipeline and Sauer Drilling Company
acquisitions. In the absence of further acquisitions, we intend to pay down this
debt in 2005 through cash flow from our operating activity. Income tax expense
increased primarily due to the increase in income before income taxes. Current
income tax expense increased in the first nine 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 nine 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).
51
On August 2, 2004, the company completed the sale of its investment in
Eagle Energy Partners I, L.P. for $6.2 million. In the third quarter of 2004, a
gain before income taxes of $3.8 million was recognized in other revenues from
this sale.
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 purposes.
Commodity Price Risk
We produce, purchase, gather, process 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 September 30, 2004, our
total bank debt was $107.5 million, of which $103.0 million 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. Based on our current debt
level at September 30, 2004, a one percent change in the interest rate we pay
will have a $89,600 per month ($1,075,000 annualized) change in our pre-tax
operating cash flow.
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.
52
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 September 30, 2004 that has materially affected, or is
reasonably likely to materially affect, our internal control over financial
reporting.
53
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
- --------------------------
Not applicable
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
- --------------------------------------------------------------------
Not applicable
Item 3. Defaults Upon Senior Securities
- ----------------------------------------
Not applicable
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
Not applicable
Item 5. Other Information
- --------------------------
Not applicable
Item 6. Exhibits
- -----------------
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.
99.1 Form of Stock Option Agreement used under the Unit Corporation
2000 Non-Employee Directors' Stock Option Agreement.
99.2 Form of ISO Agreement used under the Employee Stock
Option Plan.
54
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
UNIT CORPORATION
Date: November 9, 2004 By: /s/ John G. Nikkel
--------------------------- ------------------------------
JOHN G. NIKKEL
Chief Executive Officer,
and Director
Date: November 9, 2004 By: /s/ David T. Merrill
--------------------------- ------------------------------
DAVID T. MERRILL
Chief Financial Officer and
Treasurer
55