Back to GetFilings.com
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 March 31, 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 45,715,768
---------------------------- ----------
Class Outstanding at May 3, 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 March 31, 2004. . . . . . . . . . 2
Consolidated Condensed Statements of Income
Three Months Ended March 31, 2003 and 2004. . . . . . . 4
Consolidated Condensed Statements of Cash Flows
Three Months Ended March 31, 2003 and 2004. . . . . . . 5
Consolidated Condensed Statements of Comprehensive
Income Three Months Ended March 31, 2003 and 2004 . . . 6
Notes to Consolidated Condensed Financial Statements. . 7
Report of Independent Accountants . . . . . . . . . . . 20
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . 21
Item 3. Quantitative and Qualitative Disclosure about
Market Risk . . . . . . . . . . . . . . . . . . . . . . 37
Item 4. Controls and Procedures . . . . . . . . . . . . . . . . 37
PART II. Other Information
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . 38
Item 2. Changes in Securities, Use of Proceeds and
Issuer Purchases of Equity Securities . . . . . . . . 38
Item 3. Defaults Upon Senior Securities. . . . . . . . . . . . 38
Item 4. Submission of Matters to a Vote of Security Holders . . 38
Item 5. Other Information . . . . . . . . . . . . . . . . . . . 38
Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . 39
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
1
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
- -----------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS (UNAUDITED)
December 31, March 31,
2003 2004
----------- -----------
(In thousands)
ASSETS
------
Current Assets:
Cash and cash equivalents $ 598 $ 377
Restricted cash -- 5,352
Accounts receivable 58,807 66,567
Materials and supplies 8,023 10,409
Income tax receivable 112 --
Other 5,202 5,763
----------- -----------
Total current assets 72,742 88,468
----------- -----------
Property and Equipment:
Drilling equipment 424,321 432,419
Oil and natural gas properties, on the
full cost method:
Proved properties 528,110 655,391
Undeveloped leasehold not being
amortized 17,486 25,244
Transportation equipment 9,828 10,108
Other 14,535 15,611
----------- -----------
994,280 1,138,773
Less accumulated depreciation, depletion,
amortization and impairment 385,219 403,263
----------- -----------
Net property and equipment 609,061 735,510
----------- -----------
Goodwill 23,722 23,722
Other Assets 7,400 9,114
----------- -----------
Total Assets $ 712,925 $ 856,814
=========== ===========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
2
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS - CONTINUED (UNAUDITED)
December 31, March 31,
2003 2004
----------- -----------
(In thousands)
LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------
Current Liabilities:
Current portion of long-term liabilities
and debt $ 1,015 $ 984
Accounts payable 32,871 30,820
Accrued liabilities 17,925 30,996
----------- -----------
Total current liabilities 51,811 62,800
----------- -----------
Long-Term Debt 400 75,000
----------- -----------
Other Long-Term Liabilities 17,893 23,700
----------- -----------
Deferred Income Taxes 127,053 162,641
----------- -----------
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
45,709,568 shares issued, respectively 9,117 9,141
Capital in excess of par value 307,938 309,538
Accumulated other comprehensive income -- (226)
Retained earnings 198,713 214,220
----------- -----------
Total shareholders' equity 515,768 532,673
----------- -----------
Total Liabilities and Shareholders' Equity $ 712,925 $ 856,814
=========== ===========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
3
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME (UNAUDITED)(NOTE 1)
Three Months Ended
March 31,
--------------------------
2003 2004
---------- ----------
(In thousands except per
share amounts)
Revenues:
Contract drilling $ 34,566 $ 63,214
Oil and natural gas 33,248 37,990
Other 750 696
---------- ----------
Total revenues 68,564 101,900
---------- ----------
Expenses:
Contract drilling:
Operating costs 27,811 46,556
Depreciation 4,894 7,464
Oil and natural gas:
Operating costs 6,615 9,732
Depreciation depletion and
amortization 6,047 10,177
General and administrative 2,450 2,771
Other 325 222
Interest 211 417
---------- ----------
Total expenses 48,353 77,339
---------- ----------
Income Before Income Taxes 20,211 24,561
---------- ----------
Income Tax Expense:
Current 155 571
Deferred 7,525 8,763
---------- ----------
Total income taxes 7,680 9,334
---------- ----------
Equity in Earnings of Unconsolidated
Investments, Net of Income Tax 128 280
---------- ----------
Income Before Change in Accounting
Principle 12,659 15,507
Cumulative Effect of Change in Accounting
Principle (Net of Income Tax of $811) 1,325 --
---------- ----------
Net Income $ 13,984 $ 15,507
========== ==========
Basic Earnings per Common Share:
Income before change in accounting
principle $ 0.29 $ 0.34
Cumulative effect of change in
accounting principle, net of
income tax 0.03 --
---------- ----------
Net income $ 0.32 $ 0.34
========== ==========
Diluted Earnings per Common Share:
Income before change in accounting
principle $ 0.29 $ 0.34
Cumulative effect of change in
accounting principle, net of income tax 0.03 --
---------- ----------
Net income $ 0.32 $ 0.34
========== ==========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
4
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended
March 31,
-------------------------
2003 2004
---------- ----------
(In thousands)
Cash Flows From Operating Activities:
Net income $ 13,984 $ 15,507
Adjustments to reconcile net income
to net cash provided (used) by
operating activities:
Depreciation, depletion,
and amortization 11,103 17,886
Deferred tax expense 7,604 8,935
Other (1,028) (17)
Changes in operating assets and
liabilities increasing (decreasing)
cash:
Accounts receivable (8,979) 899
Accounts payable (434) (2,388)
Material and supplies inventory 1,017 (2,386)
Prepaid expenses 112 (565)
Contract advances 27 2,955
Other - net 1,029 1,786
---------- ----------
Net cash provided by
operating activities 24,435 42,612
---------- ----------
Cash Flows From (Used In) Investing
Activities:
Capital expenditures (including producing
property acquisitions) (18,663) (124,324)
Proceeds from disposition of assets 141 1,023
Other-net 31 350
---------- ----------
Net cash used in
investing activities (18,491) (122,951)
---------- ----------
Cash Flows From (Used In) Financing
Activities:
Net borrowings (payments) under
line of credit (4,500) 74,600
Net payments of notes payable
and other long-term debt (1,000) --
Proceeds from exercise of stock options 393 219
Book overdrafts (1,106) 5,299
---------- ----------
Net cash from (used in) financing
activities (6,213) 80,118
---------- ----------
Net Decrease in Cash and
Cash Equivalents (269) (221)
Cash and Cash Equivalents, Beginning
of Year 497 598
---------- ----------
Cash and Cash Equivalents, End of Period $ 228 $ 377
========== ==========
See Note 3 for non-cash investing activities.
The accompanying notes are an integral part of the
consolidated condensed financial statements.
5
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
Three Months Ended
March 31,
---------------------
2003 2004
--------- ---------
(In thousands)
Net Income $ 13,984 $ 15,507
Other Comprehensive Income,
Net of Taxes:
Change in value of cash
flow derivative
instruments used as
cash flow hedges 155 (304)
Adjustment reclassification -
derivative settlements -- 78
--------- ---------
Comprehensive Income $ 14,139 $ 15,281
========= =========
The accompanying notes are an integral part of the
consolidated condensed financial statements.
6
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 1 - BASIS OF PREPARATION AND PRESENTATION
- ----------------------------------------------
The accompanying unaudited consolidated condensed financial statements
include the accounts of Unit Corporation and its wholly owned subsidiaries
("company") and have been prepared under the rules and regulations of the
Securities and Exchange Commission. As applicable under these regulations,
certain information and footnote disclosures have been condensed or omitted and
the consolidated condensed financial statements do not include all disclosures
required by generally accepted accounting principles. In the opinion of the
company, the unaudited consolidated condensed financial statements contain all
adjustments necessary (all adjustments are of a normal recurring nature) to
present fairly the interim financial information. Certain reclassifications have
been made to prior year financial information to conform to the current period
presentation.
Results for the three months ended March 31, 2004 are not necessarily
indicative of the results to be realized during the full year. The consolidated
condensed financial statements have been derived from audited financial
statements and should be read with the company's Annual Report on Form 10-K for
the year ended December 31, 2003. Our independent accountants have performed a
review of these interim financial statements in accordance with standards
established by the American Institute of Certified Public Accountants. 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
accountants' liability under Section 11 does not extend to it.
7
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.
Three Three
Months Months
Ended Ended
2003 2004
--------- ---------
(In thousands except
per share amounts)
Net Income, as Reported $ 13,984 $ 15,507
Add Stock-Based Employee Compensation
Expense Included in Reported Net
Income, Net of Tax 167 219
Less Total Stock-Based Employee
Compensation Expense Determined
Under Fair Value Based Method
For All Awards (404) (513)
--------- ---------
Pro Forma Net Income $ 13,747 $ 15,213
========= =========
Basic Earnings per Share:
As reported $ 0.32 $ 0.34
========= =========
Pro forma $ 0.32 $ 0.33
========= =========
Diluted Earnings per Share:
As reported $ 0.32 $ 0.34
========= =========
Pro forma $ 0.32 $ 0.33
========= =========
8
The fair value of each option granted is estimated using the Black-Scholes
model. There were no options granted in the first quarter of 2003 and 2004. For
options granted in fiscal 2002 and 2003, 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
4.24% in 2002 and 2003. Expected life ranged from 1 to 10 years based on prior
experience depending on the vesting periods involved and the make up of
participating employees.
9
NOTE 2 - EARNINGS PER SHARE
- ---------------------------
The following data shows the amounts used in computing earnings per share
for the company.
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------- ------------- ----------
(In thousands except per share amounts)
For the Three Months Ended
March 31, 2003:
Basic earnings per common share:
Income before change in
accounting principle $ 12,659 43,432 $ 0.29
Cumulative effect of change
in accounting principle
net of income tax 1,325 43,432 0.03
------------- ----------
Net Income $ 13,984 43,432 $ 0.32
============= ==========
Diluted earnings per common
share:
Weighted average number
of common shares used
in basic earnings per
common share 43,432
Effect of dilutive stock
options 205
-------------
Weighted average number of
common shares and dilutive
potential common shares
used in diluted earnings
per share 43,637
=============
Income before change in
accounting principle $ 12,659 43,637 $ 0.29
Cumulative effect of change
in accounting principle
net of income tax 1,325 43,637 0.03
------------- ----------
Net Income $ 13,984 43,637 $ 0.32
============= ==========
10
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------- ------------- ----------
(In thousands except per share amounts)
For the Three Months Ended
March 31, 2004:
Basic earnings per common
share:
Income before change in
accounting principle $ 15,507 45,671 $ 0.34
============= ==========
Net Income $ 15,507 45,671 $ 0.34
============= ==========
Diluted earnings per common
share:
Weighted average number of
common shares used in
basic earnings per
common share 45,671
Effect of dilutive stock
options 188
-------------
Weighted average number of
common shares and dilutive
potential common shares
used in diluted earnings
per share 45,859
=============
Income before change in
accounting principle $ 15,507 45,859 $ 0.34
============= ==========
Net Income $ 15,507 45,859 $ 0.34
============= ==========
The following options and their average exercise prices were not included
in the computation of diluted earnings per share for the three months ended
March 31, 2003 because the option exercise prices were greater than the average
market price of common shares:
2003
----------
Options 176,000
==========
Average exercise price $ 19.17
==========
11
NOTE 3 - ACQUISITIONS
- ---------------------
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
development drilling in the future. The results of operations for the acquired
entity are included in the statement of income for the period subsequent to
January 30, 2004.
The total consideration paid for this acquisition 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.
As of the acquisition date, cash of $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 March 31,
2004, $5.4 million remained in escrow and is reflected as restricted cash.
12
Unaudited summary pro forma results of operations for the company,
reflecting the above acquisitions as if they had occurred at the beginning of
the year ended December 31, 2003 are as follow:
Three Months Three Months
Ended Ended
March 31, March 31,
2003 2004
-------------- --------------
(In thousands except per
share amounts)
Revenues $ 78,993 $ 105,080
============== ==============
Income Before Change in
Accounting Principle $ 15,245 $ 16,069
============== ==============
Net Income $ 13,601 $ 16,069
============== ==============
Diluted Earnings per Share:
Income before change in
accounting principle $ 0.35 $ 0.35
============== ==============
Net income $ 0.31 $ 0.35
============== ==============
The pro forma results of operations are not necessarily indicative of the
actual results of operations that would have occurred had the purchase actually
been made at the beginning of the respective periods nor of the results which
may occur in the future.
NOTE 4 - LOAN AGREEMENT
- -----------------------
On January 30, 2004, in conjunction with the company's acquisition of
PetroCorp Incorporated, the company replaced its loan agreement with a revolving
credit facility totaling $150 million having a four year term ending January 30,
2008. Borrowings under the new credit facility are limited to a commitment
amount. Although, the current value of the company's assets under the latest
loan value determination supported the full $150 million, the company elected to
set the loan commitment at $120 million in order to reduce financing costs. The
company pays a commitment fee of .375 of 1% for any unused portion of the
commitment amount. The company paid origination, agency and syndication fees of
$515,000 at the inception of the new agreement $40,000 of which will be paid
13
annually and the remainder of the fees will be amortized over the 4 year life of
the loan.
The borrowing base under the current credit facility is subject to a
semi-annual re-determination on May 10 and November 10 of each year, beginning
May 10, 2004. The calculation is based primarily on the sum of a percentage of
the discounted future value of the company's oil and natural gas reserves, as
determined by the banks. In addition, an amount representing a part of the value
of the company's drilling rig fleet, limited to $20 million, is added to the
borrowing base. The agreement also allows for one requested special
re-determination of the borrowing base (by either the lender or the company)
between each scheduled re-determination date if conditions warrant such a
request.
At the company's election, any part of the outstanding debt may be fixed at
a Eurodollar Rate for a 30, 60, 90 or 180 day term. During any Eurodollar Rate
funding period the outstanding principal balance of the note to which such
Eurodollar Rate option applies may be repaid on three days prior notice to the
administrative agent. 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 loan 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 loan 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 loan agreement) of not less than 1
to 1, and
. a leverage ratio of long-term debt to consolidated EBITDA (as defined
in the loan agreement) for the most recently ended rolling four fiscal
quarters of no greater than 3.25 to 1.0.
The company is in compliance with the covenants of its loan agreement as of
March 31, 2004.
14
NOTE 5 - NEW ACCOUNTING PRONOUNCEMENTS
- --------------------------------------
On January 1, 2003 the company adopted Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS 143
establishes an accounting standard requiring the recording of the fair value of
liabilities associated with the retirement of long-lived assets. The company
owns oil and natural gas properties which require expenditures to plug and
abandon the wells when the oil and natural gas reserves in the wells are
depleted. These expenditures under FAS 143 are recorded in the period in which
the liability is incurred (at the time the wells are drilled or acquired). The
company does not have any assets restricted for the purpose of settling the
plugging liabilities.
The following table shows the activity for the three months ending March
31, 2003 and 2004 relating to the company's retirement obligation for plugging
liability:
Short-Term Long-Term
Plugging Plugging
Liability Liability
------------- -------------
(In Thousands)
Plugging Liability 1/1/04 $ 303 $ 11,691
Accretion of Discount 4 173
Liability Incurred in the Period -- 5,566
Liability Settled in the Period (57) --
Sold -- (17)
Reclassification of Liability
From Long- to Short-Term -- --
------------- -------------
Plugging Liability 3/31/04 $ 250 $ 17,413
============= =============
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
15
as it applies to entities created after February 1, 2003. The adoption of FIN 46
with respect to these entities, primarily Eagle Energy Partnership I, L.P., did
not have an impact on the company's financial position or results of operations
or cash flows. For entities created prior to February 1, 2003, which are not
special purpose entities, as defined in FIN 46, FIN 46 and the amendment of FIN
46 were effective for the company, as amended, in the quarter ending March 31,
2004. The company evaluated FIN 46 and FIN 46(R) with regard to these types of
entities in which it has an ownership interest and there was no material impact
to the financial position, results of operations or cash flows from the adoption
of FIN 46 and FIN 46(R).
NOTE 6 - INTANGIBLE UNDEVELOPED LEASEHOLD AND INTANGIBLE DEVELOPED LEASEHOLD
- ----------------------------------------------------------------------------
Statement of Financial Accounting Standards No. 141, "Business
Combinations" (FAS 141) and Statement of Financial Accounting Standards, No.
142, "Goodwill and Intangible Assets" (FAS 142) were issued by the the FASB in
June 2001 and became effective for the company on July 1, 2001 and January 1,
2002, respectively. FAS 141 requires all business combinations initiated after
June 30, 2001 to be accounted for using the purchase method. Additionally, FAS
141 requires companies to disaggregate and report separately from goodwill
certain intangible assets. FAS 142 establishes new guidelines for accounting for
goodwill and other intangible assets. Under FAS 142, goodwill and certain other
intangible assets are not amortized, but rather are reviewed annually for
impairment. Depending on how the accounting and disclosure literature is
applied, oil and gas mineral rights held under lease and other contractual
arrangements representing the right to extract oil and natural gas reserves for
both undeveloped and developed leaseholds may be classified separately from oil
and gas properties, as intangible assets on our balance sheets. In addition, the
notes to the company's financial statements would include the disclosures
required by FAS 141 and 142 regarding intangibles. To date, the company, like
many other oil and gas companies, has included oil and gas extraction rights as
part of the oil and gas properties, even after FAS 141 and 142 became effective.
The company's results of operations and cash flows would not be affected, since
these oil and gas mineral extraction rights would continue to be amortized in
accordance with full cost accounting rules.
At March 31, 2004, the company had undeveloped leaseholds of approximately
$16.4 million that would be classified on our balance sheet as "intangible
undeveloped leasehold" and developed leaseholds of an estimated $129.1 million
that would be classified as "intangible developed leasehold" if the
interpretations were applied. This classification would require the company to
make the disclosures set forth under FAS 142 related to these interests.
The Financial Accounting Standards Emerging Issues Task Force (EITF) has
recently issued proposed FASB Staff Position (FSP) FAS 141-a and 142-a
16
"Interaction of FASB Statements No. 141, Business Combinations, and No. 142,
Goodwill and Other Intangible Assets, and EITF Issue No. 04-2, "Whether Mineral
Rights Are Tangible or Intangible Assets." The proposed FSP would amend FAS 141
and FAS 142 to remove some inconsistencies between the standards related to the
proper classification of assets related to mineral rights.
On April 30, 2004, the FASB directed the FASB staff to issue the FSP and
the guidance in the FSP shall be applied to the first reporting period beginning
after April 29, 2004. Under the FSP certain use rights may have characteristics
of tangible assets, so we intend to continue to classify our oil and natural gas
mineral extraction rights as tangible oil and gas properties.
NOTE 7 - HEDGING ACTIVITY
- -------------------------
Periodically the company hedges the prices it will receive for a portion of
its future natural gas and oil production. The hedge is made in an attempt to
reduce the impact and uncertainty that price variations have on cash flow.
During the first quarter of 2003, the company entered into two natural gas
collar contracts. Each contract was for 10,000 MMBtu's of production per day and
covered the period of April through September 2003. One contract had a floor
price of $4.00 and a ceiling price of $5.75 and the other contract has a floor
price of $4.50 and a ceiling price of $6.02. During the first quarter of 2003,
the company also entered into two oil collar contracts. Each contract was for
5,000 barrels of production per month and covered the period of May through
December 2003. One contract had a floor price of $25.00 and a ceiling price of
$32.20 and the other contact had a floor price of $26.00 and a ceiling price of
$31.40. The fair value of the collar contracts was recognized on the March 31,
2003 balance sheet as a derivative asset of $246,000 and at $155,000, net of
tax, in accumulated other comprehensive income. These hedges were fully
effective and thus did not affect net income.
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. 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.
The fair value of the collar contract and the hedge was recognized on the March
31, 2004 balance sheet as a derivative liability of $365,000 and at a loss of
$226,000, net of tax, in accumulated other comprehensive income. Oil revenues
were reduced by $127,000 for the quarter due to the settlement of the oil hedge
in February and March of 2004.
17
NOTE 8 - INDUSTRY SEGMENT INFORMATION
- -------------------------------------
The company has two business segments: Contract Drilling, and Oil and
Natural Gas, representing its two strategic business units offering different
products and services. The Contract Drilling segment provides land contract
drilling of oil and natural gas wells and the Oil and Natural Gas segment is
engaged in the development, acquisition and production of oil and natural gas
properties.
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 month periods ended March
31, 2003 and 2004 is as follows:
18
Three Months Ended
March 31,
2003 2004
---------- ----------
(In thousands)
Revenues:
Contract drilling $ 36,513 $ 65,580
Elimination of inter-segment
revenue 1,947 2,366
---------- ----------
Contract drilling net of
inter-segment revenue 34,566 63,214
Oil and natural gas 33,248 37,990
Other 750 696
---------- ----------
Total revenues $ 68,564 $ 101,900
========== ==========
Operating Income (1):
Contract drilling $ 1,861 $ 9,194
Oil and natural gas 20,586 18,081
---------- ----------
Total operating income 22,447 27,275
General and administrative
expense (2,450) (2,771)
Interest expense (211) (417)
Other income - net 425 474
---------- ----------
Income before income taxes $ 20,211 $ 24,561
========== ==========
(1) Operating income is total operating revenues less operating
expenses, depreciation, depletion and amortization and does not
include non-operating revenues, general corporate expenses,
interest expense or income taxes.
The cumulative effect of change in accounting principle recorded in the
first quarter of 2003 of $1,325,000, net of $811,000 in income tax, is all
related to the oil and natural gas segment.
19
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders
Unit Corporation
We have reviewed the accompanying consolidated condensed balance sheet of Unit
Corporation and its subsidiaries as of March 31, 2004, and the related
consolidated condensed statements of income, comprehensive income and cash flows
for the three month periods ended March 31, 2003 and 2004. These interim
financial statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical review procedures to
financial data and making inquiries of persons responsible for financial and
accounting matters. It is substantially less in scope than an audit conducted in
accordance with generally accepted auditing standards, the objective of which is
the expression of an opinion regarding the financial statements taken as a
whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the accompanying condensed consolidated interim financial statements
for them to be in conformity with accounting principles generally accepted in
the United States of America.
We previously audited, in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet as of December
31, 2003, and the related consolidated statements of income, shareholder's
equity and cash flows for the year then ended (not presented herein); and in our
report dated February 18, 2004, we expressed an unqualified opinion on those
consolidated financial statements. In our opinion, the information set forth in
the accompanying condensed consolidated balance sheet as of December 31, 2003,
is fairly stated in all material respects in relation to the consolidated
balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
April 19, 2004
20
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
- ---------------------------------------------------------------------------
FINANCIAL CONDITION
- -------------------
Summary. Our financial condition and liquidity depends on the cash flow
generated from our two principal business segments (and our subsidiaries that
carry out those operations) and borrowings under our bank loan agreement. Our
cash flow is influenced mainly by the prices we receive for our natural gas
production, the demand for and the dayrates we receive for our drilling rigs
and, to a lesser extent, the prices we receive for our oil production. At March
31, 2004, we had cash totaling $377,000 and we had borrowed $75.0 million of the
$120.0 million we have elected to have available under our loan agreement.
Our two principal business segments are (i) contract drilling carried out
by our subsidiaries Unit Drilling Company and Service Drilling Southwest, L.L.C.
and (ii) oil and natural gas exploration, carried out by our subsidiaries Unit
Petroleum Company and PetroCorp Incorporated.
The following is a summary of certain financial information on March 31,
2003 and March 31, 2004 and for the three months ended March 31, 2003 and March
31, 2004:
March 31, March 31, Percent
2003 2004 Change
-------------- -------------- -------
(In thousands except percent amounts)
Working Capital $ 28,571 $ 25,668 (10%)
Long-Term Debt $ 26,000 $ 75,000 188%
Shareholders' Equity $ 436,984 $ 532,673 22%
Ratio of Long-Term debt to
Total Capitalization 6% 12%
Income Before Change in
Accounting Principle $ 12,659 $ 15,507 22%
Net Income $ 13,984 $ 15,507 11%
Net Cash Provided by
Operating Activities $ 24,435 $ 42,612 74%
Net Cash Used in Investing
Activities $ (18,491) $ (122,951) 565%
Net Cash Provided by (Used
in) Financing Activities $ (6,213) $ 80,118 1,390%
21
The following table summarizes certain operating information for the first
three months of 2003 and 2004:
Percent
2003 2004 Change
------------ ------------ --------
Oil Production (MBbls) 114 215 89%
Natural Gas Production (MMcf) 4,855 6,294 30%
Average Oil Price Received $ 30.40 $ 30.63 1%
Average Natural Gas Price
Received $ 5.96 $ 4.90 (18%)
Average Number of Our
Drilling Rigs in Use
During the Period 50.8 81.7 61%
Total Number of Our Drilling
Rigs Available at the End
of the Period 75 88 17%
Our Bank Loan Agreement. On January 30, 2004, in conjunction with our
acquisition of PetroCorp Incorporated, we replaced our loan agreement with a
revolving credit facility totaling $150 million having a four year term ending
January 30, 2008. Borrowings under the new credit facility are limited to a
commitment amount. Although the current value of our assets under the latest
loan value computation supported the full $150 million, we elected to set the
loan commitment at $120 million in order to reduce financing costs since we are
charged a commitment fee of .375 of 1% on the amount available but not borrowed.
We paid 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. Following the
acquisition of PetroCorp Incorporated our borrowings were $90.0 million. Prior
to March 31, 2004 we reduced our borrowings and at March 31, 2004 and April 19,
2004 our borrowings were $75.0 million.
The loan value under our current credit facility is subject to a
semi-annual re-determination on May 10 and November 10 of each year, beginning
May 10, 2004. The calculation 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. Interest on the Eurodollar Rate is computed at the
Eurodollar Base Rate applicable for the interest period plus 1.00% to 1.50%
depending on the level of debt as a percentage of the total loan value and is
payable at the end of each term or every 90 days whichever is less. Borrowings
not under the Eurodollar Rate bear interest at the JPMorgan Chase Prime Rate
22
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 March 31, 2004, all
of our $75.0 million debt was subject to the Eurodollar Rate.
The loan 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 loan 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 loan agreement) of not less than 1
to 1, and
. a leverage ratio of long-term debt to consolidated EBITDA (as defined
in the loan agreement) for the most recently ended rolling four fiscal
quarters of no greater than 3.25 to 1.0.
The company is in compliance with the covenants of its loan agreement as of
March 31, 2004.
Contractual Commitments. We have the following contractual obligations at March
31, 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) $ 75,000 $ -- $ -- $ 75,000 $ --
Retirement
Agreement(2) 1,575 300 600 600 75
Operating
Leases(3) 3,386 725 1,411 892 358
Drill Pipe
Acquisi-
tions(4) 9,309 9,309 -- -- --
--------- -------- -------- --------- --------
Total
Contractual
Obligations $ 89,270 $10,334 $ 2,011 $ 76,492 $ 433
========= ======== ======== ========= ========
23
- -------------------
(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,
Texas under the terms of operating leases expiring through January 31,
2010 along with leasing space on short-term commitments to stack
excess rig equipment and production inventory. Subsequent to March 31,
2004, we signed a rental agreement for a district office in Midland,
Texas. The rental agreement's term for three years and will be
approximately $2,600 per month.
(4) Due to the increasing cost of steel and the potential for limited
availability of new drill pipe within the industry, in the first
quarter of 2004 we made a commitment to purchase approximately 275,000
feet of drill pipe from three different suppliers by the end of 2004.
24
At March 31, 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) $ 1,928 Unknown Unknown Unknown Unknown
Separation
Benefit
Agreement(2) $ 2,623 $ 434 Unknown Unknown Unknown
Plugging
Liability(3) $ 17,663 $ 250 $ 439 $ 736 $ 16,238
Gas Balancing
Liability(4) $ 1,191 Unknown Unknown Unknown Unknown
Repurchase
Obliga-
tions(5) Unknown Unknown Unknown Unknown Unknown
(1) We provide a salary deferral plan which allows participants to defer
the recognition of salary for income tax purposes until actual
distribution of benefits, which occurs at either termination of
employment, death or certain defined unforeseeable emergency
hardships. We recognize payroll expense and record a liability,
included in other long-term liabilities in our Consolidated Balance
Sheet, at the time of deferral.
(2) Effective January 1, 1997, we adopted a separation benefit plan
("Separation Plan"). The Separation Plan allows eligible employees
whose employment with us is involuntarily terminated or, in the case
of an employee who has completed 20 years of service, voluntarily or
involuntarily terminated, to receive benefits equivalent to 4 weeks
salary for every whole year of service completed with Unit up to a
maximum of 104 weeks. To receive payments the recipient must waive any
claims against us in exchange for receiving the separation benefits.
On October 28, 1997, we adopted a Separation Benefit Plan for Senior
Management ("Senior Plan"). The Senior Plan provides certain officers
and key executives of Unit with benefits generally equivalent to the
Separation Plan. The Compensation Committee of the Board of Directors
has absolute discretion in the selection of the individuals covered in
this plan.
(3) On January 1, 2003 we adopted Financial Accounting Standards No. 143,
"Accounting for Asset Retirement Obligations" (FAS 143). FAS 143
establishes an accounting standard requiring the recording of the fair
value of liabilities associated with the retirement of long-lived
25
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. No repurchases were
made in the first quarter of 2004.
Hedging. Periodically we hedge the prices we will receive for a portion of our
future natural gas and oil production. We do so in an attempt to reduce the
impact and uncertainty that price variations have on our cash flow.
During the first quarter of 2003, we entered into two natural gas collar
contracts. Each contract was for 10,000 MMBtu's of production per day and
covered the period of April through September 2003. One contract had a floor
price of $4.00 and a ceiling price of $5.75 and the other contract has a floor
price of $4.50 and a ceiling price of $6.02. During the first quarter of 2003,
we also entered into two oil collar contracts. Each contract was for 5,000
barrels of production per month and covered the period of May through December
2003. One contract had a floor price of $25.00 and a ceiling price of $32.20 and
the other contact had a floor price of $26.00 and a ceiling price of $31.40. The
fair value of the collar contracts was recognized on the March 31, 2003 balance
sheet as a derivative asset of $246,000 and at $155,000, net of tax, in
accumulated other comprehensive income. These hedges were fully effective and
thus did not affect net income.
During the first and second quarters of 2004, we entered into two natural
gas collars. Each 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
26
average price of $31.40. The fair value of the collar contract and the hedge was
recognized on the March 31, 2004 balance sheet as a derivative liability of
$365,000 and at a loss of $226,000, net of tax, in accumulated other
comprehensive income. Oil revenues were reduced by $127,000 for the quarter due
to the settlement of the oil hedge in February and March of 2004.
Self-Insurance or Retentions. We are self-insured (or have a retention) for
certain losses relating to workers' compensation, general liability, property
damage and employee medical benefits. The exposure (i.e. our deductible or
retention) per occurrence ranges from $200,000 for general liability to $1
million for rig physical damage. We have purchased stop-loss coverage in order
to limit, to the extent feasible, our per occurrence and aggregate exposure to
certain claims. There is no assurance that such coverage will adequately protect
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
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 $206,800 per month ($2,482,000
annualized) change in our pre-tax operating cash flow. Our first quarter 2004
average natural gas price was $4.90 compared to an average natural gas price of
$5.98 for the first quarter of 2003. A $1.00 per barrel change in our oil price
would have a $76,400 per month ($917,000 annualized) change in our pre-tax
operating cash flow based on our production in 2004 after the acquisition of
PetroCorp Incorporated. Our first quarter 2004 average oil price was $30.63
compared with an average oil price of $30.40 received in the first quarter 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 loan agreement since that
determination is based mainly on the value of our oil and natural gas reserves.
Such a reduction could limit our ability to carry out our planned capital
projects.
27
We sell most of our natural gas production to third parties under
month-to-month contracts. Several of these buyers have experienced financial
complications resulting from the recent investigations into the energy trading
industry. The long-term implications to the energy trading business, as well as
to oil and natural gas producers, because of these investigations remains, to be
determined. We continue to evaluate the information available to us about our
buyers and try to reduce any possible future adverse impact to us. Presently we
believe that our buyers will be able to perform their commitments to us. We own
a 16.7% limited partner interest in Eagle Energy Partners I LP, whose purchases,
which are competitively marketed, accounted for 25% of our oil and natural gas
revenues in the first quarter of 2004 and they marketed approximately 48% 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
34 wells (15.98 net wells) in the first quarter of 2004 compared to 18 wells
(9.13 net wells) in the first quarter of 2003. Our total capital expenditures
for oil and natural gas exploration and acquisitions in the first quarter of
2004 totaled $135.3 million with $115.7 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 165 to 175 wells in 2004 and total
capital expenditures for oil and natural gas exploration and acquisitions is
planned to be around $95 million excluding the PetroCorp Incorporated
acquisition. Due to the shortage of steel and the resulting increase in prices
we purchased 320,000 feet of casing for approximately $2.4 million in April 2004
to be held in inventory until needed.
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 such
shortages have occurred periodically in the past. At the end of the first
quarter of 2004 we increased wages in some of our areas of drilling operations
and implemented longevity pay incentives to help maintain our contract drilling
labor base. If demand for drilling rigs increases rapidly in the future,
shortages of experienced personnel may limit our ability to increase the number
of rigs we could operate.
We currently do not have any shortages in drill pipe and drilling
equipment. Due to the increasing cost of steel and increasing potential for
28
shortages in the availability of new drill pipe within the industry, in the
first quarter of 2004 we made a commitment to purchase approximately 275,000
feet of drill pipe for $9.3 million from three different suppliers by the end of
2004.
Most of our contract drilling fleet is targeted to the drilling of natural
gas wells, so changes in natural gas prices influence the demand for our
drilling rigs and the prices we can charge for our contract drilling services.
The average rates received for our rigs during 2003 and 2004 were at a low of
$7,275 per day in February of 2003. Natural gas and oil prices have been rising
since the second quarter of 2003 through the first quarter of 2004 and both
demand for our rigs and dayrates have continued to improve. In the first quarter
of 2004 the average dayrate we received was approximately $8,250 per day. The
average use of our rigs in the first quarter of 2004 was 81.7 rigs (93%)
compared with 50.8 rigs (68%) for the first quarter of 2003. Based on the
average utilization of our rigs in the first quarter of 2004, a $100 per day
change in dayrates has a $8,170 per day ($2,982,000 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 subsidiary provides 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. During the first quarter of 2003 and 2004, we
drilled 12 and 8 wells, respectively for our exploration and production
subsidiary. Per regulations provided by the Securities and Exchange Commission,
the profit received by our contract drilling segment of $330,000 and $929,000
during the first quarter of 2003 and 2004, respectively, was used to reduce the
carrying value of our oil and natural gas properties rather than being included
in our profits in current operations.
Drilling Acquisitions and Capital Expenditures. On December 8, 2003, we acquired
SerDrilco Incorporated and its subsidiary, Service Drilling Southwest LLC for
$35.0 million in cash. The terms of the acquisition include an earn-out
provision allowing the sellers to obtain one-half of the cash flow in excess of
$10 million for each of the three years following the acquisition. The assets of
SerDrilco Incorporated included 12 drilling rigs, spare drilling equipment, a
fleet of 12 larger trucks and trailers, various other vehicles and a district
office and an equipment yard in and near Borger, Texas.
For our contract drilling operations during the first quarter of 2004, we
incurred $9.7 million in capital expenditures. For the year 2004, we have
budgeted capital expenditures of approximately $30 million for our contract
drilling operations.
On April 20, 2004, we announced that we have reached an agreement to buy
two drilling rigs and related equipment for $5.5 million. The rigs are rated at
850 and 1,000 horsepower respectively and are ready for work with depth
capacities from 12,000 to 15,000 feet. The rigs are to be added into our Rocky
Mountain division, bringing the total rigs in that division to 10. Closing of
this transaction is expected to occur on or before May 7, 2004. With this
29
acquisition, our total rig fleet will consist of 90 drilling rigs, with the 91st
rig being built and expected to be operational in 30 days.
Oil and Natural Gas Limited Partnerships and Other Entity Relationships. We are
the general partner for 10 oil and natural gas limited partnerships which were
formed privately and publicly. The partnership's revenues and costs are shared
under formulas prescribed in each limited partnership agreement. The
partnerships repay us for contract drilling, well supervision and general and
administrative expense. Related party transactions for contract drilling and
well supervision fees are the related party's share of such costs. These costs
are billed on the same basis as billings to unrelated 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 paid to us for all of these fees was
$873,000. We expect the fees to be about the same in 2004. Our proportionate
share of assets, liabilities and net income relating to the oil and natural gas
partnerships is included in our consolidated financial statements.
We own a 40% equity interest in Superior Pipeline Company LLC, an Oklahoma
Limited Liability Company. Superior is a natural gas gathering and processing
company. Our investment, including our share of the equity in the earnings of
that company, totaled $3.3 million at March 31, 2004 and is reported in other
assets in our balance sheet. During the first quarter of 2004, Superior Pipeline
Company LLC purchased $1.1 million of our natural gas production and paid
$11,000 for our natural gas liquids. We paid this company $5,000 for gathering
and compression services in the first quarter.
We also own a 16.7% limited partnership interest in Eagle Energy
Partnership I, L.P. ("Eagle") for $2.5 million. Eagle is engaged in the purchase
and sale of natural gas, electricity (or similar electricity based products),
future commodities, and the performance of scheduling and nomination services
for both energy related commodities and similar energy management functions.
Eagle marketed approximately 48% of the natural gas volumes we sell for
ourselves and third parties in the first quarter of 2004.
Critical Accounting Policies. We account for our oil and natural gas exploration
and development activities using the full cost method of accounting. Under this
method, all costs incurred in the acquisition, exploration and development of
oil and natural gas properties are capitalized. At the end of each quarter, the
net capitalized costs of our oil and natural gas properties is limited to the
lower of unamortized cost or a ceiling. The ceiling is defined as the sum of the
present value (10% 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
30
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 March 31, 2004 ($5.27 per Mcf
for natural gas and $34.39 per barrel for oil), the unamortized cost of our
domestic oil and natural gas properties did not exceed the ceiling of our proved
oil and natural gas reserves. Natural gas prices remain erratic and any
significant declines below prices used in the reserve evaluation could result in
a ceiling test write-down in following quarterly reporting periods.
The value of our oil and natural gas reserves is used to determine the
borrowing base under our loan agreement with our banks. This amount is affected
by both price changes and the measurement of reserve volumes. Oil and natural
gas reserves cannot be measured exactly. Our estimates of oil and natural gas
reserves requires extensive judgments of our reservoir engineering data and are
less precise than other estimates made in connection with financial disclosures.
Assigning monetary values to these estimates does not reduce the subjectivity
and changing nature of reserve estimates. Indeed, the uncertainties inherent in
the disclosure are compounded by applying additional estimates of the rates and
timing of production and the costs that will be incurred in developing and
producing the reserves.
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.
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.
31
We recognize revenues and expense generated from "daywork" drilling
contracts as the services are performed, since we do not bear the risk of
completion of the well. Under "footage" and "turnkey" contracts, we bear the
risk of completion of the well, so revenues and expenses are recognized when the
well is substantially completed. Under this method, substantial completion is
determined when the well bore reaches the negotiated depth as stated in the
contract. The entire amount of a loss, if any, is recorded when the loss can be
reasonably determined, however, any profit is recorded only at the time the well
is finished. The costs of uncompleted drilling contracts include expenses
incurred to date on "footage" or "turnkey" contracts, which are still in process
at the end of the period, and are included in other current assets.
NEW ACCOUNTING PRONOUNCEMENTS
- -----------------------------
On January 17, 2003, the FASB issued FASB Interpretation No. 46,
"Consolidation of Variable Interest Entities, an interpretation of ARB 51" ("FIN
46"). The primary objectives of FIN 46 are to provide guidance on the
identification of entities for which control is achieved through means other
than through voting rights ("variable interest entities" or "VIEs") and how to
determine when and which business enterprise should consolidate the VIE. This
new model for consolidation applies to an entity which either (1) the equity
investors (if any) do not have a controlling financial interest or (2) the
equity investment at risk is insufficient to finance that entity's activities
without receiving additional subordinated financial support from other parties.
FIN 46, as amended, was effective for us in the fourth quarter of 2003 as
it applies to entities created after February 1, 2003. The adoption of FIN 46
with respect to these entities, primarily Eagle Energy Partnership I, L.P., did
not have an impact on our financial position or results of operations or cash
flows. For entities created prior to February 1, 2003, which are not special
purpose entities, as defined in FIN 46, FIN 46 and the amendment of FIN 46 were
effective for us, as amended, in the quarter ending March 31, 2004. We evaluated
FIN 46 and FIN 46(R) with regard to these types of entities in which we have an
ownership interest and there was no material impact to the financial position,
results of operations or cash flows from the adoption of FIN 46 and FIN 46(R).
Statement of Financial Accounting Standards No. 141, "Business
Combinations" (FAS 141) and Statement of Financial Accounting Standards, No.
142, "Goodwill and Intangible Assets" (FAS 142) were issued by the FASB in June
2001 and became effective for us on July 1, 2001 and January 1, 2002,
respectively. FAS 141 requires all business combinations initiated after June
30, 2001 to be accounted for using the purchase method. Additionally, FAS 141
requires companies to disaggregate and report separately from goodwill certain
intangible assets. FAS 142 establishes new guidelines for accounting for
goodwill and other intangible assets. Under FAS 142, goodwill and certain other
intangible assets are not amortized, but rather are reviewed annually for
impairment. Depending on how the accounting and disclosure literature is
applied, oil and gas mineral rights held under lease and other contractual
arrangements representing the right to extract oil and natural gas reserves for
32
both undeveloped and developed leaseholds may be classified separately from
oil and gas properties, as intangible assets on our balance sheets. In addition,
the notes to our financial statements would include the disclosures required by
FAS 141 and 142 regarding intangibles. To date, we, like many other oil and gas
companies, have included oil and gas extraction rights as part of the oil and
gas properties, even after FAS 141 and 142 became effective. Our results of
operations and cash flows would not be affected, since these oil and gas mineral
extraction rights would continue to be amortized in accordance with full cost
accounting rules.
At March 31, 2003 and 2004, we had undeveloped leaseholds of approximately
$14.2 million and $16.4 million, respectively that would be classified on our
balance sheets as "intangible undeveloped leasehold" and developed leaseholds of
an estimated $20.0 million and $129.1 million, respectively that would be
classified as "intangible developed leasehold" if the interpretations were
applied. This classification would require us to make the disclosures set forth
under FAS 142 related to these interests.
The Financial Accounting Standards Emerging Issues Task Force (EITF) has
recently issued proposed FASB Staff Position (FSP) FAS 141-a and 142-a
"Interaction of FASB Statements No. 141, Business Combinations, and No. 142,
Goodwill and Other Intangible Assets, and EITF Issue No. 04-2, "Whether Mineral
Rights Are Tangible or Intangible Assets." The proposed FSP would amend FAS 141
and FAS 142 to remove some inconsistencies between the standards related to the
proper classification of assets related to mineral rights.
On April 30, 2004, the FASB directed the FASB staff to issue the FSP and
the guidance in the FSP shall be applied to the first reporting period beginning
after April 29, 2004. Under the FSP certain use rights may have characteristics
of tangible assets, so we intend to continue to classify our oil and natural gas
mineral extraction rights as tangible oil and gas properties.
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;
33
. exploitation and exploration prospects;
. estimates of proved oil and natural gas reserves;
. reserve potential;
. development and infill drilling potential;
. drilling prospects;
. expansion and other development trends of the oil and natural gas
industry;
. our business strategy;
. production of our oil and natural gas reserves;
. expansion and growth of our business and operations;
. availability of drilling rigs and rig related equipment;
. drilling rig 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 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.
34
RESULTS OF OPERATIONS
- ---------------------
First Quarter 2004 versus First Quarter 2003
- --------------------------------------------
Provided below is a comparison of selected operating and financial data for
the first quarter of 2004 versus the first quarter of 2003:
First First Percent
Quarter 2003 Quarter 2004 Change
--------------- --------------- ---------
Total Revenue $ 68,564,000 $ 101,900,000 49%
Income Before Change in Accounting
Principle $ 12,659,000 $ 15,507,000 22%
Net Income $ 13,984,000 $ 15,507,000 11%
Oil and Natural Gas:
Revenue $ 33,248,000 $ 37,990,000 14%
Average natural gas price (Mcf) $ 5.96 $ 4.90 (18%)
Average oil price (Bbl) $ 30.40 $ 30.63 1%
Natural gas production (Mcf) 4,855,000 6,294,000 30%
Oil production (Bbl) 114,000 215,000 89%
Depreciation, depletion and
amortization rate (Mcfe) $ 1.08 $ 1.33 23%
Depreciation, depletion and
amortization $ 6,047,000 $ 10,177,000 68%
Drilling:
Revenue $ 34,566,000 $ 63,214,000 83%
Percentage of revenue from
daywork contracts 95% 100%
Average number of rigs in use 50.8 81.7 61%
Average dayrate on daywork
contracts $ 7,317 $ 8,252 13%
Depreciation $ 4,894,000 $ 7,464,000 53%
General and Administrative Expense $ 2,450,000 $ 2,771,000 13%
Interest Expense $ 211,000 $ 417,000 98%
Average Interest Rate 2.10% 2.19% 4%
Average Long-Term Debt Outstanding $ 31,612,000 $ 56,019,000 77%
Oil and natural gas revenues increased due to increases in both oil and
natural gas produced and to a lesser extent from an increase in oil prices
between the first quarter of 2004 and the first quarter of 2003. A reduction in
natural gas prices partially offset the increases. PetroCorp Incorporated was
acquired on January 30, 2004 and its production is included in our operating
results subsequent to the acquisition date. Oil production was up 89% between
35
the comparative quarters. Approximately 69% of the increase was from the
production added through the PetroCorp Incorporated acquisition. Natural gas
production was up 30% between the comparative quarters. Approximately 49% of the
increase in natural gas production was from wells acquired through the PetroCorp
Incorporated acquisition. The remainder of the increase in production for both
oil and natural gas came from wells added through our development drilling
program. Total operating cost increased in the first quarter of 2004 when
compared with the first quarter of 2003 due to mainly from the acquisition of
PetroCorp Incorporated and to a lesser extent from costs associated with
workovers. PetroCorp Incorporated has historically experienced higher operating
cost per equivalent barrel due to the types of wells under production and the
reserve base being more toward oil. Gross production taxes which are based on a
percentage of revenues were also higher. Our total depreciation, depletion and
amortization ("DD&A) increased due to the increase in equivalent volumes
produced and an increase in our DD&A rate per Mcfe. The acquisition of PetroCorp
Incorporated was made at a higher cost per equivalent volumes than we have
previously experienced through both our drilling program and from other
acquisitions on average. During 2003, we also experienced higher cost per Mcfe
for the discovery of new reserves through our development drilling program.
Contract drilling revenues increased between the comparative quarters due
to increases in demand for our drilling rigs and increases in dayrates. Natural
gas prices remained between $4.00 and $5.50 through most of 2003 causing an
increase in demand for our rigs. Dayrates, which typically increase after the
increase in demand for rigs, also started increasing in the second quarter of
2003 and have continued to steadily increase throughout the first quarter of
2004. Along with the increase in demand we also added 12 drilling rigs with the
acquisition of SerDrilco, Inc. in December of 2003 contributing to the increase
in total drilling revenues and operating cost. We did not drill any turnkey or
footage wells in the first quarter of 2004. Approximately 5% of our total
drilling revenues in the first quarter of 2003 came from footage and turnkey
contracts, which had profit margins lower than our daywork contracts. Contract
drilling depreciation increased due to the acquisition of 12 rigs in the fourth
quarter of 2003.
General and administrative expense was higher in the first quarter of 2004
due to increases in employee, insurance and general office administrative costs.
Our total interest expense was higher due to the additional debt incurred from
the PetroCorp Incorporated acquisition. Income tax expense increased primarily
due to the increase in income before income taxes.
Net income in the first quarter 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).
36
Item 3. Quantitative and Qualitative Disclosures about Market Risk
- ------- ----------------------------------------------------------
Our operations are exposed to market risks due to changes in commodity
prices. The price we receive is primarily driven by the prevailing worldwide
price for crude oil and market prices applicable to our natural gas production.
Historically, these prices have been volatile and such volatility is expected to
continue.
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.
Item 4. Controls and Procedures
- --------------------------------
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 were no changes in the company's internal controls or in other
factors that could significantly affect these internal controls subsequent to
the date of our most recent evaluation.
37
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
- --------------------------
Not applicable
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of
Equity Securities
- ------------------------------------------------------------------------
Not applicable
Item 3. Defaults Upon Senior Securities
- ----------------------------------------
Not applicable
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
Not applicable
Item 5. Other Information
- --------------------------
Not applicable
38
Item 6. Exhibits and Reports on Form 8-K
- -----------------------------------------
(a) Exhibits:
15 Letter re: Unaudited Interim Financial Information.
31.1 Certification of Chief Executive Officer under Rule 13a - 14(a)
of the Exchange Act.
31.2 Certification of Chief Financial Officer under Rule 13a - 14(a)
of the Exchange Act.
32 Certification of Chief Executive Officer and Chief Financial
Officer under Rule 13a - 14(a) of the Exchange Act and 18 U.S.C.
Section 1350, as adopted under Section 906 of the Sarbanes-Oxley
Act of 2002.
(b) On January 14, 2004, we filed a report on Form 8-K under item 7 and 9.
This report announced the retirement of Earle Lamborn from Unit
Corporation and his resignation from Unit's Board of Directors
effective January 15, 2004.
On February 2, 2004, we filed a report on Form 8-K under item 7 and 9.
This report announced that Unit Corporation has closed its acquisition
of PetroCorp Incorporated. Unit also announced that on January 30,
2004, it had entered into a new $150 million credit facility in place
of its existing loan agreement.
On February 18, 2004, we filed a report on Form 8-K under item 7 and
12. This report announced our earnings for the quarter and year ended
December 31, 2003 in an attached exhibit.
On March 3, 2004, we filed a report on Form 8-K/A under item 7. This
report amended Form 8-K filed February 2, 2004 to include the
historical financial statements of PetroCorp Incorporated and the
related pro forma financial information.
On April 19, 2004, we filed a report on Form 8-K under item 7, 9 and
12. This report announced our earnings for the quarter ended March 31,
2004 in an attached exhibit.
On April 20, 2004, we filed a report on Form 8-K under item 7 and 9.
This report announced that we have reached an agreement to buy two
drilling rigs and related equipment for $5.5 million. Closing of this
transaction is expected to occur on or before May 7, 2004.
39
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: May 4, 2004 By: /s/ John G. Nikkel
---------------- ------------------------------
JOHN G. NIKKEL
Chief Executive Officer,
and Director
Date: May 4, 2004 By: /s/ David T. Merrill
---------------- ------------------------------
DAVID T. MERRILL
Chief Financial Officer and
Treasurer
40