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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, 2005
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 45,858,044
---------------------------- ----------
Class Outstanding at May 2, 2005
FORM 10-Q
UNIT CORPORATION
TABLE OF CONTENTS
Page
Number
PART I. Financial Information
Item 1. Financial Statements (Unaudited)
Consolidated Condensed Balance Sheets
March 31, 2005 and December 31, 2004. . . . . . . . . . 2
Consolidated Condensed Statements of Income
Three Months Ended March 31, 2005 and 2004. . . . . . . 4
Consolidated Condensed Statements of Cash Flows
Three Months Ended March 31, 2005 and 2004. . . . . . . 5
Consolidated Condensed Statements of Comprehensive
Income Three Months Ended March 31, 2005 and 2004 . . . 6
Notes to Consolidated Condensed Financial Statements. . 7
Report of Independent Registered Public Accounting
Firm. . . . . . . . . . . . . . . . . . . . . . . . . . 19
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . 20
Item 3. Quantitative and Qualitative Disclosure about
Market Risk . . . . . . . . . . . . . . . . . . . . . . 38
Item 4. Controls and Procedures . . . . . . . . . . . . . . . . 39
PART II. Other Information
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . 40
Item 2. Unregistered Sales of Equity Securities and
Use of Proceeds . . . . . . . . . . . . . . . . . . . . 40
Item 3. Defaults Upon Senior Securities. . . . . . . . . . . . 40
Item 4. Submission of Matters to a Vote of Security Holders . . 40
Item 5. Other Information . . . . . . . . . . . . . . . . . . . 40
Item 6. Exhibits. . . . . . . . . . . . . . . . . . . . . . . . 41
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
1
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
- ------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
March 31,
2005 December 31,
(Unaudited) 2004
------------ ------------
(In thousands)
ASSETS
------
Current Assets:
Cash and cash equivalents $ 470 $ 665
Restricted cash 77 2,571
Accounts receivable 103,628 93,180
Materials and supplies 14,132 13,054
Other 10,409 9,131
------------ ------------
Total current assets 128,716 118,601
------------ ------------
Property and Equipment:
Drilling equipment 529,761 508,845
Oil and natural gas properties, on the
full cost method:
Proved properties 759,849 731,622
Undeveloped leasehold not being
amortized 31,519 28,170
Gas gathering and processing equipment 40,996 38,417
Transportation equipment 13,621 13,559
Other 11,174 10,946
------------ ------------
1,386,920 1,331,559
Less accumulated depreciation, depletion,
amortization and impairment 490,841 466,923
------------ ------------
Net property and equipment 896,079 864,636
------------ ------------
Goodwill 31,615 30,509
Other Assets 9,813 9,390
------------ ------------
Total Assets $ 1,066,223 $ 1,023,136
============ ============
The accompanying notes are an integral part of the
consolidated condensed financial statements.
2
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS - CONTINUED
March 31,
2005 December 31,
(Unaudited) 2004
------------ ------------
(In thousands)
LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------
Current Liabilities:
Current portion of other liabilities $ 7,635 $ 5,837
Accounts payable 57,534 49,268
Accrued liabilities 21,149 19,818
Income taxes payable 9,342 33
Contract advances 1,075 2,220
------------ ------------
Total current liabilities 96,735 77,176
------------ ------------
Long-Term Debt 78,000 95,500
------------ ------------
Other Long-Term Liabilities 37,555 37,725
------------ ------------
Deferred Income Taxes 213,965 204,466
------------ ------------
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, 45,857,544 and
45,745,399 shares issued, respectively 9,172 9,149
Capital in excess of par value 312,514 310,132
Accumulated other comprehensive income (loss) (1,436) --
Retained earnings 319,718 288,988
------------ ------------
Total shareholders' equity 639,968 608,269
------------ ------------
Total Liabilities and Shareholders' Equity $ 1,066,223 $ 1,023,136
============ ===========
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
March 31,
------------------------
2005 2004
---------- ----------
(In thousands except per
Share amounts)
Revenues:
Contract drilling $ 96,681 $ 63,214
Oil and natural gas 56,864 37,990
Gas gathering and processing 18,230 30
Other (195) 376
---------- ----------
Total revenues 171,580 101,610
---------- ----------
Expenses:
Contract drilling:
Operating costs 63,431 46,556
Depreciation 9,610 7,464
Oil and natural gas:
Operating costs 12,413 9,632
Depreciation, depletion and
amortization 14,432 10,177
Gas gathering and processing:
Operating costs 16,834 15
Depreciation 638 17
General and administrative 3,971 2,771
Interest 687 417
---------- ----------
Total expenses 122,016 77,049
---------- ----------
Income Before Income Taxes 49,564 24,561
---------- ----------
Income Tax Expense:
Current 9,417 571
Deferred 9,417 8,763
---------- ----------
Total income taxes 18,834 9,334
---------- ----------
Equity in Earnings of Unconsolidated
Investments, Net of Income Tax -- 280
---------- ----------
Net income $ 30,730 $ 15,507
========== ==========
Net Income per Common Share:
Basic $ 0.67 $ 0.34
========== ==========
Diluted $ 0.67 $ 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,
------------------------
2005 2004
---------- ----------
(In thousands)
Cash Flows From Operating Activities:
Net income $ 30,730 $ 15,507
Adjustments to reconcile net income
to net cash provided (used) by
operating activities:
Depreciation, depletion
and amortization 24,874 17,886
Deferred tax expense 9,417 8,935
Other 1,246 (17)
Changes in operating assets and
liabilities increasing (decreasing)
cash:
Accounts receivable (10,448) 899
Accounts payable (10,781) (2,388)
Material and supplies inventory (1,078) (2,386)
Accrued liabilities 13,277 1,670
Prepaid expenses (214) (565)
Contract advances (1,145) 2,955
Other - net 16 116
---------- ----------
Net cash provided by
operating activities 55,894 42,612
---------- ----------
Cash Flows From (Used In) Investing
Activities:
Capital expenditures (including
producing property acquisitions
and other acquisitions) (47,121) (124,324)
Proceeds from disposition of assets 2,328 1,023
Other-net (207) 350
---------- ----------
Net cash used in
investing activities (45,000) (122,951)
---------- ----------
Cash Flows From (Used In) Financing
Activities:
Net borrowings (payments) under
line of credit (17,500) 74,600
Net payments of notes payable
and other long-term debt 276 --
Proceeds from exercise of stock options 517 219
Book overdrafts 5,618 5,299
---------- ----------
Net cash from (used in) financing
activities (11,089) 80,118
---------- ----------
Net Decrease in Cash and
Cash Equivalents (195) (221)
Cash and Cash Equivalents, Beginning
of Year 665 598
---------- ----------
Cash and Cash Equivalents, End of Period $ 470 $ 377
========== ==========
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,
---------------------
2005 2004
--------- ---------
(In thousands)
Net Income $ 30,730 $ 15,507
Other Comprehensive Income,
Net of Taxes:
Change in value of cash
flow derivative
instruments used as
cash flow hedges (1,464) (304)
Adjustment reclassification -
derivative settlements 28 78
--------- ---------
Comprehensive Income $ 29,294 $ 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, 2005 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, 2004. The company's independent
registered public accounting firm performed a review of these interim financial
statements in accordance with 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 registered public accounting
firm's liability under Section 11 does not extend to it.
The company's stock-based compensation plans are accounted for under the
recognition and measurement principles of APB 25, "Accounting for Stock Issued
to Employees," and related Interpretations. No stock-based employee compensation
cost related to stock options is reflected in net income, as all options granted
under the plan had an exercise price equal to the market value of the underlying
common stock on the date of grant. Compensation expense included in reported net
income is the company's matching 401(k) contribution. The following table
illustrates the effect on net income and earnings per share if the company had
applied the fair value recognition provisions of Financial Accounting Standards
Board Statement No. 123, "Accounting for Stock-Based Compensation," to
stock-based employee compensation.
7
Three Months Ended
----------------------
2005 2004
--------- ---------
(In thousands except
per share amounts)
Net Income, as Reported $ 30,730 $ 15,507
Add Stock-Based Employee Compensation
Expense Included in Reported Net
Income, Net of Tax 549 219
Less Total Stock-Based Employee
Compensation Expense Determined
Under Fair Value Based Method
For All Awards (1,030) (513)
--------- ---------
Pro Forma Net Income $ 30,249 $ 15,213
========= =========
Basic Earnings per Share:
As reported $ 0.67 $ 0.34
========= =========
Pro forma $ 0.66 $ 0.33
========= =========
Diluted Earnings per Share:
As reported $ 0.67 $ 0.34
========= =========
Pro forma $ 0.66 $ 0.33
========= =========
The fair value of each option granted is estimated using the Black-Scholes
model. There were no options granted in the first quarter of 2004. In the first
quarter of 2005 options for 4,000 shares with an estimated fair market value of
approximately $80,101 were granted. For options granted in 2005, the company's
estimate of stock volatility was 0.55 based on previous stock performance.
Dividend yield was estimated to remain at zero with a risk free interest rate of
4.42. 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.
8
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, 2005:
Basic earnings per common share $ 30,730 45,800 $ 0.67
Effect of dilutive stock options -- 250 --
------------- ------------- ----------
Diluted earnings per common share $ 30,730 46,050 $ 0.67
============= ============= ==========
For the Three Months Ended
March 31, 2004:
Basic earnings per common share $ 15,507 45,671 $ 0.34
Effect of dilutive stock options -- 188 --
------------- ------------- ----------
Diluted earnings per common share $ 15,507 45,859 $ 0.34
============= ============= ==========
All of the stock options outstanding at March 31, 2005 and 2004 were
included in the computation of diluted earnings per share for the three months
ended March 31, 2005 and 2004.
9
NOTE 3 - ACQUISITIONS
- ---------------------
On January 5, 2005 the company acquired a subsidiary of Strata Drilling LLC
for $10.5 million in cash. In this acquisition the company acquired two drilling
rigs as well as spare parts, inventory, drill pipe, and other major rig
components. The two rigs are 1,500 horsepower, diesel electric rigs with the
capacity to drill 12,000 to 20,000 feet. One rig was operating under contract
when acquired and the other rig will require approximately $2 million in
expenditures before it will be placed in service. The latter rig should be fully
operational during the second quarter of 2005. Both rigs will be in our Rocky
Mountain Division. The results of operations for this acquired company are
included in the statement of income for the period after January 5, 2005.
The $10.5 million paid in this acquisition was allocated as follows (in
thousands):
Rigs $ 5,712
Spare Drilling Equipment 2,715
Drill Pipe and Collars 932
Goodwill 1,106
----------
Total consideration $ 10,465
==========
NOTE 4 - CREDIT AGREEMENT
- -------------------------
Long-term debt consisted of the following as of March 31, 2005 and 2004:
2005 2004
---------- ----------
(In thousands)
Revolving Credit Loan,
with Interest at March 31,
2005 and 2004 of 3.7% and 2.2%,
Respectively $ 78,000 $ 75,000
Less Current Portion -- --
---------- ----------
Total Long-Term Debt $ 78,000 $ 75,000
========== ==========
10
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 and the company has elected to have the full $150.0 million available as
the commitment amount. 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 associated with the new agreement,
$40,000 of which will be paid annually. The fees will be amortized over the four
year life of the loan.
The borrowing base under the current credit facility is subject to
re-determination on May 10 and November 10 of each year. Each re-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 LIBOR Rate for a 30, 60, 90 or 180 day term. During any LIBOR Rate funding
period the outstanding principal balance of the note to which such LIBOR 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 LIBOR Rate is computed at the LIBOR 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 LIBOR 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 the company's 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 the company's
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,
11
. 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.
On March 31, 2005, the company was in compliance with the covenants of its
credit agreement.
NOTE 5 - ASSET RETIREMENT OBLIGATIONS
- -------------------------------------
Under Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations" (FAS 143) the company is required to record the fair
value of liabilities associated with the retirement of long-lived assets. The
company owns oil and natural gas properties which require cash 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 these
plugging liabilities.
12
The following table shows the activity for the three months ending March
31, 2005 and 2004 relating to the company's retirement obligation for plugging
liability:
Three Months Ended
-----------------------------
2005 2004
------------- -------------
(In Thousands)
Short-Term Plugging Liability:
Liability at beginning of period $ 226 $ 303
Accretion of discount 8 4
Liability settled in the period -- (57)
------------- -------------
Plugging liability at end of
period $ 234 $ 250
============= =============
Long-Term Plugging Liability:
Liability at beginning of period $ 18,909 $ 11,691
Accretion of discount 234 173
Liability incurred in the period 144 5,566
Liability settled in the period (23) --
Sold -- (17)
Revision of estimate (2) --
------------- -------------
Plugging liability at end of
period $ 19,262 $ 17,413
============= =============
13
NOTE 6 - NEW ACCOUNTING PRONOUNCEMENTS
- --------------------------------------
In November 2004, the FASB issued Statement on Financial Accounting
Standards No. 151, "Inventory Costs, an amendment of ARB No. 43, Chapter 4,"
which clarifies the types of costs that should be expensed rather than
capitalized as inventory. The provisions of FAS 151 are effective for years
beginning after June 15, 2005. The company does not expect this statement to
have a material impact on its results of operations, financial condition or cash
flows.
The FASB issued Statement on Financial Accounting Standards No. 153,
"Exchanges of Productive Assets," in December 2004 that amended Accounting
Principles Board (APB) Opinion No. 29, "Accounting for Non-monetary
Transactions." FAS 153 requires that non-monetary exchanges of similar
productive assets are to be accounted for at fair value. Previously these
transactions were accounted for at book value of the assets. This statement is
effective for non-monetary transactions occurring in fiscal periods beginning
after June 15, 2005. The company does not expect this statement to have a
material impact on its results of operations, financial condition or cash flows.
In December 2004, the FASB issued FAS 123R, which requires that
compensation cost relating to share-based payments be recognized in the
company's financial statements. The company currently accounts for those
payments under recognition and measurement principles of APB Opinion No. 25,
"Accounting for Stock Issued to Employees," and related interpretations. Under
Statement No. 123R, Unit would have been required to implement the standard as
of the beginning of the first interim period that begins after June 15, 2005. On
April 15, 2005, the Securities and Exchange Commission (SEC) approved a new rule
that allows the implementation of Statement No. 123R at the beginning of the
next fiscal year after June 15, 2005 (January 1, 2006 for Unit). The company is
preparing to implement this standard effective January 1, 2006. On March 29,
2005, the SEC issued Staff Accounting Bulletin No. 107 (SAB 107) on FAS 123R to
assist preparers by simplifying some on the implementation challenges of
FAS123R. In SAB 107, the SEC staff acknowledges that there exists a range of
potential conduct, conclusions, or methodologies that reasonably could be
applied in estimating fair values of share-based arrangements; thus, if a
registrant makes a good-faith estimate in accordance with the provisions of
FAS123R, future events that affect an instrument's fair value will not cast a
doubt concerning the reasonableness of the original estimate. Although the
transition method to be used to adopt the standard has not been selected, see
Note 1 for the effect on net income and earnings per share for the three months
ended March 31, 2005 and 2004 if the company had applied the fair value
recognition provision of FAS 123 to stock based employee compensation.
14
NOTE 7 - GOODWILL
- -----------------
Goodwill represents the excess of the cost of the acquisition of Hickman
Drilling Company, CREC Rig Equipment Company, CDC Drilling Company, SerDrilco
Incorporated, Sauer Drilling Company and Strata Drilling LLC over the fair value
of the net assets acquired. For goodwill and intangible assets recorded in the
financial statements, an impairment test is performed at least annually to
determine whether the fair value has decreased. Goodwill is all related to the
drilling segment. In the first quarter of 2005, the carrying amount of goodwill
was increased $1.1 million for the goodwill recorded in the acquisition of
Strata Drilling LLC.
NOTE 8 - HEDGING ACTIVITY
- -------------------------
The company periodically enters into derivative commodity instruments to
hedge its exposure to price fluctuations on oil and natural gas production. Such
instruments include regulated natural gas and crude oil futures contracts traded
on the New York Mercantile Exchange (NYMEX) and over-the- counter swaps and
basic hedges with major energy derivative product specialists. Initial adoption
of this standard was not material.
During the first and second quarters of 2004, the company entered into two
natural gas collar contracts. Each collar contract was for 10,000 MMBtu's of
production per day. One contract covered the period of April through October of
2004 and had a floor of $4.50 and a ceiling of $6.76. The other contract covered
the period of May through October of 2004 and had a floor of $5.00 and a ceiling
of $7.00. The company also entered into an oil hedge covering 1,000 barrels of
oil production per day. This transaction covered the periods of February through
December of 2004 and had an average price of $31.40. These hedges were cash flow
hedges and there was no material amount of ineffectiveness. 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.
In January 2005, the company 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 2005 and has a floor of $5.50 and
a ceiling of $7.19. The other contract covers the period of April through
October of 2005 and has a floor of $5.50 and a ceiling of $7.30. In March 2005,
the company also entered into an oil collar contract covering 1,000 barrels of
oil production per day. This transaction covers the period of April through
December of 2005 and has a floor of $45.00 and a ceiling of $69.25. These hedges
are cash flow hedges and there is no material amount of ineffectiveness. The
fair value of the collar contracts was recognized on the March 31, 2005 balance
sheet as a derivative liability of $2.7 million and at a loss of $1.6 million,
net of tax, in accumulated other comprehensive income.
15
In February 2005, the company entered into an interest rate swap to help
manage its exposure to possible future interest rate increases. The contract
swaps $50.0 million of variable rate debt to fixed and covers the period from
March 1, 2005 through January 2008. This period coincides with the remaining
length of the company's current credit facility. The fixed rate is based on
three-month LIBOR and is at 3.99%. The swap is a cash flow hedge. The company's
interest expense was increased by $46,500 in the first quarter of 2005 and the
fair value of the swap was recognized on the March 31, 2005 balance sheet as a
derivative asset of $333,000 and at a gain of $207,000, net of tax, in
accumulated other comprehensive income.
NOTE 9 - INDUSTRY SEGMENT INFORMATION
- -------------------------------------
The company has three business segments: Contract Drilling, Oil and
Natural Gas Exploration and Production and Gas Gathering and Processing,
representing its three main business units offering different products and
services. The Contract Drilling segment is engaged in the land contract drilling
of oil and natural gas wells; the Oil and Natural Gas Exploration and Production
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 purchasing, gathering, processing and treating of natural gas.
The company evaluates the performance of its operating segments based
on operating income, which is defined as operating revenues less operating
expenses and depreciation, depletion and amortization. The company has natural
gas production in Canada, which is not significant. Information regarding the
company's operations by industry segment for the three month periods ended March
31, 2005 and 2004 is as follows:
16
Three Months Ended
March 31,
2005 2004
---------- ----------
(In thousands)
Revenues:
Contract drilling $ 99,320 $ 65,580
Elimination of inter-segment
revenue 2,639 2,366
---------- ----------
Contract drilling net of
inter-segment revenue 96,681 63,214
---------- ----------
Oil and natural gas 56,864 37,990
---------- ----------
Gas gathering and processing 20,088 335
Elimination of inter-segment
revenue 1,858 305
---------- ----------
Gas gathering and processing net
of inter-segment revenue 18,230 30
---------- ----------
Other (195) 376
---------- ----------
Total revenues $ 171,580 $ 101,610
========== ==========
17
Three Months Ended
March 31,
2005 2004
---------- ----------
(In thousands)
Operating Income (1):
Contract drilling $ 23,640 $ 9,194
Oil and natural gas 30,019 18,181
Gas gathering and processing 758 (2)
---------- ----------
Total operating income 54,417 27,373
General and administrative
expense (3,971) (2,771)
Interest expense (687) (417)
Other income (expense) - net (195) 376
---------- ----------
Income before income taxes $ 49,564 $ 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.
18
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 March 31, 2005, and the related
consolidated condensed statements of income and comprehensive income for each of
the three month periods ended March 31, 2005 and 2004 and the consolidated
condensed statement of cash flows for the three month periods ended March 31,
2005 and 2004. These interim financial statements are the responsibility of the
Company's management.
We conducted our review in accordance with standards of the Public Company
Accounting Oversight Board (United States). A review of interim financial
information consists principally of applying analytical review 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 auditing standards of the Public
Company Accounting Oversight Board (United States), the consolidated balance
sheet as of December 31, 2004, and the related consolidated statements of
income, shareholders' equity and cash flows for the year then ended,
management's assessment of the effectiveness of the company's internal control
over financial reporting as of December 31, 2004 and the effectiveness of the
company's internal control over financial reporting as of December 31, 2004; and
in our report dated March 14, 2005, we expressed unqualified opinions thereon.
The consolidated financial statements and management's assessment of the
effectiveness of internal control over financial reporting referred to above are
not presented herein. In our opinion, the information set forth in the
accompanying consolidated condensed balance sheet as of December 31, 2004, is
fairly stated in all material respects in relation to the consolidated balance
sheet from which it has been derived.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
May 3, 2005
19
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
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 and, to
a lesser extent, the prices we receive for our oil production;
. the quantity of natural gas we produce;
. the demand for and the dayrates we receive for our drilling
rigs; and
. the margins we obtain from our natural gas gathering and
processing contracts.
At March 31, 2005, we had cash totaling $470,000 and we had borrowed $78.0
million of the $150.0 million we had elected to have available under our credit
agreement.
Our three principal business segments are:
. contract drilling carried out by our subsidiaries Unit
Drilling Company and Service Drilling Southwest, L.L.C.;
. oil and natural gas exploration, carried out by our
subsidiary Unit Petroleum Company and, until it was
merged into Unit Petroleum Company in March 2005,
PetroCorp Incorporated; and
. natural gas purchasing, gathering and processing
carried out by our subsidiary Superior Pipeline
Company, L.L.C.
20
The following is a summary of certain financial information on March 31,
2005 and March 31, 2004 and for the three months ended March 31, 2005 and March
31, 2004:
March 31, March 31, Percent
2005 2004 Change
-------------- -------------- -------
(In thousands except percent amounts)
Working Capital $ 31,981 $ 25,668 25%
Long-Term Debt $ 78,000 $ 75,000 4%
Shareholders' Equity $ 639,968 $ 532,673 20%
Ratio of Long-Term debt to
Total Capitalization 11% 12%
Net Income $ 30,730 $ 15,507 98%
Net Cash Provided by
Operating Activities $ 55,894 $ 42,612 31%
Net Cash Used in Investing
Activities $ (45,000) $ (122,951) 63%
Net Cash Provided by (Used
in) Financing Activities $ (11,089) $ 80,118 (114%)
The following table summarizes certain operating information for the first
three months of 2005 and 2004:
Percent
2005 2004 Change
------------ ------------ --------
Oil Production (MBbls) 280 215 30%
Natural Gas Production (MMcf) 7,653 6,294 22%
Average Oil Price Received $ 44.56 $ 30.63 45%
Average Oil Price Received
Excluding Hedge $ 44.56 $ 31.22 43%
Average Natural Gas Price
Received $ 5.69 $ 4.90 16%
Average Natural Gas Price
Received Excluding Hedge $ 5.69 4 4.90 16%
Average Number of Our
Drilling Rigs in Use
During the Period 99.3 81.7 22%
Total Number of Our Drilling
Rigs Available at the End
of the Period 102 88 16%
Gas Gathered - MMBtu/day 107,254 12,637 749%
Gas Processed - MMBtu/day 30,336 64 47,300%
Number of Natural Gas
Gathering Systems 32 15 113%
Our Bank Credit Agreement. At March 31, 2005, we had a $150.0 million bank
credit agreement consisting of a revolving credit facility maturing on January
30, 2008. Borrowings under the credit facility are limited to a commitment
amount and we currently elected to have the full $150.0 million available as the
21
commitment amount. 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 associated with the new agreement, $40,000 of which will be paid
annually. The remainder of the fees will be amortized over the four year life of
the loan. The average interest rate for the first quarter of 2005 was 3.9%. At
March 31, 2005 and May 2, 2005 our borrowings were $78.0 million and $67.5
million, respectively.
The borrowing base under our credit facility is subject to re-determination
on May 10 and November 10 of each year. The latest re-determination supported
the full $150.0 million. Each re-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
borrowing base. The agreement also 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 LIBOR
Rate for a 30, 60, 90 or 180 day term. During any LIBOR Rate funding period the
outstanding principal balance of the note to which such LIBOR 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 LIBOR Rate is computed at the LIBOR 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 LIBOR 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
March 31, 2005, all of our $78.0 million debt was subject to the LIBOR 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 loan agreement) of not less
than 1 to 1, and
22
. 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.
We were in compliance with the covenants of our credit agreement as of
March 31, 2005.
In February 2005, we entered into an interest rate swap to help manage our
exposure to possible future interest rate increases. The contract swaps $50.0
million of variable rate debt to fixed and covers the period from March 1, 2005
through January 2008. This period coincides with the remaining length of our
current credit facility. The fixed rate is based on three-month LIBOR and is at
3.99%. The swap is a cash flow hedge. Our interest expense was increased by
$46,500 in the first quarter of 2005 and the fair value of the swap was
recognized on the March 31, 2005 balance sheet as a derivative asset of $333,000
and at a gain of $207,000, net of tax, in accumulated other comprehensive
income.
Contractual Commitments. At March 31, 2005 we have the following
contractual obligations:
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) $ 86,619 $ 3,039 $ 83,580 $ -- $ --
Retirement
Agreements(2) 2,162 350 1,219 593 --
Operating
Leases(3) 3,592 995 1,543 1,054 --
Drill Pipe and
Engine
Acquisi-
tions(4) 13,567 13,567 -- -- --
Tubing and
Casing
Acquisi-
tions(5) 2,457 2,457 -- -- --
SerDrilco Inc.
Earn-Out
Agreement(6) 1,890 1,890 -- -- --
--------- --------- --------- -------- --------
Total
Contractual
Obligations $ 110,287 $ 22,298 $ 86,342 $ 1,647 $ --
========= ========= ========= ======== ========
-------------------
23
(1) See Previous Discussion in Management Discussion and Analysis
regarding bank debt. This obligation is presented in accordance with
the terms of the credit agreement signed on January 30, 2004 and
includes interest calculated at the March 31, 2005 interest rate of
3.7% including the effect of the interest rate swap related to $50.0
million of debt outstanding.
(2) In the second quarter of 2001, we recorded $1.3 million in additional
employee benefit expense for the present value of a separation
agreement made in connection with the retirement of King Kirchner from
his position as Chief Executive Officer. The liability associated with
this expense, including accrued interest, will be paid in monthly
payments of $25,000 starting in July 2003 and continuing through June
2009. In the first quarter of 2004, we acquired a liability for the
present value of a separation agreement between PetroCorp Incorporated
and one of its previous officers. The liability associated with this
agreement will be paid in quarterly payments of $12,500 through
December 31,2007. In the first quarter of 2005, we recorded $0.7
million in additional employee benefit expense for the present value
of a separation agreement made in connection with the retirement of
John Nikkel from his position as Chief Executive Officer. The
liability associated with this expense, including accrued interest,
will be paid in monthly payment of $31,250 starting in November 2006
and continuing through October 2008. These liabilities as presented
above are undiscounted.
(3) We lease office space in Tulsa and Woodward, Oklahoma; Houston and
Midland, Texas and Denver Colorado under the terms of operating leases
expiring through January 31, 2010. Additionally, we have several
equipment leases and lease space on short-term commitments to stack
excess rig equipment and production inventory.
(4) Due to the increasing cost of steel and the potential for limited
availability of new drill pipe within the industry, we have a
commitment to purchase approximately $11.8 million of drill pipe and
drill collars. We have also committed to purchase $1.8 million of
engines and generators for the construction of new rigs.
(5) Our oil and natural gas segment has a commitment to purchase $2.5
million of tubing and casing for delivery during the second and third
quarter of 2005.
(6) 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
$10.0 million for each of the three years following the acquisition.
For the year ending December 31, 2004, the drilling rigs included in
the earn-out provision had cash flow of approximately $13.8 million.
24
At March 31, 2005, we also had 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) $ 2,334 Unknown Unknown Unknown Unknown
Separation
Benefit
Agreement(2) $ 2,898 $ 770 $ 225 Unknown Unknown
Plugging
Liability(3) $ 19,496 $ 234 $ 551 $ 1,877 $ 16,834
Gas Balancing
Liability(4) $ 1,080 Unknown Unknown Unknown Unknown
Repurchase
Obliga-
tions(5) Unknown Unknown Unknown Unknown Unknown
Workers'
Compensation
Liability(6) $ 17,525 $ 6,281 $ 1,998 $ 1,149 $ 8,097
(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. On May 5, 2004 we also adopted the Special Separation
Benefit Plan ("Special Plan"). This plan is identical to the
25
Separation Benefit Plan with the exception that the benefits under the
plan vest on the earliest of a participant's reaching the age of 65 or
serving 20 years with the Unit. As of March 31, 2005, there were no
participants the Special 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 recorded a liability for certain properties where we believe
there are insufficient oil and 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. No repurchases were made in
the first quarter of 2005 and 2004.
(6) We have recorded a liability for future estimated payments related to
workers' compensation claims made primarily in our contract drilling
segment.
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 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 covered the period of April through October of 2004 and
had a floor of $4.50 and a ceiling of $6.76. The other contract covered the
period of May through October of 2004 and had a floor of $5.00 and a ceiling of
$7.00. We also entered into an oil hedge covering 1,000 barrels of oil
production per day. This transaction covered the periods of February through
December of 2004 and had an average price of $31.40. These hedges were cash flow
26
hedges and there was no material amount of ineffectiveness. 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.
In January 2005, 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 2005 and has a floor of $5.50 and
a ceiling of $7.19. The other contract covers the period of April through
October of 2005 and has a floor of $5.50 and a ceiling of $7.30. In March 2005,
we also entered into an oil collar contract covering 1,000 barrels of oil
production per day. This transaction covers the periods of April through
December of 2005 and has a floor of $45.00 and a ceiling of $69.25. These hedges
are cash flow hedges and there is no material amount of ineffectiveness. The
fair value of the collar contracts was recognized on the March 31, 2004 balance
sheet as a derivative liability of $2.7 million and at a loss of $1.6 million,
net of tax, in accumulated other comprehensive income.
In February 2005, we entered into an interest rate swap to help manage our
exposure to possible future interest rate increases. The contract swaps $50.0
million of variable rate debt to fixed and covers the period from March 1, 2005
through January 2008. This period coincides with the remaining length of our
current credit facility. The fixed rate is based on three-month LIBOR and is at
3.99%. The swap is a cash flow hedge. Our interest expense was increased by
$46,500 in the first quarter of 2005 and the fair value of the swap was
recognized on the March 31, 2005 balance sheet as a derivative asset of $333,000
and at a gain of $207,000, net of tax, in accumulated other comprehensive
income.
Self-Insurance or Retentions. We are self-insured for certain losses
relating to workers' compensation, general liability, property damage and
employee medical benefits. Our insurance policies contain deductibles or
retentions per occurrence ranging from $200,000 for general liability to $1.0
million for drilling 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 the insurance coverage we
have 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. Natural gas comprises 85% 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 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.
27
Based on our first quarter 2005 production, a $.10 per Mcf change in what
we are paid for our natural gas production would result in a corresponding
$239,000 per month ($2.9 million annualized) change in our pre-tax operating
cash flow. Our first quarter 2005 average natural gas price was $5.69 compared
to an average natural gas price of $4.90 for the first quarter of 2004. A $1.00
per barrel change in our oil price would have a $86,800 per month ($1.0 million
annualized) change in our pre-tax operating cash flow based on our production in
the first quarter of 2005. Our first quarter 2005 average oil price was $44.56
compared with an average oil price of $30.63 received in the first quarter of
2004.
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.
Most of our natural gas production is sold to third parties under
month-to-month contracts. Presently we believe that our buyers will be able to
perform their commitments to us.
Oil and Natural Gas Acquisitions and Capital Expenditures. Most of our
capital expenditures are discretionary and directed toward future growth. Our
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 26 wells (8.84 net wells) in the first quarter of 2005 compared to 34
wells (15.98 net wells) in the first quarter of 2004. Our total capital
expenditures for oil and natural gas exploration and acquisitions in the first
quarter of 2005 totaled $31.6 million. Based on current prices, we plan to drill
an estimated 220 to 230 wells in 2005 and estimate our total capital
expenditures for oil and natural gas exploration and acquisitions to be around
$125.0 million. We have commitments to purchase $2.5 million of tubing and
casing for delivery during the second quarter of 2005.
Contract Drilling. Our drilling work is subject to many factors that
influence the number of drilling rigs we have working as well as the costs and
revenues associated with that work. These factors include the demand for
drilling rigs, 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. Because of the current high
demand for drilling rigs, we are experiencing some difficulty in hiring and
keeping all of the rig crews we need.
In response, at the end of the first and fourth quarters of 2004, we
increased wages in some of our drilling areas and implemented longevity pay
incentives to help maintain our contract drilling labor base. To date, these
28
efforts have allowed us to meet our labor requirements. If current demand for
drilling rigs continues, shortages of experienced personnel may limit our
ability to operate our drilling rigs at or above the 98% utilization rate we
achieved in the first quarter of 2005.
We currently do not have any shortages of drill pipe and drilling
equipment. Because of increasing steel costs and the potential for shortages in
the availability of new drill pipe, at March 31, 2005 we had commitments to
purchase approximately $11.8 million of drill pipe and drill collars. We have
also committed to purchase $1.8 million of engines and generators for the
construction of new rigs.
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 we received for our drilling rigs during 2003 and 2004 reached
a low of $7,275 per day in February of 2003. However, as natural gas and oil
prices began to rise during the second quarter of 2003 and have continued to
remain strong through the first quarter of 2005, both demand for our drilling
rigs and dayrates have improved. In the first quarter of 2005, the average
dayrate we received was $10,253 per day compared to $8,252 per day in the first
quarter of 2004. The average use of our drilling rigs in the first quarter of
2005 was 99.3 drilling rigs (98%) compared with 81.7 rigs (93%) for the first
quarter of 2004. Based on the average utilization of our drilling rigs during
the first quarter of 2005, a $100 per day change in dayrates has an $9,930 per
day ($3.6 million annualized) change in our pre-tax operating cash flow. We
expect that utilization and dayrates for our drilling rigs will continue to
depend mainly on the price of natural gas and the availability of drilling rigs
to meet the demands of the industry.
Our contract drilling subsidiary provides drilling services for our
exploration and production subsidiary. 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
quarter of 2005 and 2004, we drilled 11 and 8 wells, respectively for our
exploration and production subsidiary. The profit received by our contract
drilling segment of $851,000 and $929,000 during the first quarter of 2005 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 January 5, 2005, we
acquired a subsidiary of Strata Drilling LLC for $10.5 million in cash. This
acquisition included two drilling rigs as well as spare parts, inventory, drill
pipe, and other major rig components. The two drilling rigs are 1,500
horsepower, diesel electric rigs with the capacity to drill 12,000 to 20,000
feet. One drilling rig was operating under contract when it was acquired and the
other drilling rig will require approximately $2 million in expenditures before
it will be placed in service. The latter rig should be fully operational during
the second quarter of 2005. Both rigs will be in our Rocky Mountain Division.
The results of operations for this acquired company are included in the
statement of income for the period after January 5, 2005.
29
On July 30, 2004, we completed our acquisition of Sauer Drilling Company, a
Casper, Wyoming-based drilling company. We paid $40.3 million in in this
acquisition which included $5.3 million for working capital. This acquisition
includes nine 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 four 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
in the Rocky Mountains in the medium-to-smaller drilling rig depth ranges. The
Casper, Wyoming equipment yard, will continue to provide service space for the
nine newly acquired drilling rigs and trucks as well as for our 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.
On May 4, 2004, we acquired two drilling rigs and related equipment for
$5.5 million. The drilling rigs are rated at 850 and 1,000 horsepower,
respectively, with depth capacities from 12,000 to 15,000 feet. We refurbished
the drilling rigs for approximately $4.0 million. One drilling rig was placed
into service at the beginning of August 2004 and the other drilling rig was
placed into service in the middle of September 2004. Both drilling rigs are
working in our Rocky Mountain division.
For our contract drilling operations, during the first quarter of 2005, we
incurred $26.0 million in capital expenditures, which includes $1.1 million in
goodwill from the Strata Drilling LLC acquisition. For the year 2005, we have
budgeted capital expenditures of approximately $60 million for our contract
drilling operations excluding the $10.5 million paid in the Strata Drilling LLC
acquisition.
Acquisition of Natural Gas Gathering and Processing Company. In July 2004,
we consolidated and increased our natural gas gathering and processing business
when we completed the acquisition of the 60% of Superior Pipeline Company,
L.L.C. we did not already own. We paid $19.8 million in this acquisition. Before
July 2004, we had developed 18 gathering systems which we have now consolidated
with Superior. Superior is a mid-stream company engaged primarily in the
purchasing, gathering, processing and treating of natural gas. It operates one
natural gas treatment plant, owns three processing plants, 32 active gathering
systems and 440 miles of pipeline. Superior operates in Oklahoma, Texas and
Louisiana and has been in business since 1996. This acquisition and
consolidation increases our ability to gather and market our natural gas (as
well as third party natural gas) and construct or acquire existing natural gas
gathering and processing facilities.
Before this acquisition, our 40% interest in the operations of Superior was
shown as equity in earnings of unconsolidated investments. 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 business segments has been eliminated. During
the first quarter of 2005, Superior purchased $1.3 million of our natural gas
30
production and paid $32,000 for our natural gas liquids which were eliminated
from our consolidated condensed financial statements.
For the year 2005, we have budgeted capital expenditures of approximately
$20.0 million for our natural gas gathering and processing operation with the
focus on growing this segment through the construction of new facilities or
acquisitions.
Oil and Natural Gas Limited Partnerships and Other Entity Relationships. We
are the general partner for 11 oil and natural gas limited partnerships which
were formed privately and publicly. Each partnership's revenues and costs are
shared under formulas prescribed in its 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 2004, the total paid to us for all of these fees was
$746,000. We expect the fees in 2005 will be comparable to those 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.
31
NEW ACCOUNTING PRONOUNCEMENTS
- -----------------------------
In November 2004, the FASB issued Statement on Financial Accounting
Standards No. 151, "Inventory Costs, an amendment of ARB No. 43, Chapter 4,"
which clarifies the types of costs that should be expensed rather than
capitalized as inventory. The provisions of FAS 151 are effective for years
beginning after June 15, 2005. We do not expect this statement to have a
material impact on our results of operations, financial condition or cash flows.
The FASB issued Statement on Financial Accounting Standards No. 153,
"Exchanges of Productive Assets," in December 2004 that amended Accounting
Principles Board (APB) Opinion No. 29, "Accounting for Non-monetary
Transactions." FAS 153 requires that non-monetary exchanges of similar
productive assets are to be accounted for at fair value. Previously these
transactions were accounted for at book value of the assets. This statement is
effective for non-monetary transactions occurring in fiscal periods beginning
after June 15, 2005. We do not expect this statement to have a material impact
on our results of operations, financial condition or cash flows.
In December 2004, the FASB issued FAS 123R, which requires that
compensation cost relating to share-based payments be recognized in our
financial statements. We currently account for those payments under recognition
and measurement principles of APB Opinion No. 25, "Accounting for Stock Issued
to Employees," and related interpretations. Under Statement No. 123R, we would
have been required to implement the standard as of the beginning of the first
interim period that begins after June 15, 2005. On April 15, 2005, the
Securities and Exchange Commission (SEC) approved a new rule that allows the
implementation of Statement No. 123R at the beginning of the next fiscal year
that begins after June 15, 2005 (January 1, 2006 for us). We are preparing to
implement this standard effective January 1, 2006. On March 29, 2005, the SEC
issued Staff Accounting Bulletin No. 107 (SAB 107) on FAS 123R to assist
preparers by simplifying some on the implementation challenges of FAS123R. In
SAB 107, the SEC staff acknowledges that there exists a range of potential
conduct, conclusions, or methodologies that reasonably could be applied in
estimating fair values of share-based arrangements; thus, if a registrant makes
a good-faith estimate in accordance with the provisions of, future events that
affect an instrument's fair value will not cast a doubt concerning the
reasonableness of the original estimate. Although the transition method to be
used to adopt the standard has not been selected, see Note 1 for the effect on
net income and earnings per share for the three months ended March 31, 2005 and
2004 if we had applied the fair value recognition provision of FAS 123 to stock
based employee compensation.
32
SAFE HARBOR STATEMENT
- ---------------------
This report, including information included in, or incorporated by
reference from, future filings by us with the SEC, as well as information
contained in written material, press releases and oral statements issued by or
on our behalf, contain, or may contain, certain statements that are
"forward-looking statements" within the meaning of federal securities laws. All
statements, other than statements of historical facts, included or incorporated
by reference in this report, which address activities, events or developments
which we expect or anticipate will or may occur in the future are
forward-looking statements. The words "believes," "intends," "expects,"
"anticipates," "projects," "estimates," "predicts" and similar expressions are
used to identify forward-looking statements.
These forward-looking statements include, among others, such things as:
. the amount and nature of our future capital expenditures;
. wells to be drilled or reworked;
. prices for oil and natural gas;
. demand for oil and natural gas;
. exploitation and exploration prospects;
. estimates of proved oil and natural gas reserves;
. oil and natural gas reserve potential;
. development and infill drilling potential;
. drilling prospects;
. expansion and other development trends of the oil and natural gas
industry;
. business strategy;
. production of oil and natural gas reserves;
. growth potential for our gathering and processing operations;
. gathering systems and processing plants to be constructed or acquired;
. volumes and prices for natural gas gathered and processed;
. expansion and growth of our business and operations; and
. demand for our drilling rigs and drilling rig rates.
33
These statements are based on certain assumptions and analyses made by us
in light of our experience and our perception of historical trends, current
conditions and expected future developments as well as other factors we believe
are appropriate in the circumstances. However, whether actual results and
developments will conform to our expectations and predictions is subject to a
number of risks and uncertainties which could cause actual results to differ
materially from our expectations, including:
. the risk factors discussed in this report and in the documents we
incorporate by reference;
. general economic, market or business conditions;
. the nature or lack of business opportunities that we pursue;
. demand for our land drilling services;
. changes in laws or regulations; and
. other factors, most of which are beyond our control.
You should not place undue reliance on any of these forward-looking
statements. We disclaim any current intention to update forward-looking
information and to release publicly the results of any future revisions we may
make to forward-looking statements to reflect events or circumstances after the
date of this report to reflect the occurrence of unanticipated events.
In order to provide a more thorough understanding of the possible effects
of some of these influences on any forward-looking statements made by us, the
following discussion outlines certain factors that in the future could cause our
consolidated results for 2005 and beyond to differ materially from those that
may be presented in any such forward-looking statement made by or on behalf of
us.
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 2005 versus First Quarter 2004
- --------------------------------------------
Provided below is a comparison of selected operating and financial data for
the first quarter of 2005 versus the first quarter of 2004:
First First Percent
Quarter 2005 Quarter 2004 Change
--------------- --------------- ---------
Total Revenue $ 171,580,000 $ 101,610,000 69%
Net Income $ 30,730,000 $ 15,507,000 98%
Oil and Natural Gas:
Revenue $ 56,864,000 $ 37,990,000 50%
Operating costs $ 12,413,000 $ 9,632,000 29%
Average natural gas price (Mcf) $ 5.69 $ 4.90 16%
Average oil price (Bbl) $ 44.56 $ 30.63 45%
Natural gas production (Mcf) 7,653,000 6,294,000 22%
Oil production (Bbl) 280,000 215,000 30%
Depreciation, depletion and
amortization rate (Mcfe) $ 1.54 $ 1.33 16%
Depreciation, depletion and
amortization $ 14,432,000 $ 10,177,000 42%
Drilling:
Revenue $ 96,681,000 $ 63,214,000 53%
Operating costs $ 63,431,000 $ 46,556,000 36%
Percentage of revenue from
daywork contracts 100% 100%
Average number of rigs in use 99.3 81.7 22%
Average dayrate on daywork
contracts $ 10,253 $ 8,252 24%
Depreciation $ 9,610,000 $ 7,464,000 29%
Gas Gathering and Processing:
Revenue $ 18,230,000 $ 30,000 60,667%
Operating costs $ 16,834,000 $ 15,000 112,127%
Depreciation $ 638,000 $ 17,000 3,653%
Gas gathered - Mmbtu/day 107,254 12,637 749%
Gas processed - Mmbtu/day 30,336 64 47,300%
General and Administrative Expense $ 3,971,000 $ 2,771,000 43%
Interest Expense $ 687,000 $ 417,000 65%
Average Interest Rate 3.74% 2.19% 71%
Average Long-Term Debt Outstanding $ 94,056,000 $ 56,019,000 68%
35
Oil and natural gas revenues increased $18.9 million or 50% in the first
quarter of 2005 as compared to the first quarter of 2004. Increased oil and
natural gas prices accounted for 53% of this increase while increased production
volumes accounted for 47% of the increase. The PetroCorp acquisition increased
oil production by 16% in the first quarter of 2005 while total oil production
increased 30%. The PetroCorp acquisition increased natural gas production for
the first quarter of 2005 by 6% while total natural gas production increased
22%. Since PetroCorp was purchased on January 30, 2004, there is an additional
month of PetroCorp production volumes in the first quarter of 2005. Increased
production outside of the PetroCorp acquisition came primarily from our
development drilling.
Oil and natural gas operating costs increased $2.8 million or 29% in the
first quarter of 2005 as compared to 2004. Costs directly related to the
production of the PetroCorp wells that we acquired in January 2004 represented
22% of this increase while 26% came from production costs related to wells we
drilled in 2004 and increases in production costs from previously owned wells.
Gross production taxes represented 36% of the increase because of higher oil and
natural gas revenues. General and administrative cost directly related to well
production represented 12% of the increase as labor costs increased primarily
because of a 41% addition in the number of employees working in the exploration
and production area. Total depreciation, depletion and amortization ("DD&A")
increased $4.3 million or 42%. Higher production volumes accounted for 56% of
this increase while increases in our DD&A rate represented 44% of this increase.
The increase in our DD&A rate in the first quarter of 2005 compared to the first
quarter of 2004 resulted primarily from 63% higher development drilling cost per
equivalent Mcf in 2004. PetroCorp's oil and natural gas reserves were added at a
5% higher cost per Mcfe than our discovery cost in 2003.
Industry demand for our drilling rigs increased throughout 2004 and the
first quarter of 2005 as natural gas prices continued to remain above $4.50.
Drilling revenues increased $33.5 million or 53% in the first quarter of 2005
versus the first quarter of 2004. In July 2004, we acquired nine drilling rigs
with the acquisition of Sauer Drilling Company. The Sauer drilling rigs
increased our first quarter 2005 drilling revenues by approximately 16%. In
addition to the Sauer drilling rigs, we also placed four additional drilling
rigs in service since the first quarter of 2004. The increase in revenue from
all of the acquired drilling rigs and the increase in utilization of our
previously owned drilling rigs represented 39% of the total increase in
revenues. Increases in dayrates and mobilization fees accounted for 61% of the
increase in total drilling revenues. Our average dayrate in the first quarter of
2005 was 24% higher than in the first quarter of 2004.
Drilling operating costs increased $16.9 million or 36% between the
comparative quarters. The increase in operating costs from all of the 14
drilling rigs place in service since the first quarter of 2004 and increased
utilization of our previously owned drilling rigs represented 55% of the total
increase in operating cost. Increases in operating cost per day accounted for
45% of the increase in total operating costs. Operating cost per day increased
$835 per day in the first quarter of 2005 when compared with the first quarter
of 2004. Approximately $609 of that increase was from costs directly associated
36
with the drilling of wells with increases in labor cost the primary cause of the
increase. Indirect drilling costs made up most of the remainder of the increase
in per day costs and consisted primarily of property taxes, safety related
expenses, repairs and the implementation of a central hiring system for our
Oklahoma drilling rigs. We expect the demand for drilling rigs to remain high
throughout 2005 and this demand will increase our drilling rig expenses. We did
not drill any turnkey or footage wells in 2004 or in the first quarter of 2005.
Contract drilling depreciation increased $2.1 million or 29%. The acquisition of
the 14 drilling rigs placed in service since the first quarter of 2004 increased
depreciation $1.1 million or 14% with the remainder of the increase attributable
to the increase in utilization of previously owned drilling rigs.
In July 2004, we consolidated and increased our natural gas gathering and
processing business when we completed the acquisition of the 60% of Superior we
did not already own. Before July 2004, we had developed 18 gathering systems
which we have now consolidated with Superior's operations. Superior is a
mid-stream company engaged primarily in the purchasing, gathering, processing
and treating of natural gas and operates one natural gas treatment plant and
owns three processing plants, 32 active gathering systems and 440 miles of
pipeline. Superior operates in Oklahoma, Texas and Louisiana.
Before the Superior acquisition, our 40% interest in the income or loss
from the operations of Superior was shown as equity in earnings of
unconsolidated investments and was $280,000 net of income tax in the first
quarter of 2004. The results of operations for Superior are included in the
statement of income for the period after July 31, 2004 and intercompany revenue
from services and purchases of production between business segments has been
eliminated. Our natural gas gathering and processing revenues, operating
expenses and depreciation were $18.2 million, $16.8 million and $0.6 million
higher in the first quarter of 2005 versus 2004, respectively, all due to the
Superior acquisition.
General and administrative expense increased $1.2 million or 43%. Personnel
costs increased $1.0 million with $0.7 million of the personnel cost increase
coming from the recognition of a liability associated with the retirement of Mr.
John Nikkel from his position as Chief Executive Officer.
Total interest expense increased $0.3 million or 65%. Average debt
outstanding was higher in the first quarter of 2005 as compared to the first
quarter of 2004 due to the PetroCorp, Superior, Sauer and Strata acquisitions in
2004 and 2005. The increase in average debt outstanding accounted for
approximately 64% of the interest expense increase with the remaining 36% coming
from an increase in average interest rates. In association with our development
of oil and natural gas properties and the construction of new drilling rigs and
natural gas gathering systems, we capitalized $311,000 of interest in the first
quarter of 2005. No interest was capitalized in 2004.
37
Income tax expense increased $9.3 million or 98% due to the increase in
income before income taxes. Our effective tax rate for the first quarter of 2005
was 38.0% versus 38.1% in the first quarter of 2004.
Other revenues decreased $0.6 million. Other revenues include $0.7 million
loss from the write-off of the net book value associated with equipment lost in
the collapse of rig number 306's derrick on March 10, 2005. The rig was repaired
and resumed drilling operations in the early part of April.
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.
Commodity Price Risk. Our major market risk exposure is in the price we
receive for our oil and natural gas production. The price we receive is
primarily driven by the prevailing worldwide price for crude oil and market
prices applicable to our natural gas production. Historically, the prices we
received for our oil and natural gas production have fluctuated and we expect
these prices to continue to fluctuate. The price of oil and natural gas also
affects both the demand for our drilling rigs and the amount we can charge for
the use of our drilling rigs. Based on our first quarter 2005 production, a $.10
per Mcf change in what we are paid for our natural gas production would result
in a corresponding $239,000 per month ($2.9 million annualized) change in our
pre-tax cash flow. A $1.00 per barrel change in our oil price would have a
$86,800 per month ($1.0 million annualized) change in our pre-tax operating cash
flow.
In an effort to try and reduce the impact of price fluctuations, over the
past several years we have periodically used hedging strategies to hedge the
price 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 Operation included above.
Interest Rate Risk. Our interest rate exposure relates to our long-term
debt, all of which bears interest at variable rates based on the JPMorgan Chase
Prime Rate or the LIBOR Rate. At our election, borrowings under our revolving
credit facility may be fixed at the LIBOR Rate for periods of up to 180 days.
Historically, we have not used any financial instruments, such as interest rate
swaps, to manage our exposure to possible increases in interest rates. However,
in February 2005, we entered into an interest rate swap for $50.0 million of our
outstanding debt to help manage our exposure to any future interest rate
volatility. A detailed explanation of this transaction has been included under
hedging in the financial condition portion of Management's Discussion and
Analysis of Financial Condition and Results of Operation included above. Based
on our average outstanding long-term debt subject to the floating rate in the
first quarter of 2005, a 1% change in the floating rate would reduce our annual
pre-tax cash flow by approximately $441,000.
38
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 ensuring the appropriate
information is recorded, processed, summarized and reported 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.
39
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
40
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.
41
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 3, 2005 By: /s/ Larry D. Pinkston
--------------------------- ------------------------------
LARRY D. PINKSTON
Chief Executive Officer
and Director
Date: May 3, 2005 By: /s/ David T. Merrill
--------------------------- ------------------------------
DAVID T. MERRILL
Chief Financial Officer and
Treasurer
42