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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2003
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 0-22664
PATTERSON-UTI ENERGY, INC.
(Exact name of registrant as specified in its charter)
DELAWARE
(State or other jurisdiction of 75-2504748
incorporation or organization) (I.R.S. Employer Identification No.)
P. O. BOX 1416, 4510 LAMESA HIGHWAY, SNYDER, TEXAS, 79550
(Address of principal executive offices) (Zip Code)
(325) 574-6300
(Registrant's telephone number, including area code)
N/A
(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. 80,922,396 shares of common
stock, $0.01 par value, as of November 13, 2003
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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
PAGE
----
PART I - Financial Information
ITEM 1. Financial Statements
Unaudited condensed consolidated balance sheets....................................................... 3
Unaudited condensed consolidated statements of income................................................. 4
Unaudited condensed consolidated statement of changes in stockholders' equity......................... 5
Unaudited condensed consolidated statements of changes in cash flows.................................. 6
Notes to unaudited condensed consolidated financial statements........................................ 7
ITEM 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations................................................................................. 14
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk............................................ 21
ITEM 4. Controls and Procedures............................................................................... 22
Forward Looking Statements and Cautionary Statements for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform Act of 1995............................................. 23
PART II - Other Information
ITEM 6. Exhibits and Reports on Form 8-K...................................................................... 24
Signatures........................................................................................................... 25
2
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
THE FOLLOWING UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
INCLUDE ALL ADJUSTMENTS WHICH, IN THE OPINION OF MANAGEMENT, ARE
NECESSARY IN ORDER TO MAKE SUCH FINANCIAL STATEMENTS NOT MISLEADING.
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in thousands, except share data)
SEPTEMBER 30, DECEMBER 31,
2003 2002
------------- -------------
ASSETS
Current assets:
Cash and cash equivalents ............................................................ $ 111,317 $ 82,154
Accounts receivable, net of allowance for doubtful accounts of $2,632 at
September 30, 2003 and $3,144 at December 31, 2002 ................................ 141,066 99,014
Federal and state income taxes receivable, net ....................................... -- 24,719
Inventory ............................................................................ 15,989 15,323
Deferred tax assets .................................................................. 19,350 15,290
Other ................................................................................ 5,418 6,515
------------- -------------
Total current assets ............................................................ 293,140 243,015
Property and equipment, at cost, net ..................................................... 675,625 627,734
Goodwill and other intangible assets, net ................................................ 51,203 51,313
Investment in equity securities .......................................................... 18,371 17,707
Other .................................................................................... 2,508 2,740
------------- -------------
Total assets .................................................................... $ 1,040,847 $ 942,509
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade ............................................................................ $ 40,008 $ 30,618
Accrued revenue distributions .................................................... 8,897 6,266
Other ............................................................................ 2,812 2,755
Federal and state income taxes payable, net .......................................... 6,796 --
Accrued expenses ..................................................................... 52,565 35,513
------------- -------------
Total current liabilities ....................................................... 111,078 75,152
Deferred tax liabilities ................................................................. 130,839 127,006
Other .................................................................................... 3,775 2,795
------------- -------------
Total liabilities ............................................................... 245,692 204,953
------------- -------------
Commitments and contingencies ............................................................ -- --
Stockholders' equity:
Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued ....... -- --
Common stock, par value $.01; authorized 200,000,000 shares with 82,419,918
and 81,576,674 issued and 80,913,370 and 80,070,126 outstanding at
September 30, 2003 and December 31, 2002, respectively .......................... 824 816
Additional paid-in capital ........................................................... 504,776 489,201
Retained earnings .................................................................... 295,924 261,003
Accumulated other comprehensive income (loss) ........................................ 5,286 (1,809)
Treasury stock, at cost, 1,506,548 shares ............................................ (11,655) (11,655)
------------- -------------
Total stockholders' equity ...................................................... 795,155 737,556
------------- -------------
Total liabilities and stockholders' equity ...................................... $ 1,040,847 $ 942,509
============= =============
The accompanying notes are an integral part of these unaudited condensed
consolidated financial statements.
3
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(in thousands, except per share amounts)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------- ----------------------
2003 2002 2003 2002
--------- --------- --------- ---------
Operating revenues:
Drilling ............................................. $ 169,077 $ 100,267 $ 468,609 $ 300,668
Drilling and completion fluids ....................... 19,580 19,714 51,431 52,049
Pressure pumping ..................................... 13,198 9,649 31,509 23,691
Oil and natural gas .................................. 5,160 3,865 16,329 10,673
--------- --------- --------- ---------
207,015 133,495 567,878 387,081
--------- --------- --------- ---------
Operating costs and expenses:
Drilling ............................................. 123,156 80,374 353,893 232,129
Drilling and completion fluids ....................... 17,180 16,393 45,483 44,965
Pressure pumping ..................................... 7,226 5,618 18,032 14,127
Oil and natural gas .................................. 1,138 989 3,509 2,985
Depreciation, depletion and amortization ............. 24,716 23,178 73,825 68,470
General and administrative ........................... 6,853 6,186 20,560 19,139
Bad debt expense ..................................... 97 165 259 195
Restructuring and other charges ...................... -- -- (2,452) 4,700
Other (income) expense ............................... (705) (91) (1,582) (149)
--------- --------- --------- ---------
179,661 132,812 511,527 386,561
--------- --------- --------- ---------
Operating income ......................................... 27,354 683 56,351 520
--------- --------- --------- ---------
Other income (expense):
Interest income ...................................... 263 261 808 754
Interest expense ..................................... (68) (93) (216) (298)
Other ................................................ 52 (135) 137 (110)
--------- --------- --------- ---------
247 33 729 346
--------- --------- --------- ---------
Income before income taxes and cumulative
effect of change in accounting principle ............. 27,601 716 57,080 866
--------- --------- --------- ---------
Income tax expense (benefit):
Current .............................................. 8,610 (9,868) 22,372 (21,219)
Deferred ............................................. 1,878 10,335 (682) 21,746
--------- --------- --------- ---------
10,488 467 21,690 527
--------- --------- --------- ---------
Income before cumulative effect of change in
accounting principle ................................. 17,113 249 35,390 339
Cumulative effect of change in accounting
principle, net of related income tax benefit of
approximately $287 ................................... -- -- (469) --
--------- --------- --------- ---------
Net income ............................................... $ 17,113 $ 249 $ 34,921 $ 339
========= ========= ========= =========
Net income per common share:
Basic:
Income before cumulative effect of
change in accounting principle ............... $ 0.21 $ 0.00 $ 0.44 $ 0.00
Cumulative effect of change in accounting
principle .................................... -- -- (0.01) --
--------- --------- --------- ---------
Net income ....................................... $ 0.21 $ 0.00 $ 0.43 $ 0.00
========= ========= ========= =========
Diluted:
Income before cumulative effect of
change in accounting principle ............... $ 0.21 $ 0.00 $ 0.43 $ 0.00
Cumulative effect of change in accounting
principle .................................... -- -- -- --
--------- --------- --------- ---------
Net income ....................................... $ 0.21 $ 0.00 $ 0.43 $ 0.00
========= ========= ========= =========
Weighted average number of common shares outstanding:
Basic ................................................ 80,904 78,964 80,535 78,378
========= ========= ========= =========
Diluted .............................................. 82,191 80,963 82,261 80,782
========= ========= ========= =========
The accompanying notes are an integral part of these unaudited condensed
consolidated financial statements.
4
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(UNAUDITED)
(in thousands)
Common Stock Accumulated
--------------------- Additional other
Number of paid-in Retained comprehensive Treasury
shares Amount capital earnings income (loss) stock Total
--------- -------- ---------- -------- ------------- -------- --------
Balance, December 31, 2002 .......... 81,577 $ 816 $489,201 $261,003 $ (1,809) $(11,655) $737,556
Exercise of stock options and
warrants ........................ 843 8 9,583 -- -- -- 9,591
Tax benefit related to exercise of
stock options ................... -- -- 5,992 -- -- -- 5,992
Foreign currency translation
adjustment ...................... -- -- -- -- 6,693 -- 6,693
Change in unrealized gain on
equity securities, net of tax ... -- -- -- -- 402 -- 402
Net income .......................... -- -- -- 34,921 -- -- 34,921
-------- -------- -------- -------- -------- -------- --------
Balance, September 30, 2003 ......... 82,420 $ 824 $504,776 $295,924 $ 5,286 $(11,655) $795,155
======== ======== ======== ======== ======== ======== ========
The accompanying notes are an integral part of these unaudited condensed
consolidated financial statements.
5
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS (UNAUDITED)
(in thousands)
NINE MONTHS ENDED
SEPTEMBER 30,
-----------------------
2003 2002
--------- --------
Cash flows from operating activities:
Net income ................................................................................ $ 34,921 $ 339
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization .......................................... 73,825 68,470
Provision for bad debts ........................................................... 259 195
Deferred income tax expense (benefit) ............................................. (682) 21,746
Tax benefit related to exercise of stock options .................................. 5,992 4,767
Other ............................................................................. (1,582) (145)
Changes in operating assets and liabilities:
Accounts receivable ........................................................... (41,189) 41,300
Federal and state income taxes receivable ..................................... 24,719 (27,423)
Inventory and other current assets ............................................ 470 1,456
Accounts payable .............................................................. 11,728 (15,642)
Federal and state income taxes payable ........................................ 6,687 --
Accrued expenses .............................................................. 16,894 (1,143)
Other liabilities ............................................................. 1,037 66
--------- --------
Net cash provided by operating activities ................................. 133,079 93,986
--------- --------
Cash flows from investing activities:
Acquisitions .............................................................................. (32,837) --
Purchases of property and equipment ....................................................... (84,463) (62,435)
Proceeds from sales of property and equipment ............................................. 3,178 824
Purchase of investment equity securities .................................................. -- (12,698)
Change in other assets .................................................................... 213 1,845
--------- --------
Net cash used in investing activities ..................................... (113,909) (72,464)
--------- --------
Cash flows from financing activities:
Proceeds from exercise of stock options and warrants ...................................... 9,591 8,611
--------- --------
Net cash provided by financing activities ................................. 9,591 8,611
--------- --------
Net increase in cash and cash equivalents ................................. 28,761 30,133
Foreign currency translation adjustment ................................... 402 (99)
Cash and cash equivalents at beginning of period .............................................. 82,154 33,584
--------- --------
Cash and cash equivalents at end of period .................................................... $ 111,317 $ 63,618
========= ========
Supplemental disclosure of cash flow information:
Net cash received (paid) during the period for:
Interest .............................................................................. $ (216) $ (298)
Income taxes .......................................................................... $ 14,622 $ (294)
The accompanying notes are an integral part of these unaudited condensed
consolidated financial statements.
6
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF CONSOLIDATION AND PRESENTATION
The interim condensed consolidated financial statements include the
accounts of Patterson-UTI Energy, Inc. (the "Company") and its wholly-owned
subsidiaries. All significant intercompany accounts and transactions have been
eliminated.
The interim condensed consolidated financial statements have been prepared
by management of the Company, without audit, pursuant to the rules and
regulations of the Securities and Exchange Commission. Certain information and
footnote disclosures normally included in financial statements prepared in
accordance with generally accepted accounting principles have been omitted
pursuant to such rules and regulations, although the Company believes the
disclosures included herein are adequate to make the information presented not
misleading. In the opinion of management, all adjustments (consisting of only
normal recurring accruals) considered necessary for presentation of the
information have been included. The unaudited condensed consolidated balance
sheet as of December 31, 2002, as presented herein, was derived from the audited
balance sheet of the Company. These unaudited condensed consolidated financial
statements should be read in conjunction with the consolidated financial
statements and related notes included in the annual report on Form 10-K for the
year ended December 31, 2002.
The U.S. dollar is the functional currency for all of the Company's
operations except for its Canadian operations, which use the Canadian dollar as
functional currency. The effects of exchange rate changes are reflected in
accumulated other comprehensive income (loss), which is a separate component of
stockholders' equity (see Note 4 of these Notes to Unaudited Condensed
Consolidated Financial Statements).
In accordance with Statement of Financial Accounting Standards No. 115,
"Accounting for Certain Investments in Debt and Equity Securities" ("SFAS No.
115"), investments in Available-for-Sale equity securities are recorded at fair
value. Unrealized gains and losses of such investments, net of tax, are included
in accumulated other comprehensive income (loss) in our consolidated balance
sheets as of September 30, 2003 and December 31, 2002, and are shown as a
separate component of stockholders' equity (see Note 4 of these Notes to
Unaudited Condensed Consolidated Financial Statements).
The Company provides a dual presentation of its earnings per share in its
Consolidated Statements of Income: Basic Earnings per Share ("Basic EPS") and
Diluted Earnings per Share ("Diluted EPS"). Basic EPS is computed using the
weighted average number of shares outstanding during the periods presented.
Diluted EPS includes common stock equivalents, generally stock options and
warrants that are "in the money", which are dilutive to earnings per share. For
the three months ended September 30, 2003 and 2002, dilutive securities included
in the calculation of Diluted EPS were 1.3 million shares and 2.0 million
shares, respectively. For the nine months ended September 30, 2003 and 2002,
dilutive securities included in the calculation of Diluted EPS were 1.7 million
shares and 2.4 million shares, respectively. For the three month periods ended
September 30, 2003 and 2002, there were 1.2 million and 2.3 million,
respectively, potentially dilutive options and warrants which were excluded from
the calculation of Diluted EPS as their exercise price was greater than the
average market price for the period. For the nine month periods ended September
30, 2003 and 2002, there were 885,000 and 2.2 million, respectively, potentially
dilutive options and warrants which were excluded from the calculation of
Diluted EPS as their exercise price was greater than the average market price
for the period.
The results of operations for the three and nine months ended September
30, 2003 are not necessarily indicative of the results to be expected for the
full year.
Certain reclassifications have been made to the 2002 consolidated
financial statements in order for them to conform with the 2003 presentation.
7
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-
CONTINUED
2. RECENT ACQUISITIONS
In January 2003, the Company acquired four land-based drilling rigs and
related equipment from SEI Drilling Company for $6.0 million in cash. The
transaction was accounted for as an acquisition of assets and the purchase price
was allocated among the assets acquired based on their estimated fair market
values.
In February 2003, the Company acquired three land-based drilling rigs, a
yard, and other related equipment from Mesa Drilling, Inc. and related entities
for $10.5 million in cash. The transaction was accounted for as an acquisition
of assets and the purchase price was allocated among the assets acquired based
on their estimated fair market values.
In April 2003, the Company acquired two land-based drilling rigs for $3.9
million in cash. The transaction was accounted for as an acquisition of assets
and the purchase price was allocated among the assets acquired based on their
estimated fair market values.
In May 2003, the Company completed the acquisition of seven land-based
drilling rigs and related equipment from Hexadyne Drilling Corporation for $10.1
million in cash. The transaction was accounted for as an acquisition of assets
and the purchase price was allocated among the assets acquired based on their
estimated fair market values.
On May 26, 2003, the Company, Patterson-UTI Acquisition, LLC, a Texas
limited liability company and wholly-owned subsidiary of the Company ("Sub"),
and TMBR/Sharp Drilling, Inc., a Texas corporation ("TMBR"), entered into an
Agreement and Plan of Merger (the "Merger Agreement") pursuant to which, upon
the satisfaction and completion of the conditions to the merger contained in the
Merger Agreement, including approval of the Merger Agreement by at least
two-thirds of the shareholders of TMBR, TMBR will merge with and into Sub with
Sub being the surviving company. If the merger is completed, each issued and
outstanding share of common stock, $.10 par value per share, of TMBR not owned
directly or indirectly by the Company or TMBR or held by TMBR shareholders who
validly exercise their dissenters' rights under Texas law, will be converted
into the right to receive $9.09 in cash from the Company and 0.312166 of a share
of common stock, $0.01 par value per share, of the Company (the "Company Common
Stock"), for a total of approximately $40.4 million in cash and approximately
1.39 million shares of Company Common Stock based on the outstanding shares of
TMBR common stock as of September 30, 2003. The Company currently intends to pay
the cash portion of the merger consideration to TMBR shareholders out of funds
available on hand and existing financing facilities.
In addition to the above mentioned acquisitions, the Company spent
approximately $2.3 million on other acquisitions of assets and costs associated
with the acquisitions completed during the nine months ended September 30, 2003.
3. STOCK-BASED COMPENSATION
At September 30, 2003, the Company had seven stock-based employee
compensation plans, of which three were active. The Company accounts for those
plans under the recognition and measurement principles of APB Opinion No. 25,
"Accounting for Stock Issued to Employees," and related Interpretations. No
stock-based employee compensation cost is reflected in net income, as all
options granted under those plans had an exercise price equal to the market
value of the underlying common stock on the date of grant. The following table
illustrates the effect on net income and net income 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 (in thousands, except per share amounts):
8
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-
CONTINUED
3. STOCK-BASED COMPENSATION - (CONTINUED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------- --------- -------------
2003 2002 2003 2002
-------- -------- -------- ---------
Net income, as reported .................................. $ 17,113 $ 249 $ 34,921 $ 339
Deduct: Total stock-based employee compensation
expense determined under fair value based
method for all awards, net of related tax effects .... (2,732) (1,376) (7,692) (4,279)
-------- -------- -------- ---------
Pro forma net income (loss) .............................. $ 14,381 $ (1,127) $ 27,229 $ (3,940)
======== ======== ======== =========
Net income (loss) per common share:
Basic, as reported ................................... $ 0.21 $ 0.00 $ 0.43 $ 0.00
======== ======== ======== =========
Basic, pro forma ..................................... $ 0.18 $ (0.01) $ 0.34 $ (0.05)
======== ======== ======== =========
Diluted, as reported ................................. $ 0.21 $ 0.00 $ 0.43 $ 0.00
======== ======== ======== =========
Diluted, pro forma ................................... $ 0.17 $ (0.01) $ 0.33 $ (0.05)
======== ======== ======== =========
4. COMPREHENSIVE INCOME (LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The following table illustrates the Company's comprehensive income (loss)
including the effects of foreign currency translation adjustments for the three
and nine months ended September 30, 2003 and 2002 (in thousands):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------- -----------------
2003 2002 2003 2002
-------- ------- ------- -----
Net income .................................................. $ 17,113 $ 249 $34,921 $ 339
Other comprehensive income (loss):
Foreign currency translation adjustment related to
our Canadian operations ............................. (378) (1,717) 6,693 362
Change in unrealized gain on equity securities, net of
tax ................................................. (813) (292) 402 (292)
-------- ------- ------- -----
Comprehensive income (loss) ................................. $ 15,922 $(1,760) $42,016 $ 409
======== ======= ======= =====
5. SETTLEMENT OF MEXICO RECEIVABLE
In March 2003, the Company received approximately $2.5 million in cash as
settlement for contract drilling services previously provided in Mexico by
Norton Drilling Company Mexico, Inc., a wholly-owned subsidiary of the Company.
The Company had been party to a lawsuit for a number of years in an effort to
collect the underlying receivable. As the collectibility of the receivable was
not certain, a reserve for the full amount of the receivable was recorded at the
time of the Company's acquisition of Norton Drilling Company Mexico, Inc. in
1999. The amount is reflected as a reduction of other expenses and included as a
component of operating income.
9
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-
CONTINUED
6. BUSINESS SEGMENTS
Our revenues, operating profits and identifiable assets are primarily
attributable to four industry segments: contract drilling of oil and natural gas
wells, drilling and completion fluid services and pressure pumping services to
operators in the oil and natural gas industry, and the exploration, development,
acquisition and production of oil and natural gas. Each of these segments
represents a distinct type of business based upon the type and nature of
services and products offered. These segments have separate management teams
which report to the Company's chief executive officer and have distinct and
identifiable revenues and expenses. Separate financial data for each of our four
business segments is provided below (in thousands).
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ ------------------------
2003 2002 2003 2002
--------- --------- --------- ---------
Operating revenues:
Drilling ..................................... $ 169,077 $ 100,267 $ 468,609 $ 300,668
Drilling and completion fluids ............... 19,580 19,714 51,431 52,049
Pressure pumping ............................. 13,198 9,649 31,509 23,691
Oil and natural gas .......................... 5,160 3,865 16,329 10,673
--------- --------- --------- ---------
Total operating revenues ......................... $ 207,015 $ 133,495 $ 567,878 $ 387,081
========= ========= ========= =========
Income (loss) before income taxes:
Drilling ..................................... $ 23,879 $ (1,031) $ 48,962 $ 5,376
Drilling and completion fluids ............... (45) 982 (1,202) 163
Pressure pumping ............................. 3,583 2,376 6,665 4,470
Oil and natural gas .......................... 1,580 750 5,066 2,099
--------- --------- --------- ---------
28,997 3,077 59,491 12,108
Corporate and other ........................ (1,643) (2,394) (5,592) (6,888)
Restructuring and other charges(a).......... -- -- 2,452 (4,700)
Interest income ............................ 263 261 808 754
Interest expense ........................... (68) (93) (216) (298)
Other ...................................... 52 (135) 137 (110)
--------- --------- --------- ---------
Income before income taxes and
cumulative effect of change in accounting
principle .................................... $ 27,601 $ 716 $ 57,080 $ 866
========= ========= ========= =========
SEPTEMBER 30, DECEMBER 31,
2003 2002
------------ ------------
Identifiable assets:
Drilling ......................................................... $ 772,046 $ 694,020
Drilling and completion fluids ................................... 33,453 34,687
Pressure pumping ................................................. 42,511 35,084
Oil and natural gas .............................................. 29,824 20,854
Corporate and other (b) .......................................... 163,013 157,864
------------ ------------
$ 1,040,847 $ 942,509
============ ============
- --------------
(a) Restructuring and other charges relate to decisions of the executive
management group regarding corporate strategy, credit risk, loss
contingencies and restructuring activities. Due to the non-operating
nature of these decisions, the related charges have been separately
presented and excluded from the results of specific segments. These
charges primarily related to the contract drilling segment.
(b) Corporate assets primarily consists of cash and cash equivalents,
current and deferred federal and state income tax assets and investment
in equity securities.
7. RECENTLY ISSUED ACCOUNTING STANDARDS
The Financial Accounting Standards Board ("FASB") issued Statement of
Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations" ("SFAS No. 143"), in June 2001. SFAS No. 143 addresses financial
accounting requirements for retirement obligations associated with tangible
long-lived assets. The Company adopted SFAS No. 143 in January 2003. As a
result, a charge of $469,000 (net of tax) was recorded as a
10
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-
CONTINUED
7. RECENTLY ISSUED ACCOUNTING STANDARDS - (CONTINUED)
cumulative effect of a change in accounting principle for the quarter ended
March 31, 2003. The change relates to the cost associated with the future
abandonment of oil and natural gas properties. The related effect to basic and
diluted earnings per share as a result of the change in accounting principle was
a decrease of $0.01 per share and $0.00 per share, respectively, for the nine
months ended September 30, 2003.
The FASB issued Statement of Financial Accounting Standards No. 148,
"Accounting for Stock-Based Compensation" ("SFAS No. 148"), in December 2002.
SFAS No. 148 amends the disclosure requirements of Statement of Financial
Accounting Standards No. 123 to require prominent disclosures in both annual and
interim financial statements about the method of accounting for stock-based
employee compensation and the effect of the method used on reported results. The
provisions of SFAS No. 148, which the Company adopted on January 1, 2003, did
not have a material impact on the Company's consolidated financial statements
(see Note 3 of these Notes to Unaudited Condensed Consolidated Financial
Statements).
The FASB issued Statement of Financial Accounting Standards No. 149,
"Amendment of Statement 133 on Derivative Instruments and Hedging Activities"
("SFAS No. 149"), in April 2003. SFAS No. 149 amends and clarifies financial
accounting and reporting for derivative instruments, including certain
derivative instruments embedded in other contracts and for hedging activities
under Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 149 is effective for
existing contracts and new contracts entered into after June 30, 2003. The
provisions of SFAS No. 149, which the Company adopted on July 1, 2003, did not
have a material impact on the Company's consolidated financial statements.
The FASB issued Statement of Financial Accounting Standards No. 150,
"Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity" ("SFAS No. 150"), in May 2003. SFAS No. 150 establishes
standards for how an issuer classifies and measures certain financial
instruments with characteristics of both liabilities and equity. SFAS No. 150 is
effective for financial instruments entered into or modified after May 31, 2003.
The provisions of SFAS No. 150, which the Company adopted on June 1, 2003, did
not have a material impact on the Company's consolidated financial statements.
The FASB issued Interpretation No. 45, "Guarantor's Accounting and
Disclosure Requirements, Including Guarantees of Indebtedness of Others" ("FIN
45"), which the Company adopted effective January 1, 2003. FIN 45 requires that
upon issuance of certain types of guarantees, a guarantor recognize and account
for the fair value of the guarantee as a liability. FIN 45 contains exclusions
to this requirement, including the exclusion of a parent's guarantee of its
subsidiaries' debt to a third party. The adoption of FIN 45 had no material
impact on the Company's consolidated financial position, results of operations
or cash flows.
The FASB issued Interpretation No. 46, "Consolidation of Variable Interest
Entities" ("FIN 46") which addresses the consolidation of variable interest
entities ("VIEs") by business enterprises that are the primary beneficiaries. A
VIE is an entity that does not have sufficient equity investment at risk to
permit it to finance its activities without additional subordinated financial
support, or whose equity investors lack the characteristics of a controlling
financial interest. The primary beneficiary of a VIE is the enterprise that has
the majority of the risks or rewards associated with the VIE. The Company
believes it has no material interests in VIEs that will require disclosure or
consolidation under FIN 46.
11
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-
CONTINUED
8. GOODWILL AND OTHER INTANGIBLE ASSETS
Intangible assets consist primarily of goodwill and covenants-not-to-compete
arising from business combinations. In accordance with Statement of Financial
Accounting Standards No. 142, "Goodwill and Other Intangible Assets," all of our
intangible assets that have definite lives are being amortized on a
straight-line basis over their estimated useful lives and goodwill is evaluated
to determine if fair value of the asset has decreased below its carrying value.
At December 31, 2002, we performed the annual goodwill evaluation and determined
no adjustment to impair goodwill was necessary. Goodwill and other intangible
assets as of September 30, 2003 and December 31, 2002 are as follows (in
thousands):
SEPTEMBER 30, DECEMBER 31,
2003 2002
------------- ------------
Goodwill ............................... $ 69,860 $ 69,860
Accumulated amortization ............... (19,661) (19,661)
-------- --------
Goodwill, net .......................... 50,199 50,199
-------- --------
Covenants-not-to-compete and other ..... 1,956 1,956
Accumulated amortization ............... (952) (842)
-------- --------
Other intangible assets, net ........... 1,004 1,114
-------- --------
Intangible assets, net ................. $ 51,203 $ 51,313
======== ========
The amount of goodwill and other intangible assets as of September 30, 2003
and December 31, 2002 assigned to the contract drilling and drilling and
completion fluids operating segments, the only operating segments that had
intangible assets for such periods, is as follows (in thousands):
September 30, 2003
Contract Drilling:
Goodwill ................................... $56,543 Accumulated Amortization ............... $16,278
Non-Competes & Other ....................... $ 1,909 Accumulated Amortization ............... $ 937
Drilling and Completion Fluids:
Goodwill ................................... $13,317 Accumulated Amortization ............... $ 3,383
Non-Competes & Other ....................... $ 47 Accumulated Amortization ............... $ 15
December 31, 2002
Contract Drilling:
Goodwill ................................... $56,543 Accumulated Amortization ............... $16,278
Non-Competes & Other ....................... $ 1,909 Accumulated Amortization ............... $ 828
Drilling and Completion Fluids:
Goodwill ................................... $13,317 Accumulated Amortization ............... $ 3,383
Non-Competes & Other ....................... $ 47 Accumulated Amortization ............... $ 14
Change in the net carrying amount of goodwill for the nine months ended
September 30, 2003 is as follows (in thousands):
DRILLING &
COMPLETION
DRILLING FLUIDS TOTAL
--------- ---------- ---------
Balance at December 31, 2002 ...... $ 40,265 $ 9,934 $ 50,199
Changes to goodwill ............... -- -- --
--------- --------- ---------
Balance at September 30, 2003 ..... $ 40,265 $ 9,934 $ 50,199
========= ========= =========
12
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-
CONTINUED
8. GOODWILL AND OTHER INTANGIBLE ASSETS - (CONTINUED)
Amortization expense for the three and nine months ended September 30,
2003 and 2002 consists of the following (in thousands):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------- -------------------
2003 2002 2003 2002
------- ------- ------- -------
Goodwill ............................... $ -- $ -- $ -- $ --
Covenants-not-to-compete and other ..... 24 47 110 272
------- ------- ------- -------
$ 24 $ 47 $ 110 $ 272
======= ======= ======= =======
Our weighted average amortization period for other intangible assets is
approximately 13 years. The following table shows the estimated amortization
expense for these assets for each of the five succeeding fiscal years (in
thousands):
2004....................... $ 97
2005....................... $ 97
2006....................... $ 97
2007....................... $ 97
2008....................... $ 97
9. INVESTMENT IN EQUITY SECURITIES
In 2002, the Company purchased 1,058,673 shares of the common stock of
TMBR, $.10 par value per share, for an aggregate cash purchase price of $17.6
million, or $16.60 per share, and approximately $84,000 of additional costs
incurred to acquire the shares. The Company owns approximately 19.2% of the
outstanding shares of TMBR based on its shares outstanding as of September 30,
2003.
The accounting treatment of shares representing the Company's investment
in the common stock of TMBR is affected by the Company's ability to sell shares
within one year. As of September 30, 2003, the Company has restrictions on its
ability to sell 77,300 of the TMBR shares within one year. These shares are
reflected in the balance sheet at cost under the cost method of accounting in
accordance with Accounting Principles Board Opinion No. 18, "The Equity Method
of Accounting for Investment in Common Stock". The remaining 981,373 TMBR shares
are not restricted from sale within one year. These shares are classified as
Available-for-Sale and are reflected in the balance sheet at fair value in
accordance with SFAS No. 115. Fair value is determined from publicly quoted
market prices as of the balance sheet date. In accordance with SFAS No. 115,
unrealized gains and losses recorded as a result of the adjustment to fair value
are reflected directly in stockholders' equity.
The following table summarizes the Company's unrealized gain on its
investment in equity securities as of September 30, 2003 (in thousands, except
share amounts):
COMMON UNREALIZED
SHARES COST GAIN TOTAL
---------- ------- ---------- -------
TMBR/Sharp Drilling, Inc.:
Cost method ....................... 77,300 $ 1,286 $ -- $ 1,286
Available-for-Sale ................ 981,373 16,395 690 17,085
---------- ------- ------- -------
1,058,673 $17,681 $ 690 $18,371
========== ======= ======= =======
13
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-
CONTINUED
9. INVESTMENT IN EQUITY SECURITIES - (CONTINUED)
On May 26, 2003, the Company entered into a merger agreement with TMBR
pursuant to which, assuming the transaction is consummated, TMBR will merge with
and into a wholly-owned subsidiary of the Company (see Note 2 of these Notes to
Unaudited Condensed Consolidated Financial Statements).
10. LEGAL MATTERS
Westfort Energy LTD and Westfort Energy (US) LTD f/k/a Canadian Delta,
Inc. ("Westfort"), filed a lawsuit against two of the Company's subsidiaries,
Patterson Petroleum LP and Patterson Drilling Company LP, in the Circuit Court,
Rankin County, Mississippi, Case No. 2002-18. The lawsuit relates to a letter
agreement entered into in July 2000 between Patterson Petroleum LP and Westfort
concerning the drilling of a daywork well in Mississippi. This lawsuit was filed
by Westfort after Patterson Petroleum LP made demand on Westfort for payment of
the contract drilling services.
The Westfort lawsuit has been dismissed without prejudice. Westfort filed
for bankruptcy in May of 2003. The Company continues to assert claims against
Westfort including the monies owed Patterson Petroleum LP under the letter
agreement in the amount of approximately $5,075,000. The Company believes that
it is remote that the outcome of this matter will have a material adverse effect
on the Company's financial condition or results of operations.
In its lawsuit, Westfort alleged breach of contract, fraud, and negligence
causes of action. Westfort sought alleged monetary damages, the return of shares
of Westfort stock, unspecified damages from alleged lost profits, lost use of
income stream, and additional operating expenses, along with alleged punitive
damages to be determined by the jury, but not less than 25% of the Company's net
worth. The Company intends to vigorously contest these claims if reasserted by
Westfort.
We are also party to various legal proceedings arising in the normal
course of our business. We do not believe that the outcome of these proceedings,
either individually or in the aggregate, will have a material adverse effect on
our financial condition.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
CRITICAL ACCOUNTING POLICIES
In addition to established accounting policies, our consolidated
financial statements are impacted by certain estimates and assumptions made by
management. The following is a discussion of our critical accounting policies
pertaining to property and equipment, oil and natural gas properties,
impairment, revenue recognition, and the use of estimates.
Property and equipment -- Property and equipment, including betterments
which extend the useful life of the asset, are stated at cost. Maintenance and
repairs are charged to expense when incurred. We provide for the depreciation of
our property and equipment using the straight-line method over the estimated
useful lives. Our method of depreciation does not change when equipment becomes
idle; we continue to depreciate idled equipment on a straight-line basis. No
provision for salvage value is considered in determining depreciation of our
property and equipment. We review our assets, including intangible assets, for
impairment when events or changes in circumstances indicate that the carrying
values of certain assets either exceed their respective fair values or may not
be recovered over their estimated remaining useful lives. The cyclical nature of
our industry has resulted in fluctuations in rig utilization over periods of
time. Management believes that the contract drilling industry will continue to
be cyclical and rig utilization will fluctuate. Based on management's
expectations of future trends we estimate future cash flows in our assessment of
impairment assuming the following four-year industry cycle: one year projected
with low utilization, one year projected as a recovery period with improving
utilization and the remaining two years projecting higher utilization.
Provisions for asset impairment are charged to income when estimated future cash
flows, on an undiscounted basis, are less than the asset's net book value.
Impairment charges
14
are recorded based on discounted cash flows. There were no impairment charges
during the periods ended September 30, 2003 or 2002.
Oil and natural gas properties -- Oil and natural gas properties are
accounted for using the successful efforts method of accounting. Exploration and
development costs, which result directly in the discovery of oil and natural gas
reserves, are capitalized to the appropriate well. Exploration costs which do
not result directly in the discovery of oil and natural gas reserves are charged
to expense when such determinations are made. In accordance with paragraph 31(b)
of SFAS 19, costs of exploratory wells are initially capitalized to wells in
progress until the outcome of the drilling is known. We review wells in progress
quarterly to determine the related reserve classification. If the reserve
classification is uncertain after one year following the completion of drilling,
we consider the costs of the well to be impaired and recognize the costs as
expense. Geological and geophysical costs, including seismic costs and costs to
carry and retain undeveloped properties, are charged to expense when incurred.
Capitalized costs of both developmental and successful exploratory type wells,
consisting of lease and well equipment, lease acquisition costs, and intangible
development costs, are depreciated, depleted, and amortized on the
units-of-production method, based on petroleum engineer estimates of proved oil
and natural gas reserves of each respective field. The Company reviews its
proved oil and natural gas properties for impairment when an event occurs such
as downward revisions in reserve estimates or decreases in oil and natural gas
prices. Proved properties are grouped by field and undiscounted cash flow
estimates are provided by our reserve engineer. If the net book value of a field
exceeds its undiscounted cash flow estimate, impairment expense is measured and
recognized as the difference between its net book value and discounted cash
flow. Unproved oil and natural gas properties are reviewed quarterly to
determine impairment. The Company's intent to drill, lease expiration, and
abandonment of area are considered. Assessment of impairment is made on a
lease-by-lease basis. If an unproved property is determined to be impaired, then
costs related to that property are expensed. Impairment expense is included in
depreciation, depletion and amortization in the accompanying financial
statements.
Revenue recognition -- Revenues are recognized when services are
performed, except for revenues earned under turnkey contract drilling
arrangements which are recognized using the completed contract method of
accounting, as described below. The Company follows the percentage-of-completion
method of accounting for footage contract drilling arrangements. Under this
method, drilling revenues and costs related to a well in progress are recognized
proportionately over the time it takes to drill the well.
Percentage-of-completion is determined based upon the amount of expenses
incurred through the measurement date as compared to total estimated expenses to
be incurred drilling the well. Under the percentage-of-completion method,
management estimates are relied upon in the determination of the total estimated
expenses to be incurred drilling the well. Due to the nature of turnkey contract
drilling arrangements and risks therein, the Company follows the completed
contract method of accounting for such arrangements. Under this method, all
drilling advances and costs (including maintenance and repairs) related to a
well in progress are deferred and recognized as revenues and expenses in the
period the well is completed. Provisions for losses on incomplete or in-process
wells are made when estimated total costs are expected to exceed estimated total
revenues.
In accordance with Emerging Issues Task Force Issue No. 00-14, the
Company recognizes reimbursements received from third parties for out-of-pocket
expenses incurred by the Company as revenues and accounts for out-of-pocket
expenses as direct costs.
Use of estimates -- The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
certain estimates and assumptions. These estimates and assumptions affect the
reported amounts of assets and liabilities, the disclosures of contingent assets
and liabilities at the balance sheet date and the amounts of revenues and
expenses recognized during the reporting period. Actual results could differ
from such estimates.
Key estimates used by management include:
o allowance for doubtful accounts,
o depreciation, depletion, and amortization,
o asset impairment,
15
o reserves for self-insured levels of insurance coverages, and
o fair values of assets and liabilities assumed.
LIQUIDITY AND CAPITAL RESOURCES
As of September 30, 2003, we had working capital of approximately $182.1
million including cash and cash equivalents of $111.3 million. For the nine
months ended September 30, 2003, our significant sources of cash flow were:
o $133.1 million provided by operations,
o $9.6 million from the exercise of stock options and warrants, and
o $3.2 million from the sale of certain property and equipment.
Correspondingly, we used approximately $32.8 million to acquire 16
land-based drilling rigs and other related equipment (see Note 2 of Notes to
Unaudited Condensed Consolidated Financial Statements included as part of Item 1
to this report) and approximately $84.5 million:
o to make capital expenditures for the betterment and refurbishment
of our drilling rigs,
o for the acquisition and procurement of drilling equipment,
o to fund capital expenditures for our drilling and completion
fluids and pressure pumping divisions, and
o to fund leasehold acquisition and exploration and development of
oil and natural gas properties.
In January 2003, the Company acquired four land-based drilling rigs and
related equipment from SEI Drilling Company for $6.0 million in cash. The
transaction was accounted for as an acquisition of assets and the purchase price
was allocated among the assets acquired based on their estimated fair market
values.
In February 2003, the Company acquired three land-based drilling rigs, a
yard, and other related equipment from Mesa Drilling, Inc. and related entities
for $10.5 million in cash. The transaction was accounted for as an acquisition
of assets and the purchase price was allocated among the assets acquired based
on their estimated fair market values.
In April 2003, the Company acquired two land-based drilling rigs for $3.9
million in cash. The transaction was accounted for as an acquisition of assets
and the purchase price was allocated among the assets acquired based on their
estimated fair market values.
In May 2003, the Company completed the acquisition of seven land-based
drilling rigs and related equipment from Hexadyne Drilling Corporation for $10.1
million in cash. The transaction was accounted for as an acquisition of assets
and the purchase price was allocated among the assets acquired based on their
estimated fair market values.
On May 26, 2003, the Company, Patterson-UTI Acquisition, LLC, a Texas
limited liability company and wholly-owned subsidiary of the Company ("Sub"),
and TMBR/Sharp Drilling, Inc., a Texas corporation ("TMBR"), entered into an
Agreement and Plan of Merger (the "Merger Agreement") pursuant to which, upon
the satisfaction and completion of the conditions to the merger contained in the
Merger Agreement, including approval of the Merger Agreement by at least
two-thirds of the shareholders of TMBR, TMBR will merge with and into Sub with
Sub being the surviving company. If the merger is completed, each issued and
outstanding share of common stock, $.10 par value per share, of TMBR not owned
directly or indirectly by the Company or TMBR or held by TMBR shareholders who
validly exercise their dissenters' rights under Texas law, will be converted
into the right to receive $9.09 in cash from the Company and 0.312166 of a share
of common stock, $0.01 par value per share, of the Company (the "Company Common
Stock"), for a total of approximately $40.4 million in cash and approximately
1.39 million shares of Company Common Stock based on the outstanding shares of
TMBR common stock as of September 30, 2003. The Company currently intends to pay
the cash portion of the merger consideration to TMBR shareholders out of funds
available on hand and existing financing facilities.
16
In addition to the above mentioned acquisitions, the Company spent
approximately $2.3 million on other acquisitions of assets and costs associated
with the acquisitions completed during the nine months ended September 30, 2003.
We believe that the current level of cash and short-term investments,
together with cash generated from operations, should be sufficient to meet our
capital needs. From time to time, acquisition opportunities are reviewed. The
timing, size or success of any acquisition and the associated capital
commitments are unpredictable. Over the longer term, should further
opportunities for growth requiring capital arise, we believe we would be able to
satisfy these needs through a combination of working capital, cash generated
from operations, and either debt or equity financing. However, there can be no
assurance that such capital would be available.
COMMITMENTS, CONTINGENCIES AND OTHER MATTERS
The Company maintains letters of credit in the aggregate amount of $31.0
million for the benefit of various insurance companies as collateral for
retrospective premiums and retained losses which could become payable under the
terms of the underlying insurance contracts. These letters of credit expire at
various times during each calendar year. No amounts have been drawn under the
letters of credit.
Westfort Energy LTD and Westfort Energy (US) LTD f/k/a Canadian Delta,
Inc. ("Westfort"), filed a lawsuit against two of the Company's subsidiaries,
Patterson Petroleum LP and Patterson Drilling Company LP, in the Circuit Court,
Rankin County, Mississippi, Case No. 2002-18. The lawsuit relates to a letter
agreement entered into in July 2000 between Patterson Petroleum LP and Westfort
concerning the drilling of a daywork well in Mississippi. This lawsuit was filed
by Westfort after Patterson Petroleum LP made demand on Westfort for payment of
the contract drilling services.
The Westfort lawsuit has been dismissed without prejudice. Westfort filed
for bankruptcy in May of 2003. The Company continues to assert claims against
Westfort including the monies owed Patterson Petroleum LP under the letter
agreement in the amount of approximately $5,075,000. The Company believes that
it is remote that the outcome of this matter will have a material adverse effect
on the Company's financial condition or results of operations.
In its lawsuit, Westfort alleged breach of contract, fraud, and negligence
causes of action. Westfort sought alleged monetary damages, the return of shares
of Westfort stock, unspecified damages from alleged lost profits, lost use of
income stream, and additional operating expenses, along with alleged punitive
damages to be determined by the jury, but not less than 25% of the Company's net
worth. The Company intends to vigorously contest these claims if reasserted by
Westfort.
We are also party to various legal proceedings arising in the normal
course of our business. We do not believe that the outcome of these proceedings,
either individually or in the aggregate, will have a material adverse effect on
our financial condition.
17
RESULTS OF OPERATIONS
The following tables summarize operations by business segment for the three
months ended September 30, 2003 and 2002:
CONTRACT DRILLING 2003 2002 % CHANGE
- ----------------- -------- --------- --------
(DOLLARS IN THOUSANDS)
Revenues ...................................... $169,077 $ 100,267 68.6%
Direct operating costs ........................ $123,156 $ 80,374 53.2%
Selling, general and administrative ........... $ 1,110 $ 918 20.9%
Depreciation and amortization ................. $ 20,932 $ 20,006 4.6%
Operating income (loss) ....................... $ 23,879 $ (1,031) N/A%
Operating days ................................ 17,652 11,656 51.4%
Average revenue per operating day ............. $ 9.58 $ 8.60 11.4%
Average direct operating cost per operating day $ 6.98 $ 6.90 1.2%
Average margin per operating day .............. $ 2.60 $ 1.70 52.9%
Number of owned rigs at end of period ......... 340 324 4.9%
Average number of rigs owned during period .... 340 324 4.9%
Average rigs operating ........................ 192 127 51.2%
Rig utilization percentage .................... 56% 39% 43.6%
Capital expenditures .......................... $ 26,598 $ 10,713 148.3%
Increased operating results in 2003 reflect increased demand for our
contract drilling services primarily in response to higher natural gas prices.
Average natural gas prices increased from $3.20 per Mcf in the third quarter of
2002 to $4.88 per Mcf in the third quarter of 2003. Our rig count increased from
127 average rigs operating during the third quarter of 2002 to 192 average rigs
operating during the third quarter of 2003. Increased revenues and direct
operating costs are attributable to an increase in the number of operating days.
Additionally, revenues further increased as a result of increased revenues
earned per operating day.
DRILLING AND COMPLETION FLUIDS 2003 2002 % CHANGE
- ------------------------------ -------- ------- --------
(DOLLARS IN THOUSANDS)
Revenues ......................................... $ 19,580 $19,714 (0.7)%
Direct operating costs ........................... $ 17,180 $16,393 4.8%
Selling, general and administrative .............. $ 1,870 $ 1,783 4.9%
Depreciation and amortization .................... $ 575 $ 556 3.4%
Operating income (loss) .......................... $ (45) $ 982 N/A%
Total jobs ....................................... 459 383 19.8%
Average revenue per job .......................... $ 42.66 $ 51.47 (17.1)%
Average costs per job ............................ $ 37.43 $ 42.80 (12.5)%
Average margin per job ........................... $ 5.23 $ 8.67 (39.7)%
Capital expenditures ............................. $ 282 $ 154 83.1%
Along with the increase in demand for our land-based contract drilling
services, demand increased for our land-based drilling and completion fluids
services in the 2003 period compared to the 2002 period. The increase in revenue
from land-based services was offset by decreases in the revenues and jobs in the
Gulf of Mexico. Land-based drilling and completion fluids jobs typically
generate less revenue and margin per job than offshore jobs. As a result, our
average revenue and margin per job decreased in the 2003 period compared to the
2002 period.
18
PRESSURE PUMPING 2003 2002 % CHANGE
- ---------------- ------- ------ --------
(DOLLARS IN THOUSANDS)
Revenues ......................................... $13,198 $9,649 36.8%
Direct operating costs ........................... $ 7,226 $5,618 28.6%
Selling, general and administrative .............. $ 1,375 $ 975 41.0%
Depreciation ..................................... $ 1,014 $ 680 49.1%
Operating income ................................. $ 3,583 $2,376 50.8%
Total jobs ....................................... 1,614 1,137 42.0%
Average revenue per job .......................... $ 8.18 $ 8.49 (3.7)%
Average costs per job ............................ $ 4.48 $ 4.94 (9.3)%
Average margin per job ........................... $ 3.70 $ 3.55 4.2%
Capital expenditures ............................. $ 2,880 $2,018 42.7%
The increases in revenues and expenses for our pressure pumping operations
were attributable to improved industry conditions, as discussed in "Contract
Drilling" above, and expansion of our pressure pumping services into the
Appalachian regions of Kentucky and West Virginia. This expansion also resulted
in increases in selling, general and administrative expenses and depreciation in
the 2003 quarter compared to the 2002 quarter.
OIL AND NATURAL GAS PRODUCTION AND EXPLORATION 2003 2002 % CHANGE
- ---------------------------------------------- ------ ------ --------
(DOLLARS IN THOUSANDS,
EXCEPT SALES PRIES)
Revenues ......................................... $5,160 $3,865 33.5%
Direct operating costs ........................... $1,138 $ 989 15.1%
Selling, general and administrative .............. $ 358 $ 301 18.9%
Depreciation and depletion ....................... $2,084 $1,825 14.2%
Operating income ................................. $1,580 $ 750 110.7%
Capital expenditures ............................. $3,052 $1,014 201.0%
Average net daily oil production (Bbls) .......... 808 762 6.0%
Average net daily gas production (Mcf) ........... 5,512 5,503 0.2%
Average oil sales price (per Bbl) ................ $28.95 $27.26 6.2%
Average gas sales price (per Mcf) ................ $ 4.87 $ 2.86 70.3%
Increased revenues and operating income are primarily attributable to
increased prices received from sales of oil and natural gas and to a lesser
extent, increases in production.
CORPORATE AND OTHER 2003 2002 % CHANGE
- ------------------- ------- ------- --------
(IN THOUSANDS)
Selling, general and administrative .............. $ 2,140 $ 2,209 (3.1)%
Bad debt expense ................................. $ 97 $ 165 (41.2)%
Depreciation, depletion and amortization ......... $ 111 $ 111 0.0%
Other (income) expense............................ $ (705) $ (91) N/A%
Capital expenditures ............................. $ -- $ 2,528 N/A%
19
The following tables summarize operations by business segment for the nine
months ended September 30, 2003 and 2002:
CONTRACT DRILLING 2003 2002 % CHANGE
- ----------------- -------- -------- --------
(DOLLARS IN THOUSANDS)
Revenues .............................................. $468,609 $300,668 55.9%
Direct operating costs ................................ $353,893 $232,129 52.5%
Selling, general and administrative ................... $ 3,339 $ 3,075 8.6%
Depreciation and amortization ......................... $ 62,415 $ 60,088 3.9%
Operating income ...................................... $ 48,962 $ 5,376 810.8%
Operating days ........................................ 51,263 33,052 55.1%
Average revenue per operating day ..................... $ 9.14 $ 9.09 0.6%
Average direct operating cost per operating day ....... $ 6.90 $ 7.02 (1.7)%
Average margin per operating day ...................... $ 2.24 $ 2.07 8.2%
Number of owned rigs at end of period ................. 340 324 4.9%
Average number of rigs owned during period ............ 334 322 3.7%
Average rigs operating ................................ 188 121 55.4%
Rig utilization percentage ............................ 56% 38% 47.4%
Capital expenditures .................................. $ 67,537 $ 48,979 37.9%
Increased operating results in 2003 reflect increased demand for our
contract drilling services primarily in response to higher natural gas prices.
Average natural gas prices increased from $3.06 per Mcf in the first nine months
of 2002 to $5.48 per Mcf in the first nine months of 2003. Our rig count
increased from 121 average rigs operating during the first nine months of 2002
to 188 average rigs operating during the first nine months of 2003. Increased
revenues and direct operating costs are attributable to an increase in the
number of operating days.
DRILLING AND COMPLETION FLUIDS 2003 2002 % CHANGE
- ------------------------------ -------- ------- --------
(DOLLARS IN THOUSANDS)
Revenues ......................................... $ 51,431 $52,049 (1.2)%
Direct operating costs ........................... $ 45,483 $44,965 1.2%
Selling, general and administrative .............. $ 5,418 $ 5,271 2.8%
Depreciation and amortization .................... $ 1,732 $ 1,650 5.0%
Operating income (loss) .......................... $ (1,202) $ 163 N/A%
Total jobs ....................................... 1,460 1,056 38.3%
Average revenue per job .......................... $ 35.23 $ 49.29 (28.5)%
Average costs per job ............................ $ 31.15 $ 42.58 (26.8)%
Average margin per job ........................... $ 4.08 $ 6.71 (39.2)%
Capital expenditures ............................. $ 559 $ 1,095 (48.9)%
Along with the increase in demand for our land-based contract drilling
services, demand increased for our land-based drilling and completion fluids
services in the 2003 period compared to the 2002 period. The increase in revenue
from land-based services was offset by decreases in the revenues and jobs in the
Gulf of Mexico. Land-based drilling and completion fluids jobs typically
generate less revenue and margin per job than offshore jobs. As a result, our
average revenue and margin per job decreased in the 2003 period compared to the
2002 period.
PRESSURE PUMPING 2003 2002 % CHANGE
- ---------------- ------- ------- --------
(DOLLARS IN THOUSANDS)
Revenues ......................................... $31,509 $23,691 33.0%
Direct operating costs ........................... $18,032 $14,127 27.6%
Selling, general and administrative .............. $ 4,131 $ 3,136 31.7%
Depreciation ..................................... $ 2,681 $ 1,958 36.9%
Operating income ................................. $ 6,665 $ 4,470 49.1%
Total jobs ....................................... 3,921 2,753 42.4%
Average revenue per job .......................... $ 8.04 $ 8.61 (6.6)%
Average costs per job ............................ $ 4.60 $ 5.13 (10.3)%
Average margin per job ........................... $ 3.44 $ 3.48 (1.1)%
Capital expenditures ............................. $ 8,999 $ 4,392 104.9%
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The increases in revenues and expenses for our pressure pumping operations
were attributable to improved industry conditions, as discussed in "Contract
Drilling" above, and expansion of our pressure pumping services into the
Appalachian regions of Kentucky and West Virginia. This expansion also resulted
in increases in selling, general and administrative expenses and depreciation in
2003 compared to 2002.
OIL AND NATURAL GAS PRODUCTION AND EXPLORATION 2003 2002 % CHANGE
- ---------------------------------------------- ------- ------- --------
(DOLLARS IN THOUSANDS,
EXCEPT SALES PRICES)
Revenues .............................................. $16,329 $10,673 53.0%
Direct operating costs ................................ $ 3,509 $ 2,985 17.6%
Selling, general and administrative ................... $ 1,090 $ 1,148 (5.1)%
Depreciation and depletion ............................ $ 6,664 $ 4,441 50.1%
Operating income ...................................... $ 5,066 $ 2,099 141.4%
Capital expenditures .................................. $ 7,368 $ 5,441 35.4%
Average net daily oil production (Bbls) ............... 788 784 0.5%
Average net daily gas production (Mcf) ................ 5,798 5,375 7.9%
Average oil sales price (per Bbl) ..................... $ 30.53 $ 24.20 26.2%
Average gas sales price (per Mcf) ..................... $ 5.20 $ 2.68 94.0%
Increased revenues and operating income are primarily attributable to
increased prices received from sales of oil and natural gas and to a lesser
extent, increases in production.
CORPORATE AND OTHER 2003 2002 % CHANGE
- ------------------- ------- ------ --------
(IN THOUSANDS)
Selling, general and administrative .............. $ 6,582 $6,509 1.1%
Bad debt expense ................................. $ 259 $ 195 32.8%
Depreciation, depletion and amortization ......... $ 333 $ 333 0.0%
Other (income) expense ........................... $(1,582) $(149) N/A%
Restructuring and other charges .................. $(2,452) $4,700 N/A%
Capital expenditures ............................. $ -- $2,528 N/A%
In 2003, Restructuring and other charges primarily reflects a payment
received in the first quarter of 2003 of approximately $2.5 million as
settlement for contract drilling services previously provided in Mexico by
Norton Drilling Company Mexico, Inc., a wholly-owned subsidiary of the Company.
The underlying accounts receivable balance had been reserved as uncollectible at
the time of the Company's acquisition of Norton Drilling Company Mexico, Inc. in
1999. In 2002, Restructuring and other charges primarily reflects a $4.7 million
charge due to the financial failure of a workers' compensation insurance carrier
we used from 1992 until March 2001.
VOLATILITY OF OIL AND NATURAL GAS PRICES AND ITS IMPACT ON OPERATIONS
Our revenue, profitability and future rate of growth are substantially
dependent upon prevailing prices for oil and natural gas, with respect to all of
our operating segments. Historically, oil and natural gas prices and markets
have been volatile. Prices are affected by market supply and demand factors as
well as actions of state and local agencies, the United States and foreign
governments and international cartels. All of these are beyond our control. Any
significant or extended decline in oil and/or natural gas prices would have a
material adverse effect on our financial condition and results of operations.
Generally, there have been substantially more drilling rigs available than
necessary to meet demand in most operational and geographic segments of the
North American land drilling industry. As a result, drilling contractors have
had difficulty sustaining profit margins.
IMPACT OF INFLATION
We believe that inflation will not have a significant near-term impact on
our financial position.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We currently have no significant exposure to interest rate market risk
because we have no outstanding balance under our credit facility. Should we
incur a balance in the future, we would have exposure associated with the
floating rate of the interest charged on that balance. The revolving credit
facility calls for periodic interest payments
21
at a floating rate ranging from LIBOR plus 1.75 % to 2.75%. The applicable rate
above LIBOR (1.75% at September 30, 2003) is based upon our trailing
twelve-month EBITDA (earnings before interest expense, income taxes, and
depreciation, depletion, and amortization expense). Our exposure to interest
rate risk due to changes in LIBOR is not expected to be material.
We conduct some business in Canadian dollars through our Canadian
land-based drilling operations. The exchange rate between Canadian dollars and
U.S. dollars has fluctuated over the last ten years. If the value of the
Canadian dollar against the U.S. dollar weakens, revenues and earnings of our
Canadian operations will be reduced when they are translated to U.S. dollars.
Also, the value of our Canadian net assets in U.S. dollars may decline.
ITEM 4. CONTROLS AND PROCEDURES
As of the end of the period covered by this Quarterly Report on Form 10-Q,
the effectiveness of our disclosure controls and procedures (as defined in Rules
13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934)
was evaluated by our management, with the participation of our Chief Executive
Officer, Cloyce A. Talbott (principal executive officer), and our Vice
President, Chief Financial Officer, Secretary and Treasurer, Jonathan D. Nelson
(principal financial officer). Messrs. Talbott and Nelson have concluded that
our disclosure controls and procedures are effective, as of the end of the
period covered by this Quarterly Report on Form 10-Q, to help ensure that
information we are required to disclose in reports that we file with the SEC is
accumulated and communicated to management and recorded, processed, summarized
and reported within the time periods prescribed by the SEC.
There were no changes in our internal control over financial reporting
that occurred during our last fiscal quarter that have materially affected, or
are reasonably likely to materially affect, our internal control over financial
reporting.
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---------------
FORWARD LOOKING STATEMENTS AND CAUTIONARY STATEMENTS FOR PURPOSES OF THE
"SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
"Management's Discussion and Analysis of Financial Condition and Results
of Operations" included in Item 2 of this Report contains forward-looking
statements which are made pursuant to the "safe harbor" provisions of the
Private Securities Litigation Reform Act of 1995. These statements include,
without limitation, statements relating to: liquidity; financing of operations;
continued volatility of oil and natural gas prices; source and sufficiency of
funds required for immediate capital needs and additional rig acquisitions (if
further opportunities arise); and other matters. The words "believes," "plans,"
"intends," "expected," "estimates" or "budgeted" and similar expressions
identify forward-looking statements. The forward-looking statements are based on
certain assumptions and analyses we make in light of our experience and our
perception of historical trends, current conditions, expected future
developments and other factors we believe are appropriate in the circumstances.
We do not undertake to update, revise or correct any of the forward-looking
information. Factors that could cause actual results to differ materially from
our expectations expressed in the forward-looking statements include, but are
not limited to, the following:
o Changes in prices and demand for oil and natural gas;
o Changes in demand for contract drilling, pressure pumping and
drilling and completion fluids services;
o Shortages of drill pipe and other drilling equipment;
o Labor shortages, primarily qualified drilling personnel;
o Effects of competition from other drilling contractors and
providers of pressure pumping and drilling and completion fluids
services;
o Occurrence of operating hazards and uninsured losses inherent in
our business operations; and
o Environmental and other governmental regulation.
For a more complete explanation of these various factors and others, see
"Forward Looking Statements and Cautionary Statements for Purposes of the 'Safe
Harbor' Provisions of the Private Securities Litigation Reform Act of 1995"
included in our Annual Report on Form 10-K for the year ended December 31, 2002,
beginning on page 13.
You are cautioned not to place undue reliance on any of our
forward-looking statements, which speak only as of the date of the document or
in the case of documents incorporated by reference, the date of those documents.
---------------
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PART II - OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) EXHIBITS.
The following exhibits are filed herewith or incorporated by reference,
as indicated:
3.1 Restated Certificate of Incorporation, as amended. (1)
3.2 Amended and Restated Bylaws. (2)
31.1 Certification of Chief Executive Officer pursuant to Rule
13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as
amended.
31.2 Certification of Chief Financial Officer pursuant to Rule
13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as
amended.
32.1 Certification of Chief Executive Officer and Chief Financial Officer
pursuant to 18 USC Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
- ----------------------
(1) Incorporated herein by reference to Item 6, "Exhibits and Reports on
Form 8-K" to Form 10-Q for the quarterly period ended June 30, 2003.
(2) Incorporated herein by reference to Item 14, "Exhibits, Financial
Statement Schedules and Reports on Form 8-K" to Annual Report on Form
10-K for the fiscal year ended December 31, 2001.
(b) REPORT ON FORM 8-K.
On July 23, 2003, the Company furnished a Current Report on Form 8-K,
dated July 23, 2003, furnishing the Company's public announcement of
its second quarter 2003 results from operations, including the
Condensed Consolidated Statements of Income and Additional Financial
and Operating Data.
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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.
PATTERSON-UTI ENERGY, INC.
By: /s/ Cloyce A. Talbott
-------------------------------------
Cloyce A. Talbott
Chief Executive Officer
By: /s/ Jonathan D. Nelson
-------------------------------------
Jonathan D. Nelson
Vice President, Chief Financial
Officer, Secretary and Treasurer
DATED: November 14, 2003
25