e10vq
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the quarterly period ended
September 30, 2006
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or
|
o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission file number 0-22664
Patterson-UTI Energy,
Inc.
(Exact name of registrant as
specified in its charter)
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|
|
DELAWARE
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75-2504748
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(State or other jurisdiction
of
incorporation or organization)
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|
(I.R.S. Employer
Identification No.)
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|
4510 LAMESA HIGHWAY,
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79549
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SNYDER, TEXAS
|
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(Zip Code)
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(Address of principal executive
offices)
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(325) 574-6300
(Registrants 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 þ No o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of accelerated filer and large
accelerated filer in
Rule 12b-2
of the Exchange Act. (Check one):
|
|
|
Large
accelerated filer þ
|
Accelerated
filer o
|
Non-accelerated
filer o
|
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
Indicate the number of shares outstanding of each of the
issuers classes of common stock, as of the latest
practicable date.
158,890,535 shares of common stock, $0.01 par value,
as of October 31, 2006
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
TABLE OF
CONTENTS
1
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
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands, except
|
|
|
|
share data)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
16,945
|
|
|
$
|
136,398
|
|
Accounts receivable, net of
allowance for doubtful accounts of $6,288 at September 30,
2006 and $2,199 at December 31, 2005
|
|
|
511,001
|
|
|
|
422,002
|
|
Inventory
|
|
|
36,083
|
|
|
|
27,907
|
|
Deferred tax assets, net
|
|
|
44,528
|
|
|
|
26,382
|
|
Other
|
|
|
53,407
|
|
|
|
25,168
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
661,964
|
|
|
|
637,857
|
|
Property and equipment, at cost,
net
|
|
|
1,328,795
|
|
|
|
1,053,845
|
|
Goodwill
|
|
|
99,056
|
|
|
|
99,056
|
|
Other
|
|
|
5,074
|
|
|
|
5,023
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
2,094,889
|
|
|
$
|
1,795,781
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
152,573
|
|
|
$
|
113,226
|
|
Accrued revenue distributions
|
|
|
14,512
|
|
|
|
13,379
|
|
Other
|
|
|
6,654
|
|
|
|
5,294
|
|
Accrued federal and state income
taxes payable
|
|
|
15,519
|
|
|
|
11,034
|
|
Accrued expenses
|
|
|
150,669
|
|
|
|
112,476
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
339,927
|
|
|
|
255,409
|
|
Borrowings under line of credit
|
|
|
65,000
|
|
|
|
|
|
Deferred tax liabilities, net
|
|
|
186,507
|
|
|
|
169,188
|
|
Other
|
|
|
4,426
|
|
|
|
4,173
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
595,860
|
|
|
|
428,770
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (see
Note 10)
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Preferred stock, par value $.01;
authorized 1,000,000 shares, no shares issued
|
|
|
|
|
|
|
|
|
Common stock, par value $.01;
authorized 300,000,000 shares with 176,616,631 and
175,909,274 issued and 159,906,735 and 172,441,178 outstanding
at September 30, 2006 and December 31, 2005,
respectively
|
|
|
1,766
|
|
|
|
1,759
|
|
Additional paid-in capital
|
|
|
674,903
|
|
|
|
672,151
|
|
Deferred Compensation
|
|
|
|
|
|
|
(9,287
|
)
|
Retained earnings
|
|
|
1,202,744
|
|
|
|
719,113
|
|
Accumulated other comprehensive
income
|
|
|
11,581
|
|
|
|
8,565
|
|
Treasury stock, at cost,
16,709,896 and 3,468,096 shares at September 30, 2006
and December 31, 2005, respectively
|
|
|
(391,965
|
)
|
|
|
(25,290
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
1,499,029
|
|
|
|
1,367,011
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and
stockholders equity
|
|
$
|
2,094,889
|
|
|
$
|
1,795,781
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited
condensed consolidated financial statements.
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
|
(In thousands, except per share amounts)
|
|
|
(In thousands, except per share amounts)
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling
|
|
$
|
577,047
|
|
|
$
|
401,046
|
|
|
$
|
1,616,100
|
|
|
$
|
1,025,938
|
|
Pressure pumping
|
|
|
40,462
|
|
|
|
27,640
|
|
|
|
107,800
|
|
|
|
66,358
|
|
Drilling and completion fluids
|
|
|
46,163
|
|
|
|
29,819
|
|
|
|
155,221
|
|
|
|
88,812
|
|
Oil and natural gas
|
|
|
9,986
|
|
|
|
10,234
|
|
|
|
29,083
|
|
|
|
28,146
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
673,658
|
|
|
|
468,739
|
|
|
|
1,908,204
|
|
|
|
1,209,254
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling
|
|
|
267,345
|
|
|
|
202,956
|
|
|
|
737,021
|
|
|
|
558,607
|
|
Pressure pumping
|
|
|
20,960
|
|
|
|
15,662
|
|
|
|
56,545
|
|
|
|
38,648
|
|
Drilling and completion fluids
|
|
|
36,183
|
|
|
|
24,062
|
|
|
|
120,418
|
|
|
|
71,857
|
|
Oil and natural gas
|
|
|
3,222
|
|
|
|
2,365
|
|
|
|
11,241
|
|
|
|
6,953
|
|
Depreciation, depletion and
impairment
|
|
|
49,215
|
|
|
|
39,545
|
|
|
|
140,245
|
|
|
|
112,319
|
|
Selling, general and administrative
|
|
|
13,777
|
|
|
|
10,565
|
|
|
|
39,428
|
|
|
|
30,157
|
|
Embezzlement costs, net of
recoveries
|
|
|
(1,512
|
)
|
|
|
5,431
|
|
|
|
2,941
|
|
|
|
12,193
|
|
Other operating expenses
|
|
|
2,563
|
|
|
|
707
|
|
|
|
3,948
|
|
|
|
2,590
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
391,753
|
|
|
|
301,293
|
|
|
|
1,111,787
|
|
|
|
833,324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
281,905
|
|
|
|
167,446
|
|
|
|
796,417
|
|
|
|
375,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
948
|
|
|
|
944
|
|
|
|
5,579
|
|
|
|
2,011
|
|
Interest expense
|
|
|
(363
|
)
|
|
|
(56
|
)
|
|
|
(476
|
)
|
|
|
(179
|
)
|
Other
|
|
|
88
|
|
|
|
19
|
|
|
|
231
|
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
673
|
|
|
|
907
|
|
|
|
5,334
|
|
|
|
1,871
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes and
cumulative effect of change in accounting principle
|
|
|
282,578
|
|
|
|
168,353
|
|
|
|
801,751
|
|
|
|
377,801
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
106,151
|
|
|
|
66,574
|
|
|
|
288,476
|
|
|
|
145,513
|
|
Deferred
|
|
|
(9,563
|
)
|
|
|
(4,526
|
)
|
|
|
(2,974
|
)
|
|
|
(6,263
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
96,588
|
|
|
|
62,048
|
|
|
|
285,502
|
|
|
|
139,250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of
change in accounting principle
|
|
|
185,990
|
|
|
|
106,305
|
|
|
|
516,249
|
|
|
|
238,551
|
|
Cumulative effect of change in
accounting principle, net of related income tax expense of $398
|
|
|
|
|
|
|
|
|
|
|
687
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
185,990
|
|
|
$
|
106,305
|
|
|
$
|
516,936
|
|
|
$
|
238,551
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of
change in accounting principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.14
|
|
|
$
|
0.62
|
|
|
$
|
3.07
|
|
|
$
|
1.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
1.12
|
|
|
$
|
0.61
|
|
|
$
|
3.03
|
|
|
$
|
1.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.14
|
|
|
$
|
0.62
|
|
|
$
|
3.08
|
|
|
$
|
1.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
1.12
|
|
|
$
|
0.61
|
|
|
$
|
3.03
|
|
|
$
|
1.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common
shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
163,412
|
|
|
|
171,613
|
|
|
|
168,036
|
|
|
|
169,846
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
165,742
|
|
|
|
174,587
|
|
|
|
170,339
|
|
|
|
173,211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited
condensed consolidated financial statements.
3
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN
STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
Additional
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
Paid-in
|
|
|
Deferred
|
|
|
Retained
|
|
|
Comprehensive
|
|
|
Treasury
|
|
|
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Compensation
|
|
|
Earnings
|
|
|
Income
|
|
|
Stock
|
|
|
Total
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Balance, December 31, 2005
|
|
|
175,909
|
|
|
$
|
1,759
|
|
|
$
|
672,151
|
|
|
$
|
(9,287
|
)
|
|
$
|
719,113
|
|
|
$
|
8,565
|
|
|
$
|
(25,290
|
)
|
|
$
|
1,367,011
|
|
Issuance of restricted stock
|
|
|
613
|
|
|
|
6
|
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of stock options
|
|
|
133
|
|
|
|
1
|
|
|
|
1,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,414
|
|
Tax benefit for stock option
exercises
|
|
|
|
|
|
|
|
|
|
|
922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
922
|
|
Stock based compensation, net of
cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
9,710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,710
|
|
Forfeitures of restricted shares
|
|
|
(39
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Elimination of deferred
compensation due to change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
(9,287
|
)
|
|
|
9,287
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation
adjustment, net of tax of $1,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,016
|
|
|
|
|
|
|
|
3,016
|
|
Payment of cash dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(33,305
|
)
|
|
|
|
|
|
|
|
|
|
|
(33,305
|
)
|
Purchases of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(366,675
|
)
|
|
|
(366,675
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
516,936
|
|
|
|
|
|
|
|
|
|
|
|
516,936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2006
|
|
|
176,616
|
|
|
$
|
1,766
|
|
|
$
|
674,903
|
|
|
$
|
|
|
|
$
|
1,202,744
|
|
|
$
|
11,581
|
|
|
$
|
(391,965
|
)
|
|
$
|
1,499,029
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited
condensed consolidated financial statements.
4
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Cash flows from operating
activities:
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
516,936
|
|
|
$
|
238,551
|
|
Adjustments to reconcile net
income to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and
impairment
|
|
|
140,245
|
|
|
|
112,319
|
|
Dry holes and abandonments
|
|
|
3,709
|
|
|
|
|
|
Provision for bad debts
|
|
|
4,200
|
|
|
|
416
|
|
Deferred income tax benefit
|
|
|
(2,576
|
)
|
|
|
(6,263
|
)
|
Tax benefit related to exercise of
stock options
|
|
|
|
|
|
|
24,047
|
|
Stock based compensation expense
|
|
|
9,710
|
|
|
|
2,121
|
|
Gain on disposal of assets
|
|
|
(437
|
)
|
|
|
(1,253
|
)
|
Changes in operating assets and
liabilities, net of business acquired:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(92,069
|
)
|
|
|
(148,825
|
)
|
Inventory and other current assets
|
|
|
(36,086
|
)
|
|
|
(4,044
|
)
|
Accounts payable
|
|
|
40,280
|
|
|
|
48,568
|
|
Income taxes payable/receivable
|
|
|
4,789
|
|
|
|
29,660
|
|
Accrued expenses
|
|
|
23,798
|
|
|
|
22,662
|
|
Other liabilities
|
|
|
1,613
|
|
|
|
1,513
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
|
614,112
|
|
|
|
319,472
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing
activities:
|
|
|
|
|
|
|
|
|
Purchases of property and equipment
|
|
|
(423,422
|
)
|
|
|
(262,723
|
)
|
Acquisitions, net of cash received
|
|
|
|
|
|
|
(73,577
|
)
|
Proceeds from disposal of property
and equipment
|
|
|
7,983
|
|
|
|
12,502
|
|
Change in other assets
|
|
|
|
|
|
|
1,766
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(415,439
|
)
|
|
|
(322,032
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing
activities:
|
|
|
|
|
|
|
|
|
Purchases of treasury stock
|
|
|
(352,393
|
)
|
|
|
|
|
Dividends paid
|
|
|
(33,305
|
)
|
|
|
(20,441
|
)
|
Proceeds from exercise of stock
options
|
|
|
1,414
|
|
|
|
42,299
|
|
Tax benefit related to exercise of
stock options
|
|
|
922
|
|
|
|
|
|
Proceeds from borrowings under
line of credit
|
|
|
65,000
|
|
|
|
|
|
Debt issuance costs
|
|
|
(341
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in)
financing activities
|
|
|
(318,703
|
)
|
|
|
21,858
|
|
|
|
|
|
|
|
|
|
|
Effect of foreign exchange rate
changes on cash
|
|
|
577
|
|
|
|
(458
|
)
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash
and cash equivalents
|
|
|
(119,453
|
)
|
|
|
18,840
|
|
Cash and cash equivalents at
beginning of period
|
|
|
136,398
|
|
|
|
112,371
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end
of period
|
|
$
|
16,945
|
|
|
$
|
131,211
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of cash
flow information:
|
|
|
|
|
|
|
|
|
Net cash paid during the period
for:
|
|
|
|
|
|
|
|
|
Interest expense
|
|
$
|
476
|
|
|
$
|
179
|
|
Income taxes
|
|
$
|
272,541
|
|
|
$
|
85,824
|
|
The accompanying notes are an integral part of these unaudited
condensed consolidated financial statements.
5
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 accounting principles generally accepted in
the United States of America 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 which are of a normal recurring nature considered
necessary for presentation of the information have been
included. The Unaudited Condensed Consolidated Balance Sheet as
of December 31, 2005, 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 Companys Annual Report on
Form 10-K
for the year ended December 31, 2005.
The Companys former Chief Financial Officer (former
CFO) has pleaded guilty to criminal charges and has been
sentenced and is serving a term of imprisonment arising out of
his embezzlement of funds totaling approximately
$77.5 million from the Company over a period of more than
five years, ending November 3, 2005. The accompanying prior
periods were previously restated to reflect the effects of the
embezzlement in the periods of occurrence. Continuing
professional and other costs related to the embezzlement are
being recognized as operating costs when incurred. In the three
months ended September 30, 2006, the Company recovered
$2.0 million from its insurance carrier related to the
embezzlement loss.
The U.S. dollar is the functional currency for all of the
Companys operations except for its Canadian operations,
which use the Canadian dollar as their functional currency. The
effects of exchange rate changes are reflected in accumulated
other comprehensive income, which is a separate component of
stockholders equity (see Note 3 of these Notes to
Unaudited Condensed Consolidated Financial Statements).
The Company provides a dual presentation of its net income per
common share in its Unaudited Condensed Consolidated Statements
of Income: Basic net income per common share (Basic
EPS) and diluted net income per common share
(Diluted EPS). Basic EPS excludes dilution and is
computed by dividing net income by the weighted average number
of common shares outstanding. Diluted EPS is based on the
weighted-average number of common shares outstanding plus the
impact of dilutive instruments, including stock options,
warrants and restricted shares using the treasury stock method.
For the three and nine months ended September 30, 2006,
options to purchase 800,000 shares of common stock were
excluded from the calculation of Diluted EPS as their inclusion
would have been anti-dilutive. For the three and nine months
ended September 30, 2005, all potentially dilutive
instruments were included in the calculation of Diluted EPS. The
following table presents information necessary to calculate net
income per share for the three and nine months ended
September 30, 2006 and 2005 as well as cash
6
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
dividends per share paid during the three and nine months ended
September 30, 2006 and 2005 (in thousands, except per share
amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
Net income
|
|
$
|
185,990
|
|
|
$
|
106,305
|
|
|
$
|
516,936
|
|
|
$
|
238,551
|
|
Weighted average number of common
shares outstanding
|
|
|
163,412
|
|
|
|
171,613
|
|
|
|
168,036
|
|
|
|
169,846
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income per common share
|
|
$
|
1.14
|
|
|
$
|
0.62
|
|
|
$
|
3.08
|
|
|
$
|
1.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common
shares outstanding
|
|
|
163,412
|
|
|
|
171,613
|
|
|
|
168,036
|
|
|
|
169,846
|
|
Dilutive effect of stock options
and restricted shares
|
|
|
2,330
|
|
|
|
2,974
|
|
|
|
2,303
|
|
|
|
3,365
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of diluted
common shares outstanding
|
|
|
165,742
|
|
|
|
174,587
|
|
|
|
170,339
|
|
|
|
173,211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per common share
|
|
$
|
1.12
|
|
|
$
|
0.61
|
|
|
$
|
3.03
|
|
|
$
|
1.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends per common share(a)
|
|
$
|
0.08
|
|
|
$
|
0.04
|
|
|
$
|
0.20
|
|
|
$
|
0.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
During March 2006, June 2006 and September 2006, cash dividends
of $6.9 million, $13.4 million and $13.0 million,
respectively, were paid on outstanding shares of 172,654,128,
167,660,960 and 162,800,466, respectively. During March 2005,
June 2005 and September 2005, cash dividends of
$6.7 million, $6.8 million and $6.9 million,
respectively, were paid on outstanding shares of 168,679,334 ,
169,741,460 and 172,591,361, respectively. |
The results of operations for the three and nine months ended
September 30, 2006 are not necessarily indicative of the
results to be expected for the full year.
|
|
2.
|
Stock-based
Compensation
|
The Company adopted Financial Accounting Standards Board
(FASB) Statement No. 123 (revised 2004),
Share-Based Payment (FAS 123(R)), on
January 1, 2006 and recognizes the cost of share-based
payments under the
fair-value-based
method. The Company uses share-based payments to compensate
employees and non-employee directors. All awards have been
equity instruments in the form of stock options or restricted
stock awards and include only service conditions. The Company
issues shares of common stock when vested stock option awards
are exercised and when restricted stock awards are granted. As a
result of the initial adoption of FAS 123(R), the Company
recognized income due to the cumulative effect of this change in
accounting principle of $687,000, net of taxes of $398,000,
related to previously expensed amortization of unvested
restricted stock grants. For the three months ended
September 30, 2006, the Company recognized
$3.3 million in stock-based compensation expense and a
related income tax benefit of $1.1 million. For the nine
months ended September 30, 2006, the Company recognized
$10.8 million in stock-based compensation expense and a
related income tax benefit of $3.5 million and recognized a
benefit in the form of a cumulative effect of change in
accounting principle associated with the adoption of
FAS 123(R) of $687,000, net of the related tax expense of
$398,000.
During 2005, the Companys shareholders approved the
Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the
2005 Plan) and the Board of Directors adopted a
resolution that no future grants would
7
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
be made under any of the Companys six other previously
existing plans. The Companys share-based compensation
plans at September 30, 2006 follow:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options &
|
|
|
|
|
|
|
Shares
|
|
|
Restricted
|
|
|
Shares
|
|
|
|
Authorized
|
|
|
Shares
|
|
|
Available
|
|
Plan Name
|
|
for Grant
|
|
|
Outstanding
|
|
|
for Grant
|
|
|
Patterson-UTI Energy, Inc. 2005
Long-Term Incentive Plan
|
|
|
6,250,000
|
|
|
|
1,546,952
|
|
|
|
4,127,961
|
|
Patterson-UTI Energy, Inc. Amended
and Restated 1997 Long-Term Incentive Plan, as amended
(1997 Plan)
|
|
|
|
|
|
|
5,097,985
|
|
|
|
|
|
Amended and Restated Patterson-UTI
Energy, Inc. 2001 Long-Term Incentive Plan (2001
Plan)
|
|
|
|
|
|
|
771,977
|
|
|
|
|
|
Amended and Restated Non-Employee
Director Stock Option Plan of Patterson-UTI Energy, Inc.
(Non-Employee Director Plan)
|
|
|
|
|
|
|
180,000
|
|
|
|
|
|
Amended and Restated Patterson-UTI
Energy, Inc. 1996 Employee Stock Option Plan (1996
Plan)
|
|
|
|
|
|
|
95,800
|
|
|
|
|
|
Patterson-UTI Energy, Inc., 1993
Incentive Stock Plan, as amended (1993 Plan)
|
|
|
|
|
|
|
125,800
|
|
|
|
|
|
A summary of the 2005 Plan follows:
|
|
|
|
|
The Compensation Committee of the Board of Directors administers
the plan.
|
|
|
|
All employees including officers and directors are eligible for
awards.
|
|
|
|
The Compensation Committee determines the vesting schedule for
awards. Awards typically vest over 1 year for non-employee
directors and 3 to 4 years for employees.
|
|
|
|
The Compensation Committee sets the term of awards and no option
term can exceed 10 years.
|
|
|
|
All options granted under the plan are granted with an exercise
price equal to or greater than the fair market value of the
Companys common stock at the time the option is granted.
|
|
|
|
The plan provides for awards of incentive stock options,
non-incentive stock options, tandem and freestanding stock
appreciation rights, restricted stock awards, other stock unit
awards, performance share awards, performance unit awards and
dividend equivalents. As of September 30, 2006, only
non-incentive stock options and restricted stock awards had been
granted under the plan.
|
Options granted under the 1997 Plan vest over three or five
years as dictated by the Compensation Committee. These options
typically had terms of ten years. All options were granted with
an exercise price equal to the fair market value of the related
common stock at the time of grant. Restricted Stock Awards
granted under the 1997 Plan vest over four years.
Options granted under the 2001 Plan vest over five years as
dictated by the Compensation Committee. These options had terms
of ten years. All options were granted with an exercise price
equal to the fair market value of the Companys common
stock at the time of grant. Restricted Stock Awards granted
under the 2001 Plan vest over four years.
Options granted under the Non-Employee Director Plan vest on the
first anniversary of the option grant. Non-Employee Director
Plan options have five year terms. All options were granted with
an exercise price equal to the fair market value of the related
common stock at the time of grant.
Options granted under the 1996 plan vested over one, four and
five years as dictated by the Compensation Committee. These
options had terms of five or ten years as dictated by the
Compensation Committee. All options were granted with an
exercise price equal to the fair market value of the
Companys common stock at the time of grant.
8
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Options granted under the 1993 Plan typically had terms of
10 years and vested over five years in 20% increments
beginning at the end of the first year. All options were granted
with an exercise price equal to the fair market value of the
Companys common stock at the time of grant.
Stock Options. The Company accounted for all
stock options under the intrinsic value method prior to
January 1, 2006. Accordingly, no compensation expense was
recognized in prior periods for stock options because they had
no intrinsic value when granted as exercise prices were equal to
the grant date market value of the related common stock. The
Modified Prospective Application (MPA) method is
being applied to transition from the intrinsic value method to
the
fair-value-based
method for stock options. The effects of the application of the
MPA method follow:
|
|
|
|
|
Previously reported amounts and disclosures are not affected.
|
|
|
|
Compensation cost, net of estimated forfeitures for the unvested
portion of awards outstanding at January 1, 2006, is
recognized under the
fair-value-based
method as the awards vest. Compensation cost is based on the
grant-date fair value of stock options as calculated for the
Companys previously reported pro forma disclosures under
FASB Statement No. 123, Accounting for Stock-Based
Compensation (FAS 123).
|
|
|
|
The fair-value based method is applied to new awards and to
awards outstanding at January 1, 2006 that are modified,
repurchased or cancelled after that date, if any.
|
The Company estimates grant date fair values of stock options
using the Black-Scholes-Merton valuation model
(Black-Scholes), except for stock options granted
prior to 1996 that are not subject to FAS 123(R) and were
not subject to FAS 123 pro forma disclosures. Volatility
assumptions are based on the historic volatility of the
Companys common stock over the most recent period equal to
the expected term of the options as of the date the options were
granted. The expected term assumptions are based on the
Companys experience with respect to employee stock option
activity. Dividend yield assumptions are based on the expected
dividends at the time the options were granted. The risk-free
interest rate assumptions are determined by reference to United
States Treasury yields. Weighted-average assumptions used to
estimate grant date fair values for stock options granted in the
three and nine month periods ended September 30, 2006 and
2005 follow:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
Volatility
|
|
|
33.59
|
%
|
|
|
N/A
|
|
|
|
33.18
|
%
|
|
|
26.95
|
%
|
Expected term (in years)
|
|
|
4.00
|
|
|
|
N/A
|
|
|
|
4.00
|
|
|
|
4.00
|
|
Dividend yield
|
|
|
1.14
|
%
|
|
|
N/A
|
|
|
|
1.09
|
%
|
|
|
0.65
|
%
|
Risk-free interest rate
|
|
|
4.91
|
%
|
|
|
N/A
|
|
|
|
4.87
|
%
|
|
|
3.84
|
%
|
No stock options were granted during the three months ended
September 30, 2005.
9
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Stock option activity from January 1, 2006 to
September 30, 2006 follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
Average
|
|
|
Aggregate
|
|
|
|
|
|
|
Average
|
|
|
Remaining
|
|
|
Intrinsic
|
|
|
|
Underlying
|
|
|
Exercise
|
|
|
Contractual
|
|
|
Value
|
|
|
|
Shares
|
|
|
Price
|
|
|
Term (Yrs)
|
|
|
($000s)
|
|
|
Outstanding at January 1, 2006
|
|
|
6,338,043
|
|
|
$
|
14.37
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
800,000
|
|
|
$
|
28.54
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(133,309
|
)
|
|
$
|
10.61
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(15,800
|
)
|
|
$
|
11.65
|
|
|
|
|
|
|
|
|
|
Expired
|
|
|
(5,587
|
)
|
|
$
|
7.62
|
|
|
|
|
|
|
|
|
|
Cancelled(a)
|
|
|
(360,833
|
)
|
|
$
|
14.83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30,
2006
|
|
|
6,622,514
|
|
|
$
|
16.15
|
|
|
|
6.43
|
|
|
$
|
54,756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at September 30,
2006
|
|
|
5,322,080
|
|
|
$
|
13.76
|
|
|
|
5.78
|
|
|
$
|
53,452
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Represents vested stock options held by the former CFO which
were cancelled by the Companys Board of Directors. |
The weighted-average grant-date fair value of stock options
granted and the aggregate intrinsic value of stock options
exercised during the three and nine month periods ended
September 30, 2006 and 2005 follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
Weighted-average grant-date fair
value of stock options granted
|
|
$
|
8.58
|
|
|
$
|
N/A
|
|
|
$
|
8.62
|
|
|
$
|
6.33
|
|
Aggregate intrinsic value of stock
options exercised ($000s)
|
|
$
|
417
|
|
|
$
|
28,118
|
|
|
$
|
2,759
|
|
|
$
|
69,315
|
|
As of September 30, 2006, options to purchase
1,300,434 shares were outstanding and not vested. Of these
non-vested options, approximately 1,273,000 are expected to
ultimately vest. Additional information as of September 30,
2006 with respect to these options that are expected to vest
follows:
|
|
|
|
|
Aggregate intrinsic value
|
|
$
|
1.3 million
|
|
Weighted-average remaining
contractual term
|
|
|
9.07 years
|
|
Weighted-average remaining
expected term
|
|
|
3.08 years
|
|
Weighted-average remaining vesting
period
|
|
|
2.14 years
|
|
Unrecognized compensation cost
|
|
$
|
9.3 million
|
|
Restricted Stock. Under all restricted stock
awards to date, shares were issued when granted, nonvested
shares are subject to forfeiture for failure to fulfill service
conditions and nonforfeitable dividends are paid on nonvested
restricted shares. Restricted stock awards prior to
January 1, 2006 were valued at the grant date market value
of the underlying common stock, recognized as contra equity
deferred compensation and amortized to expense under the
graded-vesting method. Implementation of
FAS 123(R) did not change the accounting for the
Companys nonvested stock awards, except as follows:
|
|
|
|
|
Prior to January 1, 2006, forfeitures were recognized as
they occurred;
|
|
|
|
From January 1, 2006 forward, forfeitures are estimated in
the determination of periodic compensation cost; and
|
10
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
Contra equity deferred compensation was reversed against
paid-in-capital
at January 1, 2006 and compensation expense is recognized
as attributed to each period.
|
The Company uses the graded-vesting attribution
method to determine periodic compensation cost from restricted
stock awards.
Restricted stock activity from January 1, 2006 to
September 30, 2006 follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Grant Date
|
|
|
|
Shares
|
|
|
Fair Value
|
|
|
Nonvested at January 1, 2006
|
|
|
623,150
|
|
|
$
|
21.44
|
|
Granted
|
|
|
613,400
|
|
|
$
|
30.46
|
|
Vested
|
|
|
(1,198
|
)
|
|
$
|
14.73
|
|
Forfeited
|
|
|
(39,352
|
)
|
|
$
|
26.15
|
|
|
|
|
|
|
|
|
|
|
Nonvested at September 30,
2006
|
|
|
1,196,000
|
|
|
$
|
25.92
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2006, approximately 949,000 shares
of nonvested restricted stock outstanding are expected to vest.
Additional information as of September 30, 2006 with
respect to these shares that are expected to vest follows:
|
|
|
|
|
Aggregate intrinsic value
|
|
$
|
22.6 million
|
|
Weighted-average remaining vesting
period
|
|
|
2.76 years
|
|
Unrecognized compensation cost
|
|
$
|
16.5 million
|
|
Dividends on Equity Awards. Nonforfeitable
dividends paid on equity awards are recognized as follows:
|
|
|
|
|
Dividends are recognized as reductions of retained earnings for
the portion of equity awards expected to vest.
|
|
|
|
Dividends are recognized as additional compensation cost for the
portion of equity awards that are not expected to vest or that
ultimately do not vest.
|
Vesting expectations, in regard to these dividend payments,
correspond with forfeiture rate assumptions used to recognize
compensation cost. Accordingly, when the Company adjusts
forfeiture rate assumptions or when actual forfeitures are
ultimately recognized, related dividends are reflected as
additional compensation expense as opposed to being charged
directly to retained earnings.
Prior Period Pro Forma Disclosures. Prior to
January 1, 2006, the Company accounted for share-based
compensation under the intrinsic value method. Other than the
restricted stock discussed above, no additional share-based
compensation expense was reflected in prior period earnings
since the exercise price was equal to the grant-date market
value of the underlying common stock for all stock options
granted prior to January 1, 2006. The effect
11
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
of share-based compensation, as if the Company had applied the
fair-value-based
method proscribed by FAS 123, on net income and earnings
per share for prior periods presented follows (in thousands,
except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2005
|
|
|
2005
|
|
|
Net income, as reported
|
|
$
|
106,305
|
|
|
$
|
238,551
|
|
Add back: Share-based employee
compensation cost, net of related tax effects, included in net
income as reported
|
|
|
639
|
|
|
|
1,339
|
|
Deduct: Share-based employee
compensation cost, net of related tax effects, that would have
been included in net income if the
fair-value-based
method had been applied to all awards
|
|
|
(3,426
|
)
|
|
|
(9,484
|
)
|
|
|
|
|
|
|
|
|
|
Pro-forma net income
|
|
$
|
103,518
|
|
|
$
|
230,406
|
|
|
|
|
|
|
|
|
|
|
Net income per common share:
|
|
|
|
|
|
|
|
|
Basic, as reported
|
|
$
|
0.62
|
|
|
$
|
1.40
|
|
|
|
|
|
|
|
|
|
|
Basic, pro-forma
|
|
$
|
0.60
|
|
|
$
|
1.36
|
|
|
|
|
|
|
|
|
|
|
Diluted, as reported
|
|
$
|
0.61
|
|
|
$
|
1.38
|
|
|
|
|
|
|
|
|
|
|
Diluted, pro-forma
|
|
$
|
0.59
|
|
|
$
|
1.33
|
|
|
|
|
|
|
|
|
|
|
The following table illustrates the Companys comprehensive
income including the effects of foreign currency translation
adjustments for the three and nine months ended
September 30, 2006 and 2005 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
Net income
|
|
$
|
185,990
|
|
|
$
|
106,305
|
|
|
$
|
516,936
|
|
|
$
|
238,551
|
|
Other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation
adjustment related to our Canadian operations, net of tax
|
|
|
478
|
|
|
|
2,286
|
|
|
|
3,016
|
|
|
|
1,319
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income, net of tax
|
|
$
|
186,468
|
|
|
$
|
108,591
|
|
|
$
|
519,952
|
|
|
$
|
239,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.
|
Property
and Equipment
|
Property and equipment consisted of the following at
September 30, 2006 and December 31, 2005 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Equipment
|
|
$
|
2,021,601
|
|
|
$
|
1,633,911
|
|
Oil and natural gas properties
|
|
|
86,143
|
|
|
|
79,079
|
|
Buildings
|
|
|
29,052
|
|
|
|
22,490
|
|
Land
|
|
|
6,104
|
|
|
|
5,611
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,142,900
|
|
|
|
1,741,091
|
|
Less accumulated depreciation and
depletion
|
|
|
(814,105
|
)
|
|
|
(687,246
|
)
|
|
|
|
|
|
|
|
|
|
Property and equipment, at cost,
net
|
|
$
|
1,328,795
|
|
|
$
|
1,053,845
|
|
|
|
|
|
|
|
|
|
|
12
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Our revenues, operating profits and identifiable assets are
primarily attributable to four business segments:
(i) contract drilling of oil and natural gas wells,
(ii) pressure pumping services, (iii) drilling and
completion fluid services to operators in the oil and natural
gas industry, and (iv) 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
Companys 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,
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling(a)
|
|
$
|
578,653
|
|
|
$
|
401,626
|
|
|
$
|
1,620,322
|
|
|
$
|
1,028,230
|
|
Pressure pumping
|
|
|
40,462
|
|
|
|
27,640
|
|
|
|
107,800
|
|
|
|
66,358
|
|
Drilling and completion fluids(b)
|
|
|
46,317
|
|
|
|
29,842
|
|
|
|
155,639
|
|
|
|
88,994
|
|
Oil and natural gas
|
|
|
9,986
|
|
|
|
10,234
|
|
|
|
29,083
|
|
|
|
28,146
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment revenues
|
|
|
675,418
|
|
|
|
469,342
|
|
|
|
1,912,844
|
|
|
|
1,211,728
|
|
Elimination of intercompany
revenues(a)(b)
|
|
|
(1,760
|
)
|
|
|
(603
|
)
|
|
|
(4,640
|
)
|
|
|
(2,474
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
673,658
|
|
|
$
|
468,739
|
|
|
$
|
1,908,204
|
|
|
$
|
1,209,254
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling
|
|
$
|
264,924
|
|
|
$
|
163,109
|
|
|
$
|
751,977
|
|
|
$
|
367,721
|
|
Pressure pumping
|
|
|
13,493
|
|
|
|
7,691
|
|
|
|
34,592
|
|
|
|
15,779
|
|
Drilling and completion fluids
|
|
|
6,558
|
|
|
|
2,746
|
|
|
|
25,038
|
|
|
|
8,261
|
|
Oil and natural gas
|
|
|
3,276
|
|
|
|
4,098
|
|
|
|
6,977
|
|
|
|
10,532
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
288,251
|
|
|
|
177,644
|
|
|
|
818,584
|
|
|
|
402,293
|
|
Corporate and other
|
|
|
(5,295
|
)
|
|
|
(4,060
|
)
|
|
|
(15,278
|
)
|
|
|
(11,580
|
)
|
Other operating expenses
|
|
|
(2,563
|
)
|
|
|
(707
|
)
|
|
|
(3,948
|
)
|
|
|
(2,590
|
)
|
Embezzlement costs, net of
recoveries(c)
|
|
|
1,512
|
|
|
|
(5,431
|
)
|
|
|
(2,941
|
)
|
|
|
(12,193
|
)
|
Interest income
|
|
|
948
|
|
|
|
944
|
|
|
|
5,579
|
|
|
|
2,011
|
|
Interest expense
|
|
|
(363
|
)
|
|
|
(56
|
)
|
|
|
(476
|
)
|
|
|
(179
|
)
|
Other
|
|
|
88
|
|
|
|
19
|
|
|
|
231
|
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes and
cumulative effect of change in accounting principle
|
|
$
|
282,578
|
|
|
$
|
168,353
|
|
|
$
|
801,751
|
|
|
$
|
377,801
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Identifiable assets:
|
|
|
|
|
|
|
|
|
Contract drilling
|
|
$
|
1,787,241
|
|
|
$
|
1,421,779
|
|
Pressure pumping
|
|
|
100,721
|
|
|
|
72,536
|
|
Drilling and completion fluids
|
|
|
104,076
|
|
|
|
90,904
|
|
Oil and natural gas
|
|
|
62,786
|
|
|
|
60,785
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,054,824
|
|
|
|
1,646,004
|
|
Corporate and other(d)
|
|
|
40,065
|
|
|
|
149,777
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
2,094,889
|
|
|
$
|
1,795,781
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes contract drilling intercompany revenues of
approximately $1.6 million and $580,000 for the three
months ended September 30, 2006 and 2005, respectively, and
approximately $4.2 million and $2.3 million for the
nine months ended September 30, 2006 and 2005, respectively. |
|
(b) |
|
Includes drilling and completion fluids intercompany revenues of
approximately $154,000 and $23,000 for the three months ended
September 30, 2006 and 2005, respectively, and
approximately $418,000 and $182,000 for the nine months ended
September 30, 2006 and 2005, respectively . |
|
(c) |
|
The Companys former CFO has pleaded guilty to criminal
charges and has been sentenced and is serving a term of
imprisonment arising out of his embezzlement of funds totaling
approximately $77.5 million from the Company over a period
of more than five years, ending November 3, 2005.
Embezzlement costs, net of recoveries include embezzled funds
and other costs incurred as a result of the embezzlement. In the
three months ended September 30, 2006, the Company
recovered $2.0 million from its insurance carrier related
to the embezzlement loss. |
|
(d) |
|
Corporate assets primarily include cash on hand managed by the
parent corporation and certain deferred federal income tax
assets. |
Goodwill is evaluated at least annually to determine if the fair
value of recorded goodwill has decreased below its carrying
value. At December 31, 2005 the Company performed its
annual goodwill evaluation and determined no adjustment to
impair goodwill was necessary. Goodwill as of September 30,
2006 and December 31, 2005 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Contract Drilling:
|
|
|
|
|
|
|
|
|
Goodwill at beginning of period
|
|
$
|
89,092
|
|
|
$
|
89,092
|
|
Changes to goodwill
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill at end of period
|
|
|
89,092
|
|
|
|
89,092
|
|
|
|
|
|
|
|
|
|
|
Drilling and completion
fluids:
|
|
|
|
|
|
|
|
|
Goodwill at beginning of period
|
|
$
|
9,964
|
|
|
$
|
9,964
|
|
Changes to goodwill
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill at end of period
|
|
|
9,964
|
|
|
|
9,964
|
|
|
|
|
|
|
|
|
|
|
Total goodwill
|
|
$
|
99,056
|
|
|
$
|
99,056
|
|
|
|
|
|
|
|
|
|
|
14
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Accrued expenses consisted of the following at
September 30, 2006 and December 31, 2005 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Workers compensation
liability
|
|
$
|
62,737
|
|
|
$
|
47,107
|
|
Salaries, wages, payroll taxes and
benefits
|
|
|
38,074
|
|
|
|
33,816
|
|
Sales, use and other taxes
|
|
|
11,647
|
|
|
|
9,484
|
|
Insurance, other than
workers compensation
|
|
|
13,734
|
|
|
|
11,365
|
|
Other
|
|
|
24,477
|
|
|
|
10,704
|
|
|
|
|
|
|
|
|
|
|
Accrued expenses
|
|
$
|
150,669
|
|
|
$
|
112,476
|
|
|
|
|
|
|
|
|
|
|
|
|
8.
|
Asset
Retirement Obligation
|
Statement of Financial Accounting Standards No. 143,
Accounting for Asset Retirement Obligations,
(SFAS No. 143), requires that the Company
record a liability for the estimated costs to be incurred in
connection with the abandonment of oil and natural gas
properties in the future. The following table describes the
changes to our asset retirement obligations during the nine
months ended September 30, 2006 and 2005 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
Balance at beginning of year
|
|
$
|
1,725
|
|
|
$
|
2,358
|
|
Liabilities incurred
|
|
|
83
|
|
|
|
61
|
|
Liabilities settled
|
|
|
(48
|
)
|
|
|
(801
|
)
|
Accretion expense
|
|
|
41
|
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation at end
of period
|
|
$
|
1,801
|
|
|
$
|
1,673
|
|
|
|
|
|
|
|
|
|
|
|
|
9.
|
Borrowings
Under Line of Credit
|
On August 2, 2006, the Company entered into an agreement to
amend its $200 million unsecured revolving line of credit
(LOC). In connection with this amendment, the
borrowing capacity under this LOC was increased to
$375 million. No significant changes were made to the terms
of the LOC including the interest to be paid on outstanding
balances and financial covenants.
As of September 30, 2006, borrowings of $65.0 million
have been advanced under the LOC. The weighted average interest
rate on borrowings outstanding at September 30, 2006 was
8.25%.
|
|
10.
|
Commitments,
Contingencies and Other Matters
|
The Company maintains letters of credit in the aggregate amount
of approximately $60 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.
As of September 30, 2006, the Company has remaining
non-cancelable commitments to purchase $240 million of
equipment through 2007.
A receiver has been appointed to identify the assets of our
former CFO in connection with his embezzlement of Company funds.
The receiver is liquidating the assets and will propose a plan
to distribute the proceeds. While the Company believes it has a
claim for at least the full amount of funds embezzled from the
Company, other creditors have asserted or may assert claims with
respect to the assets held by the receiver.
15
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In December 2005, two derivative actions were filed in Texas
state court in Scurry County, Texas, and in May 2006, a
derivative action was filed in federal court in Lubbock, Texas,
in each case, against the directors of the Company, alleging
that the directors breached their fiduciary duties to the
Company as a result of alleged failure to timely discover the
embezzlement. The Board of Directors formed a special litigation
committee to review and inquire about these allegations and
recommend the Companys response, if any. Further legal
proceedings in these suits were stayed pending completion of the
work of the special litigation committee. Settlement
negotiations are taking place. The lawsuits seek recovery on
behalf of and for the Company and do not seek recovery from the
Company.
The Company is party to various other legal proceedings arising
in the normal course of its business. The Company does not
believe that the outcome of these proceedings, either
individually or in the aggregate, will have a material adverse
effect on its financial condition.
On March 2, 2006, the Companys Board of Directors
approved a cash dividend on its common stock in the amount of
$0.04 per share. The cash dividend of approximately
$6.9 million was paid on March 30, 2006 to holders of
record on March 15, 2006. On April 26, 2006, the
Companys Board of Directors approved an increase in its
quarterly cash dividend from $0.04 to $0.08 on each outstanding
share of its common stock. This dividend of approximately
$13.4 million was paid on June 30, 2006 to holders of
record on June 15, 2006. On August 2, 2006, the
Companys Board of Directors approved a cash dividend on
its common stock in the amount of $0.08 per share. This
dividend of approximately $13.0 million was paid on
September 29, 2006 to holders of record on
September 14, 2006. The amount and timing of all future
dividend payments is subject to the discretion of the Board of
Directors and will depend upon business conditions, results of
operations, financial condition, terms of the Companys
credit facilities and other factors.
On March 27, 2006, the Companys Board of Directors
increased the Companys previously authorized stock buyback
program to allow for future purchases of up to $200 million
of the Companys outstanding common stock. During the
second quarter of 2006, the Company completed the authorized
buyback with the purchase of 6,704,800 shares of its common
stock at a cost of approximately $200 million. On
August 2, 2006, the Companys Board of Directors again
increased the Companys previously authorized stock buyback
program to allow for future purchases of up to $250 million
of the Companys outstanding common stock. During the three
months ended September 30, 2006, the Company purchased
6,537,000 shares of its common stock at a cost of
approximately $167 million. As of September 30, 2006,
the Company is authorized to purchase approximately
$83 million of the Companys outstanding common stock
under the stock buyback program. Shares purchased under the
stock buyback program have been accounted for as treasury stock.
On October 31, 2006, the Companys Board of Directors
approved a quarterly cash dividend of $0.08 on each outstanding
share of its common stock. The dividend is to be paid on
December 29, 2006 to holders of record as of
December 14, 2006.
|
|
13.
|
Recently
Issued Accounting Standards
|
In June 2006, the FASB issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes an
interpretation of FASB Statement No. 109
(FIN 48). FIN 48 clarifies the accounting
for uncertainty in income taxes recognized in an
enterprises financial statements and prescribes a
recognition threshold and measurement attribute for the
financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return.
FIN 48 is effective for fiscal years beginning after
December 15, 2006 and will be effective for the company as
of January 1, 2007. The application of this standard is not
expected to be material.
16
PATTERSON-UTI
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In September 2006, the FASB issued Statement No. 157,
Fair Value Measurements (FAS 157).
FAS 157 defines fair value, establishes a framework for
measuring fair value in generally accepted accounting
principles, and expands disclosures about fair value
measurement. FAS 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007
and interim periods within those fiscal years. FAS 157 will
be effective for the Company in the quarter ending
March 31, 2008. The application of FAS 157 is not
expected to have a material impact to the Company.
In September 2006, the SEC staff issued Staff Accounting
Bulletin No. 108, Considering the Effects of Prior
Year Misstatements when Quantifying Misstatements in Current
Year Financial Statements (SAB 108).
SAB 108 was issued in order to eliminate the diversity of
practice surrounding how public companies quantify financial
statement misstatements. Traditionally, there have been two
widely-recognized methods for quantifying the effects of
financial statement misstatements. The roll-over
method focuses primarily on the impact of a misstatement on the
income statement (including the reversing effect of prior year
misstatements) but its use can lead to the accumulation of
misstatements in the balance sheet. The iron-curtain
method, on the other hand, focuses primarily on the effect of
correcting the period-end balance sheet with less emphasis on
the reversing effects of prior year errors on the income
statement. The Company currently uses the iron-curtain method
for quantifying identified financial statement misstatements. In
SAB 108, the SEC staff established an approach that
requires quantification of financial statement misstatements
based on the effects of the misstatements on each of the
companys financial statements and the related financial
statement disclosures. This model is commonly referred to as a
dual approach because it requires quantification of
errors under both the iron curtain and the roll-over methods.
The Company will apply the provisions of SAB 108 in the
quarter ending December 31, 2006 and the impact is not
expected to be material.
17
|
|
ITEM 2.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
Management Overview We are a leading provider
of contract services to the North American oil and natural gas
industry. Our services primarily involve the drilling, on a
contract basis, of land-based oil and natural gas wells and, to
a lesser extent, we provide pressure pumping services and
drilling and completion fluid services. In addition to the
aforementioned contract services, we also engage in the
development, exploration, acquisition and production of oil and
natural gas. For the three and nine months ended
September 30, 2006 and 2005, our operating revenues
consisted of the following (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
Contract drilling
|
|
$
|
577,047
|
|
|
|
86
|
%
|
|
$
|
401,046
|
|
|
|
86
|
%
|
|
$
|
1,616,100
|
|
|
|
84
|
%
|
|
$
|
1,025,938
|
|
|
|
85
|
%
|
Pressure pumping
|
|
|
40,462
|
|
|
|
6
|
|
|
|
27,640
|
|
|
|
6
|
|
|
|
107,800
|
|
|
|
6
|
|
|
|
66,358
|
|
|
|
6
|
|
Drilling and completion fluids
|
|
|
46,163
|
|
|
|
7
|
|
|
|
29,819
|
|
|
|
6
|
|
|
|
155,221
|
|
|
|
8
|
|
|
|
88,812
|
|
|
|
7
|
|
Oil and natural gas
|
|
|
9,986
|
|
|
|
1
|
|
|
|
10,234
|
|
|
|
2
|
|
|
|
29,083
|
|
|
|
2
|
|
|
|
28,146
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
673,658
|
|
|
|
100
|
%
|
|
$
|
468,739
|
|
|
|
100
|
%
|
|
$
|
1,908,204
|
|
|
|
100
|
%
|
|
$
|
1,209,254
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We provide our contract services to oil and natural gas
operators in many of the oil and natural gas producing regions
of North America. Our contract drilling operations are focused
in various regions of Texas, New Mexico, Oklahoma, Arkansas,
Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North
Dakota, South Dakota and Western Canada while our pressure
pumping services are focused primarily in the Appalachian Basin.
Our drilling and completion fluids services are provided to
operators offshore in the Gulf of Mexico and on land in Texas,
Southeastern New Mexico, Oklahoma and the Gulf Coast region of
Louisiana. Our oil and natural gas operations are primarily
focused in West and South Texas, Southeastern New Mexico, Utah
and Mississippi.
We have been a leading consolidator of the land-based contract
drilling industry over the past several years, increasing our
drilling fleet to 403 rigs as of September 30, 2006. Based
on publicly available information, we believe we are the second
largest owner of land-based drilling rigs in North America.
The profitability of our business is most readily assessed by
two primary indicators in our contract drilling segment: our
average number of rigs operating and our average revenue per
operating day. During the third quarter of 2006, our average
number of rigs operating was 301 per day compared to 295 in
the second quarter of 2006 and 283 in the third quarter of 2005.
Our average revenue per operating day increased to $20,810 in
the third quarter of 2006 from $19,780 in the second quarter of
2006 and $15,420 in the third quarter of 2005. Primarily due to
these improvements, we experienced an increase of approximately
$79.7 million, or 75%, in consolidated net income for the
third quarter of 2006 as compared to the third quarter of 2005.
Our revenues, profitability and cash flows are highly dependent
upon the market prices of oil and natural gas. During periods of
improved commodity prices, the capital spending budgets of oil
and natural gas operators tend to expand, which results in
increased demand for our contract services. Conversely, in
periods of time when these commodity prices deteriorate, the
demand for our contract services generally weakens and we
experience downward pressure on pricing for our services. In
addition, our operations are highly impacted by competition, the
availability of excess equipment, labor issues and various other
factors which are more fully described as Risk
Factors included as Item 1A in our Annual Report on
Form 10-K
for the year ended December 31, 2005.
Management believes that the liquidity shown on our balance
sheet as of September 30, 2006, which includes
approximately $322 million in working capital (including
$16.9 million in cash) and $250 million available
under a $375 million line of credit ($65.0 million in
borrowings are outstanding at September 30, 2006 and
availability of $60.0 million is reserved for outstanding
letters of credit), provides us with the ability to pursue
acquisition opportunities, expand into new regions, make
improvements to our assets, pay cash dividends, buy back the
Companys common stock and survive downturns in our
industry.
Commitments and Contingencies The Company
maintains letters of credit in the aggregate amount of
approximately $60.0 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.
18
As of September 30, 2006, the Company has remaining
non-cancelable commitments to purchase $240 million of
equipment through 2007.
A receiver has been appointed to identify the assets of our
former CFO in connection with his embezzlement of Company funds.
The receiver is liquidating the assets and will propose a plan
to distribute the proceeds. While the Company believes it has a
claim for at least the full amount of funds embezzled from the
Company, other creditors have asserted or may assert claims with
respect to the assets held by the receiver.
In December 2005, two derivative actions were filed in Texas
state court in Scurry County, Texas, and in May 2006, a
derivative action was filed in federal court in Lubbock, Texas,
in each case, against the directors of the Company, alleging
that the directors breached their fiduciary duties to the
Company as a result of alleged failure to timely discover the
embezzlement. The Board of Directors formed a special litigation
committee to review and inquire about these allegations and
recommend the Companys response, if any. Further legal
proceedings in these suits were stayed pending completion of the
work of the special litigation committee. Settlement
negotiations are taking place. The lawsuits seek recovery on
behalf of and for the Company and do not seek recovery from the
Company.
Trading and Investing We have not engaged in
trading activities that include high-risk securities, such as
derivatives and non-exchange traded contracts. We invest cash
primarily in highly liquid, short-term investments such as
overnight deposits, money markets, and highly rated municipal
and commercial bonds.
Description of Business We conduct our
contract drilling operations in Texas, New Mexico, Oklahoma,
Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming,
Montana, North Dakota, South Dakota and Western Canada. As of
September 30, 2006, we owned 403 drilling rigs. We provide
pressure pumping services to oil and natural gas operators
primarily in the Appalachian Basin. These services consist
primarily of well stimulation and cementing for completion of
new wells and remedial work on existing wells. We provide
drilling fluids, completion fluids and related services to oil
and natural gas operators offshore in the Gulf of Mexico and on
land in Texas, Southeastern New Mexico, Oklahoma and the Gulf
Coast region of Louisiana. Drilling and completion fluids are
used by oil and natural gas operators during the drilling
process to control pressure when drilling oil and natural gas
wells. We are also engaged in the development, exploration,
acquisition and production of oil and natural gas. Our oil and
natural gas operations are focused primarily in producing
regions in West and South Texas, Southeastern New Mexico, Utah
and Mississippi.
The North American land drilling industry has experienced
periods of downturn in demand over the last decade. During these
periods, there have been substantially more drilling rigs
available than necessary to meet demand. As a result, drilling
contractors have had difficulty sustaining profit margins during
the downturn periods.
In addition to adverse effects that future declines in demand
could have on us, ongoing factors which could adversely affect
utilization rates and pricing, even in an environment of
stronger oil and natural gas prices and increased drilling
activity, include:
|
|
|
|
|
movement of drilling rigs from region to region,
|
|
|
|
reactivation of land-based drilling rigs, or
|
|
|
|
new construction of drilling rigs.
|
We cannot predict either the future level of demand for our
contract drilling services or future conditions in the oil and
natural gas contract drilling business.
Critical
Accounting Policies
In addition to established accounting policies, our consolidated
financial statements are impacted by certain estimates and
assumptions made by management. No changes in our critical
accounting policies have occurred since the filing of the
Companys Annual Report on
Form 10-K
for the period ended December 31, 2005.
19
Liquidity
and Capital Resources
As of September 30, 2006, we had working capital of
approximately $322 million, including cash and cash
equivalents of $16.9 million. For the nine months ended
September 30, 2006, our significant sources of cash flow
included:
|
|
|
|
|
$614 million provided by operations,
|
|
|
|
$65.0 million in proceeds from borrowings under our line of
credit,
|
|
|
|
$8.0 million in proceeds from disposal of property and
equipment, and
|
|
|
|
$2.3 million from the exercise of stock options and related
tax benefits.
|
During the nine months ended September 30, 2006, we used
$352 million to purchase shares of treasury stock,
$33.3 million to pay dividends on the Companys common
stock and $423 million:
|
|
|
|
|
to make capital expenditures for the betterment and
refurbishment of our drilling rigs,
|
|
|
|
to acquire and procure drilling equipment and facilities to
support our drilling operations,
|
|
|
|
to fund capital expenditures for our pressure pumping and
drilling and completion fluids divisions, and
|
|
|
|
to fund leasehold acquisition and exploration and development of
oil and natural gas properties.
|
On August 2, 2006, the Company entered into an agreement to
amend its $200 million unsecured revolving line of credit
(LOC). In connection with this amendment, the
borrowing capacity under this LOC was increased to
$375 million. No significant changes were made to the terms
of the LOC, including the interest to be paid on outstanding
balances and financial covenants. As of September 30, 2006,
we had borrowed $65.0 million under the LOC and
$60.0 million in letters of credit were outstanding such
that we had available borrowings of $250 million at
September 30, 2006.
On March 2, 2006, the Companys Board of Directors
approved a cash dividend on its common stock in the amount of
$0.04 per share. The dividend of approximately
$6.9 million was paid on March 30, 2006. On
April 26, 2006, the Companys Board of Directors
approved an increase in its quarterly cash dividend from $0.04
to $0.08 on each outstanding share of its common stock. This
dividend of approximately $13.4 million was paid on
June 30, 2006 to holders of record on June 15, 2006.
On August 2, 2006, the Companys Board of Directors
approved a quarterly cash dividend of $0.08 on each outstanding
share of its common stock. This dividend of approximately
$13.0 million was paid on September 29, 2006 to
holders of record as of September 14, 2006. On
October 31, 2006, the Companys Board of Directors
approved a quarterly cash dividend of $0.08 on each outstanding
share of its common stock. The dividend is to be paid on
December 29, 2006 to holders of record as of
December 14, 2006. The amount and timing of all future
dividend payments is subject to the discretion of the Board of
Directors and will depend upon business conditions, results of
operations, financial condition, terms of the Companys
credit facilities and other factors.
On March 27, 2006, the Companys Board of Directors
increased the Companys previously authorized stock buyback
program to allow for future purchases of up to $200 million
of the Companys outstanding common stock. During the
second quarter of 2006, the Company completed the authorized
buyback with the purchase of 6,704,800 shares of its common
stock at a cost of approximately $200 million. On
August 2, 2006, the Companys Board of Directors again
increased the Companys previously authorized stock buyback
program to allow for future purchases of up to $250 million
of the Companys outstanding common stock. During the three
months ended September 30, 2006, the Company purchased
6,537,000 shares of its common stock at a cost of
approximately $167 million. As of September 30, 2006
the Company is authorized to purchase approximately
$83 million of the Companys outstanding common stock
under the stock buyback program. Shares purchased under the
stock buyback program have been accounted for as treasury stock.
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 evaluated. The timing, size
or success of any acquisition and the associated capital
commitments are unpredictable. Should 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, our existing credit facility and
additional debt or equity financing. However, there can be no
assurance that such capital would be available.
20
Results
of Operations
Prior to the adoption of FAS 123(R) on January 1,
2006, the Company accounted for all stock options under the
intrinsic value method. Accordingly, no compensation expense was
recognized in prior periods for stock options because exercise
prices were equal to the grant date market value of the related
common stock. The modified prospective method was applied to
transition from the intrinsic value method to the
fair-value-based
method for stock options (see Note 2 of these Notes to
Unaudited Condensed Consolidated Financial Statements). The use
of the modified prospective method does not result in
adjustments to years prior to the adoption of FAS 123(R)
which impact the comparability of certain items between 2006 and
2005. Incremental stock-based compensation in 2006 resulting
from the adoption of FAS 123(R) is included in selling,
general and administrative expenses in the statements of income.
The following tables summarize operations by business segment
for the three months ended September 30, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract Drilling
|
|
2006
|
|
|
2005
|
|
|
% Change
|
|
|
|
(Dollars in thousands)
|
|
|
Revenues
|
|
$
|
577,047
|
|
|
$
|
401,046
|
|
|
|
43.9
|
%
|
Direct operating costs
|
|
$
|
267,345
|
|
|
$
|
202,956
|
|
|
|
31.7
|
%
|
Selling, general and administrative
|
|
$
|
1,817
|
|
|
$
|
1,286
|
|
|
|
41.3
|
%
|
Depreciation
|
|
$
|
42,961
|
|
|
$
|
33,695
|
|
|
|
27.5
|
%
|
Operating income
|
|
$
|
264,924
|
|
|
$
|
163,109
|
|
|
|
62.4
|
%
|
Operating days
|
|
|
27,725
|
|
|
|
26,015
|
|
|
|
6.6
|
%
|
Average revenue per operating day
|
|
$
|
20.81
|
|
|
$
|
15.42
|
|
|
|
35.0
|
%
|
Average direct operating costs per
operating day
|
|
$
|
9.64
|
|
|
$
|
7.80
|
|
|
|
23.6
|
%
|
Number of owned rigs at end of
period
|
|
|
403
|
|
|
|
403
|
|
|
|
0.0
|
%
|
Average number of rigs owned
during period
|
|
|
403
|
|
|
|
398
|
|
|
|
1.3
|
%
|
Average rigs operating
|
|
|
301
|
|
|
|
283
|
|
|
|
6.4
|
%
|
Rig utilization percentage
|
|
|
75
|
%
|
|
|
71
|
%
|
|
|
5.6
|
%
|
Capital expenditures
|
|
$
|
152,879
|
|
|
$
|
90,114
|
|
|
|
69.7
|
%
|
Revenues and direct operating costs increased as a result of the
increased number of operating days, as well as an increase in
the average revenue and average direct operating costs per
operating day. Operating days and average rigs operating
increased primarily as a result of increased demand for our
contract drilling services and the increase in the number of
marketable rigs in our fleet due to our ongoing rig activation
program. Average revenue per operating day increased as a result
of increased demand and pricing for our drilling services.
Average direct operating costs per operating day increased
primarily as a result of increased compensation costs and an
increase in the cost of maintenance for our rigs. Significant
capital expenditures were incurred during the third quarter of
2006 to activate additional drilling rigs, to modify and upgrade
our existing drilling rigs and to acquire additional related
equipment such as drill pipe, drill collars, engines, fluid
circulating systems, rig hoisting systems and safety enhancement
equipment. The increase in depreciation expense was a result of
significant capital expenditures.
|
|
|
|
|
|
|
|
|
|
|
|
|
Pressure Pumping
|
|
2006
|
|
|
2005
|
|
|
% Change
|
|
|
|
(Dollars in thousands)
|
|
|
Revenues
|
|
$
|
40,462
|
|
|
$
|
27,640
|
|
|
|
46.4
|
%
|
Direct operating costs
|
|
$
|
20,960
|
|
|
$
|
15,662
|
|
|
|
33.8
|
%
|
Selling, general and administrative
|
|
$
|
3,450
|
|
|
$
|
2,464
|
|
|
|
40.0
|
%
|
Depreciation
|
|
$
|
2,559
|
|
|
$
|
1,823
|
|
|
|
40.4
|
%
|
Operating income
|
|
$
|
13,493
|
|
|
$
|
7,691
|
|
|
|
75.4
|
%
|
Total jobs
|
|
|
3,116
|
|
|
|
2,714
|
|
|
|
14.8
|
%
|
Average revenue per job
|
|
$
|
12.99
|
|
|
$
|
10.18
|
|
|
|
27.6
|
%
|
Average direct operating costs per
job
|
|
$
|
6.73
|
|
|
$
|
5.77
|
|
|
|
16.6
|
%
|
Capital expenditures
|
|
$
|
7,692
|
|
|
$
|
5,865
|
|
|
|
31.2
|
%
|
21
Revenues and direct operating costs increased as a result of the
increased number of jobs, as well as an increase in the average
revenue and average direct operating cost per job. The increase
in jobs was attributable to increased demand for our services
and increased operating capacity which has been added in
anticipation of that demand. Increased average revenue per job
was due to increased pricing for our services and an increase in
the number of larger jobs. Average direct operating costs per
job increased as a result of increases in compensation and the
cost of materials used in our operations as well as an increase
in the number of larger jobs. Selling, general and
administrative expense increased as a result of additional
expenses which were necessary to support expanding the
operations of the pressure pumping segment. Increased
depreciation expense was largely due to the expansion of the
pressure pumping segment through capital expenditures.
Significant capital expenditures were incurred during the third
quarter of 2006 to modify and upgrade existing equipment and to
add additional equipment.
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and Completion Fluids
|
|
2006
|
|
|
2005
|
|
|
% Change
|
|
|
|
(Dollars in thousands)
|
|
|
Revenues
|
|
$
|
46,163
|
|
|
$
|
29,819
|
|
|
|
54.8
|
%
|
Direct operating costs
|
|
$
|
36,183
|
|
|
$
|
24,062
|
|
|
|
50.4
|
%
|
Selling, general and administrative
|
|
$
|
2,733
|
|
|
$
|
2,402
|
|
|
|
13.8
|
%
|
Depreciation
|
|
$
|
689
|
|
|
$
|
609
|
|
|
|
13.1
|
%
|
Operating income
|
|
$
|
6,558
|
|
|
$
|
2,746
|
|
|
|
138.8
|
%
|
Total jobs
|
|
|
550
|
|
|
|
485
|
|
|
|
13.4
|
%
|
Average revenue per job
|
|
$
|
83.93
|
|
|
$
|
61.48
|
|
|
|
36.5
|
%
|
Average direct operating costs per
job
|
|
$
|
65.79
|
|
|
$
|
49.61
|
|
|
|
32.6
|
%
|
Capital expenditures
|
|
$
|
1,122
|
|
|
$
|
687
|
|
|
|
63.3
|
%
|
Revenues and direct operating costs increased as a result of
increases in the average revenue and direct operating costs per
job and in the number of total jobs. Average revenue and direct
operating costs per job increased primarily as a result of an
increase in large jobs in the Gulf of Mexico, as well as an
increase in the average size of our smaller land-based jobs.
Selling, general and administrative expense increased primarily
due to increased incentive compensation resulting from higher
profitability levels.
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas Production and Exploration
|
|
2006
|
|
|
2005
|
|
|
% Change
|
|
|
|
(Dollars in thousands,
|
|
|
|
except sales prices)
|
|
|
Revenues
|
|
$
|
9,986
|
|
|
$
|
10,234
|
|
|
|
(2.4
|
)%
|
Direct operating costs
|
|
$
|
3,222
|
|
|
$
|
2,365
|
|
|
|
36.2
|
%
|
Selling, general and administrative
|
|
$
|
684
|
|
|
$
|
545
|
|
|
|
25.5
|
%
|
Depreciation, depletion and
impairment
|
|
$
|
2,804
|
|
|
$
|
3,226
|
|
|
|
(13.1
|
)%
|
Operating income
|
|
$
|
3,276
|
|
|
$
|
4,098
|
|
|
|
(20.1
|
)%
|
Capital expenditures
|
|
$
|
4,982
|
|
|
$
|
3,858
|
|
|
|
29.1
|
%
|
Average net daily oil production
(Bbls)
|
|
|
961
|
|
|
|
869
|
|
|
|
10.6
|
%
|
Average net daily gas production
(Mcf)
|
|
|
4,820
|
|
|
|
6,567
|
|
|
|
(26.6
|
)%
|
Average oil sales price (per Bbl)
|
|
$
|
68.66
|
|
|
$
|
60.42
|
|
|
|
13.6
|
%
|
Average natural gas sales price
(per Mcf)
|
|
$
|
6.77
|
|
|
$
|
7.75
|
|
|
|
(12.6
|
)%
|
Revenues decreased due to a decrease in the net daily production
and sales price of natural gas. Average net daily natural gas
production decreased as a result of production declines and the
sale of certain natural gas properties. Direct operating costs
increased due primarily to approximately $608,000 in costs
associated with the abandonment of an exploratory well.
Depreciation, depletion and impairment expense includes
approximately
22
$889,000 and $702,000 incurred during the three months ended
September 30, 2006 and 2005, respectively, to impair
certain oil and natural gas properties.
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and Other
|
|
2006
|
|
|
2005
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
Selling, general and administrative
|
|
$
|
5,093
|
|
|
$
|
3,868
|
|
|
|
31.7
|
%
|
Depreciation
|
|
$
|
202
|
|
|
$
|
192
|
|
|
|
5.2
|
%
|
Other operating expenses
|
|
$
|
2,563
|
|
|
$
|
707
|
|
|
|
262.5
|
%
|
Embezzlement costs, net of
recoveries
|
|
$
|
(1,512
|
)
|
|
$
|
5,431
|
|
|
|
N/A
|
%
|
Interest income
|
|
$
|
948
|
|
|
$
|
944
|
|
|
|
0.4
|
%
|
Interest expense
|
|
$
|
363
|
|
|
$
|
56
|
|
|
|
548.2
|
%
|
Other income
|
|
$
|
88
|
|
|
$
|
19
|
|
|
|
363.2
|
%
|
Selling, general and administrative expense increased primarily
as a result of compensation expense related to the adoption of a
new accounting standard in 2006 requiring the expensing of stock
options. Other operating expenses in 2005 include approximately
$675,000 in charges to increase reserves related to the
financial failure of a workers compensation insurance
carrier used previously by the Company, approximately $200,000
related to losses incurred as a result of Hurricane Katrina and
approximately $50,000 in bad debt expense reduced by
approximately $218,000 in gains on the disposal of certain
assets. Other operating expenses in 2006 include approximately
$3.0 million in bad debt expense reduced by approximately
$437,000 in gains associated with the disposal of certain
assets. Embezzlement costs, net of recoveries in 2005 includes
payments made to or for the benefit of Jonathan D. Nelson, our
former CFO, for assets and services that were not received by
the Company and in 2006 includes continuing professional and
other costs related to the embezzlement, net of insurance
proceeds of $2.0 million received in connection with the
loss. Interest expense in 2006 increased due to borrowings under
our line of credit during the third quarter of 2006.
The following tables summarize operations by business segment
for the nine months ended September 30, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract Drilling
|
|
2006
|
|
|
2005
|
|
|
% Change
|
|
|
|
(Dollars in thousands)
|
|
|
Revenues
|
|
$
|
1,616,100
|
|
|
$
|
1,025,938
|
|
|
|
57.5
|
%
|
Direct operating costs
|
|
$
|
737,021
|
|
|
$
|
558,607
|
|
|
|
31.9
|
%
|
Selling, general and administrative
|
|
$
|
5,338
|
|
|
$
|
3,701
|
|
|
|
44.2
|
%
|
Depreciation
|
|
$
|
121,764
|
|
|
$
|
95,909
|
|
|
|
27.0
|
%
|
Operating income
|
|
$
|
751,977
|
|
|
$
|
367,721
|
|
|
|
104.5
|
%
|
Operating days
|
|
|
81,489
|
|
|
|
73,746
|
|
|
|
10.5
|
%
|
Average revenue per operating day
|
|
$
|
19.83
|
|
|
$
|
13.91
|
|
|
|
42.6
|
%
|
Average direct operating costs per
operating day
|
|
$
|
9.04
|
|
|
$
|
7.57
|
|
|
|
19.4
|
%
|
Number of owned rigs at end of
period
|
|
|
403
|
|
|
|
403
|
|
|
|
0.0
|
%
|
Average number of rigs owned
during period
|
|
|
403
|
|
|
|
395
|
|
|
|
2.0
|
%
|
Average rigs operating
|
|
|
298
|
|
|
|
270
|
|
|
|
10.4
|
%
|
Rig utilization percentage
|
|
|
74
|
%
|
|
|
68
|
%
|
|
|
8.8
|
%
|
Capital expenditures
|
|
$
|
377,165
|
|
|
$
|
222,492
|
|
|
|
69.5
|
%
|
Revenues and direct operating costs increased as a result of the
increased number of operating days, as well as an increase in
the average revenue and average direct operating costs per
operating day. Operating days and average rigs operating
increased primarily as a result of increased demand for our
contract drilling services and the increase in the number of
marketable rigs in our fleet due to our ongoing rig activation
program. Average revenue per operating day increased as a result
of increased demand and pricing for our drilling services.
Average direct operating costs per operating day increased
primarily as a result of increased compensation costs and an
increase in the cost of maintenance for our rigs. Selling,
general and administrative expense increased due to additional
personnel and other costs to support the increased level of
activity in the contract drilling segment. Significant capital
expenditures were incurred in 2006 to activate additional
drilling rigs, to modify and upgrade our existing drilling rigs
and to acquire additional related equipment such as drill pipe,
drill collars, engines, fluid circulating
23
systems, rig hoisting systems and safety enhancement equipment.
Increased depreciation expense was due to capital expenditures.
|
|
|
|
|
|
|
|
|
|
|
|
|
Pressure Pumping
|
|
2006
|
|
|
2005
|
|
|
% Change
|
|
|
|
(Dollars in thousands)
|
|
|
Revenues
|
|
$
|
107,800
|
|
|
$
|
66,358
|
|
|
|
62.5
|
%
|
Direct operating costs
|
|
$
|
56,545
|
|
|
$
|
38,648
|
|
|
|
46.3
|
%
|
Selling, general and administrative
|
|
$
|
9,588
|
|
|
$
|
6,858
|
|
|
|
39.8
|
%
|
Depreciation
|
|
$
|
7,075
|
|
|
$
|
5,073
|
|
|
|
39.5
|
%
|
Operating income
|
|
$
|
34,592
|
|
|
$
|
15,779
|
|
|
|
119.2
|
%
|
Total jobs
|
|
|
8,844
|
|
|
|
6,968
|
|
|
|
26.9
|
%
|
Average revenue per job
|
|
$
|
12.19
|
|
|
$
|
9.52
|
|
|
|
28.0
|
%
|
Average direct operating costs per
job
|
|
$
|
6.39
|
|
|
$
|
5.55
|
|
|
|
15.1
|
%
|
Capital expenditures
|
|
$
|
27,371
|
|
|
$
|
20,598
|
|
|
|
32.9
|
%
|
Revenues and direct operating costs increased as a result of the
increased number of jobs, as well as an increase in the average
revenue and average direct operating cost per job. The increase
in jobs was attributable to increased demand for our services
and increased operating capacity which has been added. Increased
average revenue per job was due to increased pricing for our
services and an increase in the number of larger jobs. Average
direct operating costs per job increased as a result of
increases in compensation and the cost of materials used in our
operations as well as an increase in the number of larger jobs.
Selling, general and administrative expense increased as a
result of additional expenses which were necessary to support
expanding the operations of the pressure pumping segment.
Increased depreciation expense was largely due to the expansion
of the pressure pumping segment through capital expenditures.
Significant capital expenditures were incurred during 2006 to
modify and upgrade existing equipment and to add additional
equipment.
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and Completion Fluids
|
|
2006
|
|
|
2005
|
|
|
% Change
|
|
|
|
(Dollars in thousands)
|
|
|
Revenues
|
|
$
|
155,221
|
|
|
$
|
88,812
|
|
|
|
74.8
|
%
|
Direct operating costs
|
|
$
|
120,418
|
|
|
$
|
71,857
|
|
|
|
67.6
|
%
|
Selling, general and administrative
|
|
$
|
7,765
|
|
|
$
|
6,964
|
|
|
|
11.5
|
%
|
Depreciation
|
|
$
|
2,000
|
|
|
$
|
1,730
|
|
|
|
15.6
|
%
|
Operating income
|
|
$
|
25,038
|
|
|
$
|
8,261
|
|
|
|
203.1
|
%
|
Total jobs
|
|
|
1,569
|
|
|
|
1,515
|
|
|
|
3.6
|
%
|
Average revenue per job
|
|
$
|
98.93
|
|
|
$
|
58.62
|
|
|
|
68.8
|
%
|
Average direct operating costs per
job
|
|
$
|
76.75
|
|
|
$
|
47.43
|
|
|
|
61.8
|
%
|
Capital expenditures
|
|
$
|
3,052
|
|
|
$
|
2,039
|
|
|
|
49.7
|
%
|
Revenues and direct operating costs increased primarily as a
result of increases in the average revenue and direct operating
costs per job. Average revenue and direct operating costs per
job increased primarily as a result of an increase in large jobs
in the Gulf of Mexico, as well as an increase in the average
size of our smaller land-based
24
jobs. Selling, general and administrative expense increased in
2006 primarily due to increased incentive compensation resulting
from higher profitability levels.
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas Production and Exploration
|
|
2006
|
|
|
2005
|
|
|
% Change
|
|
|
|
(Dollars in thousands,
|
|
|
|
except sales prices)
|
|
|
Revenues
|
|
$
|
29,083
|
|
|
$
|
28,146
|
|
|
|
3.3
|
%
|
Direct operating costs
|
|
$
|
11,241
|
|
|
$
|
6,953
|
|
|
|
61.7
|
%
|
Selling, general and administrative
|
|
$
|
2,050
|
|
|
$
|
1,598
|
|
|
|
28.3
|
%
|
Depreciation, depletion and
impairment
|
|
$
|
8,815
|
|
|
$
|
9,063
|
|
|
|
(2.7
|
)%
|
Operating income
|
|
$
|
6,977
|
|
|
$
|
10,532
|
|
|
|
(33.8
|
)%
|
Capital expenditures
|
|
$
|
15,699
|
|
|
$
|
12,286
|
|
|
|
27.8
|
%
|
Average net daily oil production
(Bbls)
|
|
|
944
|
|
|
|
854
|
|
|
|
10.5
|
%
|
Average net daily gas production
(Mcf)
|
|
|
4,986
|
|
|
|
7,465
|
|
|
|
(33.2
|
)%
|
Average oil sales price (per Bbl)
|
|
$
|
66.24
|
|
|
$
|
52.92
|
|
|
|
25.2
|
%
|
Average natural gas sales price
(per Mcf)
|
|
$
|
6.96
|
|
|
$
|
6.63
|
|
|
|
5.0
|
%
|
Revenues increased slightly due to an increase in the net daily
production and sales price of oil which was offset by a decrease
in the net daily production of natural gas. Average net daily
natural gas production decreased as a result of production
declines and the sale of certain natural gas properties during
2005. The increase in direct operating costs includes a charge
of $3.1 million associated with the abandonment of
exploratory wells in 2006. Depreciation, depletion and
impairment expense includes approximately $2.2 million and
$1.5 million incurred during the nine months ended
September 30, 2006 and 2005, respectively, to impair
certain oil and natural gas properties.
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and Other
|
|
2006
|
|
|
2005
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
Selling, general and administrative
|
|
$
|
14,687
|
|
|
$
|
11,036
|
|
|
|
33.1
|
%
|
Depreciation
|
|
$
|
591
|
|
|
$
|
544
|
|
|
|
8.6
|
%
|
Other operating expenses
|
|
$
|
3,948
|
|
|
$
|
2,590
|
|
|
|
52.4
|
%
|
Embezzlement costs, net of
recoveries
|
|
$
|
2,941
|
|
|
$
|
12,193
|
|
|
|
(75.9
|
)%
|
Interest income
|
|
$
|
5,579
|
|
|
$
|
2,011
|
|
|
|
177.4
|
%
|
Interest expense
|
|
$
|
476
|
|
|
$
|
179
|
|
|
|
165.9
|
%
|
Other income
|
|
$
|
231
|
|
|
$
|
39
|
|
|
|
492.3
|
%
|
Capital Expenditures
|
|
$
|
135
|
|
|
$
|
5,308
|
|
|
|
(97.5
|
)%
|
Selling, general and administrative expense increased primarily
as a result of compensation expense related to the adoption of a
new accounting standard in 2006 requiring the expensing of stock
options. Other operating expenses in 2005 include approximately
$1.3 million in gains recognized on the sale of certain oil
and natural gas properties and other equipment reduced by
approximately $3.2 million in charges to increase reserves
related to the financial failure of a workers compensation
insurance carrier used previously by the Company, approximately
$200,000 related to losses incurred as a result of Hurricane
Katrina and approximately $416,000 in bad debt expenses. Other
operating expenses in 2006 include approximately
$4.2 million in bad debt expense reduced by gains
associated with the disposal of certain assets. Interest income
increased as a result of higher cash balances and improvements
in interest rates in 2006. Interest expense in 2006 increased
due to borrowings under our line of credit during the third
quarter of 2006. Embezzlement costs, net of recoveries in 2005
includes payments made to or for the benefit of Jonathan D.
Nelson, our former CFO, for assets and services that were not
received by the Company and in 2006 includes continuing
professional and other costs related to the embezzlement, net of
insurance proceeds of $2.0 million received in connection
with the loss.
Recently
Issued Accounting Standards
In June 2006, the FASB issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes an
interpretation of FASB Statement No. 109
(FIN 48). FIN 48 clarifies the accounting
for uncertainty in income taxes recognized in an
enterprises financial statements and prescribes a
recognition threshold and measurement attribute for the
financial statement recognition and measurement of a tax
position taken or expected to be taken in a
25
tax return. FIN 48 is effective for fiscal years beginning
after December 15, 2006 and will be effective for the
Company as of January 1, 2007. The application of this
standard is not expected to be material.
In September 2006, the FASB issued Statement No. 157,
Fair Value Measurements (FAS 157).
FAS 157 defines fair value, establishes a framework for
measuring fair value in generally accepted accounting
principles, and expands disclosures about fair value
measurement. FAS 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007
and interim periods within those fiscal years. FAS 157 will
be effective for the Company in the quarter ending
March 31, 2008. The application of FAS 157 is not
expected to have a material impact to the Company.
In September 2006, the SEC staff issued Staff Accounting
Bulletin No. 108, Considering the Effects of Prior
Year Misstatements when Quantifying Misstatements in Current
Year Financial Statements (SAB 108).
SAB 108 was issued in order to eliminate the diversity of
practice surrounding how public companies quantify financial
statement misstatements. Traditionally, there have been two
widely-recognized methods for quantifying the effects of
financial statement misstatements. The roll-over
method focuses primarily on the impact of a misstatement on the
income statement (including the reversing effect of prior year
misstatements) but its use can lead to the accumulation of
misstatements in the balance sheet. The iron-curtain
method, on the other hand, focuses primarily on the effect of
correcting the period-end balance sheet with less emphasis on
the reversing effects of prior year errors on the income
statement. The Company currently uses the iron-curtain method
for quantifying identified financial statement misstatements. In
SAB 108, the SEC staff established an approach that
requires quantification of financial statement misstatements
based on the effects of the misstatements on each of the
companys financial statements and the related financial
statement disclosures. This model is commonly referred to as a
dual approach because it requires quantification of
errors under both the iron curtain and the roll-over methods.
The Company will apply the provisions of SAB 108 in the
quarter ending December 31, 2006 and the impact is not
expected to be material.
Volatility
of Oil and Natural Gas Prices and its Impact on
Operations
Our revenue, profitability, and rate of growth are substantially
dependent upon prevailing prices for oil and natural gas, with
respect to all of our operating segments. For many years, oil
and natural gas prices and markets have been volatile. Prices
are affected by market supply and demand factors as well as
international military, political and economic conditions, and
the ability of OPEC to set and maintain production and price
targets. All of these factors are beyond our control. Natural
gas prices fell from an average of $6.23 per Mcf in the
first quarter of 2001 to an average of $2.51 per Mcf for
the same period in 2002. During this same period, the average
number of our rigs operating dropped by approximately 50%. The
average market price of natural gas improved from $3.36 in 2002
to $6.77 in the third quarter of 2006, resulting in an increase
in demand for our drilling services. Our average number of rigs
operating increased from 126 in 2002 to 301 in the third quarter
of 2006. We expect oil and natural gas prices to continue to be
volatile and to affect our financial condition and operations
and ability to access sources of capital. A significant decrease
in expected market prices for natural gas could result in a
material decrease in demand for drilling rigs and reduction in
our operation results.
The North American land drilling industry has experienced many
downturns in demand over the last decade. During these periods,
there have been substantially more drilling rigs available than
necessary to meet demand. As a result, drilling contractors have
had difficulty sustaining profit margins during the downturn
periods.
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 exposure to interest rate market risk
associated with borrowings under our credit facility. The
revolving credit facility calls for periodic interest payments
at a floating rate ranging from LIBOR plus 0.625% to 1.0% or at
the prime rate. The applicable rate above LIBOR is based upon
our debt to capitalization ratio. Our exposure to interest rate
risk due to changes in the prime rate or LIBOR is not 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
during the last several years. If the value of
26
the Canadian dollar against the U.S. dollar weakens,
revenues and earnings of our Canadian operations will be reduced
and the value of our Canadian net assets will decline when they
are translated to U.S. dollars.
ITEM 4. Controls
and Procedures
Disclosure Controls and Procedures We
maintain disclosure controls and procedures (as such terms are
defined in
Rules 13a-15(e)
and
15d-15(e)
promulgated under the Securities Exchange Act of 1934, as
amended (the Exchange Act)) designed to ensure that
the information required to be disclosed in the reports that we
file with the SEC under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in the
SECs rules and forms, and that such information is
accumulated and communicated to our management, including our
Chief Executive Officer (CEO) and Chief Financial
Officer (CFO), as appropriate, to allow timely
decisions regarding required disclosure.
Under the supervision and with the participation of our
management, including our CEO and CFO, we conducted an
evaluation of the effectiveness of our disclosure controls and
procedures as of the end of the period covered by this Quarterly
Report on
Form 10-Q.
Based on that evaluation, and due to the material weaknesses in
the Companys internal control over financial reporting as
reported in the Companys Annual Report on
Form 10-K
for the year ended December 31, 2005, our CEO and CFO
concluded that our disclosure controls and procedures were not
effective at a reasonable level of assurance, as of
September 30, 2006. For a discussion of the material
weaknesses, see Item 9A of our Annual Report on
Form 10-K
for the year ended December 31, 2005.
Changes in Internal Control Over Financial
Reporting Our management is responsible for
establishing and maintaining adequate internal control over
financial reporting as such term is defined in Exchange Act
Rule 13a-15(f).
With the participation of our CEO and CFO, our management
evaluates any changes in our internal control over financial
reporting that occurred during each fiscal quarter which have
materially affected, or are reasonably likely to materially
affect, such internal control. At December 31, 2005, the
Companys assessment of the effectiveness of its internal
control over financial reporting concluded that material
weaknesses in its control environment and controls over property
and equipment existed. During the first nine months of 2006, the
Company has implemented, or is in the process of implementing,
remediation steps to address these material weaknesses. You can
find more information about these material weaknesses and the
actions that we have taken and are planning to take to remediate
the material weaknesses in Item 9A of our Annual Report on
Form 10-K
for the year ended December 31, 2005.
There were no changes in the Companys internal control
over financial reporting during its most recently completed
fiscal quarter that have materially affected or are reasonably
likely to materially affect its internal control over financial
reporting, as defined in
Rule 13a-15(f)
under the Exchange Act.
FORWARD
LOOKING STATEMENTS AND CAUTIONARY STATEMENTS FOR PURPOSES OF
THE SAFE HARBOR PROVISIONS OF THE PRIVATE
SECURITIES
LITIGATION REFORM ACT OF 1995
Managements 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:
|
|
|
|
|
Changes in prices and demand for oil and natural gas;
|
|
|
|
Changes in demand for contract drilling, pressure pumping and
drilling and completion fluids services;
|
27
|
|
|
|
|
Shortages of drill pipe and other drilling equipment;
|
|
|
|
Labor shortages, primarily qualified drilling personnel;
|
|
|
|
Effects of competition from other drilling contractors and
providers of pressure pumping and drilling and completion fluids
services;
|
|
|
|
Occurrence of operating hazards and uninsured losses inherent in
our business operations; and
|
|
|
|
Environmental and other governmental regulation.
|
For a more complete explanation of these factors and others, see
Risk Factors included as Item 1A in our Annual
Report on
Form 10-K
for the year ended December 31, 2005, beginning on
page 11.
You are cautioned not to place undue reliance on any of our
forward-looking statements, which speak only as of the date of
this Report or, in the case of documents incorporated by
reference, the date of those documents.
28
PART II
OTHER INFORMATION
ITEM 2. Unregistered
Sales of Equity Securities and Use of Proceeds
The table below sets forth the information with respect to
purchases of our common stock made by the Company during the
quarter ended September 30, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Approximate Dollar
|
|
|
|
|
|
|
|
|
|
Total Number of
|
|
|
Value of Shares
|
|
|
|
|
|
|
|
|
|
Shares (or Units)
|
|
|
That May yet be
|
|
|
|
|
|
|
|
|
|
Purchased as Part
|
|
|
Purchased Under the
|
|
|
|
Total
|
|
|
Average Price
|
|
|
of Publicly
|
|
|
Plans or
|
|
|
|
Number of Shares
|
|
|
Paid per
|
|
|
Announced Plans
|
|
|
Programs (in
|
|
Period Covered
|
|
Purchased(1)
|
|
|
Share
|
|
|
or Programs(2)
|
|
|
thousands)(2)
|
|
|
July 1-31, 2006
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
August 1-31, 2006
|
|
|
2,887,000
|
|
|
$
|
27.16
|
|
|
|
2,887,000
|
|
|
$
|
171,587
|
|
September 1-30, 2006
|
|
|
3,650,000
|
|
|
$
|
24.18
|
|
|
|
3,650,000
|
|
|
$
|
83,324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
6,537,000
|
|
|
$
|
25.50
|
|
|
|
6,537,000
|
|
|
$
|
83,324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All of the reported shares were purchased in open-market
transactions. |
|
(2) |
|
On June 7, 2004, our Board of Directors authorized a stock
buyback program for the purchase of up to $30 million of
our outstanding common stock, which repurchases could be made
from time to time as, in the opinion of management, market
conditions warranted, in the open market or in privately
negotiated transactions. On March 27, 2006, our Board of
Directors increased the stock buyback program to allow the
future purchases of up to $200 million of our outstanding
common stock. As of June 30, 2006, the purchases under this
program had been completed, and on August 2, 2006, the
Companys Board of Directors authorized an increase in the
size of the previously approved stock buyback program to allow
for future purchases of up to $250 million of the
Companys outstanding common stock. |
|
|
ITEM 4.
|
Submission
of Matters to a Vote of Security Holders
|
On July 12, 2006, the Company held its Annual Meeting of
Stockholders. At the meeting, the stockholders voted on the
election of eight persons to serve as directors of the Company.
The eight nominees to the Board of Directors of the Company were
elected at the meeting. The number of votes cast for or
withheld, were as follows:
|
|
|
|
|
|
|
|
|
|
|
Votes For
|
|
|
Votes Withheld
|
|
|
Mark S. Siegel
|
|
|
147,055,845
|
|
|
|
4,169,682
|
|
Cloyce A. Talbott
|
|
|
148,290,667
|
|
|
|
2,934,860
|
|
Kenneth N. Berns
|
|
|
144,213,982
|
|
|
|
7,011,545
|
|
Robert C. Gist
|
|
|
144,100,153
|
|
|
|
7,125,374
|
|
Curtis W. Huff
|
|
|
148,128,445
|
|
|
|
3,097,082
|
|
Terry H. Hunt
|
|
|
149,970,941
|
|
|
|
1,254,586
|
|
Kenneth R. Peak
|
|
|
144,035,789
|
|
|
|
7,189,738
|
|
Nadine C. Smith
|
|
|
144,001,236
|
|
|
|
7,224,291
|
|
|
|
ITEM 5.
|
Other
Information
|
None.
(a) Exhibits.
29
The following exhibits are filed herewith or incorporated by
reference, as indicated:
|
|
|
|
|
|
3
|
.1
|
|
Restated Certificate of
Incorporation, as amended (filed August 9, 2004 as
Exhibit 3.1 to the Companys Quarterly Report on
Form 10-Q
for the quarterly period ended June 30, 2004 and
incorporated herein by reference).
|
|
3
|
.2
|
|
Amendment to Restated Certificate
of Incorporation, as amended (filed August 9, 2004 as
Exhibit 3.2 to the Companys Quarterly Report on
Form 10-Q
for the quarterly period ended June 30, 2004 and
incorporated herein by reference).
|
|
3
|
.3
|
|
Amended and Restated Bylaws (filed
March 19, 2002 as Exhibit 3.2 to the Companys
Annual Report on
Form 10-K
for the fiscal year ended December 31, 2001 and
incorporated herein by reference).
|
|
10
|
.1
|
|
Commitment Increase and Joinder
Agreement, dated as of August 2, 2006, by and among
Patterson-UTI Energy, Inc., the guarantors party thereto, the
lenders party thereto, and Bank of America, N.A. as
Administrative Agent, L/C Issuer and Lender (filed
August 21, 2006 as Exhibit 10.1 to the Companys
Current Report on
Form 8-K
and incorporated herein by reference).
|
|
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.
|
30
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.
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By:
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/s/ Cloyce
A. Talbott
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Cloyce A. Talbott
(Principal Executive Officer)
President & Chief Executive Officer
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By:
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/s/ John
E. Vollmer III
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John E. Vollmer III
(Principal Financial and Accounting Officer)
Senior Vice President-Corporate Development,
Chief Financial Officer, Secretary and Treasurer
DATED: November 6, 2006
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