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 |
For the quarterly period ended June 30, 2008
or
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 0-22664
Patterson-UTI Energy, Inc.
(Exact name of registrant as specified in its charter)
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DELAWARE
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75-2504748 |
(State or other jurisdiction of
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(I.R.S. Employer |
incorporation or organization)
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Identification No.) |
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450 GEARS ROAD, SUITE 500 |
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HOUSTON, TEXAS
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77067 |
(Address of principal executive offices)
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(Zip Code) |
(281) 765-7100
(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, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act: (Check one)
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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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.
156,635,799 shares of common stock, $0.01 par value, as of July 31, 2008
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
PART I FINANCIAL INFORMATION
ITEM 1. Financial Statements
The following unaudited consolidated financial statements include all adjustments which are,
in the opinion of management, necessary for a fair statement of the results for the interim periods
presented.
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(unaudited, in thousands, except share data)
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June 30, |
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December 31, |
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2008 |
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2007 |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
62,232 |
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$ |
17,434 |
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Accounts receivable, net of allowance for doubtful accounts of $10,162 at
June 30, 2008 and $10,014 at December 31, 2007 |
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391,652 |
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373,279 |
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Accrued Federal and state income taxes receivable |
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18,445 |
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Inventory |
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39,888 |
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44,416 |
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Deferred tax assets, net |
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33,930 |
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35,370 |
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Other |
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63,512 |
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52,286 |
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Total current assets |
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609,659 |
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522,785 |
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Property and equipment, net |
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1,873,511 |
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1,841,404 |
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Goodwill |
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96,198 |
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96,198 |
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Other |
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4,589 |
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4,812 |
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Total assets |
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$ |
2,583,957 |
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$ |
2,465,199 |
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LIABILITIES AND STOCKHOLDERS EQUITY |
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Current liabilities: |
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Accounts payable |
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$ |
151,674 |
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$ |
156,916 |
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Accrued Federal and state income taxes payable |
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1,458 |
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Accrued expenses |
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122,828 |
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136,834 |
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Total current liabilities |
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274,502 |
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295,208 |
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Borrowings under line of credit |
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50,000 |
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Deferred tax liabilities, net |
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247,597 |
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219,490 |
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Other |
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5,569 |
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4,471 |
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Total liabilities |
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527,668 |
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569,169 |
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Commitments and contingencies (see Note 10) |
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Stockholders equity: |
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Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued |
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Common stock, par value $.01; authorized 300,000,000 shares with 180,216,614
and 177,385,808 issued and 156,619,765 and 153,942,800 outstanding at June
30, 2008 and December 31, 2007, respectively |
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1,802 |
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1,773 |
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Additional paid-in capital |
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755,124 |
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703,581 |
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Retained earnings |
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1,831,947 |
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1,716,620 |
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Accumulated other comprehensive income |
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18,126 |
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20,207 |
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Treasury stock, at cost, 23,596,849 and 23,443,008 shares at June 30, 2008
and December 31, 2007, respectively |
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(550,710 |
) |
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(546,151 |
) |
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Total stockholders equity |
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2,056,289 |
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1,896,030 |
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Total liabilities and stockholders equity |
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$ |
2,583,957 |
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$ |
2,465,199 |
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The accompanying notes are an integral part of these unaudited consolidated financial statements.
1
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(unaudited, in thousands, except per share amounts)
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Three Months Ended |
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Six Months Ended |
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June 30, |
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June 30, |
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2008 |
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2007 |
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2008 |
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2007 |
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Operating revenues: |
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Contract drilling |
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$ |
416,835 |
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$ |
419,191 |
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$ |
836,984 |
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$ |
886,689 |
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Pressure pumping |
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57,094 |
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51,592 |
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99,958 |
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90,176 |
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Drilling and completion fluids |
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38,745 |
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39,667 |
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71,295 |
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70,427 |
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Oil and natural gas |
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13,609 |
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12,108 |
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22,600 |
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22,367 |
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526,283 |
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522,558 |
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1,030,837 |
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1,069,659 |
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Operating costs and expenses: |
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Contract drilling |
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251,381 |
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228,297 |
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495,748 |
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474,451 |
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Pressure pumping |
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32,506 |
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25,777 |
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61,011 |
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46,928 |
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Drilling and completion fluids |
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31,449 |
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32,628 |
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59,982 |
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58,019 |
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Oil and natural gas |
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3,529 |
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2,461 |
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5,596 |
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5,739 |
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Depreciation, depletion and impairment |
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65,673 |
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59,947 |
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129,399 |
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115,878 |
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Selling, general and administrative |
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17,747 |
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16,322 |
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34,743 |
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30,991 |
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Embezzlement costs (recoveries) |
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(41,935 |
) |
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(41,935 |
) |
Gain on disposal of assets |
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(2,721 |
) |
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(16,475 |
) |
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(2,535 |
) |
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(16,273 |
) |
Other operating expenses |
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300 |
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400 |
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600 |
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1,000 |
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399,864 |
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307,422 |
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|
784,544 |
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674,798 |
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Operating income |
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126,419 |
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215,136 |
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246,293 |
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394,861 |
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Other income (expense): |
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Interest income |
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493 |
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|
457 |
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|
836 |
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|
826 |
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Interest expense |
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(63 |
) |
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(831 |
) |
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(340 |
) |
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(1,594 |
) |
Other |
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|
353 |
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|
109 |
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|
737 |
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|
203 |
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|
|
|
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|
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|
783 |
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(265 |
) |
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|
1,233 |
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(565 |
) |
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Income before income taxes |
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127,202 |
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|
214,871 |
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247,526 |
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394,296 |
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Income tax expense: |
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|
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|
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|
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Current |
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29,229 |
|
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|
56,350 |
|
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|
57,941 |
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|
109,783 |
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Deferred |
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|
16,551 |
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|
18,970 |
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|
30,754 |
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|
|
29,161 |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45,780 |
|
|
|
75,320 |
|
|
|
88,695 |
|
|
|
138,944 |
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|
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Net income |
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$ |
81,422 |
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$ |
139,551 |
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$ |
158,831 |
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$ |
255,352 |
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Net income per common share: |
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Basic |
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$ |
0.53 |
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|
$ |
0.90 |
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$ |
1.04 |
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$ |
1.64 |
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Diluted |
|
$ |
0.52 |
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|
$ |
0.88 |
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$ |
1.02 |
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$ |
1.62 |
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Weighted average number of common shares outstanding: |
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Basic |
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|
153,978 |
|
|
|
155,527 |
|
|
|
153,289 |
|
|
|
155,457 |
|
|
|
|
|
|
|
|
|
|
|
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Diluted |
|
|
156,437 |
|
|
|
157,912 |
|
|
|
155,766 |
|
|
|
157,580 |
|
|
|
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|
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|
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|
|
|
|
|
|
|
|
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Cash dividends per common share |
|
$ |
0.16 |
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|
$ |
0.12 |
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$ |
0.28 |
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$ |
0.20 |
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|
|
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|
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|
The accompanying notes are an integral part of these unaudited consolidated financial statements.
2
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS EQUITY
(unaudited, in thousands)
|
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|
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|
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Accumulated |
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Common Stock |
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Additional |
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Other |
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Number of |
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Paid-in |
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Retained |
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Comprehensive |
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Treasury |
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Shares |
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Amount |
|
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Capital |
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Earnings |
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Income |
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|
Stock |
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|
Total |
|
Balance, December 31, 2007 |
|
|
177,386 |
|
|
$ |
1,773 |
|
|
$ |
703,581 |
|
|
$ |
1,716,620 |
|
|
$ |
20,207 |
|
|
$ |
(546,151 |
) |
|
$ |
1,896,030 |
|
Issuance of restricted stock |
|
|
577 |
|
|
|
6 |
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|
(6 |
) |
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Forfeitures of restricted shares |
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|
(30 |
) |
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|
|
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|
Exercise of stock options |
|
|
2,284 |
|
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|
23 |
|
|
|
25,344 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,367 |
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
10,137 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,137 |
|
Tax benefit related to
stock-based compensation |
|
|
|
|
|
|
|
|
|
|
16,068 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,068 |
|
Foreign currency translation
adjustment, net of tax of
$1,206 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,081 |
) |
|
|
|
|
|
|
(2,081 |
) |
Payment of cash dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(43,504 |
) |
|
|
|
|
|
|
|
|
|
|
(43,504 |
) |
Purchase of treasury stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,559 |
) |
|
|
(4,559 |
) |
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
158,831 |
|
|
|
|
|
|
|
|
|
|
|
158,831 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2008 |
|
|
180,217 |
|
|
$ |
1,802 |
|
|
$ |
755,124 |
|
|
$ |
1,831,947 |
|
|
$ |
18,126 |
|
|
$ |
(550,710 |
) |
|
$ |
2,056,289 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
The accompanying notes are an integral part of these unaudited consolidated financial statements.
3
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS
(unaudited, in thousands)
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
|
2008 |
|
|
2007 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Net income |
|
$ |
158,831 |
|
|
$ |
255,352 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and impairment |
|
|
129,399 |
|
|
|
115,878 |
|
Provision for bad debts |
|
|
600 |
|
|
|
1,000 |
|
Dry holes and abandonments |
|
|
600 |
|
|
|
786 |
|
Deferred income tax expense |
|
|
30,754 |
|
|
|
29,161 |
|
Stock-based compensation expense |
|
|
10,137 |
|
|
|
8,416 |
|
Gain on disposal of assets |
|
|
(2,535 |
) |
|
|
(16,273 |
) |
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(19,609 |
) |
|
|
90,703 |
|
Embezzlement recovery receivable |
|
|
|
|
|
|
(42,500 |
) |
Income taxes receivable/payable |
|
|
(19,923 |
) |
|
|
6,427 |
|
Inventory and other current assets |
|
|
(2,912 |
) |
|
|
14,352 |
|
Accounts payable |
|
|
14,929 |
|
|
|
6,876 |
|
Accrued expenses |
|
|
(13,960 |
) |
|
|
(18,864 |
) |
Other liabilities |
|
|
(13,035 |
) |
|
|
(4,730 |
) |
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
273,276 |
|
|
|
446,584 |
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Purchases of property and equipment |
|
|
(176,162 |
) |
|
|
(325,592 |
) |
Proceeds from disposal of assets |
|
|
4,429 |
|
|
|
26,803 |
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(171,733 |
) |
|
|
(298,789 |
) |
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Purchases of treasury stock |
|
|
(4,559 |
) |
|
|
(415 |
) |
Dividends paid |
|
|
(43,504 |
) |
|
|
(31,387 |
) |
Tax benefit related to stock-based compensation |
|
|
16,068 |
|
|
|
1,060 |
|
Proceeds from borrowings under line of credit |
|
|
|
|
|
|
82,500 |
|
Repayment of borrowings under line of credit |
|
|
(50,000 |
) |
|
|
(187,500 |
) |
Proceeds from exercise of stock options |
|
|
25,367 |
|
|
|
934 |
|
|
|
|
|
|
|
|
Net cash used in financing activities |
|
|
(56,628 |
) |
|
|
(134,808 |
) |
|
|
|
|
|
|
|
Effect of foreign exchange rate changes on cash |
|
|
(117 |
) |
|
|
1,103 |
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
|
44,798 |
|
|
|
14,090 |
|
Cash and cash equivalents at beginning of period |
|
|
17,434 |
|
|
|
13,385 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
62,232 |
|
|
$ |
27,475 |
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow information: |
|
|
|
|
|
|
|
|
Net cash paid during the period for: |
|
|
|
|
|
|
|
|
Interest expense |
|
$ |
444 |
|
|
$ |
1,194 |
|
Income taxes |
|
$ |
60,025 |
|
|
$ |
96,759 |
|
The accompanying notes are an integral part of these unaudited consolidated financial statements.
4
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of Consolidation and Presentation
The interim unaudited 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 Company has no controlling financial interests
in any entity that is not a wholly-owned subsidiary and which would require consolidation.
The interim 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 either on the face of the financial statements or herein are sufficient to make the
information presented not misleading. In the opinion of management, all adjustments which are of a
normal recurring nature considered necessary for a fair statement of the information in conformity
with accounting principles generally accepted in the United States have been included. The
Unaudited Consolidated Balance Sheet as of December 31, 2007, as presented herein, was derived from
the audited balance sheet of the Company, but does not include all disclosures required by
accounting principles generally accepted in the United States of America. These unaudited
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 fiscal
year ended December 31, 2007.
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.
The Company provides a dual presentation of its net income per common share in its Unaudited
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 during the period excluding
nonvested restricted stock. Diluted EPS is based on the weighted-average number of common shares
outstanding plus the impact of dilutive instruments, including stock options, restricted stock and
stock unit awards using the treasury stock method. The following table presents information
necessary to calculate net income per share for the three and six months ended June 30, 2008 and
2007 as well as potentially dilutive securities excluded from the weighted average number of
diluted common shares outstanding, as their inclusion would have been anti-dilutive during the
three and six months ended June 30, 2008 and 2007 (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
Net income |
|
$ |
81,422 |
|
|
$ |
139,551 |
|
|
$ |
158,831 |
|
|
$ |
255,352 |
|
Weighted average number of common shares outstanding excluding nonvested
restricted stock |
|
|
153,978 |
|
|
|
155,527 |
|
|
|
153,289 |
|
|
|
155,457 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income per common share |
|
$ |
0.53 |
|
|
$ |
0.90 |
|
|
$ |
1.04 |
|
|
$ |
1.64 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding excluding nonvested
restricted stock |
|
|
153,978 |
|
|
|
155,527 |
|
|
|
153,289 |
|
|
|
155,457 |
|
Dilutive effect of stock options, restricted shares and stock unit awards |
|
|
2,459 |
|
|
|
2,385 |
|
|
|
2,477 |
|
|
|
2,123 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of diluted common shares outstanding |
|
|
156,437 |
|
|
|
157,912 |
|
|
|
155,766 |
|
|
|
157,580 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per common share |
|
$ |
0.52 |
|
|
$ |
0.88 |
|
|
$ |
1.02 |
|
|
$ |
1.62 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Potentially dilutive securities excluded as anti-dilutive |
|
|
655 |
|
|
|
1,785 |
|
|
|
2,380 |
|
|
|
2,435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassifications Certain reclassifications have been made to the 2007 consolidated
financial statements in order for them to conform with the 2008 presentation.
The results of operations for the three and six months ended June 30, 2008 are not necessarily
indicative of the results to be expected for the full year.
5
2. Stock-based Compensation
The Company recognizes the cost of share-based awards under the fair-value method. The
Company uses share-based awards to compensate employees and non-employee directors. All awards
have been equity instruments in the form of stock options, restricted stock awards and stock unit
awards and have included both service and, in certain cases, performance conditions. The Company
issues shares of common stock when vested stock option awards are exercised, when restricted stock
awards are granted and when stock unit awards vest.
Stock Options. The Company estimates the grant date fair values of stock options using the
Black-Scholes-Merton valuation model (Black-Scholes). 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 are 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 are granted. The risk-free
interest rate assumptions are determined by reference to United States Treasury yields.
Weighted-average assumptions used to estimate the grant date fair values for stock options granted
in the three and six-month periods ended June 30, 2008 and 2007 follow:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
|
|
2008 |
|
2007 |
|
2008 |
|
2007 |
Volatility |
|
|
35.74 |
% |
|
|
36.36 |
% |
|
|
35.73 |
% |
|
|
36.38 |
% |
Expected term (in years) |
|
|
4.00 |
|
|
|
4.00 |
|
|
|
4.00 |
|
|
|
4.00 |
|
Dividend yield |
|
|
1.64 |
% |
|
|
2.00 |
% |
|
|
1.68 |
% |
|
|
1.96 |
% |
Risk-free interest rate |
|
|
2.92 |
% |
|
|
4.56 |
% |
|
|
2.94 |
% |
|
|
4.56 |
% |
Stock option activity from January 1, 2008 to June 30, 2008 follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
Underlying |
|
|
Exercise |
|
|
|
Shares |
|
|
Price |
|
Outstanding at January 1, 2008 |
|
|
7,403,084 |
|
|
$ |
17.52 |
|
Granted |
|
|
694,500 |
|
|
$ |
28.75 |
|
Exercised |
|
|
(2,284,041 |
) |
|
$ |
11.11 |
|
Expired |
|
|
(134 |
) |
|
$ |
14.64 |
|
|
|
|
|
|
|
|
Outstanding at June 30, 2008 |
|
|
5,813,409 |
|
|
$ |
21.38 |
|
|
|
|
|
|
|
|
Exercisable at June 30, 2008 |
|
|
4,206,407 |
|
|
$ |
19.30 |
|
|
|
|
|
|
|
|
Restricted Stock. Under restricted stock awards to date, shares were issued when granted.
Nonvested shares are subject to forfeiture for failure to fulfill service conditions and, in
certain cases, performance conditions. Nonforfeitable cash dividends are paid on nonvested
restricted shares.
Restricted stock activity from January 1, 2008 to June 30, 2008 follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
Grant Date |
|
|
|
Shares |
|
|
Fair Value |
|
Nonvested restricted stock outstanding at January 1, 2008 |
|
|
1,490,150 |
|
|
$ |
26.22 |
|
Granted |
|
|
576,950 |
|
|
$ |
30.31 |
|
Vested |
|
|
(534,337 |
) |
|
$ |
24.36 |
|
Forfeited |
|
|
(30,185 |
) |
|
$ |
26.15 |
|
|
|
|
|
|
|
|
Nonvested restricted stock outstanding at June 30, 2008 |
|
|
1,502,578 |
|
|
$ |
28.45 |
|
|
|
|
|
|
|
|
Stock Units. Under stock unit awards to date, shares are not issued until the awards vest.
Awards are subject to forfeiture for failure to fulfill service conditions. Nonforfeitable cash
dividend equivalents are paid on nonvested stock units.
6
Stock unit activity from January 1, 2008 to June 30, 2008 follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
Grant Date |
|
|
|
Shares |
|
|
Fair Value |
|
Nonvested stock units outstanding at January 1, 2008 |
|
|
|
|
|
$ |
|
|
Granted |
|
|
17,500 |
|
|
$ |
31.60 |
|
Vested |
|
|
|
|
|
$ |
|
|
Forfeited |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
Nonvested stock units outstanding at June 30, 2008 |
|
|
17,500 |
|
|
$ |
31.60 |
|
|
|
|
|
|
|
|
3. Comprehensive Income
The following table reflects the Companys comprehensive income after considering the effects
of foreign currency translation adjustments for the three and six months ended June 30, 2008 and
2007 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
Net income |
|
$ |
81,422 |
|
|
$ |
139,551 |
|
|
$ |
158,831 |
|
|
$ |
255,352 |
|
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation
adjustment related to Canadian
operations, net of tax |
|
|
925 |
|
|
|
5,770 |
|
|
|
(2,081 |
) |
|
|
6,418 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income, net of tax |
|
$ |
82,347 |
|
|
$ |
145,321 |
|
|
$ |
156,750 |
|
|
$ |
261,770 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4. Property and Equipment
Property and equipment consisted of the following at June 30, 2008 and December 31, 2007 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
Equipment |
|
$ |
2,811,632 |
|
|
$ |
2,748,007 |
|
Oil and natural gas properties |
|
|
82,625 |
|
|
|
75,732 |
|
Buildings |
|
|
56,328 |
|
|
|
50,955 |
|
Land |
|
|
9,827 |
|
|
|
9,991 |
|
|
|
|
|
|
|
|
|
|
|
2,960,412 |
|
|
|
2,884,685 |
|
Less accumulated depreciation and depletion |
|
|
(1,086,901 |
) |
|
|
(1,043,281 |
) |
|
|
|
|
|
|
|
Property and equipment, net |
|
$ |
1,873,511 |
|
|
$ |
1,841,404 |
|
|
|
|
|
|
|
|
7
5. Business Segments
The Companys 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 and (iv) the investment, on a
working interest basis, in oil and natural gas properties. 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 operating decision
maker and have distinct and identifiable revenues and expenses. Separate financial data for each
of our four business segments is provided in the table below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling (a) |
|
$ |
417,874 |
|
|
$ |
420,285 |
|
|
$ |
838,826 |
|
|
$ |
888,624 |
|
Pressure pumping |
|
|
57,094 |
|
|
|
51,592 |
|
|
|
99,958 |
|
|
|
90,176 |
|
Drilling and completion fluids (b) |
|
|
38,746 |
|
|
|
39,702 |
|
|
|
71,346 |
|
|
|
70,583 |
|
Oil and natural gas |
|
|
13,609 |
|
|
|
12,108 |
|
|
|
22,600 |
|
|
|
22,367 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment revenues |
|
|
527,323 |
|
|
|
523,687 |
|
|
|
1,032,730 |
|
|
|
1,071,750 |
|
Elimination of intercompany revenues (a)(b) |
|
|
(1,040 |
) |
|
|
(1,129 |
) |
|
|
(1,893 |
) |
|
|
(2,091 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
526,283 |
|
|
$ |
522,558 |
|
|
$ |
1,030,837 |
|
|
$ |
1,069,659 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling |
|
$ |
106,795 |
|
|
$ |
137,712 |
|
|
$ |
225,181 |
|
|
$ |
309,417 |
|
Pressure pumping |
|
|
14,277 |
|
|
|
17,599 |
|
|
|
18,729 |
|
|
|
27,840 |
|
Drilling and completion fluids |
|
|
4,055 |
|
|
|
3,906 |
|
|
|
4,722 |
|
|
|
6,182 |
|
Oil and natural gas |
|
|
7,173 |
|
|
|
5,116 |
|
|
|
11,470 |
|
|
|
7,729 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
132,300 |
|
|
|
164,333 |
|
|
|
260,102 |
|
|
|
351,168 |
|
Corporate and other |
|
|
(8,602 |
) |
|
|
(7,607 |
) |
|
|
(16,344 |
) |
|
|
(14,515 |
) |
Embezzlement (costs) recoveries (c) |
|
|
|
|
|
|
41,935 |
|
|
|
|
|
|
|
41,935 |
|
Gain on disposal of assets (d) |
|
|
2,721 |
|
|
|
16,475 |
|
|
|
2,535 |
|
|
|
16,273 |
|
Interest income |
|
|
493 |
|
|
|
457 |
|
|
|
836 |
|
|
|
826 |
|
Interest expense |
|
|
(63 |
) |
|
|
(831 |
) |
|
|
(340 |
) |
|
|
(1,594 |
) |
Other |
|
|
353 |
|
|
|
109 |
|
|
|
737 |
|
|
|
203 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
$ |
127,202 |
|
|
$ |
214,871 |
|
|
$ |
247,526 |
|
|
$ |
394,296 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
Identifiable assets: |
|
|
|
|
|
|
|
|
Contract drilling |
|
$ |
2,154,535 |
|
|
$ |
2,132,910 |
|
Pressure pumping |
|
|
188,976 |
|
|
|
154,120 |
|
Drilling and completion fluids |
|
|
101,154 |
|
|
|
91,989 |
|
Oil and natural gas |
|
|
36,742 |
|
|
|
37,885 |
|
Corporate and other (e) |
|
|
102,550 |
|
|
|
48,295 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,583,957 |
|
|
$ |
2,465,199 |
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes contract drilling intercompany revenues of approximately $1.0 million and $1.1 million for the three months
ended June 30, 2008 and 2007, respectively. Includes contract drilling intercompany revenues of approximately $1.8
million and $1.9 million for the six months ended June 30, 2008 and 2007, respectively. |
|
(b) |
|
Includes drilling and completion fluids intercompany revenues of approximately $1,000 and $35,000 for the three
months ended June 30, 2008 and 2007, respectively. Includes drilling and completion fluids intercompany revenues of
approximately $51,000 and $156,000 for the six months ended June 30, 2008. |
|
(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
from the Company. The embezzlement recovery in 2007
includes the recognition of the recovery of assets
seized by a court appointed receiver, net of
professional and other costs incurred as a result of
the embezzlement. |
|
(d) |
|
Gains or losses associated with the disposal of assets relate to decisions of the executive management group
regarding corporate strategy. Accordingly, the related gains or losses have been separately presented and excluded
from the results of specific segments. |
|
(e) |
|
Corporate and other assets primarily include cash on hand managed by the corporate group and certain tax assets. |
8
6. Goodwill
Goodwill is evaluated at least annually to determine if the fair value of recorded goodwill
has decreased below its carrying value. At December 31, 2007 the Company performed its annual
goodwill evaluation and determined no adjustment to impair goodwill was necessary. Goodwill at
both June 30, 2008 and December 31, 2007 includes $86.2 million in the Contract Drilling segment
and $10.0 million in the Drilling and Completion Fluids segment.
7. Accrued Expenses
Accrued expenses consisted of the following at June 30, 2008 and December 31, 2007 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
Salaries, wages, payroll taxes and benefits |
|
$ |
26,656 |
|
|
$ |
33,816 |
|
Workers compensation liability |
|
|
65,596 |
|
|
|
70,989 |
|
Sales, use and other taxes |
|
|
10,027 |
|
|
|
12,119 |
|
Insurance, other than workers compensation |
|
|
16,443 |
|
|
|
16,308 |
|
Other |
|
|
4,106 |
|
|
|
3,602 |
|
|
|
|
|
|
|
|
|
|
$ |
122,828 |
|
|
$ |
136,834 |
|
|
|
|
|
|
|
|
8. Asset Retirement Obligation
Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement
Obligations, 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 the Companys asset retirement obligations during the six months
ended June 30, 2008 and 2007 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
2007 |
|
Balance at beginning of year |
|
$ |
1,593 |
|
|
$ |
1,829 |
|
Liabilities incurred |
|
|
261 |
|
|
|
151 |
|
Liabilities settled |
|
|
(207 |
) |
|
|
(632 |
) |
Accretion expense |
|
|
29 |
|
|
|
31 |
|
Revision in estimated costs of plugging oil and natural gas wells |
|
|
1,025 |
|
|
|
289 |
|
|
|
|
|
|
|
|
Asset retirement obligation at end of period |
|
$ |
2,701 |
|
|
$ |
1,668 |
|
|
|
|
|
|
|
|
9. Borrowings Under Line of Credit
The Company has an unsecured revolving line of credit (LOC) with a maximum borrowing
capacity of $375 million. Interest is paid on outstanding LOC balances at a floating rate ranging
from LIBOR plus 0.625% to 1.0% or the prime rate at the Companys election. Any outstanding
borrowings must be repaid at maturity on December 16, 2009. This arrangement includes various
fees, including a commitment fee on the average daily unused amount (0.15% at June 30, 2008).
There are customary restrictions and covenants associated with the LOC. Financial covenants
provide for a maximum debt to capitalization ratio and a minimum interest coverage ratio. The
Company does not expect that the restrictions and covenants will impact its ability to operate or
react to opportunities that might arise. As of June 30, 2008, the Company had no borrowings
outstanding under the LOC. However, the Company had $58.6 million in letters of credit outstanding
and as a result, the Company had available borrowing capacity of approximately $316 million at June
30, 2008.
10. Commitments, Contingencies and Other Matters
Commitments As of June 30, 2008, the Company maintained letters of credit in the aggregate
amount of $58.6 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 the
calendar year and are typically renewed annually. As of June 30, 2008, no amounts had been drawn
under the letters of credit.
9
As of June 30, 2008, the Company had non-cancelable commitments to purchase approximately
$61.7 million of equipment. In addition to commitments at June 30, 2008 the Company entered into
agreements in July 2008 to purchase new drilling equipment totaling approximately $111 million.
The Company is party to various 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, results of
operations or cash flows.
11. Stockholders Equity
Cash Dividends The Company paid cash dividends during the six months ended June 30, 2008 and
2007 as follows:
|
|
|
|
|
|
|
|
|
2008: |
|
Per Share |
|
|
Total |
|
|
|
|
|
|
|
(in thousands) |
|
Paid on March 28, 2008 |
|
$ |
0.12 |
|
|
$ |
18,493 |
|
Paid on June 27, 2008 |
|
|
0.16 |
|
|
|
25,011 |
|
|
|
|
|
|
|
|
Total cash dividends |
|
$ |
0.28 |
|
|
$ |
43,504 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007: |
|
Per Share |
|
|
Total |
|
|
|
|
|
|
|
(in thousands) |
|
Paid on March 30, 2007 |
|
$ |
0.08 |
|
|
$ |
12,527 |
|
Paid on June 29, 2007 |
|
|
0.12 |
|
|
|
18,860 |
|
|
|
|
|
|
|
|
Total cash dividends |
|
$ |
0.20 |
|
|
$ |
31,387 |
|
|
|
|
|
|
|
|
On July 30, 2008, the Companys Board of Directors approved a cash dividend on its common
stock in the amount of $0.16 per share to be paid on September 30, 2008 to holders of record as of
September 12, 2008. The amount and timing of all future dividend payments, if any, 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 August 1, 2007, the Companys Board of Directors approved a stock buyback program
(Program), authorizing purchases of up to $250 million of the Companys common stock in open
market or privately negotiated transactions. As of June 30, 2008, the Company had authority
remaining under the Program to purchase approximately $180 million of the Companys outstanding
common stock. Shares purchased under the Program are accounted for as treasury stock.
The Company purchased 151,794 shares of treasury stock from employees during the six months
ended June 30, 2008 to provide employees with the funds necessary to satisfy payroll tax
withholding obligations upon the vesting of shares of restricted stock. The purchases were made at
fair market value and the total purchase price for these shares was approximately $4.5 million.
These purchases were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term
Incentive Plan and not pursuant to the Program.
12. Income Taxes
The Company adopted Financial Accounting Standards Board (FASB) Interpretation No. 48,
Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No. 109 (FIN 48)
on January 1, 2007. 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. As of June 30, 2008, the Company had no unrecognized tax
benefits. In connection with the adoption of FIN 48, the Company established a policy to account
for interest and penalties with respect to income taxes as operating expenses. As of June 30,
2008, the tax years ended December 31, 2004 through December 31, 2007 are open for examination by
U.S. taxing authorities. As of June 30, 2008, the tax years ended December 31, 2003 through
December 31, 2007 are open for examination by Canadian taxing authorities.
10
13. Recently Issued Accounting Standards
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. The initial
application of FAS 157 is limited to financial assets and liabilities and became effective on
January 1, 2008 for the Company. The impact of the initial application was not material. The
Company will adopt FAS 157 on a prospective basis for nonfinancial assets and liabilities that are
not measured at fair value on a recurring basis on January 1, 2009. The application of FAS 157 to
the Companys nonfinancial assets and liabilities will primarily be limited to assets acquired and
liabilities assumed in a business combination, asset retirement obligations and asset impairments,
including goodwill and long-lived assets. This application of FAS 157 is not expected to have a
material impact to the Company.
In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1, Determining Whether
Instruments Granted in Share-Based Payment Transactions Are Participating Securities (FSP EITF
03-6-1). FSB EITF 03-6-1 clarifies that share-based payment awards that entitle their holders to
receive nonforfeitable dividends before vesting should be considered participating securities and,
as such, should be included in the calculation of basic earnings-per-share using the two-class
method. Certain of the Companys share-based payment awards entitle the holders to receive
nonforfeitable dividends and the application of the provisions of FSP EITF 03-6-1 may have the
effect of reducing basic and diluted earnings-per-share by an immaterial amount. FSP EITF 03-6-1
is effective for financial statements issued for fiscal years beginning after December 15, 2008, as
well as interim periods within those years. Once effective, all prior-period earnings-per-share
data presented must be adjusted retrospectively to conform with the provisions of the FSP. The FSP
will be effective for the Company beginning in the quarter ending March 31, 2009 and early
application is not permitted.
11
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 invest, on a working interest basis, in oil and natural gas properties. For the three and
six months ended June 30, 2008 and 2007, our operating revenues consisted of the following (dollars
in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
Contract drilling |
|
$ |
416,835 |
|
|
|
79 |
% |
|
$ |
419,191 |
|
|
|
80 |
% |
|
$ |
836,984 |
|
|
|
81 |
% |
|
$ |
886,689 |
|
|
|
83 |
% |
Pressure pumping |
|
|
57,094 |
|
|
|
11 |
|
|
|
51,592 |
|
|
|
10 |
|
|
|
99,958 |
|
|
|
10 |
|
|
|
90,176 |
|
|
|
8 |
|
Drilling and completion fluids |
|
|
38,745 |
|
|
|
7 |
|
|
|
39,667 |
|
|
|
8 |
|
|
|
71,295 |
|
|
|
7 |
|
|
|
70,427 |
|
|
|
7 |
|
Oil and natural gas |
|
|
13,609 |
|
|
|
3 |
|
|
|
12,108 |
|
|
|
2 |
|
|
|
22,600 |
|
|
|
2 |
|
|
|
22,367 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
526,283 |
|
|
|
100 |
% |
|
$ |
522,558 |
|
|
|
100 |
% |
|
$ |
1,030,837 |
|
|
|
100 |
% |
|
$ |
1,069,659 |
|
|
|
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, Alabama,
Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota, Pennsylvania 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. The oil and
natural gas properties in which we hold working interests are primarily located in West and South
Texas, Southeastern New Mexico, Utah and Mississippi.
Our consolidated net income for the second quarter of 2008 decreased by $58.1 million or 42%
as compared to the second quarter of 2007. Included in consolidated net income for the second
quarter of 2007 was a pre-tax gain of approximately $41.9 million associated with the recovery of
embezzled funds and approximately $16.5 million in net pre-tax gains from the disposal of certain
oil and natural gas properties and other assets. Excluding the above-mentioned gains, our
consolidated net income for the second quarter of 2007 would have been approximately $102 million
and the decrease in net income for the second quarter of 2008 would have been approximately $20.2
million or 20%.
Typically, 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 second quarter of 2008, our average number of rigs operating
was 244 per day compared to 237 in the second quarter of 2007. Our average revenue per operating
day was $18,740 in the second quarter of 2008 compared to $19,410 in the second quarter of 2007.
The decrease in our consolidated net income was primarily due to our contract drilling segment
experiencing a decrease in the average revenue per operating day and an increase in the average
costs per operating day in the second quarter of 2008 as compared to the second quarter of 2007.
Our revenues, profitability and cash flows are highly dependent upon prevailing prices for
natural gas and, to a lesser extent, oil. 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 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 fiscal year ended December
31, 2007.
We believe that the liquidity shown on our balance sheet as of June 30, 2008, which includes
approximately $335 million in working capital (including $62.2 million in cash and cash
equivalents) and approximately $316 million available under a $375 million line of credit, provides
us with the ability to build new equipment, make improvements to our equipment, expand into new
regions, pursue acquisition opportunities, pay cash dividends and survive downturns in our
industry.
Commitments and Contingencies As of June 30, 2008, we maintained letters of credit in the
aggregate amount of $58.6 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 and are typically renewed annually. As of June 30, 2008, no amounts had been drawn
under the letters of credit.
12
As of June 30, 2008, we had non-cancelable commitments to purchase approximately $61.7 million
of equipment. In addition to commitments at June 30, 2008, we entered into agreements in July 2008
to purchase new drilling equipment totaling approximately $111 million.
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 and money market accounts.
Description of Business We conduct our contract drilling operations in Texas, New Mexico,
Oklahoma, Arkansas, Louisiana, Mississippi, Alabama, Colorado, Utah, Wyoming, Montana, North
Dakota, South Dakota, Pennsylvania and Western Canada. As of June 30, 2008, we had approximately
350 currently marketable land-based 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 also invest, on a working interest basis, in oil and natural gas properties.
The North American land drilling industry has experienced periods of downturn in demand at
various times during 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 continue to adversely affect utilization rates and pricing, even in an
environment of high 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 |
|
|
|
|
construction of new drilling rigs. |
As a result of an increase in drilling activity and increased prices for drilling services in
2005 and 2006, construction of new drilling rigs increased significantly in that time period. The
addition of new drilling rigs to the market resulted in excess capacity compared to demand, and
construction of new drilling rigs moderated in 2007. With a recent increase in demand in 2008, we
believe that further construction of new drilling rigs will continue. 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 fiscal year ended December 31, 2007.
Liquidity and Capital Resources
As of June 30, 2008, we had working capital of $335 million including cash and cash
equivalents of $62.2 million. For the six months ended June 30, 2008, our sources of cash flow
included:
|
|
|
$273 million from operating activities, |
|
|
|
$4.4 million in proceeds from the disposal of property and equipment, and |
|
|
|
$41.4 million from the exercise of stock options and tax benefits associated with
stock-based compensation. |
During the six months ended June 30, 2008, we used $43.5 million to pay dividends on our
common stock, $50.0 million to repay borrowings under our line of credit, $4.6 million to
repurchase our common stock and $176 million:
|
|
|
to build new drilling rigs, |
|
|
|
to make capital expenditures for the betterment and refurbishment of our drilling rigs, |
13
|
|
|
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 investments in oil and natural gas properties on a working interest basis. |
As of June 30, 2008, we had no borrowings outstanding under our $375 million revolving line of
credit. However, we had $58.6 million in letters of credit outstanding and as a result, we had
available borrowing capacity of approximately $316 million at June 30, 2008.
We paid cash dividends during the six months ended June 30, 2008 as follows:
|
|
|
|
|
|
|
|
|
|
|
Per Share |
|
|
Total |
|
|
|
|
|
|
|
(in thousands) |
|
Paid on March 28, 2008 |
|
$ |
0.12 |
|
|
$ |
18,493 |
|
Paid on June 27, 2008 |
|
|
0.16 |
|
|
|
25,011 |
|
|
|
|
|
|
|
|
Total cash dividends |
|
$ |
0.28 |
|
|
$ |
43,504 |
|
|
|
|
|
|
|
|
On July 30, 2008, our Board of Directors approved a cash dividend on our common stock in the
amount of $0.16 per share to be paid on September 30, 2008 to holders of record as of September 12,
2008. The amount and timing of all future dividend payments, if any, is subject to the discretion
of the Board of Directors and will depend upon business conditions, results of operations,
financial condition, terms of our credit facilities and other factors.
On August 1, 2007, our Board of Directors approved a stock buyback program (Program),
authorizing purchases of up to $250 million of our common stock in open market or privately
negotiated transactions. As of June 30, 2008, we had authority remaining under the Program to
purchase approximately $180 million of our outstanding common stock. Shares purchased under the
Program are 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 on reasonable
terms, if at all.
Results of Operations
The following tables summarize operations by business segment for the three months ended June
30, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract Drilling |
|
2008 |
|
2007 |
|
% Change |
|
|
(Dollars in thousands) |
|
|
|
|
Revenues |
|
$ |
416,835 |
|
|
$ |
419,191 |
|
|
|
(0.6 |
)% |
Direct operating costs |
|
$ |
251,381 |
|
|
$ |
228,297 |
|
|
|
10.1 |
% |
Selling, general and administrative |
|
$ |
1,297 |
|
|
$ |
1,400 |
|
|
|
(7.4 |
)% |
Depreciation |
|
$ |
57,362 |
|
|
$ |
51,782 |
|
|
|
10.8 |
% |
Operating income |
|
$ |
106,795 |
|
|
$ |
137,712 |
|
|
|
(22.5 |
)% |
Operating days |
|
|
22,245 |
|
|
|
21,597 |
|
|
|
3.0 |
% |
Average revenue per operating day |
|
$ |
18.74 |
|
|
$ |
19.41 |
|
|
|
(3.5 |
)% |
Average direct operating costs per operating day |
|
$ |
11.30 |
|
|
$ |
10.57 |
|
|
|
6.9 |
% |
Average rigs operating |
|
|
244 |
|
|
|
237 |
|
|
|
3.0 |
% |
Capital expenditures |
|
$ |
67,815 |
|
|
$ |
129,913 |
|
|
|
(47.8 |
)% |
Revenues in the second quarter of 2008 were relatively flat as compared to the second quarter
of 2007 as a result of a slight increase in the number of operating days offset by a slight
decrease in the average revenue per operating day. Direct operating costs in the second quarter of
2008 increased as compared to the second quarter of 2007 as a result of increases in operating days
and average direct operating costs per operating day. The increase in average direct operating
costs per operating day includes costs incurred in activating drilling rigs. Significant capital
expenditures have been incurred to build new drilling rigs, to modify and upgrade our
14
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 the capital expenditures discussed above.
|
|
|
|
|
|
|
|
|
|
|
|
|
Pressure Pumping |
|
2008 |
|
2007 |
|
% Change |
|
|
(Dollars in thousands) |
|
|
|
|
Revenues |
|
$ |
57,094 |
|
|
$ |
51,592 |
|
|
|
10.7 |
% |
Direct operating costs |
|
$ |
32,506 |
|
|
$ |
25,777 |
|
|
|
26.1 |
% |
Selling, general and administrative |
|
$ |
5,834 |
|
|
$ |
4,808 |
|
|
|
21.3 |
% |
Depreciation |
|
$ |
4,477 |
|
|
$ |
3,408 |
|
|
|
31.4 |
% |
Operating income |
|
$ |
14,277 |
|
|
$ |
17,599 |
|
|
|
(18.9 |
)% |
Total jobs |
|
|
3,400 |
|
|
|
3,573 |
|
|
|
(4.8 |
)% |
Average revenue per job |
|
$ |
16.79 |
|
|
$ |
14.44 |
|
|
|
16.3 |
% |
Average direct operating costs per job |
|
$ |
9.56 |
|
|
$ |
7.21 |
|
|
|
32.6 |
% |
Capital expenditures |
|
$ |
17,689 |
|
|
$ |
14,206 |
|
|
|
24.5 |
% |
Revenues and direct operating costs increased as a result of an increase in the average
revenue and average direct operating costs per job. Increased average revenue per job was due to
increased pricing for our services and an increase in larger jobs being driven by demand for
services associated with unconventional reservoirs in the Appalachian Basin. Average direct
operating costs per job increased as a result of increases in compensation, maintenance and the
cost of materials used in our operations, as well as an increase in larger jobs. Selling, general
and administrative expense increased primarily as a result of expenses to support the expanding
operations of the pressure pumping segment. Significant capital expenditures have been incurred to
add capacity, expand our areas of operation and modify and upgrade existing equipment. The
increase in depreciation expense is a result of the capital expenditures discussed above.
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and Completion Fluids |
|
2008 |
|
2007 |
|
% Change |
|
|
(Dollars in thousands) |
|
|
|
|
Revenues |
|
$ |
38,745 |
|
|
$ |
39,667 |
|
|
|
(2.3 |
)% |
Direct operating costs |
|
$ |
31,449 |
|
|
$ |
32,628 |
|
|
|
(3.6 |
)% |
Selling, general and administrative |
|
$ |
2,517 |
|
|
$ |
2,436 |
|
|
|
3.3 |
% |
Depreciation |
|
$ |
724 |
|
|
$ |
697 |
|
|
|
3.9 |
% |
Operating income |
|
$ |
4,055 |
|
|
$ |
3,906 |
|
|
|
3.8 |
% |
Capital expenditures |
|
$ |
1,525 |
|
|
$ |
1,023 |
|
|
|
49.1 |
% |
The results of operations in our drilling and completions fluids division in the second
quarter of 2008 were relatively consistent with those in the second quarter of 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas Production and Exploration |
|
2008 |
|
2007 |
|
% Change |
|
|
(Dollars in thousands, |
|
|
|
|
|
|
except sales prices) |
|
|
|
|
Revenues |
|
$ |
13,609 |
|
|
$ |
12,108 |
|
|
|
12.4 |
% |
Direct operating costs |
|
$ |
3,529 |
|
|
$ |
2,461 |
|
|
|
43.4 |
% |
Selling, general and administrative |
|
$ |
|
|
|
$ |
674 |
|
|
|
(100.0 |
)% |
Depreciation, depletion and impairment |
|
$ |
2,907 |
|
|
$ |
3,857 |
|
|
|
(24.6 |
)% |
Operating income |
|
$ |
7,173 |
|
|
$ |
5,116 |
|
|
|
40.2 |
% |
Capital expenditures |
|
$ |
4,527 |
|
|
$ |
4,619 |
|
|
|
(2.0 |
)% |
Average net daily oil production (Bbls) |
|
|
814 |
|
|
|
1,107 |
|
|
|
(26.5 |
)% |
Average net daily natural gas production (Mcf) |
|
|
4,126 |
|
|
|
6,444 |
|
|
|
(36.0 |
)% |
Average oil sales price (per Bbl) |
|
$ |
123.71 |
|
|
$ |
63.04 |
|
|
|
96.2 |
% |
Average natural gas sales price (per Mcf) |
|
$ |
11.85 |
|
|
$ |
7.84 |
|
|
|
51.1 |
% |
Revenues increased due to an increase in the average sales price of oil and natural gas
partially offset by a decrease in the average net daily production of oil and natural gas and by
the elimination of well operations revenue due to the sale in the fourth quarter of 2007 of the
operating responsibilities associated with oil and natural gas wells. Average net daily oil and
natural gas production decreased primarily due to production declines. The increase in direct
operating costs is due to an increase of approximately $610,000 in costs associated with the
abandonment of exploratory wells, as well as increased production taxes and other production costs.
Selling, general and administrative expenses decreased in the second quarter of 2008 due to the
sale of operating responsibilities mentioned above and the resulting elimination of headcount in
our oil and natural gas production and exploration segment. Depreciation, depletion and impairment
expense in the second quarter of 2008 includes approximately $79,000 incurred to impair certain oil
and natural gas properties compared to approximately $534,000 incurred to impair certain oil and
natural gas properties in
15
the second quarter of 2007. Depletion expense decreased approximately $439,000 primarily due
to the lower production of oil and natural gas.
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and Other |
|
2008 |
|
2007 |
|
% Change |
|
|
(Dollars in thousands) |
|
|
|
|
Selling, general and administrative |
|
$ |
8,099 |
|
|
$ |
7,004 |
|
|
|
15.6 |
% |
Depreciation |
|
$ |
203 |
|
|
$ |
203 |
|
|
|
0.0 |
% |
Other operating expenses |
|
$ |
300 |
|
|
$ |
400 |
|
|
|
(25.0 |
)% |
Gain on disposal of assets |
|
$ |
(2,721 |
) |
|
$ |
(16,475 |
) |
|
|
(83.5 |
)% |
Embezzlement costs (recoveries) |
|
$ |
|
|
|
$ |
(41,935 |
) |
|
|
(100.0 |
)% |
Interest income |
|
$ |
493 |
|
|
$ |
457 |
|
|
|
7.9 |
% |
Interest expense |
|
$ |
63 |
|
|
$ |
831 |
|
|
|
(92.4 |
)% |
Other income |
|
$ |
353 |
|
|
$ |
109 |
|
|
|
223.9 |
% |
Selling, general and administrative expense increased primarily as a result of additional
compensation expense and an increase in payroll tax expense associated with the exercise of stock
options during the second quarter of 2008. The decrease in gain on disposal of assets in the
second quarter of 2008 compared to the second quarter of 2007 is due to a sale in the second
quarter of 2007 of certain oil and natural gas properties. Gains and losses on the disposal of
assets are considered as part of our corporate activities due to the fact that such transactions
relate to decisions of the executive management group regarding corporate strategy. Embezzlement
costs (recoveries) in the second quarter of 2007 includes a recovery of $42.5 million, reduced by
approximately $600,000 in professional and other costs incurred.
The following tables summarize operations by business segment for the six months ended June
30, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract Drilling |
|
2008 |
|
2007 |
|
% Change |
|
|
(Dollars in thousands) |
|
|
|
|
Revenues |
|
$ |
836,984 |
|
|
$ |
886,689 |
|
|
|
(5.6 |
)% |
Direct operating costs |
|
$ |
495,748 |
|
|
$ |
474,451 |
|
|
|
4.5 |
% |
Selling, general and administrative |
|
$ |
2,821 |
|
|
$ |
2,851 |
|
|
|
(1.1 |
)% |
Depreciation |
|
$ |
113,234 |
|
|
$ |
99,970 |
|
|
|
13.3 |
% |
Operating income |
|
$ |
225,181 |
|
|
$ |
309,417 |
|
|
|
(27.2 |
)% |
Operating days |
|
|
44,478 |
|
|
|
44,569 |
|
|
|
(0.2 |
)% |
Average revenue per operating day |
|
$ |
18.82 |
|
|
$ |
19.89 |
|
|
|
(5.4 |
)% |
Average direct operating costs per operating day |
|
$ |
11.15 |
|
|
$ |
10.65 |
|
|
|
4.7 |
% |
Average rigs operating |
|
|
244 |
|
|
|
246 |
|
|
|
(0.8 |
)% |
Capital expenditures |
|
$ |
135,026 |
|
|
$ |
283,189 |
|
|
|
(52.3 |
)% |
Revenues in the first six months of 2008 decreased as compared to the first six months of 2007
as a result of decreases in the average revenue per operating day and in the number of operating
days. Direct operating costs in the first six months of 2008 increased as compared to the first
six months of 2007 as a result of the increase in average direct operating costs per operating day.
The increase in average direct operating costs per operating day includes costs incurred in
activating drilling rigs. The reactivation and construction of new land drilling rigs in the
United States has resulted in excess capacity compared to demand. Operating days, average rigs
operating and average revenue per operating day decreased in the first six months of 2008 as a
result of the excess capacity of drilling rigs. Significant capital expenditures have been
incurred to build new drilling rigs, to modify and upgrade our 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 the capital expenditures discussed above.
|
|
|
|
|
|
|
|
|
|
|
|
|
Pressure Pumping |
|
2008 |
|
2007 |
|
% Change |
|
|
(Dollars in thousands) |
|
|
|
|
Revenues |
|
$ |
99,958 |
|
|
$ |
90,176 |
|
|
|
10.8 |
% |
Direct operating costs |
|
$ |
61,011 |
|
|
$ |
46,928 |
|
|
|
30.0 |
% |
Selling, general and administrative |
|
$ |
11,441 |
|
|
$ |
8,876 |
|
|
|
28.9 |
% |
Depreciation |
|
$ |
8,777 |
|
|
$ |
6,532 |
|
|
|
34.4 |
% |
Operating income |
|
$ |
18,729 |
|
|
$ |
27,840 |
|
|
|
(32.7 |
)% |
Total jobs |
|
|
6,311 |
|
|
|
6,412 |
|
|
|
(1.6 |
)% |
Average revenue per job |
|
$ |
15.84 |
|
|
$ |
14.06 |
|
|
|
12.7 |
% |
Average direct operating costs per job |
|
$ |
9.67 |
|
|
$ |
7.32 |
|
|
|
32.1 |
% |
Capital expenditures |
|
$ |
30,648 |
|
|
$ |
30,631 |
|
|
|
0.1 |
% |
16
Revenues and direct operating costs increased as a result of an increase in the average
revenue and average direct operating costs per job. Increased average revenue per job was due to
increased pricing for our services and an increase in larger jobs being driven by demand for
services associated with unconventional reservoirs in the Appalachian Basin. Average direct
operating costs per job increased as a result of increases in compensation, maintenance and the
cost of materials used in our operations, as well as an increase in larger jobs. Selling, general
and administrative expense increased primarily as a result of expenses to support the expanding
operations of the pressure pumping segment. Significant capital expenditures have been incurred to
add capacity, expand our areas of operation and modify and upgrade existing equipment. The
increase in depreciation expense is a result of the capital expenditures discussed above.
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and Completion Fluids |
|
2008 |
|
2007 |
|
% Change |
|
|
(Dollars in thousands) |
|
|
|
|
Revenues |
|
$ |
71,295 |
|
|
$ |
70,427 |
|
|
|
1.2 |
% |
Direct operating costs |
|
$ |
59,982 |
|
|
$ |
58,019 |
|
|
|
3.4 |
% |
Selling, general and administrative |
|
$ |
5,143 |
|
|
$ |
4,833 |
|
|
|
6.4 |
% |
Depreciation |
|
$ |
1,448 |
|
|
$ |
1,393 |
|
|
|
3.9 |
% |
Operating income |
|
$ |
4,722 |
|
|
$ |
6,182 |
|
|
|
(23.6 |
)% |
Capital expenditures |
|
$ |
1,533 |
|
|
$ |
2,121 |
|
|
|
(27.7 |
)% |
Operating income in the first six months of 2007 included a reduction in direct operating
costs of approximately $1.3 million related to a recovery received on an insurance claim. The
results of operations in our drilling and completions fluids division in the first six months of
2008 were relatively consistent with those in the first six months of 2007 excluding the insurance
recovery in 2007 mentioned above.
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas Production and Exploration |
|
2008 |
|
2007 |
|
% Change |
|
|
(Dollars in thousands, |
|
|
|
|
|
|
except sales prices) |
|
|
|
|
Revenues |
|
$ |
22,600 |
|
|
$ |
22,367 |
|
|
|
1.0 |
% |
Direct operating costs |
|
$ |
5,596 |
|
|
$ |
5,739 |
|
|
|
(2.5 |
)% |
Selling, general and administrative |
|
$ |
|
|
|
$ |
1,322 |
|
|
|
(100.0 |
)% |
Depreciation, depletion and impairment |
|
$ |
5,534 |
|
|
$ |
7,577 |
|
|
|
(27.0 |
)% |
Operating income |
|
$ |
11,470 |
|
|
$ |
7,729 |
|
|
|
48.4 |
% |
Capital expenditures |
|
$ |
8,955 |
|
|
$ |
9,651 |
|
|
|
(7.2 |
)% |
Average net daily oil production (Bbls) |
|
|
758 |
|
|
|
1,104 |
|
|
|
(31.3 |
)% |
Average net daily natural gas production (Mcf) |
|
|
3,776 |
|
|
|
5,944 |
|
|
|
(36.5 |
)% |
Average oil sales price (per Bbl) |
|
$ |
111.23 |
|
|
$ |
59.69 |
|
|
|
86.3 |
% |
Average natural gas sales price (per Mcf) |
|
$ |
10.57 |
|
|
$ |
7.53 |
|
|
|
40.4 |
% |
Revenues increased due to an increase in the average sales price of oil and natural gas
partially offset by a decrease in the average net daily production of oil and natural gas and by
the elimination of well operations revenue due to the sale in the fourth quarter of 2007 of the
operating responsibilities associated with oil and natural gas wells. Average net daily oil and
natural gas production decreased primarily due to the sale of properties in 2007 and production
declines. Selling, general and administrative expenses decreased in the first six months of 2008
due to the sale of the operating responsibilities mentioned above and the resulting elimination of
headcount in our oil and natural gas production and exploration segment. Depreciation, depletion
and impairment expense in the first six months of 2008 includes approximately $300,000 incurred to
impair certain oil and natural gas properties compared to approximately $1.1 million incurred to
impair certain oil and natural gas properties in the first six months of 2007. Depletion expense
decreased approximately $1.2 million primarily due to the sale of certain properties in 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and Other |
|
2008 |
|
2007 |
|
% Change |
|
|
(Dollars in thousands) |
|
|
|
|
Selling, general and administrative |
|
$ |
15,338 |
|
|
$ |
13,109 |
|
|
|
17.0 |
% |
Depreciation |
|
$ |
406 |
|
|
$ |
406 |
|
|
|
0.0 |
% |
Other operating expenses |
|
$ |
600 |
|
|
$ |
1,000 |
|
|
|
(40.0 |
)% |
Gain on disposal of assets |
|
$ |
(2,535 |
) |
|
$ |
(16,273 |
) |
|
|
(84.4 |
)% |
Embezzlement costs (recoveries) |
|
$ |
|
|
|
$ |
(41,935 |
) |
|
|
(100.0 |
)% |
Interest income |
|
$ |
836 |
|
|
$ |
826 |
|
|
|
1.2 |
% |
Interest expense |
|
$ |
340 |
|
|
$ |
1,594 |
|
|
|
(78.7 |
)% |
Other income |
|
$ |
737 |
|
|
$ |
203 |
|
|
|
263.1 |
% |
17
Selling, general and administrative expense increased primarily as a result of additional
compensation expense and an increase in payroll tax expense associated with the exercise of stock
options during the first six months of 2008. The decrease in gain on disposal of assets in the
first six months of 2008 compared to the first six months of 2007 is due to a sale in 2007 of
certain oil and natural gas properties. Gains and losses on the disposal of assets are considered
part of our corporate activities due to the fact that such transactions relate to decisions of the
executive management group regarding corporate strategy. Embezzlement costs (recoveries) in the
first six months of 2007 included a recovery of $42.5 million, reduced by approximately $600,000 in
professional and other costs incurred.
Recently Issued Accounting Standards
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. The initial
application of FAS 157 is limited to financial assets and liabilities and became effective on
January 1, 2008 for us. The impact of the initial application was not material. We will adopt FAS
157 on a prospective basis for nonfinancial assets and liabilities that are not measured at fair
value on a recurring basis on January 1, 2009. The application of FAS 157 to our nonfinancial
assets and liabilities will primarily be limited to assets acquired and liabilities assumed in a
business combination, asset retirement obligations and asset impairments, including goodwill and
long-lived assets. This application of FAS 157 is not expected to have a material impact to us.
In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1, Determining Whether
Instruments Granted in Share-Based Payment Transactions Are Participating Securities (FSP EITF
03-6-1). FSB EITF 03-6-1 clarifies that share-based payment awards that entitle their holders to
receive nonforfeitable dividends before vesting should be considered participating securities and,
as such, should be included in the calculation of basic earnings-per-share using the two-class
method. Certain of our share-based payment awards entitle the holders to receive nonforfeitable
dividends and the application of the provisions of FSP EITF 03-6-1 may have the effect of reducing
basic and diluted earnings-per-share by an immaterial amount. FSP EITF 03-6-1 is effective for
financial statements issued for fiscal years beginning after December 15, 2008, as well as interim
periods within those years. Once effective, all prior-period earnings-per-share data presented
must be adjusted retrospectively to conform with the provisions of the FSP. The FSP will be
effective for us beginning in the quarter ending March 31, 2009 and early application is not
permitted.
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 natural gas and, to a lesser extent, oil. 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. During 2006,
the average market price of natural gas retreated from record highs that were set in 2005. The
price dropped from an average of $8.98 per Mcf in 2005 to an average of $6.94 per Mcf in 2006 and
an average of $7.18 per Mcf in 2007. This resulted in our customers moderating their increase in
drilling activities during 2007. This moderation combined with the reactivation and construction
of new land drilling rigs in the United States resulted in excess capacity. Prices have rebounded
to an average of $10.33 per Mcf for the first six months of 2008 and activity has increased. We
expect oil and natural gas prices to continue to be volatile and to affect our financial condition,
operations and ability to access sources of capital. A significant decrease in market prices for
natural gas could result in a material decrease in demand for drilling rigs and adversely affect
our operating results.
The North American land drilling industry has experienced many downturns in demand at various
times during 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.
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 at our election. 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 due to the fact that we had no
outstanding borrowings as of June 30, 2008.
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 the Canadian dollar against the
18
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. This currency
rate risk is not material to our results of operations or financial condition.
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, our CEO
and CFO concluded that our disclosure controls and procedures were effective as of June 30, 2008.
Changes in Internal Control Over Financial Reporting There were no changes in our internal
control over financial reporting during our most recently completed fiscal quarter that have
materially affected or are reasonably likely to materially affect our 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 Part I of this Quarterly Report on Form 10-Q 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:
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Changes in prices and demand for oil and natural gas; |
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Excess industry capacity of land drilling rigs resulting from the reactivation or
construction of new land drilling rigs; |
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Changes in demand for contract drilling, pressure pumping and drilling and completion
fluids services; |
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Shortages of drill pipe and other drilling equipment; |
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Labor shortages, primarily qualified drilling personnel; |
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Effects of competition from other drilling contractors and providers of pressure pumping
and drilling and completion fluids services; |
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Occurrence of operating hazards and uninsured losses inherent in our business operations;
and |
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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 fiscal year ended December 31, 2007.
19
You are cautioned not to place undue reliance on any of our forward-looking statements, which
speak only as of the date of this Quarterly Report on Form 10-Q or, in the case of documents
incorporated by reference, the date of those documents.
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 us during the quarter ended June 30, 2008.
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Approximate Dollar |
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Total Number of |
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Value of Shares |
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Shares (or Units) |
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That May yet be |
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Purchased as Part |
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Purchased Under the |
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Total |
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Average Price |
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of Publicly |
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Plans or |
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Number of Shares |
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Paid per |
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Announced Plans |
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Programs (in |
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Period Covered |
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Purchased |
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Share |
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or Programs |
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thousands)(1) |
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April 1-30, 2008 (2) |
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77,354 |
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$ |
29.00 |
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$ |
179,646 |
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May 1-31, 2008 |
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$ |
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$ |
179,646 |
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June 1-30, 2008 (3) |
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58,626 |
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$ |
33.58 |
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2,047 |
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$ |
179,573 |
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Total |
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135,980 |
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$ |
30.98 |
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2,047 |
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$ |
179,573 |
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(1) |
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On August 1, 2007, our Board of Directors approved a stock buyback
program authorizing purchases of up to $250 million of our common
stock in open market or privately negotiated transactions. Shares
that are purchased under authority other than the approved stock
buyback program do not reduce the amount remaining available under the
plan. |
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(2) |
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During April 2008, we purchased 77,354 shares from employees to
provide the funds necessary to satisfy their tax withholding
obligations upon the vesting of restricted shares. The price paid was
the closing price of our common stock on the last business day prior
to the date the shares vested. These purchases were made pursuant to
the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive
Plan (the 2005 Plan) and not pursuant to the stock buyback program. |
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(3) |
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Includes 56,579 shares purchased during June 2008 from employees to
provide the respective employees with the funds necessary to satisfy
their tax withholding obligations with respect to the vesting of
restricted shares. The price paid was the closing price of our common
stock on the last business day prior to the date the shares vested.
These purchases were made pursuant to the terms of the 2005 Plan and
not pursuant to the stock buyback program. |
ITEM 4. Submission of Matters to a Vote of Security Holders
On June 5, 2008, the Company held its Annual Meeting of Stockholders. At the meeting, the
stockholders voted on the following matters:
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1. |
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The election of seven persons to serve as directors of the Company. |
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2. |
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The approval of an amendment to Patterson-UTIs 2005 Long-Term Incentive Plan to increase
the number of shares available for issuance under the plan. |
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3. |
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Ratification of the appointment of PricewaterhouseCoopers LLP as the independent
registered public accounting firm of the Company for the fiscal year ending December 31,
2008. |
20
The seven nominees for election to the Board of Directors of the Company were elected at the
meeting, and the other proposals received the affirmative votes required for approval. The voting
results were as follows:
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1. |
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Election of Directors |
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Votes For |
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Votes Withheld |
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Mark S. Siegel |
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114,345,500 |
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19,066,089 |
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Kenneth N. Berns |
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116,726,827 |
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16,684,762 |
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Charles O. Buckner |
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116,369,784 |
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17,041,805 |
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Curtis W. Huff |
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118,692,050 |
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14,719,539 |
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Terry H. Hunt |
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117,664,973 |
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15,746,616 |
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Kenneth R. Peak |
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115,961,923 |
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17,449,666 |
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Cloyce A. Talbott |
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113,947,789 |
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19,463,800 |
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Votes |
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Broker |
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Votes For |
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Against |
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Abstentions |
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Non-votes |
2. |
|
Approval of an
amendment to
Pattterson-UTIs 2005
Long-Term Incentive
Plan to increase the
number of shares
available for issuance
under the plan |
|
|
97,484,311 |
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18,449,578 |
|
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|
101,790 |
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|
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17,375,910 |
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3. |
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Ratification of
PricewaterhouseCoopers
LLP as the Companys
independent registered
public accounting firm |
|
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131,861,890 |
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|
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1,497,893 |
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|
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51,806 |
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0 |
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ITEM 6. Exhibits
The following exhibits are filed herewith or incorporated by reference, as indicated:
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3.1 |
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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). |
|
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3.2 |
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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). |
|
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3.3 |
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Second Amended and Restated Bylaws (filed August 6, 2007 as Exhibit
3.3 to the Companys Quarterly Report on Form 10-Q for the
quarterly period ended June 30, 2007 and incorporated herein by
reference). |
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31.1* |
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Certification of Chief Executive Officer pursuant to Rule
13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as
amended. |
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31.2* |
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Certification of Chief Financial Officer pursuant to Rule
13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as
amended. |
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|
32.1* |
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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. |
21
SIGNATURE
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.
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PATTERSON-UTI ENERGY, INC. |
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By: |
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/s/ Gregory W. Pipkin |
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Gregory W. Pipkin |
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(Principal Accounting Officer and Duly Authorized Officer)
Chief Accounting Officer and Assistant Secretary |
DATED: August 1, 2008
22