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 September 30, 2010
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
(State or other jurisdiction of
incorporation or organization)
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75-2504748
(I.R.S. Employer
Identification No.) |
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450 GEARS ROAD, SUITE 500
HOUSTON, TEXAS
(Address of principal executive offices)
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77067
(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 has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (section 232.405 of this chapter) during the preceding 12
months (or for such shorter period that the registrant was required to submit and post such files).
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 (Do not check if a smaller reporting company) |
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Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuers classes of common stock, as
of the latest practicable date.
154,126,195
shares of common stock, $0.01 par value, as of October 29, 2010
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
PART I FINANCIAL INFORMATION
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ITEM 1. |
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Financial Statements |
The following unaudited consolidated financial statements include all adjustments which are,
in the opinion of management, necessary for a fair statement of the results for the interim periods
presented.
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(unaudited, in thousands, except share data)
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September 30, |
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December 31, |
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2010 |
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2009 |
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ASSETS
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Current assets: |
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Cash and cash equivalents |
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$ |
73,916 |
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$ |
49,877 |
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Accounts receivable, net of allowance for doubtful accounts of $8,053 and $10,911 at
September 30, 2010 and December 31, 2009, respectively |
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251,646 |
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164,498 |
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Federal and state income taxes receivable |
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4,635 |
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118,869 |
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Inventory |
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9,530 |
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6,941 |
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Deferred tax assets, net |
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62,313 |
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32,877 |
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Assets held for sale |
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42,424 |
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Other |
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49,454 |
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41,782 |
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Total current assets |
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451,494 |
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457,268 |
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Property and equipment, net |
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2,397,218 |
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2,110,402 |
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Goodwill |
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86,234 |
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86,234 |
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Deposits on equipment purchases |
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49,860 |
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914 |
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Other |
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12,602 |
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7,334 |
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Total assets |
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$ |
2,997,408 |
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$ |
2,662,152 |
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LIABILITIES AND STOCKHOLDERS EQUITY
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Current liabilities: |
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Accounts payable |
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$ |
181,134 |
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$ |
83,700 |
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Accrued expenses |
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125,869 |
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109,608 |
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Current portion of long term debt |
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5,000 |
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Total current liabilities |
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312,003 |
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193,308 |
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Long term debt |
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95,000 |
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Deferred tax liabilities, net |
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448,645 |
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381,656 |
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Other |
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7,621 |
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5,488 |
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Total liabilities |
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863,269 |
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580,452 |
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Commitments and contingencies (see Note 11) |
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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 $.01; authorized 300,000,000 shares with 181,461,796 and
180,828,773 issued and 154,118,246 and 153,610,785 outstanding at September 30, 2010 and
December 31, 2009, respectively |
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1,814 |
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1,808 |
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Additional paid-in capital |
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791,265 |
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781,635 |
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Retained earnings |
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1,941,854 |
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1,901,853 |
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Accumulated other comprehensive income |
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19,646 |
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14,996 |
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Treasury stock, at cost, 27,343,550 shares and 27,217,988 shares at September 30, 2010 and
December 31, 2009, respectively |
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(620,440 |
) |
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(618,592 |
) |
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Total stockholders equity |
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2,134,139 |
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2,081,700 |
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Total liabilities and stockholders equity |
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$ |
2,997,408 |
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$ |
2,662,152 |
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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 OPERATIONS
(unaudited, in thousands, except per share data)
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Three Months Ended |
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Nine Months Ended |
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September 30, |
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September 30, |
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2010 |
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2009 |
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2010 |
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2009 |
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Operating revenues: |
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Contract drilling |
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$ |
290,759 |
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$ |
112,294 |
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$ |
741,470 |
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$ |
439,714 |
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Pressure pumping |
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81,104 |
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41,687 |
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194,219 |
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113,408 |
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Oil and natural gas |
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6,800 |
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5,690 |
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21,564 |
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15,255 |
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Total operating revenues |
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378,663 |
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159,671 |
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957,253 |
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568,377 |
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Operating costs and expenses: |
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Contract drilling |
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174,999 |
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71,035 |
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459,448 |
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254,306 |
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Pressure pumping |
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51,305 |
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31,092 |
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132,401 |
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87,419 |
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Oil and natural gas |
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1,484 |
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1,780 |
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5,326 |
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5,576 |
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Depreciation, depletion and impairment |
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85,431 |
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69,582 |
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239,930 |
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207,571 |
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Selling, general and administrative |
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13,685 |
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11,384 |
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37,491 |
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33,213 |
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Net gain on asset disposals |
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(250 |
) |
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(868 |
) |
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(21,940 |
) |
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(423 |
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Provision for bad debts |
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(500 |
) |
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285 |
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(1,500 |
) |
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6,035 |
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Total operating costs and expenses |
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326,154 |
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184,290 |
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851,156 |
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593,697 |
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Operating income (loss) |
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52,509 |
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(24,619 |
) |
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106,097 |
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(25,320 |
) |
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Other income (expense): |
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Interest income |
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64 |
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53 |
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1,631 |
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318 |
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Interest expense |
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(6,227 |
) |
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(1,448 |
) |
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(9,011 |
) |
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(2,734 |
) |
Other |
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260 |
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228 |
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509 |
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263 |
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Total other income (expense) |
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(5,903 |
) |
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(1,167 |
) |
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(6,871 |
) |
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(2,153 |
) |
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Income (loss) before income taxes |
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46,606 |
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(25,786 |
) |
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99,226 |
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(27,473 |
) |
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Income tax expense (benefit): |
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Current |
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(1,748 |
) |
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(2,677 |
) |
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(4,230 |
) |
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(5,231 |
) |
Deferred |
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18,980 |
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(6,295 |
) |
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40,368 |
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(4,372 |
) |
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Total income tax expense (benefit) |
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17,232 |
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(8,972 |
) |
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36,138 |
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(9,603 |
) |
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Income (loss) from continuing operations |
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29,374 |
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(16,814 |
) |
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63,088 |
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(17,870 |
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Loss from discontinued operations, net of income taxes |
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(1,766 |
) |
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(2,250 |
) |
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Net income (loss) |
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$ |
29,374 |
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|
$ |
(18,580 |
) |
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$ |
63,088 |
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$ |
(20,120 |
) |
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Basic income (loss) per common share: |
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Income (loss) from continuing operations |
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$ |
0.19 |
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$ |
(0.11 |
) |
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$ |
0.41 |
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$ |
(0.12 |
) |
Loss from discontinued operations, net of income taxes |
|
$ |
0.00 |
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|
$ |
(0.01 |
) |
|
$ |
0.00 |
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|
$ |
(0.01 |
) |
Net income (loss) |
|
$ |
0.19 |
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|
$ |
(0.12 |
) |
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$ |
0.41 |
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$ |
(0.13 |
) |
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Diluted income (loss) per common share: |
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Income (loss) from continuing operations |
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$ |
0.19 |
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$ |
(0.11 |
) |
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$ |
0.41 |
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|
$ |
(0.12 |
) |
Loss from discontinued operations, net of income taxes |
|
$ |
0.00 |
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|
$ |
(0.01 |
) |
|
$ |
0.00 |
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|
$ |
(0.01 |
) |
Net income (loss) |
|
$ |
0.19 |
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$ |
(0.12 |
) |
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$ |
0.41 |
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$ |
(0.13 |
) |
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Weighted average number of common shares outstanding: |
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Basic |
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152,933 |
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|
152,242 |
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|
152,682 |
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|
151,975 |
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Diluted |
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154,109 |
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|
152,242 |
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|
152,682 |
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|
151,975 |
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Cash dividends per common share |
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$ |
0.05 |
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$ |
0.05 |
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$ |
0.15 |
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$ |
0.15 |
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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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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, 2009 |
|
|
180,829 |
|
|
$ |
1,808 |
|
|
$ |
781,635 |
|
|
$ |
1,901,853 |
|
|
$ |
14,996 |
|
|
$ |
(618,592 |
) |
|
$ |
2,081,700 |
|
|
|
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|
|
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|
Comprehensive income: |
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|
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|
|
|
|
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|
Net income |
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|
|
|
|
|
|
|
|
|
|
|
|
|
63,088 |
|
|
|
|
|
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|
|
|
|
|
63,088 |
|
Foreign currency translation
adjustment, net of tax of
$2,814 |
|
|
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|
|
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|
|
|
|
|
|
|
|
|
|
4,650 |
|
|
|
|
|
|
|
4,650 |
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|
|
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|
|
|
|
|
|
|
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|
|
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Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
63,088 |
|
|
|
4,650 |
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|
|
|
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|
67,738 |
|
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Issuance of restricted stock |
|
|
646 |
|
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|
6 |
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(6 |
) |
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Vesting of stock unit awards |
|
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7 |
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Forfeitures of restricted stock |
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|
(54 |
) |
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Exercise of stock options |
|
|
34 |
|
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|
|
|
|
290 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
290 |
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
11,881 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,881 |
|
Tax expense related to
stock-based compensation |
|
|
|
|
|
|
|
|
|
|
(2,535 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,535 |
) |
Payment of cash dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(23,087 |
) |
|
|
|
|
|
|
|
|
|
|
(23,087 |
) |
Purchase of treasury stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,848 |
) |
|
|
(1,848 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2010 |
|
|
181,462 |
|
|
$ |
1,814 |
|
|
$ |
791,265 |
|
|
$ |
1,941,854 |
|
|
$ |
19,646 |
|
|
$ |
(620,440 |
) |
|
$ |
2,134,139 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited consolidated financial statements.
3
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS EQUITY
(unaudited, in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
Common Stock |
|
|
Additional |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Number of |
|
|
|
|
|
|
Paid-in |
|
|
Retained |
|
|
Comprehensive |
|
|
Treasury |
|
|
|
|
|
|
Shares |
|
|
Amount |
|
|
Capital |
|
|
Earnings |
|
|
Income |
|
|
Stock |
|
|
Total |
|
Balance, December 31, 2008 |
|
|
180,192 |
|
|
$ |
1,801 |
|
|
$ |
765,512 |
|
|
$ |
1,970,824 |
|
|
$ |
5,774 |
|
|
$ |
(616,969 |
) |
|
$ |
2,126,942 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20,120 |
) |
|
|
|
|
|
|
|
|
|
|
(20,120 |
) |
Foreign currency translation
adjustment, net of tax of
$4,183 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,214 |
|
|
|
|
|
|
|
7,214 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20,120 |
) |
|
|
7,214 |
|
|
|
|
|
|
|
(12,906 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of restricted stock |
|
|
604 |
|
|
|
6 |
|
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vesting of restricted stock units |
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeitures of restricted stock |
|
|
(41 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of stock options |
|
|
61 |
|
|
|
1 |
|
|
|
378 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
379 |
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
14,108 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,108 |
|
Tax expense related to
stock-based compensation |
|
|
|
|
|
|
|
|
|
|
(2,720 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,720 |
) |
Payment of cash dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(23,005 |
) |
|
|
|
|
|
|
|
|
|
|
(23,005 |
) |
Purchase of treasury stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,623 |
) |
|
|
(1,623 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2009 |
|
|
180,822 |
|
|
$ |
1,808 |
|
|
$ |
777,272 |
|
|
$ |
1,927,699 |
|
|
$ |
12,988 |
|
|
$ |
(618,592 |
) |
|
$ |
2,101,175 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited consolidated financial statements.
4
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, in thousands)
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
63,088 |
|
|
$ |
(20,120 |
) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and impairment |
|
|
239,930 |
|
|
|
207,571 |
|
Provision for bad debts |
|
|
(1,500 |
) |
|
|
6,035 |
|
Dry holes and abandonments |
|
|
479 |
|
|
|
120 |
|
Deferred income tax expense |
|
|
40,368 |
|
|
|
(4,372 |
) |
Stock-based compensation expense |
|
|
11,881 |
|
|
|
13,848 |
|
Net gain on asset disposals |
|
|
(21,940 |
) |
|
|
(423 |
) |
Tax expense related to stock-based compensation |
|
|
(2,535 |
) |
|
|
(2,720 |
) |
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(97,455 |
) |
|
|
255,856 |
|
Income taxes receivable/payable |
|
|
114,209 |
|
|
|
(116 |
) |
Inventory and other assets |
|
|
(6,864 |
) |
|
|
7,738 |
|
Accounts payable |
|
|
31,674 |
|
|
|
(79,466 |
) |
Accrued expenses |
|
|
18,227 |
|
|
|
(25,510 |
) |
Other liabilities |
|
|
2,218 |
|
|
|
(55 |
) |
Net cash provided by operating activities of discontinued operations |
|
|
10,687 |
|
|
|
55,122 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
402,467 |
|
|
|
413,508 |
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Purchases of property and equipment |
|
|
(513,679 |
) |
|
|
(350,441 |
) |
Proceeds from disposal of assets |
|
|
27,224 |
|
|
|
3,173 |
|
Net cash provided by investing activities of discontinued operations |
|
|
42,646 |
|
|
|
(54 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(443,809 |
) |
|
|
(347,322 |
) |
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Purchases of treasury stock |
|
|
(1,848 |
) |
|
|
(1,623 |
) |
Dividends paid |
|
|
(23,087 |
) |
|
|
(23,005 |
) |
Debt issuance costs |
|
|
(10,328 |
) |
|
|
(6,169 |
) |
Proceeds from long term debt |
|
|
100,000 |
|
|
|
|
|
Proceeds from exercise of stock options |
|
|
290 |
|
|
|
379 |
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
65,027 |
|
|
|
(30,418 |
) |
|
|
|
|
|
|
|
Effect of foreign exchange rate changes on cash |
|
|
354 |
|
|
|
2,252 |
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
|
24,039 |
|
|
|
38,020 |
|
Cash and cash equivalents at beginning of period |
|
|
49,877 |
|
|
|
81,223 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
73,916 |
|
|
$ |
119,243 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow information: |
|
|
|
|
|
|
|
|
Net cash (paid) received during the period for: |
|
|
|
|
|
|
|
|
Interest expense |
|
$ |
(3,031 |
) |
|
$ |
(1,440 |
) |
Income taxes |
|
$ |
115,661 |
|
|
$ |
7,754 |
|
|
|
|
|
|
|
|
|
|
Supplemental investing and financing information: |
|
|
|
|
|
|
|
|
Net increase (decrease) in payables for purchases of property and equipment |
|
$ |
66,819 |
|
|
$ |
(12,235 |
) |
Net (increase) decrease in deposits on equipment purchases |
|
$ |
(48,946 |
) |
|
$ |
43,944 |
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited consolidated financial statements.
5
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of Consolidation and Presentation
The unaudited interim 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. Except for wholly-owned subsidiaries, the Company
has no controlling financial interests in any entity which would require consolidation.
The unaudited interim consolidated financial statements have been prepared by management of
the Company 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, 2009, as presented herein, was derived from
the audited consolidated 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, 2009. The results of operations for the three and nine months ended
September 30, 2010 are not necessarily indicative of the results to be expected for the full year.
The U.S. dollar is the functional currency for all of the Companys operations except for its
Canadian operations, which uses the Canadian dollar as its functional currency. The effects of
exchange rate changes are reflected in accumulated other comprehensive income, which is a separate
component of stockholders equity.
Certain reclassifications have been made to the 2009 consolidated financial statements in
order for them to conform with the 2010 presentation.
The carrying values of cash and cash equivalents, trade receivables and accounts payable
approximate fair value.
The Company provides a dual presentation of its net income per common share in its unaudited
consolidated statements of operations: 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 first allocating earnings between common
stockholders and holders of non-vested shares of restricted stock. Basic EPS is then determined by
dividing the earnings attributable to common stockholders by the weighted average number of common
shares outstanding during the period, excluding non-vested shares of restricted stock.
Diluted EPS is based on the weighted average number of common shares outstanding plus the
dilutive effect of potential common shares, including stock options, non-vested shares of
restricted stock and restricted stock units. The dilutive effect of stock options and restricted
stock units is determined based on the treasury stock method. The dilutive effect of non-vested
shares of restricted stock is based on the more dilutive of the treasury stock method or the
two-class method, assuming a reallocation of undistributed earnings to common stockholders after
considering the dilutive effect of potential common shares other than non-vested shares of
restricted stock.
6
The following table presents information necessary to calculate income from continuing
operations per share, income from discontinued operations per share and net income per share for
the three and nine months ended September 30, 2010 and 2009 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 (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
BASIC EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations |
|
$ |
29,374 |
|
|
$ |
(16,814 |
) |
|
$ |
63,088 |
|
|
$ |
(17,870 |
) |
Adjust for (income) loss attributed to holders of non-vested restricted stock |
|
|
(224 |
) |
|
|
159 |
|
|
|
(476 |
) |
|
|
170 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations attributed to common stockholders |
|
$ |
29,150 |
|
|
$ |
(16,655 |
) |
|
$ |
62,612 |
|
|
$ |
(17,700 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from discontinued operations, net |
|
$ |
|
|
|
$ |
(1,766 |
) |
|
$ |
|
|
|
$ |
(2,250 |
) |
Adjust for income attributed to holders of non-vested restricted stock |
|
|
|
|
|
|
16 |
|
|
|
|
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from discontinued operations attributed to common stockholders |
|
$ |
|
|
|
$ |
(1,750 |
) |
|
$ |
|
|
|
$ |
(2,230 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding, excluding non-vested
shares of restricted stock |
|
|
152,933 |
|
|
|
152,242 |
|
|
|
152,682 |
|
|
|
151,975 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic income (loss) from continuing operations per common share |
|
$ |
0.19 |
|
|
$ |
(0.11 |
) |
|
$ |
0.41 |
|
|
$ |
(0.12 |
) |
Basic loss from discontinued operations per common share |
|
$ |
0.00 |
|
|
$ |
(0.01 |
) |
|
$ |
0.00 |
|
|
$ |
(0.01 |
) |
Basic net income (loss) per common share |
|
$ |
0.19 |
|
|
$ |
(0.12 |
) |
|
$ |
0.41 |
|
|
$ |
(0.13 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DILUTED EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations attributed to common stockholders |
|
$ |
29,150 |
|
|
$ |
(16,655 |
) |
|
$ |
62,612 |
|
|
$ |
(17,700 |
) |
Add incremental earnings related to potential common shares |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted income (loss) from continuing operations attributed to common
stockholders |
|
$ |
29,151 |
|
|
$ |
(16,655 |
) |
|
$ |
62,612 |
|
|
$ |
(17,700 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding, excluding non-vested
shares of restricted stock |
|
|
152,933 |
|
|
|
152,242 |
|
|
|
152,682 |
|
|
|
151,975 |
|
Add dilutive effect of potential common shares |
|
|
1,176 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of diluted common shares outstanding |
|
|
154,109 |
|
|
|
152,242 |
|
|
|
152,682 |
|
|
|
151,975 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted income (loss) from continuing operations per common share |
|
$ |
0.19 |
|
|
$ |
(0.11 |
) |
|
$ |
0.41 |
|
|
$ |
(0.12 |
) |
Diluted loss from discontinued operations per common share |
|
$ |
0.00 |
|
|
$ |
(0.01 |
) |
|
$ |
0.00 |
|
|
$ |
(0.01 |
) |
Diluted net income (loss) per common share |
|
$ |
0.19 |
|
|
$ |
(0.12 |
) |
|
$ |
0.41 |
|
|
$ |
(0.13 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Potentially dilutive securities excluded as anti-dilutive |
|
|
4,644 |
|
|
|
8,204 |
|
|
|
6,726 |
|
|
|
8,204 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2. Discontinued Operations
On January 20, 2010, the Company exited the drilling and completion fluids business, which had
previously been presented as one of the Companys reportable operating segments. On that date, the
Companys wholly owned subsidiary, Ambar Lone Star Fluids Services LLC, completed the sale of
substantially all of its assets, excluding billed accounts receivable. The sales price was
approximately $42.6 million. Upon the Companys exit from the drilling and completion fluids
business, the Company classified its drilling and completion fluids operating segment as a
discontinued operation. Accordingly, the results of operations of this business have been
reclassified and presented as results of discontinued operations for all periods presented in these
consolidated financial statements. As of December 31, 2009, the assets to be disposed of were
considered held for sale and were presented separately within current assets under the caption
Assets held for sale in the consolidated balance sheet. Upon being classified as held for sale,
the assets to be disposed of were adjusted to fair value less estimated costs to sell resulting in
an impairment loss of $1.9 million. Due to the fact that the carrying value of the assets had been
adjusted to net realizable value, no additional gain or loss was recognized in connection with the
sale in 2010.
7
Summarized operating results from discontinued operations for the three and nine months ended
September 30, 2010, and 2009 are shown below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Drilling and completion fluids revenues |
|
$ |
|
|
|
$ |
16,488 |
|
|
$ |
3,737 |
|
|
$ |
64,585 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes |
|
$ |
|
|
|
$ |
(2,666 |
) |
|
$ |
|
|
|
$ |
(3,398 |
) |
Income tax benefit |
|
|
|
|
|
|
(900 |
) |
|
|
|
|
|
|
(1,148 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from discontinued operations, net of income tax |
|
$ |
|
|
|
$ |
(1,766 |
) |
|
$ |
|
|
|
$ |
(2,250 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
3. Acquisitions
On October 1, 2010, two subsidiaries of the Company, Universal Pressure Pumping, Inc. (UPP)
and Universal Wireline, Inc. completed the acquisition of certain assets from Key Energy Pressure
Pumping Services, LLC (Key Pressure Pumping) and Key Electric Wireline Services, LLC (together
with Key Pressure Pumping, the Sellers) relating to the
businesses of providing pressure pumping
services and electric wireline services to participants in the oil and natural gas industry for an
approximate aggregate purchase price of $238 million in cash
(the Purchase Price). This acquisition expands the
Companys pressure pumping operations to additional markets
primarily in Texas. The Purchase
Price, which was funded through a combination of cash on hand and a
$200 million draw on the Companys revolving credit facility, is subject to certain adjustments based on closing inventory. The Company is in the process
of determining the fair values of the assets acquired and liabilities assumed and the results of
operations for these acquired businesses will be included in the Companys consolidated results of
operations beginning in the quarter ending December 31, 2010. The acquisition was effected
pursuant to an Asset Purchase Agreement dated July 2, 2010, as amended, modified and supplemented,
by and among Patterson-UTI Energy, Inc., UPP (formerly known as Portofino Acquisition Company),
Sellers and Key Energy Services, Inc., a Maryland corporation.
4. Stock-based Compensation
The Company uses share-based payments to compensate employees and non-employee directors. The
Company recognizes the cost of share-based payments under the fair-value-based method. Share-based
awards consist of equity instruments in the form of stock options, restricted stock or restricted
stock units and have included service and, in certain cases, performance conditions. Additionally,
share-based awards also include both cash-settled and share-settled performance unit awards.
Cash-settled performance unit awards are accounted for as liability awards. Share-settled
performance unit awards are accounted for as equity awards. The Company issues shares of common
stock when vested stock options are exercised, when restricted stock is granted and when restricted
stock units and share-settled performance unit awards vest.
Stock Options. The Company estimates the grant date fair values of stock options using the
Black-Scholes-Merton valuation model. 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
nine month periods ended September 30, 2010 and 2009 follow:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
Volatility |
|
|
N/A |
|
|
|
49.53 |
% |
|
|
45.98 |
% |
|
|
49.90 |
% |
Expected term (in years) |
|
|
N/A |
|
|
|
4.00 |
|
|
|
5.00 |
|
|
|
4.00 |
|
Dividend yield |
|
|
N/A |
|
|
|
1.39 |
% |
|
|
1.35 |
% |
|
|
1.67 |
% |
Risk-free interest rate |
|
|
N/A |
|
|
|
2.27 |
% |
|
|
2.47 |
% |
|
|
1.67 |
% |
8
Stock option activity from January 1, 2010 to September 30, 2010 follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
Underlying |
|
|
Exercise |
|
|
|
Shares |
|
|
Price |
|
Outstanding at January 1, 2010 |
|
|
6,841,770 |
|
|
$ |
20.17 |
|
Granted |
|
|
1,016,250 |
|
|
$ |
14.85 |
|
Exercised |
|
|
(33,868 |
) |
|
$ |
8.56 |
|
Cancelled |
|
|
(10,000 |
) |
|
$ |
13.17 |
|
Expired |
|
|
(77,000 |
) |
|
$ |
19.46 |
|
|
|
|
|
|
|
|
Outstanding at September 30, 2010 |
|
|
7,737,152 |
|
|
$ |
19.54 |
|
|
|
|
|
|
|
|
Exercisable at September 30, 2010 |
|
|
5,930,096 |
|
|
$ |
20.86 |
|
|
|
|
|
|
|
|
Restricted Stock. For all restricted stock awards to date, shares of common stock were issued
when the awards were made. Non-vested shares are subject to forfeiture for failure to fulfill
service conditions and, in certain cases, performance conditions. Non-forfeitable dividends are
paid on non-vested shares of restricted stock. For restricted stock awards made prior to 2008, the
Company uses the graded-vesting attribution method to recognize periodic compensation cost over
the vesting period. For restricted stock awards made in 2008 and thereafter, the Company uses the
straight-line method to recognize periodic compensation cost over the vesting period.
Restricted stock activity from January 1, 2010 to September 30, 2010 follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
Grant Date |
|
|
|
Shares |
|
|
Fair Value |
|
Non-vested restricted stock outstanding at January 1, 2010 |
|
|
1,231,901 |
|
|
$ |
21.67 |
|
Granted |
|
|
645,950 |
|
|
$ |
14.27 |
|
Vested |
|
|
(713,329 |
) |
|
$ |
23.64 |
|
Forfeited |
|
|
(54,128 |
) |
|
$ |
22.08 |
|
|
|
|
|
|
|
|
Non-vested restricted stock outstanding at September 30, 2010 |
|
|
1,110,394 |
|
|
$ |
16.08 |
|
|
|
|
|
|
|
|
Restricted Stock Units. For all restricted stock unit awards made to date, shares of common
stock are not issued until the units vest. Restricted stock units are subject to forfeiture for
failure to fulfill service conditions. Non-forfeitable cash dividend equivalents are paid on
non-vested restricted stock units.
Restricted stock unit activity from January 1, 2010 to September 30, 2010 follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
Grant Date |
|
|
|
Shares |
|
|
Fair Value |
|
Non-vested restricted stock units outstanding at January 1, 2010 |
|
|
16,167 |
|
|
$ |
26.81 |
|
Granted |
|
|
9,000 |
|
|
$ |
13.81 |
|
Vested |
|
|
(7,333 |
) |
|
$ |
28.08 |
|
Forfeited |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
Non-vested restricted stock units outstanding at September 30, 2010 |
|
|
17,834 |
|
|
$ |
19.73 |
|
|
|
|
|
|
|
|
Performance Unit Awards. On April 28, 2009, the Company granted cash-settled performance unit
awards to certain executive officers (the 2009 Performance Units). The 2009 Performance Units
provide for those executive officers to receive a cash payment upon the achievement of certain
performance goals established by the Company during a specified period. The performance period for
the 2009 Performance Units is the period from April 1, 2009 through March 31, 2012, but can extend
through March 31, 2014 in certain circumstances. The performance goals for the 2009 Performance
Units are tied to the Companys total shareholder return for the performance period as compared to
total shareholder return for a peer group determined by the Compensation Committee of the Board of
Directors. These goals are considered to be market conditions under the relevant accounting
standards and the market conditions are factored into the determination of the fair value of the
performance units. Generally, the recipients will receive a base payment if the Companys total
shareholder return is positive and, when compared to the peer group, is at or above the
25th percentile but less than the 50th percentile, two times the base if at
or above the 50th percentile but less than the 75th percentile, and four
times the base if at the 75th percentile or higher. The total base amount with respect
to the 2009 Performance Units is approximately $1.7 million. As the 2009 Performance Units are to
be settled in cash at the end of the performance period, the Companys pro-rated
9
obligation is measured at estimated fair value at the end of each reporting period using a
Monte Carlo simulation model. As of September 30, 2010 this pro-rated obligation was approximately
$1.7 million.
On April 27, 2010, the Company granted stock-settled performance unit awards to certain
executive officers (the 2010 Performance Units). The 2010 Performance Units provide for those
executive officers to receive a grant of shares of stock upon the achievement of certain
performance goals established by the Company during a specified period. The performance period for
the 2010 Performance Units is the period from April 1, 2010 through March 31, 2013, but can extend
through March 31, 2015 in certain circumstances. The performance goals for the 2010 Performance
Units are tied to the Companys total shareholder return for the performance period as compared to
total shareholder return for a peer group determined by the Compensation Committee of the Board of
Directors. These goals are considered to be market conditions under the relevant accounting
standards and the market conditions are factored into the determination of the fair value of the
performance units. Generally, the recipients will receive a base number of shares if the Companys
total shareholder return is positive and, when compared to the peer group, is at or above the
25th percentile but less than the 50th percentile, two times the base if at
or above the 50th percentile but less than the 75th percentile, and four
times the base if at the 75th percentile or higher. The grant of shares when
achievement is between the 25th and 75th percentile will be determined on a
pro-rata basis. The total base number of shares with respect to the 2010 Performance Units is
89,375 shares. Because the 2010 Performance Units are stock-settled awards, they are accounted for
as equity awards and measured at fair value on the date of grant. The fair value of the 2010
Performance Units as of the date of grant was approximately $3.1 million using a Monte Carlo
simulation model. This amount will be recognized on a straight-line basis over the performance
period. During the three and nine months ended September 30, 2010, the Company recognized
approximately $260,000 and $520,000, respectively, in expense related to the 2010 Performance
Units.
5. Property and Equipment
Property and equipment consisted of the following at September 30, 2010 and December 31, 2009
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Equipment |
|
$ |
3,684,115 |
|
|
$ |
3,230,737 |
|
Oil and natural gas properties |
|
|
102,594 |
|
|
|
93,354 |
|
Buildings |
|
|
56,824 |
|
|
|
56,563 |
|
Land |
|
|
10,291 |
|
|
|
9,795 |
|
|
|
|
|
|
|
|
|
|
|
3,853,824 |
|
|
|
3,390,449 |
|
Less accumulated depreciation and depletion |
|
|
(1,456,606 |
) |
|
|
(1,280,047 |
) |
|
|
|
|
|
|
|
Property and equipment, net |
|
$ |
2,397,218 |
|
|
$ |
2,110,402 |
|
|
|
|
|
|
|
|
During the nine months ended September 30, 2010, the Company sold certain rights to explore
and develop zones deeper than depths that it generally targets for certain of the oil and natural
gas properties in which it has working interests. The proceeds from this sale were approximately
$22.3 million and the sale resulted in a gain on disposal of $20.1 million.
10
6. Business Segments
The Companys revenues, operating profits and identifiable assets are primarily attributable
to three business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure
pumping services and (iii) the investment, on a working interest basis, in oil and natural gas
properties. Each of these segments represents a distinct type of business. These segments have
separate management teams which report to the Companys chief operating decision maker. The
results of operations in these segments are regularly reviewed by the chief operating decision
maker for purposes of determining resource allocation and assessing performance. As discussed in
Note 2, in January 2010 the Company exited the drilling and completion fluids business which
previously was reported as a business segment. Operating results for that business for the three
and nine months ended September 30, 2010 and 2009 are presented as discontinued operations in the
consolidated statements of operations. Separate financial data for each of our business segments
is provided in the table below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling |
|
$ |
291,597 |
|
|
$ |
112,620 |
|
|
$ |
743,967 |
|
|
$ |
440,359 |
|
Pressure pumping |
|
|
81,104 |
|
|
|
41,687 |
|
|
|
194,219 |
|
|
|
113,408 |
|
Oil and natural gas |
|
|
6,800 |
|
|
|
5,690 |
|
|
|
21,564 |
|
|
|
15,255 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment revenues |
|
|
379,501 |
|
|
|
159,997 |
|
|
|
959,750 |
|
|
|
569,022 |
|
Elimination of intercompany revenues (a) |
|
|
(838 |
) |
|
|
(326 |
) |
|
|
(2,497 |
) |
|
|
(645 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
378,663 |
|
|
$ |
159,671 |
|
|
$ |
957,253 |
|
|
$ |
568,377 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling |
|
$ |
41,479 |
|
|
$ |
(19,911 |
) |
|
$ |
72,279 |
|
|
$ |
6,215 |
|
Pressure pumping |
|
|
17,586 |
|
|
|
1,211 |
|
|
|
28,769 |
|
|
|
(562 |
) |
Oil and natural gas |
|
|
2,465 |
|
|
|
1,854 |
|
|
|
8,209 |
|
|
|
(1,144 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61,530 |
|
|
|
(16,846 |
) |
|
|
109,257 |
|
|
|
4,509 |
|
Corporate and other |
|
|
(9,271 |
) |
|
|
(8,641 |
) |
|
|
(25,100 |
) |
|
|
(30,252 |
) |
Net gain on asset disposals (b) |
|
|
250 |
|
|
|
868 |
|
|
|
21,940 |
|
|
|
423 |
|
Interest income |
|
|
64 |
|
|
|
53 |
|
|
|
1,631 |
|
|
|
318 |
|
Interest expense |
|
|
(6,227 |
) |
|
|
(1,448 |
) |
|
|
(9,011 |
) |
|
|
(2,734 |
) |
Other |
|
|
260 |
|
|
|
228 |
|
|
|
509 |
|
|
|
263 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes |
|
$ |
46,606 |
|
|
$ |
(25,786 |
) |
|
$ |
99,226 |
|
|
$ |
(27,473 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Identifiable assets: |
|
|
|
|
|
|
|
|
Contract drilling |
|
$ |
2,563,883 |
|
|
$ |
2,129,567 |
|
Pressure pumping |
|
|
246,034 |
|
|
|
213,094 |
|
Oil and natural gas |
|
|
30,991 |
|
|
|
25,355 |
|
Corporate and other (c) |
|
|
156,500 |
|
|
|
294,136 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,997,408 |
|
|
$ |
2,662,152 |
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Consists of contract drilling intercompany revenues for drilling
services provided to the oil and natural gas exploration and
production segment. |
|
(b) |
|
Net gains or losses associated with the disposal of assets relate to
corporate strategy decisions of the executive management group.
Accordingly, the related gains or losses have been separately
presented and excluded from the results of specific segments. |
|
(c) |
|
Corporate and other assets at December 31, 2009 primarily include
identifiable assets associated with the Companys former drilling and
completion fluids segment as well as cash on hand, income taxes
receivable and certain deferred Federal income tax assets. Corporate
assets at September 30, 2010 primarily include cash on hand and
certain deferred Federal income tax assets. |
11
7. Goodwill
Goodwill is evaluated at least annually to determine if the fair value of recorded goodwill
has decreased below its carrying value. The Company performs this annual evaluation in the fourth
quarter of each year. For purposes of impairment testing, goodwill is evaluated at the reporting
unit level. The Companys reporting units for impairment testing have been determined to be its
operating segments.
As of September 30, 2010 and December 31, 2009, the Company had goodwill of $86.2 million, all
within its contract drilling reporting unit. In the event that market conditions weaken, the
Company may be required to record an impairment of goodwill in its contract drilling reporting unit
in the future, and such impairment could be material.
8. Accrued Expenses
Accrued expenses consisted of the following at September 30, 2010 and December 31, 2009 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
Salaries, wages, payroll taxes and benefits |
|
$ |
23,929 |
|
|
$ |
14,744 |
|
Workers compensation liability |
|
|
63,660 |
|
|
|
66,015 |
|
Insurance, other than workers compensation |
|
|
11,332 |
|
|
|
11,261 |
|
Sales, use and other taxes |
|
|
16,053 |
|
|
|
10,975 |
|
Other |
|
|
10,895 |
|
|
|
6,613 |
|
|
|
|
|
|
|
|
|
|
$ |
125,869 |
|
|
$ |
109,608 |
|
|
|
|
|
|
|
|
9. Asset Retirement Obligation
The Company records a liability for the estimated costs to be incurred in connection with the
abandonment of oil and natural gas properties in the future. This liability is included in the
caption other in the liabilities section of the consolidated balance sheet. The following table
describes the changes to the Companys asset retirement obligations during the nine months ended
September 30, 2010 and 2009 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
Balance at beginning of year |
|
$ |
2,955 |
|
|
$ |
3,047 |
|
Liabilities incurred |
|
|
279 |
|
|
|
125 |
|
Liabilities settled |
|
|
(331 |
) |
|
|
(304 |
) |
Accretion expense |
|
|
83 |
|
|
|
89 |
|
Revision in estimated costs of plugging oil and natural gas wells |
|
|
|
|
|
|
(14 |
) |
|
|
|
|
|
|
|
Asset retirement obligation at end of period |
|
$ |
2,986 |
|
|
$ |
2,943 |
|
|
|
|
|
|
|
|
10. Long Term Debt
On July 2, 2010, the Company entered into a 364-Day Credit Agreement (the 364-Day Credit
Agreement) among the Company, as borrower, and Wells Fargo Bank, N.A., as administrative agent and
lender. The 364-Day Credit Agreement was a committed senior unsecured single draw term loan credit
facility that permitted a borrowing of up to $250 million; provided that the loan must be drawn no
later than September 30, 2010 or, if an additional fee was paid, October 30, 2010. The maturity
date under the 364-Day Credit Agreement was 364 days after the date on which the closing conditions
under the 364-Day Credit Agreement were met. The loan was not drawn as of September 30, 2010 and
the 364-Day Credit Agreement expired at that time.
On August 19, 2010, the Company entered into a Credit Agreement (the 2010 Credit Agreement)
among the Company, as borrower, Wells Fargo Bank, N.A., as administrative agent, letter of credit
issuer, swing line lender and lender, and each of the other letter of credit issuer and lender
parties thereto. The 2010 Credit Agreement is a committed senior unsecured credit facility that
permits aggregate borrowings of up to $500 million pursuant to a revolving credit facility and a
term loan facility. The 2010 Credit Agreement replaced a previous unsecured revolving credit
facility.
12
The revolving credit facility permits aggregate borrowings of up to, at any time outstanding,
$400 million, which contains a letter of credit facility that, at any time outstanding, is limited
to $150 million and a swing line facility that, at any time outstanding, is limited to $40 million.
Subject to customary conditions, the Company may request that the lenders aggregate commitments
with respect to the revolving credit facility be increased by up to $100 million, not to exceed
total commitments of $500 million. The maturity date for the revolving facility is August 19,
2013.
The term loan facility provided for a loan of $100 million which was funded on August 19,
2010. The term loan facility is
payable in quarterly principal installments commencing November 19, 2010, and the installment
amounts vary from 1.25% of the original principal amount for each of the first four quarterly
installments, 2.50% of the original principal amount for each of the subsequent eight quarterly
installments, 5.00% of the original principal amount for the next subsequent three quarterly
installments and the remainder at maturity. The maturity date for the term loan facility is August
19, 2014.
Loans under the 2010 Credit Agreement bear interest by reference, at the Companys election,
to the LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to
the base rate. The applicable margin on LIBOR rate loans varies from 2.75% to 3.75% and the
applicable margin on base rate loans varies from 1.75% to 2.75%, in each case determined based upon
the Companys debt to capitalization ratio. As of September 30, 2010, the applicable margin on
LIBOR rate loans was 2.75% and the applicable margin on base rate loans was 1.75%. A letter of
credit fee is payable by the Company equal to the applicable margin for LIBOR rate loans times the
daily amount available to be drawn under outstanding letters of credit. The commitment fee payable
to the lenders for the unused portion of the revolving credit facility varies from 0.50% to 0.75%
based upon the Companys debt to capitalization ratio and was 0.50% as of September 30, 2010.
Each domestic subsidiary of the Company other than any immaterial subsidiary has
unconditionally guaranteed all existing and future indebtedness and liabilities of the Company and
the other guarantors arising under the 2010 Credit Agreement and other loan documents. Such
guarantees also cover obligations of the Company and any subsidiary of the Company arising under
any interest rate swap contract with any person while such person is a lender or affiliate of a
lender under the 2010 Credit Agreement.
The 2010 Credit Agreement contains customary representations, warranties, indemnities and
affirmative and negative covenants. The 2010 Credit Agreement also requires compliance with two
financial covenants. The Company must not permit its debt to capitalization ratio to exceed 45% at
any time. The 2010 Credit Agreement generally defines the debt to capitalization ratio as the
ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus
consolidated net worth, with consolidated net worth determined as of the last day of the most
recently ended fiscal quarter. The Company also must not permit the interest coverage ratio as of
the last day of a fiscal quarter to be less than 3.00 to 1.00. The 2010 Credit Agreement generally
defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation
and amortization (EBITDA) of the four prior fiscal quarters to interest charges for the same
period. 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 September 30, 2010, the Company had $100 million outstanding under the term loan
facility at an interest rate of 3.125% and no borrowings outstanding under the revolving credit
facility. The Company had $41.2 million in letters of credit outstanding at September 30, 2010
and, as a result, had available borrowing capacity of approximately $359 million at that date.
Presented
below is a schedule of the principal repayment requirements of long-term debt by fiscal year
as of September 30, 2010 (in thousands):
|
|
|
|
|
Year ending December 31, |
|
|
|
|
2010 |
|
$ |
1,250 |
|
2011 |
|
|
6,250 |
|
2012 |
|
|
10,000 |
|
2013 |
|
|
12,500 |
|
2014 |
|
|
70,000 |
|
Thereafter |
|
|
|
|
|
|
|
|
Total |
|
$ |
100,000 |
|
|
|
|
|
11. Commitments, Contingencies and Other Matters
As of September 30, 2010, the Company maintained letters of credit in the aggregate amount of
$41.2 million for the benefit of various insurance companies as collateral for retrospective
premiums and retained losses which could become payable under the terms
13
of the underlying insurance contracts. These letters of credit expire annually at various
times during the year and are typically renewed. As of September 30, 2010, no amounts had been
drawn under the letters of credit.
As
of September 30, 2010, the Company had commitments to purchase
approximately $250 million
of major equipment.
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.
12. Stockholders Equity
Cash Dividends The Company paid cash dividends during the nine months ended September 30,
2009 and 2010 as follows:
|
|
|
|
|
|
|
|
|
|
|
Per Share |
|
|
Total |
|
|
|
|
|
|
|
(in thousands) |
|
2009: |
|
|
|
|
|
|
|
|
Paid on March 31, 2009 |
|
$ |
0.05 |
|
|
$ |
7,655 |
|
Paid on June 30, 2009 |
|
|
0.05 |
|
|
|
7,675 |
|
Paid on September 30, 2009 |
|
|
0.05 |
|
|
|
7,675 |
|
|
|
|
|
|
|
|
Total cash dividends |
|
$ |
0.15 |
|
|
$ |
23,005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Share |
|
|
Total |
|
|
|
|
|
|
|
(in thousands) |
|
2010: |
|
|
|
|
|
|
|
|
Paid on March 30, 2010 |
|
$ |
0.05 |
|
|
$ |
7,677 |
|
Paid on June 30, 2010 |
|
|
0.05 |
|
|
|
7,706 |
|
Paid on September 30, 2010 |
|
|
0.05 |
|
|
|
7,704 |
|
|
|
|
|
|
|
|
Total cash dividends |
|
$ |
0.15 |
|
|
$ |
23,087 |
|
|
|
|
|
|
|
|
On October 27, 2010, the Companys Board of Directors approved a cash dividend on its common
stock in the amount of $0.05 per share to be paid on December 30, 2010 to holders of record as of
December 15, 2010. 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
authorizing purchases of up to $250 million of the Companys common stock in open market or
privately negotiated transactions. During the nine months ended September 30, 2010, the Company
purchased 8,743 shares of its common stock under the program at a cost of approximately $123,000.
As of September 30, 2010, the Company is authorized to purchase approximately $113 million of the
Companys outstanding common stock under the program. Shares purchased under the program are
accounted for as treasury stock.
The Company purchased 116,819 shares of treasury stock from employees during the nine months
ended September 30, 2010. These shares were purchased at fair market value upon the vesting of
restricted stock to provide the employees with the funds necessary to satisfy payroll tax
withholding obligations. The total purchase price for these shares was approximately $1.7 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 stock buyback program.
13. Income Taxes
On January 1, 2010, the Company converted its Canadian operations from a Canadian branch to a
controlled foreign corporation for Federal income tax purposes. Because the statutory tax rates in
Canada are lower than those in the United States, this transaction triggered a $5.1 million
reduction in the Companys deferred tax liabilities, which is being amortized as a reduction to
deferred income tax expense over the weighted average remaining useful life of the Canadian assets.
As a result of the above conversion, the Companys Canadian assets are no longer subject to
United States taxation, provided that the related unremitted earnings are permanently reinvested in
Canada. Effective January 1, 2010, the Company has elected to permanently reinvest these
unremitted earnings in Canada, and it intends to do so for the foreseeable future. As a result, no
deferred United States Federal or state income taxes have been provided on such unremitted foreign
earnings, which totaled approximately $1.7 million as of September 30, 2010.
14
14. Recently Issued Accounting Standards
In June 2009, the FASB issued a new accounting standard that amends the accounting and
disclosure requirements for the consolidation of variable interest entities. This new standard
removes the previously existing exception from applying consolidation guidance to qualifying
special-purpose entities and requires ongoing reassessments of whether an enterprise is the primary
beneficiary of a variable interest entity. Before this new standard, generally accepted accounting
principles required reconsideration of whether an enterprise is the primary beneficiary of a
variable interest entity only when specific events occurred. This new standard is effective as of
the beginning of each reporting entitys first annual reporting period that begins after November
15, 2009, for interim periods within that first annual reporting period, and for interim and annual
reporting periods thereafter. This new standard became effective for the Company on January 1,
2010. The adoption of this standard did not impact the Companys consolidated financial
statements.
In October 2009, the FASB issued a new accounting standard that addresses the accounting for
multiple-deliverable revenue arrangements to enable vendors to account for deliverables separately
rather than as a combined unit. This new standard addresses how to separate deliverables and how
to measure and allocate arrangement consideration to one or more units of accounting. Existing
accounting standards require a vendor to use objective and reliable evidence of fair value for the
undelivered items or the residual method to separate deliverables in a multiple-deliverable
arrangement. Under the new standard, it is expected that multiple-deliverable arrangements will be
separated in more circumstances than under current requirements. The new standard establishes a
hierarchy for determining the selling price of a deliverable for purposes of allocating revenue to
multiple deliverables. The selling price used will be based on vendor-specific objective evidence
if available, third-party evidence if vendor-specific objective evidence is not available, or
estimated selling price if neither vendor-specific objective evidence nor third-party evidence is
available. The new standard must be prospectively applied to all revenue arrangements entered into
in fiscal years beginning on or after June 15, 2010 and will be effective for the Company on
January 1, 2011. The adoption of this standard is not expected to have a material impact on the
Companys consolidated financial position, results of operations or cash flows.
15. Subsequent Events
On October 5, 2010, the Company completed an issuance and sale of $300 million in aggregate
principal amount of its 4.97% Series A Senior Notes due October 5, 2020 (the Notes) in a private
placement. A portion of the proceeds from the Notes were used to repay a $200 million borrowing on
the Companys revolving credit facility which had been drawn to fund a portion of the acquisition that closed on October 1, 2010 as discussed in Note 3. The Notes are senior unsecured
obligations of the Company, which rank equally in right of payment with all other unsubordinated
indebtedness of the Company. The Notes are guaranteed on a senior unsecured basis by each of the
existing domestic subsidiaries of the Company other than immaterial subsidiaries.
The Notes bear interest at a rate of 4.97% per annum and were priced at 100% of the principal
amount of the Notes. The Company will pay interest on the Notes on April 5 and October 5 of each
year commencing on April 5, 2011. The Notes will mature on October 5, 2020. The Notes are
prepayable at the Companys option, in whole or in part, provided that in the case of a partial
prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of
the Notes then outstanding, at any time and from time to time at 100% of the principal amount
prepaid, plus accrued and unpaid interest to the prepayment date, plus a make-whole premium as
specified in the note purchase agreement. The Company must offer to prepay the Notes upon the
occurrence of any change of control. In addition, the Company must offer to prepay the Notes upon
the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in
productive assets. If any offer to prepay is accepted, the purchase price of each prepaid Note is
100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment
date.
The note purchase agreement requires compliance with two financial covenants. The Company
must not permit its debt to capitalization ratio to exceed 50% at any time. The note purchase
agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed
money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with
consolidated net worth determined as of the last day of the most recently ended fiscal quarter.
The Company also must not permit the interest coverage ratio as of the last day of a fiscal quarter
to be less than 2.50 to 1.00. The note purchase agreement generally defines the interest coverage
ratio as the ratio for the four prior quarters of EBITDA to interest charges.
Events of default under the note purchase agreement include failure to pay principal or
interest when due, failure to comply with the financial and operational covenants, a cross default
event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable,
the occurrence of certain ERISA events, a change of control event and bankruptcy and other
insolvency events. If an event of default occurs and is continuing, then holders of a majority in
principal amount of the Notes have the right to
declare all the Notes then outstanding to be immediately due and payable. In addition, if the
Company defaults in payments on any Note, then until such defaults are cured, the holder thereof
may declare all the Notes held by it to be immediately due and payable.
15
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (this Report) and other public filings and press releases
by us contain forward-looking statements within the meaning of the Securities Act of 1933, as
amended (the Securities Act), and the Securities Exchange Act of 1934, as amended (the Exchange
Act), and the Private Securities Litigation Reform Act of 1995, as amended. These
forward-looking statements involve risk and uncertainty. These forward-looking 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); impact of
inflation; demand for our services; and other matters. Our forward-looking statements can be
identified by the fact that they do not relate strictly to historic or current facts and often use
words such as believes, budgeted, continue, expects, estimates, project, will,
could, may, plans, intends, strategy, or anticipates, or the negative thereof and other
words and expressions of similar meaning. 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. Although we believe that the expectations reflected in such
forward-looking statements are reasonable, we can give no assurance that such expectations will
prove to have been correct. Forward-looking statements may be made orally or in writing,
including, but not limited to, Managements Discussion and Analysis of Financial Condition and
Results of Operations included in this Report and other sections of our filings with the United
States Securities and Exchange Commission (the SEC) under the Exchange Act and the Securities
Act.
Forward-looking statements are not guarantees of future performance and a variety of factors
could cause actual results to differ materially from the anticipated or expected results expressed
in or suggested by these forward-looking statements. Factors that might cause or contribute to
such differences include, but are not limited to, deterioration of global economic conditions,
declines in oil and natural gas prices that could adversely affect demand for our services and
their associated effect on day rates, rig utilization and planned capital expenditures, excess
availability of land drilling rigs, including as a result of the reactivation or construction of
new land drilling rigs, adverse industry conditions, adverse credit and equity market conditions,
difficulty in integrating acquisitions, demand for oil and natural gas, shortages of rig equipment,
governmental regulation and ability to retain management and field personnel. Refer to Risk
Factors contained in Part 1 of our Annual Report on Form 10-K for the year ended December 31, 2009
and Part II of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 for a more
complete discussion of these and other factors that might affect our performance and financial
results. You are cautioned not to place undue reliance on any of our forward-looking statements.
These forward-looking statements are intended to relay our expectations about the future, and speak
only as of the date they are made. We undertake no obligation to publicly update or revise any
forward-looking statement, whether as a result of new information, changes in internal estimates or
otherwise.
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, pressure pumping services. In
addition to the aforementioned contract services, we also invest, on a working interest basis, in
oil and natural gas properties. Prior to the sale of substantially all of the assets of our
drilling and completion fluids business in January 2010, we provided drilling fluids, completion
fluids and related services to oil and natural gas operators. Due to our exit from the drilling
and completion fluids business in January 2010, we have presented the results of that operating
segment as discontinued operations in this Report. For the three and nine months ended September
30, 2010 and 2009, our operating revenues from continuing operations consisted of the following
(dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Contract drilling |
|
$ |
290,759 |
|
|
|
77 |
% |
|
$ |
112,294 |
|
|
|
70 |
% |
|
$ |
741,470 |
|
|
|
78 |
% |
|
$ |
439,714 |
|
|
|
77 |
% |
Pressure pumping |
|
|
81,104 |
|
|
|
21 |
|
|
|
41,687 |
|
|
|
26 |
|
|
|
194,219 |
|
|
|
20 |
|
|
|
113,408 |
|
|
|
20 |
|
Oil and natural gas |
|
|
6,800 |
|
|
|
2 |
|
|
|
5,690 |
|
|
|
4 |
|
|
|
21,564 |
|
|
|
2 |
|
|
|
15,255 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
378,663 |
|
|
|
100 |
% |
|
$ |
159,671 |
|
|
|
100 |
% |
|
$ |
957,253 |
|
|
|
100 |
% |
|
$ |
568,377 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Generally, the profitability of our business is impacted most by two primary factors in our
contract drilling segment: our average number of rigs operating and our average revenue per
operating day. During the third quarter of 2010, our average number of rigs operating was 178
compared to 73 in the third quarter of 2009. Our average revenue per operating day was $17,730 in
the third quarter of 2010 compared to $16,800 in the third quarter of 2009. We had consolidated
net income of $29.4 million for the third quarter of 2010 compared to a consolidated net loss of
$18.6 million for the third quarter of 2009. The increase in consolidated net
16
income was primarily due to our contract drilling segment experiencing an increase in the
average number of rigs operating and increases in large fracturing jobs in our pressure pumping
segment in the third quarter of 2010 compared to the third quarter of 2009.
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 generally 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. Subsequent to reaching a peak in June 2008, there was a
significant decline in oil and natural gas prices and a substantial deterioration in the global
economic environment. As part of this deterioration, there was substantial uncertainty in the
capital markets and access to financing was reduced. Due to these conditions, our customers
reduced or curtailed their drilling programs, which resulted in a decrease in demand for our
services, as evidenced by the decline in our monthly average of rigs operating from a high of 283
in October 2008 to a low of 60 in June 2009 before partially recovering to 184 in September 2010.
Furthermore, these factors have resulted in, and could continue to result in, certain of our
customers experiencing an inability to pay suppliers, including us. We are also highly impacted by
competition, the availability of excess equipment, labor issues and various other factors that
could materially adversely affect our business, financial condition, cash flows and results of
operations. Please see Risk Factors included in Part I of our Annual Report on Form 10-K for the
fiscal year ended December 31, 2009 and Part II of our Quarterly Report on Form 10-Q for the
quarter ended June 30, 2010.
We believe that our liquidity as of September 30, 2010, which includes approximately $139
million in working capital and approximately $359 million available under our $400 million
revolving credit facility, together with cash expected to be generated from operations, should
provide us with sufficient ability to fund our current plans to build new equipment, make
improvements to our existing equipment and pay cash dividends.
On July 2, 2010, we entered into an Asset Purchase Agreement wherein one of our subsidiaries
agreed to purchase certain assets and assume certain liabilities from Key Energy Pressure Pumping
Services, LLC and Key Electric Wireline Services, LLC relating to the businesses of providing
certain pressure pumping services and electric wireline services to participants in the oil and
natural gas industry for an approximate aggregate purchase price of $238 million in cash. This
transaction closed on October 1, 2010, with two of our subsidiaries purchasing such assets and
assuming such liabilities. The purchase price was funded through a combination of cash on hand and
a $200 million draw on our revolving credit facility. The revolving credit facility borrowing was
subsequently repaid on October 5, 2010 using proceeds from the sale of $300 million in aggregate
principal amount of our 4.97% Series A Senior Notes due October 5, 2020.
If we pursue additional opportunities for growth that require capital, we believe we would be
able to satisfy these needs through a combination of working capital, cash generated from
operations, borrowing capacity under our revolving credit facility or additional debt or equity
financing. However, there can be no assurance that such capital will be available on reasonable
terms, if at all.
Commitments and Contingencies As of September 30, 2010, we maintained letters of credit in
the aggregate amount of $41.2 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 annually at various times during
the year and are typically renewed. As of September 30, 2010, no amounts had been drawn under the
letters of credit.
As
of September 30, 2010, we had commitments to purchase
approximately $250 million of major
equipment.
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 primarily in Texas, New
Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota,
Pennsylvania, West Virginia and western Canada. As of September 30, 2010, we had approximately 350
marketable land-based drilling rigs. As of October 1, 2010, we provide pressure pumping and
wireline services to oil and natural gas operators primarily in Texas and the Appalachian Basin.
Pressure pumping services consist primarily of well stimulation and cementing for completion of new
wells and remedial work on existing wells. Wireline services consist primarily of perforating,
completion and production logging and casing integrity services. Prior to the sale of
substantially all of the assets of our drilling and completion fluids business in January 2010, we
provided drilling fluids, completion fluids and related services to oil and natural gas operators
offshore in the Gulf of Mexico and on land in Texas, New Mexico, Oklahoma and Louisiana. Due to
our exit from the drilling and completion fluids business in January 2010, we have presented the
results of that operating segment as discontinued operations in this Report.
17
The North American land drilling industry has experienced periods of downturn in demand over
the last decade. During these periods, there have been substantially more drilling rigs available
than necessary to meet demand. As a result, drilling contractors have had difficulty sustaining
profit margins and, at times, have sustained losses during the downturn periods.
In addition, exploration and development of unconventional resource plays has substantially
increased recently and some drilling rigs are not capable of drilling these wells efficiently.
Accordingly, the utilization of some older technology drilling rigs may be hampered by their lack
of capability to successfully compete for this work. Other 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. |
Construction of new drilling rigs increased significantly during the last ten years. The
addition of new drilling rigs to the market has significantly contributed to excess capacity. 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 our Annual Report on Form 10-K for the fiscal
year ended December 31, 2009.
Liquidity and Capital Resources
As of September 30, 2010, we had working capital of $139 million, including cash and cash
equivalents of $73.9 million compared to working capital of $264 million and cash and cash
equivalents of $49.9 million at December 31, 2009. The decrease in working capital during the nine
months ended September 30, 2010 was primarily due to capital expenditures and deposits on equipment
purchases exceeding operating cash flow.
During the nine months ended September 30, 2010, our sources of cash flow included:
|
|
|
$402 million from operating activities, |
|
|
|
|
$100 million in term borrowings under our $500 million credit facility, |
|
|
|
|
$42.6 million in proceeds from the disposal of our drilling and completion fluids business,
and |
|
|
|
|
$27.2 million in proceeds from the sale of certain oil and natural gas rights and the
disposal of other assets. |
During the nine months ended September 30, 2010, we used $23.1 million to pay dividends on our
common stock, $10.3 million to pay debt issuance costs, and $514 million to:
|
|
|
build new drilling rigs, |
|
|
|
|
make capital expenditures for the betterment and refurbishment of our drilling rigs, |
|
|
|
|
acquire and procure drilling equipment and facilities to support our drilling operations, |
|
|
|
|
fund capital expenditures for our pressure pumping segment, and |
|
|
|
|
fund investments in oil and natural gas properties on a working interest basis. |
18
We paid cash dividends during the nine months ended September 30, 2010 as follows:
|
|
|
|
|
|
|
|
|
|
|
Per Share |
|
|
Total |
|
|
|
|
|
|
|
(in thousands) |
|
Paid on March 30, 2010 |
|
$ |
0.05 |
|
|
$ |
7,677 |
|
Paid on June 30, 2010 |
|
|
0.05 |
|
|
|
7,706 |
|
Paid on September 30, 2010 |
|
|
0.05 |
|
|
|
7,704 |
|
|
|
|
|
|
|
|
Total cash dividends |
|
$ |
0.15 |
|
|
$ |
23,087 |
|
|
|
|
|
|
|
|
On October 27, 2010, our Board of Directors approved a cash dividend on our common stock in
the amount of $0.05 per share to be paid on December 30, 2010 to holders of record as of December
15, 2010. 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, authorizing
purchases of up to $250 million of our common stock in open market or privately negotiated
transactions. During the nine months ended September 30, 2010, we purchased 8,743 shares of our
common stock under the program at a cost of approximately $123,000. As of September 30, 2010, we
are authorized to purchase approximately $113 million of our outstanding common stock under the
program.
On August 19, 2010, we entered into the 2010 Credit Agreement. The 2010 Credit Agreement is a
committed senior unsecured credit facility that permits aggregate borrowings of up to $500 million
pursuant to a revolving credit facility and a term loan facility. The 2010 Credit Agreement
replaced a previous unsecured revolving credit facility.
The revolving credit facility permits aggregate borrowings of up to, at any time outstanding,
$400 million, which contains a letter of credit facility that, at any time outstanding, is limited
to $150 million and a swing line facility that, at any time outstanding, is limited to $40 million.
Subject to customary conditions, we may request that the lenders aggregate commitments with
respect to the revolving credit facility be increased by up to $100 million, not to exceed total
commitments of $500 million. The maturity date for the revolving facility is August 19, 2013.
The term loan facility provided for a loan of $100 million which was funded on August 19,
2010, the proceeds of which may be used for general corporate purposes. The term loan facility is
payable in quarterly principal installments commencing November 19, 2010, and the installment
amounts vary from 1.25% of the original principal amount for each of the first four quarterly
installments, 2.50% of the original principal amount for each of the subsequent eight quarterly
installments, 5.00% of the original principal amount for the next subsequent three quarterly
installments and the remainder at maturity. The maturity date for the term loan facility is August
19, 2014.
Loans under the 2010 Credit Agreement bear interest by reference, at our election, to the
LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to the
base rate. The applicable margin on LIBOR rate loans varies from 2.75% to 3.75% and the applicable
margin on base rate loans varies from 1.75% to 2.75%, in each case determined based upon our debt
to capitalization ratio. As of September 30, 2010, the applicable margin on LIBOR rate loans was
2.75% and the applicable margin on base rate loans was 1.75%. A letter of credit fee is payable by
us equal to the applicable margin for LIBOR rate loans times the daily amount available to be drawn
under outstanding letters of credit. The commitment fee payable to the lenders for the unused
portion of the revolving credit facility varies from 0.50% to 0.75% based upon our debt to
capitalization ratio and was 0.50% as of September 30, 2010.
The 2010 Credit Agreement contains customary representations, warranties, indemnities and
affirmative and negative covenants. The 2010 Credit Agreement also requires compliance with two
financial covenants. We must not permit our debt to capitalization ratio to exceed 45% at any
time. The 2010 Credit Agreement generally defines the debt to capitalization ratio as the ratio of
(a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net
worth, with consolidated net worth determined as of the last day of the most recently ended fiscal
quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal
quarter to be less than 3.00 to 1.00. The 2010 Credit Agreement generally defines the interest
coverage ratio as the ratio of EBITDA of the four prior fiscal quarters to interest charges for the
same period. We were in compliance with these financial covenants as of September 30, 2010. We do
not expect that the restrictions and covenants will impair our ability to operate or react to
opportunities that might arise.
19
As of September 30, 2010, the Company had $100 million outstanding under the term loan
facility at an interest rate of 3.125% and no borrowings outstanding under the revolving credit
facility. The Company had $41.2 million in letters of credit outstanding at September 30, 2010
and, as a result, had available borrowing capacity of approximately $359 million at that date.
On October 5, 2010, we completed an issuance and sale of $300 million in aggregate principal
amount of our 4.97% Series A Senior Notes due October 5, 2020 (the Notes) in a private placement.
The Notes bear interest at a rate of 4.97% per annum and were priced at 100% of the principal
amount of the Notes. We will pay interest on the Notes on April 5 and October 5 of each year
commencing on April 5, 2011. The Notes will mature on October 5, 2020. The Notes are prepayable
at the our option, in whole or in part, provided that in the case of a partial prepayment,
prepayment must be in an amount not less than 5% of the aggregate principal amount of the Notes
then outstanding, at any time and from time to time at 100% of the principal amount prepaid, plus
accrued and unpaid interest to the prepayment date, plus a make-whole premium as specified in the
note purchase agreement. We must offer to prepay the Notes upon the occurrence of any change of
control. In addition, we must offer to prepay the Notes upon the occurrence of certain asset
dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any
offer to prepay is accepted, the purchase price of each prepaid Note is 100% of the principal
amount thereof, plus accrued and unpaid interest thereon to the prepayment date.
The note purchase agreement requires compliance with two financial covenants. We must not
permit our debt to capitalization ratio to exceed 50% at any time. The note purchase agreement
generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money
indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net
worth determined as of the last day of the most recently ended fiscal quarter. We also must not
permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to
1.00. The note purchase agreement generally defines the interest coverage ratio as the ratio for
the four prior quarters of EBITDA to interest charges.
Events of default under the note purchase agreement include failure to pay principal or
interest when due, failure to comply with the financial and operational covenants, a cross default
event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable,
the occurrence of certain ERISA events, a change of control event and bankruptcy and other
insolvency events. If an event of default occurs and is continuing, then holders of a majority in
principal amount of the Notes have the right to declare all the Notes then outstanding to be
immediately due and payable. In addition, if we default in payments on any Note, then until such
defaults are cured, the holder thereof may declare all the Notes held by it to be immediately due
and payable.
We believe that the current level of cash, short-term investments and borrowing capacity
available under our revolving credit facility, together with cash expected to be generated from
operations, should be sufficient to fund our current plans to build new equipment, make
improvements to our existing equipment and pay cash dividends.
On July 2, 2010, we entered into an Asset Purchase Agreement wherein one of our subsidiaries
agreed to purchase certain assets and assume certain liabilities from Key Energy Pressure Pumping
Services, LLC and Key Electric Wireline Services, LLC relating to the business of providing certain
pressure pumping services and certain electric wireline services to participants in the oil and
natural gas industry for an approximate aggregate purchase price of $238 million in cash. The
transaction closed on October 1, 2010, with two of our subsidiaries purchasing such assets and
assuming such liabilities. The purchase price was funded through a combination of cash on hand and
a $200 million draw on our revolving credit facility. The revolving credit facility borrowing was
subsequently repaid on October 5, 2010 using proceeds from the sale of the Notes.
From time to time, opportunities to expand our business, including acquisitions and the
building of new equipment, are evaluated. The timing, size or success of any acquisition and the
associated capital commitments are unpredictable. If we pursue additional opportunities for growth
that require capital, we believe we would be able to satisfy these needs through a combination of
working capital, cash generated from operations, borrowing capacity under our revolving credit
facility or additional debt or equity financing. However, there can be no assurance that such
capital will be available on reasonable terms, if at all.
20
Results of Operations
The following tables summarize operations by business segment for the three months ended
September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract Drilling |
|
2010 |
|
2009 |
|
%Change |
|
|
(Dollars in thousands) |
|
|
|
|
Revenues |
|
$ |
290,759 |
|
|
$ |
112,294 |
|
|
|
158.9 |
% |
Direct operating costs |
|
$ |
174,999 |
|
|
$ |
71,035 |
|
|
|
146.4 |
% |
Selling, general and administrative |
|
$ |
1,664 |
|
|
$ |
1,087 |
|
|
|
53.1 |
% |
Depreciation |
|
$ |
72,617 |
|
|
$ |
60,083 |
|
|
|
20.9 |
% |
Operating income (loss) |
|
$ |
41,479 |
|
|
$ |
(19,911 |
) |
|
|
N/M |
|
Operating days |
|
|
16,400 |
|
|
|
6,685 |
|
|
|
145.3 |
% |
Average revenue per operating day |
|
$ |
17.73 |
|
|
$ |
16.80 |
|
|
|
5.5 |
% |
Average direct operating costs per operating day |
|
$ |
10.67 |
|
|
$ |
10.63 |
|
|
|
0.4 |
% |
Average rigs operating |
|
|
178 |
|
|
|
73 |
|
|
|
143.8 |
% |
Capital expenditures |
|
$ |
192,233 |
|
|
$ |
93,340 |
|
|
|
105.9 |
% |
Revenues increased in 2010 compared to 2009 as a result of a significant increase in operating
days and an increase in average revenue per operating day. Direct operating costs increased in
2010 compared to 2009 primarily as a result of an increase in the number of operating days. The
increase in operating days was due to increased demand largely caused by higher prices for natural
gas and oil. Significant capital expenditures were incurred in 2010 and 2009 to build new drilling
rigs, to modify and upgrade our drilling rigs and to acquire additional related equipment such as
top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and
safety enhancement equipment. Depreciation expense increased as a result of capital expenditures.
|
|
|
|
|
|
|
|
|
|
|
|
|
Pressure Pumping |
|
2010 |
|
2009 |
|
%Change |
|
|
(Dollars in thousands) |
|
|
|
|
Revenues |
|
$ |
81,104 |
|
|
$ |
41,687 |
|
|
|
94.6 |
% |
Direct operating costs |
|
$ |
51,305 |
|
|
$ |
31,092 |
|
|
|
65.0 |
% |
Selling, general and administrative |
|
$ |
2,668 |
|
|
$ |
2,168 |
|
|
|
23.1 |
% |
Depreciation |
|
$ |
9,545 |
|
|
$ |
7,216 |
|
|
|
32.3 |
% |
Operating income |
|
$ |
17,586 |
|
|
$ |
1,211 |
|
|
|
N/M |
|
Fracturing jobs |
|
|
420 |
|
|
|
455 |
|
|
|
(7.7 |
)% |
Other jobs |
|
|
1,600 |
|
|
|
1,446 |
|
|
|
10.7 |
% |
Total jobs |
|
|
2,020 |
|
|
|
1,901 |
|
|
|
6.3 |
% |
Average revenue per fracturing job |
|
$ |
147.20 |
|
|
$ |
64.52 |
|
|
|
128.1 |
% |
Average revenue per other job |
|
$ |
12.05 |
|
|
$ |
8.53 |
|
|
|
41.3 |
% |
Average revenue per total job |
|
$ |
40.15 |
|
|
$ |
21.93 |
|
|
|
83.1 |
% |
Average direct operating costs per total job |
|
$ |
25.40 |
|
|
$ |
16.36 |
|
|
|
55.3 |
% |
Capital expenditures |
|
$ |
15,531 |
|
|
$ |
3,582 |
|
|
|
333.6 |
% |
Our customers have increased their activities in the development of unconventional reservoirs
in the Appalachian Basin resulting in an increase in larger fracturing jobs associated therewith.
As a result, we have experienced an increase in the number of larger fracturing jobs as a
proportion of the total fracturing jobs we performed. Revenues and direct operating costs
increased primarily as a result of the increase in average revenue and direct operating costs per
job. Increased average revenue per fracturing job reflects the increase in the proportion of
larger fracturing jobs to total fracturing jobs, which was driven by demand for services associated
with unconventional reservoirs. Average revenue per other job increased as a result of increased
pricing for the services provided and a change in job mix. Average direct operating costs per job
increased primarily due to the increase in larger fracturing jobs. Significant capital
expenditures have been incurred in recent years to add capacity. Depreciation expense increased as
a result of capital expenditures.
21
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas Production and Exploration |
|
2010 |
|
2009 |
|
%Change |
|
|
(Dollars in thousands, |
|
|
|
|
|
|
except sales prices) |
|
|
|
|
Revenues |
|
$ |
6,800 |
|
|
$ |
5,690 |
|
|
|
19.5 |
% |
Direct operating costs |
|
$ |
1,484 |
|
|
$ |
1,780 |
|
|
|
(16.6 |
)% |
Depreciation, depletion and impairment |
|
$ |
2,851 |
|
|
$ |
2,056 |
|
|
|
38.7 |
% |
Operating income |
|
$ |
2,465 |
|
|
$ |
1,854 |
|
|
|
33.0 |
% |
Capital expenditures |
|
$ |
4,782 |
|
|
$ |
2,214 |
|
|
|
116.0 |
% |
Average net daily oil production (Bbls) |
|
|
828 |
|
|
|
735 |
|
|
|
12.7 |
% |
Average net daily natural gas production (Mcf) |
|
|
2,558 |
|
|
|
3,172 |
|
|
|
(19.4 |
)% |
Average oil sales price (per Bbl) |
|
$ |
73.26 |
|
|
$ |
66.01 |
|
|
|
11.0 |
% |
Average natural gas sales price (per Mcf) |
|
$ |
5.19 |
|
|
$ |
4.20 |
|
|
|
23.6 |
% |
Revenues increased due to higher average sales prices of oil and natural gas and increased oil
production partially offset by a reduction in natural gas production. Depreciation, depletion and
impairment expense in 2010 includes approximately $119,000 incurred to impair certain oil and
natural gas properties compared to approximately $249,000 incurred to impair certain oil and
natural gas properties in 2009. Capital expenditures increased in 2010 as a result of greater
drilling activity and increased costs per well.
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and Other |
|
2010 |
|
2009 |
|
%Change |
|
|
(Dollars in thousands) |
|
|
|
|
Selling, general and administrative |
|
$ |
9,353 |
|
|
$ |
8,129 |
|
|
|
15.1 |
% |
Depreciation |
|
$ |
418 |
|
|
$ |
227 |
|
|
|
84.1 |
% |
Provision for bad debts |
|
$ |
(500 |
) |
|
$ |
285 |
|
|
|
N/M |
|
Net gain (loss) on asset disposals |
|
$ |
250 |
|
|
$ |
868 |
|
|
|
(71.2 |
)% |
Interest income |
|
$ |
64 |
|
|
$ |
53 |
|
|
|
20.8 |
% |
Interest expense |
|
$ |
6,227 |
|
|
$ |
1,448 |
|
|
|
330.0 |
% |
Other income |
|
$ |
260 |
|
|
$ |
228 |
|
|
|
14.0 |
% |
Capital expenditures |
|
$ |
2,288 |
|
|
$ |
4,762 |
|
|
|
52.0 |
% |
Selling, general and administrative expense increased in 2010 primarily as a result of
increased personnel costs. The provision for bad debts in 2009 resulted from an increase in our
reserve on specific account balances based on the deteriorating economic and credit environment at
the time. The negative provision for bad debts in 2010 is the result of reductions in our reserve
for specific accounts due to improved industry conditions. Gains and losses on the disposal of
assets are treated as part of our corporate activities because such transactions relate to
corporate strategy decisions of our executive management group. Interest expense increased due to
the recognition of deferred financing costs. Interest expense in 2010 includes $3.3 million due to
the recognition of remaining deferred financing costs associated with the revolving credit facility
that was replaced in August 2010 and includes $1.3 million due to the recognition of deferred
financing costs associated with the 364-Day Credit Agreement as it expired on September 30, 2010.
Capital expenditures have increased in 2010 due to the ongoing implementation of a new enterprise
resource planning system.
The following tables summarize operations by business segment for the nine months ended
September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract Drilling |
|
2010 |
|
2009 |
|
%Change |
|
|
(Dollars in thousands) |
|
|
|
|
Revenues |
|
$ |
741,470 |
|
|
$ |
439,714 |
|
|
|
68.6 |
% |
Direct operating costs |
|
$ |
459,448 |
|
|
$ |
254,306 |
|
|
|
80.7 |
% |
Selling, general and administrative |
|
$ |
3,816 |
|
|
$ |
3,169 |
|
|
|
20.4 |
% |
Depreciation |
|
$ |
205,927 |
|
|
$ |
176,024 |
|
|
|
17.0 |
% |
Operating income |
|
$ |
72,279 |
|
|
$ |
6,215 |
|
|
|
N/M |
|
Operating days |
|
|
43,407 |
|
|
|
23,878 |
|
|
|
81.8 |
% |
Average revenue per operating day |
|
$ |
17.08 |
|
|
$ |
18.42 |
|
|
|
(7.3 |
)% |
Average direct operating costs per operating day |
|
$ |
10.58 |
|
|
$ |
10.65 |
|
|
|
(0.7 |
)% |
Average rigs operating |
|
|
159 |
|
|
|
87 |
|
|
|
82.8 |
% |
Capital expenditures |
|
$ |
455,708 |
|
|
$ |
308,789 |
|
|
|
47.6 |
% |
Revenues increased in 2010 compared to 2009 as a result of a significant increase in operating
days somewhat reduced by the impact of a decrease in average revenue per operating day. Average
revenue per operating day decreased in 2010 primarily due to decreases in dayrates for rigs that
were operating in the spot market and a smaller proportion of rigs on term contracts which are
generally at higher rates. Revenues in 2009 also included $8.0 million from the early termination
of drilling contracts. We recognized no revenues from the early termination of drilling contracts
in 2010. Direct operating costs increased in 2010 compared to 2009
22
primarily as a result of an increase in the number of operating days. The increase in
operating days was due to increased demand largely caused by higher prices for natural gas and oil.
Significant capital expenditures were incurred in 2010 and 2009 to build new drilling rigs, to
modify and upgrade our drilling rigs and to acquire additional related equipment such as top
drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and
safety enhancement equipment. Depreciation expense increased as a result of capital expenditures.
|
|
|
|
|
|
|
|
|
|
|
|
|
Pressure Pumping |
|
2010 |
|
2009 |
|
%Change |
|
|
(Dollars in thousands) |
|
|
|
|
Revenues |
|
$ |
194,219 |
|
|
$ |
113,408 |
|
|
|
71.3 |
% |
Direct operating costs |
|
$ |
132,401 |
|
|
$ |
87,419 |
|
|
|
51.5 |
% |
Selling, general and administrative |
|
$ |
8,014 |
|
|
$ |
6,508 |
|
|
|
23.1 |
% |
Depreciation |
|
$ |
25,035 |
|
|
$ |
20,043 |
|
|
|
24.9 |
% |
Operating income (loss) |
|
$ |
28,769 |
|
|
$ |
(562 |
) |
|
|
N/M |
|
Fracturing jobs |
|
|
1,078 |
|
|
|
1,200 |
|
|
|
(10.2 |
)% |
Other jobs |
|
|
4,350 |
|
|
|
4,151 |
|
|
|
4.8 |
% |
Total jobs |
|
|
5,428 |
|
|
|
5,351 |
|
|
|
1.4 |
% |
Average revenue per fracturing job |
|
$ |
134.31 |
|
|
$ |
64.61 |
|
|
|
107.9 |
% |
Average revenue per other job |
|
$ |
11.36 |
|
|
$ |
8.64 |
|
|
|
31.5 |
% |
Average revenue per total job |
|
$ |
35.78 |
|
|
$ |
21.19 |
|
|
|
68.9 |
% |
Average direct operating costs per total job |
|
$ |
24.39 |
|
|
$ |
16.34 |
|
|
|
49.3 |
% |
Capital expenditures |
|
$ |
36,342 |
|
|
$ |
32,155 |
|
|
|
13.0 |
% |
Our customers have increased their activities in the development of unconventional reservoirs
in the Appalachian Basin resulting in an increase in larger fracturing jobs associated therewith.
As a result, we have experienced an increase in the number of larger fracturing jobs as a
proportion of the total fracturing jobs we performed. A decrease in smaller traditional fracturing
jobs contributed to the overall decrease in the number of total fracturing jobs. Revenues and
direct operating costs increased primarily as a result of the increase in average revenue and
direct operating costs per job. Increased average revenue per fracturing job reflects the increase
in the proportion of larger fracturing jobs to total fracturing jobs, which was driven by demand
for services associated with unconventional reservoirs. Average revenue per other job increased as
a result of increased pricing for the services provided and a change in job mix. Average direct
operating costs per job primarily increased due to the increase in larger fracturing jobs.
Selling, general and administrative expense increased primarily due to additional costs necessary
to support increased business activity in 2010. Significant capital expenditures have been
incurred in recent years to add capacity. Depreciation expense increased as a result of capital
expenditures.
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas Production and Exploration |
|
2010 |
|
2009 |
|
%Change |
|
|
(Dollars in thousands, |
|
|
|
|
|
|
except sales prices) |
|
|
|
|
Revenues |
|
$ |
21,564 |
|
|
$ |
15,255 |
|
|
|
41.4 |
% |
Direct operating costs |
|
$ |
5,326 |
|
|
$ |
5,576 |
|
|
|
(4.5 |
)% |
Depreciation, depletion and impairment |
|
$ |
8,029 |
|
|
$ |
10,823 |
|
|
|
(25.8 |
)% |
Operating income (loss) |
|
$ |
8,209 |
|
|
$ |
(1,144 |
) |
|
|
N/M |
|
Capital expenditures |
|
$ |
15,902 |
|
|
$ |
4,735 |
|
|
|
235.8 |
% |
Average net daily oil production (Bbls) |
|
|
829 |
|
|
|
790 |
|
|
|
4.9 |
% |
Average net daily natural gas production (Mcf) |
|
|
2,916 |
|
|
|
3,385 |
|
|
|
(13.9 |
)% |
Average oil sales price (per Bbl) |
|
$ |
75.05 |
|
|
$ |
53.47 |
|
|
|
40.4 |
% |
Average natural gas sales price (per Mcf) |
|
$ |
5.75 |
|
|
$ |
4.04 |
|
|
|
42.3 |
% |
Revenues increased due to higher average sales prices of oil and natural gas partially offset
by a reduction in natural gas production. Average net daily natural gas production decreased
primarily due to production declines on existing wells. Depreciation, depletion and impairment
expense in 2010 includes approximately $789,000 incurred to impair certain oil and natural gas
properties compared to approximately $3.3 million incurred to impair certain oil and natural gas
properties in 2009. Depletion expense decreased approximately $378,000 primarily due to lower
natural gas production. Capital expenditures increased in 2010 as a result of greater drilling
activity and increased costs per well.
23
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and Other |
|
2010 |
|
2009 |
|
%Change |
|
|
(Dollars in thousands) |
|
|
|
|
Selling, general and administrative |
|
$ |
25,661 |
|
|
$ |
23,536 |
|
|
|
9.0 |
% |
Depreciation |
|
$ |
939 |
|
|
$ |
681 |
|
|
|
37.9 |
% |
Provision for bad debts |
|
$ |
(1,500 |
) |
|
$ |
6,035 |
|
|
|
N/M |
|
Net gain on asset disposals |
|
$ |
21,940 |
|
|
$ |
423 |
|
|
|
N/M |
|
Interest income |
|
$ |
1,631 |
|
|
$ |
318 |
|
|
|
412.9 |
% |
Interest expense |
|
$ |
9,011 |
|
|
$ |
2,734 |
|
|
|
229.6 |
% |
Other income |
|
$ |
509 |
|
|
$ |
263 |
|
|
|
93.5 |
% |
Capital expenditures |
|
$ |
5,727 |
|
|
$ |
4,762 |
|
|
|
20.3 |
% |
Selling, general and administrative expense increased in 2010 primarily as a result of
increased personnel costs. The provision for bad debts in 2009 resulted from an increase in our
reserve on specific account balances based on the deteriorating economic and credit environment at
the time. The negative provision for bad debts in 2010 is the result of collections of certain
accounts that had previously been reserved and reductions in our reserve for certain accounts due
to improved industry conditions. Gains and losses on the disposal of assets are treated as part of
our corporate activities because such transactions relate to corporate strategy decisions of our
executive management group. The gain on asset disposals in 2010 includes a gain of $20.1 million
related to the sale of certain rights to explore and develop zones deeper than depths that we
generally target for certain of the oil and natural gas properties in which we have working
interests. Interest income increased due to the collection of interest on a customer account as
well as interest received on prior overpayments of sales taxes in certain jurisdictions. Interest
expense increased due to the recognition of deferred financing costs. Interest expense in 2010
includes $3.3 million due to the recognition of remaining deferred financing costs associated with
the revolving credit facility that was replaced in August 2010 and includes $1.3 million due to the
recognition of deferred financing costs associated with the 364-Day Credit Agreement as it expired
on September 30, 2010. Capital expenditures have increased in 2010 due to the ongoing
implementation of a new enterprise resource planning system.
Income Taxes
On January 1, 2010, we converted our Canadian operations from a Canadian branch to a
controlled foreign corporation for Federal income tax purposes. Because the statutory tax rates in
Canada are lower than those in the United States, this transaction triggered a $5.1 million
reduction in our deferred tax liabilities, which is being amortized as a reduction to deferred
income tax expense over the weighted average remaining useful life of the Canadian assets.
As a result of the above conversion, our Canadian assets are no longer subject to United
States taxation, provided that the related unremitted earnings are permanently reinvested in
Canada. Effective January 1, 2010, we have elected to permanently reinvest these unremitted
earnings in Canada, and we intend to do so for the foreseeable future. As a result, no deferred
United States Federal or state income taxes have been provided on such unremitted foreign earnings,
which totaled approximately $1.7 million as of September 30, 2010.
Recently Issued Accounting Standards
In June 2009, the FASB issued a new accounting standard that amends the accounting and
disclosure requirements for the consolidation of variable interest entities. This new standard
removes the previously existing exception from applying consolidation guidance to qualifying
special-purpose entities and requires ongoing reassessments of whether an enterprise is the primary
beneficiary of a variable interest entity. Before this new standard, generally accepted accounting
principles required reconsideration of whether an enterprise is the primary beneficiary of a
variable interest entity only when specific events occurred. This new standard is effective as of
the beginning of each reporting entitys first annual reporting period that begins after November
15, 2009, for interim periods within that first annual reporting period, and for interim and annual
reporting periods thereafter. This new standard became effective for us on January 1, 2010. The
adoption of this standard did not impact our consolidated financial statements.
In October 2009, the FASB issued a new accounting standard that addresses the accounting for
multiple-deliverable revenue arrangements to enable vendors to account for deliverables separately
rather than as a combined unit. This new standard addresses how to separate deliverables and how
to measure and allocate arrangement consideration to one or more units of accounting. Existing
accounting standards require a vendor to use objective and reliable evidence of fair value for the
undelivered items or the residual method to separate deliverables in a multiple-deliverable
arrangement. Under the new standard, it is expected that multiple-deliverable arrangements will be
separated in more circumstances than under current requirements. The new standard establishes a
hierarchy for determining the selling price of a deliverable for purposes of allocating revenue to
multiple deliverables. The selling
24
price used will be based on vendor-specific objective evidence if available, third-party
evidence if vendor-specific objective evidence is not available, or estimated selling price if
neither vendor-specific objective evidence nor third-party evidence is available. The new standard
must be prospectively applied to all revenue arrangements entered into in fiscal years beginning on
or after June 15, 2010 and will be effective for the Company on January 1, 2011. The adoption of
this standard is not expected to have a material impact on our consolidated financial position,
results of operations or cash flows.
Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition
Our revenue, profitability, financial condition and rate of growth are substantially dependent
upon prevailing prices for natural gas and oil. For many years, oil and natural gas prices and
markets have been extremely 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
2008, the monthly average market price of natural gas (monthly average Henry Hub price as reported
by the Energy Information Administration) peaked in June at $13.06 per Mcf before rapidly declining
to an average of $5.99 per Mcf in December. In 2009, the monthly average market price of natural
gas declined further to a low of $3.06 per Mcf in September. This decline in the market price of
natural gas resulted in our customers significantly reducing their drilling activities beginning in
the fourth quarter of 2008 and drilling activities remained low throughout 2009. Construction of
new land drilling rigs in the United States during the last ten years has significantly contributed
to excess capacity. As a result of these factors, our average number of rigs operating has
declined significantly from historic highs. 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. Low market prices for natural gas and oil would likely result in demand for our drilling
rigs decreasing and would adversely affect our operating results, financial condition and cash
flows.
The North American land drilling industry has experienced downturns in demand 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 and, at times, have incurred losses during the downturn periods.
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk
We currently have exposure to interest rate market risk associated with any borrowings that we
have under our term credit facility or our revolving credit facility. Interest is paid on the
outstanding principal amount of borrowings at a floating rate based on, at our election, LIBOR or a
base rate. The margin on LIBOR loans ranges from 2.75% to 3.75% and the margin on base rate loans
ranges from 1.75% to 2.75%, based on our debt to capitalization ratio. At September 30, 2010, the
margin on LIBOR loans was 2.75% and the margin on base rate loans was 1.75%. As of September 30,
2010, we had no borrowings outstanding under our revolving credit facility and $100 million
outstanding under our term credit facility at an interest rate of 3.125%.
We conduct a portion of our 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 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 risk is
not material to our results of operations or financial condition.
The carrying values of cash and cash equivalents, trade receivables and accounts payable
approximate fair value due to the short-term maturity of these items.
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 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 September 30,
2010.
25
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.
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 September 30, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Approximate Dollar |
|
|
|
|
|
|
|
|
|
|
|
Total Number of |
|
|
Value of Shares |
|
|
|
|
|
|
|
|
|
|
|
Shares (or Units) |
|
|
That May Yet Be |
|
|
|
|
|
|
|
|
|
|
|
Purchased as Part |
|
|
Purchased Under the |
|
|
|
Total |
|
|
Average Price |
|
|
of Publicly |
|
|
Plans or |
|
|
|
Number of Shares |
|
|
Paid per |
|
|
Announced Plans |
|
|
Programs (in |
|
Period Covered |
|
Purchased |
|
|
Share |
|
|
or Programs |
|
|
thousands)(1) |
|
July 1-31, 2010 (2) |
|
|
51 |
|
|
$ |
15.90 |
|
|
|
|
|
|
$ |
113,162 |
|
August 1-31, 2010 (2) |
|
|
27,968 |
|
|
$ |
14.79 |
|
|
|
2,637 |
|
|
$ |
113,123 |
|
September 1-30, 2010 (2) |
|
|
51 |
|
|
$ |
16.84 |
|
|
|
|
|
|
$ |
113,123 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
28,070 |
|
|
$ |
14.79 |
|
|
|
2,637 |
|
|
$ |
113,123 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
On August 2, 2007, we announced that 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. |
|
(2) |
|
We purchased 51 shares in July, 25,331 shares in August and 51 shares
in September 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 Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan
and not pursuant to the stock buyback program. |
ITEM 6. Exhibits
The following exhibits are filed herewith or incorporated by reference, as indicated:
|
|
|
2.1
|
|
Asset Purchase Agreement dated July 2, 2010 by and among
Patterson-UTI Energy, Inc., Portofino
Acquisition Company, Key Energy Pressure
Pumping Services, LLC, Key
Electric Wireline Services, LLC, and Key Energy Services, Inc. (filed July 6, 2010 as Exhibit 2.1 to the Companys Current Report
on Form 8-K and incorporated herein by reference). |
|
|
|
2.2*
|
|
Letter Agreement dated
September 1, 2010 by and among Patterson-UTI Energy, Inc.,
Universal Pressure Pumping, Inc., Universal Wireline, Inc., Key
Energy
Services, Inc., Key Energy Pressure Pumping Services, LLC and Key
Electric Wireline Services LLC. |
|
|
|
2.3*
|
|
Letter Agreement dated
October 1, 2010 by and among Patterson-UTI Energy, Inc.,
Universal Pressure Pumping, Inc., Universal Wireline, Inc., Key
Energy
Services, Inc., Key Energy Pressure Pumping Services, LLC and Key
Electric Wireline Services LLC. |
|
|
|
3.1
|
|
Restated Certificate of Incorporation, as amended (filed August 9,
2004 as Exhibit 3.1 to the Companys Quarterly Report on Form 10-Q
for the quarterly period ended June 30, 2004 and incorporated
herein by reference). |
|
|
|
3.2
|
|
Amendment to Restated Certificate of Incorporation, as amended
(filed August 9, 2004 as Exhibit 3.2 to the Companys Quarterly
Report on Form 10-Q for the quarterly period ended June 30, 2004
and incorporated herein by reference). |
|
|
|
3.3
|
|
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). |
|
|
|
10.1
|
|
Fifth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term
Incentive Plan (filed August 2, 2010 as Exhibit 10.4 to the
Companys Quarterly Report on Form 10-Q for the quarterly period
ended June 30, 2010 and incorporated herein by reference). |
|
|
|
10.2
|
|
364-Day Credit Agreement dated July 2, 2010, among Patterson-UTI
Energy, Inc., as borrower, and Wells Fargo Bank, N.A., as
administrative agent and lender (filed July 6, 2010 as Exhibit 10.1
to the Companys Current Report on Form 8-K and incorporated herein
by reference). |
26
|
|
|
10.3
|
|
Credit Agreement dated August 19, 2010, among Patterson-UTI Energy,
Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent,
letter of credit issuer, swingline lender and lender and each of
the other letter of credit issuer and lender parties thereto (filed
August 19, 2010 as Exhibit 10.1 to the Companys Current Report on
Form 8-K and incorporated herein by reference). |
|
|
|
10.4
|
|
Note Purchase Agreement dated October 5, 2010 by and among the
Company and the purchasers named therein (filed October 6, 2010 as
Exhibit 10.1 to the Companys Current Report on Form 8-K and
incorporated herein by reference). |
|
|
|
31.1*
|
|
Certification of Chief Executive Officer pursuant to
Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as
amended. |
|
|
|
31.2*
|
|
Certification of Chief Financial Officer pursuant to
Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as
amended. |
|
|
|
32.1*
|
|
Certification of Chief Executive Officer and Chief Financial
Officer pursuant to 18 USC Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
101*
|
|
The following materials from Patterson-UTI Energy, Inc.s Quarterly
Report on Form 10-Q for the quarter ended September 30, 2010,
formatted in XBRL (Extensible Business Reporting Language): (i)
the Consolidated Balance Sheets, (ii) the Consolidated Statements
of Operations, (iii) the Consolidated Statements of Changes in
Stockholders Equity, (iv) the Consolidated Statements of Cash
Flows, and (v) Notes to Consolidated Financial Statements, tagged
as blocks of text. |
27
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.
|
|
|
|
|
|
PATTERSON-UTI ENERGY, INC.
|
|
|
By: |
/s/
Gregory W. Pipkin |
|
|
|
Gregory W. Pipkin |
|
|
|
(Principal Accounting Officer and Duly Authorized Officer)
Chief Accounting Officer and Assistant Secretary |
|
|
DATED: November 1, 2010
28