UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
| | |
þ | | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2005March 31, 2006
OR
| | |
o | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number1-16337
OIL STATES INTERNATIONAL, INC.
(Exact name of registrant as specified in its charter)
| | |
Delaware | | 76-0476605 |
| | |
(State or other jurisdiction of | | (I.R.S. Employer |
incorporation or organization) | | (I.R.S. Employer Identification No.) |
| | |
Three Allen Center, 333 Clay Street, Suite 4620, | | 77002 |
| | |
Houston, Texas | | (Zip Code)77002 |
| | |
(Address of principal executive offices) | | (Zip Code) |
(713) 652-0582
(Registrant’s telephone number, including area code)
None
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
YESþ NOo
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, (as definedor a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b – 22b-2 of the Exchange Act).Act.
YESCheck one: Large Accelerated Filerþ NOAccelerated Filero Non-Accelerated Filero
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
YESo NOþ
The Registrant had 49,055,90649,523,086 shares of common stock outstanding as of October 24, 2005.April 28, 2006.
OIL STATES INTERNATIONAL, INC.
INDEX
2
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Amounts)
| | | | | | | | | | | | | | | | | | | | | | | | |
| | THREE MONTHS ENDED | | NINE MONTHS ENDED | | | THREE MONTHS ENDED | |
| | SEPTEMBER 30, | | SEPTEMBER 30, | | | MARCH 31, | |
| | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | |
Revenues | | $ | 394,140 | | $ | 251,538 | | $ | 1,084,555 | | $ | 677,910 | | | $ | 496,231 | | $ | 331,946 | |
| | |
Costs and expenses: | | |
Cost of sales | | 308,267 | | 197,521 | | 853,631 | | 534,833 | | | 378,233 | | 260,653 | |
Selling, general and administrative expenses | | 22,441 | | 16,504 | | 62,165 | | 47,077 | | | 25,444 | | 19,065 | |
Depreciation and amortization expense | | 12,253 | | 9,161 | | 33,697 | | 26,477 | | | 12,886 | | 10,228 | |
Other operating expense (income) | | | (87 | ) | | 441 | | | (394 | ) | | 868 | | | 465 | | | (214 | ) |
| | | | | | | | | | | | | | |
| | 342,874 | | 223,627 | | 949,099 | | 609,255 | | | 417,028 | | 289,732 | |
| | | | | | | | | | | | | | |
Operating income | | 51,266 | | 27,911 | | 135,456 | | 68,655 | | | 79,203 | | 42,214 | |
| | |
Interest expense | | | | (4,796 | ) | | | (2,314 | ) |
Interest income | | 77 | | 65 | | 313 | | 222 | | | 273 | | 131 | |
Interest expense | | | (3,857 | ) | | | (1,993 | ) | | | (9,313 | ) | | | (5,463 | ) | |
Other income | | 545 | | 494 | | 1,037 | | 931 | | |
Equity in earnings of unconsolidated affiliates | | | 684 | | 144 | |
Gain on sale of workover services business | | | 11,494 | | — | |
Other income (loss) | | | 246 | | | (98 | ) |
| | | | | | | | | | | | | | |
Income before income taxes | | 48,031 | | 26,477 | | 127,493 | | 64,345 | | | 87,104 | | 40,077 | |
Income tax expense | | | (17,723 | ) | | | (10,964 | ) | | | (47,045 | ) | | | (20,520 | ) | | | (34,188 | ) | | | (14,788 | ) |
| | | | | | | | | | | | | | |
Net income | | $ | 30,308 | | $ | 15,513 | | $ | 80,448 | | $ | 43,825 | | | $ | 52,916 | | $ | 25,289 | |
| | | | | | | | | | | | | | |
| | |
Earnings per share: | | |
Net income per share: | | |
Basic | | $ | 0.62 | | $ | 0.31 | | $ | 1.63 | | $ | 0.89 | | | $ | 1.08 | | $ | 0.51 | |
Diluted | | $ | 0.60 | | $ | 0.31 | | $ | 1.59 | | $ | 0.88 | | | $ | 1.04 | | $ | 0.50 | |
| | |
Weighted average number of common shares outstanding: | | |
Basic | | 48,925 | | 49,409 | | 49,436 | | 49,262 | | | 49,208 | | 49,669 | |
Diluted | | 50,108 | | 50,061 | | 50,442 | | 49,895 | | | 51,022 | | 50,560 | |
The accompanying notes are an integral part of
these financial statements.
3
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands)
| | | | | | | | | | | | | | | | |
| | SEPTEMBER 30, | | DECEMBER 31, | | | MARCH 31, | | DECEMBER 31, | |
| | 2005 | | 2004 | | | 2006 | | 2005 | |
| | (UNAUDITED) | | | (UNAUDITED) | |
ASSETS | | |
Current assets: | | |
Cash and cash equivalents | | $ | 17,329 | | $ | 19,740 | | | $ | 11,999 | | $ | 15,298 | |
Accounts receivable, net | | 250,867 | | 198,297 | | | 302,296 | | 274,070 | |
Inventories, net | | 334,590 | | 209,825 | | | 368,687 | | 360,926 | |
Prepaid expenses and other current assets | | 4,755 | | 7,322 | | | 14,074 | | 13,450 | |
| | | | | | | | | | |
Total current assets | | 607,541 | | 435,184 | | | 697,056 | | 663,744 | |
| | |
Property, plant, and equipment, net | | 290,319 | | 227,343 | | | 305,866 | | 310,452 | |
Goodwill, net | | 340,784 | | 258,046 | | | 330,431 | | 339,703 | |
Investments in unconsolidated affiliates | | | 31,730 | | 2,265 | |
Other noncurrent assets | | 27,349 | | 13,039 | | | 47,138 | | 26,708 | |
| | | | | | | | | | |
Total assets | | $ | 1,265,993 | | $ | 933,612 | | | $ | 1,412,221 | | $ | 1,342,872 | |
| | | | | | | | | | |
| | |
LIABILITIES AND STOCKHOLDERS’ EQUITY | | |
| | |
Current liabilities: | | |
Accounts payable and accrued liabilities | | $ | 179,886 | | $ | 159,265 | | | $ | 197,129 | | $ | 214,504 | |
Income taxes | | 10,084 | | 5,821 | | | 27,482 | | 7,023 | |
Current portion of long-term debt | | 3,937 | | 228 | | | 3,566 | | 3,901 | |
Deferred revenue | | 29,016 | | 25,420 | | | 33,243 | | 34,046 | |
Other current liabilities | | 2,280 | | 2,296 | | | 3,814 | | 3,223 | |
| | | | | | | | | | |
Total current liabilities | | 225,203 | | 193,030 | | | 265,234 | | 262,697 | |
| | |
Long-term debt | | 403,038 | | 173,887 | | | 406,007 | | 402,109 | |
Deferred income taxes | | 37,570 | | 28,871 | | | 38,936 | | 35,259 | |
Other liabilities | | 8,713 | | 7,800 | | | 8,392 | | 8,823 | |
| | | | | | | | | | |
Total liabilities | | 674,524 | | 403,588 | | | 718,569 | | 708,888 | |
| | |
Stockholders’ equity: | | |
Common stock | | 503 | | 496 | | | 507 | | 504 | |
Additional paid-in capital | | 348,292 | | 338,906 | | | 357,581 | | 350,667 | |
Retained earnings | | 248,628 | | 168,180 | | | 342,909 | | 289,993 | |
Accumulated other comprehensive income | | 24,363 | | 22,759 | | | 23,202 | | 23,137 | |
Treasury stock | | | (30,317 | ) | | | (317 | ) | | | (30,547 | ) | | | (30,317 | ) |
| | | | | | | | | | |
Total stockholders’ equity | | 591,469 | | 530,024 | | | 693,652 | | 633,984 | |
| | | | | | | | | | |
Total liabilities and stockholders’ equity | | $ | 1,265,993 | | $ | 933,612 | | | $ | 1,412,221 | | $ | 1,342,872 | |
| | | | | | | | | | |
The accompanying notes are an integral part of
these financial statements.
4
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
| | | | | | | | | | | | | | | | |
| | NINE MONTHS ENDED SEPTEMBER 30, | | | THREE MONTHS ENDED MARCH 31, | |
| | 2005 | | 2004 | | | 2006 | | 2005 | |
Cash flows from operating activities: | | |
Net income | | $ | 80,448 | | $ | 43,825 | | | $ | 52,916 | | $ | 25,289 | |
Adjustments to reconcile net income to net cash from operating activities: | | |
Depreciation and amortization | | 33,697 | | 26,477 | | | 12,886 | | 10,228 | |
Deferred income tax provision (benefit) | | 1,101 | | | (2,453 | ) | |
Tax benefit of option exercises | | 2,919 | | — | | |
Deferred income tax provision | | | 2,788 | | 1,752 | |
Excess tax benefits from share-based payment arrangements | | | | (1,791 | ) | | — | |
Non-cash gain on sale of workover business | | | | (11,494 | ) | | — | |
Non-cash compensation charge | | | 1,688 | | 36 | |
Other, net | | 1,645 | | 1,237 | | | 83 | | 2,158 | |
Changes in working capital | | | (119,536 | ) | | | (4,294 | ) | | | (38,418 | ) | | | (45,595 | ) |
| | | | | | | | | | |
Net cash flows provided by operating activities | | 274 | | 64,792 | | | 18,658 | | | (6,132 | ) |
| | |
Cash flows from investing activities: | | |
Acquisitions of businesses, net of cash acquired | | | (146,568 | ) | | | (79,455 | ) | | | (49 | ) | | | (22,606 | ) |
Cash balances of workover business sold | | | | (4,366 | ) | | — | |
Capital expenditures | | | (49,445 | ) | | | (38,117 | ) | | | (26,542 | ) | | | (17,147 | ) |
Proceeds from sale of equipment | | 2,034 | | 3,072 | | | 792 | | 501 | |
Other, net | | | (554 | ) | | | (63 | ) | | | (30 | ) | | | (80 | ) |
| | | | | | | | | | |
Net cash flows used in investing activities | | | (194,533 | ) | | | (114,563 | ) | | | (30,195 | ) | | | (39,332 | ) |
| | |
Cash flows from financing activities: | | |
Revolving credit borrowings | | 50,673 | | 49,700 | | | 5,300 | | 45,148 | |
Contingent convertible notes issued | | 175,000 | | — | | |
Bridge loan and other borrowings | | 25,000 | | 102 | | |
Debt repayments | | | (25,469 | ) | | | (774 | ) | | | (1,854 | ) | | | (113 | ) |
Issuance of common stock | | 6,112 | | 3,491 | | | 3,297 | | 3,165 | |
Payment of financing costs | | | (6,460 | ) | | | (81 | ) | |
Purchase of treasury stock | | | (30,000 | ) | | — | | |
Excess tax benefits from share-based payment arrangements | | | 1,791 | | — | |
Other, net | | — | | | (139 | ) | | | (101 | ) | | | (707 | ) |
| | | | | | | | | | |
Net cash flows provided by financing activities | | 194,856 | | 52,299 | | | 8,433 | | 47,493 | |
| | |
Effect of exchange rate changes on cash | | | (2,455 | ) | | 2,192 | | | | (178 | ) | | | (439 | ) |
| | | | | | | | | | |
Net increase (decrease) in cash and cash equivalents from continuing operations | | | (1,858 | ) | | 4,720 | | | | (3,282 | ) | | 1,590 | |
Net cash used in discontinued operations | | | (553 | ) | | | (500 | ) | |
Net cash used in discontinued operations — operating activities | | | | (17 | ) | | | (142 | ) |
Cash and cash equivalents, beginning of period | | 19,740 | | 19,318 | | | 15,298 | | 19,740 | |
| | | | | | | | | | |
Cash and cash equivalents, end of period | | $ | 17,329 | | $ | 23,538 | | | $ | 11,999 | | $ | 21,188 | |
| | | | | | | | | | |
| | |
Non-cash financing activities: Borrowings for acquisitions | | $ | 6,553 | | $ | 4,675 | | |
Non cash investing activities: | | |
Receipt of stock and notes for hydraulic workover business in merger transaction, net of unrecognized gain of $9.6 million (See Note 10) | | | $ | 50,349 | | $ | — | |
| | |
Non-cash financing activities: | | |
Borrowings for acquisitions | | | $ | — | | $ | 750 | |
The accompanying notes are an integral part of these
consolidated financial statements.
5
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
The accompanying unaudited consolidated financial statements of the Company and its wholly-owned subsidiaries have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission pertaining to interim financial information. Certain information in footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been condensed or omitted pursuant to these rules and regulations. The unaudited financial statements included in this report reflect all the adjustments, consisting of normal recurring adjustments, which the Company considers necessary for a fair presentation of the results of operations for the interim periods covered and for the financial condition of the Company at the date of the interim balance sheet. Results for the interim periods are not necessarily indicative of results for the year.
Preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosed amounts of contingent assets and liabilities and the reported amounts of revenues and expenses. If the underlying estimates and assumptions, upon which the financial statements are based, change in future periods, actual amounts may differ from those included in the accompanying consolidated condensed financial statements.
From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the FASB) which are adopted by the Company as of the specified effective date. Unless otherwise discussed, management believes the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s consolidated financial statements upon adoption.
The financial statements included in this report should be read in conjunction with the Company’s audited financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2004.2005.
2. DETAILS OF SELECTED BALANCE SHEET ACCOUNTS
Additional information regarding selected balance sheet accounts is presented below (in thousands):
| | | | | | | | | | | | | | | | |
| | SEPTEMBER 30, | | DECEMBER 31, | | | MARCH 31, | | DECEMBER 31, | |
| | 2005 | | 2004 | | | 2006 | | 2005 | |
Accounts receivable, net: | | |
Trade | | $ | 212,586 | | $ | 177,784 | | | $ | 266,363 | | $ | 236,936 | |
Unbilled revenue | | 38,904 | | 21,431 | | | 35,575 | | 36,789 | |
Other | | 1,881 | | 605 | | | 2,207 | | 2,514 | |
Allowance for doubtful accounts | | | (2,504 | ) | | | (1,523 | ) | | | (1,849 | ) | | | (2,169 | ) |
| | | | | | | | | | |
| | $ | 250,867 | | $ | 198,297 | | | $ | 302,296 | | $ | 274,070 | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | SEPTEMBER 30, | | DECEMBER 31, | | | MARCH 31, | | DECEMBER 31, | |
| | 2005 | | 2004 | | | 2006 | | 2005 | |
Inventories, net: | | |
Tubular goods | | $ | 241,543 | | $ | 123,555 | | | $ | 265,846 | | $ | 274,232 | |
Other finished goods and purchased products | | 40,146 | | 29,255 | | | 44,063 | | 35,716 | |
Work in process | | 30,506 | | 39,936 | | | 35,495 | | 30,288 | |
Raw materials | | 28,160 | | 21,978 | | | 29,054 | | 26,412 | |
| | | | | | | | | | |
| | |
Total inventories | | 340,355 | | 214,724 | | | 374,458 | | 366,648 | |
Inventory reserves | | | (5,765 | ) | | | (4,899 | ) | | | (5,771 | ) | | | (5,722 | ) |
| | | | | | | | | | |
| | $ | 334,590 | | $ | 209,825 | | | $ | 368,687 | | $ | 360,926 | |
| | �� | | | | | | | | |
6
| | | | | | | | | | | | | | | | | | | | | | | | |
| | ESTIMATED | | SEPTEMBER 30, | | DECEMBER 31, | | | ESTIMATED | | MARCH 31, | | DECEMBER 31, | |
| | USEFUL LIFE | | 2005 | | 2004 | | | USEFUL LIFE | | 2006 | | 2005 | |
Property, plant and equipment, net: | | |
Land | | $ | 9,468 | | $ | 5,909 | | | $ | 9,315 | | $ | 9,576 | |
Buildings and leasehold improvements | | 5-40 years | | 59,879 | | 43,482 | | | 5-40 years | | 58,740 | | 60,049 | |
Machinery and equipment | | 2-20 years | | 277,810 | | 236,266 | | | 2-20 years | | 271,713 | | 292,713 | |
Rental tools | | 3-15 years | | 70,038 | | 56,572 | | | 2-10 years | | 57,283 | | 72,327 | |
Office furniture and equipment | | 1-10 years | | 16,325 | | 14,238 | | | 1-15 years | | 16,030 | | 16,231 | |
Vehicles | | 2-5 years | | 27,255 | | 11,036 | | | 2-10 years | | 26,920 | | 26,035 | |
Construction in progress | | 9,008 | | 12,841 | | | 26,975 | | 22,283 | |
| | | | | | | | | | |
| | |
Total property, plant and equipment | | 469,783 | | 380,344 | | | 466,976 | | 499,214 | |
Less: Accumulated depreciation | | | (179,464 | ) | | | (153,001 | ) | | | (161,110 | ) | | | (188,762 | ) |
| | | | | | | | | | |
| | $ | 290,319 | | $ | 227,343 | | | $ | 305,866 | | $ | 310,452 | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | SEPTEMBER 30, | | DECEMBER 31, | | | MARCH 31, | | DECEMBER 31, | |
| | 2005 | | 2004 | | | 2006 | | 2005 | |
Accounts payable and accrued liabilities: | | |
Trade accounts payable | | $ | 135,324 | | $ | 124,193 | | | $ | 160,722 | | $ | 168,445 | |
Accrued compensation | | 18,228 | | 13,589 | | | 13,046 | | 22,529 | |
Accrued insurance | | 5,269 | | 4,261 | | | 5,367 | | 4,820 | |
Accrued taxes, other than income taxes | | 6,719 | | 3,310 | | | 5,717 | | 4,354 | |
Reserves related to discontinued operations | | 3,647 | | 4,200 | | | 3,510 | | 3,527 | |
Other | | 10,699 | | 9,712 | | | 8,767 | | 10,829 | |
| | | | | | | | | | |
| | $ | 179,886 | | $ | 159,265 | | | $ | 197,129 | | $ | 214,504 | |
| | | | | | | | | | |
3. RECENT ACCOUNTING PRONOUNCEMENTS
In the fourth quarter of 2004, the FASB issued Statement No. 123 (revised 2004), or SFAS No. 123R, “Share-Based Payment,” which replaces Statement No. 123 “Accounting for Stock-Based Compensation,” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123R eliminates the alternative to use APB Opinion 25’s intrinsic value method of accounting that was provided in Statement No. 123 as originally issued. After a phase-in period for Statement No. 123R, pro forma disclosure will no longer be allowed.
Alternative phase-in methods are allowed under Statement No. 123R, which is effective for registrants as of the beginning of the first fiscal year beginning after June 15, 2005. We are currently in the process of evaluating the impact of SFAS No. 123R on our consolidated condensed financial statements. We will adopt SFAS No. 123R on January 1, 2006.
7
4. EARNINGS PER SHARE (EPS)
| | | | | | | | | | | | | | | | |
| | THREE MONTHS ENDED | | | NINE MONTHS ENDED | |
| | SEPTEMBER 30 | | | SEPTEMBER 30 | |
| | 2005 | | | 2004 | | | 2005 | | | 2004 | |
| | (In thousands, except per share data) | |
Basic earnings per share: | | | | | | | | | | | | | | | | |
Net income | | $ | 30,308 | | | $ | 15,513 | | | $ | 80,448 | | | $ | 43,825 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Weighted average number of shares outstanding | | | 48,925 | | | | 49,409 | | | | 49,436 | | | | 49,262 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Basic earnings per share | | $ | 0.62 | | | $ | 0.31 | | | $ | 1.63 | | | $ | 0.89 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Diluted earnings per share: | | | | | | | | | | | | | | | | |
Net income | | $ | 30,308 | | | $ | 15,513 | | | $ | 80,448 | | | $ | 43,825 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Weighted average number of shares outstanding | | | 48,925 | | | | 49,409 | | | | 49,436 | | | | 49,262 | |
Effect of dilutive securities: | | | | | | | | | | | | | | | | |
Options on common stock | | | 1,095 | | | | 621 | | | | 936 | | | | 596 | |
Restricted stock | | | 88 | | | | 31 | | | | 70 | | | | 37 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Total shares and diluted securities | | | 50,108 | | | | 50,061 | | | | 50,442 | | | | 49,895 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Diluted earnings per share | | $ | 0.60 | | | $ | 0.31 | | | $ | 1.59 | | | $ | 0.88 | |
| | | | | | | | | | | | |
Our 2 3/8% contingent convertible notes were not convertible at any time during the periods presented and no shares have been added to our outstanding shares for these notes (See Note 6). | | | | | | | | |
| | THREE MONTHS ENDED | |
| | MARCH 31, | |
| | 2006 | | | 2005 | |
| | (In thousands, except per share data) | |
Basic earnings per share: | | | | | | | | |
Net income | | $ | 52,916 | | | $ | 25,289 | |
| | | | | | |
| | | | | | | | |
Weighted average number of shares outstanding | | | 49,208 | | | | 49,669 | |
| | | | | | |
| | | | | | | | |
Basic earnings per share | | $ | 1.08 | | | $ | 0.51 | |
| | | | | | |
| | | | | | | | |
Diluted earnings per share: | | | | | | | | |
Net income | | $ | 52,916 | | | $ | 25,289 | |
| | | | | | |
| | | | | | | | |
Weighted average number of shares outstanding | | | 49,208 | | | | 49,669 | |
Effect of dilutive securities: | | | | | | | | |
Options on common stock | | | 1,028 | | | | 849 | |
2 3/8% Contingent Convertible Notes | | | 724 | | | | — | |
Restricted stock awards and other | | | 62 | | | | 42 | |
| | | | | | |
| | | | | | | | |
Total shares and dilutive securities | | | 51,022 | | | | 50,560 | |
| | | | | | |
| | | | | | | | |
Diluted earnings per share | | $ | 1.04 | | | $ | 0.50 | |
| | | | | | |
5.4. ACQUISITIONS AND GOODWILL
On February 1, 2005, the Company completed the acquisition of Elenburg Exploration Company, Inc. (Elenburg), a Wyoming based land drilling company for cashtotal consideration of $21.3$22.1 million, including transaction costs, plus a note payable to the former owners of $0.8 million. At the date of acquisition, Elenburg ownsowned and operatesoperated 7 rigs which provideprovided shallow land drilling services in Montana, Wyoming, Colorado, and Utah. The Elenburg acquisition allowed the Company to expand its drilling business into different geographic areas. The operations of Elenburg have been included in the drilling services business within the well site services segment.
Effective May 1, 2005 and June 1, 2005 the Company acquired Stinger Wellhead Protection, Inc., certain affiliated companies and related intellectual property, (collectively, Stinger) for cashtotal consideration of $78.0$96.1 million, net of cash acquired and including transaction costs plusand a note payable to the former owners of $5.0 million. Stinger provides wellhead isolation equipment and services through its 2329 locations in the United States, Canada, Central and Canada. South America.
7
Stinger’s patented equipment is utilized during pressure pumping operations and isolates the customers’ blow-out preventers or wellheads from the pressure and abrasion experienced during the fracturing process of an oil or gas well. In June 2005, the Company completed the acquisition of Stinger’s international operations for additional cash consideration of $6.2 million, net of cash acquired and including transaction costs. The Stinger international operations are conducted primarily in Central and South America. The Stinger acquisition expanded the Company’s rental tool and services capabilities, especially in the pressure pumping market. The operations of Stinger have been included in the rental tools business within the well site services segment.
On June 2, 2005, the Company purchased Phillips Casing and Tubing, L.P. (Phillips) for cashtotal consideration of $31.1$31.2 million net of cash acquired and including transaction costs. Phillips distributes oil country tubular goods (OCTG), primarily carbon ERW (electronic resistance welded) pipe, from its facilities in Midland and Godley, Texas. The operations of Phillips have been combined with our tubular services segment.
On June 6, 2005, the Company acquired Noble Structures, Inc. (Noble) for cashtotal consideration of $7.9$8.7 million, plusincluding transaction costs and a note payable of $0.8 million. The acquisition expanded the Company’s accommodation manufacturing capabilities in Canada in order to meet increased demand for remote site facilities, principally in the oil sands region. The operations of Noble have been combined with our accommodations business within well site services.
The cash consideration paid for all of the Company’s acquisitions in the period was initially funded utilizing its existing bank credit facility and a $25 million bridge loan (See Note 6). Accounting for thecertain acquisitions made in the
8
periodsince March 31, 2005 has not been finalized and is subject to adjustments during the purchase price allocation period, which is not expected to exceed a period of one year from the respective acquisition dates. The Elenburg, Stinger and Noble acquisitions are included in the Well Site Services segment and the Phillips acquisition is included in the Tubular Services segment.
Changes in the carrying amount of goodwill for the ninethree month period ended September 30, 2005March 31, 2006 are as follows (in thousands):
| | | | | | | | | | | | | | | | |
| | Balance as of | | | | | | | Foreign currency | | | Balance as of | |
| | January 1, | | | Goodwill | | | translation and | | | September 30, | |
| | 2005 | | | acquired | | | other changes | | | 2005 | |
Offshore Products | | $ | 75,582 | | | $ | 2 | | | $ | (518 | ) | | $ | 75,066 | |
Tubular Services | | | 51,604 | | | | 10,239 | | | | — | | | | 61,843 | |
Drilling services | | | 9,397 | | | | 14,469 | | | | — | | | | 23,866 | |
Workover services | | | 9,340 | | | | — | | | | — | | | | 9,340 | |
Rental tools | | | 61,921 | | | | 56,006 | | | | 1,257 | | | | 119,184 | |
Accommodations | | | 50,202 | | | | 415 | | | | 868 | | | | 51,485 | |
| | | | | | | | | | | | |
Total Wellsite Services | | | 130,860 | | | | 70,890 | | | | 2,125 | | | | 203,875 | |
| | | | | | | | | | | | |
Total | | $ | 258,046 | | | $ | 81,131 | | | $ | 1,607 | | | $ | 340,784 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | Foreign currency | | | Balance as of | |
| | Balance as of | | | Goodwill | | | translation and | | | March 31, | |
| | January 1, 2006 | | | acquired | | | other changes | | | 2006 | |
Offshore Products | | $ | 74,922 | | | $ | — | | | $ | 53 | | | $ | 74,975 | |
Tubular Services | | | 62,015 | | | | 173 | | | | — | | | | 62,188 | |
Wellsite Services | | | 202,766 | | | | (55 | ) | | | (9,443 | ) (1) | | | 193,268 | |
| | | | | | | | | | | | |
Total | | $ | 339,703 | | | $ | 118 | | | $ | (9,390 | ) | | $ | 330,431 | |
| | | | | | | | | | | | |
| | |
(1) | | Effective March 1, 2006, the Company sold its workover services business — See Note 10. A total of $9,340 of goodwill was associated with the workover services business sold. |
6.5. DEBT
As of September 30, 2005March 31, 2006 and December 31, 2004,2005, long-term debt consisted of the following (in thousands):
| | | | | | | | |
| | September 30, | | | December 31, | |
| | 2005 | | | 2004 | |
| | (Unaudited) | | | | | |
US revolving credit facility, with available commitments up to $280 million and with an average interest rate of 4.9% for the three months period ended September 30, 2005 | | $ | 187,100 | | | $ | 172,600 | |
Canadian revolving credit facility, with available commitments up to $45 million and with an average interest rate of 4.1% for the three month period ended September 30, 2005 | | | 36,173 | | | | — | |
2 3/8% contingent convertible senior notes due 2025 | | | 175,000 | | | | — | |
Subordinated unsecured notes payable to sellers of businesses, interest ranging from 5% to 6%, maturing in 2006 and 2007 | | | 8,109 | | | | 1,010 | |
Obligations under capital leases | | | 593 | | | | 505 | |
| | | | | | |
Total debt | | | 406,975 | | | | 174,115 | |
Less: current maturities | | | 3,937 | | | | 228 | |
| | | | | | |
Total long-term debt | | $ | 403,038 | | | $ | 173,887 | |
| | | | | | |
On June 15, 2005, the Company sold $125 million aggregate principal amount of 2 3/8% contingent convertible senior notes due 2025 through a placement to qualified institutional buyers pursuant to the SEC’s Rule 144A. The Company granted the initial purchaser of the notes a 30-day option to purchase up to an additional $50 million aggregate principal amount of the notes. This option was exercised in July 2005 and an additional $50 million of the notes were sold at that time.
The notes are senior unsecured obligations of the Company and bear interest at a rate of 2 3/8% per annum. The notes mature on July 1, 2025, and may not be redeemed by the Company prior to July 6, 2012. Holders of the notes may require the Company to repurchase some or all of the notes on July 1, 2012, 2015, and 2020. The notes provide for a net share settlement, and therefore may be convertible, under certain circumstances, into a combination of cash, up to the principal amount of the notes, and common stock of the company, if there is any excess above the principal amount of the notes, at an initial conversion price of $31.75 per share. Shares underlying the notes were not included in the calculation of diluted earnings per share because the terms of the notes require that the Company’s stock price in any quarter, for any period prior to July 1, 2023, be above 120% of the initial conversion price for at least 20 trading days in a defined period before the notes are convertible. As a result, there would be no conversion allowed under the terms of the notes at September 30, 2005.
The Company utilized $30 million of the net proceeds of the offering on June 15, 2005 to repurchase 1,183,432 shares of its common stock and the remaining portion of the net proceeds to repay a $25.0 million bridge loan and to repay approximately $66.0 million of borrowings under its senior secured credit facility. Net proceeds of the | | | | | | | | |
| | March 31, | | | December 31, | |
| | 2006 | | | 2005 | |
| | (Unaudited) | | | | | |
US revolving credit facility, with available commitments up to $280 million and with an average interest rate of 6.0% for the three month period ended March 31, 2006 | | $ | 184,900 | | | $ | 179,600 | |
Canadian revolving credit facility, with available commitments up to $45 million and with an average interest rate of 5.1% for the three month period ended March 31, 2006 | | | 41,984 | | | | 42,885 | |
2 3/8% contingent convertible senior notes due 2025 | | | 175,000 | | | | 175,000 | |
Subordinated unsecured notes payable to sellers of businesses, interest ranging from 5% to 6%, maturing in 2006 and 2007 | | | 6,232 | | | | 7,493 | |
Capital lease obligations and other notes payable in monthly installments of principal and interest at various interest rates | | | 1,457 | | | | 1,032 | |
| | | | | | |
Total debt | | | 409,573 | | | | 406,010 | |
Less: current maturities | | | (3,566 | ) | | | (3,901 | ) |
| | | | | | |
Total long-term debt | | $ | 406,007 | | | $ | 402,109 | |
| | | | | | |
98
additional notes sold in July 2005, totaling $48.5 million, were utilized to repay borrowings under the Company’s senior secured credit facility.
On May 11, 2005 the Company borrowed $25 million under a bridge loan with a bank which was due in 2010. The loan was unsecured and was repaid in full on June 21, 2005. The average interest rate on this bridge loan for the period it was outstanding was 6.0%.
7.6. COMPREHENSIVE INCOME AND CHANGES IN COMMON STOCK OUTSTANDING:
Comprehensive income for the three month periods ended March 31, 2006 and nine months ended September 30, 2005 and 2004 was as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | THREE MONTHS | | NINE MONTHS | | | THREE MONTHS | |
| | ENDED SEPTEMBER 30, | | ENDED SEPTEMBER 30, | | | ENDED MARCH 31, | |
| | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | |
Comprehensive income: | | |
Net income | | $ | 30,308 | | $ | 15,513 | | $ | 80,448 | | $ | 43,825 | | | $ | 52,916 | | $ | 25,289 | |
Other comprehensive income: | | | | | | | |
Cumulative translation adjustment | | 6,211 | | 5,489 | | 1,676 | | 3,070 | | | 24 | | | (1,021 | ) |
Foreign currency hedge | | | (10 | ) | | — | | | (72 | ) | | — | | | 41 | | 23 | |
| | | | | | | | | | | | | | |
Total comprehensive income | | $ | 36,509 | | $ | 21,002 | | $ | 82,052 | | $ | 46,895 | | | $ | 52,981 | | $ | 24,291 | |
| | | | | | | | | | | | | | |
| | | | |
Shares of common stock outstanding — January 1, 2005 | | | 49,577,786 | |
| | | | |
Shares issued upon exercise of stock options | | | 660,052 | |
Repurchase of shares held in treasury | | | (1,183,432 | ) (1) |
| | | |
Shares of common stock outstanding — September 30, 2005 | | | 49,054,406 | |
| | | |
| | |
(1) | | See Note 6 | | |
Shares of common stock outstanding — DebtJanuary 1, 2006 | | | 49,179,258 | |
| | | | |
Shares issued upon exercise of stock options and vesting of stock awards | | | 303,466 | |
Shares withheld for discussiontaxes on vesting of treasuryrestricted stock purchased.awards and transferred to treasury | | | (2,410 | ) |
| | | |
Shares of common stock outstanding — March 31, 2006 | | | 49,480,314 | |
| | | |
8.7. STOCK BASED COMPENSATION
The Company has elected to followWe adopted Statement of Financial Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees,” for expense recognition purposes. As a result, the Company is obligated to provide the expanded disclosures required under SFASStandards No. 123 “AccountingR (SFAS 123R) effective January 1, 2006. This pronouncement requires companies to measure the cost of employee services received in exchange for Stock Based Compensation,” and SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure-an amendmentan award of SFAS No. 123,” for stock-based compensation granted in 1998 and thereafter. See also Note 3 — Recent Accounting Pronouncements.
The Company accounts for its employee stock-based compensation plan under APB Opinion No. 25 and its related interpretations. The Company is authorized to grant commonequity instruments (typically stock options) based awards covering 7,700,000 shares of common stock underon the 2001 Equity Participation Plan, as amended and restated (the Equity Participation Plan), to employees, consultants and directors with amounts, exercise prices and vesting schedules determined by the compensation committee of the Company’s Board of Directors. Any restricted stock awards issued under the Equity Participation Plan are considered compensatory in nature and the Company recognizes thegrant-date fair value of the award as compensation expenseaward. The fair value is estimated using option-pricing models. The resulting cost is recognized over itsthe period during which an employee is required to provide service in exchange for the awards, usually the vesting period. SincePrior to the adoption of SFAS 123R, this accounting treatment was optional with pro forma disclosures required. We adopted SFAS 123R using the modified prospective transition method, which is explained below.
SFAS 123R is effective for all stock options we grant beginning January 1, 2006. For those stock option awards granted prior to January 1, 2006, but for which the vesting period is not complete, we used the modified prospective transition method permitted by SFAS 123R. Under this method of accounting, the remaining unamortized value of non-vested options will be expensed over the remaining vesting period using the grant-date fair values. Our options typically vest in equal annual installments over a four year service period. Expense related to an option grant is recognized on a straight line basis over the specific vesting period for those options.
The fair value of options is determined at the grant date using a Black-Scholes option pricing model, which requires us to make several assumptions. The risk-free interest rate is based on the U.S Treasury yield curve in effect for the expected term of the option at the time of grant. The dividend yield on our common stock is assumed to be zero since we do not pay dividends and have no current plans to do so in the future. The expected market price volatility of our common stock is based on an estimate made by us that considers the historical and implied volatility of our common stock as well as a peer group of companies over a time period equal to the expected term of the option. The expected life of the options awarded in 2006 was based on a formula considering the vesting period and term of the options awarded as permitted by U.S. Securities and Exchange Commission regulations.
9
The table below summarizes stock option activity pursuant to our plans for the three months ended March 31, 2006:
| | | | | | | | | | | | | | | | |
| | | | | | | | | | Weighted- | | |
| | | | | | Weighted- | | Average | | Aggregate |
| | | | | | Average | | Contractual | | Intrinsic Value |
| | Options | | Exercise Price | | Life (Years) | | (Thousands) |
Outstanding at beginning of period | | | 2,694,061 | | | $ | 13.65 | | | | | | | | | |
Granted | | | 495,000 | | | $ | 34.86 | | | | | | | | | |
Exercised | | | (293,325 | ) | | $ | 11.24 | | | | | | | | | |
Cancelled | | | (52,500 | ) | | $ | 16.15 | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Outstanding at end of period | | | 2,843,236 | | | $ | 17.55 | | | | 5.4 | | | $ | 54,878 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Exercisable at end of period | | | 1,317,304 | | | $ | 11.56 | | | | 5.5 | | | $ | 33,321 | |
| | | | | | | | | | | | | | | | |
On February 2001, all option grants have been priced at15, 2006, we issued stock options for 495,000 shares of our common stock with an exercise price of $34.86 per share. The exercise price is the closing price on the day of grant, vest 25% per year and have a life ranging from six to ten years. Because the exercise price of options granted under the Equity Participation Plan have been equal to the market price of the Company’sour common stock on the date of grant. The options vest in four equal installments on the first, second, third and fourth anniversaries of the date of grant, no compensation expense related to stock optionsand have been recorded. Had compensation expense for its Equity Participation Plan been determined consistent with SFAS No. 123 utilizing thea term of six years. The weighted-average fair value method,of options granted during the Company’s net income and earningsfirst quarter of 2006 was determined to be $12.77 per share based on the following assumptions.
| | | | |
Risk-free interest rate | | | 4.5 | % |
| | | | |
Dividend yield | | | 0 | % |
| | | | |
Expected market price volatility of our common stock | | | 37 | % |
| | | | |
Expected life of options (years) | | | 4.25 | |
The total intrinsic value of options exercised during the three months ended March 31, 2006 was $7.1 million. Cash received from option exercises during the three months ended March 31, 2006 totaled $3.3 million.
The following tables summarize the range of exercise prices and the weighted average remaining contractual life of the options outstanding and the range of exercise prices for the three and nine months ended September 30, 2005 and 2004, would have been as follows (in thousands, except per share amounts):options exercisable at March 31, 2006:
| | | | | | | | | | | | | | |
Options Outstanding |
| | | | | | | | Weighted | | |
Range of | | | | | | Average Remaining | | Weighted Average |
Exercise Prices | | Outstanding | | Contractual Life | | Exercise Price |
$ | 6.27 — $9.00 | | | | 583,683 | | | | 5.3 | | | $ | 8.44 | |
$ | 10.51 | | | | 8,750 | | | | 6.4 | | | $ | 10.51 | |
$ | 11.49 | | | | 475,185 | | | | 6.9 | | | $ | 11.49 | |
$ | 11.65 — $13.00 | | | | 70,000 | | | | 6.7 | | | $ | 12.28 | |
$ | 13.70 | | | | 554,525 | | | | 3.9 | | | $ | 13.70 | |
$ | 14.31 — $34.86 | | | | 1,151,093 | | | | 5.4 | | | $ | 26.89 | |
| | | | | | | | | | | | | | |
| | | | | 2,843,236 | | | | | | | | | |
| | | | | | | | | | | | | | |
10
| | | | | | | | | | | | | | | | |
| | THREE MONTHS ENDED | | | NINE MONTHS ENDED | |
| | SEPTEMBER 30, | | | SEPTEMBER 30, | |
| | 2005 | | | 2004 | | | 2005 | | | 2004 | |
Net income as reported | | $ | 30,308 | | | $ | 15,513 | | | $ | 80,448 | | | $ | 43,825 | |
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects | | | (634 | ) | | | (604 | ) | | | (1,882 | ) | | | (1,985 | ) |
| | | | | | | | | | | | |
Pro forma net income | | $ | 29,674 | | | $ | 14,909 | | | $ | 78,566 | | | $ | 41,840 | |
| | | | | | | | | | | | |
Net income per share as reported: | | | | | | | | | | | | | | | | |
Basic | | $ | 0.62 | | | $ | 0.31 | | | $ | 1.63 | | | $ | 0.89 | |
Diluted | | | 0.60 | | | | 0.31 | | | | 1.59 | | | | 0.88 | |
Pro forma net income per share as if fair value method had been applied to all awards: | | | | | | | | | | | | | | | | |
Basic | | $ | 0.61 | | | $ | 0.30 | | | $ | 1.59 | | | $ | 0.85 | |
Diluted | | | 0.59 | | | | 0.30 | | | | 1.56 | | | | 0.84 | |
| | | | | | | | | | | | |
| | | | | | Options Exercisable | | | | | |
| | Range of | | | | | | Weighted Average |
| | Exercise Prices | | Exercisable | | Exercise Price |
| | $ | 6.27 — $9.00 | | | | 583,683 | | | $ | 8.44 | |
| | $ | 10.51 | | | | 5,313 | | | $ | 10.51 | |
| | $ | 11.49 | | | | 312,873 | | | $ | 11.49 | |
| | $ | 11.65 — $13.00 | | | | 42,500 | | | $ | 12.17 | |
| | $ | 13.70 | | | | 222,775 | | | $ | 13.70 | |
| | $ | 14.31 — $34.86 | | | | 150,160 | | | $ | 20.47 | |
| | | | | | | | | | | | |
| | | | | | | 1,317,304 | | | | | |
| | | | | | | | | | | | |
During the first quarter of 2006, we granted 39,750 restricted stock awards valued at a total of $1.4 million. A total of 24,250 of these awards vest in four equal annual installments, 2,000 of these awards vest in two equal annual installments and the remaining 13,500 awards vest after one year.
Impact of Adoption of SFAS 123R.Stock based compensation expense recognized under SFAS 123R in the three months ended March 31, 2006 totaled $1.7 million, or $0.02 per basic and diluted share. For the three months ended March 31, 2005, our stock compensation expense related primarily to restricted stock awards and totaled $36,000. At March 31, 2006, $13.3 million of compensation cost related to unvested stock options and restricted stock awards attributable to future performance had not yet been recognized.
The following table illustrates the pro forma effect on net income and income per share for the three months ended March 31, 2005 had we applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” (in thousands except per share amounts):
| | | | |
| | Three months ended | |
| | March 31, 2005 | |
Net income, as reported | | $ | 25,289 | |
Deduct total stock-based employee compensation expense determined under SFAS 123, net of tax | | | (600 | ) |
| | | |
Pro forma net income | | $ | 24,689 | |
| | | |
Net income per share as reported: | | | | |
Basic | | $ | 0.51 | |
Diluted | | $ | 0.50 | |
Pro Forma net income per share as if fair value method had been applied to all awards: | | | | |
Basic | | $ | 0.50 | |
Diluted | | $ | 0.49 | |
On November 10, 2005, the FASB issued FASB Staff Position No. FAS 123(R)-3, “Transition Election Related to Accounting for Tax Effects of Share-Based Payment Awards.” We have elected to adopt the alternative transition method provided for in this FASB Staff Position for calculating the tax effects of share-based compensation pursuant to FAS 123R. The alternative transition method includes a simplified method to establish the beginning balance of the additional paid-in capital pool related to the tax effects of employee share-based compensation, which is available to absorb tax deficiencies recognized subsequent to the adoption of FAS 123R.
9.8. INCOME TAXES
Our primary deferred tax asset, which totaled approximately $12.5 million at December 31, 2004, is related to $35.8 million in available federal net operating loss carryforwards, or NOLs, as of that date. A valuation allowance of approximately $5.1 million was provided against the deferred tax asset associated with our NOLs at December 31, 2004. The NOLs will expire in varying amounts during the years 2010 through 2020 if they are not first used to offset taxable income generated by the Company. The Company’s ability to utilize a significant portion of the NOLs is currently limited under Section 382 of the Internal Revenue Code (Code) due to a change of control that occurred during 1995. A successive change in control was triggered in 2003 pursuant to Section 382 of the Code; however it did not significantly change the Company’s NOL utilization expectations.
The Company’s income tax provision for the three months ended September 30, 2005March 31, 2006 totaled $17.7$34.2 million, or 36.9%39.3%, of pretax income compared to $11.0$14.8 million, or 41.4%36.9% of pretax income, for the three months ended September 30, 2004. OurMarch 31, 2005. The effective tax rate was higher in the third quarter of 2004ended March 31, 2006 because of a change in the estimated 2004 annualhigher effective tax rate during that quarter.applicable to the gain recognized on the sale of our workover services business.
The Company’sCompany has not provided United States income taxes and foreign withholding taxes on a cumulative total of approximately $213.0 million of undistributed earnings of certain non-United States subsidiaries assumed to be
11
indefinitely invested outside the United States. Should the Company decide to repatriate such foreign earnings, the Company would have to adjust the income tax provision for the nine months ended September 30, 2005 totaled $47.0 million, or 36.9% of pretax income, compared to $20.5 million, or 31.9% of pretax income, for the nine months ended September 30, 2004. Our effective tax rate was lower in the first nine months of 2004 as a result ofperiod management determined that the recognition of a $5.4 million income tax benefit inearnings will no longer be indefinitely invested outside the first quarter related to the partial reversal of the valuation allowance applied against NOLs which were recorded as of the prior year end.
Based upon the loss limitation provisions of Section 382 of the Code, we expect to utilize approximately $8 million of our NOLs to offset taxable income generated by the Company during the tax year ended December 31, 2005.United States.
10.9. SEGMENT AND RELATED INFORMATION
In accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information”, the Company has identified the following reportable segments: Offshore Products, Tubular Services, and Well Site Services. The Company’s reportable segments are strategic business units that offer different products and services. They are managed separately because each business requires different technology and marketing strategies. Most of the businesses were initially acquired as a unit, and the management at the time of the acquisition was retained. Subsequent acquisitions have been direct extensions to our business segments. The separate business lines within the Well Site segment have been disclosed to provide additional detail for that segment. Results of our Canadian business related to the provision of work force accommodations, catering and logistics services are seasonal with significant activity occurring in the peak winter drilling season. We sold our workover services business, effective March 1, 2006, in exchange for an equity interest in Boots & Coots International Well Control Inc. (AMEX:WEL) and a note receivable — See Note 10.
11
Financial information by industry segment for each of the three and nine month periods ended September 30,March 31, 2006 and 2005 and 2004 is summarized in the following table (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Revenues from | | Depreciation | | Operating | | | | | | | Revenues from | | Depreciation | | Operating | | | | | |
| | unaffiliated | | and | | income | | Capital | | | | | unaffiliated | | and | | income | | Capital | | | |
| | customers | | amortization | | (loss) | | expenditures | | Total assets | | | customers | | amortization | | (loss) | | expenditures | | Total assets | |
Three months ended September 30, 2005 | | |
Three months ended March 31, 2006 | | | | | | | | | | | | | | | | | |
Well Site Services - | | | | | | | | | | | | | | | | | |
Accommodations | | | $ | 104,589 | | $ | 3,578 | | $ | 25,359 | | $ | 11,536 | | $ | 296,005 | |
Rental tools | | | 49,588 | | 4,005 | | 16,893 | | 5,542 | | 253,423 | |
Drilling services | | | 28,018 | | 1,679 | | 11,781 | | 6,332 | | 82,679 | |
Workover services (1) | | | 8,544 | | 725 | | 1,789 | | 263 | | 50,921 | |
| | | | | | | | | | | | |
Total Well Site Services | | | 190,739 | | 9,987 | | 55,822 | | 23,673 | | 683,028 | |
Offshore Products | | $ | 64,345 | | $ | 2,453 | | $ | 5,885 | | $ | 1,211 | | $ | 282,145 | | | 78,272 | | 2,609 | | 10,065 | | 2,560 | | 305,159 | |
Tubular Services | | 188,258 | | 274 | | 19,801 | | 66 | | 373,668 | | | 227,220 | | 263 | | 17,818 | | 286 | | 404,077 | |
Well Site Services — | | |
Drilling services | | 24,005 | | 1,489 | | 7,282 | | 3,779 | | 76,987 | | |
Workover services | | 10,349 | | 1,006 | | 1,108 | | 782 | | 51,715 | | |
Rental tools | | 40,010 | | 3,702 | | 10,861 | | 5,122 | | 237,309 | | |
Accommodations | | 67,173 | | 3,319 | | 9,479 | | 4,459 | | 231,428 | | |
| | | | | | | | | | | | |
Total Well Site Services | | 141,537 | | 9,516 | | 28,730 | | 14,142 | | 597,439 | | |
Corporate and Eliminations | | — | | 10 | | | (3,150 | ) | | 159 | | 12,741 | | | — | | 27 | | | (4,502 | ) | | 23 | | 19,957 | |
| | | | | | | | | | | | | | | | | | | | | | |
Total | | $ | 394,140 | | $ | 12,253 | | $ | 51,266 | | $ | 15,578 | | $ | 1,265,993 | | | $ | 496,231 | | $ | 12,886 | | $ | 79,203 | | $ | 26,542 | | $ | 1,412,221 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | |
Three months ended September 30, 2004 | | |
Three months ended March 31, 2005 | | | | | | | | | | | | | | | | | |
Well Site Services - | | | | | | | | | | | | | | | | | |
Accommodations | | | $ | 83,194 | | $ | 2,810 | | $ | 17,092 | | $ | 5,240 | | $ | 231,776 | |
Rental tools | | | 19,057 | | 2,655 | | 3,263 | | 4,470 | | 125,686 | |
Drilling services | | | 16,854 | | 1,201 | | 4,173 | | 3,467 | | 67,182 | |
Workover services | | | 8,490 | | 936 | | 74 | | 532 | | 47,187 | |
| | | | | | | | | | | | |
Total Well Site Services | | | 127,595 | | 7,602 | | 24,602 | | 13,709 | | 471,831 | |
Offshore Products | | $ | 55,268 | | $ | 2,310 | | $ | 2,678 | | $ | 1,315 | | $ | 270,485 | | | 66,491 | | 2,432 | | 5,268 | | 3,241 | | 287,131 | |
Tubular Services | | 116,872 | | 183 | | 14,123 | | 93 | | 209,128 | | | 137,860 | | 172 | | 15,145 | | 71 | | 233,803 | |
Well Site Services — | | |
Drilling services | | 12,751 | | 822 | | 3,522 | | 1,406 | | 33,376 | | |
Workover services | | 8,143 | | 970 | | 41 | | 522 | | 47,669 | | |
Rental tools | | 16,165 | | 2,484 | | 2,348 | | 3,875 | | 120,259 | | |
Accommodations | | 42,339 | | 2,379 | | 7,468 | | 10,070 | | 179,867 | | |
| | | | | | | | | | | | |
Total Well Site Services | | 79,398 | | 6,655 | | 13,379 | | 15,873 | | 381,171 | | |
Corporate and Eliminations | | — | | 13 | | | (2,269 | ) | | — | | 8,754 | | | — | | 22 | | | (2,801 | ) | | 126 | | 8,400 | |
| | | | | | | | | | | | | | | | | | | | | | |
Total | | $ | 251,538 | | $ | 9,161 | | $ | 27,911 | | $ | 17,281 | | $ | 869,538 | | | $ | 331,946 | | $ | 10,228 | | $ | 42,214 | | $ | 17,147 | | $ | 1,001,165 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | Revenues from | | | Depreciation | | | Operating | | | | | | | |
| | unaffiliated | | | and | | | income | | | Capital | | | | |
| | customers | | | amortization | | | (loss) | | | expenditures | | | Total assets | |
Nine months ended September 30, 2005 | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Offshore Products | | $ | 194,695 | | | $ | 7,316 | | | $ | 16,649 | | | $ | 6,315 | | | $ | 282,145 | |
Tubular Services | | | 493,897 | | | | 656 | | | | 53,069 | | | | 200 | | | | 373,668 | |
Well Site Services — | | | | | | | | | | | | | | | | | | | | |
Drilling services | | | 60,599 | | | | 4,105 | | | | 15,984 | | | | 11,374 | | | | 76,987 | |
Workover services | | | 29,712 | | | | 2,924 | | | | 3,189 | | | | 2,022 | | | | 51,715 | |
Rental tools | | | 90,296 | | | | 9,631 | | | | 22,472 | | | | 14,486 | | | | 237,309 | |
Accommodations | | | 215,356 | | | | 9,022 | | | | 32,803 | | | | 14,754 | | | | 231,428 | |
| | | | | | | | | | | | | | | |
Total Well Site Services | | | 395,963 | | | | 25,682 | | | | 74,448 | | | | 42,636 | | | | 597,439 | |
Corporate and Eliminations | | | — | | | | 43 | | | | (8,710 | ) | | | 294 | | | | 12,741 | |
| | | | | | | | | | | | | | | |
Total | | $ | 1,084,555 | | | $ | 33,697 | | | $ | 135,456 | | | $ | 49,445 | | | $ | 1,265,993 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Nine months ended September 30, 2004 | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Offshore Products | | $ | 146,096 | | | $ | 6,606 | | | $ | 4,696 | | | $ | 5,116 | | | $ | 270,485 | |
Tubular Services | | | 283,426 | | | | 516 | | | | 28,452 | | | | 235 | | | | 209,128 | |
Well Site Services — | | | | | | | | | | | | | | | | | | | | |
Drilling services | | | 34,530 | | | | 2,408 | | | | 7,999 | | | | 3,864 | | | | 33,376 | |
Workover services | | | 25,683 | | | | 2,910 | | | | 1,117 | | | | 1,713 | | | | 47,669 | |
Rental tools | | | 48,652 | | | | 7,174 | | | | 6,913 | | | | 7,861 | | | | 120,259 | |
Accommodations | | | 139,523 | | | | 6,821 | | | | 25,034 | | | | 19,328 | | | | 179,867 | |
| | | | | | | | | | | | | | | |
Total Well Site Services | | | 248,388 | | | | 19,313 | | | | 41,063 | | | | 32,766 | | | | 381,171 | |
Corporate and Eliminations | | | — | | | | 42 | | | | (5,556 | ) | | | — | | | | 8,754 | |
| | | | | | | | | | | | | | | |
Total | | $ | 677,910 | | | $ | 26,477 | | | $ | 68,655 | | | $ | 38,117 | | | $ | 869,538 | |
| | | | | | | | | | | | | | | |
| | |
(1) | | Subsequent to the March 1, 2006 effective date of the sale of our workover services business (See Note 10), we have classified our investment in Boots & Coots International Well Control, Inc. common stock and the notes receivable acquired in the transaction as workover services assets. |
12
10. WORKOVER SERVICES BUSINESS TRANSACTION
Effective March 1, 2006 we completed a transaction to combine our workover services business with Boots & Coots International Well Control, Inc. (Amex: WEL) (Boots & Coots) in exchange for 26.5 million shares of Boots & Coots common stock valued at $1.45 per share at closing and senior subordinated promissory notes totaling $21.6 million.
As a result of the closing of the transaction, Oil States owns 45.6% of Boots & Coots. The senior subordinated promissory notes received in the transaction bear a fixed annual interest rate of 10% and mature four and one half years from the closing of the transaction. In connection with this transaction, we also entered into a Registration Rights Agreement requiring Boots & Coots to file a shelf registration statement within 30 days for all of the Boots & Coots shares we received in the transaction and also allowing us certain “piggyback” registration rights for these shares. The transaction terms also allowed us to nominate two additional members to Boots & Coots’ existing five-member Board of Directors and provided us the right to nominate an additional member to the Boots & Coots Board of Directors.
The transaction resulted in a non-cash pretax gain of $21.1 million of which $9.6 million has not been recognized in accordance with the guidance in Emerging Issues Task Force Issue No. 01-2 covering gain recognition involving non-cash transactions and retained equity interests. After the gain adjustment and income taxes, the transaction had a $5.9 million, or $0.12 per diluted share, impact on net income and earnings per share, respectively. We will account for our investment in Boots & Coots utilizing the equity method of accounting. Differences between Boots & Coots total book equity after the transaction, net to the Company’s interest, and the carrying value of our investment in Boots & Coots are principally attributable to the reversal of a portion of the gain on the sale of the workover services business and to goodwill.
11. COMMITMENTS AND CONTINGENCIES
We are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our products or operations. Some of these claims relate to matters occurring prior to our acquisition of businesses, and some relate to businesses we have sold. In certain cases, we are entitled to indemnification from the sellers of businesses and in other cases, we have indemnified the buyers that purchased businesses from us. Although we can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by indemnity or insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.
On February 18, 2005, the Companywe announced that itwe had conducted an internal investigation prompted by the discovery of over billings totaling approximately $400,000 by one of itsour subsidiaries (the “Subsidiary”) to a government owned oil company in South America. The over billings were detected by the Company during routine financial review procedures, and appropriate financial statement adjustments were included in itsour previously reported fourth quarter 2004 results. The CompanyWe and independent counsel retained by the Company’sour audit committee conducted separate investigations consisting of interviews and ana thorough examination of the facts and circumstances in this matter. The CompanyWe voluntarily reported the results of itsour investigation to the Securities and Exchange Commission (the “SEC”) and has fully cooperated with additional requests for information received from the SEC. The Company understands that the SEC has recently completed its informal investigation of this matter. On October 31, 2005, the Company’sour counsel received a “Wells Notice” from the staff of the SEC indicating that the staff has made a preliminary decision to recommend that the SEC bring a civil action against the Company alleging violations of provisions of the Securities and Exchange Act of 1934 relating to the maintenance of books, records and internal accounting controls and procedures as set forth in Sections 13(b)(2)(A) and (B) of the Act. The alleged violations related to this over billings matter. A “Wells Notice” is notCompany reached a formal allegation or proof of wrongdoing. Recipients of “Wells Notices” have the opportunity to respond tosettlement agreement with the SEC staff before the staff makes a formal recommendation on whether any action should be broughtApril 27, 2006. The Company consented to an Order by the SEC. TheSEC (Order), without admitting or denying the findings in the Order, that required the Company is engaged in discussions with the staffto cease and desist from committing or causing violations of the SEC regarding“books and records” and “internal control provisions” of the “Wells Notice”laws of the Securities and is currently evaluating its planned responseExchange Act of 1934. The settlement did not require the Company to this matter.pay a monetary penalty.
13
This quarterly report onForm 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Exchange Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Actual results could differ materially from those projected in the forward-looking statements as a result of a number of important factors. For a discussion of important factors that could affect our results, please refer to “Item 1. Business” including the risk factors discussed therein and the financial statement line item discussions set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in ourForm 10-K Annual Report for the year ended December 31, 20042005 filed with the Securities and Exchange Commission on March 2, 20052006 and Item 2., which follows. Except to the extent required by law, we undertake no obligation to update publicly any forward-looking statements, even if new information becomes available or other events occur in the future.
ITEM 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis together with our financial statements and the notes to those statements included elsewhere in this Quarterly Report on Form 10-Q.
Critical Accounting Policies
In our selection of critical accounting policies, our objective is to properly reflect our financial position and results of operations in each reporting period in a manner that will be understood by those who utilize our financial statements. Often we must use our judgment about uncertainties.
There are several critical accounting policies that we have put into practice that have an important effect on our reported financial results. There have been no changes in these policies since the filing of our Annual Report on Form 10-K for the year ended December 31, 2004.
We have contingent liabilities and future claims for which we have made estimates of the amount of the eventual cost to liquidate these liabilities or claims. These liabilities and claims sometimes involve threatened or actual litigation where damages have been quantified and we have made an assessment of our exposure and recorded a provision in our accounts to cover an expected loss. Other claims or liabilities have been estimated based on our experience in these matters and, when appropriate, the advice of outside counsel or other outside experts. Upon the ultimate resolution of these uncertainties, our future reported financial results will be impacted by the difference between our estimates and the actual amounts paid to settle a liability. Examples of areas where we have made important estimates of future liabilities include litigation, taxes, fines, penalties, interest, warranty claims, contract claims and discontinued operations.
The determination of impairment on long-lived assets, including goodwill, is conducted when indicators of impairment are present. If such indicators were present, the determination of the amount of impairment would be based on our judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. Our industry is highly cyclical and our estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows, can have a significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment charges.
We recognize revenue and profit as work progresses on long-term, fixed price contracts using the percentage-of-completion method, which relies on estimates of total expected contract revenue and costs. We follow this method since reasonably dependable estimates of the revenue and costs applicable to various stages of a contract can be made. Recognized revenues and profit are subject to revisions as the contract progresses to completion. Revisions in profit estimates are charged to income or expense in the period in which the facts and circumstances that give rise to the revision become known. Provisions for estimated losses on uncompleted contracts are made in the period in which losses are determined.
Our valuation allowances, especially related to potential bad debts in accounts receivable and to obsolescence or market value declines of inventory, involve reviews of underlying details of these assets, known trends in the marketplace and the application of historical factors that provide us with a basis for recording these allowances. If market conditions are less favorable than those projected by management, or if our historical experience is materially different from future experience, additional allowances may be required. We record a valuation allowance
14
to reduce our deferred tax assets to the amount that is more likely than not to be realized. While we have considered future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for the valuation allowance, in the event we were to determine that we would be able to realize our deferred tax assets in the future in excess of our net recorded amount, an adjustment to the deferred tax asset would increase income in the period such determination was made. Likewise, should we determine that we would not likely be able to realize all or part of our net deferred tax asset in the future, an adjustment to the deferred tax asset would be charged to expense in the period such determination was made. See also “Note 9 – Income Taxes” and “Tax Matters” herein.
The selection of the useful lives of many of our assets requires the judgments of our operating personnel as to the length of these useful lives. Should our estimates be too long or short, we might eventually report a disproportionate number of losses or gains upon disposition or retirement of our long-lived assets. We believe our estimates of useful lives are appropriate.
Overview
We provide a broad range of products and services to the oil and gas industry through our offshore products, tubular services and well site services business segments. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas industry, particularly our customers’ willingness to spend capital on the exploration for and development of oil and gas reserves. Demand for our products and services by our customers is highly sensitive to current and expected oil and natural gas prices. Generally, our tubular services and well site services segments respond more rapidly to shorter-term movements in oil and natural gas prices than our offshore products segment. Our offshore products segment provides highly engineered and technically designed products for offshore oil and gas development and production systems and facilities. Sales of our offshore products and services depend upon the development of offshore production systems, repairs and upgrades of existing drilling rigs and construction of new drilling rigs. In this segment, we are particularly influenced by deepwater drilling and production activities, which are driven largely by our customers’ outlook for longer-term future oil prices. Through our tubular services segment, we distribute a broad range of casing and tubing. Sales of tubular products and services depend upon the overall level of drilling activity, the types of wells being drilled and the level of oil country tubular goods (OCTG) pricing. Historically, tubular services gross margins expand during periods of rising OCTG prices and contract during periods of decreasing OCTG prices. In our well site services business segment, we provide shallow land drilling services, hydraulic well control services, work force accommodations, catering and logistics services and rental tools. Demand for our drilling services is driven by land drilling activity in Texas, New Mexico, Ohio and in the Rocky Mountains area in the U.S. Our workover services are conducted in the U.S., South America, Africa, and the Middle East and are dependent upon the level of workover activity in those areas. Our rental tools and services depend primarily upon the level of drilling and workover activity in the U.S., Canada and Central and South America. Our accommodations segment is conducted primarily in Canada and its activity levels have historically been driven by oil and gas drilling and mining activities. In the past year, we have seen increased demand in our work force accommodation business as a result of oil sands development activities in Northern Alberta, Canada. We also support remote accommodations needs primarilyEffective March 1, 2006, we completed a transaction to combine our workover services business with Boots & Coots (Amex: WEL) (Boots & Coots) and we now own a 45.6% equity interest in Boots & Coots. See Note 10 to the U.S. and Canada.Unaudited Condensed Consolidated Financial Statements.
We have a diversified product and service offering which has exposure throughout the oil and gas cycle. Demand for our tubular services and well site services segments are highly correlated to changes in the rig count in the United States and Canada. The table below sets forth a summary of North American rig activity, as measured by Baker Hughes Incorporated, as of and for the periods indicated.
1514
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Average Rig Count for | | Average Rig Count for | |
| | Year Ended December 31, | | Year Ended December 31, | |
| | 2004 | | 2003 | | 2002 | | 2001 | | 2000 | | 2005 | | 2004 | | 2003 | | 2002 | | 2001 | |
U.S. Land | | 1,093 | | 924 | | 718 | | 1,003 | | 778 | | | 1,294 | | 1,093 | | 924 | | 718 | | 1,003 | |
U.S. Offshore | | 97 | | 108 | | 113 | | 153 | | 140 | | | 89 | | 97 | | 108 | | 113 | | 153 | |
| | | | | | | | | | | | | | | | | | | | | | |
Total U.S | | 1,190 | | 1,032 | | 831 | | 1,156 | | 918 | | |
Total U.S. | | | 1,383 | | 1,190 | | 1,032 | | 831 | | 1,156 | |
Canada (1) | | 369 | | 372 | | 266 | | 341 | | 345 | | | 458 | | 369 | | 372 | | 266 | | 341 | |
| | | | | | | | | | | | | | | | | | | | | | |
Total North America | | 1,559 | | 1,404 | | 1,097 | | 1,497 | | 1,263 | | | 1,841 | | 1,559 | | 1,404 | | 1,097 | | 1,497 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Average Rig Count for | | Average Rig Count for | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, | |
| | 2005 | | 2004 | | 2005 | | 2004 | | 2006 | | 2005 | |
U.S. Land | | 1,330 | | 1,133 | | 1,254 | | 1,075 | | | 1,438 | | 1,178 | |
U.S. Offshore | | 98 | | 95 | | 97 | | 96 | | | 81 | | 101 | |
| | | | | | | | | | | | | | |
Total U.S | | 1,428 | | 1,228 | | 1,351 | | 1,171 | | |
Total U.S. | | | 1,519 | | 1,279 | |
Canada (1) | | 494 | | 328 | | 416 | | 346 | | | 665 | | 521 | |
| | | | | | | | | | | | | | |
Total North America | | 1,922 | | 1,556 | | 1,767 | | 1,517 | | | 2,184 | | 1,800 | |
| | | | | | | | | | | | | | |
| | |
(1) | | Canadian rig counts typically increase during the peak winter drilling season. |
The average North American rig count for the ninethree months ended September 30, 2005March 31, 2006 increased by 250384 rigs, or 16.5%21.3%, compared to the ninethree months ended September 30, 2004.March 31, 2005. This overall increase in activity, while tempered somewhat by relatively flatlower activity levels in the U.S. Gulf of Mexico did contribute to increased revenues in our tubular services and well site services segments. Our well site services segment results for the first ninethree months of 20052006 also benefited from capital spending, which aggregated $71.4$82.9 million for that segment in the twelve months ended September 30, 2005,March 31, 2006, the acquisition of Elenburg Exploration Company on February 1, 2005 for total consideration of $22.1 million, the acquisition of Stinger Wellhead Protection, Inc. and certain affiliated companies and related intellectual property (collectively, Stinger) for total consideration of $89.2$96.1 million in May and June 2005 and the impact of increased activity levels and pricing gains in certain business lines. The Canadian rig count increased 20.2%27.6% in the first ninethree months of 20052006 compared to the corresponding period in 2004.2005. Our remote accommodations, catering and logistics services activities benefited from the Canadian rig count increase and from increased activities in the Northern Alberta oil sands area and, to a lesser extent,area.
Repair activity resulting from the Canadian rig count increase.
Hurricanes Katrina and Rita did not materially affect our operating results in the third quarter, despite some activity delays and lack of cost absorption in some of our manufacturing facilities. Our activities which were negatively impacted by the storms were offshore tubular (OCTG) sales, offshore rental tools usage and some downtime in our offshore products manufacturing facilities in Houma, Louisiana and Houston, Texas. Repair activity resulting from these hurricanes shouldhave continued to benefit our offshore products and U.S. Gulf accommodations businessesbusinesses. Decreased rig counts in the future. On the other hand, sustained levels of reduced offshore activity due to repair efforts couldU.S. Gulf, however, have negatively impact well workover activity which would adversely affectaffected our hydraulic workovertubular services segment and our rental tool businesses.business.
During the first ninethree months of 2005,2006, the results generated by our Canadian workforce accommodations, catering and logistics operations benefited from the strengthening of the Canadian currency. In the first ninethree months of 2005,2006, the Canadian dollar was worth $0.83$0.87 U.S. dollars compared to $0.76$0.82 in the first ninethree months of 2004,2005, an increase of 9.2%6.1%.
On May 11, 2004, our tubular services segment purchased the OCTG distribution business of Hunting Energy Services, L.P. (Hunting) for $47.2 million, including purchase price adjustments. On June 2, 2005 we acquired all of the outstanding stock of Phillips Casing and Tubing, Inc. (Phillips) for total consideration of $31.1$31.2 million. Both of these acquisitionsThis acquisition resulted in increased OCTG inventory and revenues from the date of acquisition. Our tubular services segment shipped 286,700126,700 tons of OCTG in the first ninethree months of 2005 (104,100 tons in the third quarter of 2005)2006 compared to 242,10082,000 tons in the first ninethree months of 2004 (90,200 tons in the third quarter of 2004).2005. Our tubular services segment benefited in the past nine monthsquarter from a 16.7% year over year22.1% year-over-year increase in average U.S. land drilling activity,activity. Our OCTG business is particularly leveraged to gas drilling in high pressure, tight formations given the acquisitionhigher volume and quality of tubulars used in the Hunting and Phillipsdrilling completion of such wells. OCTG distribution businesses and increasedprices have remained fairly constant during the first three months of 2006 compared to the year 2005 when we experienced several price increases for our OCTG prices.inventory. Our tubular services gross margins have been atdeclined compared to historically high levels reached in 2005 and are expected to continue at relatively strong levels throughout 2005. The tubularTubular services gross margin as a percent of revenues decreased to 12.3%9.3% in the thirdfirst quarter of 2005 compared to2006 from a gross margin percent of 14.4%13.0% in the third
16
first quarter of 20042005 and 12.7%11.0% in the secondfourth quarter of 2005. These decreases are attributable to less frequent and smaller OCTG price increases in the third quarter of 2005 compared to earlier periods and to a higher mix of lower margin carbon grade OCTG products sold.sold in response to increased land drilling activity. The lingering effects of the hurricanes on Gulf of Mexico drilling activity resulted in reduced demand for higher margin seamless alloy tubulars while strong land based drilling activity increased carbon grade sales.
15
Our offshore products segment reported a much improved first nine monthsquarter of 20052006 compared to the first nine monthsquarter of 20042005 as a result of increased activity and greater fixed cost absorption. Our offshore products backlog totaled $119.4$220.8 million at September 30, 2005, $97.5March 31, 2006, $110.7 million at December 31, 20042005 and $87.3$99.8 million at September 30, 2004.March 31, 2005. We believe that the deepwater offshore construction and development business is characterized by lengthy projects and a long “lead-time” order cycle. While changechanges in backlog levels from one quarter to the next doesdo not necessarily evidence a long-term trend, we believe activity levels in our offshore products segment will increase in future quarters, given the significant growth in our backlog, when compared to year end 20042005 levels.
The Company’sOur income tax provision for the first nine monthsquarter of 20052006 totaled $47.0$34.2 million, or 39.3% of pretax income compared to $14.8 million, or 36.9% of pretax income.income, for the first quarter of 2005. Our effective tax rate increased in the first ninethree months of 20052006 compared to the first ninethree months of 2004. Our first nine months2005 as a result of 2004 reflected an effectivea higher tax rate applicable to the gain recognized on the sale of 31.9% due to greater NOL benefits recognized in the first quarter of 2004 when a $5.4 million income tax benefit was recognized upon a partial reversal of valuation allowances applied against net operating loss carryforwards. In the third quarter of 2005, our income tax provision totaled $17.7 million, 36.9% of pretax income compared to $11.0 million, or 41.4% of pretax income in the third quarter of 2004.workover services business. See Note 10.
Management believes that fundamental oil and gas supply and demand factors will continue to support a high level of drilling activity in North America which should continue to positively impact the Company, particularly itsour tubular services and well site service segments. We also believe that oil and gas producers have increased their view of longer term oil and gas prices based on current supply and demand fundamentals, even though such long term price expectations are still at levels below current prices. As a result, our customers could increasehave increased their spending onand commitments for deepwater offshore exploration and development which should benefithas benefited our offshore products segment. However, there can be no assurance that these expectationstrends will be realizedcontinue and there is a risk that continued energy prices at current levels could negatively impact worldwide economic growth and, correspondingly, reduce the demand for energy causing oil and gas expenditures to decline which would be adverse to our business. In addition, particularly in our well site services segment, we must continue to monitor industry capacity additions and evaluate our expected returns, project risks and expected cash flows and evaluate such capacity additions in light of their impact on the competitive marketplace.
1716
Results of Operations (in millions, except margin percentages)
| | | | | | | | | | | | | | | | | | | | | | | | |
| | THREE MONTHS ENDED | | NINE MONTHS ENDED | | | THREE MONTHS ENDED | |
| | SEPTEMBER 30, | | SEPTEMBER 30, | | | MARCH 31, | |
| | 2005 | | 2004 | | 2005 | | 2004 | | | 2006 | | 2005 | |
Revenues | | |
Offshore Products | | $ | 64.3 | | $ | 55.2 | | $ | 194.7 | | $ | 146.1 | | |
Tubular Services | | 188.3 | | 116.9 | | 493.9 | | 283.4 | | |
Well Site Services — | | |
Well Site Services - | | |
Accommodations | | 67.2 | | 42.3 | | 215.4 | | 139.5 | | | $ | 104.6 | | $ | 83.2 | |
Rental tools | | 40.0 | | 16.2 | | 90.3 | | 48.7 | | | 49.6 | | 19.1 | |
Drilling services | | 24.0 | | 12.8 | | 60.6 | | 34.5 | | | 28.0 | | 16.8 | |
Workover services | | 10.3 | | 8.1 | | 29.7 | | 25.7 | | | 8.5 | | 8.5 | |
| | | | | | | | | | | | | | |
Total Well Site Services | | 141.5 | | 79.4 | | 396.0 | | 248.4 | | | 190.7 | | 127.6 | |
Offshore Products | | | 78.3 | | 66.5 | |
Tubular Services | | | 227.2 | | 137.8 | |
| | | | | | | | | | | | | | |
Total | | $ | 394.1 | | $ | 251.5 | | $ | 1,084.6 | | $ | 677.9 | | | $ | 496.2 | | $ | 331.9 | |
| | | | | | | | | | | | | | |
| | |
Gross Margin | | |
Offshore Products | | $ | 14.3 | | $ | 10.7 | | $ | 42.6 | | $ | 27.8 | | |
Tubular Services | | 23.2 | | 16.8 | | 62.5 | | 35.7 | | |
Well Site Services — | | |
Well Site Services - | | |
Accommodations | | 16.4 | | 12.9 | | 51.9 | | 40.8 | | | $ | 33.3 | | $ | 23.0 | |
Rental tools | | 19.6 | | 7.2 | | 44.0 | | 21.5 | | | 26.5 | | 8.7 | |
Drilling services | | 9.3 | | 4.6 | | 21.4 | | 11.0 | | | 14.0 | | 5.8 | |
Workover services | | 3.1 | | 1.8 | | 8.5 | | 6.3 | | | 3.2 | | 1.7 | |
| | | | | | | | | | | | | | |
Total Well Site Services | | 48.4 | | 26.5 | | 125.8 | | 79.6 | | | 77.0 | | 39.2 | |
Offshore Products | | | 19.9 | | 14.1 | |
Tubular Services | | | 21.1 | | 18.0 | |
| | | | | | | | | | | | | | |
Total | | $ | 85.9 | | $ | 54.0 | | $ | 230.9 | | $ | 143.1 | | | $ | 118.0 | | $ | 71.3 | |
| | | | | | | | | | | | | | |
| | |
Gross Margin as a Percent of Revenues | | |
Well Site Services - | | |
Accommodations | | | | 31.8 | % | | | 27.6 | % |
Rental tools | | | | 53.4 | % | | | 45.5 | % |
Drilling services | | | | 50.0 | % | | | 34.5 | % |
Workover services | | | | 37.6 | % | | | 20.0 | % |
Total Well Site Services | | | | 40.4 | % | | | 30.7 | % |
Offshore Products | | | 22.2 | % | | | 19.4 | % | | | 21.9 | % | | | 19.0 | % | | | 25.4 | % | | | 21.2 | % |
Tubular Services | | | 12.3 | % | | | 14.4 | % | | | 12.7 | % | | | 12.6 | % | | | 9.3 | % | | | 13.1 | % |
Well Site Services — | | |
Total | | | | 23.8 | % | | | 21.5 | % |
| | |
Operating Income (Loss) | | |
Well Site Services - | | | | | | | | |
Accommodations | | | 24.4 | % | | | 30.5 | % | | | 24.1 | % | | | 29.2 | % | | $ | 25.3 | | $ | 17.1 | |
Rental tools | | | 49.0 | % | | | 44.4 | % | | | 48.7 | % | | | 44.1 | % | | 16.9 | | 3.2 | |
Drilling services | | | 38.8 | % | | | 35.9 | % | | | 35.3 | % | | | 31.9 | % | | 11.8 | | 4.2 | |
Workover services | | | 30.1 | % | | | 22.2 | % | | | 28.6 | % | | | 24.5 | % | | 1.8 | | 0.1 | |
| | | | | | | | | | | | | | |
Total Well Site Services | | | 34.2 | % | | | 33.4 | % | | | 31.8 | % | | | 32.0 | % | | 55.8 | | 24.6 | |
| | | | | | | | | | |
Total | | | 21.8 | % | | | 21.5 | % | | | 21.3 | % | | | 21.1 | % | |
| | | | | | | | | | |
| | |
Operating Income (Loss) | | |
Offshore Products | | $ | 5.9 | | $ | 2.7 | | $ | 16.6 | | $ | 4.7 | | | 10.1 | | 5.3 | |
Tubular Services | | 19.8 | | 14.1 | | 53.1 | | 28.5 | | | 17.8 | | 15.1 | |
Well Site Services — | | |
Accommodations | | 9.5 | | 7.5 | | 32.8 | | 25.1 | | |
Rental tools | | 10.9 | | 2.3 | | 22.5 | | 6.9 | | |
Drilling services | | 7.3 | | 3.5 | | 16.0 | | 8.0 | | |
Workover services | | 1.1 | | 0.1 | | 3.2 | | 1.1 | | |
| | | | | | | | | | |
Total Well Site Services | | 28.8 | | 13.4 | | 74.5 | | 41.1 | | |
| | | | | | | | | | |
Corporate / Other | | | (3.2 | ) | | | (2.3 | ) | | | (8.7 | ) | | | (5.6 | ) | | | (4.5 | ) | | | (2.8 | ) |
| | | | | | | | | | | | | | |
Total | | $ | 51.3 | | $ | 27.9 | | $ | 135.5 | | $ | 68.7 | | | $ | 79.2 | | $ | 42.2 | |
| | | | | | | | | | | | | | |
THREE MONTHS ENDED SEPTEMBER 30, 2005MARCH 31, 2006 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2004MARCH 31, 2005
Revenues.Total revenues increased $142.6$164.3 million, or 56.7%49.5%, to $394.1$496.2 million during the current quarter compared to revenues of $251.5$331.9 million during the quarter ended September 30, 2004.March 31, 2005. Offshore products revenues increased $9.1$11.8 million, or 16.5%17.7%, due to higher activity levels supporting offshore production facility construction. Tubular services revenues and tons shipped increased $71.4$89.4 million, or 61.1%64.9%, and 14,00044,700 tons, or 15.5%54.5%,
1817
respectively, in the three monthsquarter ended September 30, 2005March 31, 2006 compared to the three monthsquarter ended September 30, 2004March 31, 2005 due to increased industry demand, higher OCTG prices and contributions from the Phillips acquisition that closed in June 2005. Our average OCTG selling prices increased 39.6%6.6% from the thirdfirst quarter of 20042005 to the thirdfirst quarter of 2005.2006. Well site services revenues increased $62.1$63.1 million, or 78.2%49.5%, to $141.5$190.7 million during the current quarter compared to $79.4$127.6 million during the quarter ended September 30, 2004.March 31, 2005. Our drilling services revenues increased $11.2 million, or 87.5%66.7%, because of contributions from the Elenburg acquisition which added 7 rigs in February 2005, higher dayrates earned and additional3 newly built rigs added to the fleet. In ourfleet since March 31, 2005. Our workover services operations were sold effective March 1, 2006. Workover services revenues were flat when comparing the two months ended February 28, 2006 to the full quarter ended March 31, 2005 primarily as a result of higher activity in all areas of our operations, especiallyVenezuela in the U.S. Gulf and Venezuela, were higher in 2005 than 2004 resulting in a $2.2 million increase in revenues.2006. The rental tools business generated revenues in the thirdfirst quarter of 20052006 of $40.0$49.6 million, which were $23.8$30.5 million, or 146.9%159.7%, higher than the thirdfirst quarter of 20042005 due to the acquisition of Stinger, capital expenditures made since last year, improving U.S. drilling and workover activity and price increases. The Stinger acquisition was responsible for $20.6 million ofcontributed materially to the $23.8 million increase in revenues generated from the Company’sour rental tools business line. Accommodations revenues in the thirdfirst quarter of 20052006 were $24.9$21.4 million, or 58.9%25.7%, higher than accommodations revenues reported in the thirdfirst quarter of 20042005 primarily because of increased drilling activity during the winter season and increased activity in support of the oil sands region of Canada.
Gross Margin.Our gross margins, which we calculate before a deduction for depreciation expense, increased $31.9$46.7 million, or 59.1%65.5%, from $54.0$71.3 million in the quarter ended September 30, 2004March 31, 2005 to $85.9$118.0 million in the quarter ended September 30, 2005.March 31, 2006. Overall margins as a percentage of revenue remained relatively constant atimproved from 21.5% for the first quarter of 2005 to 23.8% of revenues in the thirdfirst quarter of 2004 compared2006 due to 21.8%improving gross margins in the third quarterall of 2005.our well site services businesses and our offshore products segment, partially offset by a decline in tubular services gross margins.
Total gross margins at offshore products were $14.3$19.9 million in the thirdfirst quarter of 20052006 compared to $10.7$14.1 million in the same period of the prior year representing an increase of 33.6%41.1%. Offshore products gross margin percentage improved from 19.4%21.2% in the thirdfirst quarter of 20042005 to 22.2%25.4% in the thirdfirst quarter of this year due to higher activity which resulted in greater overhead absorption, cost savingshigher margins on hurricane repair equipment and efficiencies resulting from manufacturing facility consolidations that occurred in 2004 and that have benefited 2005 and the absence of a $1.0 million warranty charge recordedalso to increased connector products sold in the third quarter of 2004.current quarter.
Tubular services gross margins increased by $6.4$3.1 million, or 38.1%17.2%, in the three months ended September 30, 2005March 31, 2006 compared to the three months ended September 30, 2004March 31, 2005 as a result of OCTG price increases and increased U.S. oil and gas land drilling activity which strengthened demand for our tubular products and services. Our tubular services segment gross margin as a percent of revenues decreased to 12.3%9.3% in the thirdfirst quarter of 2005 when2006 compared to 14.4%13.1% in the thirdfirst quarter of 20042005 because of less frequent and smaller OCTG price increases, in the third quarter of 2005 than in the same period in 2004higher industry inventory levels and because of a higher mix of lower margin carbon grade OCTG products sold in support of increased land drilling in the thirdfirst quarter of 2005.2006 coupled with the lingering effects of the hurricanes on Gulf of Mexico drilling activity which resulted in reduced demand for higher margin seamless alloy tubulars. Our acquisition of Phillips increased our participation in the carbon grade OCTG market segment.
Well site services gross margins increased by $21.9$37.8 million, or 82.6%96.4%, during the quarter ended September 30, 2005March 31, 2006 compared to the quarter ended September 30, 2004.March 31, 2005. Drilling services gross margins in the thirdfirst quarter of 2006 totaled $14.0 million compared to $5.8 million in the first quarter of 2005, totaled $9.3 million compared to $4.6 million in the third quarter of 2004, an increase of $4.7$8.2 million, or 102.2%141.4%. The drilling services gross margin percentage improved to 38.8%50.0% of revenues in the thirdfirst quarter of 20052006 from 35.9%34.5% of revenues in the thirdfirst quarter of 20042005 due primarily to higher dayrates in 20052006 and higher costs in the prior year duea move from billing on a footage rate basis to several problem jobs.billing on a dayrate basis for most of our drilling rigs. Rental tools gross margins totaled $19.6$26.5 million in the thirdfirst quarter of 2006 compared to $8.7 million in the first quarter of 2005, compared to $7.2 million in the third quarter of 2004, an increase of $12.4$17.8 million, or 172.2%204.6%. Rental tools gross margin percentage increased from 44.4%45.5% for the thirdfirst quarter of 20042005 to 49.0%53.4% in the thirdfirst quarter of 2005.2006. The improvement in gross margins and gross margin as a percentage of revenues resulted primarily from the positive impact of the Stinger acquisition which generated $11.7 million of the $12.4 million increase in rental tools gross margins.and pricing improvements realized. Workover gross margins improved to $3.1$3.2 million in the two months ended February 28, 2006 compared to $1.7 million in the three months ended September 30,March 31, 2005, an improvement despite the Company being sold effective March 1, 2006. Accommodations gross margins in the first quarter of 2006 totaled $33.3 million compared to $1.8$23.0 million in the three months ended September 30, 2004,first quarter of 2005, an improvementincrease of $1.3$10.3 million, or 72.2%44.8%. The workover gross margin percentage increased to 30.1% of revenues31.8% in the thirdfirst quarter of 2005 compared to 22.2% in the third quarter of 2004 due to a greater mix of activity involving lower cost workover activity and slightly higher dayrates. Accommodations gross margins in the third quarter of 2005 totaled $16.4 million compared to $12.9 million in the third quarter of 2004, an increase of $3.5 million, or 27.1%. The gross margin percentage declined to 24.4% in the third quarter of 20052006 compared to a 30.5%27.6% gross margin percentage for the thirdfirst quarter of 20042005 due to the higher relative mixbenefits of lower margin manufacturing revenues.
1918
price and utilization increases for our accommodations equipment, partially offset by losses on an accommodations installation project.
Selling, General and Administrative Expenses.Selling, general and administrative expenses (SG&A) increased $5.9$6.3 million, or 36.0%33.5%, in the thirdfirst quarter of 20052006 compared to the same period in 2004.2005. During the three months ended September 30, 2005,March 31, 2006, SG&A totaled $22.4$25.4 million, or 5.7%5.1% of revenues, compared to SG&A of $16.5$19.1 million, or 6.6%5.7% of revenues, for the three months ended September 30, 2004.March 31, 2005. Increased SG&A expense associated with acquisitions completed since the thirdfirst quarter of 2004, ad valorem taxes for2005, increased levelsstock compensation expense due to the implementation of OCTG inventory,SFAS No. 123R which required the expensing of stock options beginning January 1, 2006 and increased incentive compensation accruals and higher professional fees associated with Sarbanes-Oxley compliance were the primary factors causing increased SG&A in 20052006 compared to 2004.2005.
Depreciation and Amortization.Depreciation and amortization expense increased $3.1$2.7 million, or 33.8%26.0%, in the thirdfirst quarter 20052006 compared to the thirdfirst quarter 20042005 due primarily to acquisitions of businesses and capital expenditures made in the past year.
Operating Income.Our operating income represents revenues less (i) cost of sales, (ii) selling, general and administrative expenses, (iii) depreciation and amortization expense, and (iv) other operating (income) expense. Our operating income increased $23.4$37.0 million, or 83.9%87.7%, to $51.3$79.2 million for the three monthsquarter ended September 30, 2005March 31, 2006 from $27.9$42.2 million for the three monthsquarter ended September 30, 2004.March 31, 2005. Offshore products operating income increased $3.2$4.8 million, tubular services operating income increased $5.7$2.7 million and well site services operating income increased $15.4$31.2 million. These increases were partially offset by higher corporate costs of $0.9$1.7 million.
Interest Expense. Interest expense increased $1.9$2.5 million, or 93.5%107.3%, for the quarter ended September 30, 2005March 31, 2006 compared to the quarter ended September 30, 2004.March 31, 2005. Interest expense increased due to higher debt levels resulting from acquisitions completed since the thirdfirst quarter of 20042005 and capital expenditures, combined with higher interest rates.rates for our bank credit facility.
Income Tax Expense. Income tax expense totaled $17.7$34.2 million, or 39.3% of pretax income, during the quarter ended March 31, 2006 compared to $14.8 million, or 36.9% of pretax income, during the quarter ended September 30, 2005 compared to $11.0 million, or 41.4% of pretax income, during the quarter ended September 30, 2004.March 31, 2005. Our effective tax rate was higher in the thirdfirst quarter of 20042006 because of a change in the estimated 2004 annualhigher effective tax rate during that quarter. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Tax Matters” discussion below.
NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2004
Revenues.Total revenues increased $406.7 million, or 60.0%, to $1,084.6 million during the nine months ended September 30, 2005 compared to revenues of $677.9 million during the nine months ended September 30, 2004. Offshore products revenues increased $48.6 million, or 33.3%, due to higher activity levels supporting offshore production facility construction. Tubular services revenues and tons shipped increased $210.5 million, or 74.3%, and 44,600 tons, or 18.4%, respectively, in the nine months ended September 30, 2005 comparedapplicable to the nine months ended September 30, 2004 due to increased industry demand, higher OCTG prices,gain recognized on the Hunting acquisition completed in May 2004 and the Phillips acquisition that closed in June 2005. Our average OCTG selling prices increased 47.1% from the first nine months of 2004 to the first nine months of 2005. Well Site services revenues increased $147.6 million, or 59.4%, to $396.0 million during the first nine months of 2005 compared to $248.4 million during the first nine months of 2004. Our drilling revenues increased $26.1 million, or 75.7%, because of contributions from the Elenburg acquisition, which added 7 rigs in February 2005, higher dayrates earned and additional rigs added to the fleet. The Elenburg acquisition was responsible for $16.6 million of the $26.1 million increase in revenues generated from the Company’s drilling operations. Our hydraulic workover revenues increased by $4.0 million, or 15.6%, in the first nine months of 2005 compared to the same period in 2004 because of higher activity in allsale of our operating areas, especially the U.S. Gulf and Venezuela. Rental tools generated revenues in the nine months ended September 30, 2005 of $90.3 million, which were $41.6 million, or 85.4%, higher than the nine months ended September 30, 2004 due to the acquisition of Stinger, capital expenditures made since last year, improving U.S. drilling activity and modest price increases. The Stinger acquisition accounted for $31.6 million of the $41.6 million revenue increase generated by the Company’s rental tools business line. Accommodations revenues in the nine months ended September 30, 2005 were $215.4 million, an increase of $75.9 million, or 54.4%, over the accommodations revenues reported in the nine months ended September 30, 2004 primarily because of increased activity in support of the oil sands region of Canada.
20
Gross Margin.Our gross margins, which we calculate before a deduction for depreciation expense, increased $87.8 million, or 61.4%, from $143.1 million in the nine months ended September 30, 2004 to $230.9 million in the nine months ended September 30, 2005. Our overall gross margin as a percent of revenues was 21.3% in the first nine months of 2005 compared to 21.1% in the first nine months of 2004. Gross margin percentages increased in all businesses except accommodations where a greater percentage of revenues was generated by manufacturing activities which generally earn a lower margin than accommodations rental and service activities.
Total gross margins at offshore products were $42.6 million in the first nine months of 2005 compared to $27.8 million in the same period of the prior year, representing an increase of 53.2%. Offshore products gross margin percentage improved from 19.0% in the first nine months of 2004 to 21.9% in the first nine months of 2005 due to higher activity, which resulted in greater overhead absorption, cost savings and efficiencies resulting from manufacturing facility consolidations that occurred in 2004 and that have benefited 2005 and the absence of a $1.0 million warranty charge recorded in the third quarter of 2004.
Tubularworkover services gross margins increased $26.8 million, or 75.1%, in the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004 as a result of price increases and increased oil and gas drilling activity which strengthened demand for our tubular products and services. Our tubular services segment gross margin as a percent of revenues remained relatively constant at 12.6% in the first nine months of 2004 compared to 12.7% in the first nine months of 2005.
Well Site services gross margins increased by $46.2 million, or 58.0%, during the first nine months of 2005 compared to the first nine months of 2004. Drilling gross margins in the nine months ended September 30, 2005 totaled $21.4 million compared to $11.0 million in the nine months ended September 30, 2004, an increase of $10.4 million, or 94.5%. Of the $10.4 million increase in drilling gross margins, $6.0 million was generated by the Elenburg acquisition. Our drilling services gross margin percentage improved to 35.3% of revenues in the first nine months of 2005 from 31.9% of revenues in the first nine months of 2004 due primarily to higher dayrates. Workover gross margins improved by $2.2 million, or 34.9%, in the first nine months of 2005 compared to the same period of the prior year because of higher activity in the U.S. Gulf and Venezuela. The workover gross margin percentage increased to 28.6% of revenues in the first nine months of 2005 compared to 24.5% in the first nine months of 2004 due primarily to higher utilization. Rental tools gross margins totaled $44.0 million in the nine months ended September 30, 2005 compared to $21.5 million in the nine months ended September 30, 2004, an increase of $22.5 million, or 104.7%. Rental tools gross margin percentage increased from 44.1% for the first nine months of 2004 to 48.7% in the first nine months of 2005. The improvement resulted from higher utilization of tools, modestly higher rental rates and the positive impact of the Stinger acquisition. Of the $22.5 million increase in rental tools gross margins, $17.4 million was generated by Stinger since its acquisition in May of 2005. Accommodations gross margins in the nine months ended September 30, 2005 totaled $51.9 million compared to $40.8 million in the nine months ended September 30, 2004, an increase of $11.1 million, or 27.2%. The gross margin percentage declined to 24.1% in the first nine months of 2005 compared to the 29.2% gross margin percentage for the first nine months of 2004 due to a higher relative mix of lower margin manufacturing revenues.
Selling, General and Administrative Expenses.Selling, general and administrative expenses (SG&A) increased $15.1 million, or 32.1%, in the first nine months of 2005 compared to the same period in 2004. During the nine months ended September 30, 2005, SG&A totaled $62.2 million, or 5.7% of revenues, compared to SG&A of $47.1 million, or 6.9% of revenues, for the nine months ended September 30, 2004. Increased SG&A expense associated with acquisitions completed since September 2004, higher ad valorem taxes for increased levels of OCTG inventory, increased incentive compensation accruals, and higher professional fees associated with Sarbanes-Oxley compliance were the primary factors causing the increased SG&A in 2005 compared to 2004.
Depreciation and Amortization.Depreciation and amortization expense increased $7.2 million, or 27.3%, in the first nine months of 2005 compared to the first nine months of 2004 due primarily to acquisitions of businesses and capital expenditures made in the past year.
Operating Income.Our operating income represents revenues less (i) cost of sales, (ii) selling, general and administrative expenses, (iii) depreciation and amortization expense, and (iv) other operating (income) expense. Our operating income increased $66.8 million, or 97.2%, to $135.5 million for the nine months ended September 30,
21
2005 from $68.7 million for the nine months ended September 30, 2004. Offshore products operating income increased $11.9 million, tubular services operating income increased $24.6 million and well site services operating income increased $33.4 million. These increases were partially offset by higher corporate costs of $3.1 million.
Interest Expense.Interest expense increased $3.9 million, or 70.5%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. Interest expense increased due to higher debt levels resulting from acquisitions completed since September 30, 2004 and capital expenditures, combined with higher interest rates.
Income Tax Expense.Income tax expense totaled $47.0 million, or 36.9% of pretax income, during the nine months ended September 30, 2005 compared to $20.5 million, or 31.9% of pretax income, during the nine months ended September 30, 2004. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Tax Matters” discussion below.business.
Liquidity and Capital Resources
Our primary liquidity needs are to fund capital expenditures, such as expanding our accommodations facilities, expanding and upgrading our manufacturing facilities and equipment, increasing and replacing our drilling rig,rigs and rental tool and workover assets, and our accommodation units, funding new product development and funding general working capital needs. In addition, capital is needed to fund strategic business acquisitions. Our primary sources of funds have been cash flow from operations, proceeds from borrowings under our bank facilities and more recently, proceeds from our $175 million convertible bond offering.note offering in 2005.
Cash totaling $0.3$18.7 million was provided by operations during the nine monthsquarter ended September 30, 2005March 31, 2006 compared to cash used in operating activities totaling $64.8$6.1 million provided by operations in the nine monthsquarter ended September 30, 2004.March 31, 2005. During the first nine monthsquarter of 2005, $119.52006, $38.0 million was used to fund working capital. SignificantlyReceivables increased working capital was investedseasonally in tubular services inventory due toour Canadian accommodations business and inventories increased volumesin our accommodations and prices paid. Additionally, trade receivables increased as a result of higher revenues and temporary disruptions of collections caused by U.S. Gulf hurricane activity in the third quarter.offshore products segments.
Cash was used in investing activities during the nine monthsquarters ended September 30,March 31, 2006 and 2005 and 2004 in the amount of $194.5$30.2 million and $114.6$39.3 million, respectively. Capital expenditures totaled $49.4$26.5 million and $38.1$17.1 million during the nine monthsquarters ended September 30,March 31, 2006 and 2005, and 2004, respectively. Capital expenditures in both yearsperiods consisted principally of purchasesthe purchase of assets for our well site services segment. In addition, weWe completed various acquisitions for net cash consideration totaling $146.6$22.6 million and $79.5 million net of cash acquired, during the first nine monthsquarter of 2005 and 2004, respectively.
On February 1, 2005, the Company completed the acquisition of Elenburg Exploration Company, Inc. (Elenburg), a Wyoming based land drilling company for cash consideration of $21.3 million, including transaction costs, plus a note payable to the former owners of $0.8 million. Elenburg owned and operated 7 rigs which provide shallow land drilling services in Montana, Wyoming, Colorado, and Utah.
Effective May 1, 2005 the Company acquired Stinger Wellhead Protection, Inc., certain affiliated companies and related intellectual property, (collectively, Stinger) for cash consideration of $78.0 million, net of cash acquired and including transaction costs, plus a note payable to the former owners of $5.0 million. Stinger provides wellhead isolation equipment and services through its 23 locations in the United States and Canada. Stinger’s patented equipment is utilized during pressure pumping operations and isolates the customers’ blow-out preventers or wellheads from the pressure and abrasion experienced during the fracturing process of an oil or gas well. In June 2005, the Company completed the acquisition of Stinger’s international operations for additional cash consideration of $6.2 million, net of cash acquired and including transaction costs. The Stinger international operations are conducted primarily in Central and South America. The Stinger acquisition expanded the Company’s rental tool and services capabilities, especially in the pressure pumping market.
On June 2, 2005, the Company purchased Phillips Casing and Tubing, L.P. (Phillips) for cash consideration of $31.1 million, net of cash acquired and including transaction costs. Phillips distributes oil country tubular goods
22
(OCTG), primarily carbon ERW (electronic resistance welded) pipe, from its facilities in Midland and Godley, Texas.
On June 6, 2005, the Company acquired Noble Structures, Inc. for cash consideration of $7.9 million, including a note payable of $0.8 million. The acquisition expanded the Company’s accommodation manufacturing capabilities in Canada in order to meet increased demand for remote site facilities, principally in the oil sands region.
The cash consideration paid for all of the Company’s acquisitions in the period was initially funded utilizing its existing bank credit facility and a $25 million bridge loan (See Note 6). Accounting for the acquisitions made in the period has not been finalized and is subject to adjustments during the purchase price allocation period, which is not expected to exceed a period of one year from the respective acquisition dates.2005.
We currently expect to spend a total of approximately $88.0$125.0 million for capital expenditures during 2005, including an expected $38.6 million in the fourth quarter,2006, for maintenance and upgrade of our equipment and facilities and also to expand our product and service offerings. We
19
expect to fund these capital expenditures with internally generated funds and proceeds from borrowings under our revolving credit facilities.
Net cash of $194.9$8.4 million wasand $47.5 million were provided by financing activities during the nine monthsquarters ended September 30,March 31, 2006 and 2005, respectively, primarily as a result of revolving credit borrowings and the issuance of $175 million aggregate principal amount of 2 3/8% contingent convertible senior notes due in 2025 (2 3/8% notes) in the second and third quarters of 2005. Net proceeds from the 2 3/8% notes were utilized to repurchase $30 million of the Company’s common stock, which was classified as treasury stock at September 30, 2005, to repay an outstanding bridge loan of $25 million and to repay indebtedness of $114.5 millionmade under our revolving credit facility. During the first quarter of 2005, the Company’sour Board of Directors authorized the repurchase of up to $50 million of the Company’sour common stock, par value $.01 per share, over a two year period. Through September 30, 2005,March 31, 2006, a total of $30 million of the Company’sour stock acquired with a portion of the proceeds from the issuance of the 2 3/8% notes,(1,183,432 shares), has been repurchased under this program. No shares of the Company’sour stock were repurchased during the three months ended September 30, 2005 andMarch 31, 2006 leaving a total of up to $20 million remains available under the program.
Our primary bank credit facility (the Credit Facility), which matures in January 2010, provides for $325 million of revolving credit. The credit agreement, which governs our Credit Facility (the Credit Agreement), contains customary financial covenants and restrictions, including restrictions on our ability to declare and pay dividends. Borrowings under the Credit Agreement are secured by a pledge of substantially all of our assets and the assets of our subsidiaries. Our obligations under the Credit Agreement are guaranteed by our significant subsidiaries. Borrowings under the Credit Agreement accrue interest at a rate equal to either LIBOR or another benchmark interest rate (at our election) plus an applicable margin based on our leverage ratio (as defined in the Credit Agreement). We must pay a quarterly commitment fee, based on the Company’sour leverage ratio, on the unused commitments under the Credit Agreement. During the first nine monthsquarter of 2005,2006, our applicable margin over LIBOR ranged from 1% to 2% and it was 1.25% as of September 30, 2005.. Our weighted average interest rate paid under the Credit Agreement was 4.7%5.8% during the three monthsquarter ended September 30, 2005March 31, 2006 and 4.4%4.2% for the nine monthsquarter ended September 30,March 31, 2005.
As of September 30, 2005,March 31, 2006, we had $223.3$226.9 million outstanding under the Credit Facility and an additional $11.3$10.9 million of outstanding letters of credit, leaving $90.4$87.2 million available to be drawn under the facility. In addition, we have other floating rate bank credit facilities in the U.S. and the U.K. that provide for an aggregate borrowing capacity of $8.6$8.5 million. We had no borrowings outstanding under these other facilities as of September 30, 2005.March 31, 2006. Our total debt represented 40.8%37.1% of our total capitalization at September 30, 2005.March 31, 2006.
We believe that cash from operations and available borrowings under our credit facilities will be sufficient to meet our liquidity needs in the coming twelve months. If our plans or assumptions change or are inaccurate, or if we make further acquisitions, we may need to raise additional capital. However, there is no assurance that we will be able to raise additional funds or be able to raise such funds on favorable terms.
Tax Matters
23
Our primary deferred tax asset, which totaled approximately $12.5 million at December 31, 2004, is related to $35.8 million in available federal net operating loss carryforwards, or NOLs, as of that date. A valuation allowance of approximately $5.1 million was provided against the deferred tax asset associated with our NOLs at December 31, 2004. The NOLs will expire in varying amounts during the years 2010 through 2020 if they are not first used to offset taxable income generated by the Company. The Company’s ability to utilize a significant portion of the NOLs is currently limited under Section 382 of the Internal Revenue Code due to a change of control that occurred during 1995. A successive change in control was triggered in 2003 pursuant to Section 382; however it did not significantly change the Company’s NOL utilization expectations.
The Company’s income tax provision for the three months ended September 30, 2005March 31, 2006 totaled $17.7$34.2 million, or 36.9%39.3% of pretax income, compared to $11.0$14.8 million, or 41.4%36.9% of pretax income, for the three months ended September 30, 2004. The Company’s income tax provision for the nine months ended September 30, 2005 totaled $47.0 million, or 36.9%, of pretax income compared to $20.5 million, or 31.9%, of pretax income for the nine months ended September 30, 2004. Our effective tax rate was lower in the first nine months of 2004 as a result of the recognition of a $5.4 million income tax benefit related to the partial reversal of the valuation allowance applied against NOLs which were recorded as of the prior year end.March 31, 2005.
We currently estimate that our effective tax rate for the full year 20052006 will approximate 35% to 38%37%. Our actual effective tax rate could differ materially from this estimate, which is subject to a number of uncertainties, including future taxable income projections, the amount of income attributable to domestic versus foreign sources, the amount of capital expenditures and any changes in applicable tax laws and regulations. Based upon the loss limitation provisions of Section 382, we should be able to utilize approximately $8$4.4 million of our NOLs to offset taxable income generated by the Company during the tax year ended December 31, 2005.2006. The income statement benefit of substantially all of our NOLs has been recognized in prior periods.
RecentCritical Accounting PronouncementsPolicies
In the fourth quarterour selection of 2004, the FASB issued Statement No. 123 (revised 2004), or SFAS No. 123R, “Share-Based Payment,” which replaces Statement No. 123 “Accounting for Stock-Based Compensation,”critical accounting policies, our objective is to properly reflect our financial position and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123R eliminates the alternative toresults of operations in each reporting period in a manner that will be understood by those who utilize our financial statements. Often we must use APB Opinion 25’s intrinsic value method of accounting that was provided in Statement No. 123 as originally issued. After a phase-in period for Statement No. 123R, pro forma disclosure will no longer be allowed.our judgment about uncertainties.
Alternative phase-in methodsThere are allowed under Statement No. 123R,several critical accounting policies that we have put into practice that have an important effect on our reported financial results.
20
We have contingent liabilities and future claims for which we have made estimates of the amount of the eventual cost to liquidate these liabilities or claims. These liabilities and claims sometimes involve threatened or actual litigation where damages have been quantified and we have made an assessment of our exposure and recorded a provision in our accounts to cover an expected loss. Other claims or liabilities have been estimated based on our experience in these matters and, when appropriate, the advice of outside counsel or other outside experts. Upon the ultimate resolution of these uncertainties, our future reported financial results will be impacted by the difference between our estimates and the actual amounts paid to settle a liability. Examples of areas where we have made important estimates of future liabilities include litigation, taxes, interest, warranty claims, contract claims and discontinued operations.
The assessment of impairment on long-lived assets, including goodwill and investments in unconsolidated subsidiaries, is conducted whenever changes in the facts and circumstances indicate a loss in value has occurred. The determination of the amount of impairment, which is effective for registrantsother than a temporary decline in value, would be based on quoted market prices, if available, or upon our judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. Our industry is highly cyclical and our estimates of the beginningperiod over which future cash flows will be generated, as well as the predictability of these cash flows and our determination of whether an other than temporary decline in value of our investment has occurred, can have a significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment charges.
We recognize revenue and profit as work progresses on long-term, fixed price contracts using the percentage-of-completion method, which relies on estimates of total expected contract revenue and costs. We follow this method since reasonably dependable estimates of the first fiscal year beginning after June 15, 2005. Werevenue and costs applicable to various stages of a contract can be made. Recognized revenues and profit are currentlysubject to revisions as the contract progresses to completion. Revisions in profit estimates are charged to income or expense in the processperiod in which the facts and circumstances that give rise to the revision become known. Provisions for estimated losses on uncompleted contracts are made in the period in which losses are determined.
Our valuation allowances, especially related to potential bad debts in accounts receivable and to obsolescence or market value declines of evaluatinginventory, involve reviews of underlying details of these assets, known trends in the impactmarketplace and the application of historical factors that provide us with a basis for recording these allowances. If market conditions are less favorable than those projected by management, or if our historical experience is materially different from future experience, additional allowances may be required.
The selection of the useful lives of many of our assets requires the judgments of our operating personnel as to the length of these useful lives. Should our estimates be too long or short, we might eventually report a disproportionate number of losses or gains upon disposition or retirement of our long-lived assets. We believe our estimates of useful lives are appropriate.
Since the adoption of SFAS No. 123R on– Share Based Payments, effective January 1, 2006, we are required to estimate the fair value of stock compensation made pursuant to awards under the Company’s 2001 Equity Participation Plan (Plan). An initial estimate of fair value of each stock option or restricted stock award determines the amount of stock compensation expense we will recognize in the future. To estimate the value of stock option awards under the Plan, we have selected a fair value calculation model. We have chosen the Black Shoals Merton “closed form” model to value stock options awarded under the Plan. We have chosen this model because our consolidated condensed financial statements.option awards have been made under straightforward and consistent vesting terms, option prices and option lives. Utilizing the Black Shoals Merton model requires us to estimate the length of time options will remain outstanding, a risk free interest rate for the estimated period options are assumed to be outstanding, forfeiture rates, future dividends and the volatility of our common stock. All of these assumptions affect the amount and timing of future stock compensation expense recognition. We will adopt SFAS No. 123R on January 1, 2006.continually monitor our actual experience and change future assumptions for awards as we consider appropriate.
21
ITEM 3.Quantitative and Qualitative Disclosures about Market Risk
Interest Rate Risk.We have long-term debt and revolving lines of credit that are subject to the risk of loss associated with movements in interest rates. As of September 30, 2005,March 31, 2006, we had floating rate obligations totaling approximately $223.3$226.9 million for amounts borrowed under our revolving credit facilities. These floating-rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. If the floating interest rate were to increase by 1% from September 30, 2005March 31, 2006 levels, our consolidated interest expense would increase by a total of approximately $2.2$2.3 million annually.
Foreign Currency Exchange Rate Risk.Our operations are conducted in various countries around the world and we receive revenue from these operations in a number of different currencies. As such, our earnings are subject to movements in foreign currency exchange rates when transactions are denominated in currencies other than the U.S. dollar, which is our functional currency or the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of exchange rate risks, we generally pay a portion of our expenses in local currencies and a substantial portion of our contracts provide for collections from customers in U.S. dollars. WeIn the past, we have hedged U.S. dollar balances and cash flows totaling $5.5 million in our U.K. subsidiary in the fourth quartersubsidiary; however, no active hedges exist as of 2005 through the first quarter ofMarch 31, 2006. Results of operations have not been materially affected by foreign currency hedging activity.
24
ITEM 4.Controls and Procedures
As of the end of the period covered by this Quarterly Report on Form 10-Q, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2005March 31, 2006 in ensuring that material information was accumulated and communicated to management, and made known to our Chief Executive Officer and Chief Financial Officer, on a timely basis to allow disclosure as required in this Quarterly Report on Form 10-Q. During the three months ended September 30, 2005,March 31, 2006, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) or in other factors which have materially affected our internal control over financial reporting, or are reasonably likely to materially affect our internal control over financial reporting.
2522
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
We are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our products or operations. Some of these claims relate to matters occurring prior to our acquisition of businesses, and some relate to businesses we have sold. In certain cases, we are entitled to indemnification from the sellers of businesses and in other cases, we have indemnified the buyers that purchased businesses from us. Although we can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by indemnity or insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.
On February 18, 2005, the Companywe announced that itwe had conducted an internal investigation prompted by the discovery of over billings totaling approximately $400,000 by one of itsour subsidiaries (the “Subsidiary”) to a government owned oil company in South America. The over billings were detected by the Company during routine financial review procedures, and appropriate financial statement adjustments were included in itsour previously reported fourth quarter 2004 results. The CompanyWe and independent counsel retained by the Company’sour audit committee conducted separate investigations consisting of interviews and ana thorough examination of the facts and circumstances in this matter. The CompanyWe voluntarily reported the results of itsour investigation to the Securities and Exchange Commission (the “SEC”) and has fully cooperated with additional requests for information received from the SEC. The Company understands that the SEC has recently completed its informal investigation of this matter. On October 31, 2005, the Company’sour counsel received a “Wells Notice” from the staff of the SEC indicating that the staff has made a preliminary decision to recommend that the SEC bring a civil action against the Company alleging violations of provisions of the Securities and Exchange Act of 1934 relating to the maintenance of books, records and internal accounting controls and procedures as set forth in Sections 13(b)(2)(A) and (B) of the Act. The alleged violations related to this over billings matter. A “Wells Notice” is notCompany reached a formal allegation or proof of wrongdoing. Recipients of “Wells Notices” have the opportunity to respond tosettlement agreement with the SEC staff before the staff makes a formal recommendation on whether any action should be broughtApril 27, 2006. The Company consented to an Order by the SEC. TheSEC (Order), without admitting or denying the findings in the Order, that required the Company is engaged in discussions with the staffto cease and desist from committing or causing violations of the SEC regarding“books and records” and “internal control provisions” of the “Wells Notice”laws of the Securities and is currently evaluating its planned responseExchange Act of 1934. The settlement did not require the Company to this matter.pay a monetary penalty.
ITEM 1A. RISK FACTORS
Item 1A. “Risk Factors” of our 2005 Form 10-K includes a detailed discussion of our risk factors. There have been no significant changes to our risk factors as set forth in our 2005 Form 10-K.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
ITEM 5. OTHER INFORMATION
None
23
ITEM 6. EXHIBITS
(a) INDEX OF EXHIBITS
| | | | |
Exhibit No. | | | | Description |
31.1*10.21**,* | | — | | Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.Non-Employee Director Compensation Summary |
| | | | |
31.2* | | — | | Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934. |
| | | | |
32.1*** | | — | | Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934. |
26
| | | | |
Exhibit No. | | | | Description |
32.2*** | | — | | Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934. |
| | |
* | | Filed herewith |
|
*** | | Furnished herewith. |
27
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | | | | | |
OIL STATES INTERNATIONAL, INC.
| | |
| | | | | | |
Date: November 3, 2005 | | By | | /s/ CINDY B. TAYLOR | | |
| | | | | | |
| | | | Cindy B. Taylor | | |
| | | | Senior Vice President, Chief Financial Officer and | | |
| | | | Treasurer (Principal Financial Officer) | | |
| | | | | | |
Date: November 3, 2005 | | By | | /s/ ROBERT W. HAMPTON | | |
| | | | | | |
| | | | Robert W. Hampton | | |
| | | | Vice President — Finance and Accounting and | | |
| | | | Secretary (Principal Accounting Officer) | | |
28
INDEX OF EXHIBITS
| | | | |
Exhibit No. | | | | Description |
31.1* | | — | | Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934. |
| | | | |
31.2* | | — | | Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934. |
| | | | |
32.1*** | | — | | Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934. |
| | | | |
32.2*** | | — | | Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934. |
| | |
* | | Filed herewith |
|
** | | Management contracts or compensation plans or arrangements |
|
*** | | Furnished herewith. |
2924
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
OIL STATES INTERNATIONAL, INC.
| | | | | | | | |
| | | | | | | | |
| | Date: May 5, 2006 | | By | | /s/ CINDY B. TAYLOR | | |
| | | | | | | | |
| | | | | | Cindy B. Taylor | | |
| | | | �� | | Senior Vice President, Chief Financial Officer and | | |
| | | | | | Treasurer (Principal Financial Officer) | | |
| | | | | | | | |
| | Date: May 5, 2006 | | By | | /s/ ROBERT W. HAMPTON | | |
| | | | | | | | |
| | | | | | Robert W. Hampton | | |
| | | | | | Vice President — Finance and Accounting and | | |
| | | | | | Secretary (Principal Accounting Officer) | | |
25
Exhibit Index
| | | | |
Exhibit No. | | | | Description |
10.21**,* | | — | | Non-Employee Director Compensation Summary |
| | | | |
31.1* | | — | | Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934. |
| | | | |
31.2* | | — | | Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934. |
| | | | |
32.1*** | | — | | Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934. |
| | | | |
32.2*** | | — | | Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934. |
| | |
* | | Filed herewith |
|
** | | Management contracts or compensation plans or arrangements |
|
*** | | Furnished herewith. |