UNITED STATES SECURITIES AND EXCHANGE
COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One) | |||
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||
| |||
| |||
For the Quarterly Period Ended | |||
or | |||
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number: 1-8038
KEY ENERGY SERVICES, INC.
(Exact Namename of Registrantregistrant as Specifiedspecified in Its Charter)its charter)
Maryland |
| 04-2648081 |
(State or |
| (I.R.S. Employer |
|
|
1301 McKinney Street, Suite 1800, Houston, Texas 77010
(Address of Principal Executive Offices)principal executive offices) (Zip Code)
713/(713) 651-4300
(Registrant’s Telephone Number, Including Area Code)telephone number, including area code)
None
(Former Name, Former Addressname, former address and Former Fiscal Year,former fiscal year, if Changed Since Last Report)changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes xNoo
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a non-accelerated filer.smaller reporting company. See definitiondefinitions of “large accelerated filer,” “accelerated filerfiler” and large accelerated filer”“smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large |
| Accelerated |
Non-accelerated filer o |
|
|
(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes oNox
As of October 31, 2007,April 30, 2008, the number of outstanding shares of common stock of the Registrantregistrant was 132,670,100.
125,298,014.
KEY ENERGY SERVICES, INC.
INDEX TO FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2007MARCH 31, 2008
FORWARD-LOOKING STATEMENTS
In addition to statements of historical fact, this report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Statements that are not historical in nature or that relate to future events and conditions are, or may be deemed to be, forward-looking statements. These “forward-looking statements” are based on our current expectations, estimates and projections about Key Energy Services, Inc. (“the Company,Company”), our industry and management’s beliefs and assumptions concerning future events and financial trends affecting our financial condition and results of operations. In some cases, you can identify these statements by terminology such as “may,” “will,” “predicts,” “projects,” “potential” or “continue” or the negative of such terms and other comparable terminology. These statements are only predictions and are subject to substantial risks and uncertainties. Actual performance or results may differ materially and adversely.
We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date of this report except as required by law. All of our written and oral forward-looking statements are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements.
2
Item 1. CONDENSEDCONSOLIDATED UNAUDITED FINANCIAL STATEMENTSFinancial Statements.
Key Energy Services, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
(In thousands)
|
| March 31, |
| December 31, |
| ||
|
| 2008 |
| 2007 |
| ||
|
| (unaudited) |
|
|
| ||
ASSETS |
|
|
|
|
| ||
Current assets: |
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 29,871 |
| $ | 58,503 |
|
Short-term investments |
| 270 |
| 276 |
| ||
Accounts receivable, net of allowance for doubtful accounts of $13,500 and $13,501 at March 31, 2008 and December 31, 2007, respectively |
| 355,327 |
| 343,408 |
| ||
Inventories |
| 25,310 |
| 22,849 |
| ||
Prepaid expenses |
| 12,644 |
| 12,997 |
| ||
Deferred tax assets |
| 27,687 |
| 27,676 |
| ||
Income taxes receivable |
| 1,261 |
| 15,796 |
| ||
Other current assets |
| 8,420 |
| 6,360 |
| ||
|
|
|
|
|
| ||
Total current assets |
| 460,790 |
| 487,865 |
| ||
|
|
|
|
|
| ||
Property and equipment, gross |
| 1,623,594 |
| 1,595,225 |
| ||
Accumulated depreciation |
| (714,776 | ) | (684,017 | ) | ||
|
|
|
|
|
| ||
Property and equipment, net |
| 908,818 |
| 911,208 |
| ||
|
|
|
|
|
| ||
Goodwill |
| 378,593 |
| 378,550 |
| ||
Other intangible assets, net |
| 43,673 |
| 45,894 |
| ||
Deferred financing costs, net |
| 11,925 |
| 12,117 |
| ||
Notes and accounts receivable - related parties |
| 168 |
| 173 |
| ||
Investment in IROC Energy Services Corp |
| 10,617 |
| 11,217 |
| ||
Other assets |
| 12,222 |
| 12,053 |
| ||
|
|
|
|
|
| ||
TOTAL ASSETS |
| $ | 1,826,806 |
| $ | 1,859,077 |
|
|
|
|
|
|
| ||
LIABILITIES AND STOCKHOLDERS’ EQUITY |
|
|
|
|
| ||
Current liabilities: |
|
|
|
|
| ||
Accounts payable |
| $ | 20,594 |
| $ | 35,159 |
|
Accrued liabilities |
| 187,935 |
| 183,364 |
| ||
Accrued interest |
| 13,117 |
| 3,895 |
| ||
Current portion of capital lease obligations |
| 9,899 |
| 10,701 |
| ||
Current notes payable - related parties, net of discount |
| 1,714 |
| 1,678 |
| ||
|
|
|
|
|
| ||
Total current liabilities |
| 233,259 |
| 234,797 |
| ||
|
|
|
|
|
| ||
Capital lease obligations, less current portion |
| 15,105 |
| 16,114 |
| ||
Notes payable - related party, less current portion |
| 20,500 |
| 20,500 |
| ||
Long-term debt |
| 475,000 |
| 475,000 |
| ||
Workers’ compensation, vehicular, health and other insurance claims |
| 42,629 |
| 43,818 |
| ||
Deferred tax liabilities |
| 159,909 |
| 160,068 |
| ||
Other non-current accrued liabilities |
| 19,150 |
| 19,531 |
| ||
|
|
|
|
|
| ||
Minority interest |
| 207 |
| 251 |
| ||
Commitments and contingencies |
|
|
|
|
| ||
|
|
|
|
|
| ||
Stockholders’ equity: |
|
|
|
|
| ||
Common stock, $0.10 par value; 200,000,000 shares authorized, 126,005,998 and 131,142,905 shares issued and outstanding at March 31, 2008 and December 31, 2007, respectively |
| 12,601 |
| 13,114 |
| ||
Additional paid-in capital |
| 643,277 |
| 704,644 |
| ||
Accumulated other comprehensive loss |
| (38,536 | ) | (37,981 | ) | ||
Retained earnings |
| 243,705 |
| 209,221 |
| ||
|
|
|
|
|
| ||
Total stockholders’ equity |
| 861,047 |
| 888,998 |
| ||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY |
| $ | 1,826,806 |
| $ | 1,859,077 |
|
See the accompanying notes which are an integral part of these condensed consolidated unaudited financial statements
3
Key Energy Services, Inc. and Subsidiaries
Condensed Consolidated Statements of Operations
(In thousands, except per share data)
(Unaudited)
|
| September 30, 2007 |
| December 31, 2006 |
| ||
|
|
| |||||
ASSETS |
| (Unaudited) |
|
|
| ||
Current assets: |
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 45,736 |
| $ | 88,375 |
|
Marketable securities |
| 110,156 |
| 61,767 |
| ||
Accounts receivable, net of allowance for doubtful accounts of $14,518 and $12,998 at September 30, 2007 and December 31, 2006, respectively |
| 296,803 |
| 272,382 |
| ||
Inventories |
| 21,334 |
| 19,505 |
| ||
Prepaid expenses |
| 8,988 |
| 4,810 |
| ||
Deferred tax assets |
| 30,408 |
| 35,968 |
| ||
Other current assets |
| 14,881 |
| 5,799 |
| ||
|
|
|
|
|
| ||
Total current assets |
| 528,306 |
| 488,606 |
| ||
|
|
|
|
|
| ||
Property, plant and equipment |
| 1,438,058 |
| 1,279,980 |
| ||
Accumulated depreciation |
| (657,980 | ) | (585,689 | ) | ||
|
|
|
|
|
| ||
Net property, plant and equipment |
| 780,078 |
| 694,291 |
| ||
|
|
|
|
|
| ||
Goodwill |
| 324,611 |
| 320,912 |
| ||
Deferred costs, net |
| 9,761 |
| 9,952 |
| ||
Notes and accounts receivable - related parties |
| 177 |
| 287 |
| ||
Other assets |
| 35,105 |
| 27,350 |
| ||
|
|
|
|
|
| ||
TOTAL ASSETS |
| $ | 1,678,038 |
| $ | 1,541,398 |
|
|
|
|
|
|
| ||
LIABILITIES AND STOCKHOLDERS’ EQUITY |
|
|
|
|
| ||
Current liabilities: |
|
|
|
|
| ||
Accounts payable |
| $ | 16,147 |
| $ | 15,294 |
|
Accrued liabilities |
| 174,601 |
| 189,570 |
| ||
Accrued interest |
| 5,386 |
| 2,530 |
| ||
Current portion of capital lease obligations |
| 10,942 |
| 11,714 |
| ||
Current portion of long-term debt |
| 5,000 |
| 4,000 |
| ||
|
|
|
|
|
| ||
Total current liabilities |
| 212,076 |
| 223,108 |
| ||
|
|
|
|
|
| ||
Capital lease obligations, less current portion |
| 16,798 |
| 14,080 |
| ||
Long-term debt, less current portion |
| 389,191 |
| 392,000 |
| ||
Workers’ compensation, vehicular, health and other insurance claims |
| 45,309 |
| 44,617 |
| ||
Deferred tax liability |
| 123,672 |
| 115,826 |
| ||
Other non-current accrued expenses |
| 22,188 |
| 21,256 |
| ||
|
|
|
|
|
| ||
Commitments and contingencies |
|
|
|
|
| ||
|
|
|
|
|
| ||
Stockholders’ equity: |
|
|
|
|
| ||
Common stock, $0.10 par value; 200,000,000 shares authorized, 131,890,674 and 131,624,038 shares issued and outstanding at September 30, 2007 and December 31, 2006, respectively |
| 13,242 |
| 13,212 |
| ||
Additional paid-in capital |
| 728,805 |
| 722,610 |
| ||
Treasury stock, at cost; 533,466 and 497,501 shares at September 30, 2007 and December 31, 2006, respectively |
| (11,564 | ) | (10,862 | ) | ||
Accumulated other comprehensive loss |
| (37,828 | ) | (36,284 | ) | ||
Retained earnings |
| 176,149 |
| 41,835 |
| ||
|
|
|
|
|
| ||
Total stockholders’ equity |
| 868,804 |
| 730,511 |
| ||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY |
| $ | 1,678,038 |
| $ | 1,541,398 |
|
|
| Three Months Ended March 31, |
| ||||
|
| 2008 |
| 2007 |
| ||
|
|
|
|
|
| ||
REVENUES: |
|
|
|
|
| ||
Well servicing |
| $ | 348,878 |
| $ | 311,160 |
|
Pressure pumping |
| 81,852 |
| 74,077 |
| ||
Fishing and rental |
| 25,669 |
| 23,682 |
| ||
|
|
|
|
|
| ||
Total revenues |
| 456,399 |
| 408,919 |
| ||
|
|
|
|
|
| ||
COSTS AND EXPENSES: |
|
|
|
|
| ||
Well servicing |
| 211,751 |
| 175,529 |
| ||
Pressure pumping |
| 53,779 |
| 46,533 |
| ||
Fishing and rental |
| 16,111 |
| 13,451 |
| ||
Depreciation and amortization |
| 39,976 |
| 29,614 |
| ||
General and administrative |
| 67,732 |
| 52,064 |
| ||
Interest expense, net of amounts capitalized |
| 10,040 |
| 9,348 |
| ||
(Gain) loss on sale of assets |
| (266 | ) | 250 |
| ||
Interest income |
| (508 | ) | (1,940 | ) | ||
Other expense (income), net |
| 877 |
| (624 | ) | ||
|
|
|
|
|
| ||
Total costs and expenses, net |
| 399,492 |
| 324,225 |
| ||
|
|
|
|
|
| ||
Income before income taxes |
| 56,907 |
| 84,694 |
| ||
Income tax expense |
| (22,457 | ) | (32,504 | ) | ||
Minority interest |
| 34 |
| — |
| ||
|
|
|
|
|
| ||
NET INCOME |
| $ | 34,484 |
| $ | 52,190 |
|
|
|
|
|
|
| ||
EARNINGS PER SHARE: |
|
|
|
|
| ||
Basic |
| $ | 0.27 |
| $ | 0.40 |
|
Diluted |
| $ | 0.27 |
| $ | 0.39 |
|
|
|
|
|
|
| ||
WEIGHED AVERAGE SHARES OUTSTANDING: |
|
|
|
|
| ||
Basic |
| 127,966 |
| 131,629 |
| ||
Diluted |
| 129,307 |
| 133,915 |
|
See the accompanying notes which are an integral part of these condensed consolidated unaudited financial statements
4
Key Energy Services, Inc.
Condensed Consolidated Statements of Operations
(In thousands, except per share data)
(Unaudited)
|
| Three Months Ended September 30, |
| Nine Months Ended September 30, |
| ||||||||
|
| 2007 |
| 2006 |
| 2007 |
| 2006 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
REVENUES: |
|
|
|
|
|
|
|
|
| ||||
Well servicing |
| $ | 311,304 |
| $ | 323,655 |
| $ | 931,289 |
| $ | 884,962 |
|
Pressure pumping |
| 77,112 |
| 69,038 |
| 228,478 |
| 181,035 |
| ||||
Fishing and rental services |
| 25,551 |
| 24,907 |
| 73,629 |
| 71,596 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Total revenues |
| 413,967 |
| 417,600 |
| 1,233,396 |
| 1,137,593 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
COSTS AND EXPENSES: |
|
|
|
|
|
|
|
|
| ||||
Well servicing |
| 193,151 |
| 185,486 |
| 545,983 |
| 536,000 |
| ||||
Pressure pumping |
| 49,357 |
| 37,305 |
| 143,299 |
| 97,764 |
| ||||
Fishing and rental services |
| 14,974 |
| 14,610 |
| 41,934 |
| 42,318 |
| ||||
Depreciation and amortization |
| 31,185 |
| 30,192 |
| 91,483 |
| 85,930 |
| ||||
General and administrative |
| 56,569 |
| 43,624 |
| 164,787 |
| 142,042 |
| ||||
Interest expense |
| 7,914 |
| 10,410 |
| 26,231 |
| 29,017 |
| ||||
Loss (gain) on sale of assets, net |
| 2,398 |
| (817 | ) | 1,945 |
| (3,062 | ) | ||||
Interest income |
| (1,851 | ) | (1,841 | ) | (5,589 | ) | (3,868 | ) | ||||
Other, net |
| 438 |
| (191 | ) | 326 |
| 280 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Total costs and expenses, net |
| 354,135 |
| 318,778 |
| 1,010,399 |
| 926,421 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Income before income taxes |
| 59,832 |
| 98,822 |
| 222,997 |
| 211,172 |
| ||||
Income tax expense |
| (23,936 | ) | (37,937 | ) | (86,775 | ) | (80,641 | ) | ||||
|
|
|
|
|
|
|
|
|
| ||||
NET INCOME |
| $ | 35,896 |
| $ | 60,885 |
| $ | 136,222 |
| $ | 130,531 |
|
|
|
|
|
|
|
|
|
|
| ||||
EARNINGS PER SHARE: |
|
|
|
|
|
|
|
|
| ||||
Basic |
| $ | 0.27 |
| $ | 0.46 |
| $ | 1.03 |
| $ | 0.99 |
|
Diluted |
| $ | 0.27 |
| $ | 0.45 |
| $ | 1.02 |
| $ | 0.97 |
|
|
|
|
|
|
|
|
|
|
| ||||
WEIGHTED AVERAGE SHARES OUTSTANDING: |
|
|
|
|
|
|
|
|
| ||||
Basic |
| 131,738 |
| 131,291 |
| 131,665 |
| 131,322 |
| ||||
Diluted |
| 133,808 |
| 134,187 |
| 133,955 |
| 134,564 |
|
See the accompanying notes which are an integral part of these condensed consolidated unaudited financial statements
5
Key Energy Services, Inc. and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income
(In thousands)
(Unaudited)
|
| Three Months Ended March 31, |
| ||||
|
| 2008 |
| 2007 |
| ||
|
|
|
|
|
| ||
NET INCOME |
| $ | 34,484 |
| $ | 52,190 |
|
|
|
|
|
|
| ||
OTHER COMPREHENSIVE LOSS, NET OF TAX: |
|
|
|
|
| ||
|
|
|
|
|
| ||
Foreign currency translation loss |
| (548 | ) | (169 | ) | ||
Deferred loss from cash flow hedges |
| — |
| (123 | ) | ||
Deferred loss from short-term investments |
| (7 | ) | (198 | ) | ||
|
|
|
|
|
| ||
COMPREHENSIVE INCOME, NET OF TAX |
| $ | 33,929 |
| $ | 51,700 |
|
See the accompanying notes which are an integral part of these condensed consolidated unaudited financial statements
5
Key Energy Services, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows
(In thousands)
(Unaudited)
|
| Three Months Ended September 30, |
| Nine Months Ended September 30, |
| ||||||||
|
| 2007 |
| 2006 |
| 2007 |
| 2006 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
NET INCOME |
| $ | 35,896 |
| $ | 60,885 |
| $ | 136,222 |
| $ | 130,531 |
|
OTHER COMPREHENSIVE INCOME (LOSS), NET |
|
|
|
|
|
|
|
|
| ||||
OF TAX: |
|
|
|
|
|
|
|
|
| ||||
Foreign currency translation loss |
| (921 | ) | (66 | ) | (920 | ) | (168 | ) | ||||
Net deferred (loss) gain from cash flow hedges |
| (510 | ) | (838 | ) | (435 | ) | 256 |
| ||||
Deferred gain (loss) from available for sale investments |
| 16 |
| 54 |
| (189 | ) | 54 |
| ||||
COMPREHENSIVE INCOME, NET OF TAX |
| $ | 34,481 |
| $ | 60,035 |
| $ | 134,678 |
| $ | 130,673 |
|
|
| Three Months Ended March 31, |
| ||||
|
| 2008 |
| 2007 |
| ||
|
|
|
|
|
| ||
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
| ||
Net income |
| $ | 34,484 |
| $ | 52,190 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
| ||
Minority interest |
| (34 | ) | — |
| ||
Depreciation and amortization |
| 39,976 |
| 29,614 |
| ||
Accretion of asset retirement obligations |
| 173 |
| 131 |
| ||
Income from equity method investment in IROC Energy Services Corp |
| (4 | ) | (556 | ) | ||
Amortization of deferred financing costs and discount |
| 542 |
| 428 |
| ||
Deferred income tax (benefit) expense |
| (110 | ) | 3,292 |
| ||
Capitalized interest |
| (1,658 | ) | (844 | ) | ||
(Gain) loss on sale of assets, net |
| (266 | ) | 250 |
| ||
Stock-based compensation |
| 2,913 |
| 2,391 |
| ||
Excess tax benefits from stock-based compensation |
| (108 | ) | — |
| ||
Changes in working capital: |
|
|
|
|
| ||
Accounts receivable, net |
| (13,040 | ) | (13,650 | ) | ||
Stock-based compensation liability awards |
| (1,225 | ) | — |
| ||
Other current assets |
| (4,179 | ) | (3,272 | ) | ||
Accounts payable, accrued interest and accrued expenses |
| 14,054 |
| 19,395 |
| ||
Other assets and liabilities |
| (1,207 | ) | (2,519 | ) | ||
|
|
|
|
|
| ||
Net cash provided by operating activities |
| 70,311 |
| 86,850 |
| ||
|
|
|
|
|
| ||
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
| ||
Capital expenditures - Well Servicing |
| (25,895 | ) | (26,791 | ) | ||
Capital expenditures - Pressure Pumping |
| (1,857 | ) | (13,576 | ) | ||
Capital expenditures - Fishing and Rental |
| (1,406 | ) | (4,006 | ) | ||
Capital expenditures - Other |
| (1,217 | ) | (2,002 | ) | ||
Proceeds from sale of fixed asssets |
| 2,088 |
| 265 |
| ||
Acquisitions, net of cash acquired |
| (993 | ) | — |
| ||
Acquisition of intangible asset |
| (1,086 | ) | — |
| ||
Cash paid for short-term investments |
| — |
| (83,077 | ) | ||
Proceeds received from sale of short-term investments |
| — |
| 18,635 |
| ||
|
|
|
|
|
| ||
Net cash used in investing activities |
| (30,366 | ) | (110,552 | ) | ||
|
|
|
|
|
| ||
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
| ||
Repayments of long-term debt |
| — |
| (1,000 | ) | ||
Repayments of capital lease obligations |
| (3,006 | ) | (2,591 | ) | ||
Repurchases of common stock |
| (65,376 | ) | — |
| ||
Proceeds from exercise of stock options |
| 353 |
| — |
| ||
Proceeds paid for debt issuance costs |
| (314 | ) | — |
| ||
Excess tax benefits from stock-based compensation |
| 108 |
| — |
| ||
|
|
|
|
|
| ||
Net cash used in financing activities |
| (68,235 | ) | (3,591 | ) | ||
|
|
|
|
|
| ||
Effect of exchange rates on cash |
| (342 | ) | (370 | ) | ||
|
|
|
|
|
| ||
Net decrease in cash and cash equivalents |
| (28,632 | ) | (27,663 | ) | ||
Cash and cash equivalents, beginning of period |
| 58,503 |
| 88,375 |
| ||
Cash and cash equivalents, end of period |
| $ | 29,871 |
| $ | 60,712 |
|
See the accompanying notes which are an integral part of these condensed consolidated unaudited financial statements
6
Key Energy Services, Inc.
Condensed Consolidated Statements of Cash Flows
(In thousands)
(Unaudited)
|
| Nine Months Ended September 30, |
| ||||
|
| 2007 |
| 2006 |
| ||
|
|
|
|
|
| ||
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
| ||
|
|
|
|
|
| ||
Net income |
| $ | 136,222 |
| $ | 130,531 |
|
|
|
|
|
|
| ||
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
| ||
Depreciation and amortization |
| 91,483 |
| 85,930 |
| ||
Accretion expense |
| 389 |
| 369 |
| ||
(Income) loss from equity investment |
| (270 | ) | 193 |
| ||
Amortization of deferred debt issuance costs |
| 1,329 |
| 1,207 |
| ||
Deferred income tax expense |
| 10,041 |
| 7,026 |
| ||
Capitalized interest |
| (3,543 | ) | (2,570 | ) | ||
Loss (gain) on sale of assets |
| 1,945 |
| (3,062 | ) | ||
Stock-based compensation |
| 9,076 |
| 5,014 |
| ||
|
|
|
|
|
| ||
Changes in working capital: |
|
|
|
|
| ||
Accounts receivable |
| (23,611 | ) | (58,331 | ) | ||
Other current assets |
| (17,780 | ) | 635 |
| ||
Accounts payable, accrued interest and accrued expenses |
| (14,507 | ) | 45,815 |
| ||
|
|
|
|
|
| ||
Other assets and liabilities |
| (551 | ) | (18,701 | ) | ||
|
|
|
|
|
| ||
Net cash provided by operating activities |
| 190,223 |
| 194,056 |
| ||
|
|
|
|
|
| ||
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
| ||
|
|
|
|
|
| ||
Capital expenditures - Well Servicing |
| (100,904 | ) | (107,517 | ) | ||
Capital expenditures - Pressure Pumping |
| (44,969 | ) | (25,856 | ) | ||
Capital expenditures - Fishing and Rental |
| (16,364 | ) | (11,053 | ) | ||
Capital expenditures - Other |
| (5,586 | ) | (2,579 | ) | ||
Proceeds from sale of fixed assets |
| 3,284 |
| 10,122 |
| ||
Acquisitions, net of cash acquired of $628 |
| (5,982 | ) | — |
| ||
Investment in available for sale securities |
| (98,446 | ) | (61,883 | ) | ||
Proceeds from the sale of available for sale securities |
| 50,035 |
| 31,163 |
| ||
|
|
|
|
|
| ||
Net cash used in investing activities |
| (218,932 | ) | (167,603 | ) | ||
|
|
|
|
|
| ||
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
| ||
|
|
|
|
|
| ||
Repayment of long-term debt |
| (4,463 | ) | (3,000 | ) | ||
Repayments under capital lease obligations |
| (8,335 | ) | (9,670 | ) | ||
Repayments on line of credit facility |
| (447 | ) | — |
| ||
Purchase of treasury stock |
| (702 | ) | (1,180 | ) | ||
|
|
|
|
|
| ||
Net cash used in financing activities |
| (13,947 | ) | (13,850 | ) | ||
|
|
|
|
|
| ||
Effect of exchange rates on cash |
| 17 |
| (633 | ) | ||
|
|
|
|
|
| ||
Net (decrease) increase in cash and cash equivalents |
| (42,639 | ) | 11,970 |
| ||
Cash and cash equivalents, beginning of period |
| 88,375 |
| 94,170 |
| ||
Cash and cash equivalents, end of period |
| $ | 45,736 |
| $ | 106,140 |
|
See the accompanying notes which are an integral part of these condensed consolidated unaudited financial statements
7
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED UNAUDITED FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIESGENERAL
The Company
Key Energy Services, Inc. is a Maryland corporation that was organized in April 1977 and commenced operations in July 1978 underits wholly owned subsidiaries (collectively, the name National Environmental Group, Inc. We emerged from a prepackaged bankruptcy plan in December 1992 as Key Energy Group, Inc. On December 9, 1998, we changed our name to Key Energy Services, Inc. (“Key” or the “Company”). We believe that we are now the leading onshore, rig-based well servicing contractor in the United States. From 1994 through 2002, we grew rapidly through a series of over 100 acquisitions,“Company,” “we,” “us,” “its,” and today we provide“our”) provides a complete range of well services to major oil companies and independent oil and natural gas production companies, including rig-based well maintenance, workover, well completion, and recompletion services, oilfield transportation services, cased-hole electric wireline services and ancillary oilfieldpressure pumping services, fishing and rental services, and pressure pumpingancillary oilfield services. During 2006 and through the third quarter of 2007, Key conducted well servicing operations onshore in the continental United States in the following regions: Gulf Coast (including South Texas, Central Gulf Coast of Texas and South Louisiana), Permian Basin of West Texas and Eastern New Mexico, Mid-Continent (including the Anadarko, Hugoton and Arkoma Basins and the ArkLaTex and North Texas regions), Four Corners (including the San Juan, Piceance, Uinta, and Paradox Basins), the Appalachian Basin, Rocky Mountains (including the Denver-Julesberg, Powder River, Wind River, Green River and Williston Basins), and California (the San Joaquin Basin), and internationally in Argentina and Mexico. During the first quarter of 2007, we were awarded a contract by PEMEX to provide well servicing activities in the Northern region of Mexico. Operations in Mexico commenced in the second quarter of 2007. In September 2007, we acquired Advanced Measurements, Inc. (“AMI”), a privately-held Canadian technology company. We also provide limited onshore drilling services in the Rocky Mountains, the Appalachian Basin and in Argentina. We conduct pressure pumping and cementing operations in a number of major domestic producing basins including California, the Permian Basin, the San Juan Basin, the Mid-Continent region, and in the Barnett Shale of North Texas. Our fishing and rental services are located primarily in the Gulf Coast and Permian Basin regions of Texas, as well as in California and the Mid-Continent region.
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements were prepared using generally accepted accounting principles in this report have beenthe United States of America (“GAAP”) for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). The condensed December 31, 2007 balance sheet was prepared from audited financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007. Certain information relating to the Company’s organization and footnote disclosures normally included in financial statements prepared in accordance with the instructions for interim financial reporting prescribed by the SEC. The December 31, 2006 year-endGAAP have been condensed consolidated balance sheet data was derived from audited financial statements but does not include all the disclosures required by GAAP.or omitted in this Quarterly Report on Form 10-Q. These interimunaudited condensed consolidated financial statements should be read togetherin conjunction with the audited consolidated financial statements and notes thereto included in ourthe Company’s Annual Report on Form 10-K for the year ended December 31, 2006.2007.
The unaudited condensed consolidated financial statements contained in this report include all material adjustments that, in the opinion of management, are necessary for a fair statement of the financial position, results of operations and cash flows for the interim periods presented herein. The results of operations for the interim periods presented in this reportthree months ended March 31, 2008 are not necessarily indicative of the results to be expected for the full year or any other interim period due to fluctuations in demand for our services, timing of maintenance and other expenditures, and other factors.
2. SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES
The preparation of these consolidated financial statements requires us to develop estimates and to make assumptions that affect our financial position, results of operations and cash flows. These estimates also impact the nature and extent of our disclosure, if any, of our contingent liabilities. Among other things, we use estimates to (1)(i) analyze assets for possible impairment, (2)(ii) determine depreciable lives for our assets, (3)(iii) assess future tax exposure and realization of deferred tax assets, (4)(iv) determine amounts to accrue for contingencies, (5)(v) value tangible and intangible assets, and (6)(vi) assess workers’ compensation, vehicular liability, self-insured risk accruals and other insurance reserves. Our actual results may differ materially from these estimates. We believe that our estimates are reasonable.
Certain reclassifications
The Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 159, “The Fair Value Option for Financial Assets and Liabilities, including an amendment of FASB Statement No. 115” (“SFAS 159”), on January 1, 2008. SFAS 159 permits companies to choose, at specified election dates, to measure eligible items at fair value (the “Fair Value Option”). Companies choosing such an election report unrealized gains and losses on items for which the Fair Value Option has been elected in earnings at each subsequent reporting period. We did not elect to measure any of our financial assets or liabilities using the Fair Value Option. We will assess at each measurement date whether to use the Fair Value Option on any future financial assets or liabilities as permitted pursuant to the provisions of SFAS 159.
There have been madeno material changes or developments in the Company’s evaluation of accounting estimates and underlying assumptions or methodologies that the Company believes to prior period amountsbe Critical Accounting Policies and Estimates as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2007.
3. NEW ACCOUNTING STANDARDS
SFAS 157. In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which is intended to conformincrease consistency and comparability in fair value measurements by defining fair value, establishing a framework for measuring fair value, and expanding disclosures about fair value measurements. SFAS 157 applies to current periodother accounting pronouncements that require or permit fair value measurements and is effective for financial statement presentation. These reclassifications primarily relatestatements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years.
In February 2008, the FASB issued FASB Staff Position FAS 157-2 (“FSP FAS 157-2”). FSP FAS 157-2 delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal
7
years, for non-financial assets and liabilities, except for items that are recognized or disclosed at fair value in the registrant’s
financial statements on a recurring basis. The adoption of SFAS 157, as modified by FSP FAS 157-2, did not have a material impact on our financial position, results of operations, or cash flows.
SFAS 141(R). In December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (“SFAS 141(R)”). SFAS 141(R) will significantly change the accounting for business combinations. Under SFAS 141(R), an acquiring entity will be required to recognize all the assets and liabilities assumed in a transaction at the acquisition-date fair value, with limited exceptions. Specific changes in SFAS 141(R) from previously issued guidance include:
· Acquisition costs will generally be expensed as incurred;
· Noncontrolling interests will be valued at fair value at the acquisition date;
· Certain acquired contingent liabilities will be recorded at fair value at the acquisition date and subsequently remeasured at either the higher of such amount or the amount determined under existing guidance for non-acquired contingencies;
· In-process research and development will be recorded at fair value as an indefinite-lived intangible asset at the acquisition date;
· Restructuring costs associated with a business combination will generally be expensed subsequent to the recastingacquisition date; and
· Changes in deferred tax asset valuation allowances and income tax uncertainties after the acquisition date generally will affect income tax expense.
SFAS 141(R) also includes new disclosure requirements related to business combinations. This statement applies to all business combinations for which the acquisition date is on or after the beginning of prior periodsthe first annual reporting period beginning on or after December 15, 2008, and earlier adoption is prohibited. The impact of the adoption of this standard on the Company’s financial position, results of operations, and cash flows will not be known until the Company completes a business combination subsequent to conformthe adoption date of this standard.
SFAS 160. In December 2007 the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements: an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 establishes new accounting and reporting standards for the noncontrolling interest (formerly referred to as “minority interests”) in a subsidiary and for the deconsolidation of a subsidiary. Specifically, this statement requires the recognition of a noncontrolling interest as equity in the consolidated financial statements and separate from the parent’s equity. The amount of net income attributable to a realignmentnoncontrolling interest will be included in consolidated net income on the face of certain positionsthe income statement. SFAS 160 clarifies that were previously reportedchanges in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, SFAS 160 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. Such gains or loss will be measured using the fair value of the noncontrolling equity investment on the deconsolidation date. SFAS 160 also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interest. SFAS 160 is effective for fiscal years and interim periods within those fiscal years, beginning on or after December 15, 2008, with early adoption prohibited. The Company is in the process of determining the impact the adoption of this standard will have on the Company’s financial position, results of operations and cash flows.
SFAS 161. In March 2008, the FASB issued SFAS No. 161, “Disclosure about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 requires more disclosures about an entity’s derivative and hedging activities in order to improve the transparency of financial reporting. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. This Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. We will adopt the provisions of SFAS 161 on January 1, 2009. The Company currently has no financial instruments that qualify as derivatives, and we do not expect that the adoption of this standard will have a componentmaterial impact on the Company’s financial position, results of direct expenses thatoperations, and cash flows.
4. ACQUISITIONS
The Company has acquired businesses consistent with its long-term growth strategy. Results of operations for acquisitions are now reported as generalincluded in the unaudited condensed consolidated statements of operations from the date of acquisition. The balances included in the unaudited condensed consolidated balance sheets related to acquisitions made during the third and administrative. These reclassifications had no effect on previously reported net income. The following tables summarize the effects of these reclassifications on previously reported amounts (in thousands):
8
|
| Three Months Ended September 30, 2006 |
| |||||||
|
| Amounts as Previously Reported |
| Effect of Reclassifications |
| Amounts as Currently Reported |
| |||
|
|
|
|
|
|
|
| |||
Well servicing costs |
| $ | 189,078 |
| $ | (3,592 | ) | $ | 185,486 |
|
Pressure pumping costs |
| 38,541 |
| (1,236 | ) | 37,305 |
| |||
Fishing and rental costs |
| 15,672 |
| (1,062 | ) | 14,610 |
| |||
General and administrative |
| 37,734 |
| 5,890 |
| 43,624 |
| |||
Total |
| $ | 281,025 |
| $ | — |
| $ | 281,025 |
|
|
| Nine Months Ended September 30, 2006 |
| |||||||
|
| Amounts as Previously Reported |
| Effect of Reclassifications |
| Amounts as Currently Reported |
| |||
|
|
|
|
|
|
|
| |||
Well servicing costs |
| $ | 547,006 |
| $ | (11,006 | ) | $ | 536,000 |
|
Pressure pumping costs |
| 101,130 |
| (3,366 | ) | 97,764 |
| |||
Fishing and rental costs |
| 45,174 |
| (2,856 | ) | 42,318 |
| |||
General and administrative |
| 124,814 |
| 17,228 |
| 142,042 |
| |||
Total |
| $ | 818,124 |
| $ | — |
| $ | 818,124 |
|
We apply the provisionsfourth quarters of EITF Issue 04-10, “Determining Whether to Aggregate Operating Segments That Do Not Meet Quantitative Thresholds” (“EITF 04-10”) in our segment reporting in Note 10—“Segment Information.” Our contract drilling operations do not meet the quantitative thresholds as described in Statement of Financial Accounting Standards No. 131, “Disclosures About Segments of an Enterprise and Related Information” (“SFAS 131”), and, under the provisions of EITF 04-10, since the operating segments meet the aggregation criteria, we have combined information about this segment with other similar segments that individually do not meet the quantitative thresholds in our Well Servicing reportable segment.
Principles of Consolidation
Within our consolidated financial statements, we include our accounts2007 and the accountsfirst quarter of our majority-owned or controlled subsidiaries. We eliminate intercompany accounts2008 are based on preliminary information and transactions. We accountare subject to change when final asset valuations are obtained and the potential for our interest in entitiesliabilities has been evaluated. Acquisitions are accounted for which we do not have significant control or influence under the cost method. When we have an interest in an entity and can exert significant influence but not control, we account for that interest using the equity method. See Note 6—“Investment in IROC Energy Services Corp.”
In determining whether we should consolidate an entity within our financial statements, we applypurchase method of accounting and the provisions of FASB Interpretation No. 46 (as amended), “Consolidation of Variable Interest Entities” (“FIN 46R”). FIN 46R requires that an equity investor in a variable interest entity have significant equitypurchase price is allocated to the net assets acquired based upon their estimated fair values at risk and hold a controlling interest, evidenced by voting rights, and absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected returns, or both. If the equity investor is unable to evidence these characteristics, the entity that retains these ownership characteristics is required to consolidate the variable interest entities created or obtained after March 15, 2004.
As further discussed in Note 2 — “Acquisitions,” on September 5, 2007, we acquired all the outstanding shares of AMI, a privately-held Canadian company. On the date of acquisition, AMIacquisition. Final valuations of assets and liabilities are obtained and recorded as soon as practicable and within one year from the date of the acquisition.
On January 17, 2008, the Company purchased the fishing and rental assets of Tri-Energy Services, LLC (“Tri-Energy”), for approximately $1.9 million in cash. These assets were integrated into our Fishing and Rental segment. The equity interests of Tri-Energy were owned a 48% interestby employees of the Company who joined the Company in another privately-held Canadian company, Advanced Flow Technologies, Inc. (“AFTI”). InOctober 2007 in connection with the acquisition weof Moncla Well Service, Inc. and related entities. The purchase price was allocated to the assets purchased and the acquisition of Tri-Energy did not result in the establishment of goodwill.
On September 5, 2007, the Company acquired Advanced Measurements, Inc., which operates in Canada and is a technology company focused on oilfield service equipment controls, data acquisition, and digital information flow. The purchase price was $6.6 million in cash and $2.9 million in assumed debt and was paid in September 2007. The purchase price is subject to a working capital adjustment mechanism which was settled in February 2008 and resulted in additional consideration paid of approximately $0.9 million. This also resulted in additional goodwill of $0.9 million.
On October 25, 2007, the Company acquired Moncla Well Service, Inc. and related entities which operate well service rigs, barges, and ancillary equipment in the southeastern United States. During the three months ended March 31, 2008, the Company refined its fair value allocation of the net assets acquired by decreasing working capital by $0.7 million with a corresponding increase to goodwill in the unaudited condensed consolidated balance sheet as of March 31, 2008.
On December 7, 2007, the Company acquired the well service assets and related equipment of Kings Oil Tools, Inc., a California-based well service company. During the three months ended March 31, 2008, the Company revised its fair value allocation of the net assets acquired by increasing the fair value of the well service assets acquired by $1.5 million, decreased the fair value of working capital accounts by $0.1 million, and paid additional fees related to the closing of the transaction of $0.1 million. These changes were requiredoffset with a corresponding net decrease to exercise an option that increased AMI’s ownershipgoodwill in the unaudited condensed consolidated balance sheet as of AFTI to 51.46%. As a result, we now consolidate AFTI intoMarch 31, 2008.
5. SUPPLEMENTAL FINANCIAL INFORMATION
The table below presents the comparative detailed financial information of current accrued liabilities at March 31, 2008 and December 31, 2007.
|
| March 31, 2008 |
| December 31, |
| ||
|
| (in thousands) |
| ||||
Current accrued liabilities: |
|
|
|
|
| ||
Accrued payroll, taxes, and employee benefits |
| $ | 55,408 |
| $ | 56,744 |
|
Accrued operating expenditures |
| 53,826 |
| 52,180 |
| ||
Income, sales, use and other taxes |
| 42,198 |
| 35,310 |
| ||
Self-insurance reserves |
| 23,572 |
| 25,208 |
| ||
Unsettled legal claims |
| 8,284 |
| 6,783 |
| ||
Phantom share liability |
| 1,118 |
| 2,458 |
| ||
Deferred revenue |
| 328 |
| 976 |
| ||
Other |
| 3,201 |
| 3,705 |
| ||
Total |
| $ | 187,935 |
| $ | 183,364 |
|
The table below presents the comparative detailed financial information of our financial statements, with the remaining 48.54% representing a minority interest.other non-current accrued liabilities at March 31, 2008 and December 31, 2007.
9
|
| March 31, 2008 |
| December 31, |
| ||
|
| (in thousands) |
| ||||
Non-current accrued liabilities: |
|
|
|
|
| ||
Asset retirement obligations |
| $ | 9,235 |
| $ | 9,298 |
|
Environmental liabilities |
| 2,863 |
| 3,090 |
| ||
Accrued rent |
| 2,746 |
| 2,829 |
| ||
Accrued income taxes |
| 2,705 |
| 2,705 |
| ||
Phantom share liability |
| 1,011 |
| 896 |
| ||
Other |
| 590 |
| 713 |
| ||
Total |
| $ | 19,150 |
| $ | 19,531 |
|
The table below presents the comparative supplemental cash flow information for the three months ended March 31, 2008 and 2007:
|
| Three Months Ended March 31, |
| ||||
|
| 2008 |
| 2007 |
| ||
|
| (in thousands) |
| ||||
Supplemental cash flow information: |
|
|
|
|
| ||
Cash paid for interest |
| $ | 2,432 |
| $ | 6,835 |
|
Cash paid for taxes |
| 1,095 |
| 6,130 |
| ||
Cash paid for interest includes cash payments for interest on our long-term debt and capital lease obligations and commitment and agency fees paid.
Revenue Recognition6.GOODWILL AND OTHER INTANGIBLE ASSETS
The changes in the carrying amount of goodwill for the three months ended March 31, 2008 are as follows:
|
| Well Servicing |
| Pressure |
| Fishing and |
| Total |
| ||||
|
| (in thousands) |
| ||||||||||
|
|
|
|
|
|
|
|
|
| ||||
December 31, 2007 |
| $ | 311,744 |
| $ | 47,905 |
| $ | 18,901 |
| $ | 378,550 |
|
Purchase price and other adjustments, net |
| 221 |
| — |
| — |
| 221 |
| ||||
Foreign currency translation |
| (178 | ) | — |
| — |
| (178 | ) | ||||
March 31, 2008 |
| $ | 311,787 |
| $ | 47,905 |
| $ | 18,901 |
| $ | 378,593 |
|
10
The components of our intangible assets are as follows:
|
| March 31, 2008 |
| December 31, |
| ||
|
| (in thousands) |
| ||||
|
|
|
|
|
| ||
Noncompete agreements: |
|
|
|
|
| ||
Gross carrying value |
| $ | 18,342 |
| $ | 18,402 |
|
Accumulated amortization |
| (3,765 | ) | (2,772 | ) | ||
Net carrying value |
| $ | 14,577 |
| $ | 15,630 |
|
|
|
|
|
|
| ||
Patents and trademarks: |
|
|
|
|
| ||
Gross carrying value |
| $ | 4,126 |
| $ | 4,150 |
|
Accumulated amortization |
| (2,686 | ) | (2,526 | ) | ||
Net carrying value |
| $ | 1,440 |
| $ | 1,624 |
|
|
|
|
|
|
| ||
Customer relationships: |
|
|
|
|
| ||
Gross carrying value |
| $ | 26,225 |
| $ | 25,139 |
|
Accumulated amortization |
| (3,754 | ) | (1,649 | ) | ||
Net carrying value |
| $ | 22,471 |
| $ | 23,490 |
|
|
|
|
|
|
| ||
Customer backlog: |
|
|
|
|
| ||
Gross carrying value |
| $ | 744 |
| $ | 999 |
|
Accumulated amortization |
| (108 | ) | (214 | ) | ||
Net carrying value |
| $ | 636 |
| $ | 785 |
|
|
|
|
|
|
| ||
Developed technology: |
|
|
|
|
| ||
Gross carrying value |
| $ | 5,644 |
| $ | 4,762 |
|
Accumulated amortization |
| (1,095 | ) | (397 | ) | ||
Net carrying value |
| $ | 4,549 |
| $ | 4,365 |
|
Certain of our intangible assets are denominated in currencies other than U.S. Dollars and as such the values of those assets are subject to fluctuations associated with changes in exchange rates. Additionally, certain of these assets are also subject to purchase accounting adjustments. The estimated fair value of intangible assets obtained through acquisitions consummated in the preceding twelve months are based on preliminary information which is subject to change when final valuations are obtained. Amortization expense for our intangible assets was $3.8 million and $0.7 million for the three months ended March 31, 2008 and 2007, respectively.
7. INVESTMENT IN IROC ENERGY SERVICES CORP.
Well Servicing Rigs. Well servicing revenue consists primarily
As of maintenanceMarch 31, 2008 and December 31, 2007, we owned 8,734,469 shares of IROC Energy Services Corp., formerly known as IROC Systems Corp. (“IROC”), an Alberta-based oilfield services workover services, completion servicescompany. This represented approximately 19.7% of IROC’s outstanding common stock on March 31, 2008 and pluggingDecember 31, 2007. IROC shares trade on the Toronto Venture Stock Exchange and abandonment services. had a closing price of $0.80 CDN and $0.74 CDN per share on March 31, 2008 and December 31, 2007, respectively. Mr. William Austin, our Chief Financial Officer, and Mr. Newton W. Wilson III, our General Counsel, serve on the board of directors of IROC.
We recognize revenue when serviceshave significant influence over the operations of IROC through our ownership interest and representation on IROC’s board of directors, but we do not control it. We account for our investment in IROC using the equity method. Our investment in IROC totaled $10.6 million and $11.2 million as of March 31, 2008 and December 31, 2007, respectively. The pro-rata share of IROC’s earnings and losses to which we are entitled is recorded in our condensed consolidated statements of operations as a component of other income and expense, with an offsetting increase or decrease to the value of our investment, as appropriate. Any earnings distributed back to us from IROC in the form of dividends would result in a decrease in the value of our equity investment.
We recorded less than $0.1 million and $0.6 million of income related to our investment in IROC for the three months ended March 31, 2008 and 2007, respectively. During those time periods, no earnings were distributed back to us by IROC in the form of dividends.
11
An impairment review of our equity method investment in IROC is performed collectionon a quarterly basis to determine if there has been a decline in fair value that is other than temporary. The fair value of the relevant receivableasset is probable, persuasive evidencemeasured using quoted market prices or, in the absence of quoted market prices, fair value is based on an arrangement existsestimate of discounted cash flows. In determining whether the decline is other than temporary, we consider the cyclicality of the industry in which the investment operates, its historical performance, its performance in relation to its peers and the current economic environment. Future conditions in the industry, operating performance and performance in relation to peers and the future economic environment may vary from our current assessment of recoverability. Such future conditions could therefore result in a determination that a decline in fair value is other than temporary. IROC’s stock price is fixed or determinable. These criteriacurrently depressed, and as such the fair value of the Company’s investment is less than the amount reflected in the Company’s consolidated financial statements. If we later determine that the decline is other than temporary, we would record a write-down in the carrying value of our asset to the then current fair market value.
8. LONG-TERM DEBT
The components of our long-term debt are typically met atas follows:
|
| March 31, 2008 |
| December 31, |
| ||
|
| (in thousands) |
| ||||
|
|
|
|
|
| ||
8.375% Senior Notes due 2014 |
| $ | 425,000 |
| $ | 425,000 |
|
Senior Secured Credit Facility revolving loans due 2012 |
| 50,000 |
| 50,000 |
| ||
Notes payable - related party, net of discount of $286 and $322 |
| 22,214 |
| 22,178 |
| ||
Capital lease obligations |
| 25,004 |
| 26,815 |
| ||
|
| 522,218 |
| 523,993 |
| ||
Less current portion |
| (11,613 | ) | (12,379 | ) | ||
Total long-term debt and capital lease obligations, net of fair value discount |
| $ | 510,605 |
| $ | 511,614 |
|
Senior Secured Credit Facility
The Company maintains a revolving credit agreement with a syndicate of banks of which Bank of America Securities LLC and Wells Fargo Bank, N.A. are the time we complete a jobAdministrative Agents (“Senior Secured Credit Facility”). The aggregate lending commitment of this facility is $400.0 million and allows for a customer. Primarily, we price well servicing rig services bycombination of borrowings and issuances of letters of credit. There were borrowings of $50.0 million and outstanding letters of credit $61.1 million under the hour of service performed. DependingSenior Secured Credit Facility at March 31, 2008. The weighted-average interest rate on the type of job, we may charge by the project or by the day.
Oilfield Transportation. Oilfield transportation revenue consists primarily of fluid and equipment transportation services and frac tanks which are used in conjunction with fluid hauling services. We recognize revenue when services are performed, collectionoutstanding borrowings of the relevant receivable is probable, persuasive evidenceSenior Secured Credit Facility was 4.17125% at March 31, 2008. The Senior Secured Credit Facility requires the Company to maintain a consolidated interest coverage ratio of an arrangement existsat least 3.0 to 1.0, maintain a consolidated leverage ratio of not more than 3.5 to 1.0, and the price is fixed or determinable. These criteria are typically metto not exceed capital expenditures of $250.0 million in any fiscal year. The Company was in compliance with these covenants at the time we complete a job for a customer. Primarily, we price oilfield trucking services by the hour or by the quantities hauled.March 31, 2008.
Pressure Pumping and Fishing and Rental Services. Pressure pumping and fishing and rental services include well stimulation and cementing services and recovering lost or stuck equipment in the wellbore. We recognize revenue when services are performed, collection of the relevant receivable is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. These criteria are typically met at the time we complete a job for a customer. Generally, we price fishing and rental tool services by the day and pressure pumping services by the job.
Ancillary Oilfield Services. Ancillary oilfield services include services such as wireline operations, wellsite construction, roustabout services, foam units and air drilling services. We recognize revenue when services are performed, collection of the relevant receivable is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. These criteria are typically met at the time we complete a job for a customer. We price ancillary oilfield services by the hour, day or project depending on the type of services performed.
Cash and Cash Equivalents
We consider short-term investments with an original maturity of less than three months to be cash equivalents. None of our cash is restricted and we have not entered into any compensating balance arrangements. However, at September 30, 2007, all of ourAll obligations under the Senior Secured Credit Facility (hereinafter defined) wereare guaranteed by most of our subsidiaries and are secured by most of our assets, including assets held by our subsidiaries, which includes our cashaccounts receivable, inventory and cash equivalents. We restrict investment of cash to financial institutions with high credit standing and limit the amount of credit exposure to any one financial institution.equipment.
Investment in Debt and Equity Securities9. INCOME TAXES
We accountThe Company’s effective tax rate for investments in debtthe three months ended March 31, 2008 and equity securities under2007 was 39.5 % and 38.4%, respectively. The primary difference between the provisionsstatutory rate of Statement of Financial Accounting Standards No. 115, “Accounting for Certain Investments in Debt35% and Equity Securities” (“SFAS 115”). Under SFAS 115, investments are classified as either “trading,” “available for sale,” or “heldour effective tax rate relates to maturity,” depending on management’s intent regarding the investment.state and foreign taxes.
Securities classified as “trading” are carried at fair value on the Company’s Consolidated Balance Sheets, with any unrealized holding gains or losses reported currently in earnings on our Consolidated Statements of Operations. Securities classified as “available for sale” are carried at fair value on the Company’s Consolidated Balance Sheets, with any unrealized holding gains or losses, net of tax, reported as a separate component of shareholders’ equity in Accumulated Other Comprehensive Income.
As of September 30, 2007March 31, 2008 and December 31, 2006,2007, we had approximately $6.9 million and $6.8 million, respectively, of unrecognized tax benefits, net of federal tax benefit, which, if recognized, would impact our effective tax rate. We are subject to U.S. Federal Income Tax as well as income taxes in multiple state and foreign jurisdictions. We have substantially concluded all U.S. federal and state tax matters through the Company had no investments in debt or equity securities that were classified as “trading” or “held to maturity.” In the third quarter of 2006, the Company began investing in Auction-Rate Securities (“ARS”) and Variable-Rate Demand Notes (“VRDN”). These are investments in long-term bonds whose returns are tied to short-term interest rates that are periodically reset, with periods ranging from 7 days to 6 months. As a result of the long-term nature of the underlying security (bonds with contractual lives ranging from 20 to 30 years), the Company accounts for ARS and VRDN investments as “available for sale” securities. Because the Company can liquidate its position in an ARS or VRDN investment at par on an interest reset date, and because management does not intend to hold these investments beyond one year they are classified as current assets in our Consolidated Balance Sheets.ended December 31, 2002.
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In additionWe recognize accrued interest expense and penalties related to unrecognized tax benefits as income tax expense. We have accrued approximately $2.5 million and $2.3 million for the ARSpayment of interest and VRDN investments, in the third quarter of 2006 the Company began to invest in 270-day commercial paper and certain other bond investments. These instruments are treated as “available for sale” securities and are carried at fair value as marketable securities on the Company’s Consolidated Balance Sheets, because their maturity dates are within one year of the date of investment. Any unrealized holding gains or losses on these securities are recorded net of tax as a separate component of stockholders’ equity in Accumulated Other Comprehensive Income until the date of maturity, at which point any gains or losses are reclassified into earnings. We use the specific identification method when determining the amount of realized gain or loss upon the date of maturity. The aggregate fair value of our available for sale investmentspenalties as of September 30, 2007 was approximately $110.2 million.
Accounts Receivable
In AugustMarch 31, 2008 and September of 2007, our Argentina subsidiary factored certain of its accounts receivable in order to improve that subsidiary’s working capital position. Five invoices with a total aggregate amount of $3.1 million were factored with recourse to us. Fees of less than $0.1 million were paid on the factored receivables on net 30 days terms. The invoices were factored in order to cover a short-term working capital shortage resulting from retroactive salary increases paid to union employees in Argentina.December 31, 2007. We do not anticipate factoring additional receivables inexpect any substantial changes within the future.
Inventories
Inventories, which consist primarily of equipment parts for use in our well servicing operations, sand and chemicals for our pressure pumping operations, and supplies held for consumption, are valued at the lower of average cost or market.
Property and Equipment
Asset Retirement Obligations. In connection with our well servicing activities, we operate a number of Salt Water Disposal (“SWD”) facilities. Our operations involve the transportation, handling and disposal of fluids in our SWD facilities that have been determined to be harmful to the environment. SWD facilities used in connection with our fluid hauling operations are subject to future costs associated with the abandonment of these properties. As a result, we have incurred costs associated with the proper storage and disposal of these materials. In accordance with Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), we recognize a liability for the fair value of all legal obligations associated with the retirement of tangible long-lived assets and capitalize an equal amount as a cost of the asset. We depreciate the additional cost over the estimated useful life of the assets. Significant judgment is involved in estimating future cash flows associated with such obligations, as well as the ultimate timing of those cash flows. If our estimates of the amount or timing of the cash flows change, such changes may have a material impact on our results of operations. Amortization of the assets associated with the asset retirement obligations was $0.1 million and $0.1 million for the quarters ended September 30, 2007, and 2006, respectively. Amortization of the assets associated with the asset retirement obligations was $0.4 million and $0.4 million for the ninenext 12 months ended September 30, 2007, and 2006, respectively.
Asset and Investment Impairments. We apply Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”) in reviewing our long-lived assets and investments for possible impairment. This statement requires that long-lived assets held and used by us, including certain identifiable intangibles, be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. For purposes of applying this statement, we group our long-lived assets on a division-by-division basis and compare the estimated future cash flows of each division to the division’s net carrying value. The division level represents the lowest level for which identifiable cash flows are available. We would record an impairment charge, reducing the division’s net carrying value to an estimated fair value, if its estimated future cash flows were less than the division’s net carrying value. “Trigger events,” as defined in SFAS 144, that cause us to evaluate our fixed assets for recoverability and possible impairment may include market conditions, such as adverse changes in the prices of oil and natural gas, which could reduce the fair value of certain of our property and equipment. The development of future cash flows and the determination of fair value for a division involves significant judgment and estimates. As of September 30, 2007 and December 31, 2006, no trigger events had been identified by management.
Change in Useful Lives. In the first quarter of 2007, management reassessed the estimated useful lives assigned to all of its equipment due to the higher activity and utilization levels experienced under recent market conditions. As a result, the maximum estimated useful lives of certain assets were adjusted to reflect higher utilization. Included in this change is a reduction in the useful life expected for a well service rig, which was reduced from an average expected life of 17 years to 15
11
years. Management also determined that the life assigned to a self-remanufactured well service rig should be the same as the 15 year life assigned to a newly constructed well service rig acquired from third parties.
The following table identifies the impact of this change in depreciation and amortization expense for the three and nine months ended September 30, 2007 (in thousands):
|
| Three Months Ended September 30, 2007 |
| Nine Months Ended September 30, 2007 |
| ||
Depreciation and amortization expense using prior lives |
| $ | 29,819 |
| $ | 86,005 |
|
Impact of change |
| 1,366 |
| 5,478 |
| ||
Depreciation and amortization expense, as reported |
| $ | 31,185 |
| $ | 91,483 |
|
|
|
|
|
|
| ||
Diluted earnings per share using prior lives |
| $ | 0.28 |
| $ | 1.06 |
|
Impact of change on diluted earnings per share |
| (0.01 | ) | (0.04 | ) | ||
Diluted earnings per share, as reported |
| $ | 0.27 |
| $ | 1.02 |
|
As a result of the change, the estimated useful lives of the Company’s asset classes are as follows:
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
Goodwill and Other Intangible Assets
Goodwill results from business acquisitions and represents the excess of acquisition costs over the fair value of the net assets acquired. We account for goodwill and other intangible assets under the provisions of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). SFAS 142 eliminates amortization for goodwill and other intangible assets with indefinite lives. Intangible assets with lives restricted by contractual, legal, or other means will continue to be amortized over their expected useful lives. Goodwill and other intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. SFAS 142 requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the fair value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination. The amount of impairment for goodwill is measured as the excess of its carrying value over its fair value. We conduct annual impairment assessments, the most recent affecting this report as of December 31, 2006. The assessments did not result in an indication of goodwill impairment.
Our intangible assets subject to amortization under SFAS 142 consist of noncompete agreements and patents and trademarks. Amortization expense for noncompete agreements is calculated using the straight-line method over the period of the agreement, ranging from three to seven years. The cost and accumulated amortization are retired when the noncompete agreement is fully amortized and no longer enforceable. Amortization expense for patents and trademarks is calculated using the straight-line method over the useful life of the patent or trademark, ranging from five to seven years. Amortization of noncompete agreements for the quarters ended September 30, 2007 and 2006 was $0.5 million and $0.5 million, respectively. Amortization of patents and trademarks for the quarters ended September 30, 2007 and 2006 was $0.2 million and $0.1 million, respectively. Amortization of noncompete agreements for the nine months ended September 30, 2007 and 2006 was $1.3 million and $1.7 million, respectively. Amortization of patents and trademarks for the nine months ended September 30, 2007 and 2006 was $0.6 million and $0.4 million, respectively. During the nine months ended September 30, 2007, the Company capitalized approximately $0.5 million of costs associated with patents and trademarks. During the nine months ended September 30, 2007, the Company capitalized approximately $1.8 million related to a two-year noncompete agreementuncertain tax positions.
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During the first quarter of 2008, the Company applied approximately $14.5 million of the income tax refund receivable due as of December 31, 2007 against the Company’s current income taxes payable. No cash refund was received by the Company.
10. COMMITMENTS AND CONTINGENCIES
Litigation. Various suits and claims arising in the ordinary course of business are pending against us. Due to locations where we conduct business in the continental United States, we are often subject to jury verdicts and arbitration hearings that result in outcomes in favor of the plaintiffs. We do not believe that the disposition of any of these matters will result in a material adverse impact on our consolidated financial position, results of operations or cash flows.
Gonzales Matter. In September 2005, a class action lawsuit, Gonzales v. Key Energy Services, Inc., was filed in Ventura County, California Superior Court, alleging that Key did not pay its hourly employees for travel time between the yard and the wellhead and that certain employees were denied meal and rest periods between shifts. We have recorded a liability for this matter and do not expect that the conclusion of this matter will have a material impact on our financial position, results of operations, or cash flows.
Litigation with Former Officers and Employees. We were named in a lawsuit by our former general counsel, Jack D. Loftis, Jr., filed in the U.S. District Court, District of New Jersey on April 21, 2006, in which he alleges a “whistle-blower” claim under the Sarbanes-Oxley Act, breach of contract, breach of good faith and fair dealing, breach of fiduciary duty, and wrongful termination. On August 17, 2007, the Company filed counterclaims against Mr. Loftis alleging attorney malpractice, breach of contract, and breach of fiduciary duties. In its counterclaims, the Company seeks repayment of all severance paid to Mr. Loftis to date (approximately $0.8 million) plus benefits paid during the period July 8, 2004 to September 21, 2004, and damages relating to the allegations of malpractice and breach of fiduciary duties. The case was transferred to and is now pending in the U.S. District Court for the Eastern District of Pennsylvania.
On September 3, 2006, our former controller and assistant controller filed a joint complaint against the Company in the 133rd District Court, Harris County, Texas, alleging constructive termination and breach of contract. Additionally, on January 11, 2008, our former Chief Operating Officer, James Byerlotzer, filed a lawsuit in the 55th District Court, Harris County, Texas, alleging breach of contract based on his inability to exercise his stock options during the period that Key was not current in its SEC filings, and based on Key’s failure to provide him shares of restricted stock.
We are vigorously defending against these claims; however, we cannot predict the outcome of the lawsuits.
Shareholder Class Action Suits and Derivative Actions. Since June 2004, we and certain of our officers and directors were named as a defendant in six class action complaints for alleged violations of federal securities laws, which were filed in federal district court in Texas. These six actions were consolidated into one action. Four shareholder derivative actions were filed, purportedly on our behalf. On September 7, 2007, we reached agreements in principle to settle all pending securities class action and derivative lawsuits in consideration of payments totaling $16.6 million in exchange for full and complete releases for all defendants, of which Key will be required to pay approximately $1.1 million. We received final approval of the settlement of the shareholder class action claims by the court on March 6, 2008 and preliminary court approval on the derivative actions on April 18, 2008. Final approval on the derivative action is anticipated to occur in the third quarter of 2008. We have recorded an appropriate liability for this matter.
Expired Option Holders. On September 24, 2007, Belinda Taylor, on behalf of herself and all similarly situated residents of Texas, filed a lawsuit in the 11th Judicial District of Harris County, Texas, alleging that the Company breached its contracts with current and former employees who held vested options that expired between April 28, 2004 and the date that the Company became current in its financial statements (the “Expired Option Holders”). The suit also alleges the Company breached its fiduciary duties and duties of good faith and fair dealing in the pricing of stock options it granted to those Expired Option Holders, based upon the alleged overstatement of assets prior to the Company’s restatement. Ms. Taylor amended her lawsuit on September 25, 2007, to include all Expired Option Holders, regardless of residence. On March 6, 2008, the parties agreed to settle all pending claims with all Expired Option Holders, excluding those terminated for cause and those who have previously filed suits against Key, for approximately $1.0 million, which includes all taxes and legal fees, and we have recorded a liability in the amount of the settlement for this matter. The settlement agreement is subject to court approval, which is expected to occur in the third quarter of 2008.
Automobile Accident Litigation. On August 22, 2007, one of our employees was involved in an automobile accident that resulted in a third party fatality. A lawsuit arising from this accident is currently pending in Jasper County, Texas. We are vigorously defending against the claims in the lawsuit; however, at this time we cannot predict the outcome of the lawsuit. Mediation is expected to occur in June 2008. We have recorded an appropriate liability for this matter.
13
Tax Audits. We are routinely the subject of audits by tax authorities and have received some material assessments from tax auditors. As of December 31, 2007 and March 31, 2008, we have recorded reserves that management feels are appropriate for future potential liabilities as a result of these audits. While we believe we have fully reserved for these assessments, the ultimate amount of settlements can vary from our estimates. In connection with our former Chief Executive Officer. Through September 30,Egyptian operations, which terminated in 2005, we are undergoing income tax audits for all periods in which we had operations. As of March 31, 2008, the Company had recorded a liability of approximately $0.4 million relating to open Egyptian tax audits. In the fourth quarter of 2007, amortizationthe Company reached a preliminary settlement with the Egyptian tax authorities on the 2003 and 2004 tax years, recording a tax benefit of this noncompete agreement was$0.7 million and reducing the tax liability accrued at December 31, 2007 to approximately $0.2$0.4 million.
Self-Insurance Reserves. We maintain reserves for workers’ compensation and vehicle liability on our balance sheet based on our judgment and estimates using an actuarial method based on claims incurred. We estimate general liability claims on a case-by-case basis. We maintain insurance policies for workers’ compensation, vehicle liability and general liability claims. These insurance policies carry self-insured retention limits or deductibles on a per occurrence basis. The retention limits or deductibles are accounted for in our accrual process for all workers’ compensation, vehicular liability and general liability claims. As further discussed in Note 2 — “Acquisitions,” in connection with our acquisition of AMI in SeptemberMarch 31, 2008 and December 31, 2007, we have recorded $66.2 million and $69.0 million, respectively, of self-insurance reserves related to workers’ compensation, vehicular liabilities and general liability claims. Partially offsetting these liabilities, we had approximately $9.4 million and $8.1 million of insurance receivables as of March 31, 2008 and December 31, 2007, respectively.
Environmental Remediation Liabilities. For environmental reserve matters, including remediation efforts for current locations and those relating to previously-disposed properties, we record liabilities when our remediation efforts are probable and the costs to conduct such remediation efforts are reasonably estimated. Environmental reserves do not reflect management’s assessment of the insurance coverage that may apply to these matters at issue, if such coverage is available, whereas our litigation reserves do reflect the application of our insurance coverage. As of March 31, 2008 and December 31, 2007, we have recorded $2.9 million and $3.1 million, respectively, for our environmental remediation liabilities.
We provide performance bonds to provide financial surety assurances for the remediation and maintenance of our Salt Water Disposal (“SWD”) properties to comply with environmental protection standards. Costs for SWD properties may be mandatory (to comply with applicable laws and regulations), in the future (required to divest or cease operations), or for optimization (to improve operations, but not for safety or regulatory compliance).
Argentina Payroll Matters. Our Argentinean subsidiary, Key Energy Services S.A., had previously underpaid social security contributions to the Administración Federal de Ingressos Públicos (“AFIP”) as a result of applying an incorrect rate in the calculation of our obligations. Additionally, we also underpaid AFIP as a result of our incorrect use of food stamp equivalents provided to employees as compensation. The correct amounts have been reflected in these financial statements. On May 31, 2007, we paid AFIP $3.5 million, representing the cumulative amount of goodwillunderpayment and $7.2interest. As a result of our underpayment, AFIP imposed fines and penalties against us and began an audit of our filings made to them in prior years. In March 2008, we received notification from AFIP that the audit was complete with respect to this matter and that no additional monies were due.
11. SHARE REPURCHASE PROGRAM
On October 26, 2007, the Company’s Board of Directors authorized a share repurchase program, in which the Company may spend up to $300.0 million to repurchase shares of its common stock on the open market. The program expires at the end of the first quarter of 2009. At March 31, 2008, the Company had $202.6 million of specifically identifiable intangibles subjectavailability under the share repurchase program to amortization under SFAS 142. Amortizationrepurchase shares of these assets for the three and nine months ended September 30, 2007 was less than $0.1 million.
Derivative Instruments and Hedging Activities
The Company applies Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) as amended by Statement of Financial Accounting Standards No. 137, No. 138 and No. 149 (“SFAS 137,” “SFAS 138,” and “SFAS 149,” respectively; collectively, “SFAS 133, as amended”) in accounting for derivative instruments. SFAS 133, as amended establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. It requires the recognition of all derivative instruments as assets and liabilitiesits common stock on the balance sheet and measurementopen market. During the first quarter of those instruments2008, the Company repurchased an aggregate of approximately 5.2 million shares at fair value. The accounting treatmenta total cost of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge, and if so, the type of hedge. For derivatives designated as cash flow hedges, the effective portion of the change inapproximately $65.3 million, which represents the fair market value of the hedging instrument is recognized in other comprehensive income untilshares based on the hedged item is recognized in earnings. Any ineffective portion of changes in the fair valueprice of the hedging instrument is recognized currently in earnings.
To account for a derivative financial instrument as a hedge,Company’s stock on the contract must meet the following criteria: the underlying asset or liability must expose the Company to risk that is not offset in another asset or liability, the hedging contract must reduce that risk, and the instrument must be properly designated as a hedge atdates of purchase. Since the inception of the contract and throughout the contract period. To beprogram in November 2007 through March 31, 2008, we have repurchased an effective hedge, there must beaggregate of approximately 7.5 million shares for a high correlation between changes in the fair valuetotal cost of the financial instrument and the fair value of the underlying asset or liability, such that changes in the market value of the financial instrument and the anticipated future cash flows would be offset by the effect of price changes on the exposed items.
In March 2006, under$97.4 million. Under the terms of our Senior Secured Credit Facility, the Company was requiredwe are limited to mitigatestock repurchases of $200 million if our consolidated debt to capitalization ratio, as defined in the risk of changes in future cash flows posed by changes in interest rates associated with the variable-rate interest term loan portion of our Senior Secured Credit Facility. We entered into two interest rate swap arrangementsFacility, is in order to offset this risk. The swaps are classified as derivative instruments and were designated at inception as cash flow hedges. Management believes that these instruments were highly effective at inception to offset changes in the future cash flowsexcess of the underlying liabilities and will continue to be highly effective throughout the life50%. As of the hedge. See Note 4—“Derivative Financial Instruments” for further discussion.
In connection with our acquisition of AMI in September 2007 (see Note 2 — “Acquisitions”), we became party to four swap arrangements that exchanged Singaporean Dollars (“SGD”) for Canadian Dollars (“CDN”). These agreements meet the definition of a derivative under SFAS 133 and as such will be recorded at fair value onMarch 31, 2008, our consolidated balance sheet. We have not electeddebt to treat these derivatives as cash flow hedges, and as a result, any gains or losses arising out of changes in the fair value of these contracts will be recorded as unrealized gains or losses in our statements of operations as a part of other income and expense. See Note 4—“Derivative Financial Instruments” for further discussion.capitalization ratio was less than 50%.
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Earnings Per Share12. EARNINGS PER SHARE
We present earnings per share information in accordance with the provisions of Statement of Financial Accounting StandardsSFAS No. 128, “Earnings Per Share” (“SFAS 128”). Under SFAS 128, basic earnings per common share is determined by dividing net earnings applicable to common stock by the weighted average number of common shares actually outstanding during the period. Diluted earnings per common share is based on the increased number of shares that would be outstanding assuming conversion of dilutive outstanding convertible securities using the “as if converted” method.
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|
| Three Months Ended March 31, |
| ||||
|
| 2008 |
| 2007 |
| ||
|
| (in thousands, except per share data) |
| ||||
|
|
|
|
|
| ||
Basic Earnings per Share Computation: |
|
|
|
|
| ||
Numerator |
|
|
|
|
| ||
Net income |
| $ | 34,484 |
| $ | 52,190 |
|
|
|
|
|
|
| ||
Denominator |
|
|
|
|
| ||
Weighted average shares outstanding |
| 127,966 |
| 131,629 |
| ||
|
|
|
|
|
| ||
Basic earnings per share |
| $ | 0.27 |
| $ | 0.40 |
|
|
|
|
|
|
| ||
Diluted Earnings per Share Computation: |
|
|
|
|
| ||
Numerator |
|
|
|
|
| ||
Net income |
| $ | 34,484 |
| $ | 52,190 |
|
|
|
|
|
|
| ||
Denominator |
|
|
|
|
| ||
Weighted average shares outstanding |
| 127,966 |
| 131,629 |
| ||
Dilutive effect from stock options |
| 580 |
| 1,717 |
| ||
Dilutive effect from unvested restricted stock |
| 269 |
| — |
| ||
Dilutive effect from warrants |
| 492 |
| 569 |
| ||
|
| 129,307 |
| 133,915 |
| ||
|
|
|
|
|
| ||
Diluted earnings per share |
| $ | 0.27 |
| $ | 0.39 |
|
|
| Three Months Ended September 30, |
| Nine Months Ended September 30, |
| |||||||||
|
| 2007 |
| 2006 |
| 2007 |
| 2006 |
| |||||
|
| (in thousands, except per share data) |
| |||||||||||
|
|
|
|
|
|
|
|
|
| |||||
Basic EPS Computation: |
|
|
|
|
|
|
|
|
| |||||
Numerator |
|
|
|
|
|
|
|
|
| |||||
Net income |
| $ | 35,896 |
| $ | 60,885 |
| $ | 136,222 |
| $ | 130,531 |
| |
|
|
|
|
|
|
|
|
|
| |||||
Denominator |
|
|
|
|
|
|
|
|
| |||||
Weighted average shares outstanding |
| 131,738 |
| 131,291 |
| 131,665 |
| 131,322 |
| |||||
|
|
|
|
|
|
|
|
|
| |||||
Basic earnings per share |
| $ | 0.27 |
| $ | 0.46 |
| $ | 1.03 |
| $ | 0.99 |
| |
|
|
|
|
|
|
|
|
|
| |||||
Diluted EPS Computation: |
|
|
|
|
|
|
|
|
| |||||
Numerator |
|
|
|
|
|
|
|
|
| |||||
Net income |
| $ | 35,896 |
| $ | 60,885 |
| $ | 136,222 |
| $ | 130,531 |
| |
|
|
|
|
|
|
|
|
|
| |||||
Denominator |
|
|
|
|
|
|
|
|
| |||||
Weighted average shares outstanding |
| 131,738 |
| 131,291 |
| 131,665 |
| 131,322 |
| |||||
Stock options |
| 1,436 |
| 2,356 |
| 1,689 |
| 2,688 |
| |||||
Warrants |
| 562 |
| 540 |
| 577 |
| 554 |
| |||||
Stock appreciation rights |
| 72 |
| — |
| 24 |
| — |
| |||||
|
| 133,808 |
| 134,187 |
| 133,955 |
| 134,564 |
| |||||
|
|
|
|
|
|
|
|
|
| |||||
Diluted earnings per share |
| $ | 0.27 |
| $ | 0.45 |
| $ | 1.02 |
| $ | 0.97 |
| |
The diluted earnings per share calculation for the quarters ended September 30,March 31, 2008 and 2007 and 2006 excludesexclude the potential exercise of 44,5001.9 million and 776,00018,000 stock options at weighted-average exercise prices of $14.63 and $16.25, respectively, because the effects of such exercises on earnings per share in those periods would be anti-dilutive. The diluted earnings per share calculation for the nine months ended September 30, 2007 and 2006 excludes the potential exercise of 27,500 and 258,667 stockThese options respectively, because the effects of such exercises on earnings per share in those periods would be anti-dilutive.
Stock-Based Compensation
We account for stock-based compensation underanti-dilutive because their exercise prices were higher than the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123(R)”), which we adopted on January 1, 2006. Prior to January 1, 2006, we accounted for share-based payments under the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”), which was permitted by Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). We adopted the provisions of SFAS 123(R) using the modified prospective transition method.
Beginning in June 2005 we began making grants of shares of common stock to certain of our employees and non-employee directors. These shares have vesting periods ranging from zero to three years. Subject to the provisions of SFAS 123(R), the Company recognizes expense in earnings equal to the fair value of the shares vesting during the period, net of actual and estimated forfeitures.
In December 2006, the Company began granting “Phantom Shares” to certain of its employees, which vest ratably over a four-year period from the date of grant. The Phantom Shares convey the right to the grantee to receive a cash payment on each anniversary date of the grant equal to the fair market value of the Phantom Shares vesting on that date. Grantees are not permitted to defer the payout to a later date. The Phantom Shares qualify as a “liability” type award under SFAS 123(R); as such, the Company accounts for the Phantom Shares at fair value, with an offsetting liability recorded on our Consolidated Balance Sheets. Changes in the fair value of the liability, net of estimated and actual forfeitures, are recorded currently in earnings as compensation expense.
14
In August 2007, the Company issued stock appreciation rights (“SARs”) to all of its executive officers. Each SAR award has a ten-year term from the date of grant and vests in equal annual installments on the first, second and third anniversaries of the date of grant. Upon the exercise of an SAR, the recipient will receive an amount equal to the difference between the exerciseaverage price and the fair market value of a share of the Company’s common stock onduring the date of exercise multiplied by the number of shares of common stock for which the SAR was exercised. All payments will be made in shares of the Company’s common stock. Prior to exercise, the SAR does not entitle the recipient to receive any shares of the Company’s common stockthree month periods ended March 31, 2008 and does not provide the recipient with any voting or other stockholder rights. The Company accounts for the SARs as equity awards under SFAS 123(R) and recognizes compensation expense ratably over the vesting period of the SAR based on its fair value on the date of issuance, net of estimated and actual forfeitures.
Foreign Currency Gains and Losses
The local currency is the functional currency for our foreign operations in Argentina, Canada and Mexico. The cumulative translation gains and losses, resulting from translating each foreign subsidiary’s financial statements from the functional currency to U.S. dollars, are included as a separate component of stockholders’ equity in other comprehensive income until a partial or complete sale or liquidation of our net investment in the foreign entity.
New Accounting Pronouncements
FIN No. 48 and FSP FIN 48-1.On July 12, 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109” (“FIN 48”), which provides clarification of SFAS 109, “Accounting for Income Taxes” with respect to the recognition of income tax benefits of uncertain tax positions in the financial statements. FIN 48 requires that uncertain tax positions be reviewed and assessed, with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard.
In May 2007, the FASB issued FASB Staff Position No. FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48” (“FSP FIN 48-1”). FSP FIN 48-1 provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. In determining whether a tax position has been effectively settled, entities must evaluate (i) whether taxing authorities have completed their examination procedures; (ii) whether the entity intends to appeal or litigate any aspect of a tax position included in a completed evaluation; and (iii) whether it is remote that a taxing authority would examine or re-examine any aspect of a taxing position. FSP FIN 48-1 is to be applied upon the initial adoption of FIN 48.
We adopted the provisions of FIN 48 and FSP FIN 48-1 on January 1, 2007 and recorded a $1.3 million decrease to the balance of our retained earnings as of January 1, 2007 to reflect the cumulative effect of adopting these standards. See Note 3—“Income Taxes” for further discussion of the impact of the adoption of these standards.
FSP EITF 00-19-2. In December 2006, the FASB issued FASB Staff Position No. EITF 00-19-2, “Accounting for Registration Payment Arrangements” (“FSP EITF 00-19-2”). FSP EITF 00-19-2 addresses accounting for Registration Payment Arrangements (“RPAs”), which are provisions within financial instruments such as equity shares, warrants or debt instruments in which the issuer agrees to file a registration statement and to have that registration statement declared effective by the SEC within a specified grace period. If the registration statement is not declared effective within the grace period or its effectiveness is not maintained for the period of time specified in the RPA, the issuer must compensate its counterparty. The FASB Staff concluded that the contingent obligation to make future payments or otherwise transfer consideration under a RPA should be recognized as a liability and measured in accordance with SFAS 5 and FASB Interpretation No. 14, “Reasonable Estimation of the Amount of a Loss,” and that the RPA should be recognized and measured separately from the instrument to which the RPA is attached.
In January 1999, the Company completed the private placement of 150,000 units (the “Units”) consisting of $150.0 million of 14% Senior Subordinated Notes due January 25, 2009 (the “14% Senior Subordinated Notes”) and 150,000 warrants to purchase an aggregate of approximately 2.2 million shares of the Company’s common stock at an exercise price of $4.88125 per share (the “Warrants”). As of September 30, 2007, 63,500 Warrants had been exercised, leaving 86,500 Warrants outstanding that were exercisable for an aggregate of approximately 1.3 million shares.
Under the terms of the Warrants, we are required to maintain an effective registration statement covering the shares of common stock issuable upon exercise. If we are unable to maintain an effective registration statement, we are required to make semiannual liquidated damages payments for periods in which an effective registration statement is not maintained. Due to our past failure to file our SEC reports in a timely manner, we do not have an effective registration statement covering the Warrants, and have been required to make liquidated damages payments, and will continue to be required to make those payments until such time as we have an effective registration statement on file for exercise of the Warrants or the warrant
15
shares issuable thereunder are eligible for resale without registration pursuant to SEC Rule 144 or otherwise. The requirement to make liquidated damages payments constitutes an RPA under the provisions of FSP EITF 00-19-2. As prescribed by the transition provisions of FSP EITF 00-19-2, on January 1, 2007, the Company recorded a current liability of approximately $1.0 million on its balance sheet, which is equivalent to the payments for the Warrant RPA for one year, and we recorded an offsetting adjustment to the opening balance of retained earnings. This amount represents the low end of a range of possible outcomes. If we continue to be unable to maintain an effective registration statement with the SEC, the total amount of liquidated damages payable under the Warrant RPA during 2007 could be as high as $1.4 million. Any subsequent changes in the carrying value of the RPA liability will be recorded in earnings as other income and expense.
2. ACQUISITIONS
Acquisition of Advanced Measurements, Inc.
On September 5, 2007, the Company, through its wholly-owned Canadian subsidiaries, purchased all of the outstanding shares of AMI, a privately-held Canadian technology company focused on oilfield service equipment controls, data acquisition, and digital information work flow. We made this acquisition in order to improve our access to oilfield services technology.
The purchase price was approximately $6.6 million in cash and approximately $3.1 million of assumed debt, which was repaid in September and November 2007. The purchase agreement also provided for deferred cash payments of up to $1.78 million related to the retention of key AMI employees. These deferred payments will be expensed as incurred.
On the date of acquisition, AMI owned a 48% interest in AFTI, a privately-held Canadian technology company focused on low cost wireless gas well production monitoring. This 48% interest was transferred to us as part of the purchase. In addition, as part of the purchase of AMI we were required to exercise an option to increase AMI’s interest in AFTI to 51.46%. The cost to exercise this option was approximately $0.5 million. As a result, AMI now owns a 51.46% interest in AFTI, and as such we consolidate AFTI into our financial statements, with the remaining 48.54% representing a minority interest.
The following table summarizes the preliminary estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition (in thousands of USD):
Cash. |
| $ | 628 |
|
Other current assets |
| 2,881 |
| |
Property and equipment |
| 555 |
| |
Goodwill |
| 3,522 |
| |
Intangible assets |
| 7,241 |
| |
Other assets |
| 1,013 |
| |
Total assets acquired |
| 15,840 |
| |
|
|
|
| |
Current liabilities |
| 1,559 |
| |
Long-term debt and capital leases |
| 3,118 |
| |
Deferred tax liability |
| 4,219 |
| |
Minority interest |
| 334 |
| |
Total liabilities assumed |
| 9,230 |
| |
Net assets acquired |
| $ | 6,610 |
|
The allocation of purchase price to specific assets and liabilities is based, in part, upon outside appraisals using customary valuation procedures and techniques. The allocation is still preliminary at this time, and may potentially change by a material amount as our purchase accounting is finalized. We anticipate finalizing our allocation of purchase price in the fourth quarter of 2007, once the final tax basis of the assets and liabilities acquired has been determined and our valuation of AMI’s intangible assets is completed.
Goodwill was recognized as part of the acquisition of AMI as the purchase price exceeded the fair value of the acquired assets and liabilities. We believe that the goodwill associated with the AMI acquisition is related to the acquired workforce and was therefore not allocated to the assets and liabilities acquired.
16
All of the $7.2 million of acquired intangible assets is subject to amortization under SFAS 142 and has a weighted-average remaining useful life of approximately 8.7 years. These intangible assets relate primarily to developed technology and customer backlog. The $3.5 million of goodwill associated with the purchase of AMI has been allocated to our Well Servicing segment; of that amount, none is expected to be deductible for income tax purposes.
In connection with our acquisition of AMI, we became party to a revolving credit agreement with a maximum outstanding amount of $0.9 million. As of September 30, 2007, AMI had drawn approximately $0.2 million on this line of credit. In November 2007, we transferred $0.9 million to AMI in order to pay off amounts outstanding under this facility and terminate it, and to provide additional working capital.
Execution of Moncla Stock Purchase Agreement
On September 19, 2007, Key Energy Services, LLC, a Delaware limited liability company and wholly-owned subsidiary of the Company, entered into a stock purchase agreement to acquire Moncla Well Service, Inc. and related entities (“Moncla”). Collectively, the Moncla assets include daylight rigs for well servicing and workovers and twenty-four hour rigs for shallow drilling, sidetracking and deep workovers. In addition, the Moncla companies operate barge rigs, and own rig-up, swab, hot oil and anchor trucks, tubing testing units and rental equipment. The Moncla companies currently operate in Texas, Louisiana, Mississippi, Alabama and Florida.
Under the stock purchase agreement, the purchase price for Moncla was, subject to certain adjustments, $145.0 million, of which $112.5 million would be paid at closing, with the balance consisting of two unsecured notes totaling $22.5 million and the assumption of approximately $10.0 million in long-term debt. The notes payable to the sellers consist of one note in the amount of $12.5 million that would be due and payable in a lump-sum, together with accrued interest, on the second anniversary of the closing. The second note would be payable in annual installments of $2.0 million, plus accrued interest, on each of the first through fifth anniversaries of the closing. Each of the notes would bear interest at the Federal Funds rate adjusted annually on the anniversary date of the closing date. Long-term debt assumed in the acquisition was paid off at closing. In addition, the purchase agreement provides for an earnout of up to $25.0 million over the next five years. The Moncla acquisition closed on October 25, 2007. See Note 11—“Subsequent Events.”
3. INCOME TAXES
The Company’s effective tax rate for the nine months ended September 30, 2007 and 2006 was 38.9% and 38.2%, respectively. The primary difference between the statutory rate of 35% and our effective tax rate relates to state taxes, which increased during 2007 primarily due to the new Texas Margins Tax, which took effect on January 1, 2007.
FIN No. 48 and FSP FIN 48-1.On July 12, 2006, the FASB issued FIN 48, which provides clarification of SFAS 109, “Accounting for Income Taxes” with respect to the recognition of income tax benefits of uncertain tax positions in the financial statements. FIN 48 requires that uncertain tax positions be reviewed and assessed, with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard.
In May 2007, the FASB issued FSP FIN 48-1. FSP FIN 48-1 provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. In determining whether a tax position has been effectively settled, entities must evaluate (i) whether taxing authorities have completed their examination procedures; (ii) whether the entity intends to appeal or litigate any aspect of a tax position included in a completed evaluation; and (iii) whether it is remote that a taxing authority would examine or re-examine any aspect of a taxing position. FSP FIN 48-1 is to be applied upon the initial adoption of FIN 48.
We adopted the provisions of FIN 48 and FSP FIN 48-1 on January 1, 2007 and recorded a $1.3 million decrease to the balance of our retained earnings as of January 1, 2007 to reflect the cumulative effect of adopting these standards. As of January 1, 2007 and September 30, 2007, we had approximately $3.9 million and $4.1 million, respectively, of unrecognized tax benefits, which, if recognized, would impact our effective tax rate. We are subject to U.S. Federal Income Tax as well as income taxes in multiple state and foreign jurisdictions. We have substantially concluded all U.S. federal and state tax matters through the year ended December 31, 2002.
We recognize accrued interest expense and penalties related to unrecognized tax benefits as income tax expense. We have accrued approximately $1.5 million and $1.0 million for the payment of interest and penalties as of September 30,
17
2007 and January 1, 2007, respectively. We do not expect any substantial changes within the next 12 months related to uncertain tax positions.
4. DERIVATIVE FINANCIAL INSTRUMENTS
We are exposed to risks due to potential changes in interest rates associated with the variable-rate interest term loan of our Senior Secured Credit Facility. As of September 30, 2007, our variable-rate interest debt instruments comprised 100% of our total debt, excluding our capital lease obligations. Based on this exposure, and because of provisions contained in our Senior Secured Credit Facility, on March 10, 2006 we entered into two $100.0 million notional amount interest rate swaps to effectively fix the interest rate on a portion of our variable-rate debt. These swaps meet the criteria of derivative instruments.
We account for derivative instruments using the guidance provided by SFAS 133, as amended. SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. It requires the recognition of all derivative instruments as assets and liabilities on the balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge, and if so, the type of hedge. For derivatives designated as cash flow hedges, the effective portion of a change in the fair value of the hedging instrument is recognized in other comprehensive income until the settlement of the forecasted hedged transaction. Any ineffective portion of changes in the fair value of the hedging instrument is recognized currently in earnings.
The Company uses a historic simulation based on regression analysis to assess the effectiveness of the swaps as a hedge of the future cash flows of the forecasted transaction, both on a historical and prospective basis. The simulation regresses the monthly changes in the cash flows associated with the hedging instrument and the hedged item. The results of the regression indicated that the swaps were highly effective in offsetting the future cash flows of the items being hedged and could be reasonably assumed to be highly effective on an ongoing basis. Based on the results of this analysis and the Company’s intent to use the instruments to reduce exposure to changes in future cash flows attributable to interest payments, the Company elected to account for the swaps as cash flow hedges.
The measurement of hedge ineffectiveness is based on a comparison of the cumulative change in the fair value of the actual swap designated as the hedging instrument and the cumulative change in fair value of a perfectly effective hypothetical derivative (“Perfect Hypothetical Derivative”) (as defined in Derivatives Implementation Group Issue G7). The perfectly effective hypothetical swap mimics the terms of the debt with a fixed interest rate assumed to be the same as the hedge instrument. This method of measuring ineffectiveness is known as the “Hypothetical Derivative Method.” Under this method, the actual swap is recorded at fair value on the Company’s Consolidated Balance Sheets and Accumulated Other Comprehensive Income is adjusted to a balance that reflects the lesser of either the cumulative change in the fair value of the actual swap or the cumulative change in the fair value of the Perfect Hypothetical Derivative. The amount of ineffectiveness, if any, is equal to the excess of the cumulative change in the fair value of the actual swap over the cumulative change in the fair value of the Perfect Hypothetical Derivative, and is recorded currently in earnings as a component of other income and expense on the Company’s Consolidated Statements of Income.
As of September 30, 2007, we recorded less than $0.1 million in current assets, less than $0.1 million in current liabilities and $0.3 million in long-term liabilities in our Consolidated Balance Sheets, based on the fair value of our derivative instruments on that date. During the nine months ended September 30, 2007, amounts recorded related to the ineffective portion of our cash flow hedges were less than $0.1 million. No amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows in any of the periods. During the three and nine months ended September 30, 2007, no amounts were reclassified to earnings in connection with forecasted transactions whose occurrence was no longer considered probable.
Foreign Currency Instruments13. SHARE-BASED COMPENSATION
In connection with our acquisitionThe Company recognized employee share-based compensation expense of AMI in September 2007 (see Note 2 — “Acquisitions”), we became party to four swap arrangements that exchanged Singaporean Dollars (“SGD”) for Canadian Dollars (“CDN”). These agreements meet the definition of a derivative under SFAS 133 and as such are recorded at fair value on our Consolidated Balance Sheets. We have not elected to treat these derivatives as cash flow hedges, and as a result, and gains or losses arising out of changes in the fair value of these contracts are recorded as unrealized gains or losses in our Consolidated Statements of Operations as a part of other income and expense.
18
As of September 30, 2007, the aggregate notional amount of these contracts was approximately $0.9 million USD and the aggregate fair value of these contracts was not material. The last of these contracts settle in January 2008. For the three and nine months ended September 30, 2007, the unrealized holding loss associated with these instruments was immaterial.
5. OTHER CURRENT AND NON-CURRENT ACCRUED LIABILITIES:
As of September 30, 2007 and December 31, 2006, the Company’s current accrued liabilities consisted of the following:
|
| September 30, 2007 |
| December 31, 2006 |
| ||
|
| (in thousands) |
| ||||
Accrued payroll, taxes and employee benefits |
| $ | 58,383 |
| $ | 64,876 |
|
Accrued operating expenditures |
| 56,060 |
| 40,150 |
| ||
Income, sales, use and other taxes |
| 29,649 |
| 30,282 |
| ||
Workers’ compensation accrual |
| 14,633 |
| 17,325 |
| ||
Unsettled Legal Claims |
| 7,201 |
| 28,754 |
| ||
Vehicular Insurance |
| 3,874 |
| 3,298 |
| ||
Equity-based compensation |
| 1,417 |
| — |
| ||
Accrued rent |
| 421 |
| 834 |
| ||
Accrued severance |
| 280 |
| 631 |
| ||
Deferred gain on sale-leaseback transactions |
| 159 |
| 159 |
| ||
Other |
| 2,524 |
| 3,261 |
| ||
Total |
| $ | 174,601 |
| $ | 189,570 |
|
|
|
|
|
|
|
As of September 30, 2007 and December 31, 2006, the Company’s other non-current accrued liabilities consisted of the following:
|
| September 30, 2007 |
| December 31, 2006 |
| ||
|
| (in thousands) |
| ||||
Asset retirement obligations |
| $ | 9,113 |
| $ | 9,622 |
|
Evironmental liabilities |
| 2,983 |
| 4,683 |
| ||
Accrued rent |
| 2,939 |
| 3,241 |
| ||
Accrued income taxes |
| 4,140 |
| 2,507 |
| ||
Equity-based compensation |
| 1,477 |
| — |
| ||
Deferred gain on sale-leaseback transactions |
| 603 |
| 722 |
| ||
Severance accruals |
| 73 |
| 234 |
| ||
Other |
| 860 |
| 247 |
| ||
Total |
| $ | 22,188 |
| $ | 21,256 |
|
|
|
|
|
|
|
6. INVESTMENT IN IROC ENERGY SERVICES CORP.
As of September 30, 2007 and December 31, 2006, we owned 8,734,469 shares of IROC Energy Services Corp., formerly known as IROC Systems Corp. (“IROC”), an Alberta-based oilfield services company. This represented approximately 19.7% and 23.0% of IROC’s outstanding common stock on September 30, 2007 and December 31, 2006, respectively. IROC shares trade on the Toronto Venture Stock Exchange and had a closing price of $1.48 CDN and $2.10 CDN per share on September 30, 2007 and December 31, 2006, respectively. Mr. William Austin, our Chief Financial Officer, and Mr. Newton W. Wilson III, our General Counsel, serve on the board of directors of IROC.
19
We have significant influence over the operations of IROC through our ownership interest and representation on IROCs board of directors, but do not control it. We account for our investment in IROC using the equity method. Our ownership interest percentage in IROC declined as a result of IROC issuing additional common stock during the nine months ended September 30, 2007. Our investment in IROC totaled $10.9$3.7 million and $10.7 million as of September 30, 2007 and December 31, 2006, respectively, and is recorded in our Condensed Consolidated Balance Sheets as a component of other non-current assets. The pro-rata share of IROC’s earnings and losses to which we are entitled are recorded in our Condensed Consolidated Statements of Operations as a component of other income and expense, with an offsetting increase or decrease to the value of our investment, as appropriate. Any earnings distributed back to us from IROC in the form of dividends would result in a decrease in the value of our equity investment.
We recorded $0.3 million of income and $0.2 million of loss, respectively, related to our investment in IROC for the nine months ended September 30, 2007 and 2006. During those time periods, no earnings were distributed back to us by IROC in the form of dividends.
7. LONG-TERM DEBT
The components of our long-term debt are as follows:
|
| September 30, |
| December 31, |
| ||
|
| 2007 |
| 2006 |
| ||
|
| (in thousands) |
| ||||
|
|
|
|
|
| ||
Senior Credit Facility term loans |
| $ | 394,000 |
| $ | 396,000 |
|
Capital lease obligations |
| 27,740 |
| 25,794 |
| ||
AMI Credit Facility |
| 191 |
| — |
| ||
|
| 421,931 |
| 421,794 |
| ||
Less: current portion |
| (15,942 | ) | (15,714 | ) | ||
Total long-term debt |
| $ | 405,989 |
| $ | 406,080 |
|
Senior Secured Credit Facility
On July 29, 2005, we entered into a Credit Agreement (the “Senior Secured Credit Facility”). The Senior Secured Credit Facility consists of (i) a revolving credit facility of up to an aggregate principal amount of $65.0 million, which will mature on July 29, 2010, (ii) a senior term loan facility in the original aggregate amount of $400.0 million, which will mature on June 30, 2012, and (iii) a prefunded letter of credit facility in the aggregate amount of $82.3 million, which will mature on July 29, 2010. The revolving credit facility includes a $25.0 million sub-facility for additional letters of credit. The proceeds from the term loan facility, along with cash on hand were used to refinance our then-existing 8.375% Senior Notes due 2013 and our then-existing 6.375% Senior Notes due 2008. The revolving credit facility may be used for general corporate purposes.
Borrowings under the Senior Secured Credit Facility through December 31, 2005 bore interest upon the outstanding principal balance, at the Company’s option, at the prime rate plus a margin of 1.75% or a Eurodollar rate plus a margin of 2.75%. These margins were increased on December 31, 2005 by 0.50% and again on June 30, 2006 by 0.50% because the Company did not meet certain filing targets for our Annual Report on Form 10-K for the year ended December 31, 2003. We were also required to pay certain fees in connection with the credit facilities, including a commitment fee as a percentage of aggregate commitments.
The Senior Secured Credit Facility contains certain covenants, which, among other things, require us to maintain a consolidated leverage ratio (defined generally as the ratio of consolidated total debt to consolidated EBITDA) as follows:
|
| |
|
| |
|
| |
|
| |
|
|
20
The Senior Secured Credit Facility also requires that we maintain a consolidated interest coverage ratio (defined generally as the ratio of consolidated EBITDA to consolidated interest expense) as of the last day of any fiscal quarter, beginning with the fourth fiscal quarter of 2005, of not less than 3.0 to 1.0. Upon the occurrence of certain events of default, such as payment default, our obligations under the Senior Secured Credit Facility may be accelerated.
All obligations under the Senior Secured Credit Facility are guaranteed by most of our subsidiaries and are secured by most of our assets, including our accounts receivable, inventory and equipment.
First Amendment to Senior Secured Credit Facility
On November 3, 2005, we amended the Senior Secured Credit Facility (the “First Amendment”) to increase the amount of capital expenditures allowed under the facility during 2005 and 2006. Under the terms of the First Amendment, we were allowed to make annual capital expenditures of $175.0 million for 2005 and $200.0 million for 2006. Additionally, under certain conditions, up to $25.0 million of the capital expenditure limit, if not spent in the permitted fiscal year, could be carried over for expenditures in the next succeeding fiscal year. Previously under the Senior Secured Credit Facility, we were limited to annual capital expenditures of $150.0 million. No fees were paid in association with the First Amendment.
Second Amendment to Senior Secured Credit Facility
On November 21, 2006, we again amended the Senior Secured Credit Facility (the “Second Amendment”) to (i) allow the Company until July 31, 2007 to file its Annual Report on Form 10-K for the year ended December 31, 2006, quarterly reports for 2005 and 2006, and quarterly reports for 2007 that were then due, and to waive any defaults due to the failure to file compliant SEC reports for prior periods; (ii) reduce the Eurodollar interest rate spread from 3.75% to 2.50% and commitment fees from 0.50% to 0.375%; (iii) increase the limitation on annual capital expenditures through 2009 to $225.0 million; (iv) increase the permitted stock repurchase basket from $50.0 million to $250.0 million and permit repurchases before the Company has made all required SEC filings; (v) increase the permitted acquisitions basket from $50.0 million to $100.0 million; and (vi) eliminate the provision requiring the Company to prepay the term loan with excess cash flow. We paid a total of $0.5 million in fees and other expenses in connection with the Second Amendment.
Third Amendment to Senior Secured Credit Facility
On July 27, 2007, the Company entered into a Third Amendment to our Senior Secured Credit Facility. The amendment (i) eliminated the $100 million limitation on permitted acquisitions; (ii) increased the permitted stock repurchase basket from $250.0 million to $300.0 million; (iii) extended until August 31, 2007, the date by which we were required to file our Annual Report on Form 10-K for the year ended December 31, 2006, and the date by which we were required to file our quarterly reports on Form 10-Q for 2005 and 2006; and (iv) extended until October 31, 2007, the date by which we were required to file our quarterly reports for the periods ending March 31 and June 30, 2007. All of these filings occurred prior to the due dates specified in the Third Amendment. We paid fees associated with the Third Amendment of approximately $1.2 million.
As of September 30, 2007, the Company is in compliance with the debt covenants and had no borrowings under the revolving credit facility of the Senior Secured Credit Facility and had $394.0 million borrowed at three-month Eurodollar rates, plus a margin of 2.50%. The weighted average interest rate on our outstanding debt, excluding our capital lease obligations, was approximately 5.39% as of September 30, 2007. As described above, the Company has interest rate swaps that hedge a portion of the interest rate expense on the term loan.
In connection with the consummation of the Moncla acquisition, one of our wholly-owned subsidiaries granted two unsecured promissory notes to the seller. Additionally, in November 2007, we commenced a private placement offering of up to $400 million of senior notes due 2017, entered into a commitment letter for a new senior secured credit facility, and entered into negotiations to amend our existing Senior Secured Credit Facility. See Note 11 — “Subsequent Events.”
AMI Credit Facility
As discussed in Note 2 — “Acquisitions,” upon our acquisition of AMI, we became party to a $0.9 million line of credit facility that AMI used to fund its working capital requirements prior to the acquisition. As of September 30, 2007, AMI had drawn approximately $0.2 million on this line of credit. On November 1, 2007, we transferred $0.9 million to AMI
21
in order to pay off amounts outstanding under this line of credit facility and to fund future working capital requirements. The Company intends to terminate this facility in the fourth quarter of 2007.
Interest Expense
Interest expense for the three and nine months ended September 30, 2007 and 2006 consisted of the following:
|
| Three Months Ended September 30, |
| ||||
|
| 2007 |
| 2006 |
| ||
|
| (in thousands) |
| ||||
Cash payments |
| $ | 7,919 |
| $ | 9,721 |
|
Commitment and agency fees paid |
| 653 |
| 1,147 |
| ||
Amortization of debt issuance costs |
| 471 |
| 404 |
| ||
Net change in accrued interest |
| 416 |
| 93 |
| ||
Capitalized interest |
| (1,545 | ) | (955 | ) | ||
Total interest expense |
| $ | 7,914 |
| $ | 10,410 |
|
|
| Nine Months Ended September 30, |
| ||||
|
| 2007 |
| 2006 |
| ||
|
| (in thousands) |
| ||||
Cash payments |
| $ | 22,955 |
| $ | 25,785 |
|
Commitment and agency fees paid |
| 2,634 |
| 3,390 |
| ||
Amortization of debt issuance costs |
| 1,329 |
| 1,207 |
| ||
Net change in accrued interest |
| 2,856 |
| 1,205 |
| ||
Capitalized interest |
| (3,543 | ) | (2,570 | ) | ||
Total interest expense |
| $ | 26,231 |
| $ | 29,017 |
|
|
|
|
|
|
|
8. COMMITMENTS AND CONTINGENCIES
Litigation. Various suits and claims arising in the ordinary course of business are pending against us. Due to locations where we conduct business in the continental United States, we are often subject to jury verdicts and arbitration hearings that result in favor of the plaintiffs. We do not believe that the disposition of any of these items will result in a material adverse impact on our consolidated financial position, results of operations or cash flows.
Gonzales Matter. In September 2005 a class action lawsuit, Gonzales v. Key Energy Services, Inc., was filed in Ventura County, California Superior Court alleging that Key did not pay its hourly employees for travel time between the yard and the wellhead and that certain employees were denied meal and rest periods between shifts. We have recorded a liability for this matter and do not expect that the conclusion of this matter will have a material impact on our results of operations, cash flows or financial position.
Litigation with Former Officers and Employees. On April 7, 2006, we delivered a notice to our former chief executive officer, Francis D. John, of our intention to treat his termination of employment effective May 1, 2004, as “for Cause” under his employment agreement with us. In response to the notice, Mr. John filed a lawsuit against us in the U.S. District Court for the Southern District of Texas, Houston Division, on May 19, 2006, in which he alleged, among other things, that we breached stock option agreements and his employment agreement. On June 13, 2006, we filed an answer and counterclaim denying Mr. John’s claims and asserting claims against Mr. John for breach of contract and declaratory judgment including, among other things, a declaration that “Cause” exists under Mr. John’s employment agreement. On June 20, 2007 we settled our litigation with Mr. John for $23 million, which was paid on July 5, 2007.
We have also been named in a lawsuit by our former general counsel, Jack D. Loftis, Jr., filed in the U.S. District Court, District of New Jersey on April 21, 2006, in which he alleges a “whistle-blower” claim under the Sarbanes-Oxley Act, breach of contract, breach of good faith and fair dealing, breach of fiduciary duty, and wrongful termination. Mr. Loftis previously filed his “whistle-blower” claim with the Department of Labor (“DOL”), which found that there was no
22
reasonable cause to believe that we violated the Sarbanes-Oxley Act when we terminated Mr. Loftis and dismissed the complaint. On July 28, and October 2, 2006, Key moved to dismiss the lawsuit for lack of jurisdiction over Key Energy or for lack of venue. On June 28, 2007, the Court denied our motions but on its own motion transferred the case to the U.S. District Court for the Eastern District of Pennsylvania.
On July 6, 2007, we delivered a notice to Mr. Loftis, through his counsel, of our intention to treat his termination of employment effective July 8, 2004 as “for cause” under his employment agreement. On August 17, 2007, the Company filed counterclaims against Mr. Loftis alleging attorney malpractice, breach of contract, and breach of fiduciary duties. In its counterclaims, the Company seeks repayment of all severance paid to Mr. Loftis to date (approximately $0.8 million) plus benefits paid during the period July 8, 2004 to September 21, 2004, as well as damages relating to the allegations of malpractice and breach of fiduciary duties. On September 21, 2007, the Company’s Board of Directors determined that Mr. Loftis should be terminated “for cause” effective July 8, 2004, and further found that his vested and unvested stock options should be deemed expired.
Additionally, on August 21, 2006, our former chief financial officer, Royce W. Mitchell, filed a suit against the Company in 385th District Court, Midland County, Texas alleging breach of contract with regard to alleged bonuses, benefits and expense reimbursements, conditional stock grants and stock options, to which he believes himself entitled; as well as relief under theories of quantum meruit, promissory estoppel, and specific performance. Although there is no scheduling order in the case, discovery is underway. Partial summary judgment motions have been made by both parties, and we are awaiting the court’s decisions. Further, our former controller and assistant controller filed a joint complaint against the Company on September 3, 2006 in 133rd District Court, Harris County, Texas alleging constructive termination and breach of contract. Following Key’s removal of the case to the federal court, constructive termination allegation was dismissed and the parties agreed to a remand of the case back to the state court. Discovery is now ongoing.
We are vigorously defending against these claims; however, we cannot predict the outcome of the lawsuits.
Shareholder Class Action Suits and Derivative Actions. Since June 2004, we have been named as a defendant in six class action complaints for alleged violations of federal securities laws, which have been filed in federal district court in Texas. These six actions have been consolidated into one action. On November 1, 2005, the plaintiffs filed a consolidated amended class action complaint. The complaint generally alleges that we made false and misleading statements and omitted material information from our public statements and SEC reports during the class period in violation of the Securities Exchange Act of 1934, including alleged: (i) overstatement of revenues, net income, and earnings per share, (ii) failure to take write-downs of assets, consisting of primarily idle equipment, (iii) failure to amortize the Company’s goodwill, (iv) failure to disclose that the Company lacked adequate internal controls and therefore was unable to ascertain the true financial condition of the Company, (v) material inflation of the Company’s financial results at all relevant times, (vi) misrepresentation of the value of acquired businesses, and (vii) failure to disclose misappropriation of funds by employees.
Four shareholder derivative actions have been filed by certain of our shareholders. Those actions are filed by individual shareholders purporting to act on our behalf, asserting various claims against the named officer and director defendants. The derivative actions generally allege the same facts as those in the shareholder class action suits. Those suits also allege breach of fiduciary duty, abuse of control, waste of corporate assets, and unjust enrichment by these defendants.
On September 7, 2007, the Company reached agreements in principle to settle all pending securities class action and derivative lawsuits in consideration of payments totaling $16.6 million in exchange for full and complete releases for all defendants. The Company’s contribution to the settlement, net of payments by its insurers and contributions from other defendants, will amount to $1.0 million. The Company has recorded a liability in this amount for the quarter ended March 31, 2007. The settlement is subject to completion of documentation and court approval following notices to all potential claimants eligible for class participation. A preliminary hearing, originally scheduled for October 24, 2007, has been reset for November 21, 2007. The final hearing is scheduled for March 25, 2008.
Tax Audits. We are routinely the subject of audits by tax authorities and have received some material assessments from tax auditors. As of September 30, 2007, we have recorded reserves for future potential liabilities as a result of these audits that management feels are appropriate. While we have fully reserved for these assessments, the ultimate amount of settlement can vary from this estimate. In connection with our Egyptian operations, we are undergoing income tax audits for all periods in which we had operations. Based on information as of the period covered by this report, we have determined that additional income taxes will be owed and have recorded a liability of approximately $1.1 million.
23
Self-Insurance Reserves. We maintain insurance policies for workers’ compensation, vehicle liability and general liability claims. These insurance policies carry self-insured retention limits or deductibles on a per occurrence basis. The retention limits or deductibles are accounted for in our accrual process for all workers’ compensation, vehicular liability and general liability claims. We maintain reserves for workers’ compensation and vehicle liability on our balance sheet based on our judgment and estimates using an actuarial method based on claims incurred. We estimate general liability claims on a case-by-case basis. As of September 30, 2007 and December 31, 2006, we have recorded $67.4 million and $69.0 million, respectively, of self-insurance reserves related to worker’s compensation, vehicular liabilities and general liability claims.
Environmental Remediation Liabilities. For environmental reserve matters, including remediation efforts for current locations and those relating to previously-disposed properties, we record liabilities when our remediation efforts are probable and the costs to conduct such remediation efforts are reasonably estimated. Environmental reserves do not reflect management’s assessment of the insurance coverage that may apply to these matters at issue, whereas our litigation reserves do reflect the application of our insurance coverage. As of September 30, 2007 and December 31, 2006, we have recorded $3.0 million and $4.7 million, respectively, for our environmental remediation liabilities.
We provide performance bonds to provide financial surety assurances for the remediation and maintenance of our SWD properties to comply with environmental protection standards. Costs for SWD properties may be mandatory (to comply with applicable laws and regulations), in the future (required to divest or cease operations), or for optimization (to improve operations, but not for safety or regulatory compliance).
Argentina Payroll Matters. Our Argentinean subsidiary, Key Energy Services S.A., had previously underpaid our social security contributions to the Administración Federal de Ingressos Públicos (“AFIP”) as a result of applying an incorrect rate in the calculation of our obligation. Additionally, we also underpaid AFIP as a result of our incorrect use of food stamp equivalents provided to employees as compensation. The correct amounts have been reflected in these financial statements. On May 31, 2007 we paid AFIP $3.5 million, representing the cumulative amount of underpayment and interest. As a result of our underpayment, AFIP has imposed fines and penalties against us and has begun an audit of our filings made to them in prior years. We have recorded an appropriate liability for this matter and do not expect the ultimate resolution of this matter to have a material impact to our results of operations, cash flows or financial position.
Well Service Rig Purchase Contract. In October 2005, we entered into a purchase and sale agreement to acquire 30 well service rigs, with the option to acquire more under the terms of the agreement. We ordered and took delivery of 25 rigs under the agreement, returned 3 defective rigs for full credit and subsequently agreed with the seller to reduce the total number of rigs deliverable under the agreement to 22 rigs. Through September 30, 2007 we have received delivery of the 22 rigs and do not have any pending orders for additional rigs.
Expired Option Holders.On September 24, 2007, Belinda Taylor, on behalf of herself and all similarly situated residents of Texas, filed a lawsuit in the 11th Judicial District of Harris County, Texas, alleging that the Company breached its contracts with former employees who held vested options that expired between April 28, 2004 and the date that the Company became current in its financial statements (the “Expired Option Holders”). The suit also alleges the Company breached its fiduciary duties and duties of good fair and fair dealing in the pricing of stock options it granted to those Expired Option Holders, based upon the alleged overstatement of assets prior to the Company’s restatement. She amended her lawsuit on September 25,2007, to include all Expired Option Holders, regardless of residence. The Company has denied the allegations and does not believe that the ultimate resolution of this matter will have a material impact on our results of operations, cash flows or financial position.
9. STOCKHOLDERS’ EQUITY
Common Stock
On September 30, 2007, we had 200,000,000 shares of common stock authorized with a $0.10 par value, of which 131,890,674 shares were issued and outstanding, net of 533,466 shares held in treasury, and no dividends were declared or paid. On December 31, 2006, we had 200,000,000 shares of common stock authorized with a $0.10 par value, of which 131,624,038 shares were issued and outstanding, net of 497,501 shares held in treasury, and no dividends had been declared or paid.
24
Common Stock Warrants
On January 22, 1999, in connection with a private placement offering, we issued 150,000 Warrants to purchase approximately 2.2 million shares of the Company’s common stock at an exercise price of $4.88125 per share. Through September 30, 2007, 63,500 Warrants had been exercised, providing $4.2 million of proceeds to us and leaving 86,500 Warrants outstanding, which are potentially convertible into an aggregate of approximately 1.3 million shares of the Company’s common stock. On the date of issuance, the value of the Warrants was estimated at $7.4 million and was classified as equity. Under the terms of the Warrants, we are required to maintain an effective registration statement with the SEC covering the shares of common stock issuable upon exercise. If we are unable to maintain an effective registration statement, we are required to make semiannual liquidated damages payments for periods in which an effective registration statement is not maintained. Due to our past failure to file our SEC reports in a timely manner, we do not have an effective registration statement covering the Warrants, and have been required to make liquidated damages payments, and will continue to be required to make those payments until such time as we have an effective registration statement on file for exercise of the Warrants or the warrant shares issuable thereunder are eligible for resale without registration pursuant to SEC Rule 144 or otherwise. We paid liquidated damages starting at $0.05 per Warrant per week and escalating to $0.20 per Warrant per week. The total amounts paid to holders of the Warrants were $0.5 million and $0.4$2.3 million during the three months ended September 30,March 31, 2008 and 2007, and 2006, respectively. The total amounts paid to the holders of the Warrants were $1.0 million and $0.9 million during the nine months ended September 30, 2007 and 2006, respectively.
Treasury Stock
During the nine months ended September 30, 2007 and 2006, the Company purchased 35,965 and 80,835 shares, respectively, of restricted common stock that had been previously granted to certain of the Company’s officers, pursuant to an agreement under which those individuals were permitted to sell shares back to the Company in order to satisfy therelated income tax withholding requirements related to the vesting of these grants. We account for treasury stock under the cost method, and as such recorded $0.7 million and $1.2 million, respectively, in treasury stock on the date of purchase, which represented the fair market value of the shares based on the price of the Company’s stock on the date of purchase.
Stock Incentive Plans
On January 13, 1998, Key’s shareholders approved the Key Energy Group, Inc. 1997 Incentive Plan, as amended (the “1997 Incentive Plan”). The 1997 Incentive Plan is an amendment and restatement of the plans formerly known as the Key Energy Group, Inc. 1995 Stock Option Plan and the Key Energy Group, Inc. 1995 Outside Directors Stock Option Plan (collectively, the “Prior Plans”).
All options previously granted under the Prior Plans and outstanding as of November 17, 1997 (the date on which our board of directors adopted the 1997 Incentive Plan) were assumed and continued, without modification, under the 1997 Incentive Plan.
Under the 1997 Incentive Plan, Key may grant the following awards to certain key employees, directors who are not employees (“Outside Directors”) and consultants of Key, our controlled subsidiaries, and our parent corporation, if any: (i) incentive stock options (“ISOs”) as defined in Section 422 of the Internal Revenue Code of 1986, as amended (the “Code”), (ii) “nonstatutory” stock options (“NSOs”), (iii) stock appreciation rights (“SARs”), (iv) shares of restricted stock, (v) performance shares and performance units, (vi) other stock-based awards and (vii) supplemental tax bonuses (collectively, “Incentive Awards”). ISOs and NSOs are sometimes referred to collectively herein as “Options.” All Options granted have a maximum contractual life of ten years.
Key may grant Incentive Awards covering an aggregate of the greater of (i) 3.0 million shares of our common stock or (ii) 10% of the shares of our common stock issued and outstanding on the last day of each calendar quarter, provided, however, that a decrease in the number of issued and outstanding shares of our common stock from the previous calendar quarter shall not result in a decrease in the number of shares available for issuance under the 1997 Incentive Plan. As of September 30, 2007, the number of shares of our common stock that may be covered by Incentive Awardsbenefit recognized was approximately 13.2 million shares. As of that date, approximately 0.5 million Incentive Awards could still be issued under the 1997 Incentive Plan.
The following table summarizes the stock option activity related to the plans for the nine months ended September 30, 2007 (options in thousands):
25
|
| Options |
| Weighted Average Exercise Price |
| Weighted Average Fair Value |
| ||
|
|
|
|
|
|
|
| ||
Outstanding at beginning of year |
| 5,829 |
| $ | 9.46 |
| $ | 4.94 |
|
Granted |
| 1,192 |
| $ | 14.41 |
| $ | 5.98 |
|
Exercised |
| — |
| $ | — |
| $ | — |
|
Cancelled or expired |
| (813 | ) | $ | 10.26 |
| $ | 5.00 |
|
Outstanding at end of period |
| 6,208 |
| $ | 10.36 |
| $ | 5.13 |
|
|
|
|
|
|
|
|
| ||
Exercisable at end of period |
| 4,165 |
| $ | 8.34 |
| $ | 4.51 |
|
The following tables summarize information about the stock options outstanding at September 30, 2007 (options in thousands):
|
| Weighted Average Remaining Contractual Life (Years) |
| Number of Options Outstanding, September 30, 2007 |
| Weighted Average Exercise Price |
| Weighted Average Fair Value |
| ||
|
|
|
|
|
|
|
|
|
| ||
Range of Exercise Prices: |
|
|
|
|
|
|
|
|
| ||
$3.00 - $7.44 |
| 1.75 |
| 944 |
| $ | 4.85 |
| $ | 3.44 |
|
$7.45 - $8.43 |
| 4.05 |
| 1,069 |
| $ | 8.16 |
| $ | 4.45 |
|
$8.44 - $11.75 |
| 4.35 |
| 1,681 |
| $ | 9.36 |
| $ | 4.96 |
|
$11.76 - $14.25 |
| 7.07 |
| 619 |
| $ | 12.09 |
| $ | 5.30 |
|
$14.26 - $18.90 |
| 9.34 |
| 1,895 |
| $ | 14.66 |
| $ | 6.46 |
|
|
|
|
| 6,208 |
| $ | 10.36 |
| $ | 5.13 |
|
|
| Number of Options Exercisable, September 30, 2007 |
| Weighted Average Exercise Price |
| Weighted Average Fair Value |
| ||
|
|
|
|
|
|
|
| ||
Range of Exercise Prices: |
|
|
|
|
|
|
| ||
$3.00 - $7.44 |
| 944 |
| $ | 4.85 |
| $ | 3.44 |
|
$7.45 - $8.43 |
| 1,057 |
| $ | 8.16 |
| $ | 4.45 |
|
$8.44 - $11.75 |
| 1,676 |
| $ | 9.36 |
| $ | 4.93 |
|
$11.76 - $14.25 |
| 478 |
| $ | 11.95 |
| $ | 5.14 |
|
$14.26 - $18.90 |
| 10 |
| $ | 14.51 |
| $ | 7.19 |
|
|
| 4,165 |
| $ | 8.34 |
| $ | 4.51 |
|
The weighted-average remaining contractual term of the outstanding exercisable options as of September 30, 2007, is approximately 4.0 years. The total fair value of stock options granted during the nine months ended September 30, 2007 was $7.1 million. The fair value of each stock option granted during the nine months ended September 30, 2007 was estimated on the date of grant using the Black-Scholes option-pricing model, based on the following weighted-average assumptions:
|
| |
|
| |
|
| |
|
|
26
During the three months ended September 30, 2007 and 2006, we recognized approximately $1.0 million and $0.7 million respectively, in compensation expense associated with options. For the nine months ended September 30, 2007 and 2006, we recognized approximately $2.2 million and $2.0 million, respectively, in compensation expense associated with options. Tax benefits of $0.2 million were recognized in association with stock options for the three and nine months ended September 30, 2007. For the options outstanding as of September 30, 2007, the Company expects that it will recognize approximately $9.1 million of expense over the next 1.5 years.
Common Stock Awards
In June 2005, we began granting shares of common stock to our outside directors and certain employees. Common stock awards granted to our outside directors vest immediately, while those granted to our employees vest over a three-year period and are subject to forfeiture. The total fair market value of all common stock awards granted during the nine months ended September 30, 2007 and 2006 was $4.5 million and $0.7 million, respectively.
Pursuant to the agreement under which they are issued restricted stock, recipients of common share awards may have shares withheld in order to satisfy those individuals’ income tax obligations associated with the vesting of the awards granted to them. We account for these as treasury stock transactions. In connection with a vesting in June of 2006, one of the recipients was permitted to have an amount withheld that was in excess of the required minimum required withholding under current tax law. Under SFAS 123(R), we are required to account for this grant as a liability award. Compensation expense for this award for the nine months ended September 30, 2007 and 2006 was $0.1 million and $0.1 million, respectively. Compensation expense recognized for this award during the quarters ended September 30, 2007 and 2006 was less than $0.1 million in both periods.
The following table summarizes information for the nine months ended September 30, 2007 about the common share awards that have been issued by the Company (shares in thousands):
|
| Outstanding |
| Weighted-Average Issuance Price |
| Vested |
| Weighted-Average Issuance Price |
| ||
Shares at beginning of period (1) |
| 833 |
| $ | 13.69 |
| 258 |
| $ | 12.43 |
|
Shares issued during period (2) |
| 302 |
| $ | 14.79 |
| 38 |
| $ | 17.92 |
|
Previously issued shares vesting during period |
| — |
| $ | — |
| 131 |
| $ | 12.03 |
|
Shares repurchased during period |
| (36 | ) | $ | 11.90 |
| (36 | ) | $ | 11.90 |
|
Shares at end of period |
| 1,099 |
| $ | 14.05 |
| 391 |
| $ | 12.88 |
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
(1) Net of 80,835 shares repurchased in June 2006.
(2) Shares issued to outside directors are immediately vested.
For common stock grants that vest immediately upon issuance, we record expense equal to the fair market value of the shares on the date of grant. For common stock grants that do not immediately vest, we recognize compensation cost ratably over the vesting period of the grant, net of actual and estimated forfeitures. For the three months ended September 30, 2007 and 2006, we recognized $1.7 million and $0.9 million, respectively, of pre-tax expense related to common stock awards, net of estimated and actual forfeitures. For the nine months ended September 30, 2007 and 2006, we recognized $3.9 million and $3.2 million, respectively, of pre-tax expense related to common stock awards, net of estimated and actual forfeitures. In connection with the expense related to common stock awards recognized during the three and nine months ended September 30, 2007, we recognized tax benefits of zero and $0.8 million, respectively. For the unvested common stock awards outstanding as of September 30, 2007, the Company anticipates that it will recognize approximately $6.6 million of expense over the next 0.8 years.
Phantom Share Awards
In December 2006, the Company announced the implementation of a “Phantom Share Plan,” pursuant to which certain of the Company’s employees were granted “Phantom Shares.” The Phantom Shares vest ratably over a four-year period and convey the right to the grantee to receive a cash payment on the anniversary date of the grant equal to the fair market value of the Phantom Shares vesting on that date. Grantees are not permitted to defer the payment to a later date. The Phantom Shares qualify as a “liability” type award under SFAS 123(R), and as such, we account for these awards at fair value. We recognize compensation expense related to the Phantom Shares based on the change in the fair value of the awards during the period and
27
the percentage of service requirement that has been performed, net of estimated and actual forfeitures, with an offsetting liability recorded on our Consolidated Balance Sheets. During the three and nine months ended September 30, 2007, we recognized approximately $0.8 million and $2.9 million of pre-tax compensation expense, respectively, associated with the Phantom Shares, and have recorded a current liability of approximately $1.4 million and a long-term liability of approximately $1.5 million as of September 30, 2007. Associated with the Phantom Shares, we recognized $0.3 million and $1.1 million, respectively, of tax benefits for the three and nine months ended September 30, 2007. For the unvested Phantom Share awards outstanding as of September 30, 2007, the Company estimates that it will recognize an additional $5.4 million of compensation expense over the next 1.8 years.
Stock Appreciation Rights
In August 2007, under the 1997 Incentive Plan, the Company issued approximately 590,000 stock appreciation rights (“SARs”) to certain executive officers. Each SAR award has a ten-year term from the date of grant and vests in equal annual installments on the first, second and third anniversaries of the date of grant. The per share exercise price of each SAR is $14.32, which was determined to be the fair market value of a share of the Company’s common stock on the date of the grant. Upon the exercise of an SAR, the recipient will receive an amount equal to the difference between the exercise price and the fair market value of a share of the Company’s common stock on the date of exercise multiplied by the number of shares of common stock for which the SAR was exercised. All payments will be made in shares of the Company’s common stock. Prior to exercise, the SAR does not entitle the recipient to receive any shares of the Company’s common stock and does not provide the recipient with any voting or other stockholder rights.
During the three and nine months ended September 30, 2007, the Company recognized approximately $0.2 million in compensation expense associated with the SARs. Tax benefits recognized in connection with the SARs for the three months ended September 30,March 31, 2008 and 2007, were less than $0.1 million. Forrespectively. The Company did not capitalize any share-based compensation during the three months ended March 31, 2008 and 2007.
The unrecognized compensation cost related to the Company’s unvested SARs outstandingstock options, restricted shares, stock appreciation rights, and phantom shares as of September 30, 2007, the Company expects that it will recognize approximately $3.3March 31, 2008 was $5.9 million, $4.2 million, $2.2 million, and $2.8 million, respectively and are expected to be recognized over a weighted-average period of expense over the next 1.9 years.1.1 years, 0.5 years, 1.4 years and 1.3 years, respectively.
10.14. SEGMENT INFORMATION
For 2007, our reportable business segments are well servicing, pressure pumping and fishing and rental.
Well Servicing. These operations provide a full range of well services, including rig-based services, oilfield transportation services and other ancillary oilfield services necessary to complete, maintain and workover oil and natural gas producing wells. Our Argentina operations are included in our well servicing segment. We aggregate our operating divisions engaged in well servicing activities into our well servicing reportable segment.
Pressure Pumping. These operations provide well stimulation and cementing services. Stimulation includes fracturing, nitrogen services and acidizing services and is used to enhance the production of oil and natural gas wells from formations which exhibit a restricted flow of oil and / or natural gas. Cementing services include pumping cement into a well between the casing and the wellbore.
Fishing and Rental. These operations provide services that include “fishing” to recover lost or stuck equipment in a wellbore through the use of “fishing tools.” In addition, this segment offers a full line of services and rental equipment designed for use both on land and offshore for drilling and workover services and includes an inventory consisting of tubulars, handling tools, pressure-control equipment and power swivels.
We evaluate the performance of our operating segments based on revenue and EBITDA, which is a non-GAAP measure and not disclosed below. Corporate expenses include general corporate expenses associated with managing all reportable operating segments. Corporate assets consist principally of cash and cash equivalents, short-term investments, debt financing costs and deferred income tax assets.
The following table sets forth our segment information as of and for the periods ended September 30, 2007March 31, 2008 and September 30, 2006, respectively:2007:
2815
|
| Well Servicing |
| Pressure Pumping |
| Fishing and Rental |
| Corporate / Other |
| Total |
| |||||
|
| (in thousands) |
| |||||||||||||
As of and for the three months ended September 30, 2007: |
|
|
|
|
|
|
|
|
|
|
| |||||
Operating revenues |
| $ | 311,304 |
| $ | 77,112 |
| $ | 25,551 |
| $ | — |
| $ | 413,967 |
|
Gross margin |
| 118,153 |
| 27,755 |
| 10,577 |
| — |
| 156,485 |
| |||||
Depreciation and amortization |
| 20,100 |
| 4,362 |
| 2,126 |
| 4,597 |
| 31,185 |
| |||||
Interest expense |
| (261 | ) | (307 | ) | (148 | ) | 8,630 |
| 7,914 |
| |||||
Net income (loss) |
| 78,372 |
| 21,400 |
| 5,786 |
| (69,662 | ) | 35,896 |
| |||||
Propery, plant and equipment, net |
| 562,833 |
| 131,620 |
| 46,950 |
| 38,675 |
| 780,078 |
| |||||
Total assets |
| 1,079,728 |
| 240,503 |
| 89,930 |
| 267,877 |
| 1,678,038 |
| |||||
Capital expenditures, excluding acquisitions |
| (33,230 | ) | (9,175 | ) | (5,445 | ) | (1,128 | ) | (48,978 | ) | |||||
|
|
|
| Pressure |
| Fishing and |
| Corporate / |
|
|
|
|
| ||||||
|
| Well Servicing |
| Pumping |
| Rental |
| Other |
| Eliminations |
| Total |
| ||||||
|
| (in thousands) |
| ||||||||||||||||
As of and for the three months ended March 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Operating revenues |
| $ | 349,418 |
| $ | 81,852 |
| $ | 25,669 |
| $ | — |
| $ | (540 | ) | $ | 456,399 |
|
Gross margin |
| 137,384 |
| 28,073 |
| 9,558 |
| — |
| (257 | ) | 174,758 |
| ||||||
Depreciation and amortization |
| 29,531 |
| 4,812 |
| 2,601 |
| 3,032 |
| — |
| 39,976 |
| ||||||
Interest expense |
| (552 | ) | (391 | ) | (120 | ) | 10,855 |
| 248 |
| 10,040 |
| ||||||
Net income (loss) |
| 82,843 |
| 21,013 |
| 5,331 |
| (74,445 | ) | (258 | ) | 34,484 |
| ||||||
Property and equipment, net |
| 695,362 |
| 131,282 |
| 48,672 |
| 33,502 |
| — |
| 908,818 |
| ||||||
Total assets |
| 1,539,182 |
| 271,214 |
| 93,143 |
| 512,550 |
| (589,283 | ) | 1,826,806 |
| ||||||
Capital expenditures, excluding acquisitions |
| (25,895 | ) | (1,857 | ) | (1,406 | ) | (1,217 | ) | — |
| (30,375 | ) | ||||||
|
|
|
| Pressure |
| Fishing and |
| Corporate / |
|
|
|
|
| ||||||
|
| Well Servicing |
| Pumping |
| Rental |
| Other |
| Eliminations |
| Total |
| ||||||
|
| (in thousands) |
| ||||||||||||||||
As of and for the three months ended March 31, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Operating revenues |
| $ | 311,160 |
| $ | 74,077 |
| $ | 23,682 |
| $ | — |
| $ | — |
| $ | 408,919 |
|
Gross margin |
| 135,631 |
| 27,544 |
| 10,231 |
| — |
| — |
| 173,406 |
| ||||||
Depreciation and amortization |
| 19,767 |
| 3,936 |
| 2,346 |
| 3,565 |
| — |
| 29,614 |
| ||||||
Interest expense |
| (167 | ) | (143 | ) | (71 | ) | 9,729 |
| — |
| 9,348 |
| ||||||
Net income (loss) |
| 98,034 |
| 21,018 |
| 5,433 |
| (72,295 | ) | — |
| 52,190 |
| ||||||
Property and equipment, net |
| 527,700 |
| 107,282 |
| 37,970 |
| 40,006 |
| — |
| 712,958 |
| ||||||
Total assets |
| 1,016,758 |
| 212,092 |
| 79,832 |
| 172,621 |
| 131,361 |
| 1,612,664 |
| ||||||
Capital expenditures, excluding acquisitions |
| (26,791 | ) | (13,576 | ) | (4,006 | ) | (2,002 | ) | — |
| (46,375 | ) | ||||||
|
| Well Servicing |
| Pressure Pumping |
| Fishing and Rental |
| Corporate / Other |
| Total |
| |||||
|
| (in thousands) |
| |||||||||||||
As of and for the three months ended September 30, 2006: |
|
|
|
|
|
|
|
|
|
|
| |||||
Operating revenues |
| $ | 323,655 |
| $ | 69,038 |
| $ | 24,907 |
| $ | — |
| $ | 417,600 |
|
Gross margin |
| 138,169 |
| 31,733 |
| 10,297 |
| — |
| 180,199 |
| |||||
Depreciation and amortization |
| 22,513 |
| 3,209 |
| 1,730 |
| 2,740 |
| 30,192 |
| |||||
Interest expense |
| (218 | ) | (117 | ) | (36 | ) | 10,781 |
| 10,410 |
| |||||
Net income (loss) |
| 102,439 |
| 26,150 |
| 5,918 |
| (73,622 | ) | 60,885 |
| |||||
Propery, plant and equipment, net |
| 522,962 |
| 91,122 |
| 34,963 |
| 32,762 |
| 681,809 |
| |||||
Total assets |
| 1,013,218 |
| 181,326 |
| 77,606 |
| 236,063 |
| 1,508,213 |
| |||||
Capital expenditures, excluding acquisitions |
| (33,132 | ) | (7,326 | ) | (6,298 | ) | (2,058 | ) | (48,814 | ) | |||||
|
| Well Servicing |
| Pressure Pumping |
| Fishing and Rental |
| Corporate / Other |
| Total |
| |||||
|
| (in thousands) |
| |||||||||||||
As of and for the nine months ended September 30, 2007: |
|
|
|
|
|
|
|
|
|
|
| |||||
Operating revenues |
| $ | 931,289 |
| $ | 228,478 |
| $ | 73,629 |
| $ | — |
| $ | 1,233,396 |
|
Gross margin |
| 385,306 |
| 85,178 |
| 31,696 |
| — |
| 502,180 |
| |||||
Depreciation and amortization |
| 63,372 |
| 12,354 |
| 6,520 |
| 9,237 |
| 91,483 |
| |||||
Interest expense |
| (696 | ) | (676 | ) | (327 | ) | 27,930 |
| 26,231 |
| |||||
Net income (loss) |
| 268,848 |
| 65,921 |
| 18,117 |
| (216,664 | ) | 136,222 |
| |||||
Propery, plant and equipment, net |
| 562,833 |
| 131,620 |
| 46,950 |
| 38,675 |
| 780,078 |
| |||||
Total assets |
| 1,079,728 |
| 240,503 |
| 89,930 |
| 267,877 |
| 1,678,038 |
| |||||
Capital expenditures, excluding acquisitions |
| (100,904 | ) | (44,969 | ) | (16,364 | ) | (5,586 | ) | (167,823 | ) | |||||
|
| Well Servicing |
| Pressure Pumping |
| Fishing and Rental |
| Corporate / Other |
| Total |
| |||||
|
| (in thousands) |
| |||||||||||||
As of and for the nine months ended September 30, 2006: |
|
|
|
|
|
|
|
|
|
|
| |||||
Operating revenues |
| $ | 884,962 |
| $ | 181,035 |
| $ | 71,596 |
| $ | — |
| $ | 1,137,593 |
|
Gross margin |
| 348,962 |
| 83,271 |
| 29,278 |
| — |
| 461,511 |
| |||||
Depreciation and amortization |
| 64,276 |
| 8,381 |
| 5,025 |
| 8,248 |
| 85,930 |
| |||||
Interest expense |
| (508 | ) | (500 | ) | (43 | ) | 30,068 |
| 29,017 |
| |||||
Net income (loss) |
| 233,776 |
| 68,440 |
| 15,925 |
| (187,610 | ) | 130,531 |
| |||||
Propery, plant and equipment, net |
| 522,962 |
| 91,122 |
| 34,963 |
| 32,762 |
| 681,809 |
| |||||
Total assets |
| 1,013,218 |
| 181,326 |
| 77,606 |
| 236,063 |
| 1,508,213 |
| |||||
Capital expenditures, excluding acquisitions |
| (107,517 | ) | (25,856 | ) | (11,053 | ) | (2,579 | ) | (147,005 | ) | |||||
Operating revenues for our foreign operations were $27.9 million and $22.2 million for the three months ended September 30, 2007 and 2006, respectively. Operating revenues for our foreign operations were $67.9 million and $57.4 million for the nine months ended September 30, 2007 and 2006, respectively. Gross margins for our foreign operations were $6.1 million and $6.5 million for the quarters ended September 30, 2007 and 2006, respectively. Gross margins for our foreign operations were $11.7 million and $14.7 million for the nine months ended September 30, 2007 and 2006, respectively.
We have $114.2 million and $77.9 million of identifiable assetsThe following table presents information related to our foreign operations as(in thousands of September 30, 2007 and December 31, 2006, respectively. Capital expendituresU.S. Dollars):
|
| Argentina |
| Mexico |
| Canada |
| Total |
| |||||
|
|
|
|
|
|
|
|
|
| |||||
As of and for the three months ended March 31, 2008: |
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
| |||||
Operating revenues |
| $ | 26,866 |
| $ | 5,701 |
| $ | 3,890 |
| $ | 36,457 |
| |
Total assets |
| 83,563 |
| 34,110 |
| 6,596 |
| 124,269 |
| |||||
|
|
|
|
|
|
|
|
|
| |||||
As of and for the three months ended March 31, 2007: |
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
| |||||
Operating revenues |
| $ | 20,427 |
| $ | — |
| $ | — |
| $ | 20,427 |
| |
Total assets |
| 76,049 |
| 10,198 | (1) | — |
| 86,247 |
| |||||
(1) Revenue-generating operations for our foreign operations were $4.9 million and $8.0 million forMexican subsidiary did not begin until the nine months ended September 30, 2007 and 2006, respectively.second quarter of 2007.
15. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS
29
During the fourth quarter of 2007, we issued $425.0 million of 8.375% Senior Notes due 2014 (the “Notes”), which are guaranteed by virtually all of our domestic subsidiaries, all of which are wholly-owned. The guarantees were joint and several, full, complete and unconditional. There were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company.
As a result of these guarantee arrangements, we are required to present the following condensed consolidating financial information pursuant to SEC Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered.”
16
11.SUBSEQUENT EVENTS
Closing of Moncla Purchase
The Company closed the acquisition of Moncla on October 25, 2007. The Company paid $145.8 million for Moncla, of which $123.3 million was paid in cash at closing. Cash paid at closing included the repayment of approximately $14.7 million of Moncla indebtedness. In addition, the purchase price includes $22.5 million of notes payable to the sellers, and the purchase agreement provides for an earnout of up to $25.0 million over the next five years. The notes payable to the sellers consist of two notes. The first is an unsecured note in the amount of $12.5 million, which is due and payable in a lump-sum, together with accrued interest, on October 25, 2009. The second unsecured note in the amount of $10.0 million is payable in annual installments of $2.0 million, plus accrued interest, beginning October 25, 2008 through 2012. Each of the notes bear interest at the Federal Funds rate adjusted annually on the anniversary date of the closing date.
Moncla is headquartered in Lafayette, Louisiana, and has offices in Sour Lake, Texas and Sandersville, Mississippi. Moncla’s fleet includes daylight rigs for well servicing and workovers and twenty-four hour rigs for shallow drilling, sidetracking and deep workovers. Moncla also has a fleet of workover barges. In addition to rigs, Moncla owns rig-up, swab, hot oil and anchor trucks, tubing testing units and rental equipment. Moncla currently operates in Texas, Louisiana, Mississippi, Alabama and Florida.
New Credit FacilityCONDENSED CONSOLIDATING BALANCE SHEETS
The Company also received a commitment from two lenders to provide, subject to customary conditions, $150 million of a new $400 million senior secured credit revolving credit facility and to use their best efforts to syndicate the remaining $250 million of the revolving credit facility. Three additional lenders have committed to provide an additional $150 million of the revolving credit facility. The commitment letter also provides for a $350 million term loan facility that the Company will terminate upon the successful completion of the offering of the senior notes. The Company expects to enter into the new senior secured revolving credit facility concurrently with the closing of the senior notes offering.
Senior Notes Offering
On November 5, 2007, the Company commenced an offering of up to $400 million of senior notes due 2017 through a private placement. Under the proposed terms of the offering certain of the Company’s domestic subsidiaries will fully and unconditionally guarantee the notes. The Company intends to use the net proceeds of the proposed offering to retire its outstanding $393 million of term loans under our existing Senior Secured Credit Facility.
Amendment to Existing Senior Secured Credit Facility
|
| March 31, 2008 |
| |||||||||||||
|
| Parent Company |
| Guarantor |
| Non-Guarantor |
| Eliminations |
| Consolidated |
| |||||
|
| (in thousands) |
| |||||||||||||
|
| (unaudited) |
| |||||||||||||
Assets: |
|
|
|
|
|
|
|
|
|
|
| |||||
Current assets |
| $ | — |
| $ | 386,908 |
| $ | 73,882 |
| $ | — |
| $ | 460,790 |
|
Net property and equipment |
| — |
| 879,261 |
| 29,557 |
| — |
| 908,818 |
| |||||
Goodwill |
| — |
| 372,594 |
| 5,999 |
| — |
| 378,593 |
| |||||
Deferred financing costs, net |
| 11,925 |
| — |
| — |
| — |
| 11,925 |
| |||||
Intercompany receivables and investments in subsidiaries |
| 1,605,437 |
| 218,954 |
| 541 |
| (1,824,932 | ) | — |
| |||||
Other assets |
| 10,617 |
| 50,781 |
| 5,282 |
| — |
| 66,680 |
| |||||
TOTAL ASSETS |
| $ | 1,627,979 |
| $ | 1,908,498 |
| $ | 115,261 |
| $ | (1,824,932 | ) | $ | 1,826,806 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Liabilities and equity: |
|
|
|
|
|
|
|
|
|
|
| |||||
Current liabilities |
| 18,867 |
| 190,111 |
| 24,281 |
| — |
| 233,259 |
| |||||
Long-term debt |
| 475,000 |
| — |
| — |
| — |
| 475,000 |
| |||||
Capital lease obligations |
| — |
| 14,982 |
| 123 |
| — |
| 15,105 |
| |||||
Long-term notes payable - related party |
| — |
| 20,500 |
| — |
| — |
| 20,500 |
| |||||
Intercompany payables |
| 113,156 |
| 1,271,699 |
| 29,013 |
| (1,413,868 | ) | — |
| |||||
Deferred tax liabilities |
| 159,909 |
| (1,807 | ) | 1,807 |
| — |
| 159,909 |
| |||||
Other long-term liabilities |
| — |
| 61,779 |
| 207 |
| — |
| 61,986 |
| |||||
Stockholders’ equity |
| 861,047 |
| 351,234 |
| 59,830 |
| (411,064 | ) | 861,047 |
| |||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY |
| $ | 1,627,979 |
| $ | 1,908,498 |
| $ | 115,261 |
| $ | (1,824,932 | ) | $ | 1,826,806 |
|
The Company is currently in discussions with its lenders under the revolving credit facility of its Senior Secured Credit Facility to amend the facility if the Company completes the offering of the senior notes. The amendment would permit the issuance of the notes, terminate the prefunded letter of credit facility and permit the Company to use the entire $65 million revolving credit portion of the Senior Secured Credit Facility for letters of credit.
|
| December 31, 2007 |
| |||||||||||||
|
| Parent Company |
| Guarantor |
| Non-Guarantor |
| Eliminations |
| Consolidated |
| |||||
|
| (in thousands) |
| |||||||||||||
Assets: |
|
|
|
|
|
|
|
|
|
|
| |||||
Current assets |
| $ | 39,501 |
| $ | 378,865 |
| $ | 69,499 |
| $ | — |
| $ | 487,865 |
|
Net property and equipment |
| — |
| 880,907 |
| 30,301 |
| — |
| 911,208 |
| |||||
Goodwill |
| — |
| 373,283 |
| 5,267 |
| — |
| 378,550 |
| |||||
Deferred financing costs, net |
| 12,117 |
| — |
| — |
| — |
| 12,117 |
| |||||
Intercompany receivables and investments in subsidiaries |
| 1,557,993 |
| 175,461 |
| — |
| (1,733,454 | ) | — |
| |||||
Other assets |
| 11,217 |
| 52,074 |
| 6,046 |
| — |
| 69,337 |
| |||||
TOTAL ASSETS |
| $ | 1,620,828 |
| $ | 1,860,590 |
| $ | 111,113 |
| $ | (1,733,454 | ) | $ | 1,859,077 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Liabilities and equity: |
|
|
|
|
|
|
|
|
|
|
| |||||
Current liabilities |
| 17,278 |
| 192,222 |
| 25,297 |
| — |
| 234,797 |
| |||||
Long-term debt |
| 475,000 |
| — |
| — |
| — |
| 475,000 |
| |||||
Capital lease obligations |
| — |
| 15,998 |
| 116 |
| — |
| 16,114 |
| |||||
Long-term notes payable - related party |
| — |
| 20,500 |
| — |
| — |
| 20,500 |
| |||||
Intercompany payables |
| 78,660 |
| 1,489,377 |
| 24,408 |
| (1,592,445 | ) | — |
| |||||
Deferred tax liabilities |
| 157,759 |
| (79 | ) | 2,388 |
| — |
| 160,068 |
| |||||
Other long-term liabilities |
| 3,133 |
| 60,216 |
| 251 |
| — |
| 63,600 |
| |||||
Stockholders’ equity |
| 888,998 |
| 82,356 |
| 58,653 |
| (141,009 | ) | 888,998 |
| |||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY |
| $ | 1,620,828 |
| $ | 1,860,590 |
| $ | 111,113 |
| $ | (1,733,454 | ) | $ | 1,859,077 |
|
3017
Item 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTSCONDENSED CONSOLIDATING UNAUDITED STATEMENTS OF OPERATIONS
|
| Three Months Ended March 31, 2008 |
| |||||||||||||
|
| Parent Company |
| Guarantor |
| Non-Guarantor |
| Eliminations |
| Consolidated |
| |||||
|
| (in thousands) |
| |||||||||||||
|
| (unaudited) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Revenues |
| $ | — |
| $ | 422,621 |
| $ | 36,457 |
| $ | (2,679 | ) | $ | 456,399 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
| |||||
Direct expenses |
| — |
| 257,771 |
| 25,666 |
| (1,796 | ) | 281,641 |
| |||||
Depreciation and amortization |
| — |
| 38,051 |
| 1,925 |
| — |
| 39,976 |
| |||||
General and administrative |
| 185 |
| 62,874 |
| 4,782 |
| (109 | ) | 67,732 |
| |||||
Interest expense, net of amounts capitalized |
| 10,756 |
| (1,007 | ) | 43 |
| 248 |
| 10,040 |
| |||||
Other, net |
| 35 |
| (664 | ) | 1,497 |
| (765 | ) | 103 |
| |||||
Total costs and expenses, net |
| 10,976 |
| 357,025 |
| 33,913 |
| (2,422 | ) | 399,492 |
| |||||
(Loss) income before income taxes |
| (10,976 | ) | 65,596 |
| 2,544 |
| (257 | ) | 56,907 |
| |||||
Income tax expense |
| (20,484 | ) | (561 | ) | (1,412 | ) | — |
| (22,457 | ) | |||||
Minority interest |
| — |
| — |
| 34 |
| — |
| 34 |
| |||||
NET (LOSS) INCOME |
| $ | (31,460 | ) | $ | 65,035 |
| $ | 1,166 |
| $ | (257 | ) | $ | 34,484 |
|
|
| Three Months Ended March 31, 2007 |
| |||||||||||||
|
| Parent Company |
| Guarantor |
| Non-Guarantor |
| Eliminations |
| Consolidated |
| |||||
|
| (in thousands) |
| |||||||||||||
|
| (unaudited) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Revenues |
| $ | — |
| $ | 388,492 |
| $ | 20,427 |
| $ | — |
| $ | 408,919 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
| |||||
Direct expenses |
| — |
| 219,302 |
| 16,211 |
| — |
| 235,513 |
| |||||
Depreciation and amortization |
| — |
| 28,315 |
| 1,299 |
| — |
| 29,614 |
| |||||
General and administrative |
| 235 |
| 50,601 |
| 1,228 |
| — |
| 52,064 |
| |||||
Interest expense, net of amounts capitalized |
| 9,732 |
| (355 | ) | (29 | ) | — |
| 9,348 |
| |||||
Other, net |
| (549 | ) | (2,056 | ) | 291 |
| — |
| (2,314 | ) | |||||
Total costs and expenses, net |
| 9,418 |
| 295,807 |
| 19,000 |
| — |
| 324,225 |
| |||||
(Loss) income before income taxes |
| (9,418 | ) | 92,685 |
| 1,427 |
| — |
| 84,694 |
| |||||
Income tax expense |
| (32,069 | ) | — |
| (435 | ) | — |
| (32,504 | ) | |||||
NET (LOSS) INCOME |
| $ | (41,487 | ) | $ | 92,685 |
| $ | 992 |
| $ | — |
| $ | 52,190 |
|
18
CONDENSED CONSOLIDATING UNAUDITED STATEMENTS OF CASH FLOWS
|
| Three Months Ended March 31, 2008 |
| |||||||||||||
|
| Parent Company |
| Guarantor |
| Non-Guarantor |
| Eliminations |
| Consolidated |
| |||||
|
| (in thousands) |
| |||||||||||||
|
| (unaudited) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Net cash (used in) provided by operating activities |
| $ | (108 | ) | $ | 67,550 |
| $ | 2,869 |
| $ | — |
| $ | 70,311 |
|
Net cash used in investing activities |
| (1,644 | ) | (97,347 | ) | — |
| 68,625 |
| (30,366 | ) | |||||
Net cash provided by (used in) financing activities |
| 1,752 |
| (2,967 | ) | 1,605 |
| (68,625 | ) | (68,235 | ) | |||||
Effect of exchange rates on cash |
| — |
| — |
| (342 | ) | — |
| (342 | ) | |||||
Net (decrease) increase in cash |
| — |
| (32,764 | ) | 4,132 |
| — |
| (28,632 | ) | |||||
Cash at beginning of period |
| — |
| 46,358 |
| 12,145 |
| — |
| 58,503 |
| |||||
Cash at end of period |
| $ | — |
| $ | 13,594 |
| $ | 16,277 |
| $ | — |
| $ | 29,871 |
|
|
| Three Months Ended March 31, 2007 |
| |||||||||||||
|
| Parent Company |
| Guarantor |
| Non-Guarantor |
| Eliminations |
| Consolidated |
| |||||
|
| (in thousands) |
| |||||||||||||
|
| (unaudited) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Net cash provided by operating activities |
| $ | — |
| $ | 82,562 |
| $ | 4,288 |
| $ | — |
| $ | 86,850 |
|
Net cash provided by (used in) investing activities |
| 3,649 |
| (105,424 | ) | (2,479 | ) | (6,298 | ) | (110,552 | ) | |||||
Net cash (used in) provided by financing activities |
| (3,649 | ) | (9,889 | ) | 3,649 |
| 6,298 |
| (3,591 | ) | |||||
Effect of exchange rates on cash |
| — |
| — |
| (370 | ) | — |
| (370 | ) | |||||
Net (decrease) increase in cash |
| — |
| (32,751 | ) | 5,088 |
| — |
| (27,663 | ) | |||||
Cash at beginning of period |
| — |
| 84,633 |
| 3,742 |
| — |
| 88,375 |
| |||||
Cash at end of period |
| $ | — |
| $ | 51,882 |
| $ | 8,830 |
| $ | — |
| $ | 60,712 |
|
16. SUBSEQUENT EVENTS
On April 3, 2008, the Company acquired Western Drilling, LLC (“Western”) for approximately $51.5 million in cash. Western owned 22 working well service rigs, three stacked well service rigs, and rental equipment used in the workover and rig relocation process. We acquired these assets to increase our service footprint in the California market, and the acquisition will be included in the Company’s Well Servicing segment. The following discussionpurchase price is subject to a working capital adjustment 45 days from the closing date. The acquisition was funded using $1.5 million of cash on hand and analysis shouldborrowings of $50.0 million under our Senior Secured Credit Facility. We have analyzed this transaction under the guidance provided by SFAS No. 141, “Accounting for Business Combinations” (“SFAS 141”) and have determined that the transaction will be read in conjunction withaccounted for as a business combination. At this time, we are unable to make a determination of the accompanying unaudited consolidated financial statementsallocation of the purchase price to the assets acquired and related notes asthe liabilities assumed.
19
Item 2. Management’s Discussion and Analysis of September 30, 2007Financial Condition and for the three and nine months ended September 30, 2007 and 2006, included elsewhere herein.Results of Operations.
Overview
We believe that we are
Key Energy Services, Inc. and its wholly owned subsidiaries (collectively, the leading onshore, rig-based well servicing contractor in the United States. Since 1994, we have grown rapidly through a series of over 100 acquisitions,“Company,” “we,” “us,” “its,” and today we provide“our”) provides a complete range of well services to major oil companies and independent oil and natural gas production companies;companies, including rig-based well maintenance, workover, well completion, and recompletion services;services, oilfield transportation services;services, pressure pumping services, fishing and rental services; pressure pumping services;services, and ancillary oilfield services.
We believe that we are the leading onshore, rig-based well servicing contractor in the United States. We operate in most major oil and natural gas producing regions of the United States as well as internationally in Argentina and Mexico. We also have a technology development company based in Canada.
We operate in three business segments:
Well Servicing:Servicing
We provide a broad range of well services, including rig-based services, oilfield transportation services and ancillary oilfield services. Our well service rig fleet is used to perform four major categories of rig services for our customers: (i) maintenance, (ii) workover, (iii) completion, and (iv) plugging and abandonment services. Our fluid transportation services include: (i) vacuum truck services, (ii) fluid transportation services, and (iii) disposal services for operators whose oil or natural gas wells produce saltwater and other fluids. In addition, we are a supplier of frac tanks which are used for temporary storage of fluids used in conjunction with fluid hauling operations and we also provide cased-hole electric wireline services.
Pressure Pumping Services:Services
We provide a broad range of stimulation and completion services, also known as pressure pumping services. Our primary services include well stimulation and cementing services. Well stimulation includes fracturing, nitrogen and acidizing services. These services (which may be used in completion and workover services) are used to enhance the production of oil and natural gas wells from formations which exhibit restricted flow of oil and natural gas. In the fracturing process, we typically pump fluid and sized sand, or proppants, into a well at high pressure in order to fracture the formation and thereby increase the flow of oil and natural gas. With our cementing services, we pump cement into a well between the casing and the wellbore. We provide pressure pumping services in the Permian Basin of Texas, the Barnett Shale of North Texas, the Mid-Continent region of Oklahoma and in the San Juan Basin. In addition, we provide cementing services in California.
Fishing &and Rental Services:Services
We provide fishing and rental services in the Gulf Coast, Mid-Continent and Permian Basin regions of the United States, as well as in the RockiesRocky Mountains and California. Fishing services involve recovering lost or stuck equipment in the wellbore andusing a “fishing tool”tool,” which is a downhole tool designed to recover any such equipment lost in the wellbore. We also offer a full line of services and rental equipment designed for use both on landonshore and offshore for drilling and workover services. Our rental tool inventory consists of tubulars, handling tools, pressure-controlled equipment, power swivels and foam air units.
The following discussion and analysis should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes as of March 31, 2008 and for the three months ended March 31, 2008 and 2007, included elsewhere herein, and the audited financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.
Performance Measures
In determining the overall health of the oilfield service industry, we believe that the Baker Hughes U.S. land drilling rig count is the best barometer of capital spending and activity levels, since this data is made publicly available on a weekly basis. Historically, our activity levels have correlated well with the capital spending by oil and natural gas producers. When commodity prices are strong, capital spending tends to be high, as illustrated by the Baker Hughes U.S. land drilling rig count. As the following table indicates, the land drilling rig count increased significantlyhas remained high over the past several quarters as commodity prices, both oil and natural gas, generally increased. have continued to increase.
3120
|
| WTI Cushing |
| NYMEX Henry Hub |
| Average Baker Hughes |
| ||
|
|
|
|
|
|
|
| ||
2006: |
|
|
|
|
|
|
| ||
First Quarter |
| $ | 63.27 |
| $ | 7.84 |
| 1,440 |
|
Second Quarter |
| $ | 70.41 |
| $ | 6.65 |
| 1,539 |
|
Third Quarter |
| $ | 70.42 |
| $ | 6.17 |
| 1,626 |
|
Fourth Quarter |
| $ | 59.98 |
| $ | 7.24 |
| 1,634 |
|
|
|
|
|
|
|
|
| ||
2007: |
|
|
|
|
|
|
| ||
First Quarter |
| $ | 58.08 |
| $ | 7.18 |
| 1,651 |
|
Second Quarter |
| $ | 64.97 |
| $ | 7.66 |
| 1,680 |
|
Third Quarter |
| $ | 75.46 |
| $ | 6.24 |
| 1,717 |
|
|
| WTI Cushing Oil (1) |
| NYMEX Henry |
| Average Baker |
| ||
|
|
|
|
|
|
|
| ||
2008: |
|
|
|
|
|
|
| ||
First Quarter |
| $ | 97.94 |
| $ | 8.74 |
| 1,712 |
|
|
|
|
|
|
|
|
| ||
2007: |
|
|
|
|
|
|
| ||
First Quarter |
| $ | 58.08 |
| $ | 7.18 |
| 1,651 |
|
Second Quarter |
| $ | 64.97 |
| $ | 7.66 |
| 1,680 |
|
Third Quarter |
| $ | 75.46 |
| $ | 6.24 |
| 1,717 |
|
Fourth Quarter |
| $ | 90.75 |
| $ | 7.39 |
| 1,733 |
|
(1) Represents the average crude oil or natural gas price respectively, for each of the periods presented. Source: Bloomberg/Energy Information Administration
(2) Source: www.bakerhughes.com.www.bakerhughes.com
Internally, we measure activity levels in our Well Servicing segment primarily through our rig and trucking hours. As capital spending by oil and natural gas producers increases, demand for well servicing activitiesour services also rises, resulting in increased rig and trucking services and more hours worked. While overall demand for the services we provide has increased during 2007, ourConversely, when activity levels have declined since 2006 due to increased capacity entering the marketplace. In addition, if activity levels were to decline due to lower spending by oil and natural gas producers, we would provide fewer rig and trucking services, which would resultresults in lower hours worked. The number of rig and trucking hours, as well as pricing, may also be affected by increases in industry capacity. We publicly release our monthly rig and trucking hours. The following table presents our quarterly rig and trucking hours from 20062007 through the thirdfirst quarter of 2007.2008.
|
| Rig Hours |
| Trucking Hours |
|
| Rig Hours |
| Trucking Hours |
|
2006: |
|
|
|
|
| |||||
|
|
|
|
|
| |||||
2008: |
|
|
|
|
| |||||
First Quarter |
| 663,819 |
| 609,317 |
|
| 659,462 |
| 585,040 |
|
Second Quarter |
| 679,545 |
| 602,118 |
| |||||
Third Quarter |
| 677,271 |
| 587,129 |
| |||||
Fourth Quarter |
| 637,994 |
| 578,471 |
| |||||
Total 2006: |
| 2,658,629 |
| 2,377,035 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
2007: |
|
|
|
|
|
|
|
|
|
|
First Quarter |
| 625,748 |
| 571,777 |
|
| 625,748 |
| 571,777 |
|
Second Quarter |
| 611,890 |
| 583,074 |
|
| 611,890 |
| 583,074 |
|
Third Quarter |
| 597,617 |
| 570,356 |
|
| 597,617 |
| 570,356 |
|
Fourth Quarter |
| 614,444 |
| 583,191 |
| |||||
Total 2007 |
| 2,449,699 |
| 2,308,398 |
|
32
Market Conditions – Quarter Ended March 31, 2008
Industry fundamentals in the U.S. marketplace remain strong as crude oil prices averaged $75.46 per barrel during the September 2007 quarter and averaged approximately $85.66 per barrel during the month of October. While natural gas prices averaged $6.24 per MMbtu during the September 2007 quarter, natural gas prices increased to an average approximately $7.22 per MMbtu during the month of October. We believe the increase in natural gas prices is seasonally related as natural gas prices tend to increase in the winter months. Industry activity levels, as measured by the
The Baker Hughes land drilling rig count improved slightlyaveraged 1,712 during the September 2007first quarter asof 2008, an increase of approximately 3.7% from the rig count averaged 1,717 rigs compared to 1,680 rigsaverage of 1,651 in the June 2007 quarter.first quarter of 2007. The higher drilling rig count totaled 1,738 on November 2, 2007.
According tois indicative of the Energy Information Association, there was approximately 3.5 Tcfstrength of natural gas in storage as of November 1, 2007. This is 8.4% higher than the five-year average and the current high levels of natural gas storage have led to concern that natural gas prices could be weak in the event that the United States has a warm winter and demand for natural gas deteriorates. As a result, natural gas prices averaged $6.24 during the September 2007 quarter, but have since improved modestly to $7.22 in the month of October 2007. Although natural gas prices have declined significantly from earlier this year, the NYMEX 12-month strip averaged over $7.50 per MMbtu as of November 1, 2007, a levelU.S. marketplace, which is still strong fordirectly associated with the strength of oil and natural gas producers.prices. Overall industry demand for the types of services we provide has remained high.
Despite
Including the recent declines in natural gas prices, there does not appear to be an impact to U.S. natural gas-directed drilling. In fact,effect of acquisitions made during the Baker Hughes land drilling rig count totaled 1,738 on November 2,third and fourth quarters of 2007, which is near the 20-year high of 1,754. While there is typically a lag between the time commodity prices change and when drillingactivity levels are impacted, recent oilfield service industry reports show a rise in the levelfirst quarter of land drilling permits,2008 (as measured by our rig and truck hours) were higher compared to the same period in 2007. Acquisitions made during the third and fourth quarters of 2007 contributed approximately 72,000 rig hours and 10,500 trucking hours during the first quarter of 2008. Additionally, our Mexico operations contributed approximately 6,000 rig hours during the first quarter of 2008, as compared to zero in the same period of 2007. Absent the increases in activity due to acquisitions and international expansion, our rig hours were down in the first quarter of 2008 as compared to the same period in 2007 and our trucking hours were essentially flat. We anticipated these changes in activity levels because of the increased supply of well service rigs and trucking assets in the market. However, the strategic acquisitions made during the third and fourth quarters of 2007 more than offset the decline in our rig hours. In response to lower utilization of our assets, we began reducing pricing for some of our customers in certain markets during late 2007. We believe these reductions will lead to increased utilization of our equipment and recapture of market share.
In addition, we experienced an unexpected decline in activity in our Southeastern division (which principally covers Louisiana), and particularly in the inland barge rig market where we are the largest supplier. We believe that that the decrease was due primarily to customers delaying projects this is often a leading indicatoryear in light of future drilling activity. The risepoor weather conditions that had occurred in drilling permits suggestsprior first quarters and that drilling activity should remain strong.resulted in them suffering high incidences of standby charges.
21
Market Outlook for the Remainder of 2008
We believe that industry long-termour business remains strong and that our activity levels should remain stable despitewill improve for the recent softnessbalance of 2008. We believe that the slowdown in the Louisiana barge rig market in our Southeastern division has reversed, and that utilization rates will be higher for the remainder of the year than were experienced in the first quarter. The onshore segment in this region has improved from the fourth quarter as well, and our backlog is building.
Commodity prices are still at record levels and demand for well servicing remains strong. As of March 31, 2008, crude oil prices were in excess of $105 per barrel and natural gas prices.prices exceeded $10 per MMbtu. We remain positive about long term industry fundamentals. Our long-term positive outlook is based on (i) strengthbelieve that the current level of today’s oil price; (ii) a healthy 12-month strip for bothhigh oil and natural gas prices; (iii)prices should result in our belief thatcustomers increasing their capital spending by our customers should remain strong; (iv) preliminary evidence that the U.S. drilling rig count permit is rising,budgets in 2008, which we believe will result in higher drilling activity; and (v) our belief that natural gas wells drilled today are experiencing faster decline rates which should require more drilling to maintain natural gas production. In the short-term, our activity levels have been negatively impacted by new capacity additions in many of our markets. This has resulted in lower equipment utilization and pricing pressure for our services. We anticipate that this additional capacity will be minimized over the next few quarters as (i) capital expenditures for new equipment are expected to decline in 2008, (ii) as service providers use new equipment to retire older equipment, and (iii) through industry consolidation. We are, however, cognizant that a material decline in natural gas prices from today’s levels could result in further erosion of our rig and trucking hours while additional capacity in all of our segments could reducedrive demand for our services orhigher. We are also encouraged by the announcements by some of our customers stating their plans to increase their exploration and production budgets over 2007 levels.
Our 2008 activity levels and financial performance are also expected to increase as a result of the acquisitions we made during the third and fourth quarters of 2007 and the expansion of our Mexico operations. The Company’s recent Kings Tool and Western Drilling acquisitions in California are performing well and have been fully integrated into our operations. We believe that improvement in the Southeastern division, specifically the inland barge market, will continue. In addition, we anticipate that our Mexico operations will continue to expand during the remainder of 2008. We have five rigs working in Mexico as of the end of April 2008, and the sixth is expected to start working by the end of May. The Company anticipates that it will have three additional price pressurerig packages in Mexico by the third quarter of 2008 and up to two more units by the end of 2008. Additionally, we have secured pricing increases for our services.operations in Argentina and anticipate margins for those operations to continue to improve in 2008.
33During the first quarter, we deployed a strategy to increase market share in the shale plays, emphasizing offerings in gas regions. We have significantly increased our presence in the Barnett Shale, with a strong presence across most of our service offerings, and, we believe that we are a leading provider in each of the Fayette, Bakken and Marcellus Shale. We expect these markets to provide significant prospects for growth. Other growth opportunities for 2008 include the creation of a coiled tubing group that will consist of our existing fleet of coiled tubing units and six state-of-the-art coiled tubing units that are scheduled to be delivered in the second quarter of 2008. In addition, we intend to continue the expansion of our cased-hole electric wireline business. We currently anticipate that we will place an additional six cased-hole wireline trucks into service during 2008.
Because the demand for our services is generally correlated to commodity prices and drilling activity, our activity levels could be negatively impacted in the event commodity prices decline rapidly or unexpectedly. During the first quarter of 2008, our business continued to face increased competition due to additional capacity and new market entrants; however, we believe that industry capacity additions are beginning to moderate. A number of oilfield service companies, including us, have announced that capital spending will generally be lower in 2008 than 2007. This should reduce the rate of growth of new equipment entering the market.
Consolidated Results of Operations
22
Results of Operations
Key Energy Services, Inc. and Subsidiaries
Condensed Consolidated Statements of Operations
(In thousands)
(Unaudited)
|
| Three Months Ended September 30, |
| Nine Months Ended September 30, |
| |||||||||||||||
|
| 2007 |
| 2006 |
| 2007 |
| 2006 |
|
| Three Months Ended March 31, |
| ||||||||
|
|
|
|
|
|
|
|
|
|
| 2008 |
| 2007 |
| ||||||
REVENUES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Well servicing. |
| $ | 311,304 |
| $ | 323,655 |
| $ | 931,289 |
| $ | 884,962 |
| |||||||
Well servicing |
| $ | 348,878 |
| $ | 311,160 |
| |||||||||||||
Pressure pumping |
| 77,112 |
| 69,038 |
| 228,478 |
| 181,035 |
|
| 81,852 |
| 74,077 |
| ||||||
Fishing and rental services |
| 25,551 |
| 24,907 |
| 73,629 |
| 71,596 |
| |||||||||||
Fishing and rental |
| 25,669 |
| 23,682 |
| |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Total revenues. |
| 413,967 |
| 417,600 |
| 1,233,396 |
| 1,137,593 |
|
| 456,399 |
| 408,919 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
COSTS AND EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Well servicing |
| 193,151 |
| 185,486 |
| 545,983 |
| 536,000 |
|
| 211,751 |
| 175,529 |
| ||||||
Pressure pumping |
| 49,357 |
| 37,305 |
| 143,299 |
| 97,764 |
|
| 53,779 |
| 46,533 |
| ||||||
Fishing and rental services |
| 14,974 |
| 14,610 |
| 41,934 |
| 42,318 |
| |||||||||||
Fishing and rental |
| 16,111 |
| 13,451 |
| |||||||||||||||
Depreciation and amortization |
| 31,185 |
| 30,192 |
| 91,483 |
| 85,930 |
|
| 39,976 |
| 29,614 |
| ||||||
General and administrative |
| 56,569 |
| 43,624 |
| 164,787 |
| 142,042 |
|
| 67,732 |
| 52,064 |
| ||||||
Interest expense. |
| 7,914 |
| 10,410 |
| 26,231 |
| 29,017 |
| |||||||||||
Loss (gain) on sale of assets, net |
| 2,398 |
| (817 | ) | 1,945 |
| (3,062 | ) | |||||||||||
Interest expense, net of amounts capitalized |
| 10,040 |
| 9,348 |
| |||||||||||||||
(Gain) loss on sale of assets |
| (266 | ) | 250 |
| |||||||||||||||
Interest income |
| (1,851 | ) | (1,841 | ) | (5,589 | ) | (3,868 | ) |
| (508 | ) | (1,940 | ) | ||||||
Other, net |
| 438 |
| (191 | ) | 326 |
| 280 |
| |||||||||||
Other expense (income), net |
| 877 |
| (624 | ) | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Total costs and expenses, net |
| 354,135 |
| 318,778 |
| 1,010,399 |
| 926,421 |
|
| 399,492 |
| 324,225 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Income before income taxes |
| 59,832 |
| 98,822 |
| 222,997 |
| 211,172 |
|
| 56,907 |
| 84,694 |
| ||||||
Income tax expense |
| (23,936 | ) | (37,937 | ) | (86,775 | ) | (80,641 | ) |
| (22,457 | ) | (32,504 | ) | ||||||
Minority interest |
| 34 |
| — |
| |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
NET INCOME |
| $ | 35,896 |
| $ | 60,885 |
| $ | 136,222 |
| $ | 130,531 |
|
| $ | 34,484 |
| $ | 52,190 |
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2006
Revenue:
Well Servicing: Well servicing revenues decreased 3.8% to $311.3For the three months ended March 31, 2008, our net income was $34.5 million, which represents a 33.9% decrease from the three months ended March 31, 2007. Our earnings per fully diluted share for the quarter ended September 30, 2007period was $0.27 per share compared to revenue of $323.7 million$0.39 per fully diluted share for the quarter ended September 30, 2006.same period in 2007. The decreasedecline in revenue is largely attributable to lower rig and trucking hours, offset modestly by increased revenue from the Company’s cased-hole wireline operation and operations under the Mexico contract, which commenced in the second quarter of 2007. For the September 2007 quarter, the Company’s composite segment revenue to total hours (defined as rig hours plus trucking hours) was approximately $266 per hour compared to approximately $256 per hour for the September 2006 quarter. The improvement is largely attributable to the Mexico contract and the incremental revenue from the cased-hole electric wireline business. Rig hours for the Company decreased 11.8% to 597,617 in the September 2007 quarter from 677,271 in the September 2006 quarter while the Company’s trucking hours decreased 2.9% to 570,356 in the September 2007 quarter from 587,129 in the September 2006 quarter. The decrease in the rig and trucking hours is largely attributable to the impact of lost market share due to new capacity additions.
Pressure Pumping Services: Pressure pumping services (“PPS”) segment revenues increased 11.7% to $77.1 million for the quarter ended September 30, 2007 compared to revenue of $69.0 million for the quarter ended September 30, 2006. The increase in revenue is attributable to incremental pressure pumping equipment and higher activity levels. At September 30, 2007, the Company had approximately 203,000 horsepower of pumping equipment as compared to approximately 162,000 horsepower at September 30, 2006. The Company’s pressure pumping segment performs several different services including fracturing, cementing, acidizing, nitrogen services, abandonment and other miscellaneous jobs. Generally, the
34
fracturing and cementing jobs represent the substantial majority of the segment’s revenue. Fracturing jobs totaled 535 in the September 2007 quarter compared to 405 the September 2006 quarter while cementing jobs totaled 594 in the September 2007 quarter compared to 538 the September 2006 quarter.
Fishing and Rental Services: Fishing and rental services (“FRS”) segment revenues for the quarter ended September 30, 2007 increased 2.6% to $25.6 million compared to revenue of $24.9 million for the quarter ended September 30, 2006. The increase in revenue is attributable to additional rental equipment and stable market conditions.
Direct Costs:
Well Servicing: Well servicing direct costs increased 4.1% to $193.2 million for the quarter ended September 30, 2007 compared to $185.5 million for the quarter ended September 30, 2006. Despite modestly lower rig and trucking hours, direct costs increased primarily due to higher vehicular liability reserves, workers’ compensation, health insurance expense and higher repairs and maintenance expense, offset by lower incentive compensation expense. Direct costs as a percent of well servicing segment revenue were 62.0% for the quarter ended September 30, 2007 as compared to 57.3% for the quarter ended September 30, 2006.
Pressure Pumping Services: PPS direct costs increased 32.3% to $49.4 million for the quarter ended September 30, 2007 compared to $37.3 million for the quarter ended September 30, 2006. The increase in direct costs is largely attributable to increased sand and chemical purchases as well as higher trucking and freight costs and higher repair and maintenance expense. The higher activity is a function of continued demand for pressure pumping services and incremental additions of pressure pumping equipment. Direct costs as a percent of PPS segment revenue were 64.0% for the quarter ended September 30, 2007 as compared to 54.0% for the quarter ended September 30, 2006.
Fishing and Rental Services: FRS direct costs increased by 2.5%, or $0.4 million, to $15.0 million for the quarter ended September 30, 2007 compared to $14.6 million for the quarter ended September 30, 2006. The increase in costs is due primarily to increased repair and maintenance and increased insurance premiums. Direct costs as a percent of total FRS segment revenue improved slightly to 58.6% for the quarter ended September 30, 2007 compared to 58.7% for the quarter ended September 30, 2006.
General and Administrative Expense
General and administrative (“G&A”) expenses increased 29.7%, to $56.6 million for the quarter ended September 30, 2007 compared to $43.6 million for the quarter ended September 30, 2006. G&A increased primarily due to higher professional fees ($9.1 million) and higher equity-based compensation ($1.8 million). The third quarter 2006 results also include the effects of a legal settlement, which resulted in a benefit of approximately $7.3 million during the third quarter of 2006. Absent this benefit, the increase in professional fees would be approximately $1.8 million and the overall increase in G&A would be approximately $5.7 million. The increase in professional feesearnings was primarily attributable to the Company’s accounting and internal controls processesincreased direct costs associated with businesses acquired during the recently-completed three year audit. G&Athird and fourth quarters of 2007, increased depreciation and amortization expense, asand higher general and administrative costs, partially offset by higher revenues. A detailed review of our operations, including a percentreview of revenueour segments, for the quarter ended September 30, 2007 totaled 13.7%of 2008 compared to 10.4% for the quarter ended September 30, 2006.same period in 2007 is provided below.
Interest ExpenseRevenues
Interest expense declined 24.0% to $7.9 million for the quarter ended September 30, 2007 compared to $10.4 million for the quarter ended September 30, 2006. The decline is primarily attributable to higher capitalized interest expense and lower interest rates and commitment fees on our Senior Secured Credit Facility. Interest expense as a percent of
Our revenue for the quarter ended September 30, 2007 totaled 1.9% compared to 2.5% for the quarter ended September 30, 2006.
Depreciation Expense
Depreciation expense was essentially flat at $31.2 million for the quarter ended September 30, 2007 compared to $30.2 million for the quarter ended September 30, 2006. During the first quarter of 2007, management revised its estimate of the useful lives of certain well servicing assets, which resulted in an additional $1.4 million of depreciation expense for the three months ended September 30, 2007. For the quarter ended September 30, 2007, the Company spent approximately $49.0March 31, 2008 increased $47.5 million, on capital expenditures as comparedor 11.6%, to $48.8$456.4 million for the quarter ended September 30, 2006. Depreciation
35
expense as a percent of revenue for the quarter ended September 30, 2007 totaled 7.5% compared to 7.2% for the quarter ended September 30, 2006.
Income Taxes
Our income tax expense was $23.9 million and $37.9from $408.9 million for the three months ended September 30,March 31, 2007. Changes in revenue for each of our reportable segments were (in millions):
|
| Change from Three |
| |
|
|
|
| |
Well servicing segment |
| $ | 37.7 |
|
Pressure pumping segment |
| 7.8 |
| |
Fishing and rental segment |
| 2.0 |
| |
Total change |
| $ | 47.5 |
|
Businesses acquired during the third and fourth quarters of 2007 and 2006, respectively. Our effective tax rate for those same periods was 40.0% and 38.4%, respectively. The differences betweencontributed approximately $45.0 million to the rates between periods relate largely to nondeductible expense for executive compensation and other nondeductible items, asincrease in well as the Texas Margin Tax. Differences between the statutory rate and the effective rate are due primarily to state and foreign income taxes and nondeductible expenditures.
Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006
Revenue
Well Servicing: Well servicing revenues over the first quarter of 2007. Other increases in well servicing revenues were attributable to the expansion of our cased-hole electric wireline business, whose revenues increased 5.2% to $931.3 approximately $4.6
23
million for the nine months ended September 30, 2007first quarter of 2008 compared to revenue of $885.0 million for the nine months ended September 30, 2006. The increase in revenue is largely attributable to higher pricing for the Company’s services and higher rig hours, offset somewhat by lower trucking hours. For the nine months ended September 30, 2007, the Company’s composite segment revenue to total hours (as defined as rig hours plus trucking hours) was approximately $261 per hour compared to approximately $232 per hour for the nine months ended September 30, 2006. Rig hours for the Company decreased 9.2% to 1,835,254 in the first nine monthsquarter of 2007, from 2,020,635and the expansion of our international operations in the first nine monthsMexico, which contributed $5.7 million of 2006 while the Company’s trucking hours decreased 4.1% to 1,725,207 in the first nine months of 2007 from 1,798,564 in the first nine months of 2006. The decrease in rig hours and trucking hours is due primarily to lost market share and to a lesser extent, inclement weather in early 2007.
Pressure Pumping Services: PPS segment revenues increased 26.2% to $228.5 million for the nine months ended September 30, 2007 compared to revenue of $181.0 million for the nine months ended September 30, 2006. The increase in revenue is attributable to incremental pressure pumping equipment and higher activity levels. At September 30, 2007, the Company had approximately 203,000 horsepower of pumping equipment as compared to approximately 162,000 horsepower at September 30, 2006. The Company’s pressure pumping segment performs several different services including fracturing, cementing, acidizing, nitrogen services, abandonment and other miscellaneous jobs. Generally, the fracturing and cementing jobs represent the substantial majority of the segment’s revenue. Fracturing jobs totaled 1,546 during the first nine monthsquarter of 2008. Absent these items, well servicing revenue decreased approximately $17.6 million. This decrease was driven primarily by lower activity levels and reduced pricing in our domestic well servicing operations as new competition and increased capacity entered the marketplace, partially offset by higher rates and increased rig utilization for our operations in Argentina.
Revenues from our pressure pumping operations increased $7.8 million, or 10.5%, for the first quarter of 2008 compared to the same period in 2007. During 2007, we expanded our pressure pumping operations in the Barnett Shale, and this segment saw a corresponding increase in the number of frac jobs performed for our customers. Offsetting the increase in frac revenue was a decline in the number of cement jobs performed by this segment, due mainly to increased competition in the Permian Basin region and a reduction in our pricing as a result of increased competition from new market entrants.
Revenues for our fishing and rental operations increased $2.0 million, or 8.4%, for the first quarter of 2008 compared to the same period in 2007. Poor weather in January and February of 2007 compared to 1,157hampered the first nine monthsoperations of 2006 while cementing jobs totaled 1,537our Fishing and Rental segment during the first nine monthsquarter of 2007, compared to 1,488and this segment’s operations saw a significant increase in activity during the first nine monthsquarter of 2006.
Fishing and Rental Services: FRS segment revenues for2008 that corresponded to the nine months ended September 30, 2007 increased 2.8% to $73.6 million compared to revenue of $71.6 million for the nine months ended September 30, 2006. Theoverall increase in revenue is primarily attributable to continued stable demand for services.activity in the sector.
Direct Costs
Well Servicing: Well servicing direct
Direct costs increased 1.9%$46.1 million, or 19.6%, to $546.0$281.6 million for the ninethree months ended September 30, 2007March 31, 2008 compared to $536.0$235.5 million for the ninethree months ended September 30, 2006.March 31, 2007. Direct costs as a percentage of revenue were 61.7% during 2008, versus 57.6% during 2007. The change in direct costs was the result of (in millions):
|
| Change from Three |
| |
|
|
|
| |
Employee compensation |
| $ | 8.4 |
|
Pressure pumping supplies and equipment |
| 6.1 |
| |
Well servicing supplies and equipment |
| 5.9 |
| |
Business acquisitions during 2007 |
| 26.3 |
| |
Self-insurance costs |
| (1.9 | ) | |
Other |
| 1.3 |
| |
Total change |
| $ | 46.1 |
|
Exclusive of the effects of acquisitions made during the third and fourth quarters of 2007, employee compensation costs, which include salaries, bonuses, 401(k) matching and related expenses, increased approximately $8.4 million primarily as a result of increased wage rates, higher incentive compensation and increased headcount. The labor market for our employees continues to be extremely tight, and in order to retain quality personnel, we have increased wage rates and bonuses from their levels in the first quarter of 2007.
Supply and equipment costs for our pressure pumping operations, which primarily include frac sand, chemicals, and the transportation costs associated with obtaining those supplies, increased approximately $6.1 million, or 18.1%, during the first quarter of 2008 compared to the same period in 2007. The increase in these costs was driven primarily by the expansion of our pressure pumping fleet during 2007, and by increasing market prices for the purchase and transportation of supplies. During the fourth quarter of 2007, we began purchasing our own trucks to haul frac sand in order to reduce our reliance on third-party transportation services, and the cost savings associated with this partially offset the increase.
Supplies and equipment for our well servicing operations increased approximately $5.9 million, or 11.1%, during the first quarter of 2008 compared to the same period in 2007. A major contributor to the increase was the cost of fuel, which increased approximately $4.8 million, or 39.0%.
Acquisitions made during the third and fourth quarters of 2007 also contributed to the increase in direct costs during the first quarter of 2008 compared to the same period in 2007. Direct costs from acquired businesses included approximately $12.7 million of employee-compensation related costs, $9.1 million of repairs and maintenance and other equipment-related costs, and $4.5 million of other direct costs.
The Company’s self-insurance costs, which are primarily associated with workers’ compensation, vehicular liability coverage and insurance premiums, decreased during the first quarter of 2008 compared to the same period in 2007. We have
24
focused on improving safety performance, and over the last several years the number of reportable incidents has declined, leading to lower current period premiums and costs associated with incidents.
Depreciation and Amortization
Depreciation and amortization expense increased approximately $10.4 million during the first quarter of 2008 compared to the first quarter of 2007. Assets acquired through business combinations during the third and fourth quarters of 2007 contributed approximately $6.1 million of depreciation and amortization expense during the first quarter of 2008. The remainder of the increase can be attributed to our larger fixed asset base; since the end of the first quarter of 2007, we have cumulatively spent approximately $196.6 million on capital expenditures.
General and Administrative
General and administrative expenses increased $15.7 million, or 30.1%, to $67.7 million for the three months ended March 31, 2008, compared to $52.1 million for the three months ended March 31, 2007. The change in general and administrative expense was the result of (in millions):
|
| Change from Three |
| |
|
|
|
| |
Employee compensation |
| $ | 6.6 |
|
Legal reserves and settlements |
| 2.8 |
| |
Bad debt |
| 0.5 |
| |
Acquisitions during 2007 |
| 3.3 |
| |
Other |
| 2.5 |
| |
Total change |
| $ | 15.7 |
|
Employee compensation, which includes salaries, cash bonuses, equity-based compensation, health insurance, 401(k) matching and other related costs, increased $6.6 million to $31.3 million for the three months ended March 31, 2008 compared to $24.7 million for the three months ended March 31, 2007. Increases in general and administrative employee compensation were driven primarily by the expansion of our business development efforts, which included the reassignment of certain operational employees previously classified as direct costs of approximately $1.9 million and the hiring of additional employees of approximately $1.1 million, and the expansion of our international operations, which contributed an additional $1.4 million in general and administrative employee compensation. All other general and administrative employee compensation costs increased approximately $0.8 million during the first quarter of 2008. Absent the expansion of our business development operations, corporate general and administrative headcount remained largely unchanged from the first quarter of 2007. Total equity-based employee compensation was $3.7 million for the quarter ended March 31, 2008, compared to $2.3 million for the first quarter of 2007. Increases in equity-based compensation were driven primarily by equity grants made to our employees during the third quarter of 2007.
Reserves and settlements for legal matters increased approximately $2.8 million during the first quarter of 2008 compared to the same period in 2007. This increase was related to several matters and reflects management’s assessment of the probability and of and estimates of loss from the outcome of these matters.
Excluding bad debt expense related to our acquisitions, bad debt expense increased $0.5 million to $0.9 million during the first quarter of 2008, compared to $0.4 million during the same period in 2007. The increase in bad debt was primarily attributable to allowances recorded due to our assessment of the collectibility of certain receivables.
Business acquisitions completed during the third and fourth quarters of 2007 contributed approximately $3.3 million of general and administrative expenses during the first quarter of 2008. General and administrative expenses from acquired businesses during the three months ended March 31, 2008 consisted of approximately $1.6 million of employee compensation and related costs and $1.7 million of other general and administrative costs.
Our professional fees were relatively flat between the first quarter of 2008, compared to the first quarter of 2007. We anticipate these fees to decline over the course of 2008 due to the timing of audit costs and an overall reduction in costs.
Interest Expense
Interest expense increased $0.7 million, or 7.4%, for the three months ended March 31, 2008, compared to the same period in 2007. The increase in interest expense is primarily attributable to increased debt levels and a higher weighted average interest rate on our outstanding debt.
25
Interest Income
Interest income declined approximately $1.4 million to $0.5 million for the first quarter of 2008 compared to $1.9 million for the first quarter of 2007. The decline in interest income is primarily attributable to the reduction in our cash and cash equivalents and short-term investments, as a result of cash payments during the fourth quarter of 2007 in connection with our acquisition of Moncla Well Service, Inc. and related entities.
Income Tax Expense
Our income tax expense decreased $10.0 million, or 30.9%, to $22.5 million for the first quarter of 2008 from $32.5 million for the first quarter of 2007. The decrease in income tax expense during the first quarter of 2008 is primarily attributable to lower taxable income. Our effective tax rates were 39.5% and 38.4% for the three months ended March 31, 2008 and 2007, respectively. Our effective tax rate has increased because of our expansion into more international tax jurisdictions, while our taxable income has decreased primarily due to margin contractions in certain of our core segments, offset by higher taxable income for our pressure pumping operations, and the acquisitions we made during the third and fourth quarters of 2007.
Results of Operations by Segment
The following table shows operating results for each of our three segments for the three month periods ended March 31, 2008 and 2007, respectively:
|
| Three Months Ended March 31, |
| |||||||
|
| 2008 |
| 2007 |
| Increase |
| |||
|
| (in thousands, except for percentages) |
| |||||||
|
|
|
|
|
|
|
| |||
Well Servicing segment |
|
|
|
|
|
|
| |||
Revenues |
| $ | 348,878 |
| $ | 311,160 |
| $ | 37,718 |
|
Direct costs |
| 211,751 |
| 175,529 |
| 36,222 |
| |||
Gross profit |
| 137,127 |
| 135,631 |
| 1,496 |
| |||
Gross margin |
| 39.3 | % | 43.6 | % | -4.3 | % | |||
|
|
|
|
|
|
|
| |||
Pressure Pumping segment |
|
|
|
|
|
|
| |||
Revenues |
| $ | 81,852 |
| $ | 74,077 |
| $ | 7,775 |
|
Direct costs |
| 53,779 |
| 46,533 |
| 7,246 |
| |||
Gross profit |
| 28,073 |
| 27,544 |
| 529 |
| |||
Gross margin |
| 34.3 | % | 37.2 | % | -2.9 | % | |||
|
|
|
|
|
|
|
| |||
Fishing and Rental segment |
|
|
|
|
|
|
| |||
Revenues |
| $ | 25,669 |
| $ | 23,682 |
| $ | 1,987 |
|
Direct costs |
| 16,111 |
| 13,451 |
| 2,660 |
| |||
Gross profit |
| 9,558 |
| 10,231 |
| (673 | ) | |||
Gross margin |
| 37.2 | % | 43.2 | % | -6.0 | % |
Well Servicing Segment
Revenues for our Well Servicing segment increased $37.7 million, or 12.1%, to $348.9 million for the three months ended March 31, 2008 compared to $311.2 million for the three months ended March 31, 2007. Businesses acquired during the third and fourth quarters of 2007 contributed approximately $45.0 million to the increase in our Well Servicing segment revenues for the first quarter of 2007. Other increases in well servicing revenues were attributable to the expansion of our cased-hole electric wireline business, whose revenues increased approximately $4.6 million for the first quarter of 2008 compared to the first quarter of 2007, and the expansion of our international operations in Mexico, which contributed $5.7 million of revenue during the first quarter of 2008. Absent these items, well servicing revenue decreased approximately $17.6 million. This decrease was driven primarily by lower activity levels and reduced pricing in our domestic well servicing operations, resulting from new competition and increased capacity entered the marketplace, partially offset by higher rates and increased rig utilization for our operations in Argentina.
26
Direct costs for our Well Servicing segment were $211.8 million during the three months ended March 31, 2008, which represented an increase of $36.2 million, or 20.6%, from the same period in 2007. The increase in direct costs for our Well Servicing segment was attributable to (in millions):
|
| Change from Three |
| |
|
|
|
| |
Employee compensation. |
| $ | 6.9 |
|
Business acquisitions during 2007 |
| 26.3 |
| |
Self-insurance costs |
| (2.3 | ) | |
Equipment and supplies. |
| 5.9 |
| |
Other |
| (0.6 | ) | |
Total change |
| $ | 36.2 |
|
Employee compensation costs, which include salaries, bonuses, health insurance, 401(k) matching and related payroll taxes, increased approximately $6.9 million for the first quarter of 2008 compared to the same period in 2007, primarily as a result of increased wage rates, higher incentive compensation and increased headcount. The labor market for our employees continues to be extremely tight, and in order to retain quality personnel, we have increased wage rates and bonuses from their levels in the first quarter of 2007.
Businesses acquired during 2007 contributed approximately $26.3 million of direct costs during the first quarter of 2008. Direct costs from acquired businesses included approximately $12.7 million of employee compensation-related expenses, $9.1 million of repairs and maintenance and other equipment-related costs, and $4.5 million of other direct costs.
Self-insurance costs for our Well Servicing segment, which are primarily associated with workers’ compensation, vehicular liability coverage and insurance premiums, decreased approximately $2.3 million during the first quarter of 2008 compared to the first quarter of 2007. We have focused on improving safety performance, and over the last several years the number of reportable incidents has declined, leading to lower current period premiums and costs associated with incidents.
Equipment and supply costs for our Well Servicing segment increased approximately $5.9 million during the first quarter of 2008 compared to the same period in 2007. The majority of the increase in equipment and supply costs relates to the increased price of fuel. Fuel costs for our well servicing operations increased approximately $4.8 million, or 39.0%, from the first quarter of 2007.
Pressure Pumping Segment
Revenues for our Pressure Pumping segment increased $7.8 million, or 10.5%, to $81.9 million for the quarter ended March 31, 2008 compared to $74.1 million for the three months ended March 31, 2007. Increased revenue in our Pressure Pumping segment is primarily attributable to the addition of several frac crews to serve our customer base in the Barnett Shale region, partially offset by declines in cementing operations due to increased freight, repairs and maintenance and chemical costs and insurance premiums. These increases were offset somewhat by decreased fuel and equipment rental costs. competition.
Direct costs as a percent of total well servicefor our Pressure Pumping segment revenue improved to 58.6% forwere $53.8 million during the ninethree months ended September 30, 2007 compared to 60.6% forMarch 31, 2008, which represented an increase of $7.2 million, or 15.6%, from the nine months ended September 30, 2006.
Pressure Pumping: PPS direct costs increased 46.6% to $143.3 million for the nine months ended September 30, 2007 compared to $97.8 million for the nine months ended September 30, 2006.same period in 2007. The increase in direct costs is largelyfor our Pressure Pumping segment was attributable to (in millions):
|
| Change from Three |
| |
|
|
|
| |
Employee compensation. |
| $ | 1.0 |
|
Equipment costs |
| 1.3 |
| |
Supply costs |
| 4.8 |
| |
Other |
| 0.1 |
| |
Total change |
| $ | 7.2 |
|
27
Employee compensation costs for our pressure pumping operations increased approximately $1.0 million for the first quarter of 2008 compared to the same period in 2007. Increases in employee compensation were driven primarily by higher wage rates for our crews and the addition of several frac crews during 2007 to support our increased operations in the Barnett Shale.
Equipment and supply costs for our pressure pumping operations increased approximately $6.1 million during the first quarter of 2008 compared to the same period in 2007. The two major contributors to the increase in equipment and supply costs were the increased cost of fuel (approximately $1.7 million) and the increased cost of frac sand and chemical purchases as well as higher truckingchemicals ($2.8 million) and freightthe related costs higher fuel expenseto transport those items ($2.3 million). The increase in these costs was driven primarily by the expansion of our pressure pumping fleet during 2007, and higher repair and maintenance expense. Direct costs as a percent of total PPS segment revenue were 62.7%by increasing market prices for the nine months ended September 30,purchase and transportation of supplies. During the fourth quarter of 2007, comparedwe began purchasing our own trucks to 54.0% forhaul frac sand in order to reduce our reliance on third-party transportation services, and the nine months ended September 30, 2006.cost savings associated with this partially offset the increase.
Fishing and Rental Services:Segment FRS direct
Revenues for our fishing and rental operations increased $2.0 million, or 8.4%, for the first quarter of 2008 compared to the same period in 2007. Poor weather in January and February of 2007 hampered the operations of our Fishing and Rental segment during the first quarter of 2007, and this segment’s operations saw a significant increase in activity during the first quarter of 2008 that corresponded to the overall increase in activity in the sector.
Direct costs decreased slightly by 0.9%for our Fishing and Rental segment increased $2.7 million, or 19.8%, to $41.9$16.1 million for the nine months ended September 30, 2007first quarter of 2008 compared to $42.3$13.5 million for the ninefirst quarter of 2007. Increased direct costs for this segment are attributable to (in millions):
|
| Change from Three Months |
| |
|
|
|
| |
Employee compensation |
| $ | 0.6 |
|
Equipment costs. |
| 1.7 |
| |
Other |
| 0.4 |
| |
Total change. |
| $ | 2.7 |
|
Employee compensation costs for our fishing and rental operations increased approximately $0.6 million for the quarter ended March 31, 2008 compared to the same period in 2007. The increase in employee compensation was driven primarily by increased headcount, which increased approximately 5% in this segment during the first quarter of 2008 compared to the same period in 2007.
Equipment costs increased approximately $1.7 million for our fishing and rental operations during the three months ended September 30, 2006. IncreasesMarch 31, 2008 compared to the three months ended March 31, 2007. Contributing to the increase in equipment costs are increased fuel expenses (approximately $0.4 million) associated with higher gas and diesel prices, increases for supplies and small parts were more than offset by decreased repair and maintenance expenses. Direct costs as a percent of
36
total FRS segment revenue improved to 57.0% for the nine months ended September 30, 2007 compared to 59.1% for the nine months ended September 30, 2006.
General and Administrative Expense
General and administrative expense increased 16.0%, to $164.8 million for the nine months ended September 30, 2007 compared to $142.0 million for the nine months ended September 30, 2006. The increase in G&A expense is primarily attributable to higher professional fees ($15.70.4 million) associated with the Company’s accounting and internal controls processesexpansion of this segment’s deepwater operations in connection with the recently completed three-year audit, higher equity-based compensation ($3.7 million), and increased salaries associated with higher corporate headcount. 2006 results also include the effects of a legal settlement which resulted in a benefit of approximately $7.3 million for the nine months ended September 30, 2006. Absent this benefit, the increase in professional fees would be approximately $8.4 million and the overall increase in G&A would be approximately $15.5 million. These increases were offset by decreased expenses related to information technology services ($1.3 million). G&A expense as a percent of revenue for the nine months ended September 30, 2007 totaled 13.4% compared to 12.5% for the nine months ended September 30, 2006.
Interest Expense
Interest expense decreased 9.6% to $26.2 million for the nine months ended September 30, 2007 compared to $29.0 million for the nine months ended September 30, 2006. The decrease in interest expense was caused by increased capitalized interest due to increased Work in Progress and lower commitment fees on our Senior Secured Credit Facility. Interest expense as a percent of revenue for the nine months ended September 30, 2007 totaled 2.1% compared to 2.6% for the nine months ended September 30, 2006.
Depreciation Expense
Depreciation expense increased 6.5% to $91.5 million for the nine months ended September 30, 2007 compared to $85.9 million for the nine months ended September 30, 2006. During the first quarter of 2007, management revised its estimate of the useful lives of certain well servicing assets, which resulted in an additional $5.5 million of depreciation expense for the nine months ended September 30, 2007. For the nine months ended September 30, 2007, the Company spent approximately $167.8 million on capital expenditures as compared to $147.0 million for the nine months ended September 30, 2006. Depreciation expense as a percent of revenue for the nine months ended September 30, 2007 totaled 7.4% compared to 7.6% for the nine months ended September 30, 2006.
Income Taxes
Our income tax expense was $86.8 million and $80.6 million for the nine months ended September 30, 2007 and 2006, respectively. Our effective tax rate for those same periods was 38.9% and 38.2%, respectively. The differences between the rates between periods relate largely to nondeductible expense for executive compensationsouthern Louisiana, and other nondeductible items, including the Texas Margin Tax. Differences between the statutory rate and the effective rate are duethird-party expenses ($0.7 million) incurred by this segment associated primarily to state and foreign income taxes and nondeductible expenditures.with tool subrentals.
Liquidity and Capital Resources
We have historically funded our operations, including capital expenditures, from cash flow from operations and have funded growth opportunities, including acquisitions, through bank borrowings and the issuance of equity and long-term debt. In recent years, we have pursued a strategy of repaying indebtedness and have accomplished this objective by using cash generated by operations and cash proceeds from asset sales.
We anticipate that our capital expenditures, excluding acquisitions, for 2007 will be between $200 million and $210 million, of which we have spent approximately $168 million through September 30, 2007. We are presently targeting capital expenditures of approximately $175 million in 2008. We do not budget for acquisitions; however we are continually evaluating opportunities that fit our specific acquisition profile.
As of September 30, 2007, we had $155.9 million in cash, cash equivalents and short term investments and $65.0 million of availability under our revolving credit facility. On October 25, 2007, we paid approximately $123.3 million inHistorical Cash Flows
37The following table summarizes our cash flows for the three months ended March 31, 2008 and 2007:
28
|
| Three Months Ended March 31, |
| ||||
|
| 2008 |
| 2007 |
| ||
|
| (in thousands) |
| ||||
|
|
|
|
|
| ||
Net cash provided by operating activities |
| $ | 70,311 |
| $ | 86,850 |
|
Cash paid for capital expenditures |
| (30,375 | ) | (46,375 | ) | ||
Cash paid for short-term investments. |
| — |
| (83,077 | ) | ||
Proceeds received from sales of short-term investments |
| — |
| 18,635 |
| ||
Other investing activities, net |
| 9 |
| 265 |
| ||
Repayments of long-term debt and capital leases |
| (3,006 | ) | (3,591 | ) | ||
Cash paid to repurchase common stock |
| (65,376 | ) | — |
| ||
Other financing activities, net |
| 147 |
| — |
| ||
Effect of changes in exchange rates on cash. |
| (342 | ) | (370 | ) | ||
Net decrease in cash and cash equivalents |
| $ | (28,632 | ) | $ | (27,663 | ) |
Sources of Liquidity
Our sources of liquidity include our current cash in connection with the closing of our purchase of the Moncla companies. We have utilized, and expect to utilize in the future, bank and capital lease financing in order to obtain capital resources.
On November 5, 2007, the Company announced that it plans to offer up to $400 million of senior notes due 2017 through a private placement. Under the proposed terms of the offering certain of the Company’s domestic subsidiaries would fully and unconditionally guarantee the notes. The Company intends to use the net proceeds of the proposed offering to retire its outstanding $393 million of term loanscash equivalents, availability under our existing Senior Secured Credit Facility.
Contemporaneously withFacility, and internally generated cash flows from operations. During the closingfourth quarter of 2007, we refinanced our indebtedness. We issued $425.0 million of 8.375% Senior Notes (the “Notes”) and used the offeringproceeds from that issuance to retire our then-existing senior credit facility. The Notes have a coupon of 8.375%, do not require prepayments, and mature in 2014. We also entered into our current Senior Secured Credit Facility during the senior notes, we expectfourth quarter of 2007. The Senior Secured Credit Facility consists of a revolving credit facility, a letter of credit sub-facility and a swing line facility up to enter into a new $400an aggregate principal amount of $400.0 million, senior securedall of which mature no later than 2012. As of March 31, 2008, $50.0 million of borrowings were outstanding under the revolving credit facility and to terminate our existing credit facility. As of November 1, 2007, we had approximately $68$61.1 million of outstanding letters or credit issued under the letter of credit sub-facility were outstanding, which reduces the total borrowing capacity under our existingthe Senior Secured Credit Facility. We expect to be able to useAs of March 31, 2008, we had $288.9 million of available borrowing capacity under the new senior secured credit facility to replace these outstanding letters of credit. Senior Secured Credit Facility.
We believe that our liquidity position is strong. As of March 31, 2008, we had approximately $522.2 million of total long-term debt and capital leases, including notes payable to affiliates, and we believe that this new senior secured revolving credit facility, together withamount is acceptable given our recent financial performance and our belief that industry activity levels for the remainder of 2008 should remain stable. On April 1, 2008, we borrowed an additional $50.0 million under our Senior Secured Credit Facility to complete our acquisition of Western on April 3, 2008.
Share Repurchase Plan
In October 2007, our Board of Directors authorized a share repurchase program of up to $300.0 million which is effective through March 31, 2009. From the inception of the program in November 2007 through April 30, 2008, we have repurchased approximately 8.5 million shares of our common stock through open market transactions for approximately $111.9 million. Share repurchases during the first quarter of 2008 were approximately 5.2 million shares for approximately $65.3 million. Our repurchase program, as well as the amount and timing of future repurchases, is subject to market conditions, our financial condition, and our liquidity. Our Senior Secured Credit Facility permits us to make stock repurchases in excess of $200.0 million only if our consolidated debt to capitalization ratio (as defined) is below 50%; as of March 31, 2008, that ratio was below 50%.
Cash Requirements
For the remainder of 2008, we anticipate our cash requirements to include working capital needs, capital expenditures, acquisitions and the repurchase of our common stock. We believe that our current cash and cash equivalents, our availability under our Senior Secured Credit Facility, and our internally generated cash flows from operations will be sufficient to finance the cash requirements of our current and near-term future operations, including the capital expenditures we have budgeted for the remainder of the year. We do not budget for acquisitions; however, we continuously evaluate opportunities that fit our capital expenditure budget.
In the event that we are not able to close this new senior secured revolving credit facility, we are pursuing an amendment tospecific acquisition profile. We anticipate financing any future acquisitions through a combination of our existingcash on hand, future cash flows from operations, and availability under our Senior Secured Credit Facility. The amendment would permit the issuance of the senior notes, terminate the $82.3 million prefunded letter of credit facility and permit us to use the entire $65 million revolving portion of our existing Senior Secured Credit Facility for letters of credit. We believe that this amended facility, together with our cash and cash equivalents and cash flow from operations will be sufficient to finance our near term operations, but we would expect to promptly pursue alternative financing arrangements to provide for greater long-term liquidity.
Cash Flow
Our net cash provided by operating activities for the nine months ended September 30, 2007, totaled $190.2 million compared to $194.1 million for the nine months ended September 30, 2006. The decrease in cash flow from operating activities is due primarily to increased working capital. Our net cash used in investing activities for the nine months ended September 30, 2007 totaled $218.9 million compared to cash used in investing activities of $167.6 million for the nine months ended September 30, 2006. Cash flows used in investing activities increased as a result of increased capital expenditures, cash investments in available for sale securities, lower proceeds received from the sale of fixed assets and our acquisition of AMI. Our net cash used in financing activities for the nine months ended September 30, 2007 totaled $14.0 million compared to $13.9 million for the nine months ended September 30, 2006.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Critical Accounting Policies
Our Accounting Department is responsible for the development and application of our accounting policies and internal control procedures. It reports to the Chief Financial Officer.
The process and preparation of our financial statements in conformity with GAAP requires our management to make certain estimates, judgments and assumptions, which may affect reported amounts of our assets and liabilities, disclosures of contingencies at the balance sheet date, the amounts of revenues and expenses recognized during the reporting period and the presentation of our statement of cash flows for the period ended. We may record materially different amounts if these estimates, judgments and assumptions change or if actual results differ. However, we analyze our estimates, assumptions and judgments based on our historical experience and various other factors that we believe to be reasonable under the circumstances.
As such, we have identified the following critical accounting policies that require a significant amount of estimation and judgment to accurately present our financial position, results of operations and statement of cash flows:
•Estimate of reserves for workers’ compensation, vehicular liability and other self-insured retentions;
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•Accounting for contingencies;
•Accounting for income taxes;
•Estimate of fixed asset depreciable lives;
•Valuation of tangible and intangible assets; and
•Stock-based compensation.
Workers’ Compensation, Vehicular Liability and Other Insurance Reserves
Well servicing and workover operations expose our employees to hazards generally associated with the oilfield. Heavy lifting, moving equipment and slippery surfaces can cause or contribute to accidents involving our employees and third parties who may be present at a site. Environmental conditions in remote domestic oil and gas basins range from extreme cold to extreme heat, from heavy rain to blowing dust. Those conditions can also lead to or contribute to accidents. Our business activities incorporate significant numbers of fluid transport trucks, other oilfield vehicles and supporting rolling stock that move on public and private roads. Vehicle accidents are a significant risk for us. We also conduct contract drilling operations, which present additional hazards inherent in the drilling of wells such as blowouts, explosions and fires, which could result in loss of hole, damaged equipment and personal injury.
As a contractor, we also enter into master service agreements with our customers. These agreements subject us to potential contractual liabilities common in the oilfield.
All of these hazards and accidents could result in damage to our property or a third party’s property and injury or death to our employees or third parties. Although we purchase insurance to protect against large losses, much risk is retained in the form of large deductibles or self-insured retentions.
The occurrence of an event not fully insured or indemnified against, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, there can be no assurance that insurance will be available to cover any or all of these risks, or that, if available, it could be obtained without a substantial increase in premiums. It is possible that, in addition to higher premiums, future insurance coverage may be subject to higher deductibles and coverage restrictions.
Based on the risks discussed above, we estimate our liability arising out of potentially insured events, including workers’ compensation, employer’s liability, vehicular liability, and general liability, and record accruals in our consolidated financial statements. Reserves related to insurance are based on the specific facts and circumstances of the insured event and our past experience with similar claims. Loss estimates for individual claims are adjusted based upon actual claim judgments, settlements and reported claims. The timing of the recognition of these losses and the associated expense is based, in part, on the timing of the events resulting in the claim and varies from period to period, in some cases materially. The actual outcome of these claims could differ significantly from estimated amounts.
We are largely self-insured for physical damage to our equipment, automobiles, and rigs. Our accruals that we maintain on our Consolidated Balance Sheets relate to these deductibles and self-insured retentions, which we estimate through the use of historical claims data and trend analysis. The actual outcome of any claim could differ significantly from estimated amounts. We adjust loss estimates in the calculation of these accruals, based upon actual claim settlements and reported claims.
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Accounting for Contingencies
In addition to our workers’ compensation, vehicular liability and other self-insurance reserves, we record other loss contingencies, which relate to numerous lawsuits, claims, proceedings and tax-related audits in the normal course of our operations on our Consolidated Balance Sheet. In accordance with Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies” (“SFAS 5”), we record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We review our loss contingencies routinely to ensure that we have appropriate reserves recorded on the balance sheet. We adjust these reserves based on estimates and judgments made by management with respect to the likely outcome of these matters, including the effect of any applicable insurance coverage for litigation matters. Our estimates and judgment could change based on new information, changes in laws or regulations, changes in management’s plans or intentions, the outcome of legal proceedings, settlements or other factors. If different estimates and judgments were applied with respect to these matters, it is likely that reserves would be recorded for different amounts. Actual results could vary materially from these reserves.
We record liabilities when environmental assessment indicates that site remediation efforts are probable and the costs can be reasonably estimated. We measure liabilities based, in part, on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability. These assumptions involve the judgments and estimates of management and any changes in assumptions could lead to increases or decreases in our ultimate liability, with any such changes recognized immediately in earnings.
Under the provisions of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations,” we record legal obligations to retire tangible, long-lived assets on our balance sheet as liabilities, which are recorded at a discount when we incur the liability. Significant judgment is involved in estimating our future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. If our estimates on the amount or timing of the cash flows change, the change may have a material impact on our results of operations.
Accounting for Income Taxes
We follow Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes,” which requires that we account for deferred income taxes using the asset and liability method and provide income taxes for all significant temporary differences. Management determines our current tax liability as well as taxes incurred as a result of current operations, yet deferred until future periods. Current taxes payable represent our liability related to our income tax return for the current year, while net deferred tax expense or benefit represents the change in the balance of deferred tax assets and liabilities reported on our consolidated balance sheets. Management estimates the changes in both deferred tax assets and liabilities using the basis of assets and liabilities for financial reporting purposes and for enacted rates that management estimates will be in effect when the differences reverse. Further, management makes certain assumptions about the timing of temporary tax differences for the differing treatment of certain items for tax and accounting purposes or whether such differences are permanent.
We establish valuation allowances to reduce deferred tax assets if we determine that it is more likely than not (e.g., a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized in future periods. To assess the likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which this taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted results, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. As a result, we can give no assurance that loss carryforwards will be realized or available in the future. Additionally, we record reserves for uncertain tax positions that are subject to management judgment related to the resolution of the tax positions and completion of audits by tax authorities in the domestic and international tax jurisdictions in which we operate.
FIN No. 48 and FSP FIN 48-1.On July 12, 2006, the FASB issued FIN 48, which provides clarification of SFAS 109, “Accounting for Income Taxes” with respect to the recognition of income tax benefits of uncertain tax positions in the financial statements. FIN 48 requires that uncertain tax positions be reviewed and assessed, with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard.
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In May 2007, the FASB issued FSP FIN 48-1. FSP FIN 48-1 provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. In determining whether a tax position has been effectively settled, entities must evaluate (i) whether taxing authorities have completed their examination procedures; (ii) whether the entity intends to appeal or litigate any aspect of a tax position included in a completed evaluation; and (iii) whether it is remote that a taxing authority would examine or re-examine any aspect of a taxing position. FSP FIN 48-1 is to be applied upon the initial adoption of FIN 48.
We adopted the provisions of FIN 48 and FSP FIN 48-1 on January 1, 2007 and recorded a $1.3 million decrease to the balance of our retained earnings as of January 1, 2007 to reflect the cumulative effect of adopting these standards.
Estimate of Depreciable Lives
We use the estimated depreciable lives of our long-lived assets, such as rigs, heavy duty trucks, trailers, etc., to compute depreciation expense, to estimate future asset retirement obligations and to conduct impairment tests. We base the estimate of our depreciable lives on a number of factors, such as the environment in which the assets operate, industry factors including forecasted prices and competition, and the assumption that we provide the appropriate amount of capital expenditures while the asset is in operation to maintain economical operation of the asset and prevent untimely demise to scrap.
We depreciate our operational assets over their depreciable lives to their salvage value, which is generally 10% of the acquisition cost. We recognize a gain or loss upon ultimate disposal of the asset.
We periodically analyze our estimates of the depreciable lives of our fixed assets to determine if the depreciable periods and salvage value continue to be appropriate. We also analyze useful lives and salvage value when events or conditions occur that could shorten the remaining depreciable life of the asset. We review the depreciable periods and salvage values for reasonableness, given current conditions. As a result, our depreciation expense is based upon estimates of depreciable lives of the fixed assets, the salvage value and economic factors, all of which require management to make significant judgments and estimates. If we determine that the depreciable lives should be shorter than originally estimated, depreciation expense may increase and impairments in the carrying values of our fixed assets may result.
In the first quarter of 2007, management reassessed the useful lives assigned to all of its equipment due to the higher activity and utilization levels experienced with recent and current market conditions. As a result, the maximum useful lives of certain assets were adjusted to reflect this higher utilization. Included in this change is a reduction in the useful life expected for a well service rig, which was reduced from an average expected life of 17 years to 15 years. Management also determined that the life assigned to a self remanufactured well service rig should be the same as the 15 year life assigned to a well service rig acquired from third parties.
Valuation of Tangible and Intangible Assets
On at least an annual basis as required by Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” and as required by Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we review long-lived assets, such as well-service rigs, drilling rigs, pressure pumping equipment, heavy duty trucks, investments, goodwill and noncompete agreements to evaluate whether our long-lived assets or goodwill may have been impaired.
Impairment tests may be required annually, as with goodwill, or as management identifies certain trigger events such as negative industry or economic trends, changes in our business strategy, and underperformance relative to historical or projected operating results. To perform an impairment test, we make judgments, estimates and assumptions regarding long-term forecasts of revenues and expenses relating to assets subject to review or, in the case of goodwill, to our reporting units. Market conditions, energy prices, estimated depreciable lives of the assets, discount rate assumptions and legal factors impact our operations and have a significant effect on the estimates of management. Using different judgments, these estimates could differ significantly and actual financial results could differ materially from these estimates. These long-term forecasts are used in the impairment tests to determine if an asset’s carrying value is recoverable or if a write-down to fair value is required.
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Stock-Based Compensation
We account for stock-based compensation under the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123(R)”), which we adopted on January 1, 2006. We adopted the provisions of SFAS 123(R) using the modified prospective transition method. Stock option awards granted by the Company are fair valued using a Black-Scholes option model and are amortized to compensation expense over the vesting period of the option award, net of estimated and actual forfeitures.
Beginning in June 2005 we began making grants of shares of common stock to certain of our employees and non-employee directors. These shares have vesting periods ranging from zero to three years. Subject to the provisions of SFAS 123(R), the Company recognizes expense in earnings equal to the fair value of the shares vesting during the period, net of actual and estimated forfeitures.
In December 2006, the Company began granting “Phantom Shares” to certain of its employees, which vest ratably over a four-year period from the date of grant. The Phantom Shares convey the right to the grantee to receive a cash payment on each anniversary date of the grant equal to the fair market value of the Phantom Shares vesting on that date. Grantees are not permitted to defer the payout to a later date. The Phantom Shares qualify as a “liability” type award under SFAS 123(R); as such, the Company accounts for the Phantom Shares at fair value, with an offsetting liability recorded on our Consolidated Balance Sheets. Changes in the fair value of the liability, net of estimated and actual forfeitures, are recorded currently in earnings as compensation expense.
In August 2007, the Company began issuing stock appreciation rights (“SARs”) to its executive officers. Each SAR award has a ten-year term from the date of grant and vests in equal annual installments on the first, second and third anniversaries of the date of grant. Upon the exercise of an SAR, the recipient will receive the spread between the exercise price and the fair market value of a share of the Company’s common stock on the date of exercise multiplied by the number of shares of common stock for which the SAR was exercised. All payments will be made in shares of the Company’s common stock. Prior to exercise, the SAR does not entitle the recipient to receive any shares of the Company’s common stock and does not provide the recipient with any voting or other stockholder rights. The Company accounts for the SARs as equity awards under SFAS 123(R) and recognizes compensation expense ratably over the vesting period of the SAR based on its fair value on the date of issuance, net of estimated and actual forfeitures.
Financial Accounting Standards Affecting This Report
FIN No. 48 and FSP FIN 48-1.On July 12, 2006, the FASB issued FIN 48, which provides clarification of SFAS 109, “Accounting for Income Taxes” with respect to the recognition of income tax benefits of uncertain tax positions in the financial statements. FIN 48 requires that uncertain tax positions be reviewed and assessed, with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard.
In May 2007, the FASB issued FSP FIN 48-1. FSP FIN 48-1 provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. In determining whether a tax position has been effectively settled, entities must evaluate (i) whether taxing authorities have completed their examination procedures; (ii) whether the entity intends to appeal or litigate any aspect of a tax position included in a completed evaluation; and (iii) whether it is remote that a taxing authority would examine or re-examine any aspect of a taxing position. FSP FIN 48-1 is to be applied upon the initial adoption of FIN 48.
We adopted the provisions of FIN 48 and FSP FIN 48-1 on January 1, 2007 and recorded a $1.3 million decrease to the balance of our retained earnings as of January 1, 2007 to reflect the cumulative effect of adopting these standards.
FSP EITF 00-19-2. In December 2006, the FASB issued FSP EITF 00-19-2. FSP EITF 00-19-2 addresses accounting for Registration Payment Arrangements (“RPAs”), which are provisions within financial instruments such as equity shares, warrants or debt instruments in which the issuer agrees to file a registration statement and to have that registration statement declared effective by the SEC within a specified grace period. If the registration statement is not declared effective within the grace period or its effectiveness is not maintained for the period of time specified in the RPA, the issuer must compensate its counterparty. The FASB Staff concluded that the contingent obligation to make future payments or otherwise transfer consideration under a RPA should be recognized as a liability and measured in accordance with SFAS 5 and FASB Interpretation No. 14, “Reasonable Estimation of the Amount of a Loss,” and that the RPA should be recognized and measured separately from the instrument to which the RPA is attached.
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In January 1999, the Company completed the private placement of 150,000 units (the “Units”) consisting of $150.0 million of 14% Senior Subordinated Notes due January 25, 2009 (the “14% Senior Subordinated Notes”) and 150,000 warrants to purchase an aggregate of approximately 2.2 million shares of the Company’s common stock at an exercise price of $4.88125 per share (the “Warrants”). As of September 30, 2007, 63,500 Warrants had been exercised, leaving 86,500 Warrants outstanding that were exercisable for an aggregate of approximately 1.3 million shares.
Under the terms of the Warrants, we are required to maintain an effective registration statement covering the shares of common stock issuable upon exercise. If we are unable to maintain an effective registration statement, we are required to make semiannual liquidated damages payments for periods in which an effective registration statement is not maintained. Due to our past failure to file our SEC reports in a timely manner, we do not have an effective registration statement covering the Warrants, and have been required to make liquidated damages payments, and will continue to be required to make those payments until such time as we have an effective registration statement on file for exercise of the Warrants or the warrant shares issuable thereunder are eligible for resale without registration pursuant to SEC Rule 144 or otherwise. The requirement to make liquidated damages payments constitutes a RPA under the provisions of FSP EITF 00-19-2. As prescribed by the transition provisions of FSP EITF 00-19-2, on January 1, 2007, the Company recorded a current liability of approximately $1.0 million on its balance sheet, which is equivalent to the payments for the Warrant RPA for one year, and we recorded an offsetting adjustment to the opening balance of retained earnings. This amount represents the low end of a range of possible outcomes. If we continue to be unable to maintain an effective registration statement with the SEC, the total amount of liquidated damages payable under the Warrant RPA during 2007 could be as high as $1.4 million. Any subsequent changes in the carrying value of the RPA liability will be recorded in earnings as other income and expense.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKSQuantitative and Qualitative Disclosures about Market Risk.
There have been no material changes in our quantitative and qualitative disclosures about market risksrisk from those disclosed in our 2007 Annual Report on Form 10-K for the year ended December 31, 2006.10-K. More detailed information concerning market risk can be found in Item 7A. “Quantitative
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“Quantitative and Qualitative Disclosures about Market Risks”Risk” in our 2007 Annual Report on Form 10-K for the year ended December 31, 2006 dated as of, and filed with the SEC on, August 13, 2007.February 29, 2008.
Item 4.CONTROLS AND PROCEDURESControls and Procedures.
Disclosure Controls and Procedures
As of the end of the period covered by this Quarterly Report, management performed, with the participation of our Chief Executive Officer and our Chief Financial Officer, an evaluation of the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designeddesignated to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on the evaluation and the identification of the material weaknesses in internal control over financial reporting as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2006,2007, management concluded that, as of September 30, 2007,March 31, 2008, the Company’s disclosure controls and procedures were not effective.
Because of the material weaknesses identified in our evaluation of internal control over financial reporting for the year ended December 31, 2006,2007, we performed additional substantive procedures so that our condensed consolidated financial statements as of and for the quarter and nine months ended September 30, 2007,March 31, 2008, are presented in accordance with generally accepted accounting principles in the United States of America (“GAAP”).
We believe that because we performed the substantial additional procedures referenced above, the consolidated condensed financial statements for the periods included in this Quarterly Report are fairly presented in all material respects in accordance with GAAP.
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Management is committed to achieving effective internal control over financial reporting. Our remediation efforts are described in Item 9A in our Annual Report on Form 10-K for the year ended December 31, 2006.2007. While these efforts continue, we will rely on additional substantive procedures and other measures as needed to assist us with meeting the objectives otherwise fulfilled by an effective control environment.
Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting during the most recently completed fiscal quarter that have materially affected or are reasonably likely to materially affect, our internal control over financial reporting.
Item 1. LEGAL PROCEEDINGSLegal Proceedings.
Class Action Lawsuits and Derivative ActionsActivities
Since June 2004, we have beenwere named as a defendant in six class action complaints for alleged violations of federal securities laws, which have been filed in federal district court in Texas. They are as follows:
Cause No. MO-04-CV-082; Peter Kaltman, on behalf of himself and all others similarly situated v. Key Energy Services, Inc., Francis D. John, Royce W. Mitchell, Richard J. Alario and James J. Byerlotzer, filed in the United States District Court for the Western District of Texas
Cause No. MO-04-CV-083; Malcolm Lord, Individually and on Behalf of all Others Similarly situated v. Key Energy Services, Inc., Francis D. John, Richard J. Alario, James J. Byerlotzer and Royce W. Mitchell, filed in the United States District Court for the Western District of Texas
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Cause No. MO-04-CV-090; Celeste Navon, on behalf of herself and all others similarly situated v. Key Energy Services, Inc., Francis John, Royce Mitchell, James Byerlotzer and Richard Alario, filed in the United States District Court for the Western District of Texas
Cause No. MO-04-CV-104; David W. Ortbals, on Behalf of Himself and All Others Similarly situated v. Key Energy Services, Inc., Richard J. Alario, James J. Byerlotzer, Francis D. John, and Royce W. Mitchell, filed in the United States District Court for the Western District of Texas
Cause No. MO-04-CV-0254; Paul E. Steward, on Behalf of Himself and All Others Similarly situated v. Key Energy Services, Inc., Francis D. John and Royce W. Mitchell, filed in the United States District Court for the Western District of Texas
Cause No. MO-04-CV-0227; Garco Investment LLP Individually and on Behalf of all Others Similarly Situated v. Key Energy Services, Inc., Richard J. Alario, James J. Byerlotzer, Francis D. John and Royce W. Mitchell, filed in the United States District Court for the Western District of Texas
These six actions have beenwere consolidated into one action. On November 1, 2005, the plaintiffs filed a consolidated amended class action complaint. The complaint iswas brought on behalf of a putative class of purchasers of our securities between April 29, 2003 and June 4, 2004. The complaint namesnamed Key, Francis D. John, Royce W. Mitchell, Richard J. Alario and James J. Byerlotzer as defendants. The complaint generally allegesalleged that we made false and misleading statements and omitted material information from our public statements and SEC reports during the class period in violation of the Securities Exchange Act of 1934, including alleged: (i) overstatement of revenues, net income, and earnings per share, (ii) failure to take write-downs of assets, consisting of primarily idle equipment, (iii) failure to amortize the Company’s goodwill, (iv) failure to disclose that the Company lacked adequate internal controls and therefore was unable to ascertain the true financial condition of the Company, (v) material inflation of the Company’s financial results at all relevant times, (vi) misrepresentation of the value of acquired businesses, and (vii) failure to disclose misappropriation of funds by employees.
In addition, four shareholder derivative suits have beenwere filed by certain of our shareholders. They are as follows:
Cause No. 2004-CV-44728; Moonlight Investments, LTD. on Behalf of Nominal Defendant Key Energy Services, Inc., v. Francis D. John, Richard J. Alario, James J. Byerlotzer, Royce W. Mitchell, Kevin P. Collins, W. Phillip Marcum, and Ralph S. Michael, III, and Key Energy Services, Inc., filed in the 385th Judicial District Court, Midland County, Texas
Cause No. EP-04-CA-0457; Sandra Weissman, Derivatively on Behalf of Key Energy Services, Inc., v. Francis D. John, David J. Breazzano, Kevin P. Collins, William D. Fertig, W. Phillip Marcum, Ralph S. Michael III, J. Robinson West, James J. Byerlotzer, Royce W. Mitchell, Richard J. Alario and Key Energy Services, Inc., a Maryland Corporation, filed in the United States District Court Western District of Texas
Cause No. EP-04-CA-0456; Daniel Bloom, Derivatively on Behalf of Key Energy Services, Inc., v. Francis D. John, David J. Breazzano, Kevin P. Collins, William D. Fertig, W. Phillip Marcum, Ralph S. Michael III, J. Robinson West, James J. Byerlotzer, Royce W. Mitchell, Richard J. Alario and Key Energy Services, Inc., a Maryland Corporation, filed in the United States District Court Western District of Texas
Cause No. 2007-31254; Sandra Weissman, Derivatively on Behalf of Key Energy Services, Inc., v. Francis D. John, David J. Breazzano, Kevin P. Collins, William D. Fertig, W. Phillip Marcum, Ralph S. Michael III, J. Robinson West, James J. Byerlotzer, Royce W. Mitchell, Richard J. Alario and Key Energy Services, Inc., a Maryland Corporation filed in the 270th Judicial District, Harris County, Texas
The first derivative suit was filed on August 9, 2004 in state court in Midland, Texas. Two other derivative suits were filed in federal court in El Paso, Texas on December 10, 2004 and subsequently transferred to federal court in Midland, Texas and consolidated by agreement of the parties. Following dismissal of those two actions for failure to make a demand, a fourth derivative suit was filed in Texas state court in Harris County, Texas on May 22, 2004.2007. Francis D. John, David J. Breazzano, Kevin P. Collins, William D. Fertig, W. Phillip Marcum, Ralph S. Michael III, J. Robinson West, James J. Byerlotzer, Royce W. Mitchell, and Richard J. Alario have beenwere named as defendants in one or more of those actions. ThoseThe actions arewere filed by individual shareholders purporting to act on our behalf, asserting various claims against the named officer and director defendants. The derivative actions generally allege the same facts as those in the shareholder class action suits. Those
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suits also allege breach of fiduciary duty, abuse of control, waste of corporate assets, and unjust enrichment by these defendants.
On September 7, 2007, the Companywe reached agreements in principle to settle all pending securities class action and derivative lawsuits in consideration of payments totaling $16.6 million in exchange for full and complete releases for all defendants. The Company’s contributiondefendants, of which Key will be required to pay approximately $1.1 million. We received final approval of the settlement net of payments by its insurersthe shareholder and contributions from other defendants, will amount to $1.0 million. The settlement is subject to completion of documentationclass action claims on March 6, 2008, and preliminary court approval following notices to all potential claimants eligible for class participation. A preliminary hearing, originally scheduled for October 24, 2007, has been set for November 21, 2007. The final hearing is scheduled for March 25,on the derivative action on April 18, 2008.
Litigation with Former General Counsel
We have been named in a lawsuit Final approval by our former general counsel, Jack D. Loftis, Jr., filedthe court in the U.S. District Court, Districtderivative action is anticipated to occur in the third quarter of New Jersey on April 21, 2006, in which he alleges a “whistle-blower” claim under the Sarbanes-Oxley Act, breach of contract, breach of good faith and fair dealing, breach of fiduciary duty, and wrongful termination. Mr. Loftis previously filed his “whistle-blower” claim with the Department of Labor (“DOL”), which found that there was no reasonable cause to believe that we violated the Sarbanes-Oxley Act when we terminated Mr. Loftis and dismissed the complaint. On July 28, and October 2, 2006, Key moved to dismiss the lawsuit for lack of jurisdiction over Key Energy or for lack of venue. On June 28, 2007, the court denied our motions but on its own motion transferred the case to the U.S. District Court for the Eastern District of2008.
44Other Matters
Pennsylvania.On July 6, 2007,
In addition to various suits and claims that have arisen in the ordinary course of business, we delivered a noticecontinue to Mr. Loftis, through his counsel, ofbe involved in litigation with our intention to treat his termination of employment effective July 8, 2004 as “for cause” under his employment agreement. On August 17, 2007, the Company filed counterclaims against Mr. Loftis alleging attorney malpractice, breach of contract, and breach of fiduciary duties. In its counterclaims, the Company seeks repayment of all severance paid to Mr. Loftis to date (approximately $815,000) plus benefits paid during the period July 8, 2004 to September 21, 2004,former executive officers as well as damages relating toa class action lawsuit in California. We do not believe that the allegationsdisposition of malpractice and breachany of fiduciary duties. On September 21, 2007, the Company’s Boardthese items, including litigation with former management, will result in a material adverse effect on our consolidated financial position, results of Directors determined that Mr. Loftis should be terminated “for cause” effective July 8, 2004, and further found that his vested and unvested stock options should be deemed expired. We are vigorously defending against Mr. Loftis’ claims; however, we cannot predict the outcome of this lawsuit.operations or cash flows.
Item 1A. RISK FACTORSRisk Factors.
There have been no material changes in our risk factors from those disclosed in our 2007 Annual Report on Form 10-K for the year ended December 31, 2006 dated as of, and filed with the SEC on, August 13, 2007.February 29, 2008. For a discussion of our risk factors, see Item 1A. “Risk Factors” in our 2007 Annual Report on Form 10-K for the year ended December 31, 2006 dated as of, and filed with the SEC on, August 13, 2007.10-K.
Item 2.UNREGISTERED SALESUnregistered Sales of Equity Securities and Use of Proceeds.
Stock Repurchases. During the first quarter of 2008, the Company repurchased an aggregate approximately 5.2 million shares of its common stock. The repurchases were made pursuant to the Company’s $300.0 million share repurchase program, which the Company announced in October 2007. The program expires March 31, 2009. Set forth below is a summary of the share repurchases during the three months ended March 31, 2008:
ISSUER PURCHASES OF EQUITY SECURITIES AND USE OF PROCEEDS
Period |
| Total Number of |
| Weighted Average |
| Total Number of |
| Appropriate Dollar |
| ||
January 1, 2008 to January 31, 2008 |
| 1,837,300 |
| $ | 12.47 |
| 1,837,300 |
| $ | 244,869,537 |
|
February 1, 2008 to February 29, 2008 |
| 1,689,896 |
| $ | 12.59 |
| 1,689,896 |
| $ | 223,540,071 |
|
March 1, 2008 to March 31, 2008 |
| 1,670,250 |
| $ | 12.52 |
| 1,670,250 |
| $ | 202,572,331 |
|
Total |
| 5,197,446 |
| $ | 12.53 |
| 5,197,446 |
| $ | 202,572,331 |
|
Item 3.Defaults Upon Senior Securities.
On July 10, 2007, we awarded an aggregate amount of 37,944 shares of stock to our non-employee directors for services provided to the Company. On August 22, 2007, we awarded an aggregate amount of 258,734 shares of restricted stock and an aggregate amount of 587,405 stock appreciation rights to our current executive officers for retention purposes. All such shares of restricted stock were granted under the Key Energy Group, Inc. 1997 Incentive Plan. Each of these issuances were made in reliance upon the exemption from the registration requirements of the Securities Act of 1933 provided by Section 4(2) thereof for transactions by an issuer not involving any public offering.
Item 3. DEFAULTS UPON SENIOR SECURITIES
None.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
None.
45Item 4.Submission of Matters to a Vote of Security Holders.
None.
None.
3.1 | Articles of Restatement of the Company. (Incorporated by | |
32
3.2 | Unanimous consent of the Board of Directors of the Company dated January 11, 2000, limiting the designation of the additional authorized shares to common stock. (Incorporated by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-8038.) | |
|
| |
3.3 | Second Amended and Restated By-laws of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Form 8-K filed on September 22, 2006, File No. 1-8038.) | |
|
| |
3.4 | Amendment to Second Amended and Restated | |
|
| |
3.5 | Amendments to Second Amended and Restated By-laws of Key Energy Services, Inc. adopted April 4, 2008. (Incorporated by Reference to Exhibit 3.1 of the Company’s Form 8-K filed on April 9, 2008, File No. 1-8038.) | |
| ||
4.1 | Warrant Agreement dated as of January 22, 1999 between the Company and the Bank of New York, a New York banking corporation as warrant agent. (Incorporated by reference to Exhibit 99(b) of the Company’s Form 8-K filed on February 3, 1999, File No. 1-8038.) | |
|
| |
4.2 | Warrant Registration Rights Agreement dated January 22, 1999, by and among the Company and Lehman Brothers Inc., Bear, Stearns & Co., Inc., F.A.C. / Equities, a division of First Albany Corporation, and Dain Rauscher Wessels, a division of Dain Rauscher Incorporated. (Incorporated by reference to Exhibit 99(e) of the Company’s Form 8-K filed on February 3, 1999, File No. 1-8038.) | |
|
| |
|
| |
|
| |
|
| |
|
| |
| 4.5* | First |
|
| |
31.1* | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
|
| |
31.2* | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
|
| |
32* | Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
*Filed herewith.herewith
4633
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.
| KEY ENERGY SERVICES, INC. | ||||
|
| (Registrant) | |||
|
|
| |||
|
| /s/ Richard J. Alario | |||
| By: | Richard J. Alario | |||
|
| President and Chief Executive Officer | |||
|
| (Principal Executive Officer) | |||
|
47Date: May 8, 2008
34
EXHIBITS INDEX
3.1 | Articles of Restatement of the Company. (Incorporated by | |
|
| |
3.2 | Unanimous consent of the Board of Directors of the Company dated January 11, 2000, limiting the designation of the additional authorized shares to common stock. (Incorporated by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-8038.) | |
|
| |
3.3 | Second Amended and Restated By-laws of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Form 8-K filed on September 22, 2006, File No. 1-8038.) | |
|
| |
3.4 | Amendment to Second Amended and Restated | |
|
| |
3.5 | Amendments to Second Amended and Restated By-laws of Key Energy Services, Inc. adopted April 4, 2008. (Incorporated by Reference to Exhibit 3.1 of the Company’s Form 8-K filed on April 9, 2008, File No. 1-8038.) | |
| ||
4.1 | Warrant Agreement dated as of January 22, 1999 between the Company and the Bank of New York, a New York banking corporation as warrant agent. (Incorporated by reference to Exhibit 99(b) of the Company’s Form 8-K filed on February 3, 1999, File No. 1-8038.) | |
|
| |
4.2 | Warrant Registration Rights Agreement dated January 22, 1999, by and among the Company and Lehman Brothers Inc., Bear, Stearns & Co., Inc., F.A.C. / Equities, a division of First Albany Corporation, and Dain Rauscher Wessels, a division of Dain Rauscher Incorporated. (Incorporated by reference to Exhibit 99(e) of the Company’s Form 8-K filed on February 3, 1999, File No. 1-8038.) | |
|
| |
|
| |
|
| |
|
| |
|
| |
| 4.5* | First |
|
| |
31.1* | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
|
| |
31.2* | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
|
| |
32* | Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
*Filed herewith.herewith
4835