e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 |
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2006
OR
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 |
FOR THE TRANSITION PERIOD FROM TO
Commission file number 1-2199
ALLIS-CHALMERS ENERGY INC.
(Exact name of registrant as specified in its charter)
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DELAWARE
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39-0126090 |
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(State or other jurisdiction of
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(I.R.S. Employer |
incorporation or organization)
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Identification No.) |
5075 WESTHEIMER, SUITE 890, HOUSTON, TEXAS 77056
(Address of principal executive offices) (Zip code)
(713) 369-0550
Registrants telephone number, including area code
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer. See definition of accelerated filer and larger accelerated filer in
Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o Accelerated filer o Non-accelerated filer þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of
the latest practicable date.
At November 1, 2006 there were 24,831,155 shares of common stock, par value $0.01 per share,
outstanding.
ALLIS-CHALMERS ENERGY INC.
FORM 10-Q
For the Quarterly Period Ended September 30, 2006
TABLE OF CONTENTS
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED CONDENSED BALANCE SHEETS
(in thousands, except for share and per share amounts)
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September 30, |
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December 31, |
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2006 |
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2005 |
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(unaudited) |
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Assets |
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Cash and cash equivalents |
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$ |
50,311 |
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$ |
1,920 |
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Trade receivables, net |
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85,156 |
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26,964 |
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Inventory |
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25,813 |
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5,945 |
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Prepaid expenses and other |
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6,374 |
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823 |
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Total current assets |
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167,654 |
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35,652 |
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Property and equipment, net |
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341,483 |
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80,574 |
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Goodwill |
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12,417 |
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12,417 |
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Other intangible assets, net |
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6,802 |
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6,783 |
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Debt issuance costs, net |
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8,585 |
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1,298 |
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Other assets |
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155 |
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631 |
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Total assets |
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$ |
537,096 |
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$ |
137,355 |
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Liabilities and Stockholders Equity |
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Current maturities of long-term debt |
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$ |
8,493 |
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$ |
5,632 |
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Trade accounts payable |
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26,311 |
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9,018 |
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Accrued salaries, benefits and payroll taxes |
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10,050 |
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1,271 |
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Accrued interest |
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4,950 |
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289 |
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Accrued income taxes |
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2,901 |
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668 |
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Accrued expenses |
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13,853 |
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3,682 |
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Accounts payable, related parties |
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60 |
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Total current liabilities |
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66,558 |
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20,620 |
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Accrued postretirement benefit obligations |
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304 |
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335 |
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Long-term debt, net of current maturities |
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262,466 |
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54,937 |
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Deferred income taxes |
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26,723 |
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Other long-term liabilities |
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577 |
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588 |
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Total liabilities |
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356,628 |
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76,480 |
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Commitments and contingencies |
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Stockholders Equity |
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Preferred stock, $0.01 par value (25,000,000 shares authorized, no shares issued) |
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Common stock, $0.01 par value (100,000,000 shares authorized;
24,583,881 issued and outstanding at September 30, 2006 and
16,859,988 issued and outstanding at December 31, 2005) |
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246 |
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169 |
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Capital in excess of par value |
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153,135 |
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58,889 |
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Retained earnings |
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27,087 |
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1,817 |
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Total stockholders equity |
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180,468 |
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60,875 |
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Total liabilities and stockholders equity |
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$ |
537,096 |
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$ |
137,355 |
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The accompanying Notes are an integral part of the Consolidated Condensed Financial Statements.
3
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED CONDENSED INCOME STATEMENTS
(in thousands, except per share amounts)
(unaudited)
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For the Three Months Ended |
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For the Nine Months Ended |
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September 30, |
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September 30, |
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2006 |
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2005 |
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2006 |
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2005 |
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Revenues |
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$ |
85,738 |
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$ |
28,908 |
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$ |
193,236 |
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$ |
71,830 |
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Cost of revenues |
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Direct costs |
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51,497 |
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19,280 |
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110,578 |
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47,756 |
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Depreciation |
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5,448 |
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1,391 |
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12,606 |
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3,397 |
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Total cost of revenues |
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56,945 |
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20,671 |
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123,184 |
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51,153 |
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Gross margin |
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28,793 |
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8,237 |
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70,052 |
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20,677 |
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General and administrative |
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9,058 |
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4,261 |
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24,540 |
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10,720 |
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Amortization |
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681 |
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452 |
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1,954 |
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1,272 |
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Income from operations |
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19,054 |
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3,524 |
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43,558 |
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8,685 |
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Other income (expense): |
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Interest, net |
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(4,660 |
) |
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(2,064 |
) |
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(12,085 |
) |
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(3,230 |
) |
Other |
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(26 |
) |
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63 |
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(6 |
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221 |
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Total other income (expense) |
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(4,686 |
) |
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(2,001 |
) |
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(12,091 |
) |
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(3,009 |
) |
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Net income before minority interest
and income taxes |
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14,368 |
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1,523 |
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31,467 |
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5,676 |
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Minority interest in income of subsidiaries |
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(488 |
) |
Provision for income taxes |
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(3,116 |
) |
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(230 |
) |
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(6,197 |
) |
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(559 |
) |
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Net income |
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$ |
11,252 |
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$ |
1,293 |
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$ |
25,270 |
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$ |
4,629 |
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Net income per common share: |
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Basic |
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$ |
0.52 |
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$ |
0.09 |
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$ |
1.33 |
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$ |
0.33 |
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Diluted |
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$ |
0.50 |
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$ |
0.08 |
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$ |
1.25 |
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$ |
0.30 |
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Weighted average shares outstanding: |
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Basic |
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21,644 |
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14,985 |
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18,944 |
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14,197 |
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Diluted |
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22,453 |
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16,601 |
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20,155 |
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15,589 |
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The accompanying Notes are an integral part of the Consolidated Condensed Financial Statements.
4
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
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For the Nine Months Ended |
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September 30, |
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2006 |
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2005 |
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Cash Flows from Operating Activities: |
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Net income |
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$ |
25,270 |
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$ |
4,629 |
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Adjustments to reconcile net income to net cash
provided by operating activities: |
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Depreciation |
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|
12,606 |
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|
3,397 |
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Amortization |
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|
1,954 |
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|
1,272 |
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Imputed interest |
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|
355 |
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Write-off of deferred financing fees due to refinancing |
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|
653 |
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Stock option expense |
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|
2,638 |
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Provision for bad debts |
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|
353 |
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Minority interest in income of subsidiaries |
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|
488 |
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Deferred taxes |
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|
494 |
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Gain on sale of property and equipment |
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(728 |
) |
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Changes in operating assets and liabilities, net of acquisitions: |
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(Increase) in trade receivable |
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|
(17,161 |
) |
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|
(7,250 |
) |
(Increase) in inventory |
|
|
(2,161 |
) |
|
|
(2,844 |
) |
Decrease in other current assets |
|
|
1,322 |
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|
|
1,322 |
|
Decrease (increase) in other assets |
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|
530 |
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|
(171 |
) |
(Decrease) increase in accounts payable |
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(1,609 |
) |
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|
1,058 |
|
Increase in accrued interest |
|
|
4,661 |
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|
497 |
|
Increase in accrued expenses |
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|
2,516 |
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|
1,269 |
|
Increase (decrease) in accrued salaries, benefits and payroll taxes |
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3,110 |
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|
(287 |
) |
Decrease in other long-term liabilities |
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|
(813 |
) |
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(151 |
) |
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Net Cash Provided By Operating Activities |
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33,337 |
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|
3,882 |
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Cash Flows from Investing Activities: |
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Acquisition of businesses, net of cash received |
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|
(203,189 |
) |
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|
(15,416 |
) |
Acquisition of assets |
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|
(21,249 |
) |
Proceeds from sale of property and equipment |
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|
3,516 |
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|
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|
Purchase of property and equipment |
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(25,811 |
) |
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|
(9,585 |
) |
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|
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|
|
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Net Cash Used In Investing Activities |
|
|
(225,484 |
) |
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|
(46,250 |
) |
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Cash Flows from Financing Activities: |
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|
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|
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Proceeds from exercises of options and warrants |
|
|
5,406 |
|
|
|
|
|
Proceeds from issuance of common stock, net |
|
|
46,484 |
|
|
|
15,888 |
|
Proceeds from long-term debt |
|
|
257,820 |
|
|
|
45,700 |
|
Proceeds from line of credit |
|
|
5,000 |
|
|
|
|
|
Repayments on long-term debt |
|
|
(51,712 |
) |
|
|
(21,438 |
) |
Repayments on related party debt |
|
|
(3,031 |
) |
|
|
|
|
Repayments on line of credit |
|
|
(11,400 |
) |
|
|
|
|
Debt issuance costs |
|
|
(8,029 |
) |
|
|
(1,217 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By Financing Activities |
|
|
240,538 |
|
|
|
38,933 |
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents |
|
|
48,391 |
|
|
|
(3,435 |
) |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year |
|
|
1,920 |
|
|
|
7,344 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
50,311 |
|
|
$ |
3,909 |
|
|
|
|
|
|
|
|
The accompanying Notes are an integral part of the Consolidated Condensed Financial Statements.
5
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 1
- NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
We are a multi-faceted oilfield service company that provides services and equipment to oil and
natural gas exploration and production companies, domestically in Texas, Louisiana, New Mexico,
Colorado, Oklahoma, Mississippi, Utah, Wyoming, offshore in the Gulf of Mexico, and internationally
in Argentina, Mexico and Bolivia. We operate in six sectors of the oil and natural gas service
industry: directional drilling services; rental tools; international drilling; casing and tubing
services; compressed air drilling services; and production services.
We derive operating revenues from rates per day and rates per job that we charge for the labor and
equipment required to provide a service and rates per day for equipment and tools that we rent to
our customers. The price we charge for our services depends upon several factors, including the
level of oil and natural gas drilling activity and the competitive environment in the particular
geographic regions in which we operate. Contracts are awarded based on price, quality of service
and equipment and general reputation and experience of our personnel. The principal operating
costs are direct and indirect labor and benefits, repairs and maintenance of our equipment,
insurance, equipment rentals, fuel, depreciation and general and administrative expenses.
Basis of Presentation
Our unaudited consolidated condensed financial statements included herein have been prepared
pursuant to the rules and regulations of the Securities and Exchange Commission, or SEC.
Accordingly, certain information and disclosures normally included in financial statements prepared
in accordance with generally accepted accounting principles have been condensed or omitted. We
believe that the presentations and disclosures herein are adequate to make the information not
misleading. The unaudited consolidated condensed financial statements reflect all adjustments
(consisting of normal recurring adjustments) necessary for a fair presentation of the interim
periods. These unaudited consolidated condensed financial statements should be read in conjunction
with our audited consolidated financial statements included in our Annual Report on Form 10-K for
the year ended December 31, 2005. The results of operations for the interim periods are not
necessarily indicative of the results of operations to be expected for the full year.
Certain reclassifications have been made to the prior years consolidated condensed financial
statements to conform with the current period presentation.
The preparation of financial statements in conformity with accounting principles generally accepted
in the United States of America requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts of revenues and expenses during
the reporting period. Future events and their effects cannot be perceived with certainty.
Accordingly, our accounting estimates require the exercise of judgment. While management believes
that the estimates and assumptions used in the preparation of the consolidated financial statements
are appropriate, actual results could differ from those estimates. Estimates are used for, but are
not limited to, determining the following: allowance for doubtful accounts, recoverability of
long-lived assets and intangibles, useful lives used in depreciation and amortization, income taxes
and valuation allowances. The accounting estimates used in the preparation of the consolidated
financial statements may change as new events occur, as more experience is acquired, as additional
information is obtained and as our operating environment changes.
In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income
Taxes an interpretation of FASB Statement No. 109 (FIN 48). FIN 48 clarifies the accounting for
uncertainty in income taxes recognized in an enterprises financial statements in accordance with
SFAS No. 109, Accounting for Income Taxes. It prescribes a recognition threshold and measurement
attribute for financial statement recognition and measurement of a tax position taken or expected
to be taken in a tax return. This interpretation is effective for fiscal years beginning after
December 15, 2006. We are currently evaluating the provisions of FIN 48 and have not yet determined
the impact, if any, on our financial statements.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS 157), which is
intended to increase 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 is effective for fiscal years beginning after November 15, 2007, and
interim periods within those fiscal years. We are currently evaluating the provisions of SFAS 157
and have not yet determined the impact, if any, on our financial statements.
6
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 2 ACQUISITIONS
Effective August 14, 2006, we acquired 100% of the outstanding stock of DLS Drilling, Logistics &
Services Corporation, or DLS, based in Argentina, for a total consideration of approximately
$117.9 million, which includes $93.7 million in cash, $38.1 million in our common stock, $3.4
million of acquisition costs, less approximately $17.3 million of debt assigned to us. DLS
operates a fleet of 51 rigs, including 20 drilling rigs, 18 workover rigs and 12 pulling rigs in
Argentina and one drilling rig in Bolivia. The following table summarizes the allocation of the
purchase price to the estimated fair value of the assets acquired and liabilities assumed at the
date of acquisition (in thousands):
|
|
|
|
|
Current assets |
|
$ |
54,370 |
|
Property and equipment |
|
|
150,441 |
|
Other long-term assets |
|
|
21 |
|
|
|
|
|
Total assets acquired |
|
|
204,832 |
|
|
|
|
|
Current liabilities |
|
|
36,530 |
|
Long-term debt, less current portion |
|
|
6,114 |
|
Intercompany note |
|
|
17,256 |
|
Other long-term liabilities |
|
|
27,000 |
|
|
|
|
|
Total liabilities assumed |
|
|
86,900 |
|
|
|
|
|
Net assets acquired |
|
$ |
117,932 |
|
|
|
|
|
Approximately $3.4 million of costs were incurred in relation to the DLS acquisition. DLS
historical property and equipment values were increased by approximately $42.7 million based on
third-party valuations
Effective April 1, 2006, we acquired 100% of the outstanding stock of Rogers Oil Tools, Inc., or
Rogers, based in Lafayette, Louisiana, for a total consideration of approximately $13.7 million,
which includes $11.3 million in cash, $1.6 million in our common stock and a $750,000 three-year
promissory note. In addition, we purchased all the patents and proprietary technology that Tommie
L. Rogers, Rogers founder and Chief Executive Officer, developed at Rogers. Rogers provides
service for tubing tongs and casing tongs and rents and sells specialized automated power tongs to
the snubbing and well control markets. Rogers also rents and sells drill pipe tongs, accessories,
hydraulic power units and hydraulic tong positioners. The following table summarizes the
allocation of the purchase price to the estimated fair value of the assets acquired and
liabilities assumed at the date of acquisition (in thousands):
|
|
|
|
|
Current assets |
|
$ |
4,520 |
|
Property and equipment |
|
|
9,866 |
|
Intangible assets |
|
|
1,131 |
|
|
|
|
|
Total assets acquired |
|
|
15,517 |
|
|
|
|
|
Current liabilities |
|
|
1,717 |
|
Other long-term liabilities |
|
|
100 |
|
|
|
|
|
Total liabilities assumed |
|
|
1,817 |
|
|
|
|
|
Net assets acquired |
|
$ |
13,700 |
|
|
|
|
|
Approximately $380,000 of costs were incurred in relation to the Rogers acquisition. Rogers
historical property and equipment values were increased by approximately $8.4 million based on
third-party valuations. Intangible assets include $981,000 assigned to patents and $150,000
assigned to non-compete based on third-party valuations and employment contracts. The intangibles
have a weighted-average useful life of 9 years.
Effective January 1, 2006, we acquired 100% of the outstanding stock of Specialty Rental Tools,
Inc., or Specialty, for $96.0 million in cash. The results of Specialtys operations have been
included in the consolidated financial statements since that date. Specialty, located in
Lafayette, Louisiana, was engaged in the rental of high quality drill pipe, heavy weight spiral
drill pipe, tubing work strings, blow-out preventors, choke manifolds and various valves and
handling tools for oil and natural gas drilling. For the year ended December 31, 2005, Specialty
had revenues of $32.7 million. The following table summarizes the allocation of the purchase
price to the estimated fair value of the assets acquired and liabilities assumed at the date of
acquisition (in thousands):
7
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 2 ACQUISITIONS (Continued)
|
|
|
|
|
Accounts receivable |
|
$ |
7,167 |
|
Other current assets |
|
|
425 |
|
Property and equipment |
|
|
90,540 |
|
|
|
|
|
Total assets acquired |
|
|
98,132 |
|
|
|
|
|
Current liabilities |
|
|
2,058 |
|
Long-term debt |
|
|
74 |
|
|
|
|
|
Total liabilities assumed |
|
|
2,132 |
|
|
|
|
|
Net assets acquired |
|
$ |
96,000 |
|
|
|
|
|
Approximately $453,000 of costs were incurred in relation to the Specialty acquisition.
Specialtys historical property and equipment values were increased by approximately $71.5 million
based on third-party valuations.
On September 1, 2005, we acquired the casing and tubing service assets of Patterson Services, Inc.
for approximately $15.6 million. These assets are located in Corpus Christi, Texas; Kilgore,
Texas; Lafayette, Louisiana and Houma, Louisiana.
Effective August 1, 2005, we acquired 100% of the outstanding capital stock of Target Energy Inc.,
or Target, for $1.3 million in cash and forgiveness of a lease receivable of approximately $0.6
million. The purchase price was allocated to the fixed assets of Target. The results of Target are
included in our directional and horizontal drilling segment as their measurement while drilling, or
MWD, equipment is utilized in that segment.
On July 11, 2005, we acquired the compressed air drilling assets of W.T. Enterprises, Inc., or WT,
based in South Texas, for $6.0 million in cash. The equipment includes compressors, boosters, mist
pumps and vehicles. Goodwill of $82,000 and other identifiable intangible assets of $1.5 million
were recorded in connection with the acquisition.
On July 11, 2005, we acquired from M-I its 45% interest in AirComp L.L.C., or AirComp, and a
subordinated note in the principal amount of $4.8 million issued by AirComp, for which we paid M-I
$7.1 million in cash and issued to M-I a $4.0 million subordinated note bearing interest at 5% per
annum. As a result, we now own 100% of AirComp.
On May 1, 2005, we acquired 100% of the outstanding capital stock of Capcoil Tubing Services, Inc.,
or Capcoil, for $2.7 million in cash, 168,161 shares of our common stock and the payment or
assumption of approximately $1.3 million of debt. Capcoil, located in Kilgore, Texas, is engaged
in downhole well servicing by providing coil tubing services to enhance production from existing
wells. Goodwill of $184,000 and other identifiable intangible assets of $1.4 million were recorded
in connection with the acquisition.
On April 1, 2005, we acquired 100% of the outstanding stock of Delta Rental Service, Inc., or
Delta, for $4.6 million in cash, 223,114 shares of our common stock and two promissory notes
totaling $350,000. The purchase price was allocated to fixed assets and inventory. Delta, located
in Lafayette, Louisiana, is a rental tool company providing specialty rental items to the oil and
gas industry such as spiral heavy weight drill pipe, test plugs used to test blow-out preventors,
well head retrieval tools, spacer spools and assorted handling tools.
8
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 2 ACQUISITIONS (Continued)
These acquisitions were accounted for using the purchase method of accounting. The results of
operations of the acquired entities since the date of acquisition are included in our consolidated
condensed income statement. The following unaudited pro forma consolidated summary financial
information illustrates the effects of the acquisitions of DLS, Rogers, Specialty, WT, the minority
interest in AirComp, Capcoil and Delta as if the acquisitions had occurred as of January 1, 2005,
based on the historical statements of operations (in thousands, except per share amounts).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended |
|
For the Nine Months Ended |
|
|
September 30, |
|
September 30, |
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
Revenues |
|
$ |
107,617 |
|
|
$ |
44,531 |
|
|
$ |
299,219 |
|
|
$ |
200,634 |
|
Operating income |
|
|
20,530 |
|
|
|
9,685 |
|
|
|
56,668 |
|
|
|
25,552 |
|
Net income |
|
|
12,843 |
|
|
|
2,400 |
|
|
|
28,568 |
|
|
|
4,858 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.56 |
|
|
$ |
0.11 |
|
|
$ |
1.19 |
|
|
$ |
0.24 |
|
Diluted |
|
$ |
0.54 |
|
|
$ |
0.11 |
|
|
$ |
1.14 |
|
|
$ |
0.22 |
|
NOTE 3 STOCK-BASED COMPENSATION
We adopted SFAS No. 123R, Share-Based Payment, effective January 1, 2006. This statement requires
all share-based payments to employees, including grants of employee stock options, to be recognized
in the financial statements based on their grant-date fair values. Compensation cost for awards
granted prior to, but not vested, as of January 1, 2006 would be based on the grant date attributes
originally used to value those awards for pro forma purposes under SFAS No. 123. We adopted SFAS
No. 123R using the modified prospective transition method, utilizing the Black-Scholes option
pricing model for the calculation of the fair value of our employee stock options. Under the
modified prospective method, we record compensation cost related to unvested stock awards as of
December 31, 2005 by recognizing the unamortized grant date fair value of these awards over the
remaining vesting periods of those awards with no change in historical reported earnings. We
estimated forfeiture rates for the first nine months of 2006 based on our historical experience.
The Black-Scholes model incorporates assumptions to value stock-based awards. The risk-free rate
of interest is the related U.S. Treasury yield curve for periods within the expected term of the
option at the time of grant. The dividend yield on our common stock is assumed to be zero as we
have historically not paid dividends and have no current plans to do so in the future. The
expected volatility is based on historical volatility of our common stock.
Prior to January 1, 2006, we accounted for our stock-based compensation using Accounting Principle
Board Opinion No. 25. Under APB No. 25, compensation expense is recognized for stock options with
an exercise price that is less than the market price on the grant date of the option. For stock
options with exercise prices at or above the market value of the stock on the grant date, we
adopted the disclosure-only provisions of SFAS No. 123, Accounting For Stock-Based Compensation.
We also adopted the disclosure-only provisions of SFAS No. 123 for the stock options granted to our
employees and directors. Accordingly, no compensation cost was recognized under APB No. 25. Our
net income for the three and nine months ended September 30, 2006 includes approximately $860,000
and $2,638,000 of compensation costs related to share-based payments. As of September 30, 2006
there is $1.6 million of unrecognized compensation expense related to non-vested stock option
grants. We expect approximately $660,000 to be recognized over the remainder of 2006,
approximately $900,000 to be recognized in 2007 and approximately $14,000 to be recognized in 2008.
9
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 3 STOCK-BASED COMPENSATION (Continued)
A summary of our stock option activity and related information as of September 30, 2006 is as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
Weighted |
|
|
|
|
Share |
|
Average |
|
Average |
|
Aggregate |
|
|
Under |
|
Exercise |
|
Contractual |
|
Intrinsic Value |
|
|
Option |
|
Price |
|
Life (Years) |
|
(millions) |
Balance at beginning of period |
|
|
2,860,867 |
|
|
$ |
5.10 |
|
|
|
|
|
|
|
|
|
Granted |
|
|
15,000 |
|
|
|
14.74 |
|
|
|
|
|
|
|
|
|
Canceled |
|
|
(53,234 |
) |
|
|
5.85 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(1,335,166 |
) |
|
|
3.46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period |
|
|
1,487,467 |
|
|
|
6.65 |
|
|
|
8.56 |
|
|
$ |
11.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of period |
|
|
668,136 |
|
|
|
5.69 |
|
|
|
8.31 |
|
|
$ |
6.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the
difference between the closing price of our common stock on the last trading day of the third
quarter of 2006 and the exercise price, multiplied by the number of in-the-money options) that
would have been received by the option holders had all option holders exercised their options on
September 30, 2006. The total intrinsic value of options exercised during the three and nine
months ended September 30, 2006 was $1.5 million and $17.7 million, respectively. The total cash
received from option exercises during the three and nine months ended September 30, 2006 was
$445,000 and $4.6 million, respectively.
The following summarizes the assumptions used in the September 30, 2006 and 2005 Black-Scholes
model:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended |
|
For the Nine Months Ended |
|
|
September 30, |
|
September 30, |
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
Expected dividend yield |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected price volatility |
|
|
72.28 |
% |
|
|
98.65 |
% |
|
|
72.28 |
% |
|
|
98.65 |
% |
Risk free interest rate |
|
|
5.07 |
% |
|
|
6.63 |
% |
|
|
5.07 |
% |
|
|
6.63 |
% |
Expected life of options |
|
7 years |
|
7 years |
|
7 years |
|
7 years |
Weighted average fair
value of options granted
at market value |
|
$ |
10.58 |
|
|
$ |
3.12 |
|
|
$ |
10.58 |
|
|
$ |
3.12 |
|
10
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 3 STOCK-BASED COMPENSATION (Continued)
The following table illustrates the pro-forma effect on net income and net income per share for the
three and nine months ended September 30, 2005 had we applied the fair value recognition provisions
of SFAS No. 123R (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
|
|
|
|
|
|
|
|
Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2005 |
|
Net income: As reported |
|
|
|
|
|
|
|
|
|
$ |
1,293 |
|
|
$ |
4,629 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less total stock based employee
compensation expense
determined under fair value based
method for all
awards net of tax related
effects |
|
|
|
|
|
|
|
|
|
|
(863 |
) |
|
|
(2,368 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma net income |
|
|
|
|
|
|
|
|
|
$ |
430 |
|
|
$ |
2,261 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
As reported |
|
|
|
|
|
$ |
0.09 |
|
|
$ |
0.33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma |
|
|
|
|
|
$ |
0.03 |
|
|
$ |
0.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
As reported |
|
|
|
|
|
$ |
0.08 |
|
|
$ |
0.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma |
|
|
|
|
|
$ |
0.03 |
|
|
$ |
0.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 4 INCOME PER COMMON SHARE
We compute income per common share in accordance with the provisions of SFAS No. 128, Earnings Per
Share. SFAS No. 128 requires companies with complex capital structures to present basic and
diluted earnings per share. Basic earnings per share are computed on the basis of the weighted
average number of shares of common stock outstanding during the period. Diluted earnings per share
is similar to basic earnings per share, but presents the dilutive effect on a per share basis of
potential common shares (e.g., convertible preferred stock, stock options, etc.) as if they had
been converted. Potential dilutive common shares that have an anti-dilutive effect (e.g., those
that increase income per share) are excluded from diluted earnings per share.
The components of basic and diluted earnings per share are as follows (in thousands, except per
share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended |
|
|
For the Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
11,252 |
|
|
$ |
1,293 |
|
|
$ |
25,270 |
|
|
$ |
4,629 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share weighted
average shares outstanding |
|
|
21,644 |
|
|
|
14,985 |
|
|
|
18,944 |
|
|
|
14,197 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of potentially dilutive common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants and employee and director
stock options |
|
|
809 |
|
|
|
1,616 |
|
|
|
1,211 |
|
|
|
1,392 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share weighted average shares
outstanding and assumed conversions |
|
|
22,453 |
|
|
|
16,601 |
|
|
|
20,155 |
|
|
|
15,589 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share basic |
|
$ |
0.52 |
|
|
$ |
0.09 |
|
|
$ |
1.33 |
|
|
$ |
0.33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share diluted |
|
$ |
0.50 |
|
|
$ |
0.08 |
|
|
$ |
1.25 |
|
|
$ |
0.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 5 GOODWILL AND INTANGIBLE ASSETS
In accordance with SFAS No. 142, Goodwill and Other Intangible Assets, goodwill and
indefinite-lived intangible assets are not permitted to be amortized. Goodwill and
indefinite-lived intangible assets remain on the balance sheet and are tested for impairment on an
annual basis, or when there is reason to suspect that their values may have been diminished or
impaired. Goodwill and indefinite-lived intangible assets listed on the balance sheet totaled $12.4
million at September 30, 2006 and December 31, 2005. Based on impairment testing performed during
2005 pursuant to the requirements of SFAS No. 142, these assets were not impaired.
Intangible assets with definite lives continue to be amortized over their estimated useful lives.
Definite-lived intangible assets that continue to be amortized under SFAS No. 142 relate to our
purchase of customer-related and marketing-related intangibles. These intangibles have useful
lives ranging from five to ten years. Amortization of intangible assets for the three and nine
months ended September 30, 2006 were $399,000 and $1,212,000, respectively, compared to $324,000
and $975,000, respectively for the same periods last year. At September 30, 2006, intangible
assets totaled $10.6 million, net of $3.8 million of accumulated amortization.
NOTE 6 INVENTORY
Inventory is comprised of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
Hammer bits |
|
|
|
|
|
|
|
|
Finished goods |
|
$ |
1,453 |
|
|
$ |
1,402 |
|
Work in process |
|
|
1,880 |
|
|
|
787 |
|
Raw materials |
|
|
2,726 |
|
|
|
233 |
|
|
|
|
|
|
|
|
Total hammer bits |
|
|
6,059 |
|
|
|
2,422 |
|
Hammers |
|
|
884 |
|
|
|
584 |
|
Drive pipe |
|
|
762 |
|
|
|
666 |
|
Rental supplies |
|
|
335 |
|
|
|
64 |
|
Chemicals and drilling fluids |
|
|
1,837 |
|
|
|
201 |
|
Rig parts and related inventory |
|
|
10,243 |
|
|
|
|
|
Coiled tubing and related inventory |
|
|
1,270 |
|
|
|
1,145 |
|
Shop supplies and related inventory |
|
|
4,423 |
|
|
|
863 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total inventory |
|
$ |
25,813 |
|
|
$ |
5,945 |
|
|
|
|
|
|
|
|
12
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 7- DEBT
Our long-term debt consists of the following: (in thousands)
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
Senior notes |
|
$ |
255,000 |
|
|
$ |
|
|
Bank term loans |
|
|
7,946 |
|
|
|
42,090 |
|
Revolving line of credit |
|
|
|
|
|
|
6,400 |
|
Subordinated note payable to M-1 LLC |
|
|
|
|
|
|
4,000 |
|
Subordinated seller note |
|
|
|
|
|
|
3,031 |
|
Seller notes |
|
|
900 |
|
|
|
850 |
|
Obligations under non-compete agreements |
|
|
332 |
|
|
|
698 |
|
Notes payable to former directors |
|
|
32 |
|
|
|
96 |
|
Real estate loan |
|
|
|
|
|
|
548 |
|
Rig, equipment and vehicle installment notes |
|
|
4,398 |
|
|
|
1,939 |
|
Insurance premium financing |
|
|
1,808 |
|
|
|
|
|
Capital lease obligations |
|
|
543 |
|
|
|
917 |
|
|
|
|
|
|
|
|
Total debt |
|
|
270,959 |
|
|
|
60,569 |
|
|
|
|
|
|
|
|
|
|
Less: current maturities |
|
|
8,493 |
|
|
|
5,632 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt obligations |
|
$ |
262,466 |
|
|
$ |
54,937 |
|
|
|
|
|
|
|
|
Senior notes, bank loans and line of credit agreements
On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified institutional
buyers pursuant to Rule 144A under the Securities Act of 1933, of $160.0 and $95.0 million
aggregate principal amount of our senior notes, respectively. The senior notes are due January 15,
2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of Specialty and
DLS, to repay existing debt and for general corporate purposes.
Prior to January 18, 2006, we were party to a July 2005 credit agreement that provided for the
following senior secured credit facilities:
|
|
|
A $13.0 million revolving line of credit. Borrowings were limited to 85% of eligible
accounts receivable plus 50% of eligible inventory (up to a maximum of $2.0 million of
borrowings based on inventory). This line of credit was to be used to finance working
capital requirements and other general corporate purposes, including the issuance of
standby letters of credit. Outstanding borrowings under this line of credit were $6.4
million at a margin above prime and LIBOR rates plus margin averaging approximately 8.1% as
of December 31, 2005. |
|
|
|
|
Two term loans totaling $42.0 million. Outstanding borrowings under these term loans
were $42.0 million as of December 31, 2005. These loans were at LIBOR rates plus a margin
which averages approximately 7.8% at December 31, 2005. |
Borrowings under the July 2005 credit facilities were to mature in July 2007. Amounts outstanding
under the term loans as of July 2006 were to be repaid in monthly principal payments based on a 48
month repayment schedule with the remaining balance due at maturity. Additionally, during the
second year, we were to be required to prepay the remaining balance of the term loans by 75% of
excess cash flow, if any, after debt service and capital expenditures. The interest rate payable
on borrowings was based on a margin over the London Interbank Offered Rate, referred to as LIBOR,
or the prime rate, and there was a 0.5% fee on the undrawn portion of the revolving line of credit.
The margin over LIBOR was to increase by 1.0% in the second year.
13
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 7 DEBT (Continued)
All amounts outstanding under our July 2005 credit agreement were paid off with the proceeds of our
senior notes offering on January 18, 2006. On January 18, 2006, we also executed an amended and
restated credit agreement which provides for a $25.0 million revolving line of credit with a
maturity of January 2010. Our January 2006 amended and restated credit agreement contains
customary events of default and financial covenants and limits our ability to incur additional
indebtedness, make capital expenditures, pay dividends or make other distributions, create liens
and sell assets. Our obligations under the January 2006 amended and restated credit agreement are
secured by substantially all of our assets.
As part of our acquisition of DLS, we assumed various bank loans with floating interest rates based
on LIBOR plus a margin and terms ranging from 2 to 5 years. The weighted average margin was 1.6%
at September 30, 2006. The bank loans are denominated in U.S. dollars and the outstanding amount
due as of September 30, 2006 was $7.9 million.
Notes payable and real estate loan
On July 11, 2005, we acquired from M-I its 45% equity interest in AirComp and the subordinated note
in the principal amount of $4.8 million issued by AirComp, for which we paid M-I $7.1 million in
cash and issued a new $4.0 million subordinated note bearing interest at 5.0% per annum. The
subordinated note issued to M-I required quarterly interest payments and the principal amount was
due October 9, 2007. Contingent upon a future equity offering, the subordinated note was
convertible into up to 700,000 shares of our common stock at a conversion price equal to the market
value of the common stock at the time of conversion. This note was repaid from the proceeds of our
offering of $95.0 million of 9.0% senior notes, which we completed in August 2006.
As of December 31, 2005, Allis-Chalmers Tubular Services Inc., or Tubular, had a subordinated note
outstanding and payable to Jens Mortensen, the seller of Tubular and one of our directors, in the
amount of $4.0 million with a fixed interest rate of 7.5%. Interest was payable quarterly and the
final maturity of the note was January 31, 2006. The subordinated note was subordinated to the
rights of our bank lenders. The balance of this subordinated note was repaid in full in January
2006 with proceeds from our senior notes offering.
As part of the acquisition of Mountain Compressed Air Inc., or Mountain Air, in 2001, we issued a
note to the sellers of Mountain Air in the original amount of $2.2 million accruing interest at a
rate of 5.75% per annum. The note was reduced to $1.5 million as a result of the settlement of a
legal action against the sellers in 2003. In March 2005, we reached an agreement with the sellers
and holders of the note as a result of an action brought against us by the sellers. Under the
terms of the agreement, we paid the holders of the note $1.0 million in cash, and agreed to pay an
additional $350,000 on June 1, 2006, and an additional $150,000 on June 1, 2007, in settlement of
all claims. At September 30, 2006 and December 31, 2005 the outstanding amounts due were $150,000
and $500,000, respectively.
In connection with the purchase of Delta, we issued to the sellers a note in the amount of
$350,000. The note bore interest at 2% and the principal and accrued interest was repaid on its
maturity of April 1, 2006. In connection with the acquisition of Rogers, we issued to the seller a
note in the amount of $750,000. The note bears interest at 5.0% and is due April 3, 2009.
In connection with the purchase of Tubular, we agreed to pay a total of $1.2 million to Mr.
Mortensen in exchange for a non-compete agreement. Monthly payments of $20,576 are due under this
agreement through January 31, 2007. In connection with the purchase of Safco-Oil Field Products,
Inc., or Safco, we also agreed to pay a total of $150,000 to the sellers in exchange for a
non-compete agreement. We are required to make annual payments of $50,000 through September 30,
2007. In connection with the purchase of Capcoil, we agreed to pay a total of $500,000 to two
management employees in exchange for non-compete agreements. We are required to make annual
payments of $110,000 through May 2008. Total amounts due under these non-compete agreements at
September 30, 2006 and December 31, 2005 were $332,000 and $698,000, respectively.
In 2000 we compensated directors, including current directors Nederlander and Toboroff, who served
on the board of directors from 1989 to March 31, 1999 without compensation, by issuing promissory
notes totaling $325,000. The notes bear interest at the rate of 5.0%. At September 30, 2006 and
December 31, 2005, the principal and accrued interest on these notes totaled approximately $32,000
and $96,000, respectively.
14
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 7 DEBT (Continued)
We also had a real estate loan which was payable in equal monthly installments of $4,344 with the
remaining outstanding balance due on January 1, 2010. The loan had a floating interest rate based
on prime plus 2.0%. The outstanding principal balance was $548,000 at December 31, 2005. The
balance of this loan was repaid in full in January 2006 with proceeds from our senior notes
offering.
Other debt
We have various rig and equipment financing loans with interest rates ranging from 5.0% to 8.7% and
terms of 2 to 5 years. As of September 30, 2006 and December 31, 2005, the outstanding balances
for rig and equipment financing loans were $4.4 million and $1.9 million, respectively. In April
2006 and August 2006, we obtained insurance premium financings in the amount of $1.9 million and
$896,000 with fixed interest rates of 5.6% and 6.0%, respectively. Under terms of the agreements,
amounts outstanding are paid over 10 month and 11 month repayment schedules. The outstanding
balance of these notes was approximately $1.8 million as of September 30, 2006. We also have
various capital leases with terms that expire in 2008. As of September 30, 2006 and December 31,
2005, amounts outstanding under capital leases were $543,000 and $917,000, respectively. In January
2006, we prepaid $350,000 of the outstanding equipment loans with proceeds from our senior notes
offering.
NOTE 8
STOCKHOLDERS EQUITY
We issued 125,285 and 2,500,000 shares of our common stock in relation to the Rogers and DLS
acquisition, respectively (see Note 2).
On August 14, 2006 we closed on a public offering of 3,450,000 shares of our common stock at a
public offering price of $14.50 per share. Net proceeds from the public offering of $47.5 million
were used to fund a portion of our acquisition of DLS.
We also had options and warrants exercised in the first nine months of 2006, which resulted in
1,648,608 shares of our common stock being issued for approximately $5.4 million. We recognized
approximately $2.6 million of compensation expense related to stock options in the first nine
months of 2006 that was recorded as capital in excess of par value (see Note 3).
NOTE 9 CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Set forth on the following pages are the condensed consolidating financial statements of (i)
Allis-Chalmers Energy Inc., (ii) its subsidiaries that are guarantors of the senior notes and
revolving credit facility and (iii) the subsidiaries that are not guarantors of the senior notes
and revolving credit facility. Prior to the acquisition of DLS, all of our subsidiaries were
guarantors of our senior notes and revolving credit facility (in thousands, except for share and
per share amounts).
15
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 9 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
September 30, 2006 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash equivalents |
|
$ |
|
|
|
$ |
48,679 |
|
|
$ |
1,632 |
|
|
$ |
|
|
|
$ |
50,311 |
|
Trade receivables, net |
|
|
|
|
|
|
53,342 |
|
|
|
31,814 |
|
|
|
|
|
|
|
85,156 |
|
Inventory |
|
|
|
|
|
|
10,723 |
|
|
|
15,090 |
|
|
|
|
|
|
|
25,813 |
|
Intercompany receivables |
|
|
110,149 |
|
|
|
|
|
|
|
|
|
|
|
(110,149 |
) |
|
|
|
|
Note receivable from affiliate |
|
|
5,897 |
|
|
|
|
|
|
|
|
|
|
|
(5,897 |
) |
|
|
|
|
Prepaid expenses and other |
|
|
|
|
|
|
2,816 |
|
|
|
3,558 |
|
|
|
|
|
|
|
6,374 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
116,046 |
|
|
|
115,560 |
|
|
|
52,094 |
|
|
|
(116,046 |
) |
|
|
167,654 |
|
Property and equipment, net |
|
|
|
|
|
|
189,452 |
|
|
|
152,031 |
|
|
|
|
|
|
|
341,483 |
|
Goodwill |
|
|
|
|
|
|
12,417 |
|
|
|
|
|
|
|
|
|
|
|
12,417 |
|
Other intangible assets, net |
|
|
609 |
|
|
|
6,096 |
|
|
|
97 |
|
|
|
|
|
|
|
6,802 |
|
Debt issuance costs, net |
|
|
8,585 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,585 |
|
Note receivable from affiliates |
|
|
10,354 |
|
|
|
|
|
|
|
|
|
|
|
(10,354 |
) |
|
|
|
|
Investments in affiliates |
|
|
306,349 |
|
|
|
|
|
|
|
|
|
|
|
(306,349 |
) |
|
|
|
|
Other assets |
|
|
5 |
|
|
|
129 |
|
|
|
22 |
|
|
|
(1 |
) |
|
|
155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
441,948 |
|
|
$ |
323,654 |
|
|
$ |
204,244 |
|
|
$ |
(432,750 |
) |
|
$ |
537,096 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt |
|
$ |
|
|
|
$ |
4,919 |
|
|
$ |
3,574 |
|
|
$ |
|
|
|
$ |
8,493 |
|
Trade accounts payable |
|
|
31 |
|
|
|
9,861 |
|
|
|
16,419 |
|
|
|
|
|
|
|
26,311 |
|
Accrued salaries, benefits and payroll taxes |
|
|
|
|
|
|
2,644 |
|
|
|
7,406 |
|
|
|
|
|
|
|
10,050 |
|
Accrued interest |
|
|
4,950 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,950 |
|
Accrued income taxes |
|
|
3 |
|
|
|
53 |
|
|
|
2,845 |
|
|
|
|
|
|
|
2,901 |
|
Accrued expenses |
|
|
129 |
|
|
|
8,280 |
|
|
|
5,444 |
|
|
|
|
|
|
|
13,853 |
|
Intercompany payables |
|
|
|
|
|
|
110,149 |
|
|
|
|
|
|
|
(110,149 |
) |
|
|
|
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
5,897 |
|
|
|
(5,897 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
5,113 |
|
|
|
135,906 |
|
|
|
41,585 |
|
|
|
(116,046 |
) |
|
|
66,558 |
|
Accrued postretirement benefit obligations |
|
|
304 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
304 |
|
Long-term debt, net of current maturities |
|
|
255,782 |
|
|
|
1,200 |
|
|
|
5,484 |
|
|
|
|
|
|
|
262,466 |
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
10,354 |
|
|
|
(10,354 |
) |
|
|
|
|
Deferred income taxes |
|
|
281 |
|
|
|
213 |
|
|
|
26,229 |
|
|
|
|
|
|
|
26,723 |
|
Other long-term liabilities |
|
|
|
|
|
|
577 |
|
|
|
|
|
|
|
|
|
|
|
577 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
261,480 |
|
|
|
137,896 |
|
|
|
83,652 |
|
|
|
(126,400 |
) |
|
|
356,628 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock |
|
|
246 |
|
|
|
3,425 |
|
|
|
42,963 |
|
|
|
(46,388 |
) |
|
|
246 |
|
Capital in excess of par value |
|
|
153,135 |
|
|
|
133,918 |
|
|
|
74,969 |
|
|
|
(208,887 |
) |
|
|
153,135 |
|
Retained earnings |
|
|
27,087 |
|
|
|
48,415 |
|
|
|
2,660 |
|
|
|
(51,075 |
) |
|
|
27,087 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
180,468 |
|
|
|
185,758 |
|
|
|
120,592 |
|
|
|
(306,350 |
) |
|
|
180,468 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stock
holders equity |
|
$ |
441,948 |
|
|
$ |
323,654 |
|
|
$ |
204,244 |
|
|
$ |
(432,750 |
) |
|
$ |
537,096 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 9 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Three Months Ended September 30, 2006 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
Revenues |
|
$ |
|
|
|
$ |
61,885 |
|
|
$ |
23,853 |
|
|
$ |
|
|
|
$ |
85,738 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs |
|
|
|
|
|
|
34,173 |
|
|
|
17,324 |
|
|
|
|
|
|
|
51,497 |
|
Depreciation |
|
|
|
|
|
|
3,949 |
|
|
|
1,499 |
|
|
|
|
|
|
|
5,448 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of revenues |
|
|
|
|
|
|
38,122 |
|
|
|
18,823 |
|
|
|
|
|
|
|
56,945 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin |
|
|
|
|
|
|
23,763 |
|
|
|
5,030 |
|
|
|
|
|
|
|
28,793 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
637 |
|
|
|
7,534 |
|
|
|
887 |
|
|
|
|
|
|
|
9,058 |
|
Amortization |
|
|
293 |
|
|
|
385 |
|
|
|
3 |
|
|
|
|
|
|
|
681 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
(930 |
) |
|
|
15,844 |
|
|
|
4,140 |
|
|
|
|
|
|
|
19,054 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in
affiliates, net of tax |
|
|
16,872 |
|
|
|
|
|
|
|
|
|
|
|
(16,872 |
) |
|
|
|
|
Interest, net |
|
|
(4,701 |
) |
|
|
264 |
|
|
|
(223 |
) |
|
|
|
|
|
|
(4,660 |
) |
Other |
|
|
11 |
|
|
|
(20 |
) |
|
|
(17 |
) |
|
|
|
|
|
|
(26 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
(expense) |
|
|
12,182 |
|
|
|
244 |
|
|
|
(240 |
) |
|
|
(16,872 |
) |
|
|
(4,686 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before income
taxes |
|
|
11,252 |
|
|
|
16,088 |
|
|
|
3,900 |
|
|
|
(16,872 |
) |
|
|
14,368 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes |
|
|
|
|
|
|
(1,876 |
) |
|
|
(1,240 |
) |
|
|
|
|
|
|
(3,116 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
11,252 |
|
|
$ |
14,212 |
|
|
$ |
2,660 |
|
|
$ |
(16,872 |
) |
|
$ |
11,252 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 9 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Nine Months Ended September 30, 2006 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
Revenues |
|
$ |
|
|
|
$ |
169,383 |
|
|
$ |
23,853 |
|
|
$ |
|
|
|
$ |
193,236 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs |
|
|
|
|
|
|
93,254 |
|
|
|
17,324 |
|
|
|
|
|
|
|
110,578 |
|
Depreciation |
|
|
|
|
|
|
11,107 |
|
|
|
1,499 |
|
|
|
|
|
|
|
12,606 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of revenues |
|
|
|
|
|
|
104,361 |
|
|
|
18,823 |
|
|
|
|
|
|
|
123,184 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin |
|
|
|
|
|
|
65,022 |
|
|
|
5,030 |
|
|
|
|
|
|
|
70,052 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
2,032 |
|
|
|
21,621 |
|
|
|
887 |
|
|
|
|
|
|
|
24,540 |
|
Amortization |
|
|
777 |
|
|
|
1,174 |
|
|
|
3 |
|
|
|
|
|
|
|
1,954 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
(2,809 |
) |
|
|
42,227 |
|
|
|
4,140 |
|
|
|
|
|
|
|
43,558 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in
affiliates,
net of
tax |
|
|
39,644 |
|
|
|
|
|
|
|
|
|
|
|
(39,644 |
) |
|
|
|
|
Interest, net |
|
|
(11,601 |
) |
|
|
(261 |
) |
|
|
(223 |
) |
|
|
|
|
|
|
(12,085 |
) |
Other |
|
|
36 |
|
|
|
(25 |
) |
|
|
(17 |
) |
|
|
|
|
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
(expense) |
|
|
28,079 |
|
|
|
(286 |
) |
|
|
(240 |
) |
|
|
(39,644 |
) |
|
|
(12,091 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before income
taxes |
|
|
25,270 |
|
|
|
41,941 |
|
|
|
3,900 |
|
|
|
(39,644 |
) |
|
|
31,467 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes |
|
|
|
|
|
|
(4,957 |
) |
|
|
(1,240 |
) |
|
|
|
|
|
|
(6,197 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
25,270 |
|
|
$ |
36,984 |
|
|
$ |
2,660 |
|
|
$ |
(39,644 |
) |
|
$ |
25,270 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 9 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
September 30, 2006 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis- |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
Cash Flows from Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
25,270 |
|
|
$ |
36,984 |
|
|
$ |
2,660 |
|
|
$ |
(39,644 |
) |
|
$ |
25,270 |
|
Adjustments to reconcile net income to
net cash provided by operating
activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation |
|
|
|
|
|
|
11,107 |
|
|
|
1,499 |
|
|
|
|
|
|
|
12,606 |
|
Amortization |
|
|
777 |
|
|
|
1,177 |
|
|
|
|
|
|
|
|
|
|
|
1,954 |
|
Imputed interest |
|
|
|
|
|
|
355 |
|
|
|
|
|
|
|
|
|
|
|
355 |
|
Stock option expense |
|
|
1,655 |
|
|
|
983 |
|
|
|
|
|
|
|
|
|
|
|
2,638 |
|
Provision for bad debts |
|
|
|
|
|
|
353 |
|
|
|
|
|
|
|
|
|
|
|
353 |
|
Equity earnings in affiliates |
|
|
(39,644 |
) |
|
|
|
|
|
|
|
|
|
|
39,644 |
|
|
|
|
|
Deferred taxes |
|
|
281 |
|
|
|
213 |
|
|
|
|
|
|
|
|
|
|
|
494 |
|
(Gain) loss on sale of equipment |
|
|
|
|
|
|
(729 |
) |
|
|
1 |
|
|
|
|
|
|
|
(728 |
) |
Changes in operating assets and
liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Increase) decrease in trade
receivables |
|
|
|
|
|
|
(17,883 |
) |
|
|
722 |
|
|
|
|
|
|
|
(17,161 |
) |
(Increase) decrease in inventory |
|
|
|
|
|
|
(2,325 |
) |
|
|
164 |
|
|
|
|
|
|
|
(2,161 |
) |
Decrease in other current assets |
|
|
396 |
|
|
|
660 |
|
|
|
266 |
|
|
|
|
|
|
|
1,322 |
|
(Increase) decrease in other assets |
|
|
548 |
|
|
|
79 |
|
|
|
(97 |
) |
|
|
|
|
|
|
530 |
|
(Decrease) increase in accounts
payable |
|
|
(82 |
) |
|
|
(1,159 |
) |
|
|
(368 |
) |
|
|
|
|
|
|
(1,609 |
) |
(Decrease) increase in accrued
interest |
|
|
4,703 |
|
|
|
(42 |
) |
|
|
|
|
|
|
|
|
|
|
4,661 |
|
(Decrease) increase in accrued
expenses |
|
|
(387 |
) |
|
|
3,560 |
|
|
|
(657 |
) |
|
|
|
|
|
|
2,516 |
|
(Decrease) increase in accrued
salaries, benefits and payroll
taxes |
|
|
(1,957 |
) |
|
|
2,988 |
|
|
|
2,079 |
|
|
|
|
|
|
|
3,110 |
|
Increase in other long- term
liabilities |
|
|
(31 |
) |
|
|
(782 |
) |
|
|
|
|
|
|
|
|
|
|
(813 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By Operating
Activities |
|
|
(8,471 |
) |
|
|
35,539 |
|
|
|
6,269 |
|
|
|
|
|
|
|
33,337 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of businesses, net of cash |
|
|
(191,940 |
) |
|
|
(11,667 |
) |
|
|
418 |
|
|
|
|
|
|
|
(203,189 |
) |
Notes receivable from affiliates |
|
|
1,005 |
|
|
|
|
|
|
|
|
|
|
|
(1,005 |
) |
|
|
|
|
Proceeds from sale of equipment |
|
|
|
|
|
|
3,516 |
|
|
|
|
|
|
|
|
|
|
|
3,516 |
|
Purchase of property and equipment |
|
|
|
|
|
|
(22,721 |
) |
|
|
(3,090 |
) |
|
|
|
|
|
|
(25,811 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Investing
Activities |
|
|
(190,935 |
) |
|
|
(30,872 |
) |
|
|
(2,672 |
) |
|
|
(1,005 |
) |
|
|
(225,484 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from exercises of
options/warrants |
|
|
5,406 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,406 |
|
Proceeds from issuance of common stock, |
|
|
46,484 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
46,484 |
|
Accounts receivable from affiliates |
|
|
(51,691 |
) |
|
|
|
|
|
|
|
|
|
|
51,691 |
|
|
|
|
|
19
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 9 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
September 30, 2006 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis- |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
Cash Flows from Financing Activities: (continued) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable to affiliates |
|
|
|
|
|
|
51,691 |
|
|
|
|
|
|
|
(51,691 |
) |
|
|
|
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
(1,005 |
) |
|
|
1,005 |
|
|
|
|
|
Proceeds from long-term debt |
|
|
256,064 |
|
|
|
1,756 |
|
|
|
|
|
|
|
|
|
|
|
257,820 |
|
Proceeds from line of credit |
|
|
5,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,000 |
|
Repayments on long-term debt |
|
|
(43,478 |
) |
|
|
(7,274 |
) |
|
|
(960 |
) |
|
|
|
|
|
|
(51,712 |
) |
Repayments on related party debt |
|
|
|
|
|
|
(3,031 |
) |
|
|
|
|
|
|
|
|
|
|
(3,031 |
) |
Repayments on line of credit |
|
|
(11,400 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11,400 |
) |
Debt issuance costs |
|
|
(8,029 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,029 |
) |
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
Net Cash Provided By Financing
Activities |
|
|
198,356 |
|
|
|
43,142 |
|
|
|
(1,965 |
) |
|
|
1,005 |
|
|
|
240,538 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents |
|
|
(1,050 |
) |
|
|
47,809 |
|
|
|
1,632 |
|
|
|
|
|
|
|
48,391 |
|
Cash and cash equivalents at beginning of
year |
|
|
1,050 |
|
|
|
870 |
|
|
|
|
|
|
|
|
|
|
|
1,920 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
|
|
|
$ |
48,679 |
|
|
$ |
1,632 |
|
|
$ |
|
|
|
$ |
50,311 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE
10 SUPPLEMENTAL CASH FLOW INFORMATION
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended |
|
|
September 30, |
|
|
2006 |
|
2005 |
|
|
(in thousands) |
Cash paid for interest and income taxes: |
|
|
|
|
|
|
|
|
Interest |
|
$ |
7,584 |
|
|
$ |
2,151 |
|
Income taxes |
|
$ |
5,581 |
|
|
$ |
459 |
|
|
|
|
|
|
|
|
|
|
Noncash activities: |
|
|
|
|
|
|
|
|
Insurance premium financed |
|
$ |
2,871 |
|
|
$ |
|
|
Common stock issued for acquisition of business |
|
$ |
39,795 |
|
|
$ |
|
|
Note payable issued for acquisition of business |
|
$ |
750 |
|
|
$ |
|
|
Settlement of lease receivable in conjunction with acquisition |
|
$ |
|
|
|
$ |
592 |
|
Deferred income taxes |
|
|
|
|
|
|
750 |
|
Non-compete payable in the future |
|
$ |
250 |
|
|
$ |
|
|
NOTE 11- SEGMENT INFORMATION
At September 30, 2006, we had six operating segments including Directional Drilling Services,
Rental Tools, International Drilling, Casing and Tubing Services, Compressed Air Drilling Services
and Production Services. All of the segments provide services to the energy industry. The
revenues, operating income (loss), depreciation and amortization, capital expenditures and assets
of each of the reporting segments, plus the corporate function, are reported below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended |
|
|
For the Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Directional drilling services |
|
$ |
18,962 |
|
|
$ |
11,383 |
|
|
$ |
52,331 |
|
|
$ |
32,218 |
|
Rental tools |
|
|
13,203 |
|
|
|
1,559 |
|
|
|
36,331 |
|
|
|
3,499 |
|
International drilling |
|
|
23,853 |
|
|
|
|
|
|
|
23,853 |
|
|
|
|
|
Casing and tubing services |
|
|
13,762 |
|
|
|
5,103 |
|
|
|
37,790 |
|
|
|
12,596 |
|
Compressed air drilling services |
|
|
12,000 |
|
|
|
7,637 |
|
|
|
32,048 |
|
|
|
16,684 |
|
Production services |
|
|
3,958 |
|
|
|
3,226 |
|
|
|
10,883 |
|
|
|
6,833 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
85,738 |
|
|
$ |
28,908 |
|
|
$ |
193,236 |
|
|
$ |
71,830 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Directional drilling services |
|
$ |
5,125 |
|
|
$ |
1,696 |
|
|
$ |
12,097 |
|
|
$ |
5,069 |
|
Rental tools |
|
|
6,575 |
|
|
|
454 |
|
|
|
18,881 |
|
|
|
780 |
|
International drilling |
|
|
4,139 |
|
|
|
|
|
|
|
4,139 |
|
|
|
|
|
Casing and tubing services |
|
|
3,734 |
|
|
|
1,336 |
|
|
|
9,899 |
|
|
|
4,015 |
|
Compressed air drilling services |
|
|
3,176 |
|
|
|
1,802 |
|
|
|
8,617 |
|
|
|
3,331 |
|
Production services |
|
|
119 |
|
|
|
(128 |
) |
|
|
737 |
|
|
|
(130 |
) |
General corporate |
|
|
(3,814 |
) |
|
|
(1,636 |
) |
|
|
(10,812 |
) |
|
|
(4,380 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
19,054 |
|
|
$ |
3,524 |
|
|
$ |
43,558 |
|
|
$ |
8,685 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 11 SEGMENT INFORMATION (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended |
|
|
For the Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Depreciation and Amortization: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Directional drilling services |
|
$ |
406 |
|
|
$ |
295 |
|
|
$ |
1,054 |
|
|
$ |
652 |
|
Rental tools |
|
|
1,735 |
|
|
|
121 |
|
|
|
5,121 |
|
|
|
386 |
|
International drilling |
|
|
1,502 |
|
|
|
|
|
|
|
1,502 |
|
|
|
|
|
Casing and tubing services |
|
|
968 |
|
|
|
510 |
|
|
|
2,736 |
|
|
|
1,418 |
|
Compressed air drilling services |
|
|
821 |
|
|
|
536 |
|
|
|
2,236 |
|
|
|
1,406 |
|
Production services |
|
|
329 |
|
|
|
279 |
|
|
|
921 |
|
|
|
604 |
|
General corporate |
|
|
368 |
|
|
|
102 |
|
|
|
990 |
|
|
|
203 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
6,129 |
|
|
$ |
1,843 |
|
|
$ |
14,560 |
|
|
$ |
4,669 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Directional drilling services |
|
$ |
384 |
|
|
$ |
945 |
|
|
$ |
3,789 |
|
|
$ |
2,145 |
|
Rental tools |
|
|
1,715 |
|
|
|
271 |
|
|
|
2,816 |
|
|
|
278 |
|
International drilling |
|
|
3,090 |
|
|
|
|
|
|
|
3,090 |
|
|
|
|
|
Casing and tubing services |
|
|
2,300 |
|
|
|
1,373 |
|
|
|
7,800 |
|
|
|
3,230 |
|
Compressed air drilling services |
|
|
3,286 |
|
|
|
915 |
|
|
|
6,302 |
|
|
|
2,841 |
|
Production services |
|
|
686 |
|
|
|
606 |
|
|
|
1,732 |
|
|
|
896 |
|
General corporate |
|
|
104 |
|
|
|
12 |
|
|
|
282 |
|
|
|
195 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
11,565 |
|
|
$ |
4,122 |
|
|
$ |
25,811 |
|
|
$ |
9,585 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of |
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
Goodwill: |
|
|
|
|
|
|
|
|
Directional drilling services |
|
$ |
4,168 |
|
|
$ |
4,168 |
|
Rental tools |
|
|
|
|
|
|
|
|
International drilling |
|
|
|
|
|
|
|
|
Casing and tubing services |
|
|
3,673 |
|
|
|
3,673 |
|
Compressed air drilling services |
|
|
3,950 |
|
|
|
3,950 |
|
Production services |
|
|
626 |
|
|
|
626 |
|
General corporate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
12,417 |
|
|
$ |
12,417 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
Directional drilling services |
|
$ |
28,222 |
|
|
$ |
20,960 |
|
Rental tools |
|
|
107,391 |
|
|
|
8,034 |
|
International drilling |
|
|
204,243 |
|
|
|
|
|
Casing and tubing services |
|
|
69,849 |
|
|
|
45,351 |
|
Compressed air drilling services |
|
|
53,648 |
|
|
|
46,045 |
|
Production services |
|
|
14,218 |
|
|
|
12,282 |
|
General corporate |
|
|
59,525 |
|
|
|
4,683 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
537,096 |
|
|
$ |
137,355 |
|
|
|
|
|
|
|
|
22
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 11 SEGMENT INFORMATION (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended |
|
|
For the Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
60,108 |
|
|
$ |
27,486 |
|
|
$ |
163,770 |
|
|
$ |
66,879 |
|
International |
|
|
25,630 |
|
|
|
1,422 |
|
|
|
29,466 |
|
|
|
4,951 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
85,738 |
|
|
$ |
28,908 |
|
|
$ |
193,236 |
|
|
$ |
71,830 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE
12 LEGAL MATTERS
We are named from time to time in legal proceedings related to our activities prior to our
bankruptcy in 1988. However, we believe that we were discharged from liability for all such claims
in the bankruptcy and believe the likelihood of a material loss relating to any such legal
proceeding is remote.
We are also involved in various other legal proceedings in the ordinary course of business. The
legal proceedings are at different stages; however, we believe that the likelihood of material loss
relating to any such legal proceeding is remote.
NOTE
13 SUBSEQUENT EVENTS
On October 17, 2006, we completed the acquisition of all of the outstanding stock of Petro-Rentals,
Incorporated, or Petro, based in Broussard, Louisiana. The purchase price of Petro consisted of
$29.8 million in cash, which includes the payment of approximately $9.5 million of debt, and
246,761 shares of our common stock. The acquisition was funded with cash on hand remaining from
our recent equity and debt securities offerings. Petro serves both the onshore and offshore
markets from its division offices in Broussard, Houma and Arcadia, Louisiana as well as from Alvin,
Texas. Petro provides a variety of quality rental tools and equipment and services, with an
emphasis on production related equipment and services, including wire line services and equipment,
land and offshore pumping services and coiled tubing.
On October 26, 2006, we announced that we had entered into a definitive agreement to purchase
substantially all the assets of Oil & Gas Rental Services, Inc., or OGRS, a Louisiana based
corporation that provides rental tools to both offshore and onshore exploration and production
companies. The consideration for the acquisition of the assets will consist of $291.0 million in
cash and 3.2 million shares of our common stock, subject to post-closing working capital
adjustments. The transaction is expected to close in the fourth quarter. OGRS has an extensive
inventory of premium rental equipment, including drill pipe, spiral heavy weight drill pipe, tubing
work strings, blow-out preventers, choke manifolds and various valves and handling tools for oil
and natural gas drilling. OGRS has facilities in Morgan City, Louisiana and Victoria, Texas. The
purchase price is subject to post-closing adjustments based on the amount of OGRSs working capital
as of the closing date. In addition, upon execution of the Agreement, we deposited $9.0 million in
an interest bearing account. The deposit will be credited against the cash portion of the purchase
price at the closing, unless the closing does not occur on or prior to December 31, 2006, and as of
such date, all of the deposit forfeiture conditions in the agreement have been satisfied (in which
case, seller would retain the $9.0 million as liquidated damages).
We received a commitment, subject to customary conditions, from Royal Bank of Canada to extend a
bridge loan to finance the cash portion of the purchase price for the acquisition of OGRS.
23
ITEM 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
This document contains forward-looking statements that involve risks and uncertainties. Our actual
results may differ materially from the results discussed in such forward-looking statements.
Factors that might cause such differences include, but are not limited to, the general condition of
the oil and natural gas drilling industry, demand for our oil and natural gas service and rental
products, and competition. Other factors are identified in our SEC filings, including our Annual
Report on Form 10-K for the year ended December 31, 2005 under the heading Risk Factors located
at the end of Item 7, Managements Discussion and Analysis of Financial Condition and Results of
Operations.
The following discussion and analysis should be read in conjunction with our selected historical
financial data and our accompanying financial statements and the notes to those financial
statements included elsewhere in this document. The following discussion contains forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of 1995 that reflect
our plans, estimates and beliefs. Our actual results could differ materially from those
anticipated in these forward-looking statements as a result of risks and uncertainties, including,
but not limited to, those discussed above.
Overview of Our Business
We are a multi-faceted oilfield services company that provides services and equipment to oil and
natural gas exploration and production companies, domestically in Texas, Louisiana, New Mexico,
Colorado, Oklahoma, Mississippi, Utah, Wyoming, offshore in the Gulf of Mexico and internationally
in Argentina, Mexico and Bolivia. We currently operate in six sectors of the oil and natural gas
service industry: directional drilling services; rental tools; international drilling; casing and
tubing services; compressed air drilling services; and production services.
We derive operating revenues from rates per day and rates per job that we charge for the labor and
equipment required to provide a service and rates per day for equipment and tools that we rent to
our customers. The price we charge for our services depends upon several factors, including the
level of oil and natural gas drilling activity and the competitive environment in the particular
geographic regions in which we operate. Contracts are awarded based on price, quality of service
and equipment, and general reputation and experience of our personnel. The demand for drilling
services has historically been volatile and is affected by the capital expenditures of oil and
natural gas exploration and production companies, which can fluctuate based upon the prices of oil
and natural gas, or the expectation for the prices of oil and natural gas.
The number of working drilling rigs, typically referred to as the rig count, is an important
indicator of activity levels in the oil and natural gas industry. The rig count in the U.S.
increased from 862 as of December 31, 2002 to 1,744 on September 30, 2006 according to the Baker
Hughes rig count. Furthermore, directional and horizontal rig counts increased from 283 as of
December 31, 2002 to 724 on September 30, 2006, which accounted for 32.8% and 42.0% of the total
U.S. rig count, respectively. Currently, we believe that the number of available drillings rigs is
insufficient to meet the demand for drilling rigs. Consequently, unless a significant number of
additional drilling rigs are brought online, the rig count may not increase substantially despite
the strong demand.
Our cost of revenues represents all direct and indirect costs associated with the operation and
maintenance of our equipment. The principal elements of these costs are direct and indirect labor
and benefits, repairs and maintenance of our equipment, insurance, equipment rentals, fuel and
depreciation. Operating expenses do not fluctuate in direct proportion to changes in revenues
because, among other factors, we have a fixed base of inventory of equipment and facilities to
support our operations, and in periods of low drilling activity we may also seek to preserve labor
continuity to market our services and maintain our equipment.
24
Comparison of Three Months Ended September 30, 2006 and 2005
Our revenues for the three months ended September 30, 2006 were $85.7 million, an increase of
196.6% compared to $28.9 million for the three months ended September 30, 2005. Revenues increased
in all of our business segments due to acquisitions completed in the third quarter of 2005 and in
2006, the investment in additional equipment, improved pricing for our services, the addition of
operations and sales personnel and the opening of new operations offices. Revenues increased most
significantly due to the acquisition of DLS Drilling, Logistics & Services Corporation, or DLS, on
August 14, 2006 which expanded our operations to a sixth operating segment, international drilling.
Revenues also increased significantly at our rental tools segment due to the acquisition of
Specialty Rental Tools, Inc., or Specialty, effective January 1, 2006. Our casing and tubing
services segment also had a substantial increase in revenue, primarily due to the acquisitions of
the casing and tubing assets of Patterson Services, Inc on September 1, 2005, and the acquisition
of Rogers Oil Tool Services, Inc., or Rogers, as of April 1, 2006, along with improved market
conditions and increased market penetration for our services in South Texas, East Texas, Louisiana
and the U.S. Gulf of Mexico. Revenues increased at our compressed air drilling segment due to the
purchase of additional equipment and improved pricing for our services. Our directional drilling
services segment revenues increased in the 2006 period compared to the 2005 period due to improved
pricing for directional drilling services, the August 2005 acquisition of Target Energy, Inc., or
Target, which provides measurement-while-drilling tools, or MWD and the purchase of additional
down-hole motors and MWDs which increased our capacity and market presence.
Our gross profit for the quarter ended September 30, 2006 increased 249.6% to $28.8 million, or
33.6% of revenues, compared to $8.2 million, or 28.5%, of revenues for the three months ended
September 30, 2005. The increase in gross profit is due to the increase in revenues in all of our
business segments. The increase in gross profit as a percentage of revenues is primarily due to
the acquisition of Specialty as of January 1, 2006, in the high margin rental tool business and the
improved pricing for our services generally. The high margin rental tool business was offset in
part by the lower margins that DLS achieves in the international drilling segment. Also
contributing to our improved gross profit margin was the acquisition of Target, the purchase of
additional MWDs and the acquisition of Rogers. The increase in gross profit was partially offset
by an increase in depreciation expense of 291.7% to $5.5 million for the third quarter of 2006
compared to $1.4 million for the third quarter of 2005. The increase is due to additional
depreciable assets resulting from the acquisitions and capital expenditures. Our cost of revenues
consists principally of our labor costs and benefits, equipment rentals, maintenance and repairs of
our equipment, depreciation, insurance and fuel. Because many of our costs are fixed, our gross
profit as a percentage of revenues is generally affected by our level of revenues.
General and administrative expense was $9.1 million in the third quarter of 2006 period compared to
$4.3 million for the third quarter of 2005. General and administrative expense increased due to
the additional expenses associated with the acquisitions, and the hiring of additional sales and
administrative personnel. General and administrative expense also increased because of increased
accounting and consulting fees and other expenses in connection with initiatives to strengthen our
internal control processes, costs related to Sarbanes Oxley compliance efforts and increased
corporate accounting and administrative staff. As a percentage of revenues, general and
administrative expenses were 10.6% in the 2006 quarter and 14.7% in the 2005 quarter.
We adopted SFAS No. 123R, Share-Based Payment, effective January 1, 2006. This statement requires
all share-based payments to employees, including grants of employee stock options, to be recognized
in the financial statements based on their grant-date fair values. We adopted SFAS No. 123R using
the modified prospective transition method, utilizing the Black-Scholes option pricing model for
the calculation of the fair value of our employee stock options. Under the modified prospective
method, we record compensation cost related to unvested stock awards as of December 31, 2005 by
recognizing the unamortized grant date fair value of these awards over the remaining vesting
periods of those awards with no change in historical reported earnings. Therefore, we recorded an
expense of $0.9 million related to stock options for the three months ended September 30, 2006, of
which $727,000 was recorded in general and administrative expense with the balance being recorded
as a direct cost. Prior to January 1, 2006, we accounted for our stock-based compensation using
Accounting Principle Board Opinion No. 25. Under APB No. 25, compensation expense is recognized
for stock options with an exercise price that is less than the market price on the grant date of
the option. Accordingly, no compensation cost was recognized under APB No. 25.
Amortization expense was $681,000 in the third quarter of 2006 compared to $452,000 in the third
quarter of 2005. The increase in amortization expense is due to the amortization of intangible
assets in connection with our acquisitions and the amortization of deferred financing costs.
25
Income from operations for the three months ended September 30, 2006 totaled $19.1 million, a
440.7% increase over income from operations of $3.5 million for the three months ended September
30, 2005, reflecting the increase in our revenues and gross profit, offset in part by increased
general and administrative expenses and amortization.
Our net interest expense was $4.7 million in the third quarter of 2006, compared to $2.1 million
for the third quarter of 2005. Interest expense increased in the 2006 quarter due to the increased
debt at a higher average interest rate. In January of 2006 we issued $160.0 million of senior
notes bearing interest at 9.0% to fund the acquisition of Specialty, pay off other outstanding debt
and for working capital. In August of 2006 we issued an additional $95.0 million of senior notes
bearing interest at 9.0% to fund a portion of the acquisition of DLS. In the third quarter of
2005, we incurred debt retirement expense of $1.1 million related to the refinancing of our debt.
This amount includes prepayment penalties and the write-off of deferred financing fees from a
previous financing.
Our provision for income taxes for the quarter ended September 30, 2006 was $3.1 million, or 21.7%
of our net income before income taxes, compared to $230,000, or 15.1% of our net income before
income taxes for the three months ended September 30, 2005. The increase in income taxes is
attributable to our higher operating income and the increase in percentage of income taxes to net
income before income taxes is primarily attributable to our operations in Argentina which are taxed
at 35.0%.
We had net income of $11.3 million for the third quarter of 2006, an increase of 770.2%, compared
to net income of $1.3 million for the third quarter of 2005.
The following table compares revenues and income from operations for each of our business segments.
Income (loss) from operations consists of revenues less cost of revenues, general and
administrative expenses, and depreciation and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
Income (Loss) from Operations |
|
|
|
Three Months Ended |
|
|
Three Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2006 |
|
|
2005 |
|
|
Change |
|
|
2006 |
|
|
2005 |
|
|
Change |
|
|
|
(in thousands) |
|
Directional drilling services |
|
$ |
18,962 |
|
|
$ |
11,383 |
|
|
$ |
7,579 |
|
|
$ |
5,125 |
|
|
$ |
1,696 |
|
|
$ |
3,429 |
|
Rental tools |
|
|
13,203 |
|
|
|
1,559 |
|
|
|
11,644 |
|
|
|
6,575 |
|
|
|
454 |
|
|
|
6,121 |
|
International drilling |
|
|
23,853 |
|
|
|
|
|
|
|
23,853 |
|
|
|
4,139 |
|
|
|
|
|
|
|
4,139 |
|
Casing and tubing services |
|
|
13,762 |
|
|
|
5,103 |
|
|
|
8,659 |
|
|
|
3,734 |
|
|
|
1,336 |
|
|
|
2,398 |
|
Compressed air drilling services |
|
|
12,000 |
|
|
|
7,637 |
|
|
|
4,363 |
|
|
|
3,176 |
|
|
|
1,802 |
|
|
|
1,374 |
|
Production services |
|
|
3,958 |
|
|
|
3,226 |
|
|
|
732 |
|
|
|
119 |
|
|
|
(128 |
) |
|
|
247 |
|
General corporate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,814 |
) |
|
|
(1,636 |
) |
|
|
(2,178 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
85,738 |
|
|
$ |
28,908 |
|
|
$ |
56,830 |
|
|
$ |
19,054 |
|
|
$ |
3,524 |
|
|
$ |
15,530 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Directional Drilling Services Segment
Revenues for the quarter ended September 30, 2006 for our directional drilling services segment
were $19.0 million, an increase of 66.6% from the $11.4 million in revenues for the quarter ended
September 30, 2005. Income from operations increased 202.2% to $5.1 million for the third quarter
of 2006 from $1.7 million for the comparable 2005 period. The improved results for this segment
are due to the increase in drilling activity in the Texas and Gulf Coast areas, improved pricing
for directional and horizontal drilling services, the acquisition of Target as of August 1, 2005,
the purchase of an additional six MWDs. Our increased operating expenses as a result of the
addition of operations and personnel were more than offset by the growth in revenues and improved
pricing for our services.
Rental Tools Segment
Revenues for the quarter ended September 30, 2006 for the rental tools segment were $13.2 million,
an increase from $1.6 million in revenues for the quarter ended September 30, 2005. Income from
operations increased to $6.6 million in the 2006 period compared to $454,000 in the 2005 period.
Our rental tools revenues and operating income for the third quarter of 2006 increased compared to
the prior year due primarily due to the acquisition of Specialty. Specialty was acquired as of
January 1, 2006, the effective date of the acquisition. Safco-Oil Field Products, Inc., or Safco,
Delta Rental Service, Inc., or Delta, and Specialty were merged in February 2006 to form
Allis-Chalmers Rental Tools, Inc
26
International Drilling Segment
On August 14, 2006, we acquired DLS which established the international drilling segment for us.
Revenues for the quarter ended September 30, 2006 for the international drilling segment were $23.9
million and the income from operations was $4.1 million.
Casing and Tubing Services Segment
Revenues for the quarter ended September 30, 2006 for the casing and tubing services segment were
$13.8 million, an increase of 169.7% from the $5.1 million in revenues for the quarter ended
September 30, 2005. Revenues from domestic operations increased to $12.3 million in the 2006
period from $3.8 million in the 2005 period as a result of the acquisition of Rogers and the casing
and tubing assets of Patterson Services on September 1, 2005, which resulted in increased market
penetration for our services in South Texas, East Texas, Louisiana and the U.S. Gulf of Mexico, and
the impact of hurricanes in September 2005. Revenues from Mexico operations were $1.5 million for
the third quarter of 2006 and $1.3 million in the third quarter of 2005. Income from operations
increased 179.5% to $3.7 million in the third quarter of 2006 from $1.3 million in the third
quarter of 2005. The increase in this segments operating income is due to our increased revenues
from domestic operations.
Compressed Air Drilling Services Segment
Our compressed air drilling revenues were $12.0 million for the three months ended September 30,
2006, an increase of 57.1% compared to $7.6 million in revenues for the three months ended
September 30, 2005. Income from operations increased to $3.2 million in the 2006 period compared
to income from operations of $1.8 million in the 2005 period. Our compressed air drilling revenues
and operating income for the third quarter of 2006 increased compared to the prior year due
primarily due to the improved pricing for our services and our investment in additional equipment.
Production Services Segment
Revenues were $4.0 million for the three months ended September 30, 2006, an increase of 22.7%
compared to $3.2 million in revenues for the three months ended September 30, 2005. Income from
operations increased to $119,000 in the 2006 period compared to a loss of $128,000 in the 2005
period. Our production services revenues and operating income for the third quarter of 2006
increased compared to the prior year due to improved pricing for our services and improved
utilization of our equipment.
General Corporate
General corporate expenses increased $2.2 million to $3.8 million for the three months ended
September 30, 2006 compared to $1.6 million for the three months ended September 30, 2005. The
increase was due to stock option expense of $0.7 million recorded in 2006 with the adoption of SFAS
123R, the increase in accounting and administrative staff to support the growing organization,
increased franchise taxes based on our increased authorized shares and cost related to our
Sarbanes-Oxley compliance effort.
Comparison of Nine Months Ended September 30, 2006 and 2005
Our revenues for the nine months ended September 30, 2006 were $193.2 million, an increase of
169.0% compared to $71.8 million for the nine months ended September 30, 2005. Revenues increased
in all of our business segments due to acquisitions completed in the second and third quarters of
2005 and in 2006, the investment in additional equipment, improved pricing for our services, the
addition of operations and sales personnel and the opening of new operations offices. Revenues
increased most significantly at our rental tools segment due to the acquisition of Specialty,
effective January 1, 2006 and Delta, on April 1, 2005. Our casing and tubing services segment
recorded substantial revenue growth due to the acquisitions of the casing and tubing assets of
Patterson Services, Inc on September 1, 2005, and the acquisition of Rogers effective April 1,
2006, along with improved market conditions and increased market penetration for our services in
South Texas, East Texas, Louisiana and the U.S. Gulf of Mexico. The acquisition of DLS on August
14, 2006, generated $23.9 million for our international drilling segment. Our directional drilling
services segment revenues increased in the 2006 period compared to the 2005 period due to improved
pricing for directional drilling services, the acquisition of Target, which provides MWD tools, the
addition of operations and sales personnel, the opening of new operations offices and the purchase
of additional down-hole motors and MWDs which increased our capacity and market presence. Revenues
also increased at our compressed air drilling segment due to the acquisition of the air drilling
assets of W.T. Enterprises, Inc., or WT, on July 11, 2005, the purchase of additional equipment and
improved pricing for our services in West Texas. Also contributing to increased revenues was the
acquisition of Capcoil Tubing Services, Inc., or Capcoil, as of May 1, 2005 in our production
services segment.
27
Our gross profit for the nine months ended September 30, 2006 increased 238.8% to $70.1 million, or
36.3% of revenues, compared to $20.7 million, or 28.8%, of revenues for the nine months ended
September 30, 2005. The increase in gross profit is due to the increase in revenues in all of our
business segments. The increase in gross profit as a percentage of revenues is primarily due to
the acquisition of Specialty as of January 1, 2006 and the acquisition of Delta as of April 1,
2005, in the high margin rental tool business and the improved pricing for our services generally.
Also contributing to our improved gross profit margin was the acquisition of Target, the purchase
of additional MWDs and the acquisition of Rogers. The increase in gross profit was partially
offset by an increase in depreciation expense of 271.1% to $12.6 million for the first nine months
of 2006 compared to $3.4 million for the first nine months of 2005. The increase is due to
additional depreciable assets resulting from the acquisitions and capital expenditures. Our cost
of revenues consists principally of our labor costs and benefits, equipment rentals, maintenance
and repairs of our equipment, depreciation, insurance and fuel. Because many of our costs are
fixed, our gross profit as a percentage of revenues is generally affected by our level of revenues.
General and administrative expense was $24.5 million in the first nine months of 2006 period
compared to $10.7 million for the first nine months of 2005. General and administrative expense
increased due to the additional expenses associated with the acquisitions, and the hiring of
additional sales and administrative personnel. General and administrative expense also increased
because of increased accounting and consulting fees and other expenses in connection with
initiatives to strengthen our internal control processes, costs related to Sarbanes Oxley
compliance efforts and increased corporate accounting and administrative staff. As a percentage of
revenues, general and administrative expenses were 12.7% for the nine months ended September 30,
2006 and 14.9% in the same period of 2005.
We adopted SFAS No. 123R, Share-Based Payment, effective January 1, 2006. This statement requires
all share-based payments to employees, including grants of employee stock options, to be recognized
in the financial statements based on their grant-date fair values. With the adoption of SFAS no.
123R, we recorded $2.6 million of expense related to stock options during the nine months ended
September 30, 2006, of which $2.3 million was recorded as a general and administrative expense with
the balance recorded as direct costs. We adopted SFAS No. 123R using the modified prospective
transition method, utilizing the Black-Scholes option pricing model for the calculation of the fair
value of our employee stock options. Under the modified prospective method, we record compensation
cost related to unvested stock awards as of December 31, 2005 by recognizing the unamortized grant
date fair value of these awards over the remaining vesting periods of those awards with no change
in historical reported earnings. Prior to January 1, 2006, we accounted for our stock-based
compensation using Accounting Principle Board Opinion No. 25. Under APB No. 25, compensation
expense is recognized for stock options with an exercise price that is less than the market price
on the grant date of the option. Accordingly, no compensation cost was recognized under APB No.
25.
Amortization expense was $2.0 million in the first nine months of 2006 compared to $1.3 million in
the first nine months of 2005. The increase in amortization expense is due to the amortization of
intangible assets in connection with our acquisitions and the amortization of deferred financing
costs.
Income from operations for the nine months ended September 30, 2006 totaled $43.6 million, a 401.5%
increase over income from operations of $8.7 million for the nine months ended September 30, 2005,
reflecting the increase in our revenues and gross profit, offset in part by increased general and
administrative expenses, and amortization.
Our net interest expense was $12.1 million in the first nine months of 2006, compared to $3.2
million for the first nine months of 2005. Interest expense increased in the 2006 period due to
the increased debt at a higher average interest rate. In January of 2006 we issued $160.0 million
of senior notes bearing interest at 9.0% to fund the acquisition of Specialty, pay off other
outstanding debt and for working capital. In August of 2006 we issued an additional $95.0 million
of senior notes bearing interest at 9.0% to fund a portion of the DLS acquisition. In the third
quarter of 2005, we incurred debt retirement expense of $1.1 million related to the refinancing of
our debt. This amount includes prepayment penalties and the write-off of deferred financing fees
from a previous financing.
Minority interest in income of subsidiaries for the nine months ended September 30, 2006 was $0
compared to $488,000 for the nine months ended September 30, 2005 due to the acquisition of the
minority interest in AirComp, as of July 11, 2005.
Our provision for income taxes for the nine months ended September 30, 2006 was $6.2 million, or
19.7% of our net income before income taxes, compared to $559,000, or 10.8% of our net income
before income taxes for the nine months ended September 30, 2005. The increase in income taxes is
attributable to our higher operating income and the increase in percentage of income taxes to net
income before income taxes is primarily attributable to our operations in Argentina which are taxed
at 35.0%.
28
We had net income of $25.3 million for the first nine months of 2006, an increase of 445.9%,
compared to net income of $4.6 million for the first nine months of 2005.
The following table compares revenues and income from operations for each of our business segments.
Income (loss) from operations consists of revenues less cost of revenues, general and
administrative expenses, and depreciation and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
Income (Loss) from Operations |
|
|
|
Nine Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2006 |
|
|
2005 |
|
|
Change |
|
|
2006 |
|
|
2005 |
|
|
Change |
|
|
|
(in thousands) |
|
Directional drilling services |
|
$ |
52,331 |
|
|
$ |
32,218 |
|
|
$ |
20,113 |
|
|
$ |
12,097 |
|
|
$ |
5,069 |
|
|
$ |
7,028 |
|
Rental tools |
|
|
36,331 |
|
|
|
3,499 |
|
|
|
32,832 |
|
|
|
18,881 |
|
|
|
780 |
|
|
|
18,101 |
|
International drilling |
|
|
23,853 |
|
|
|
|
|
|
|
23,853 |
|
|
|
4,139 |
|
|
|
|
|
|
|
4,139 |
|
Casing and tubing services |
|
|
37,790 |
|
|
|
12,596 |
|
|
|
25,194 |
|
|
|
9,899 |
|
|
|
4,015 |
|
|
|
5,884 |
|
Compressed air drilling services |
|
|
32,048 |
|
|
|
16,684 |
|
|
|
15,364 |
|
|
|
8,617 |
|
|
|
3,331 |
|
|
|
5,286 |
|
Production services |
|
|
10,883 |
|
|
|
6,833 |
|
|
|
4,050 |
|
|
|
737 |
|
|
|
(130 |
) |
|
|
867 |
|
General corporate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10,812 |
) |
|
|
(4,380 |
) |
|
|
(6,432 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
193,236 |
|
|
$ |
71,830 |
|
|
$ |
121,406 |
|
|
$ |
43,558 |
|
|
$ |
8,685 |
|
|
$ |
34,873 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Directional Drilling Services Segment
Revenues for the nine months ended September 30, 2006 for our directional drilling services segment
were $52.3 million, an increase of 62.4% from the $32.2 million in revenues for the nine months
ended September 30, 2005. Income from operations increased 138.6% to $12.1 million for the first
nine months of 2006 from $5.1 million for the comparable 2005 period. The improved results for
this segment are due to the increase in drilling activity in the Texas and Gulf Coast areas,
improved pricing for directional and horizontal drilling services, the acquisition of Target as of
August 1, 2005, the purchase of an additional six MWDs, the establishment of new operations in West
Texas and Oklahoma, and the addition of operations and sales personnel which increased our capacity
and market presence. Our increased operating expenses as a result of the addition of operations
and personnel were more than offset by the growth in revenues and improved pricing for our
services.
Rental Tools Segment
Revenues for the nine months ended September 30, 2006 for the rental tools segment were $36.3
million, an increase from $3.5 million in revenues for the nine months ended September 30, 2005.
Income from operations increased to $18.9 million in the 2006 period compared to $780,000 in the
2005 period. Our rental tools revenues and operating income for the first nine months of 2006
increased compared to the prior year due primarily due to the acquisitions of Specialty and Delta.
Delta was acquired as of April 1, 2005, and Specialty was acquired as of January 1, 2006, the
effective date of their respective acquisitions. Safco, Delta and Specialty were merged in
February 2006 to form Allis-Chalmers Rental Tools, Inc.
International Drilling Segment
On August 14, 2006, we acquired DLS which established the international drilling segment for us.
Revenues for the quarter ended September 30, 2006 for the international drilling segment were $23.9
million and the income from operations was $4.1 million.
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Casing and Tubing Services Segment
Revenues for the nine months ended September 30, 2006 for the casing and tubing services segment
were $37.8 million, an increase of 200.0% from the $12.6 million in revenues for the nine months
ended September 30, 2005. Revenues from domestic operations increased to $33.1 million in the 2006
period from $8.0 million in the 2005 period as a result of the acquisitions of the casing and
tubing assets of Patterson Services on September 1, 2005 and Rogers effective April 1, 2006, which
resulted in increased market penetration for our services in South Texas, East Texas, Louisiana and
the U.S. Gulf of Mexico. Revenues from Mexico operations increased to $4.7 million in the first
nine months of 2006 from $4.6 million in the 2005 period. Income from operations increased 146.6%
to $9.9 million in the first nine months of 2006 from $4.0 million in the first nine months of
2005. The increase in this segments operating income is due to our increased revenues from
domestic operations. The operating income as a percentage of revenue decreased to 26.2% for the
nine months ended September 30, 2006 compared to 31.9% for the same period of 2005. The decrease
in operating income as a percentage of revenues is due to the increase in domestic revenues as
compared to Mexico revenues, which have higher operating income margins.
Compressed Air Drilling Services Segment
Our compressed air drilling revenues were $32.0 million for the nine months ended September 30,
2006, an increase of 92.1% compared to $16.7 million in revenues for the nine months ended
September 30, 2005. Income from operations increased to $8.6 million in the 2006 period compared
to income from operations of $3.3 million in the 2005 period. Our compressed air drilling revenues
and operating income for the first nine months of 2006 increased compared to the prior year due
primarily due to the acquisition of the air drilling assets of WT as of July 11, 2005, improved
pricing for our services and our investment in additional equipment.
Production Services Segment
Revenues were $10.9 million for the nine months ended September 30, 2006, an increase of 59.3%
compared to $6.8 million in revenues for the nine months ended September 30, 2005. Income from
operations increased to $737,000 in the 2006 period compared to loss from operations of $130,000 in
the 2005 period. Our production services revenues and operating income for the first nine months
of 2006 increased compared to the prior year due to the acquisition of Capcoil and improved pricing
for our services and improved utilization of our equipment.
General Corporate
General corporate expenses increased $6.4 million to $10.8 million for the nine months ended
September 30, 2006 compared to $4.4 million for the nine months ended September 30, 2005. The
increase was due to stock option expense of $2.3 million recorded in 2006 with the adoption of SFAS
123R, the increase in accounting and administrative staff to support the growing organization,
increased franchise taxes based on our increased authorized shares and cost related to our
Sarbanes-Oxley compliance effort.
Liquidity and Capital Resources
Our on-going capital requirements arise primarily from our need to service our debt, to complete
acquisitions to acquire and maintain equipment, and to fund our working capital requirements. Our
primary sources of liquidity are proceeds from the issuance of debt and equity securities and cash
flows from operations. We had cash and cash equivalents of $50.3 million at September 30, 2006
compared to $1.9 million at December 31, 2005.
Operating Activities
In the nine months ended September 30, 2006, our operating activities provided $33.3 million in
cash compared to $3.9 million for the same period in 2005. Net income for the nine months ended
September 30, 2006 increased to $25.3 million, compared to $4.6 million in the 2005 period. The
$25.3 million in net income for the 2006 period includes a charge of $2.6 million related to the
expensing of stock options as required under SFAS No. 123R. Revenues and income from operations
increased in the first nine months of 2006 due to acquisitions completed in 2006 and the second and
third quarters of 2005, the investment in additional equipment, the opening of new operations
offices, the addition of operations and sales personnel and improved pricing for our services
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Non-cash expenses totaled $17.2 million during the first nine months of 2006 consisting of $14.6
million of depreciation and amortization, $2.6 million from the expensing of stock options,
$355,000 of imputed interest related to the effective date of the Specialty acquisition, $353,000
related to increases to the allowance for doubtful accounts receivables, less $728,000 on the gain
from asset retirements.
Non-cash expenses during the first nine months of 2005 totaled $5.8 million, consisting of
depreciation and amortization expense of $4.7 million, $653,000 from the write-off of deferred
financing costs due to the early retirement of debt and $488,000 of minority interest in the income
of AirComp.
During the nine months ended September 30, 2006, changes in operating assets and liabilities used
$9.6 million in cash, principally due to an increase of $17.2 million in accounts receivable, an
increase of $2.2 million in inventory, a decrease of $1.6 million in accounts payable, offset in
part by an increase of $4.7 million in accrued interest and an increase of $2.5 million in accrued
expenses. Accounts receivable increased due to the increase in our revenues in the first nine
months of 2006. Other inventory increased primarily due to increased activity levels. The
increase in accrued interest relates to our 9.0% senior notes issued in 2006 which is only payable
in January and July. The increase in accrued expenses can be attributed to additional income tax
liability due to profitability and additional expenses related to higher activity levels.
During the nine months ended September 30, 2005, changes in operating assets and liabilities used
$6.6 million in cash, principally due to an increase of $7.3 million in accounts receivable, an
increase in inventory of $2.8 million, offset in part by a decrease of $1.3 million in other
current assets, an increase of $1.1 million in accounts payable, an increase in accrued expenses of
$1.3 million and an increase of $497,000 in accrued interest. Accounts receivable increased due to
the increase in our revenues in the first nine months of 2005. The increase in inventory primarily
relates to the expansion of our production services segment with the acquisition of Capcoil.
Accounts payable increased due to the increased level of activity.
Investing Activities
During the nine months ended September 30, 2006, we used $225.5 million in investing activities,
consisting of $95.8 million for the acquisition of Specialty, net of cash received, $10.7 million
for the acquisition of Rogers, net of cash received, $96.6 million for the acquisition of DLS, net
of cash received and $25.8 million for capital expenditures, offset by $3.5 million of proceeds
from equipment sales. Included in the $25.8 million for capital expenditures was $ 7.8 million for
equipment used in our casing and tubing segment, $3.0 million for the expansion of our MWD
equipment used in the directional drilling segment, $6.3 million for additional equipment in our
compressed air drilling services segment and $3.1 million for our international drilling segment.
A majority of our equipment sales relate to items lost in hole by our customers.
During the first nine months of 2005, we used $46.3 million in investing activities, consisting of
$15.4 million for acquisitions of businesses, net of cash received, $21.3 for acquisitions
structured as asset purchases and $9.6 million for capital expenditures. Equipment purchases
consisted primarily of $3.2 million for casing equipment, approximately $2.1 million for the
purchase of downhole motors and approximately $2.8 million for new compressed air drilling
equipment.
Financing Activities
During the nine months ended September 30, 2006, financing activities provided $240.5 million in
cash. We received $257.8 million in proceeds from long-term debt, repaid $51.7 million in
borrowings under long-term debt facilities, repaid $3.0 million in related party debt, repaid $6.4
million net under our line of credit and paid $8.0 million in debt issuance costs. We also
received $46.5 million from the issuance of our common stock in a public offering, net of expenses
along with $5.4 million in proceeds from the exercise of options and warrants.
During the nine months ended September 30, 2005, financing activities provided a net of $38.9
million in cash. We received $45.7 million in proceeds from long-term debt, repaid $21.4 million
in borrowings under long-term facilities and paid $1.2 million in debt issuance costs. We also
received $15.9 million in proceeds from the issuance of common stock in a public offering completed
in August of 2005.
At September 30, 2006, we had $271.0 million in outstanding indebtedness, of which $262.5 million
was long term debt and $8.5 million was the current portion of long term debt.
On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified institutional
buyers pursuant to Rule 144A under the Securities Act of 1933, of $160.0 and $95.0 million
aggregate principal amount of our senior notes, respectively. The senior notes are due January 15,
2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of Specialty and
DLS, to repay existing debt and for general corporate purposes.
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Prior to January 18, 2006, we were party to a July 2005 credit agreement that provided for the
following senior secured credit facilities:
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A $13.0 million revolving line of credit. Borrowings were limited to 85% of eligible
accounts receivable plus 50% of eligible inventory (up to a maximum of $2.0 million of
borrowings based on inventory). This line of credit was to be used to finance working
capital requirements and other general corporate purposes, including the issuance of
standby letters of credit. Outstanding borrowings under this line of credit were $6.4
million at a margin above prime and LIBOR rates plus margin averaging approximately 8.1% as
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Two term loans totaling $42.0 million. Outstanding borrowings under these term loans
were $42.0 million as of December 31, 2005. These loans were at LIBOR rates plus a margin
which averages approximately 7.8% at December 31, 2005. |
Borrowings under the July 2005 credit facilities were to mature in July 2007. Amounts outstanding
under the term loans as of July 2006 were to be repaid in monthly principal payments based on a 48
month repayment schedule with the remaining balance due at maturity. Additionally, during the
second year, we were to be required to prepay the remaining balance of the term loans by 75% of
excess cash flow, if any, after debt service and capital expenditures. The interest rate payable
on borrowings was based on a margin over the London Interbank Offered Rate, referred to as LIBOR,
or the prime rate, and there was a 0.5% fee on the undrawn portion of the revolving line of credit.
The margin over LIBOR was to increase by 1.0% in the second year.
All amounts outstanding under our July 2005 credit agreement were paid off with the proceeds of our
senior notes offering on January 18, 2006. On January 18, 2006, we also executed an amended and
restated credit agreement which provides for a $25.0 million revolving line of credit which matures
in January 2010. Our January 2006 amended and restated credit agreement contains customary events
of default and financial covenants and limits our ability to incur additional indebtedness, make
capital expenditures, pay dividends or make other distributions, create liens and sell assets. Our
obligations under the January 2006 amended and restated credit agreement are secured by
substantially all of our assets.
As part of our acquisition of DLS, we assumed various bank loans with floating interest rates based
on LIBOR plus a margin and terms ranging from 2 to 5 years. The weighted average margin was 1.6%
at September 30, 2006. The bank loans are denominated in U.S. dollars and the outstanding amount
due as of September 30, 2006 was $7.9 million.
On July 11, 2005, we acquired from M-I its 45% equity interest in AirComp and the subordinated note
in the principal amount of $4.8 million issued by AirComp, for which we paid M-I $7.1 million in
cash and issued a new $4.0 million subordinated note bearing interest at 5.0% per annum. The
subordinated note issued to M-I required quarterly interest payments and the principal amount was
due October 9, 2007. Contingent upon a future equity offering, the subordinated note was
convertible into up to 700,000 shares of our common stock at a conversion price equal to the market
value of the common stock at the time of conversion. This note was repaid from the proceeds of our
9.0% senior notes offering, which we completed in August 2006.
As of December 31, 2005, Allis-Chalmers Tubular Services Inc., or Tubular, had a subordinated note
outstanding and payable to Jens Mortensen, the seller of Tubular and one of our directors, in the
amount of $4.0 million with a fixed interest rate of 7.5%. Interest was payable quarterly and the
final maturity of the note was January 31, 2006. The subordinated note was subordinated to the
rights of our bank lenders. The balance of this subordinated note was repaid in full in January
2006 with proceeds from our senior notes offering.
As part of the acquisition of Mountain Compressed Air Inc., or Mountain Air, in 2001, we issued a
note to the sellers of Mountain Air in the original amount of $2.2 million accruing interest at a
rate of 5.75% per annum. The note was reduced to $1.5 million as a result of the settlement of a
legal action against the sellers in 2003. In March 2005, we reached an agreement with the sellers
and holders of the note as a result of an action brought against us by the sellers. Under the
terms of the agreement, we paid the holders of the note $1.0 million in cash, and agreed to pay an
additional $350,000 on June 1, 2006, and an additional $150,000 on June 1, 2007, in settlement of
all claims. At September 30, 2006 and December 31, 2005 the outstanding amounts due were $150,000
and $500,000, respectively.
In connection with the purchase of Delta, we issued to the sellers a note in the amount of
$350,000. The note bore interest at 2% and the principal and accrued interest was repaid on its
maturity of April 1, 2006. In connection with the acquisition of Rogers, we issued to the seller a
note in the amount of $750,000. The note bears interest at 5.0% and is due April 3, 2009.
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In connection with the purchase of Tubular, we agreed to pay a total of $1.2 million to Mr.
Mortensen in exchange for a non-compete agreement. Monthly payments of $20,576 are due under this
agreement through January 31, 2007. In connection with the purchase of Safco, we also agreed to
pay a total of $150,000 to the sellers in exchange for a non-compete agreement. We are required to
make annual payments of $50,000 through September 30, 2007. In connection with the purchase of
Capcoil, we agreed to pay a total of $500,000 to two management employees in exchange for
non-compete agreements. We are required to make annual payments of $110,000 through May 2008.
Total amounts due under these non-compete agreements at September 30, 2006 and December 31, 2005
were $332,000 and $698,000, respectively.
In 2000 we compensated directors, including current directors Nederlander and Toboroff, who served
on the board of directors from 1989 to March 31, 1999 without compensation, by issuing promissory
notes totaling $325,000. The notes bear interest at the rate of 5.0%. At September 30, 2006 and
December 31, 2005, the principal and accrued interest on these notes totaled approximately $32,000
and $96,000, respectively.
We also had a real estate loan which was payable in equal monthly installments of $4,344 with the
remaining outstanding balance due on January 1, 2010. The loan had a floating interest rate based
on prime plus 2.0%. The outstanding principal balance was $548,000 at December 31, 2005. The
balance of this loan was repaid in full in January 2006 with proceeds from our senior notes
offering.
We have various rig and equipment financing loans with interest rates ranging from 5.0% to 8.7% and
terms of 2 to 5 years. As of September 30, 2006 and December 31, 2005, the outstanding balances
for rig and equipment financing loans were $4.4 million and $1.9 million, respectively. In April
2006 and August 2006, we obtained insurance premium financings in the amount of $1.9 million and
$896,000 with fixed interest rates of 5.6% and 6.0%, respectively. Under terms of the agreements,
amounts outstanding are paid over 10 month and 11 month repayment schedules. The outstanding
balance of these notes was approximately $1.8 million as of September 30, 2006. We also have
various capital leases with terms that expire in 2008. As of September 30, 2006 and December 31,
2005, amounts outstanding under capital leases were $543,000 and $917,000, respectively. In January
2006, we prepaid $350,000 of the outstanding equipment loans with proceeds from our senior notes
offering.
Off Balance Sheet Arrangements
We have no off balance sheet arrangements, other than normal operating leases and employee
contracts, that have or are likely to have a current or future material effect on our financial
condition, changes in financial condition, revenues, expenses, results of operations, liquidity,
capital expenditures or capital resources. We do not guarantee obligations of any unconsolidated
entities.
Capital Requirements
We have identified capital expenditure projects that will require up to approximately $12.0 million
for the remainder of 2006, exclusive of any acquisitions. We believe that our current cash
generated from operations, cash available under our credit facilities and cash on hand will provide
sufficient funds for our identified projects.
We intend to implement a growth strategy of increasing the scope of services through both internal
growth and acquisitions. We are regularly involved in discussions with a number of potential
acquisition candidates. The acquisition of assets could require additional financing. We also
expect to make capital expenditures to acquire and to maintain our existing equipment. Our
performance and cash flow from operations will be determined by the demand for our services which
in turn are affected by our customers expenditures for oil and gas exploration and development,
and industry perceptions and expectations of future oil and natural gas prices in the areas where
we operate. We will need to refinance our existing debt facilities as they become due and provide
funds for capital expenditures and acquisitions. To effect our expansion plans, we will require
additional equity or debt financing. There can be no assurance that we will be successful in
raising the additional debt or equity capital or that we can do so on terms that will be acceptable
to us.
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Recent Developments
On
October 17, 2006, we completed the acquisition of all of the outstanding stock of Petro-Rentals,
Incorporated, or Petro, based in Broussard, Louisiana. The purchase price of Petro consisted of
$29.8 million in cash, which includes the payment of approximately $9.5 million of debt, and
246,761 shares of our common stock. The acquisition was funded with cash on hand remaining from
our recent equity and debt securities offerings. Petro serves both the onshore and offshore
markets from its division offices in Broussard, Houma and Arcadia, Louisiana as well as from Alvin,
Texas. Petro provides a variety of quality rental tools and equipment and services, with an
emphasis on production related equipment and services, including wire line services and equipment,
land and offshore pumping services and coiled tubing.
On October 26, 2006, we announced that we had entered into a definitive agreement to purchase
substantially all the assets of Oil & Gas Rental Services, Inc., or OGRS, a Louisiana based
corporation that provides rental tools to both offshore and onshore exploration and production
companies. The consideration for the acquisition of the assets will consist of $291.0 million in
cash and 3.2 million shares of our common stock, subject to post-closing working capital
adjustments. The transaction is expected to close in the fourth quarter. OGRS has an extensive
inventory of premium rental equipment, including drill pipe, spiral heavy weight drill pipe, tubing
work strings, blow-out preventers, choke manifolds and various valves and handling tools for oil
and natural gas drilling. OGRS has facilities in Morgan City, Louisiana and Victoria, Texas. In
addition, upon execution of the Agreement, we deposited $9.0 million in an interest bearing
account. The deposit will be credited against the cash portion of the purchase price at the
closing, unless the closing does not occur on or prior to December 31, 2006, and as of such date,
all of the deposit forfeiture conditions in the agreement have been satisfied (in which case,
seller would retain the $9.0 million as liquidated damages).
We received a commitment, subject to customary conditions, from Royal Bank of Canada to extend a
bridge loan to finance the cash portion of the purchase price for the acquisition of OGRS.
Critical Accounting Policies
Please see our Annual Report on Form 10-K for the year ended December 31, 2005 for a description of
other policies that are critical to our business operations and the understanding of our results of
operations. The impact and any associated risks related to these policies on our business
operations is discussed throughout Managements Discussion and Analysis of Financial Condition and
Results of Operations where such policies affect our reported and expected financial results. No
material changes to such information have occurred during the nine months ended September 30, 2006.
In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income
Taxes an interpretation of FASB Statement No. 109 (FIN 48). FIN 48 clarifies the accounting for
uncertainty in income taxes recognized in an enterprises financial statements in accordance with
SFAS No. 109, Accounting for Income Taxes. It prescribes a recognition threshold and measurement
attribute for financial statement recognition and measurement of a tax position taken or expected
to be taken in a tax return. This interpretation is effective for fiscal years beginning after
December 15, 2006. We are currently evaluating the provisions of FIN 48 and have not yet determined
the impact, if any, on our financial statements.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS 157), which is
intended to increase 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 is effective for fiscal years beginning after November 15, 2007, and
interim periods within those fiscal years. We are currently evaluating the provisions of SFAS 157
and have not yet determined the impact, if any, on our financial statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.
We are exposed to market risk primarily from changes in interest rates and foreign currency
exchange risks.
Interest Rate Risk.
Fluctuations in the general level of interest rates on our current and future fixed and variable
rate debt obligations expose us to market risk. We are vulnerable to significant fluctuations in
interest rates affecting our adjustable rate debt, and any future refinancing of our fixed rate
debt and our future debt.
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At December 31, 2005, we were exposed to interest rate fluctuations on approximately $49.0 million
of notes payable and bank credit facility borrowings carrying variable interest rates. During the
first quarter of 2006, we repaid the existing variable interest rate debt. As part of our acquisition of DLS, we assumed various bank loans carrying
variable interest rates with an outstanding balance of $7,946,000 as of September 30, 2006.
We have also been subject to interest rate market risk for short-term invested cash and cash
equivalents. The principal of such invested funds would not be subject to fluctuating value
because of their highly liquid short-term nature. As of September 30, 2006, we had $43.1 million
invested in short-term investments.
Foreign Currency Exchange Rate Risk.
We have designated the U.S. dollar as the functional currency for our operations in international
locations as we contract with customers, purchase equipment and finance capital using the U.S.
dollar. Local currency transaction gains and losses, arising from remeasurement of certain assets
and liabilities denominated in local currency, are included in our consolidated statements of
income. We conduct business in Mexico through our Mexican partner, Matyep. This business exposes
us to foreign exchange risk. To control this risk, we provide for payment in U.S. dollars.
However, we have historically provided our partner a discount upon payment equal to 50% of any loss
suffered by our partner as a result of devaluation of the Mexican peso between the date of
invoicing and the date of payment. To date, such payments have not been material in amount.
ITEM 4. CONTROLS AND PROCEDURES.
(a) Evaluation of Disclosure Controls and Procedures.
We maintain disclosure controls and procedures that are designed to ensure that information
required to be disclosed in our reports under the Securities Exchange Act of 1934, as amended, are
recorded, processed, summarized and reported within the time periods specified in the SECs rules
and forms, and that such information is accumulated and communicated to management, including our
chief executive officer and chief financial officer, as appropriate, to allow timely decisions
regarding required disclosures.
Management, including our chief executive officer and our chief financial officer, has evaluated
the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules
13a-15(e) and 15d-15(e)) as of the end of the period covered by this Report, which we refer to as
the Evaluation Date.
As disclosed in the notes to our consolidated financial statements and under the caption
Managements Discussion and Analysis of Financial Condition and Results of Operations
Restatement, in each case, as set forth in our Annual Report on Form 10-K for the year ended
December 31, 2005, as amended, we understated diluted earnings per share due to an incorrect
calculation of our weighted shares outstanding for the third quarter of 2003, for each of the first
three quarters of 2004, for the years ended December 31, 2003 and 2004 and for the quarter ended
March 31, 2005. In addition, we understated basic earnings per share due to an incorrect
calculation of our weighted average basic shares outstanding for the quarter ended September 30,
2004. Consequently, we have restated our financial statements for each of those periods. The
incorrect calculation resulted from a mathematical error and an improper application of Statement
of Financial Accounting Standards, or SFAS, No. 128, Earnings Per Share. Management has concluded
that the need to restate our financial statements resulted, in part, from the lack of sufficient
experienced accounting personnel, which in turn resulted in a lack of effective control over the
financial reporting process.
As part of our growth strategy over the past five years, we have completed acquisitions of several
privately-held businesses, including closely-held entities. Prior to becoming part of our
consolidated company, these businesses were not required to implement or maintain, and did not
implement or maintain, the disclosure controls and procedures or internal controls over financial
reporting that federal law requires of publicly-held companies such as ours. We are in the process
of creating and implementing appropriate disclosure controls and procedures and internal controls
over financial reporting at each of our recently acquired businesses. However, we have not yet
completed this process and cannot assure you as to when the process will be complete.
In addition, during the fourth quarter of 2005, we failed to timely file a Current Report on Form
8-K relating to the issuance of shares of our common stock in connection with recent stock option
and warrant exercises. The current report, which was due to be filed in November 2005, was filed in
February 2006.
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As a result of the issues described above, our management has concluded that, as of the Evaluation
Date, our disclosure controls and procedures were not effective to enable us to record, process,
summarize, and report information required to be included in our SEC filings within the required
time period, and to ensure that such information is accumulated and communicated to our management,
including our chief executive officer and chief financial accounting officer, to allow timely
decisions regarding required disclosure.
(b) Change in Internal Control Over Financial Reporting.
The following changes were made in our internal control over financial reporting (as such term is
defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the period covered by this
report that have materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting:
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We continued the engagement of an independent internal controls consulting firm which is
in the process of documenting, analyzing, identifying and testing internal controls. |
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During the quarter we completed the process of consolidating our payroll functions,
excluding recent acquisitions, to improve quality control over the process. In addition,
we completed the change to a new third party processor to handle our payroll calculations. |
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We hired an information technology director who has improved our back-up capability and
is in the process of upgrading our network infrastructure. |
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We hired a tax manager with responsibility for tax notices and the preparation of income and franchise tax returns. |
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We continue to implement improvements in the way the accounting software is utilized. |
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
We are involved in various legal proceedings in the ordinary course of business. The legal
proceedings are at different stages; however, we believe that the likelihood of material loss
relating to any such legal proceeding is remote.
ITEM 1A. RISK FACTORS
Except as described below, there have been no material changes during the quarter ended September
30, 2006 to the risk factors set forth in Part I, Item 1A in our Annual Report on Form 10-K for the
year ended December 31, 2005, as amended, which we refer to as our Annual Report.
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The first paragraph of the risk factor titled, We have a substantial amount of debt which
could adversely affect our financial health and prevent us from making principal and interest
payments on our senior notes and other debt is updated as follows: |
As of September 30, 2006, we had approximately $271.0 million of consolidated total indebtedness
outstanding and approximately $11.7 million of additional secured borrowing capacity available
under our credit agreement as of September 30, 2006.
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We updated the risk factor titled, Failure to maintain effective disclosure controls and
procedures and/or internal controls over financial reporting could have a material adverse
effect on our operations to include the added risk that we may not be able to conclude that
we have effective disclosure controls and procedures and/or effective internal controls over
financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act if we are not
successful in integrating acquired businesses into our consolidated companys system of
disclosure controls and procedures and internal controls over financial reporting. We have
also added the following paragraph to the risk factor: |
During the course of our integration of any acquired business, we may identify needed improvements
to our or such acquired business internal controls and may be required to design enhanced
processes and controls in order to make such improvements. This could result in significant delays
and costs to us and could require us to divert substantial resources, including management time,
from other activities.
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We updated the risk factor titled, Historically, we have been dependent on a few customers
operating in a single industry, the loss of one or more could adversely affect our financial
condition and results of operation to include the following: |
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DLS currently relies on two customers for a majority of its revenue. In 2005, Pan American Energy
LLC Sucursal Argentina, or Pan American Energy, represented 55% of DLS revenues and Repsol-YPF
represented 15% of DLS revenues.
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In addition to the risk factors previously disclosed in the Annual Report, we have
identified the following new risk factors, which are primarily related to our recent
acquisition of DLS: |
We are a holding company, and as a result we are dependent on cash transfers from our subsidiaries
to meet our obligations, including with respect to our senior notes.
We are a holding company and do not conduct any business operations of our own. Our principal
assets are the equity interests we own in our operating subsidiaries, either directly or
indirectly. As a result, we are dependent upon cash dividends, distributions or other transfers we
receive from our subsidiaries in order to make dividend payments to our stockholders, to repay any
debt we may incur, and to meet our other obligations. The ability of our subsidiaries to pay
dividends and make payments to us will depend on their operating results and may be restricted by,
among other things, applicable corporate, tax and other laws and regulations and agreements of
those subsidiaries, as well as by the terms of our credit agreement and the indenture governing our
senior notes. For example, the corporate laws of some jurisdictions prohibit the payment of
dividends by any subsidiary unless the subsidiary has a capital surplus or net profits in the
current or immediately preceding fiscal year. Payments or distributions from our subsidiaries also
could be subject to restrictions on dividends or repatriation of earnings under applicable local
law, and monetary transfer restrictions in the jurisdictions in which our subsidiaries operate.
Our subsidiaries are separate and distinct legal entities. Any right that we have to receive any
assets of, or distributions from any subsidiary upon its bankruptcy, dissolution, liquidation or
reorganization, or to realize proceeds from the sale of the assets of any subsidiary, will be
junior to the claims of that subsidiarys creditors, including trade creditors.
We anticipate that our recent acquisition of DLS will substantially change the nature of our
operations and business.
We anticipate that our recent acquisition of DLS will substantially change the nature and
geographic location of our operations and business as a result of the character and location of
DLS businesses, which have substantially different operating characteristics and are in different
geographic locations from our existing businesses. Prior to our acquisition of DLS, we have
operated as an oilfield services company domestically in Texas, Louisiana, New Mexico, Colorado,
Oklahoma, Mississippi, Utah, Wyoming, offshore in the Gulf of Mexico, and internationally in
Mexico. DLS business is located primarily in Argentina, and we have no significant operations in
South America other than through DLS. Accordingly, this acquisition will subject us to risks
inherent in operating in a foreign country where we do not have significant prior experience. DLS
business consists of employing drilling and workover rigs for drilling, completion and repair
services for oil and gas wells, and we do not own any drilling rigs or workover rigs other than
through DLS, and have not historically provided such services. Consequently, we may not be able to
realize the economic benefits of this acquisition as efficiently as in our prior acquisitions, if
at all.
A material or extended decline in expenditures by oil and gas companies due to a decline or
volatility in oil and gas prices, a decrease in demand for oil and gas or other factors may reduce
demand for DLS services and substantially reduce DLS revenues, profitability, cash flows and/or
liquidity.
The profitability of DLS operations depends upon conditions in the oil and gas industry and,
specifically, the level of exploration and production expenditures of oil and gas company
customers. The oil and gas industry is cyclical and subject to governmental price controls. The
demand for contract drilling and related services is directly influenced by many factors beyond
DLS control, including:
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oil and gas prices and expectations about future prices; |
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the demand for oil and gas, both in Latin America and globally; |
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the cost of producing and delivering oil and gas; |
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advances in exploration, development and production technology; |
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government regulations, including governmental imposed commodity price controls, export
controls and renationalization of a countrys oil and gas industry; |
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local and international political and economic conditions; |
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the ability of OPEC to set and maintain production levels and prices; |
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the level of production by non-OPEC countries; and |
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the policies of various governments regarding exploration and development of their oil and gas reserves. |
Depending on the factors outlined above, companies exploring for oil and gas may cancel or curtail
their drilling programs, thereby reducing demand for drilling services. Such a reduction in demand
may erode daily rates and utilization of DLS rigs. Any significant decrease in daily rates or
utilization of DLS rigs could materially reduce DLS revenues, profitability, cash flows and/or
liquidity.
37
DLS operations and financial condition could be affected by union activity and general labor
unrest. Additionally, DLS labor expenses could increase as a result of governmental regulation of
payments to employees.
In Argentina, labor organizations have substantial support and have considerable political
influence. The demands of labor organizations have increased in recent years as a result of the
general labor unrest and dissatisfaction resulting from the disparity between the cost of living
and salaries in Argentina as a result of the devaluation of the Argentine peso. There can be no
assurance that DLS will not face labor disruptions in the future or that any such disruptions will
not have a material adverse effect on DLS financial condition or results of operations.
The Argentine government has in the past and may in the future promulgate laws, regulations and
decrees requiring companies in the private sector to maintain minimum wage levels and provide
specified benefits to employees, including significant mandatory severance payments. In the
aftermath of the Argentine economic crisis of 2001 and 2002, both the government and private sector
companies have experienced significant pressure from employees and labor organizations relating to
wage levels and employee benefits. In early 2005 the Argentine government promised not to order
salary increases by decree. However, there has been no abatement of pressure to mandate salary
increases, and it is possible the government will adopt measures that will increase salaries or
require DLS to provide additional benefits, which would increase DLS costs and potentially reduce
DLS profitability, cash flow and/or liquidity.
Rig upgrade, refurbishment and construction projects are subject to risks, including delays and
cost overruns, which could have an adverse effect on DLS results of operations and cash flows.
DLS often has to make upgrade and refurbishment expenditures for its rig fleet to comply with DLS
quality management and preventive maintenance system or contractual requirements or when repairs
are required in response to an inspection by a governmental authority. DLS may also make
significant expenditures when it moves rigs from one location to another. Additionally, DLS may
make substantial expenditures for the construction of new rigs. Rig upgrade, refurbishment and
construction projects are subject to the risks of delay or cost overruns inherent in any large
construction project.
Significant cost overruns or delays could adversely affect DLS financial condition and results of
operations. Additionally, capital expenditures for rig upgrade, refurbishment or construction
projects could exceed DLS planned capital expenditures, impairing DLS ability to service its debt
obligations.
An oversupply of comparable rigs in the geographic markets in which DLS competes could depress the
utilization rates and dayrates for DLS rigs and materially reduce DLS revenues and profitability.
Utilization rates, which are the number of days a rig actually works divided by the number of days
the rig is available for work, and dayrates, which are the contract prices customers pay for rigs
per day, are also affected by the total supply of comparable rigs available for service in the
geographic markets in which DLS competes. Improvements in demand in a geographic market may cause
DLS competitors to respond by moving competing rigs into the market, thus intensifying price
competition. Significant new rig construction could also intensify price competition. In the past,
there have been prolonged periods of rig oversupply with correspondingly depressed utilization
rates and dayrates largely due to earlier, speculative construction of new rigs. Improvements in
dayrates and expectations of longer-term, sustained improvements in utilization rates and dayrates
for drilling rigs may lead to construction of new rigs. These increases in the supply of rigs
could depress the utilization rates and dayrates for DLS rigs and materially reduce DLS revenues
and profitability.
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Political and economic instability in South America may hurt DLS operations materially.
Currently, DLS derives substantially all of its revenues from operations in Argentina and a small
portion from operations in Bolivia. DLS operations are subject to the following risks, among
others:
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expropriation of assets; |
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nationalization of components of the energy industry in the geographic areas where DLS operates; |
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foreign currency fluctuations and devaluation; |
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new economic and tax policies; |
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restrictions on currency, income, capital or asset repatriation; |
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political instability, war and civil disturbances; |
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uncertainty or instability resulting from armed hostilities or other crises in the
Middle East or the geographic areas in which DLS operates; and |
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acts of terrorism. |
DLS attempts to limit the risks of currency fluctuation and restrictions on currency repatriation
where possible by obtaining contracts providing for payment of a percentage of the contract in U.S.
dollars or freely convertible foreign currency. To the extent possible, DLS seeks to limit its
exposure to local currencies by matching the acceptance of local currencies to DLS expense
requirements in those currencies. Although DLS has done this in the past, DLS may not be able to
take these actions in the future, thereby exposing DLS to foreign currency fluctuations that could
cause its results of operations, financial condition and cash flows to deteriorate materially.
Over the past several years, Argentina and Bolivia have experienced political and economic
instability that resulted in significant changes in their general economic policies and
regulations.
DLS derives a small portion of its revenues from operating one drilling rig in Bolivia. Recently,
Bolivian President Evo Morales announced the nationalization of Bolivias natural gas industry and
ordered the Bolivian military to occupy Bolivias natural gas fields. This measure will likely
adversely affect the Bolivian operations of foreign oil and gas companies operating in Bolivia,
including DLS customers and potential future customers, and accordingly, DLS prospects for future
business in Bolivia may be harmed. In addition, in light of these recent political developments in
Bolivia, DLS assets in Bolivia may be subject to an increased risk of expropriation or government
imposed restrictions on movement to a new location.
Devaluation of the Argentine peso will adversely affect DLS results of operations.
The Argentine peso has been subject to significant devaluation in the past and may be subject to
significant fluctuations in the future. Given the economic and political uncertainties in
Argentina, it is impossible to predict whether, and to what extent, the value of the Argentine peso
may depreciate or appreciate against the U.S. dollar. We cannot predict how these uncertainties
will affect DLS financial results, but there is a risk that DLS financial performance could be
adversely affected. Moreover, we cannot predict whether the Argentine government will further
modify its monetary policy and, if so, what effect any of these changes could have on the value of
the Argentine peso. Such changes could have an adverse effect on DLS financial condition and
results of operations.
Argentina continues to face considerable political and economic uncertainty.
Although general economic conditions have shown improvement and political protests and social
disturbances have diminished considerably since the economic crisis of 2001 and 2002, the rapid and
radical nature of the changes in the Argentine social, political, economic and legal environment
over the past several years and the absence of a clear political consensus in favor of any
particular set of economic policies have given rise to significant uncertainties about the
countrys economic and political future. It is currently unclear whether the economic and
political stability experienced over the past several years will continue and it is possible that,
despite recent economic growth, Argentina may return to a deeper recession, higher inflation and
unemployment and greater social unrest. If instability persists, there could be a material adverse
effect on DLS results of operations and financial condition.
In the event of further social or political crisis, companies in Argentina may also face the risk
of further civil and social unrest, strikes, expropriation, nationalization, forced renegotiation
or modification of existing contracts and changes in taxation policies, including royalty and tax
increases and retroactive tax claims. In addition, investments in Argentine companies may be
further affected by changes in laws and policies of the United States affecting foreign trade,
taxation and investment.
39
An increase in inflation could have a material adverse effect on DLS results of operations.
The devaluation of the Argentine peso created pressures on the domestic price system that generated
high rates of inflation in 2002 before substantially stabilizing in 2003 and remaining stable in
2004. In 2005, however, inflation rates began to increase. In addition, in response to the
economic crisis in 2002, the federal government granted the Central Bank greater control over
monetary policy than was available to it under the previous monetary regime, known as the
Convertibility regime, including the ability to print currency, to make advances to the federal
government to cover its anticipated budget deficit and to provide financial assistance to financial
institutions with liquidity problems. We cannot assure you that inflation rates will remain stable
in the future. Significant inflation could have a material adverse effect on DLS results of
operations and financial condition.
DLS is subject to numerous governmental laws and regulations, including those that may impose
significant liability on DLS for environmental and natural resource damages.
Many aspects of DLS operations are subject to laws and regulations that may relate directly or
indirectly to the contract drilling and well servicing industries, including those requiring DLS to
control the discharge of oil and other contaminants into the environment or otherwise relating to
environmental protection. The countries where DLS operates have environmental laws and regulations
covering the discharge of oil and other contaminants and protection of the environment in
connection with operations. Failure to comply with these laws and regulations may result in the
assessment of administrative, civil and even criminal penalties, the imposition of remedial
obligations, and the issuance of injunctions that may limit or prohibit DLS operations. Laws and
regulations protecting the environment have become more stringent in recent years and may in
certain circumstances impose strict liability, rendering DLS liable for environmental and natural
resource damages without regard to negligence or fault on DLS part. These laws and regulations
may expose DLS to liability for the conduct of, or conditions caused by, others or for acts that
were in compliance with all applicable laws at the time the acts were performed. The application
of these requirements, the modification of existing laws or regulations or the adoption of new laws
or regulations curtailing exploratory or development drilling for oil and gas could materially
limit future contract drilling opportunities or materially increase DLS costs or both.
DLS is subject to hazards customary for drilling operations, which could adversely affect its
financial performance if DLS is not adequately indemnified or insured.
Substantially all of DLS operations are subject to hazards that are customary for oil and gas
drilling operations, including blowouts, reservoir damage, loss of well control, cratering, oil and
gas well fires and explosions, natural disasters, pollution and mechanical failure. Any of these
risks could result in damage to or destruction of drilling equipment, personal injury and property
damage, suspension of operations or environmental damage. Generally, drilling contracts provide
for the division of responsibilities between a drilling company and its customer, and DLS generally
obtains indemnification from its customers by contract for some of these risks. However, there may
be limitations on the enforceability of indemnification provisions that allow a contractor to be
indemnified for damages resulting from the contractors fault. To the extent that DLS is unable to
transfer such risks to customers by contract or indemnification agreements, DLS generally seeks
protection through insurance. However, DLS has a significant amount of self-insured retention or
deductible for certain losses relating to workers compensation, employers liability, general
liability and property damage. There is no assurance that such insurance or indemnification
agreements will adequately protect DLS against liability from all of the consequences of the
hazards and risks described above. The occurrence of an event not fully insured or for which DLS
is not 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 continue to be available to cover any or all of these risks, or, even if
available, that insurance premiums or other costs will not rise significantly in the future, so as
to make the cost of such insurance prohibitive.
In connection with our recent acquisition of DLS, the DLS sellers have the right to designate two
nominees for election to our board of directors, and their interests may be different from yours.
The DLS sellers collectively hold 2.5 million shares of our common stock, representing
approximately 10.1% of our issued and outstanding shares. Under the investors rights agreement
that we entered into in connection with the DLS acquisition, the DLS sellers have the right to
designate two nominees for election to our board of directors. As a result, the DLS sellers have a
greater ability to determine the composition of our board of directors and to control our future
operations and strategy as compared to the voting power and control that could be exercised by a
stockholder owning the same number of shares and not benefiting from board designation rights.
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Conflicts of interest between the DLS sellers and other holders of our securities may arise with
respect to sales of shares of capital stock owned by the DLS sellers or other matters. In
addition, the interests of the DLS sellers regarding any proposed merger or sale may differ from
the interests of other holders of our securities.
The board designation rights described above could also have the effect of delaying or preventing a
change in our control or otherwise discouraging a potential acquirer from attempting to obtain
control of us, which in turn could have a material and adverse effect on the market price of our
securities and/or our ability to meet our obligations thereunder.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
On August 14, 2006, we issued 2.5 million shares of common stock to the sellers of DLS as the stock
portion of the purchase price of DLS. The transaction was exempt from the registration
requirements of the Securities Act pursuant to Section 4(2) of the Securities Act, as a transaction
by the issuer not involving any public offering.
ITEM 6. EXHIBITS
(a) The exhibits listed on the Exhibit Index immediately following the signature page of this
Quarterly Report on Form 10-Q are filed as part of this report.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as
amended, the registrant has duly caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized on November 8, 2006.
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Allis-Chalmers Energy Inc. |
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(Registrant) |
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/s/ Munawar H. Hidayatallah |
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Munawar H. Hidayatallah |
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Chief Executive Officer and |
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Chairman |
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EXHIBIT INDEX
1.1 |
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Underwriting Agreement dated as of August 8, 2006 by and between the Registrant and the
underwriters listed on Schedule A thereto (incorporated by reference to Exhibit 1.1 to the
Registrants Form 8-K filed on August 9, 2006). |
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4.1 |
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First Supplemental Indenture dated as of August 11, 2006 by and among Allis-Chalmers GP, LLC,
Allis-Chalmers LP, LLC, Allis-Chalmers Management, LP, Rogers Oil Tool Services, Inc., the
Registrant, the other Guarantors (as defined in the Indenture referred to therein) and Wells
Fargo Bank, N.A (incorporated by reference to Exhibit 4.2 to the Registrants Form 8-K filed
on August 14, 2006). |
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10.1 |
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Purchase Agreement dated as of August 8, 2006 by and between the Registrant, the guarantors
listed on Schedule B thereto and RBC Capital Markets Corporation (incorporated by reference to
Exhibit 10.4 to the Registrants Form 8-K filed on August 14, 2006). |
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10.2 |
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Registration Rights Agreement dated as of August 14, 2006 by and among the Registrant, the
guarantors listed on Schedule A thereto and RBC Capital Markets Corporation (incorporated by
reference to Exhibit 10.1 to the Registrants Form 8-K filed on August 14, 2006). |
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10.3 |
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Investors Rights Agreement dated as of August 18, 2006 by and among the Registrant and the
investors named on Exhibit A thereto (incorporated by reference to Exhibit 10.1 to the
Registrants Form 8-K filed on August 14, 2006). |
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10.4 |
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First Amendment to Amended and Restated Credit Agreement dated as of August 8, 2006, by and
among the Registrant, the guarantors named thereto and Royal Bank of Canada (incorporated by
reference to Exhibit 10.3 to the Registrants Form 8-K filed on August 14, 2006). |
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10.5 |
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2006 Incentive Plan (incorporated by reference to Exhibit 10.1 to the Registrants Form 8-K
filed on September 18, 2006). |
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10.6 |
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Form of Employee Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 to the
Registrants Form 8-K filed on September 18, 2006). |
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10.7 |
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Form of Employee Nonqualified Stock Option Agreement (incorporated by reference to Exhibit
10.3 to the Registrants Form 8-K filed on September 18, 2006). |
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10.8 |
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Form of Employee Incentive Stock Option Agreement (incorporated by reference to Exhibit 10.4
to the Registrants Form 8-K filed on September 18, 2006). |
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10.9 |
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Form of Non-Employee Director Restricted Stock Agreement (incorporated by reference to
Exhibit 10.5 to the Registrants Form 8-K filed on September 18, 2006). |
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10.10 |
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Form of Non-Employee Director Nonqualified Stock Option Agreement (incorporated by reference
to Exhibit 10.6 to the Registrants Form 8-K filed on September 18, 2006). |
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10.11 |
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Stock Purchase Agreement dated October 17, 2006 by and between Allis-Chalmers Production
Services, Inc. and Randolph J. Hebert (incorporated by reference to Exhibit 10.1 to the
Registrants Form 8-K filed on October 19, 2006). |
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10.12 |
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Asset Purchase Agreement dated October 25, 2006 by and between the Registrant and Oil & Gas
Rental Services, Inc. (incorporated by reference to Exhibit 10.1 to the Registrants Form 8-K
filed on October 26, 2006). |
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31.1* |
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Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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31.2* |
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Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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32.1* |
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Certification of the Chief Executive Officer and Chief Financial Officer pursuant to 18
U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |