Form 10-Q
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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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 MARCH 31, 2009
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 1-02199
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.) |
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5075 WESTHEIMER, SUITE 890, HOUSTON, TEXAS
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77056 |
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(Address of principal executive offices)
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(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 has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12
months (or for such shorter period that the registrant was required to submit and post such files).
Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act:
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Large accelerated filer o
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Accelerated filer þ
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company)
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act).
Yes o No þ
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of
the latest practicable date.
At May 1, 2009 there were 35,691,742 shares of common stock, par value $0.01 per share,
outstanding.
ALLIS-CHALMERS ENERGY INC.
FORM 10-Q
For the Quarterly Period Ended March 31, 2009
TABLE OF CONTENTS
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED CONDENSED BALANCE SHEETS
(in thousands, except for share and per share amounts)
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March 31, |
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December 31, |
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2009 |
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2008 |
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(unaudited) |
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Assets |
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Cash and cash equivalents |
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$ |
10,860 |
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$ |
6,866 |
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Trade receivables, net |
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132,548 |
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157,871 |
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Inventories |
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37,324 |
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39,087 |
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Deferred income tax asset |
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5,182 |
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6,176 |
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Prepaid expenses and other |
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13,622 |
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15,238 |
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Total current assets |
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199,536 |
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225,238 |
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Property and equipment, net |
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754,109 |
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760,990 |
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Goodwill |
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43,273 |
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43,273 |
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Other intangible assets, net |
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36,184 |
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37,371 |
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Debt issuance costs, net |
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12,200 |
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12,664 |
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Deferred income tax asset |
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9,496 |
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3,993 |
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Other assets |
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31,113 |
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31,522 |
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Total assets |
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$ |
1,085,911 |
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$ |
1,115,051 |
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Liabilities and Stockholders Equity |
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Current maturities of long-term debt |
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$ |
13,568 |
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$ |
14,617 |
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Trade accounts payable |
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46,041 |
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62,078 |
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Accrued salaries, benefits and payroll taxes |
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19,869 |
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20,192 |
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Accrued interest |
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7,475 |
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18,623 |
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Accrued expenses |
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25,402 |
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26,642 |
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Total current liabilities |
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112,355 |
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142,152 |
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Long-term debt, net of current maturities |
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581,446 |
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579,044 |
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Deferred income taxes |
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8,388 |
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8,253 |
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Other long-term liabilities |
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1,838 |
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2,193 |
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Total liabilities |
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704,027 |
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731,642 |
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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, $0.01 par value (100,000,000 shares authorized;
35,691,742 issued and outstanding at March 31, 2008 and
35,674,742 issued and outstanding at December 31, 2008) |
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357 |
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357 |
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Capital in excess of par value |
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335,713 |
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334,633 |
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Retained earnings |
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45,814 |
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48,419 |
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Total stockholders equity |
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381,884 |
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383,409 |
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Total liabilities and stockholders equity |
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$ |
1,085,911 |
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$ |
1,115,051 |
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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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March 31, |
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2009 |
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2008 |
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Revenues |
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$ |
145,103 |
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$ |
153,182 |
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Operating costs and expenses |
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Direct costs |
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103,134 |
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98,511 |
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Depreciation |
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19,371 |
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14,502 |
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Selling, general and administrative |
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13,640 |
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15,471 |
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Amortization |
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1,187 |
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1,116 |
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Total operating costs and expenses |
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137,332 |
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129,600 |
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Income from operations |
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7,771 |
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23,582 |
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Other income (expense): |
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Interest expense |
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(13,507 |
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(12,041 |
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Interest income |
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5 |
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1,152 |
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Other |
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217 |
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107 |
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Total other income (expense) |
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(13,285 |
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(10,782 |
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Income (loss) before income taxes |
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(5,514 |
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12,800 |
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Provision for income taxes |
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2,909 |
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(4,750 |
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Net income (loss) |
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$ |
(2,605 |
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$ |
8,050 |
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Net income (loss) per common share: |
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Basic |
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$ |
(0.07 |
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$ |
0.23 |
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Diluted |
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$ |
(0.07 |
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$ |
0.23 |
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Weighted average shares outstanding: |
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Basic |
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35,206 |
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34,837 |
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Diluted |
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35,206 |
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35,173 |
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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 Three Months Ended |
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March 31, |
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2009 |
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2008 |
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Cash Flows from Operating Activities: |
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Net income (loss) |
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$ |
(2,605 |
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$ |
8,050 |
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Adjustments to reconcile net income to net cash
provided by operating activities: |
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Depreciation and amortization |
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20,558 |
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15,618 |
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Amortization and write-off of deferred financing fees |
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555 |
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519 |
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Stock-based compensation |
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1,080 |
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2,612 |
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Allowance for bad debts |
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385 |
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267 |
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Deferred taxes |
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(4,374 |
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1,965 |
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Gain on sale of property and equipment |
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(357 |
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(130 |
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Changes in operating assets and liabilities, net of acquisitions: |
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Decrease (increase) in trade receivable |
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24,938 |
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(10,306 |
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Decrease (increase) in inventories |
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1,763 |
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(810 |
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Decrease in prepaid expenses and other current assets |
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1,616 |
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228 |
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Decrease (increase) in other assets |
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657 |
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(1,271 |
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Increase (decrease) in trade accounts payable |
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(16,037 |
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1,523 |
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(Decrease) in accrued interest |
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(11,148 |
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(10,926 |
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Increase (decrease) in accrued expenses |
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(1,240 |
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10,943 |
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Increase (decrease) in accrued salaries, benefits and payroll taxes |
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(323 |
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564 |
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(Decrease) in other long-term liabilities |
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(355 |
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(162 |
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Net Cash Provided By Operating Activities |
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15,113 |
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18,684 |
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Cash Flows from Investing Activities: |
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Investment in note receivable |
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(40,000 |
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Deposits on asset commitments |
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(248 |
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(5,331 |
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Proceeds from sale of property and equipment |
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1,825 |
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1,488 |
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Purchase of property and equipment |
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(13,958 |
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(39,677 |
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Net Cash Used In Investing Activities |
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(12,381 |
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(83,520 |
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Cash Flows from Financing Activities: |
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Proceeds from exercises of options |
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61 |
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Proceeds from long-term debt |
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13,142 |
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Net borrowings under line of credit |
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6,000 |
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20,500 |
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Payments on long-term debt |
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(4,647 |
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(2,292 |
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Debt issuance costs |
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(91 |
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(21 |
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Net Cash Provided By Financing Activities |
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1,262 |
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31,390 |
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Net change in cash and cash equivalents |
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3,994 |
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(33,446 |
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Cash and cash equivalents at beginning of year |
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6,866 |
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43,693 |
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Cash and cash equivalents at end of period |
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$ |
10,860 |
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$ |
10,247 |
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Supplemental information: |
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Interest paid |
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$ |
23,867 |
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$ |
22,412 |
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Income taxes paid |
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$ |
2,589 |
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$ |
2,181 |
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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
Allis-Chalmers Energy Inc. and subsidiaries (Allis-Chalmers, we, our or us) is a
multi-faceted oilfield service company that provides services and equipment to oil and natural gas
exploration and production companies, throughout the United States including Texas, Oklahoma,
Louisiana, Arkansas, Pennsylvania, New Mexico, offshore in the Gulf of Mexico, and internationally,
primarily in Argentina, Brazil and Mexico. We operate in three sectors of the oil and natural gas
service industry: Oilfield Services; Drilling and Completion and Rental 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, 2008. 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 September 2006, the Financial Accounting Standards Board, or FASB, issued Statement of Financial
Accounting Standards No. 157, Fair Value Measurements, or SFAS No. 157. SFAS No. 157 clarifies the
principle that fair value should be based on the assumptions that market participants would use
when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the
information used to develop those assumptions. Under the standard, fair value measurements would
be separately disclosed by level within the fair value hierarchy. SFAS No. 157 is effective for
financial statements issued for fiscal years beginning after November 15, 2007, and interim periods
within those fiscal years, with early adoption permitted. Subsequently, the FASB provided for a
one-year deferral of the provisions of SFAS No. 157 for non-financial assets and liabilities that
are recognized or disclosed at fair value in the consolidated financial statements on a
non-recurring basis. As allowed under SFAS No. 157, we adopted all requirements of SFAS No. 157 on
January 1, 2008, except as they relate to nonfinancial assets and liabilities, which were adopted
on January 1, 2009 and neither adoption had any impact on our financial statements.
6
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 1 NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141 (revised
2007), Business Combinations, or SFAS No. 141(R). SFAS No. 141(R) changes the requirements for an
acquirers recognition and measurement of the assets acquired and the liabilities assumed in a
business combination. Additionally, SFAS No. 141(R) requires that acquisition-related costs,
including restructuring costs, be recognized as expense separately from the acquisition. We
adopted SFAS No. 141(R) on January 1, 2009 and there was no impact on our financial statements.
In April 2008, the FASB issued FASB Staff Position SFAS 142-3, Determination of the Useful Life of
Intangible Assets, or FSP SFAS 142-3. FSP SFAS 142-3 amends the factors that should be considered
in developing renewal or extension assumptions used to determine the useful life of a recognized
intangible asset under SFAS No. 142. The objective of FSP SFAS 142-3 is to improve the consistency
between the useful life of a recognized intangible asset under SFAS No. 142 and the period of
expected cash flows used to measure the fair value of the asset under SFAS No. 141R, and other U.S.
GAAP principles. FSP SFAS 142-3 is effective for fiscal years beginning after December 15, 2008.
We adopted FSP SFAS 142-3 on January 1, 2009 and there was no impact on our financial statements.
In April 2009, the FASB issued FASB Staff Position SFAS 141(R)-1, Accounting for Assets Acquired
and Liabilities Assumed in a Business Combination That Arise from Contingencies, or FSP SFAS
141(R)-1. FSP SFAS 141(R)-1 amends the guidance in SFAS No. 141(R) to require contingent assets
acquired and liabilities assumed in a business combination to be recognized at fair value on the
acquisition date if fair value can be reasonably estimated during the measurement period. If fair
value cannot be reasonably estimated during the measurement period, the contingent asset or
liability would be recognized in accordance with SFAS No. 5, Accounting for Contingencies, and FASB
Interpretation (FIN) No. 14, Reasonable Estimation of the Amount of a Loss. Further, this FSP
eliminated the specific subsequent accounting guidance for contingent assets and liabilities from
Statement 141(R), without significantly revising the guidance in SFAS No. 141. However, contingent
consideration arrangements of an acquiree assumed by the acquirer in a business combination would
still be initially and subsequently measured at fair value in accordance with SFAS No. 141(R). FSP
SFAS 141(R)-1 is effective for all business acquisitions occurring on or after the beginning of the
first annual reporting period beginning on or after December 15, 2008. We adopted the provisions
of FSP SFAS 141(R)-1 on January 1, 2009 and there was no impact on our financial statements.
In April 2009, the FASB issued FASB Staff Position SFAS 157-4, Determining Fair Value When the
Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and
Identifying Transactions That Are Not Orderly, or FSP SFAS 157-4. FSP SFAS 157-4 provides
additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and
level of activity for the asset or liability have significantly decreased. This FSP re-emphasizes
that regardless of market conditions the fair value measurement is an exit price concept as defined
in SFAS No. 157. This FSP clarifies and includes additional factors to consider in determining
whether there has been a significant decrease in market activity for an asset or liability and
provides additional clarification on estimating fair value when the market activity for an asset or
liability has declined significantly. The scope of this FSP does not include assets and
liabilities measured under level 1 inputs. FSP SFAS 157-4 is applied prospectively to all fair
value measurements where appropriate and will be effective for interim and annual periods ending
after June 15, 2009. We will adopt the provisions of FSP SFAS 157-4 on April 1, 2009 and do not
expect the adoption to have a material impact on our financial statements.
In April 2009, the FASB issued FASB Staff Position SFAS 107-1 and APB 28-1, Interim Disclosures
about Fair Value of Financial Instruments or FSP SFAS 107-1 and APB 28-1. FSP SFAS 107-1 and APB
281-1 amends SFAS No. 107, Disclosures about Fair Value of Financial Instruments, to require
publicly-traded companies, as defined in APB Opinion No. 28, Interim Financial Reporting, to
provide disclosures on the fair value of financial instruments in interim financial
statements. FSP SFAS 107-1 and APB 28-1 is effective for interim periods ending after June 15,
2009. We will adopt the additional disclosure requirements in our June 30, 2009 financial
statements.
7
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 2 STOCK-BASED COMPENSATION
We adopted Statement of Financial Accounting Standards 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 estimated forfeiture rates for the first three months of 2009 and 2008 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.
Our net income (loss) for the three months ended March 31, 2009 and 2008 includes approximately
$1.1 million and $2.6 million, respectively of compensation costs related to share-based payments.
As of March 31, 2009 there is $1.3 million of unrecognized compensation expense related to
non-vested stock option grants. We expect approximately $684,000 to be recognized over the
remainder of 2009, approximately $538,000, $27,000 and $5,000 to be recognized during the years
ended 2010, 2011 and 2012, respectively.
A summary of our stock option activity and related information is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
Weighted |
|
|
|
|
|
|
Shares |
|
|
Average |
|
|
Average |
|
|
Aggregate |
|
|
|
Under |
|
|
Exercise |
|
|
Contractual |
|
|
Intrinsic Value |
|
|
|
Option |
|
|
Price |
|
|
Life (Years) |
|
|
(millions) |
|
Balance at December 31, 2008 |
|
|
901,732 |
|
|
$ |
10.95 |
|
|
|
|
|
|
|
|
|
Granted |
|
|
120,000 |
|
|
|
1.23 |
|
|
|
|
|
|
|
|
|
Canceled |
|
|
(206,000 |
) |
|
|
21.66 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at March 31, 2009 |
|
|
815,732 |
|
|
|
6.82 |
|
|
|
6.79 |
|
|
$ |
0.08 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at March 31, 2009 |
|
|
683,732 |
|
|
$ |
7.53 |
|
|
|
6.21 |
|
|
$ |
0.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 first
quarter of 2009 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
March 31, 2009.
No options were granted during the three months ended March 31, 2008. The following summarizes the
assumptions used for the options granted in the three months ended March 31, 2009 Black-Scholes
model:
|
|
|
|
|
|
|
For the Three Months Ended |
|
|
|
March 31, |
|
|
|
2009 |
|
Expected dividend yield |
|
|
|
|
Expected price volatility |
|
|
77.32 |
% |
Risk free interest rate |
|
|
1.37 |
% |
Expected life of options |
|
5 years |
|
Weighted average fair value of options granted
at market value |
|
$ |
0.77 |
|
8
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 2 STOCK-BASED COMPENSATION (Continued)
Restricted stock awards, or RSAs, activity during the three months ended March 31, 2009 were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
Number of |
|
|
Grant-Date Fair Value |
|
|
|
Shares |
|
|
Per Share |
|
Nonvested at December 31, 2008 |
|
|
953,102 |
|
|
$ |
15.34 |
|
Granted |
|
|
17,000 |
|
|
|
1.23 |
|
Vested |
|
|
(6,740 |
) |
|
|
10.42 |
|
Forfeited |
|
|
(5,600 |
) |
|
|
16.50 |
|
|
|
|
|
|
|
|
Nonvested at March 31, 2009 |
|
|
957,762 |
|
|
$ |
15.12 |
|
|
|
|
|
|
|
|
|
We determine the fair value of RSAs based on the market price of our common stock on the date of
grant. Compensation cost for RSAs is primarily recognized on a straight-line basis over the
vesting or service period and is net of forfeitures. As of March 31, 2009, there was $7.9 million
of total unrecognized compensation cost related to nonvested RSAs. We expect approximately $3.0
million to be recognized over the remainder of 2009 and approximately $3.5 million, $1.2 million
and $195,000 to be recognized during the years ended 2010, 2011 and 2012, respectively.
NOTE 3 INCOME PER COMMON SHARE
We compute income per common share in accordance with the provisions of Statement of Financial
Accounting Standards No. 128, Earnings Per Share, or SFAS No. 128. 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 |
|
|
|
March 31, |
|
|
|
2009 |
|
|
2008 |
|
Numerator: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(2,605 |
) |
|
$ |
8,050 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
Weighted average common shares outstanding excluding
nonvested restricted stock |
|
|
35,206 |
|
|
|
34,837 |
|
|
|
|
|
|
|
|
|
|
Effect of potentially dilutive common shares: |
|
|
|
|
|
|
|
|
Warrants and employee and director stock options
and restricted shares |
|
|
|
|
|
|
336 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding
and assumed conversions |
|
|
35,206 |
|
|
|
35,173 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share |
|
|
|
|
|
|
|
|
Basic |
|
$ |
(0.07 |
) |
|
$ |
0.23 |
|
|
|
|
|
|
|
|
Diluted |
|
$ |
(0.07 |
) |
|
$ |
0.23 |
|
|
|
|
|
|
|
|
Potentially dilutive securities excluded as anti-dilutive |
|
|
1,537 |
|
|
|
1,088 |
|
|
|
|
|
|
|
|
Warrants and share based compensation shares of approximately 70,000 were excluded in the
computation of diluted earnings per share for the three months ended March 31, 2009 as the effect
would have been anti-dilutive due to the net loss for the period.
9
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 4 GOODWILL AND INTANGIBLE ASSETS
In accordance with Statement of Financial Accounting Standards No. 142, Goodwill and Other
Intangible Assets, or SFAS No. 142, 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 $43.3 million at March 31, 2009 and December 31, 2008. Based
on impairment testing performed during 2008 pursuant to the requirements of SFAS No. 142, these
assets were impaired to their current carrying values.
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 twenty years. Amortization of intangible assets for the three months
ended March 31, 2009 were $1.2 million, compared to $1.1 million for the same period in the prior
year. At March 31, 2009, intangible assets totaled $36.2 million, net of $10.4 million of
accumulated amortization.
NOTE 5 INVENTORIES
Inventories consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Manufactured |
|
|
|
|
|
|
|
|
Finished goods |
|
$ |
3,298 |
|
|
$ |
2,821 |
|
Work in process |
|
|
2,203 |
|
|
|
1,654 |
|
Raw materials |
|
|
2,225 |
|
|
|
2,499 |
|
|
|
|
|
|
|
|
Total manufactured |
|
|
7,726 |
|
|
|
6,974 |
|
Hammers |
|
|
2,164 |
|
|
|
2,257 |
|
Drive pipe |
|
|
485 |
|
|
|
443 |
|
Rental supplies |
|
|
2,837 |
|
|
|
3,023 |
|
Chemicals and drilling fluids |
|
|
3,733 |
|
|
|
3,698 |
|
Rig parts and related inventory |
|
|
10,667 |
|
|
|
13,097 |
|
Coiled tubing and related inventory |
|
|
1,729 |
|
|
|
1,817 |
|
Shop supplies and related inventory |
|
|
7,983 |
|
|
|
7,778 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total inventories |
|
$ |
37,324 |
|
|
$ |
39,087 |
|
|
|
|
|
|
|
|
10
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 6 DEBT
Our long-term debt consisted of the following: (in thousands)
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Senior notes |
|
$ |
505,000 |
|
|
$ |
505,000 |
|
Bank term loans |
|
|
46,048 |
|
|
|
49,609 |
|
Revolving line of credit |
|
|
42,500 |
|
|
|
36,500 |
|
Seller notes |
|
|
750 |
|
|
|
750 |
|
Notes payable to former directors |
|
|
32 |
|
|
|
32 |
|
Insurance premium financing |
|
|
85 |
|
|
|
991 |
|
Capital lease obligations |
|
|
599 |
|
|
|
779 |
|
|
|
|
|
|
|
|
Total debt |
|
|
595,014 |
|
|
|
593,661 |
|
|
|
|
|
|
|
|
|
|
Less: current maturities |
|
|
13,568 |
|
|
|
14,617 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt obligations |
|
$ |
581,446 |
|
|
$ |
579,044 |
|
|
|
|
|
|
|
|
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
Rental Tools, Inc., or Specialty, and DLS Drilling, Logistics & Services Company, or DLS, to repay
existing debt and for general corporate purposes.
In January 2007, we closed on a private offering, to qualified institutional buyers pursuant to
Rule 144A under the Securities Act, of $250.0 million principal amount of 8.5% senior notes due
2017. The proceeds of the senior notes offering, together with a portion of the proceeds of our
concurrent common stock offering, were used to repay the debt outstanding under our $300.0 million
bridge loan facility which we incurred to finance our acquisition of substantially all the assets
of Oil & Gas Rental Services, Inc, or OGR.
On January 18, 2006, we also executed an amended and restated credit agreement which provided for a
$25.0 million revolving line of credit with a maturity of January 2010. On April 26, 2007, we
entered into a Second Amended and Restated Credit Agreement, which increased our revolving line of
credit to $62.0 million, and had a final maturity date of April 26, 2012. On December 3, 2007, we
entered into a First Amendment to Second Amended and Restated Credit Agreement, which increased our
revolving line of credit to $90.0 million. The 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 amended and restated credit agreement are secured by
substantially all of our assets located in the U.S. We were in compliance with all debt covenants
as of March 31, 2009 and December 31, 2008. On April 9, 2009, we, along with certain of our
subsidiaries, entered into a Third Amendment to our existing Second Amended and Restated Credit
Agreement dated as of April 26, 2007, with Royal Bank of Canada, as administrative agent and
collateral agent, and the lenders party thereto. The Third Amendment, among other things, modifies
the leverage ratio and interest coverage ratio covenants of the Credit Agreement. In addition,
permitted maximum capital expenditures were reduced to $85.0 million for 2009 compared to the
previous limit of $120.0 million, which is consistent with our previously announced plans to limit
capital expenditures for the year. The credit agreement loan rates are based on prime or LIBOR
plus a margin. The weighted average interest rate was 6.4% and 4.6% at March 31, 2009 and December
31, 2008, respectively. As of March 31, 2009 and December 31, 2008, amounts borrowed under the
facility were $42.5 million and $36.5 and availability was reduced by outstanding letters of credit
of $5.8 million.
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 interest rates on
these loans was 3.4% and 5.1% as of March 31, 2009 and December 31, 2008, respectively. The bank
loans are denominated in U.S. dollars and the outstanding amount due as of March 31, 2009 and
December 31, 2008 was $1.9 million and $2.5 million, respectively.
11
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 6 DEBT (Continued)
On February 15, 2008, through our DLS subsidiary in Argentina, we entered into a $25.0 million
import finance facility with a bank. The facility was available for draws until December 31, 2008,
but as of that date we had drawn down the whole facility. Borrowings under this facility were used
to fund a portion of the purchase price of the new drilling and service rigs ordered for our
Drilling and Completion segment. Each drawdown shall be repaid over four years in equal
semi-annual installments beginning one year after each disbursement with the final principal
payment due not later than March 15, 2013. The import finance facility is unsecured and contains
customary events of default and financial covenants and limits DLS ability to incur additional
indebtedness, make capital expenditures, create liens and sell assets. We were in compliance with
all debt covenants as of March 31, 2009 and December 31, 2008. The bank loan rates are based on
LIBOR plus a margin. The weighted average interest rate was 6.3% and 6.9% at March 31, 2009 and
December 31, 2008, respectively. The bank loans are denominated in U.S. dollars and the
outstanding amount as of March 31, 2009 and December 31, 2008 was $23.5 million and $25.0 million,
respectively.
As part of our acquisition of BCH Ltd, or BCH, we assumed a $23.6 million term loan credit facility
with a bank. The credit agreement is dated June 2007 and contains customary events of default and
financial covenants. Obligations under the facility are secured by substantially all of the BCH
assets. The facility is repayable in quarterly principal installments plus interest with the final
payment due not later than August 2012. We were in compliance with all debt covenants as of March
31, 2009 and December 31, 2008. The credit facility loan is denominated in U.S. dollars and
interest rates are based on LIBOR plus a margin. At March 31, 2009 and December 31, 2008, the
outstanding amount of the loan was $20.6 million and $22.1 million and the interest rate was 4.5%
and 6.0%, respectively.
Notes payable
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 was paid in full in April 2009 in accordance with
its terms.
In 2000 we compensated directors, including current directors Robert Nederlander and Leonard
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%. As of
March 31, 2009 and December 31, 2008, the principal and accrued interest on these notes totaled
approximately $32,000.
In April 2008 and August 2008, we obtained insurance premium financings in the aggregate amount of
$3.0 million with a fixed average weighted interest rate of 4.9%. Under terms of the agreements,
amounts outstanding are paid over 10 and 11 month repayment schedules. The outstanding balance of
these notes was approximately $85,000 and $991,000 at March 31, 2009 and December 31, 2008,
respectively.
Other debt
As part of our acquisition of BCH, we assumed various capital leases with terms of two to three
years. The outstanding balance under these capital leases was $599,000 and $779,000 at March 31,
2009 and December 31, 2008, respectively.
NOTE 7 STOCKHOLDERS EQUITY
We recognized approximately $1.1 million of compensation expense related to share-based payments in
the first three months of 2009 that was recorded as capital in excess of par value (see Note 2).
NOTE 8 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 (in thousands, except for share and per share amounts).
12
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 8 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
March 31, 2009 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
|
|
|
$ |
6,736 |
|
|
$ |
4,124 |
|
|
$ |
|
|
|
$ |
10,860 |
|
Trade receivables, net |
|
|
|
|
|
|
67,637 |
|
|
|
67,857 |
|
|
|
(2,946 |
) |
|
|
132,548 |
|
Inventories |
|
|
|
|
|
|
19,690 |
|
|
|
17,634 |
|
|
|
|
|
|
|
37,324 |
|
Intercompany receivables |
|
|
|
|
|
|
70,595 |
|
|
|
|
|
|
|
(70,595 |
) |
|
|
|
|
Note receivable from affiliate |
|
|
22,087 |
|
|
|
|
|
|
|
|
|
|
|
(22,087 |
) |
|
|
|
|
Prepaid expenses and other |
|
|
6,208 |
|
|
|
7,175 |
|
|
|
5,421 |
|
|
|
|
|
|
|
18,804 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
28,295 |
|
|
|
171,833 |
|
|
|
95,036 |
|
|
|
(95,628 |
) |
|
|
199,536 |
|
Property and equipment, net |
|
|
|
|
|
|
493,506 |
|
|
|
260,603 |
|
|
|
|
|
|
|
754,109 |
|
Goodwill |
|
|
|
|
|
|
23,251 |
|
|
|
20,022 |
|
|
|
|
|
|
|
43,273 |
|
Other intangible assets, net |
|
|
494 |
|
|
|
28,163 |
|
|
|
7,527 |
|
|
|
|
|
|
|
36,184 |
|
Debt issuance costs, net |
|
|
12,114 |
|
|
|
86 |
|
|
|
|
|
|
|
|
|
|
|
12,200 |
|
Note receivable from affiliates |
|
|
8,638 |
|
|
|
|
|
|
|
|
|
|
|
(8,638 |
) |
|
|
|
|
Investments in affiliates |
|
|
947,839 |
|
|
|
|
|
|
|
|
|
|
|
(947,839 |
) |
|
|
|
|
Other assets |
|
|
9,444 |
|
|
|
27,430 |
|
|
|
3,735 |
|
|
|
|
|
|
|
40,609 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,006,824 |
|
|
$ |
744,269 |
|
|
$ |
386,923 |
|
|
$ |
(1,052,105 |
) |
|
$ |
1,085,911 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt |
|
$ |
782 |
|
|
$ |
85 |
|
|
$ |
12,701 |
|
|
$ |
|
|
|
$ |
13,568 |
|
Trade accounts payable |
|
|
|
|
|
|
20,160 |
|
|
|
28,827 |
|
|
|
(2,946 |
) |
|
|
46,041 |
|
Accrued salaries, benefits and payroll taxes |
|
|
|
|
|
|
4,628 |
|
|
|
15,241 |
|
|
|
|
|
|
|
19,869 |
|
Accrued interest |
|
|
7,150 |
|
|
|
|
|
|
|
325 |
|
|
|
|
|
|
|
7,475 |
|
Accrued expenses |
|
|
98 |
|
|
|
11,754 |
|
|
|
13,550 |
|
|
|
|
|
|
|
25,402 |
|
Intercompany payables |
|
|
69,410 |
|
|
|
|
|
|
|
1,185 |
|
|
|
(70,595 |
) |
|
|
|
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
22,087 |
|
|
|
(22,087 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
77,440 |
|
|
|
36,627 |
|
|
|
93,916 |
|
|
|
(95,628 |
) |
|
|
112,355 |
|
Long-term debt, net of current maturities |
|
|
547,500 |
|
|
|
|
|
|
|
33,946 |
|
|
|
|
|
|
|
581,446 |
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
8,638 |
|
|
|
(8,638 |
) |
|
|
|
|
Deferred income taxes |
|
|
|
|
|
|
|
|
|
|
8,388 |
|
|
|
|
|
|
|
8,388 |
|
Other long-term liabilities |
|
|
|
|
|
|
45 |
|
|
|
1,793 |
|
|
|
|
|
|
|
1,838 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
624,940 |
|
|
|
36,672 |
|
|
|
146,681 |
|
|
|
(104,266 |
) |
|
|
704,027 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock |
|
|
357 |
|
|
|
3,526 |
|
|
|
42,963 |
|
|
|
(46,489 |
) |
|
|
357 |
|
Capital in excess of par value |
|
|
335,713 |
|
|
|
570,512 |
|
|
|
133,339 |
|
|
|
(703,851 |
) |
|
|
335,713 |
|
Retained earnings |
|
|
45,814 |
|
|
|
133,559 |
|
|
|
63,940 |
|
|
|
(197,499 |
) |
|
|
45,814 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
381,884 |
|
|
|
707,597 |
|
|
|
240,242 |
|
|
|
(947,839 |
) |
|
|
381,884 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and
stockholders equity |
|
$ |
1,006,824 |
|
|
$ |
744,269 |
|
|
$ |
386,923 |
|
|
$ |
(1,052,105 |
) |
|
$ |
1,085,911 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 8 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Three Months Ended March 31, 2009 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
|
Revenues |
|
$ |
|
|
|
$ |
65,967 |
|
|
$ |
79,789 |
|
|
$ |
(653 |
) |
|
$ |
145,103 |
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs |
|
|
|
|
|
|
41,295 |
|
|
|
62,492 |
|
|
|
(653 |
) |
|
|
103,134 |
|
Depreciation |
|
|
|
|
|
|
14,309 |
|
|
|
5,062 |
|
|
|
|
|
|
|
19,371 |
|
Selling, general and
administrative |
|
|
942 |
|
|
|
9,168 |
|
|
|
3,530 |
|
|
|
|
|
|
|
13,640 |
|
Amortization |
|
|
12 |
|
|
|
980 |
|
|
|
195 |
|
|
|
|
|
|
|
1,187 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
operating costs and expenses |
|
|
954 |
|
|
|
65,752 |
|
|
|
71,279 |
|
|
|
(653 |
) |
|
|
137,332 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from
operations |
|
|
(954 |
) |
|
|
215 |
|
|
|
8,510 |
|
|
|
|
|
|
|
7,771 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in
affiliates, net of tax |
|
|
10,612 |
|
|
|
|
|
|
|
|
|
|
|
(10,612 |
) |
|
|
|
|
Interest, net |
|
|
(12,284 |
) |
|
|
(8 |
) |
|
|
(1,210 |
) |
|
|
|
|
|
|
(13,502 |
) |
Other |
|
|
21 |
|
|
|
(31 |
) |
|
|
227 |
|
|
|
|
|
|
|
217 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
(expense) |
|
|
(1,651 |
) |
|
|
(39 |
) |
|
|
(983 |
) |
|
|
(10,612 |
) |
|
|
(13,285 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)before
income taxes |
|
|
(2,605 |
) |
|
|
176 |
|
|
|
7,527 |
|
|
|
(10,612 |
) |
|
|
(5,514 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes |
|
|
|
|
|
|
4,304 |
|
|
|
(1,395 |
) |
|
|
|
|
|
|
2,909 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(2,605 |
) |
|
$ |
4,480 |
|
|
$ |
6,132 |
|
|
$ |
(10,612 |
) |
|
$ |
(2,605 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 8 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Three Months Ended March 31, 2009 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis- |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Chalmers |
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
Cash Flows from Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(2,605 |
) |
|
$ |
4,480 |
|
|
$ |
6,132 |
|
|
$ |
(10,612 |
) |
|
$ |
(2,605 |
) |
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
12 |
|
|
|
15,289 |
|
|
|
5,257 |
|
|
|
|
|
|
|
20,558 |
|
Amortization and write-off of
deferred financing fees |
|
|
555 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
555 |
|
Stock based compensation |
|
|
1,080 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,080 |
|
Allowance for bad debts |
|
|
|
|
|
|
385 |
|
|
|
|
|
|
|
|
|
|
|
385 |
|
Equity earnings in affiliates |
|
|
(10,612 |
) |
|
|
|
|
|
|
|
|
|
|
10,612 |
|
|
|
|
|
Deferred taxes |
|
|
(4,702 |
) |
|
|
1,177 |
|
|
|
(849 |
) |
|
|
|
|
|
|
(4,374 |
) |
(Gain) on sale of equipment |
|
|
|
|
|
|
(343 |
) |
|
|
(14 |
) |
|
|
|
|
|
|
(357 |
) |
Changes in operating assets and
liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in trade receivables |
|
|
|
|
|
|
21,930 |
|
|
|
3,008 |
|
|
|
|
|
|
|
24,938 |
|
(Increase) decrease in inventories |
|
|
|
|
|
|
(308 |
) |
|
|
2,071 |
|
|
|
|
|
|
|
1,763 |
|
(Increase) decrease in prepaid
expenses and other current assets |
|
|
1,789 |
|
|
|
(278 |
) |
|
|
105 |
|
|
|
|
|
|
|
1,616 |
|
(Increase) decrease in other assets |
|
|
(104 |
) |
|
|
233 |
|
|
|
528 |
|
|
|
|
|
|
|
657 |
|
(Decrease) in trade accounts
payable |
|
|
|
|
|
|
(9,023 |
) |
|
|
(7,014 |
) |
|
|
|
|
|
|
(16,037 |
) |
(Decrease) in accrued interest |
|
|
(10,782 |
) |
|
|
|
|
|
|
(366 |
) |
|
|
|
|
|
|
(11,148 |
) |
(Decrease) increase in accrued
expenses |
|
|
(183 |
) |
|
|
(2,087 |
) |
|
|
1,030 |
|
|
|
|
|
|
|
(1,240 |
) |
(Decrease) increase in accrued
salaries, benefits and payroll
taxes |
|
|
|
|
|
|
695 |
|
|
|
(1,018 |
) |
|
|
|
|
|
|
(323 |
) |
(Decrease) in other long- term
liabilities |
|
|
|
|
|
|
(19 |
) |
|
|
(336 |
) |
|
|
|
|
|
|
(355 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By (Used In)
Operating Activities |
|
|
(25,552 |
) |
|
|
32,131 |
|
|
|
8,534 |
|
|
|
|
|
|
|
15,113 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deposits on asset commitments |
|
|
|
|
|
|
|
|
|
|
(248 |
) |
|
|
|
|
|
|
(248 |
) |
Proceeds from sale of property and
equipment |
|
|
|
|
|
|
1,810 |
|
|
|
15 |
|
|
|
|
|
|
|
1,825 |
|
Purchase of property and equipment |
|
|
|
|
|
|
(9,578 |
) |
|
|
(4,380 |
) |
|
|
|
|
|
|
(13,958 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Investing
Activities |
|
|
|
|
|
|
(7,768 |
) |
|
|
(4,613 |
) |
|
|
|
|
|
|
(12,381 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 8 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Three Months Ended March 31, 2009 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis- |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
|
Cash Flows from Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable from affiliates |
|
|
|
|
|
|
(19,557 |
) |
|
|
|
|
|
|
19,557 |
|
|
|
|
|
Accounts payable to affiliates |
|
|
19,557 |
|
|
|
|
|
|
|
|
|
|
|
(19,557 |
) |
|
|
|
|
Net borrowing under line of credit |
|
|
6,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,000 |
|
Payments on long-term debt |
|
|
|
|
|
|
(907 |
) |
|
|
(3,740 |
) |
|
|
|
|
|
|
(4,647 |
) |
Debt issuance costs |
|
|
(5 |
) |
|
|
(86 |
) |
|
|
|
|
|
|
|
|
|
|
(91 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By (Used
In) Financing Activities |
|
|
25,552 |
|
|
|
(20,550 |
) |
|
|
(3,740 |
) |
|
|
|
|
|
|
1,262 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash
equivalents |
|
|
|
|
|
|
3,813 |
|
|
|
181 |
|
|
|
|
|
|
|
3,994 |
|
Cash and cash equivalents at
beginning of year |
|
|
|
|
|
|
2,923 |
|
|
|
3,943 |
|
|
|
|
|
|
|
6,866 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end
of period |
|
$ |
|
|
|
$ |
6,736 |
|
|
$ |
4,124 |
|
|
$ |
|
|
|
$ |
10,860 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 8 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
|
|
|
$ |
2,923 |
|
|
$ |
3,943 |
|
|
$ |
|
|
|
$ |
6,866 |
|
Trade receivables, net |
|
|
|
|
|
|
88,528 |
|
|
|
70,865 |
|
|
|
(1,522 |
) |
|
|
157,871 |
|
Inventories |
|
|
|
|
|
|
19,382 |
|
|
|
19,705 |
|
|
|
|
|
|
|
39,087 |
|
Intercompany receivables |
|
|
|
|
|
|
51,038 |
|
|
|
|
|
|
|
(51,038 |
) |
|
|
|
|
Note receivable from affiliate |
|
|
20,680 |
|
|
|
|
|
|
|
|
|
|
|
(20,680 |
) |
|
|
|
|
Prepaid expenses and other |
|
|
8,798 |
|
|
|
8,074 |
|
|
|
4,542 |
|
|
|
|
|
|
|
21,414 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
29,478 |
|
|
|
169,945 |
|
|
|
99,055 |
|
|
|
(73,240 |
) |
|
|
225,238 |
|
Property and equipment, net |
|
|
|
|
|
|
499,704 |
|
|
|
261,286 |
|
|
|
|
|
|
|
760,990 |
|
Goodwill |
|
|
|
|
|
|
23,251 |
|
|
|
20,022 |
|
|
|
|
|
|
|
43,273 |
|
Other intangible assets, net |
|
|
506 |
|
|
|
29,143 |
|
|
|
7,722 |
|
|
|
|
|
|
|
37,371 |
|
Debt issuance costs, net |
|
|
12,664 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,664 |
|
Note receivable from affiliates |
|
|
10,045 |
|
|
|
|
|
|
|
|
|
|
|
(10,045 |
) |
|
|
|
|
Investments in affiliates |
|
|
937,227 |
|
|
|
|
|
|
|
|
|
|
|
(937,227 |
) |
|
|
|
|
Other assets |
|
|
3,837 |
|
|
|
27,663 |
|
|
|
4,015 |
|
|
|
|
|
|
|
35,515 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
993,757 |
|
|
$ |
749,706 |
|
|
$ |
392,100 |
|
|
$ |
(1,020,512 |
) |
|
$ |
1,115,051 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders
Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term
debt |
|
$ |
782 |
|
|
$ |
992 |
|
|
$ |
12,843 |
|
|
$ |
|
|
|
$ |
14,617 |
|
Trade accounts payable |
|
|
|
|
|
|
27,759 |
|
|
|
35,841 |
|
|
|
(1,522 |
) |
|
|
62,078 |
|
Accrued salaries, benefits and
payroll taxes |
|
|
|
|
|
|
3,933 |
|
|
|
16,259 |
|
|
|
|
|
|
|
20,192 |
|
Accrued interest |
|
|
17,932 |
|
|
|
|
|
|
|
691 |
|
|
|
|
|
|
|
18,623 |
|
Accrued expenses |
|
|
281 |
|
|
|
13,841 |
|
|
|
12,520 |
|
|
|
|
|
|
|
26,642 |
|
Intercompany payables |
|
|
49,853 |
|
|
|
|
|
|
|
1,185 |
|
|
|
(51,038 |
) |
|
|
|
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
20,680 |
|
|
|
(20,680 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current
liabilities |
|
|
68,848 |
|
|
|
46,525 |
|
|
|
100,019 |
|
|
|
(73,240 |
) |
|
|
142,152 |
|
Long-term debt, net of current
maturities |
|
|
541,500 |
|
|
|
|
|
|
|
37,544 |
|
|
|
|
|
|
|
579,044 |
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
10,045 |
|
|
|
(10,045 |
) |
|
|
|
|
Deferred income tax liability |
|
|
|
|
|
|
|
|
|
|
8,253 |
|
|
|
|
|
|
|
8,253 |
|
Other long-term liabilities |
|
|
|
|
|
|
64 |
|
|
|
2,129 |
|
|
|
|
|
|
|
2,193 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
610,348 |
|
|
|
46,589 |
|
|
|
157,990 |
|
|
|
(83,285 |
) |
|
|
731,642 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock |
|
|
357 |
|
|
|
3,526 |
|
|
|
42,963 |
|
|
|
(46,489 |
) |
|
|
357 |
|
Capital in excess of par value |
|
|
334,633 |
|
|
|
570,512 |
|
|
|
133,339 |
|
|
|
(703,851 |
) |
|
|
334,633 |
|
Retained earnings |
|
|
48,419 |
|
|
|
129,079 |
|
|
|
57,808 |
|
|
|
(186,887 |
) |
|
|
48,419 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders
equity |
|
|
383,409 |
|
|
|
703,117 |
|
|
|
234,110 |
|
|
|
(937,227 |
) |
|
|
383,409 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
and stock holders
equity |
|
$ |
993,757 |
|
|
$ |
749,706 |
|
|
$ |
392,100 |
|
|
$ |
(1,020,512 |
) |
|
$ |
1,115,051 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 8 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Three Months Ended March 31, 2008 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
Revenues |
|
$ |
|
|
|
$ |
90,128 |
|
|
$ |
63,061 |
|
|
$ |
(7 |
) |
|
$ |
153,182 |
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs |
|
|
|
|
|
|
49,865 |
|
|
|
48,653 |
|
|
|
(7 |
) |
|
|
98,511 |
|
Depreciation |
|
|
|
|
|
|
11,333 |
|
|
|
3,169 |
|
|
|
|
|
|
|
14,502 |
|
Selling, general and
administrative |
|
|
2,376 |
|
|
|
10,733 |
|
|
|
2,362 |
|
|
|
|
|
|
|
15,471 |
|
Amortization |
|
|
12 |
|
|
|
1,095 |
|
|
|
9 |
|
|
|
|
|
|
|
1,116 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
operating costs and expenses |
|
|
2,388 |
|
|
|
73,026 |
|
|
|
54,193 |
|
|
|
(7 |
) |
|
|
129,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from
operations |
|
|
(2,388 |
) |
|
|
17,102 |
|
|
|
8,868 |
|
|
|
|
|
|
|
23,582 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in
affiliates, net of tax |
|
|
21,223 |
|
|
|
|
|
|
|
|
|
|
|
(21,223 |
) |
|
|
|
|
Interest, net |
|
|
(10,812 |
) |
|
|
76 |
|
|
|
(153 |
) |
|
|
|
|
|
|
(10,889 |
) |
Other |
|
|
27 |
|
|
|
44 |
|
|
|
36 |
|
|
|
|
|
|
|
107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
(expense) |
|
|
10,438 |
|
|
|
120 |
|
|
|
(117 |
) |
|
|
(21,223 |
) |
|
|
(10,782 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)before
income taxes |
|
|
8,050 |
|
|
|
17,222 |
|
|
|
8,751 |
|
|
|
(21,223 |
) |
|
|
12,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes |
|
|
|
|
|
|
(1,511 |
) |
|
|
(3,239 |
) |
|
|
|
|
|
|
(4,750 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
8,050 |
|
|
$ |
15,711 |
|
|
$ |
5,512 |
|
|
$ |
(21,223 |
) |
|
$ |
8,050 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 8 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Three Months Ended March 31, 2008 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis- |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
Cash Flows from Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
8,050 |
|
|
$ |
15,711 |
|
|
$ |
5,512 |
|
|
$ |
(21,223 |
) |
|
$ |
8,050 |
|
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
12 |
|
|
|
12,428 |
|
|
|
3,178 |
|
|
|
|
|
|
|
15,618 |
|
Amortization and write-off of
deferred financing fees |
|
|
519 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
519 |
|
Stock based compensation |
|
|
2,612 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,612 |
|
Allowance for bad debts |
|
|
|
|
|
|
267 |
|
|
|
|
|
|
|
|
|
|
|
267 |
|
Equity earnings in affiliates |
|
|
(21,223 |
) |
|
|
|
|
|
|
|
|
|
|
21,223 |
|
|
|
|
|
Deferred taxes |
|
|
901 |
|
|
|
|
|
|
|
1,064 |
|
|
|
|
|
|
|
1,965 |
|
(Gain) on sale of equipment |
|
|
|
|
|
|
(130 |
) |
|
|
|
|
|
|
|
|
|
|
(130 |
) |
Changes in operating assets and
liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Increase) in trade receivables |
|
|
|
|
|
|
(2,800 |
) |
|
|
(7,506 |
) |
|
|
|
|
|
|
(10,306 |
) |
(Increase) in inventories |
|
|
|
|
|
|
(720 |
) |
|
|
(90 |
) |
|
|
|
|
|
|
(810 |
) |
(Increase) decrease in prepaid
expenses and other current assets |
|
|
|
|
|
|
690 |
|
|
|
(462 |
) |
|
|
|
|
|
|
228 |
|
(Increase) decrease in other assets |
|
|
(1,457 |
) |
|
|
36 |
|
|
|
150 |
|
|
|
|
|
|
|
(1,271 |
) |
(Decrease) increase in trade
accounts payable |
|
|
|
|
|
|
(328 |
) |
|
|
1,851 |
|
|
|
|
|
|
|
1,523 |
|
(Decrease) increase in accrued
interest |
|
|
(10,958 |
) |
|
|
30 |
|
|
|
2 |
|
|
|
|
|
|
|
(10,926 |
) |
(Decrease) increase in accrued
expenses |
|
|
(1,488 |
) |
|
|
9,677 |
|
|
|
2,754 |
|
|
|
|
|
|
|
10,943 |
|
Increase in accrued salaries,
benefits and payroll taxes |
|
|
|
|
|
|
171 |
|
|
|
393 |
|
|
|
|
|
|
|
564 |
|
(Decrease) in other long- term
liabilities |
|
|
(31 |
) |
|
|
(32 |
) |
|
|
(99 |
) |
|
|
|
|
|
|
(162 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By (Used In)
Operating Activities |
|
|
(23,063 |
) |
|
|
35,000 |
|
|
|
6,747 |
|
|
|
|
|
|
|
18,684 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes receivable from affiliates |
|
|
(3,075 |
) |
|
|
|
|
|
|
|
|
|
|
3,075 |
|
|
|
|
|
Investment in note receivable |
|
|
(40,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(40,000 |
) |
Deposits on asset commitments |
|
|
|
|
|
|
|
|
|
|
(5,331 |
) |
|
|
|
|
|
|
(5,331 |
) |
Proceeds from sale of property and
equipment |
|
|
|
|
|
|
1,488 |
|
|
|
|
|
|
|
|
|
|
|
1,488 |
|
Purchase of property and equipment |
|
|
|
|
|
|
(21,149 |
) |
|
|
(18,528 |
) |
|
|
|
|
|
|
(39,677 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By (Used in)
Investing Activities |
|
|
(43,075 |
) |
|
|
(19,661 |
) |
|
|
(23,859 |
) |
|
|
3,075 |
|
|
|
(83,520 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 8 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Three Months Ended March 31, 2008 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis- |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
|
Cash Flows from Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable from affiliates |
|
|
45,598 |
|
|
|
|
|
|
|
|
|
|
|
(45,598 |
) |
|
|
|
|
Accounts payable to affiliates |
|
|
|
|
|
|
(45,598 |
) |
|
|
|
|
|
|
45,598 |
|
|
|
|
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
3,075 |
|
|
|
(3,075 |
) |
|
|
|
|
Proceeds from exercises of options |
|
|
61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61 |
|
Proceeds from long-term debt |
|
|
|
|
|
|
|
|
|
|
13,142 |
|
|
|
|
|
|
|
13,142 |
|
Net borrowing under line of credit |
|
|
20,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,500 |
|
Payments on long-term debt |
|
|
|
|
|
|
(1,662 |
) |
|
|
(630 |
) |
|
|
|
|
|
|
(2,292 |
) |
Debt issuance costs |
|
|
(21 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By (Used
In) Financing Activities |
|
|
66,138 |
|
|
|
(47,260 |
) |
|
|
15,587 |
|
|
|
(3,075 |
) |
|
|
31,390 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash
equivalents |
|
|
|
|
|
|
(31,921 |
) |
|
|
(1,525 |
) |
|
|
|
|
|
|
(33,446 |
) |
Cash and cash equivalents at
beginning of year |
|
|
|
|
|
|
41,176 |
|
|
|
2,517 |
|
|
|
|
|
|
|
43,693 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end
of period |
|
$ |
|
|
|
$ |
9,255 |
|
|
$ |
992 |
|
|
$ |
|
|
|
$ |
10,247 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 9 SEGMENT INFORMATION
All of our 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 |
|
|
|
March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
Revenues |
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
44,450 |
|
|
$ |
67,903 |
|
Drilling and Completion |
|
|
79,146 |
|
|
|
63,061 |
|
Rental Services |
|
|
21,507 |
|
|
|
22,218 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
145,103 |
|
|
$ |
153,182 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss): |
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
(1,213 |
) |
|
$ |
13,297 |
|
Drilling and Completion |
|
|
8,509 |
|
|
|
8,868 |
|
Rental Services |
|
|
3,948 |
|
|
|
6,222 |
|
General corporate |
|
|
(3,473 |
) |
|
|
(4,805 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
7,771 |
|
|
$ |
23,582 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and Amortization: |
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
7,315 |
|
|
$ |
5,630 |
|
Drilling and Completion |
|
|
5,257 |
|
|
|
3,178 |
|
Rental Services |
|
|
7,904 |
|
|
|
6,669 |
|
General corporate |
|
|
82 |
|
|
|
141 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
20,558 |
|
|
$ |
15,618 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures: |
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
4,032 |
|
|
$ |
14,427 |
|
Drilling and Completion |
|
|
4,639 |
|
|
|
18,529 |
|
Rental Services |
|
|
5,256 |
|
|
|
6,691 |
|
General corporate |
|
|
31 |
|
|
|
30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
13,958 |
|
|
$ |
39,677 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
United States |
|
$ |
61,559 |
|
|
$ |
83,984 |
|
Argentina |
|
|
63,425 |
|
|
|
62,641 |
|
Brazil |
|
|
10,766 |
|
|
|
|
|
Other international |
|
|
9,353 |
|
|
|
6,557 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
145,103 |
|
|
$ |
153,182 |
|
|
|
|
|
|
|
|
21
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 9 SEGMENT INFORMATION (Continued)
|
|
|
|
|
|
|
|
|
|
|
As of |
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Goodwill: |
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
23,250 |
|
|
$ |
23,250 |
|
Drilling and Completion |
|
|
20,023 |
|
|
|
20,023 |
|
Rental Services |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
43,273 |
|
|
$ |
43,273 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
289,454 |
|
|
$ |
309,901 |
|
Drilling and Completion |
|
|
405,236 |
|
|
|
411,486 |
|
Rental Services |
|
|
352,317 |
|
|
|
360,376 |
|
General corporate |
|
|
38,904 |
|
|
|
33,288 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,085,911 |
|
|
$ |
1,115,051 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long Lived Assets: |
|
|
|
|
|
|
|
|
United States |
|
$ |
570,649 |
|
|
$ |
573,975 |
|
Argentina |
|
|
190,200 |
|
|
|
212,456 |
|
Brazil |
|
|
82,130 |
|
|
|
79,568 |
|
Other international |
|
|
43,396 |
|
|
|
23,814 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
886,375 |
|
|
$ |
889,813 |
|
|
|
|
|
|
|
|
NOTE 10 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 have been named as a defendant in two lawsuits in connection with our proposed merger with
Bronco Drilling, Inc., which was terminated August 2008. We do not believe that the suits have any
merit.
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.
22
ITEM 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis should be read in conjunction with our consolidated financial
statements and the notes thereto included elsewhere in this report. This report 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.
For more information on forward-looking statements please refer to the section entitled
Forward-Looking Statements on page 32.
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, throughout the United States including Texas,
Oklahoma, Louisiana, Arkansas, Pennsylvania, New Mexico, offshore in the Gulf of Mexico and
internationally primarily in Argentina, Brazil and Mexico. We currently operate in three sectors
of the oil and natural gas service industry: Oilfield Services; Drilling and Completion and Rental
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 the 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 development 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 active rigs drilling, or the rig count, is an important indicator of activity levels
in the oil and natural gas industry. The rig count in the U.S. peaked at 2,031 in August 2008 but
then declined to 1,721 as of December 26, 2008, according to the Baker Hughes rig count, and has
continued to decline to 955 as of April 24, 2009. The rapid decline in the U.S. rig count is due
to the economic slowdown in the U.S. and the decrease in natural gas and oil prices which has
impacted the capital expenditures of our customers. The turmoil in the financial markets and its
impact on the availability of capital for our customers has also affected drilling activity in the
U.S. Directional and horizontal rig counts, according to the Baker Hughes rig count, have also
decreased and were 557 as of April 24, 2009 compared to 912 as of December 26, 2008, which
accounted for 58% and 53% of the total U.S. rig count, respectively.
While our revenue can be correlated to the rig count, our operating costs do not fluctuate in
direct proportion to changes in revenues. Our operating expenses consist 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 operating income as a percentage of
revenues is generally affected by our level of revenues.
Our Industry
The oilfield services industry is highly cyclical. The most critical factor in assessing the
outlook for the industry is the worldwide supply and demand for oil and the domestic supply and
demand for natural gas. The industry is driven by commodity demand and corresponding price
increases. As demand increases, producers raise their prices. The price escalation enables
producers to increase their capital expenditures. The increased capital expenditures ultimately
result in greater revenues and profits for services and equipment companies. The increased capital
expenditures also ultimately result in greater production which historically has resulted in
increased supplies and reduced prices.
23
Company Outlook
We believe that our revenue and operating income for our Oilfield Services and Rental Services
segment will suffer significantly in 2009, due to the reduction of our customers spending and the
drop in U.S. rig count. We have already taken steps in 2009 to reduce costs, including laying off
employees and closing unprofitable operating locations. Even with these steps, our Oilfield
Services segment may still generate negative operating income in 2009 due to its focus in the U.S.
market. Although we expect our Rental Services segment to be negatively impacted in a material
fashion by the industry wide reduction in drilling and completion activity, we believe that our
Rental Services segment will still generate positive operating income, albeit on lower revenue and
at reduced margins. We anticipate our Drilling and Completion segment results in 2009 will be
stable or comparable with 2008 as we benefit from a full year of operations on rigs acquired during
2008 and from the acquisition of BCH at the end of 2008. Our Drilling and Completion segment
primarily operates in Argentina and Brazil, but we have two rigs coming into service in 2009 in the
U.S. market. Currently, we have no firm commitments of work for our U.S. rigs, so the impact of
revenue and operating income from these rigs may be insignificant.
We expect to incur less general and administrative expenses in 2009 as we reduce our administrative
staff to reflect the decline in activity. Our net interest expense is dependent upon our level of
debt and cash on hand, which are principally dependent on acquisitions we complete, our capital
expenditures and our cash flows from operations. Due to the tightness of credit in the financial
markets, we may see an increase in our effective interest rate in 2009. In addition, the interest
rate on our credit facilities may increase if we violate any of our financial covenants in 2009.
The sustainability and future growth in our operating income is principally dependent on our level
of revenues and the pricing environment of our services. In addition, the demand for our services
is dependent upon our customers capital spending plans, which are largely driven by current
commodity prices and their expectations of future commodity prices. Recent declines in both
natural gas and oil prices have caused our customers to delay or curtail capital spending plans.
In addition to the impact of the decline in natural gas prices on our customers capital
expenditures and overall liquidity, the recent credit crisis has limited the availability of funds,
which has lead to decreased capital expenditures for our customers. The slowdown in economic
activity caused by the recession has reduced demand for energy and resulted in lower oil and
natural gas prices. Such a continued slowdown in economic activity could have a material adverse
effect on our revenue and profitability. We are monitoring the credit worthiness of our customers,
as well as outstanding receivables, in light of the current credit crisis and as such increased our
reserve for doubtful accounts significantly at December 31, 2008, but further reserves may be
necessary in 2009.
We continue to monitor the effect of the global financial crisis on our industry, and the resulting
impact on the capital spending budgets of our customers in order to estimate the effect on our
company. We have already reduced our planned capital spending significantly in 2009 compared to
2008. We believe that 2009 will be an extremely challenging year for our operations but we are
optimistic that our cost saving cuts, coupled with our strategy of striving to mitigate cyclical
risk through our international growth, by offering new equipment and technology to our customers
and our focus on the U.S. land shale plays, will carry us through the current recession.
Results of Operations
In December 2008, we acquired all of the outstanding stock of BCH, which is reported as part of our
Drilling and Completion segment. In August 2008, we sold our drill pipe tong manufacturing assets,
which were reported in our Oilfield Services segment. We consolidated the results of these
transactions from the date they were effective.
The foregoing acquisition and disposition affect the comparability from period to period of our
historical results, and our historical results may not be indicative of our future results.
24
Comparison of Three Months Ended March 31, 2009 and 2008
Our revenues for the three months ended March 31, 2009 were $145.1 million, a decrease of 5.3%
compared to $153.2 million for the three months ended March 31, 2008. The decrease in revenues is
due to the decrease in revenues in our Oilfield Services and our Rental Services segments, offset
in part by an increase in revenues in our Drilling and Completion segment. The increase in
revenues in our Drilling and Completion segment was due to the acquisition of BCH and additional
drilling and service rigs placed in service in 2008. The Drilling and Completion segment generated
$79.1 million in revenues for the three months ended March 31, 2009 compared to $63.1 million for
the three months ended March 31, 2008. BCH generated $10.8 million of revenues for the quarter
ended March 31, 2009. Our Oilfield Services segment revenues decreased to $44.5 million for the
three months ended March 31, 2009 compared to $67.9 million for the three months ended March 31,
2008 due to the decline in U.S. drilling activity. Revenues for our Rental Services segment
decreased to $21.5 million for the three months ended March 31, 2009 compared to $22.2 million for
the three months ended March 31, 2008 due to the reduction of drilling activity. The decrease in
drilling activity has also caused the pricing for our Oilfield Services and Rental Services segment
to become more competitive.
Our direct costs for the three months ended March 31, 2009 increased 4.7% to $103.1 million, or
71.1% of revenues, compared to $98.5 million, or 64.3%, of revenues for the three months ended
March 31, 2008 due to the acquisition of BCH at the end of 2008 and because revenues in our
Oilfield Services and Rental Services segments decreased faster during the quarter than the
reduction in direct costs. The benefit of certain cost reduction steps, including layoffs and
closure of certain operating locations, was not fully realized during the first quarter of 2009.
On a percentage basis, the reduction in revenues in our Oilfield Services segment outpaced the
reduction in direct costs for that segment when comparing the three months ended March 31, 2009 to
the three months ended March 31, 2008. Oilfield Services revenues for the three months ended March
31, 2009 decreased 34.5% from revenues for the three months ended March 31, 2008, while the direct
costs decreased 22.0% over that same period. This unfavorable variance was primarily associated
with the fact that not all of our direct costs are variable and therefore do not fluctuate with
revenues. Our Oilfield Services segment has also been impacted by pricing pressure that decreases
revenues but has no impact on direct costs. On a percentage basis, direct costs in our Drilling
and Completion segment outpaced the growth in our revenues for that segment. Drilling and
Completion revenues for the three months ended March 31, 2009 increased 25.5% from revenues for the
three months ended March 31, 2008, while the direct costs increased 27.1% over that same period.
This unfavorable variance is primarily attributed to lower utilization of our drilling and service
rigs during the three months ended March 31, 2009 compared to the same period of the prior year.
Our direct costs in our Rental Services segment increased while our revenue declined for that
segment. Rental Services revenues for the three months ended March 31, 2009 decreased 3.2% from
revenues in the Rental Services segment for the three months ended March 31, 2008, while the direct
costs increased 13.0% over that same period. Our direct costs for the Rental Services segment are
largely fixed because they primarily relate to yard expenses to maintain the rental inventory. In
addition, pricing pressure has reduced our Rental Services revenues but had no impact on our direct
costs.
Depreciation expense increased 33.6% to $19.4 million for the three months ended March 31, 2009
from $14.5 million for the three months ended March 31, 2008. The primary increase in depreciation
expense is due to our capital expenditure programs in 2008, principally the addition of new service
rigs and one drilling rig in Argentina and the expansion of our coiled tubing fleet. Depreciation
expense as a percentage of revenues increased to 13.3% for the first quarter of 2009, compared to
9.5% for the first quarter of 2008, due to the decrease in revenues as a result of the decline in
U.S. drilling activity. The acquisition of BCH at the end of 2008 contributed an additional $0.9
million of depreciation in the first three months of March 31, 2009.
Selling, general and administrative expense was $13.6 million for the three months ended March 31,
2009 compared to $15.5 million for the three months ended March 31, 2008. Selling, general and
administrative expense decreased primarily due to cost reduction steps that were made in the three
months ended March 31, 2009 in response to market conditions and a decrease related to the
amortization of share-based compensation arrangements. Selling, general and administrative expense
includes share-based compensation expense of $1.1 million in the first quarter of 2009 and $2.6
million in the first quarter of 2008. As a percentage of revenues, selling, general and
administrative expenses were 9.4% for the three months ended March 31, 2009 compared to 10.1% for
the same period in the prior year.
Amortization expense was $1.2 million for the three months ended March 31, 2009 compared to
$1.1 million for the three months ended March 31, 2008.
25
Our income from operations for the three months ended March 31, 2009 totaled $7.8 million, compared
to $23.6 million in income from operations for the three months ended March 31, 2008, for a total
decrease of $15.8 million. The decrease is primarily related to the decreased revenue combined
with the increase in direct costs and depreciation from the three months ended March 31, 2009
compared to three months ended March 31, 2008.
Our interest expense was $13.5 million for the three months ended March 31, 2009, compared to
$12.0 million for the three months ended March 31, 2008. During 2009, we increased our borrowing
against our revolving credit facility and as of March 31, 2009, we had an outstanding balance of
$42.5 million compared to an outstanding balance of $20.5 million at March 31, 2008. In 2008,
through our DLS subsidiary in Argentina, we also entered into a new $25.0 million import finance
facility with a bank to fund a portion of the purchase price of new drilling and service rigs.
Interest expense also increased due to the acquisition of BCH at the end of 2008. BCH had a $22.1
million term loan facility at December 31, 2008. Interest expense includes amortization expense of
deferred financing costs of $555,000 and $519,000 for the three months ended March 31, 2009 and
2008, respectively.
Our interest income was $5,000 for the three months ended March 31, 2009, compared to $1.1 million
for the three months ended March 31, 2008. In January 2008, we invested $40.0 million into a 15%
convertible subordinated secured debenture with BCH. We earned interest on this note up until
December 31, 2008, when we acquired all of the outstanding stock of BCH.
Our benefit for income taxes for the three months ended March 31, 2009 was $2.9 million, or 52.8%
of our net loss before income taxes, compared to an income tax expense of $4.8 million, or 37.1% of
our net income before income taxes for 2008. The income tax benefit recorded in 2009 was the
result of net loss before income taxes compared to net income before income taxes in the previous
year and a higher effective tax rate. Our U.S. effective tax rate was 33.0% for the three months
ended March 31, 2009, compared to 37.3% for the same period in the prior year. The lower effective
tax rate on our U.S. operations was due to nondeductible expenses and state income taxes. Our tax
rate from our DLS operations was 10.8% for the three months ended March 31, 2009, compared to 37.0%
for the same period in the prior year due to the impact of foreign currency operations and the
increase in the portion of income in the first quarter of 2009 that was generated in non-taxable
jurisdictions.
We had a net loss of $2.6 million for the three months ended March 31, 2009, compared to net income
of $8.1 million for the three months ended March 31, 2008 due to the foregoing reasons.
The following table compares revenues and income (loss) from operations for each of our business
segments for the quarter ended March 31, 2009 and 2008. Income (loss) from operations consists of
our revenues and the gain on asset dispositions less direct costs, selling, general and
administrative expenses, depreciation and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
Income (Loss) from Operations |
|
|
|
Three Months Ended |
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
Change |
|
|
2009 |
|
|
2008 |
|
|
Change |
|
|
|
(in thousands) |
|
|
Oilfield Services |
|
$ |
44,450 |
|
|
$ |
67,903 |
|
|
$ |
(23,453 |
) |
|
$ |
(1,213) |
|
|
$ |
13,297 |
|
|
$ |
(14,510 |
) |
Drilling and Completion |
|
|
79,146 |
|
|
|
63,061 |
|
|
|
16,085 |
|
|
|
8,509 |
|
|
|
8,868 |
|
|
|
(359 |
) |
Rental Services |
|
|
21,507 |
|
|
|
22,218 |
|
|
|
(711 |
) |
|
|
3,948 |
|
|
|
6,222 |
|
|
|
(2,274 |
) |
General corporate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,473 |
) |
|
|
(4,805 |
) |
|
|
1,332 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
145,103 |
|
|
$ |
153,182 |
|
|
$ |
(8,079 |
) |
|
$ |
7,771 |
|
|
$ |
23,582 |
|
|
$ |
(15,811 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
Oilfield Services
Revenues for our Oilfield Services segment were $44.5 million for the three months ended March 31,
2009, a decrease of 34.5% compared to $67.9 million in revenues for the three months ended March
31, 2008. Income from operations decreased $14.5 million and resulted in loss from operations of
$1.2 million in the first quarter of 2009 compared to income from operations of $13.3 million in
the first quarter of 2008. Our Oilfield Services segment revenues and operating income for the
first quarter of 2009 decreased compared to the first quarter of 2008 due primarily to market
conditions that resulted in lower utilization of our services and a reduction in the pricing for
our services. Additionally, depreciation and amortization expense for the Oilfield Services
segment increased by $1.7 million or 29.9% in the first quarter of 2009 compared to the first
quarter of the previous year, due to capital expenditures completed during 2008, including six
coiled tubing units delivered in the last half of 2008. We have not realized the benefits of these
capital expenditures due to decreased utilization and pricing of our equipment as a result of the
decline in U.S. drilling activity.
Drilling and Completion
Revenues for the quarter ended March 31, 2009 for the Drilling and Completion segment were $79.1
million, an increase of 25.5% compared to $63.1 million in revenues for the quarter ended March 31,
2008. Income from operations decreased to $8.5 million in the first quarter of 2009 compared to
$8.9 million in the first quarter of 2008, due to an increase of $2.1 million, or 65.4%, in
depreciation and amortization in the first quarter of 2009 compared to the first quarter of 2008.
The increase in depreciation and amortization expense was the result of the addition of new rigs in
Argentina and the acquisition of BCH. Our Drilling and Completion segment revenues increased in
the first quarter of 2009 primarily due to the acquisition of BCH at the end of 2008, which
generated $10.8 million of revenues during the three months ended March 31, 2009. We also
benefited from 16 new service rigs and one drilling rig which were placed in service in Argentina
at various dates in 2008 and one drilling rig placed in service in March 2009. The utilization and
rates for our service and drilling rigs in Argentina declined in the first quarter of 2009 compared
to the prior year.
Rental Services
Revenues for the quarter ended March 31, 2009 for the Rental Services segment were $21.5 million, a
decrease from $22.2 million in revenues for the quarter ended March 31, 2008. Income from
operations decreased to $3.9 million in the first quarter of 2009 compared to $6.2 million in the
first quarter of 2008. Our Rental Services segment revenues and operating income for the first
quarter of 2009 decreased compared to the prior year due primarily to the decrease in utilization
of our rental equipment and a more competitive pricing environment due to a decrease in drilling
activity in the U.S. Depreciation and amortization expense for our Rental Services segment
increased $1.2 million, or 18.5%, in the first quarter of 2009 compared to the first quarter of
2008 due to capital expenditures made during 2008 and a $584,000 additional reduction in the
carrying value of our airplane to its ultimate selling price received in April 2009.
General Corporate
General corporate expenses decreased $1.3 million to $3.5 million for the three months ended March
31, 2009 compared to $4.8 million for the three months ended March 31, 2008. The decrease was due
to the decrease in payroll costs and benefits due to reduced management and accounting and
administrative staff and the decrease in share-based compensation expense.
Liquidity
Our on-going capital requirements arise primarily from our need to service our debt, to acquire and
maintain equipment, to fund our working capital requirements and to complete acquisitions. Our
primary sources of liquidity are proceeds from the issuance of debt and equity securities and cash
flows from operations. Our amended and restated revolving credit facility permits borrowings of up
to $90.0 million in principal amount. As of March 31, 2009, we had $41.7 million available for
borrowing under our amended and restated revolving credit facility. We also have up to $25.0
million available under a new credit agreement which we executed in February 2009 to fund a portion
of the purchase price of two drilling rigs to be acquired in May 2009. Cash flows from operations
are expected to be our primary source of liquidity in fiscal 2009. We had cash and cash
equivalents of $10.9 million at March 31, 2009 compared to $6.9 million at December 31, 2008.
27
Our revolving credit agreement requires us to maintain specified financial ratios. If we fail to
comply with the financial ratio covenants, it could limit or eliminate the availability under our
revolving credit agreement. Our ability to maintain such financial ratios may be affected by
events beyond our control, including changes in general economic and business conditions, and we
cannot assure you that we will maintain or meet such ratios and tests or that the lenders under the
credit agreement will waive any failure to meet such ratios or tests. The decrease in the U.S. rig
count experienced late in 2008 and early 2009, the expectation of additional decreases in the U.S.
rig count, and the resulting decrease in demand for our services adversely impacts our ability to
maintain or meet such financial ratios.
Operating Activities
During the three months ended March 31, 2009, our operating activities provided $15.1 million in
cash. Our net loss for the three months ended March 31, 2009 was $2.6 million. Non-cash expenses
totaled $17.8 million during the first three months of 2009 consisting of $20.6 million of
depreciation and amortization, $1.1 million for share based compensation expense, $555,000 in
amortization of deferred financing fees, $385,000 related to increases to the allowance for
doubtful accounts receivables, less $4.4 million for deferred income taxes related to timing
differences and $357,000 on the gain from asset disposals.
During the three months ended March 31, 2009, changes in operating assets and liabilities used
$129,000 in cash, principally due to a decrease in accounts payable of $16.0 million, a decrease in
accrued interest of $11.1 million, a decrease in accrued expenses of $1.2 million, offset by a
decrease in trade receivables of $24.9 million, a decrease of $1.8 million in inventory and a
decrease in prepaid expenses and other current assets of $1.6 million. Accounts payable, accrued
expenses, trade receivables and inventory decreased primarily due to the drop in our activity in
the first three months of 2009. The decrease in accrued interest relates to the semi-annual
payment of interest on our senior notes. The decrease in prepaid expense and other current assets
primarily relates to amortization of prepaid expenses.
During the three months ended March 31, 2008, our operating activities provided $18.7 million in
cash. Net income for the three months ended March 31, 2008 was $8.1 million. Non-cash expenses
totaled $20.9 million during the first three months of 2008 consisting of $15.6 million of
depreciation and amortization, $2.0 million for deferred income taxes related to timing
differences, $519,000 in amortization of deferred financing fees, $2.6 million from the expensing
of stock options, $267,000 related to increases to the allowance for doubtful accounts receivables,
less $130,000 on the gain from asset disposals.
During the three months ended March 31, 2008, changes in operating assets and liabilities used
$10.2 million in cash, principally due to an increase of $10.3 million in trade receivables, an
increase of $810,000 in inventories, a decrease of $10.9 million in accrued interest, an increase
in other assets of $1.3 million, offset in part by an increase of $1.5 million in accounts payable
and an increase of $10.9 million in accrued expenses. Trade receivables increased primarily due to
the increase in our revenues in the first three months of 2008. The decrease in accrued interest
relates to the semi-annual payment of interest on our 8.5% senior notes. The increase in other
assets primarily relates to $1.1 million of interest income on our $40.0 million note receivable
from BCH. The increase in accounts payable can be attributed to additional expenses related to our
growth. The increase in accrued expenses is primarily related to a $5.7 million accrual for rental
equipment, along with an increase of our accrued income taxes payable of $1.6 million related to
current period results, and a general increase due to our growth.
Investing Activities
During the three months ended March 31, 2009, we used $12.4 million in investing activities,
consisting of $14.0 million for capital expenditures, offset by $1.8 million of proceeds from
equipment sales. Included in the $14.0 million for capital expenditures was $4.0 million for our
Oilfield Services segment, $4.6 million for additional equipment in our Drilling and Completion
segment and $5.3 million for drill pipe and other equipment used in our Rental Services segment. A
majority of our equipment sales relate to items lost in hole or damaged beyond repair by our
customers.
During the three months ended March 31, 2008, we used $83.5 million in investing activities,
consisting of a $40.0 million convertible subordinated secured note from BCH Ltd, $39.7 million for
capital expenditures, $5.3 million for deposits on equipment purchases for our Drilling and
Completion segment, offset by $1.5 million of proceeds from equipment sales. Included in the $39.7
million for capital expenditures was $14.4 million for our Oilfield Services segment, including
additional casing and tubing equipment and coiled tubing support equipment, $18.5 million for
additional equipment in our Drilling and Completion segment and $6.7 million for drill pipe and
other equipment used in our Rental Services segment. A majority of our equipment sales relate to
items lost in hole or damaged beyond repair by our customers.
28
Financing Activities
During the three months ended March 31, 2009, financing activities provided $1.3 million in cash.
We borrowed $6.0 million under our revolving credit facility and repaid $4.6 million in borrowings
under long-term debt facilities.
During the three months ended March 31, 2008, financing activities provided $31.4 million in cash.
We received $20.5 million from borrowings under our revolving line of credit and an additional
$13.1 million in proceeds from long-term debt and repaid $2.3 million in borrowings under long-term
debt facilities. We also received $61,000 in proceeds from the exercise of options and warrants.
At March 31, 2009, we had $595.0 million in outstanding indebtedness, of which $581.4 million was
long-term debt and $13.6 million is due within one year.
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.
In January 2007, we closed on a private offering, to qualified institutional buyers pursuant to
Rule 144A under the Securities Act, of $250.0 million principal amount of 8.5% senior notes due
2017. The proceeds of the senior notes offering, together with a portion of the proceeds of our
concurrent common stock offering, were used to repay the debt outstanding under our $300.0 million
bridge loan facility which we incurred to finance our acquisition of substantially all the assets
of OGR.
On January 18, 2006, we also executed an amended and restated credit agreement which provided for a
$25.0 million revolving line of credit with a maturity of January 2010. On April 26, 2007, we
entered into a Second Amended and Restated Credit Agreement, which increased our revolving line of
credit to $62.0 million, and had a final maturity date of April 26, 2012. On December 3, 2007, we
entered into a First Amendment to Second Amended and Restated Credit Agreement, which increased our
revolving line of credit to $90.0 million. The 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 amended and restated credit agreement are secured by
substantially all of our assets located in the U.S. We were in compliance with all debt covenants
as of March 31, 2009 and December 31, 2008. The credit agreement loan rates are based on prime or
LIBOR plus a margin. The weighted average interest rate was 6.4% and 4.6% at March 31, 2009 and
December 31, 2008, respectively. As of March 31, 2009 and December 31, 2008, amounts borrowed
under the facility were $42.5 million and $36.5 and availability was reduced by outstanding letters
of credit of $5.8 million.
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 interest rates on
these loans was 3.4% and 5.1% as of March 31, 2009 and December 31, 2008, respectively. The bank
loans are denominated in U.S. dollars and the outstanding amount due as of March 31, 2009 and
December 31, 2008 was $1.9 million and $2.5 million, respectively.
On February 15, 2008, through our DLS subsidiary in Argentina, we entered into a $25.0 million
import finance facility with a bank. The facility was available for draws until December 31, 2008,
but as of that date we had drawn down the whole facility. Borrowings under this facility were used
to fund a portion of the purchase price of the new drilling and service rigs ordered for our
Drilling and Completion segment. Each drawdown shall be repaid over four years in equal
semi-annual installments beginning one year after each disbursement with the final principal
payment due not later than March 15, 2013. The import finance facility is unsecured and contains
customary events of default and financial covenants and limits DLS ability to incur additional
indebtedness, make capital expenditures, create liens and sell assets. We were in compliance with
all debt covenants as of March 31, 2009 and December 31, 2008. The bank loan rates are based on
LIBOR plus a margin. The weighted average interest rate was 6.3% and 6.9% at March 31, 2009 and
December 31, 2008, respectively. The bank loans are denominated in U.S. dollars and the
outstanding amount as of March 31, 2009 and December 31, 2008 was $23.5 million and $25.0 million,
respectively.
29
As part of our acquisition of BCH, we assumed a $23.6 million term loan credit facility with a
bank. The credit agreement is dated June 2007 and contains customary events of default and
financial covenants. Obligations under the facility are secured by substantially all of the BCH
assets. The facility is repayable in quarterly principal installments plus interest with the final
payment due not later than August 2012. We were in compliance with all debt covenants as of March
31, 2009 and December 31, 2008. The credit facility loan is denominated in U.S. dollars and
interest rates are based on LIBOR plus a margin. At March 31, 2009 and December 31, 2008, the
outstanding amount of the loan was $20.6 million and $22.1 million and the interest rate was 4.5%
and 6.0%, respectively.
Notes payable
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 was paid in full in April 2009 in accordance with
its terms.
In 2000 we compensated directors, including current directors Robert Nederlander and Leonard
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%. As of
March 31, 2009 and December 31, 2008, the principal and accrued interest on these notes totaled
approximately $32,000.
In April 2008 and August 2008, we obtained insurance premium financings in the aggregate amount of
$3.0 million with a fixed average weighted interest rate of 4.9%. Under terms of the agreements,
amounts outstanding are paid over 10 and 11 month repayment schedules. The outstanding balance of
these notes was approximately $85,000 and $991,000 at March 31, 2009 and December 31, 2008,
respectively.
Other debt
As part of our acquisition of BCH, we assumed various capital leases with terms of two to three
years. The outstanding balance under these capital leases was $599,000 and $779,000 at March 31,
2009 and December 31, 2008, respectively.
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. At March 31, 2009, we had a $90.0 million revolving line of credit with a maturity of
April 2012. At March 31, 2009, we borrowed $42.5 million on the facility and availability was
further reduced by outstanding letters of credit of $5.8 million.
Capital Resources
We have reduced our planned capital spending for 2009 compared to 2008. We currently expect to
spend a total of approximately $55.0 million for the remainder of 2009, which is net of equipment
deposits paid in 2008. This amount includes budgeted but unidentified expenditures which may be
required to enhance or extend the life of existing assets. We believe that our cash generated from
operations, cash on hand and cash available under our credit facilities will provide sufficient
funds for our identified projects and to service our debt. However, the decrease in drilling
activity and the resulting decrease in demand and pricing for our services has an adverse impact on
our cash flow from operations and our liquidity. This could require us to raise external capital
and we cannot be assured such capital will be available to us, especially in the current tight
credit market and volatility in the equity market. Our ability to obtain capital for opportunistic
acquisitions or additional projects to implement our growth strategy over the longer term will
depend upon our future operating performance and financial condition, which will be dependent upon
the prevailing conditions in our industry and the global market, including the availability of
equity and debt financing, many of which are beyond our control.
30
Recent Developments
On April 5, 2009, Carlos A. Bulgheroni resigned from our board of directors for personal reasons,
effective April 7, 2009.
On April 9, 2009, we, along with certain of our subsidiaries, entered into a Third Amendment to our
existing Second Amended and Restated Credit Agreement dated as of April 26, 2007, with Royal Bank
of Canada, as administrative agent and collateral agent, and the lenders party thereto. The Third
Amendment, among other things, modifies the leverage ratio and interest coverage ratio covenants of
the Credit Agreement. In addition, permitted maximum capital expenditures were reduced to
$85.0 million for 2009 compared to the previous limit of $120.0 million, which is consistent with
our previously announced plans to limit capital expenditures for the year.
Critical Accounting Policies
Please see our Annual Report on Form 10-K for the year ended December 31, 2008 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 three months ended March 31, 2009.
Recently Issued Accounting Standards
In September 2006, the Financial Accounting Standards Board, or FASB, issued Statement of Financial
Accounting Standards No. 157, Fair Value Measurements, or SFAS No. 157. SFAS No. 157 clarifies the
principle that fair value should be based on the assumptions that market participants would use
when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the
information used to develop those assumptions. Under the standard, fair value measurements would
be separately disclosed by level within the fair value hierarchy. SFAS No. 157 is effective for
financial statements issued for fiscal years beginning after November 15, 2007, and interim periods
within those fiscal years, with early adoption permitted. Subsequently, the FASB provided for a
one-year deferral of the provisions of SFAS No. 157 for non-financial assets and liabilities that
are recognized or disclosed at fair value in the consolidated financial statements on a
non-recurring basis. As allowed under SFAS No. 157, we adopted all requirements of SFAS No. 157 on
January 1, 2008, except as they relate to nonfinancial assets and liabilities, which were adopted
on January 1, 2009 and neither adoption had any impact on our financial statements.
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141 (revised
2007), Business Combinations, or SFAS No. 141(R). SFAS No. 141(R) changes the requirements for an
acquirers recognition and measurement of the assets acquired and the liabilities assumed in a
business combination. Additionally, SFAS No. 141(R) requires that acquisition-related costs,
including restructuring costs, be recognized as expense separately from the acquisition. We
adopted SFAS No. 141(R) on January 1, 2009 and there was no impact on our financial statements.
In April 2008, the FASB issued FASB Staff Position SFAS 142-3, Determination of the Useful Life of
Intangible Assets, or FSP SFAS 142-3. FSP SFAS 142-3 amends the factors that should be considered
in developing renewal or extension assumptions used to determine the useful life of a recognized
intangible asset under SFAS No. 142. The objective of FSP SFAS 142-3 is to improve the consistency
between the useful life of a recognized intangible asset under SFAS No. 142 and the period of
expected cash flows used to measure the fair value of the asset under SFAS No. 141R, and other U.S.
GAAP principles. FSP SFAS 142-3 is effective for fiscal years beginning after December 15, 2008.
We adopted FSP SFAS 142-3 on January 1, 2009 and there was no impact on our financial statements.
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In April 2009, the FASB issued FASB Staff Position SFAS 141(R)-1, Accounting for Assets Acquired
and Liabilities Assumed in a Business Combination That Arise from Contingencies, or FSP SFAS
141(R)-1. FSP SFAS 141(R)-1 amends the guidance in SFAS No. 141(R) to require contingent assets
acquired and liabilities assumed in a business combination to be recognized at fair value on the
acquisition date if fair value can be reasonably estimated during the measurement period. If fair
value cannot be reasonably estimated during the measurement period, the contingent asset or
liability would be recognized in accordance with SFAS No. 5, Accounting for Contingencies, and FASB
Interpretation (FIN) No. 14, Reasonable Estimation of the Amount of a Loss. Further, this FSP
eliminated the specific subsequent accounting guidance for contingent assets and liabilities from
Statement 141(R), without significantly revising the guidance in SFAS No. 141. However, contingent
consideration arrangements of an acquiree assumed by the acquirer in a business combination would
still be initially and subsequently measured at fair value in accordance with SFAS No. 141(R). FSP
SFAS 141(R)-1 is effective for all business acquisitions occurring on or after the beginning of the
first annual reporting period beginning on or after December 15, 2008. We adopted the provisions
of FSP SFAS 141(R)-1 on January 1, 2009 and there was no impact on our financial statements.
In April 2009, the FASB issued FASB Staff Position SFAS 157-4, Determining Fair Value When the
Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and
Identifying Transactions That Are Not Orderly, or FSP SFAS 157-4. FSP SFAS 157-4 provides
additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and
level of activity for the asset or liability have significantly decreased. This FSP re-emphasizes
that regardless of market conditions the fair value measurement is an exit price concept as defined
in SFAS No. 157. This FSP clarifies and includes additional factors to consider in determining
whether there has been a significant decrease in market activity for an asset or liability and
provides additional clarification on estimating fair value when the market activity for an asset or
liability has declined significantly. The scope of this FSP does not include assets and
liabilities measured under level 1 inputs. FSP SFAS 157-4 is applied prospectively to all fair
value measurements where appropriate and will be effective for interim and annual periods ending
after June 15, 2009. We will adopt the provisions of FSP SFAS 157-4 on April 1, 2009 and do not
expect the adoption to have a material impact on our financial statements.
In April 2009, the FASB issued FASB Staff Position SFAS 107-1 and APB 28-1, Interim Disclosures
about Fair Value of Financial Instruments or FSP SFAS 107-1 and APB 28-1. FSP SFAS 107-1 and APB
281-1 amends SFAS No. 107, Disclosures about Fair Value of Financial Instruments, to require
publicly-traded companies, as defined in APB Opinion No. 28, Interim Financial Reporting, to
provide disclosures on the fair value of financial instruments in interim financial
statements. FSP SFAS 107-1 and APB 28-1 is effective for interim periods ending after June 15,
2009. We will adopt the additional disclosure requirements in our June 30, 2009 financial
statements.
Forward-Looking Statements
This quarterly report contains forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, as amended, or the Securities Act, regarding our business, financial
condition, results of operations and prospects. Words such as expects, anticipates, intends,
plans, believes, seeks, estimates and similar expressions or variations of such words are intended
to identify forward-looking statements. However, these are not the exclusive means of identifying
forward-looking statements. Although such forward-looking statements reflect our good faith
judgment, such statements can only be based on facts and factors currently known to us.
Consequently, forward-looking statements are inherently subject to risks and uncertainties, and
actual outcomes may differ materially from the results and outcomes discussed in the
forward-looking statements. Further information about the risks and uncertainties that may impact
us are described under Item 1ARisk Factors in our Annual Report on Form 10-K for the year ended
December 31, 2008. You should read those sections carefully. You should not place undue reliance
on forward-looking statements, which speak only as of the date of this quarterly report. We
undertake no obligation to update publicly any forward-looking statements in order to reflect any
event or circumstance occurring after the date of this quarterly report or currently unknown facts
or conditions or the occurrence of unanticipated events.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES 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. We have approximately $88.5 million of adjustable rate debt with a
weighted average interest rate of 5.9% at March 31, 2009.
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.
As of the end of the period covered by this quarterly report, we have evaluated the effectiveness
of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(e)
and 15d 15(e) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. This
evaluation was carried out under the supervision and with the participation of our management,
including our chief executive officer and chief financial officer. Based on this evaluation, these
officers have concluded that, as of March 31, 2009, our disclosure controls and procedures are
effective at a reasonable assurance level in ensuring that the information required to be disclosed
by us in reports filed under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the Securities and Exchange Commission, or SEC, rules and
forms.
We maintain disclosure controls and procedures that are designed to ensure that information
required to be disclosed in our reports under the Exchange Act, 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.
(b) Change in Internal Control Over Financial Reporting.
There have not been any changes 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.
PART II. OTHER INFORMATION
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.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized on May 8,
2009.
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Allis-Chalmers Energy Inc.
(Registrant)
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/s/ Munawar H. Hidayatallah |
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Munawar H. Hidayatallah |
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Chief Executive Officer and
Chairman
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EXHIBIT INDEX
10.1 |
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Amended and Restated Performance award Agreement, dated March 11, 2009, between
Allis-Chalmers Energy Inc. and Munawar H. Hidayatallah (incorporated by reference to Exhibit
10.1 to the Registrants Form 8-K filed on March 13, 2009). |
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10.2 |
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Letter agreements dated March 9, 2009, by each of Munawar H. Hidayatallah, Victor M. Perez,
Theodore F. Pound III, David Bryan, Terrence P. Keane and Mark Patterson (incorporate by
reference to Exhibit 10.2 to the Registrants Form 8-K filed on March 13, 2009). |
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10.3 |
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Third Amendment to Second Amended and Restated Credit Agreement, dated as of April 9, 2009,
by and among the Company, as borrower, certain subsidiaries of the Company, as guarantors,
Royal Bank of Canada, as administrative agent, and the lenders named thereto (incorporated by
reference to Exhibit 10.1 to the Registrants Form 8-K filed on April 9, 2009). |
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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. |
35