Form 10-Q
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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
incorporation or organization)
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(I.R.S. Employer
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
(Do not check if a smaller reporting company)
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Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of
the latest practicable date.
At August 1, 2009 there were 71,369,635 shares of common stock, par value $0.01 per share,
outstanding.
ALLIS-CHALMERS ENERGY INC.
FORM 10-Q
For the Quarterly Period Ended June 30, 2009
TABLE OF CONTENTS
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED CONDENSED BALANCE SHEETS
(in thousands, except for share and per share amounts)
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June 30, |
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December 31, |
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2009 |
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2008 |
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(unaudited) |
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Assets |
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Cash and cash equivalents |
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$ |
59,359 |
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$ |
6,866 |
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Trade receivables, net |
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99,027 |
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157,871 |
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Inventories |
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36,561 |
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39,087 |
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Deferred income tax asset |
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6,642 |
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6,176 |
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Prepaid expenses and other |
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14,109 |
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15,238 |
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Total current assets |
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215,698 |
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225,238 |
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Property and equipment, net |
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767,665 |
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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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34,997 |
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37,371 |
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Debt issuance costs, net |
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10,611 |
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12,664 |
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Deferred income tax asset |
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9,577 |
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3,993 |
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Other assets |
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21,700 |
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31,522 |
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Total assets |
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$ |
1,103,521 |
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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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$ |
15,559 |
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$ |
14,617 |
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Trade accounts payable |
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35,257 |
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62,078 |
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Accrued salaries, benefits and payroll taxes |
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19,156 |
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20,192 |
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Accrued interest |
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15,669 |
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18,623 |
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Accrued expenses |
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21,506 |
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26,642 |
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Total current liabilities |
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107,147 |
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142,152 |
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Long-term debt, net of current maturities |
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483,210 |
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579,044 |
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Deferred income tax liability |
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8,215 |
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8,253 |
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Other long-term liabilities |
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1,588 |
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2,193 |
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Total liabilities |
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600,160 |
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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; liquidation value $1,000 per share
(25,000,000 shares authorized, 36,393 shares issued and outstanding
at June 30, 2009 and no shares issued at December 31, 2008) |
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34,183 |
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Common stock, $0.01 par value (100,000,000 shares authorized;
71,369,635 issued and outstanding at June 30, 2009 and
35,674,742 issued and outstanding at December 31, 2008) |
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714 |
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357 |
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Capital in excess of par value |
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422,775 |
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334,633 |
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Retained earnings |
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45,689 |
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48,419 |
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Total stockholders equity |
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503,361 |
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383,409 |
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Total liabilities and stockholders equity |
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$ |
1,103,521 |
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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 STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
(unaudited)
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For the Three Months Ended |
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For the Six Months Ended |
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June 30, |
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June 30, |
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2009 |
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2008 |
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2009 |
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2008 |
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Revenues |
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$ |
112,505 |
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$ |
163,135 |
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$ |
257,608 |
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$ |
316,317 |
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Operating costs and expenses
Direct costs |
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87,239 |
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104,329 |
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190,373 |
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202,840 |
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Depreciation |
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19,181 |
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15,225 |
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38,552 |
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29,727 |
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Selling, general and administrative |
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15,525 |
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14,842 |
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29,165 |
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30,313 |
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Loss on asset disposition |
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1,916 |
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1,916 |
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Amortization |
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1,187 |
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1,071 |
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2,374 |
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2,187 |
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Total operating costs and expenses |
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125,048 |
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135,467 |
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262,380 |
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265,067 |
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Income (loss) from operations |
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(12,543 |
) |
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27,668 |
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(4,772 |
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51,250 |
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Other income (expense): |
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Interest expense |
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(13,221 |
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(12,036 |
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(26,728 |
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(24,077 |
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Interest income |
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9 |
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1,538 |
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14 |
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2,690 |
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Gain on debt extinguishment |
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26,365 |
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26,365 |
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Other |
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(485 |
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369 |
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(268 |
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476 |
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Total other income (expense) |
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12,668 |
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(10,129 |
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(617 |
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(20,911 |
) |
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Income (loss) before income taxes |
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125 |
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17,539 |
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(5,389 |
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30,339 |
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Provision for income taxes |
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(215 |
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(6,981 |
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2,694 |
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(11,731 |
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Net income (loss) |
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(90 |
) |
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10,558 |
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(2,695 |
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18,608 |
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Preferred stock dividend |
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(35 |
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(35 |
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Net income (loss) attributed
to common stockholders |
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$ |
(125 |
) |
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$ |
10,558 |
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$ |
(2,730 |
) |
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$ |
18,608 |
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Net income (loss) per common share: |
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Basic |
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$ |
0.00 |
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$ |
0.30 |
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$ |
(0.08 |
) |
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$ |
0.53 |
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Diluted |
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$ |
0.00 |
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$ |
0.30 |
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$ |
(0.08 |
) |
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$ |
0.53 |
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Weighted average shares outstanding: |
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Basic |
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36,959 |
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35,018 |
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36,087 |
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34,928 |
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Diluted |
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36,959 |
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35,534 |
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36,087 |
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35,386 |
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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 Six Months Ended |
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June 30, |
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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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$ |
(2,695 |
) |
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$ |
18,608 |
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Adjustments to reconcile net income (loss) to net cash
provided by operating activities: |
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Depreciation and amortization |
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40,926 |
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31,914 |
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Amortization and write-off of debt issuance costs |
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1,151 |
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1,038 |
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Stock-based compensation |
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2,345 |
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4,385 |
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Allowance for bad debts |
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3,565 |
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636 |
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Deferred taxes |
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(6,088 |
) |
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4,309 |
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Gain on sale of property and equipment |
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(602 |
) |
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(537 |
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Loss on asset disposition |
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1,916 |
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Gain on debt extinguishment |
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(26,365 |
) |
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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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55,279 |
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(13,887 |
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Decrease (increase) in inventories |
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2,526 |
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(4,498 |
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Decrease (increase) in prepaid expenses and other current assets |
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7,411 |
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(178 |
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Decrease (increase) in other assets |
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1,120 |
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(3,657 |
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Increase (decrease) in trade accounts payable |
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(27,170 |
) |
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8,667 |
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Increase (decrease) in accrued interest |
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(2,954 |
) |
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319 |
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Increase (decrease) in accrued expenses |
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(5,760 |
) |
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4,533 |
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Increase (decrease) in accrued salaries, benefits and payroll taxes |
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(1,036 |
) |
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5,012 |
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(Decrease) in other long-term liabilities |
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(605 |
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(249 |
) |
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Net Cash Provided By Operating Activities |
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42,964 |
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56,415 |
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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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10,032 |
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(3,447 |
) |
Proceeds from sale of property and equipment |
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6,693 |
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3,578 |
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Purchase of property and equipment |
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(57,993 |
) |
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(74,663 |
) |
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Net Cash Used In Investing Activities |
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(41,268 |
) |
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(114,532 |
) |
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Cash Flows from Financing Activities: |
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Proceeds from issuance of stock, net |
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120,337 |
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Proceeds from exercises of options |
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609 |
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Proceeds from long-term debt |
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25,000 |
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17,946 |
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Net borrowings (repayments) under line of credit |
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(36,500 |
) |
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|
10,000 |
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Payments on long-term debt |
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(57,396 |
) |
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(4,102 |
) |
Tax benefits on stock-based compensation plans |
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|
72 |
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Debt issuance costs |
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(644 |
) |
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(21 |
) |
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Net Cash Provided By Financing Activities |
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50,797 |
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|
24,504 |
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Net change in cash and cash equivalents |
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52,493 |
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(33,613 |
) |
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Cash and cash equivalents at beginning of period |
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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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$ |
59,359 |
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$ |
10,080 |
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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, Bolivia 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.
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.
We have evaluated subsequent events through August 6, 2009, up to the time of filing this Form 10-Q
with the SEC.
Financial Instruments
Financial instruments consist of cash and cash equivalents, accounts receivable and payable, and
debt. The carrying value of cash and cash equivalents and accounts receivable and payable
approximate fair value due to their short-term nature. We believe the fair values and the carrying
value of our debt, excluding the senior notes, would not be materially different due to the
instruments interest rates approximating market rates for similar borrowings at June 30, 2009.
Our senior notes, in the approximate aggregate amount of $430.2 million, trade over the counter
in limited amounts and on an infrequent basis. Based on those trades we estimate the fair value of
our senior notes to be approximately $297 million at June 30, 2009. The price at which our senior
notes trade is based on many factors such as the level of interest rates, the economic environment,
the outlook for the oilfield services industry and the perceived credit risk. Additionally, due to
the turmoil in the financial markets of 2008 and 2009, and its impact on investors of our senior
notes, the price at which our senior notes trade may be affected by the investors financial
distress and need for liquidity.
6
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 1 NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Reclassification
Certain reclassifications have been made to the prior years consolidated condensed financial
statements to conform with the current period presentation.
New Accounting Pronouncements
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 position or results of
operations.
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 position or
results of operations.
In April 2008, the FASB issued FASB Staff Position Statement of Financial Accounting Standards No.
142-3, Determination of the Useful Life of Intangible Assets, or FSP SFAS No. 142-3. FSP SFAS No.
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 Statement of Financial
Accounting Standards No. 142, Goodwill and Other Intangible Assets, or SFAS No. 142. The objective
of FSP SFAS No. 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 No. 142-3 is
effective for fiscal years beginning after December 15, 2008. We adopted FSP SFAS No. 142-3 on
January 1, 2009 and there was no impact on our financial position or results of operations.
In April 2009, the FASB issued FASB Staff Position Statement of Financial Accounting Standards No.
141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That
Arise from Contingencies, or FSP SFAS No. 141(R)-1. FSP SFAS No. 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 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 SFAS No. 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 No. 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 No. 141(R)-1 on January 1, 2009
and there was no impact on our financial position or results of operations.
7
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 1 NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
In April 2009, the FASB issued FASB Staff Position Statement of Financial Accounting Standards No.
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 No. 157-4.
FSP SFAS No. 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 No. 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 adopted the provisions of FSP SFAS No. 157-4 on
April 1, 2009 and there was no impact on our financial position or results of operations.
In April 2009, the FASB issued FASB Staff Position Statement of Financial Accounting Standards No.
107-1 and Accounting Principles Board Opinion No. 28-1, Interim Disclosures about Fair Value of
Financial Instruments or FSP SFAS 107-1 and APB 28-1. FSP SFAS No. 107-1 and APB No. 28-1 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 No. 107-1 and
APB No. 28-1 is effective for interim periods ending after June 15, 2009. We adopted the
additional disclosure requirements in our June 30, 2009 financial statements and there was no
impact on our financial position or results of operations.
In May 2009, the FASB issued Statement of Financial Accounting Standards No. 165, Subsequent
Events, or SFAS No. 165. SFAS No. 165 establishes general standards of accounting for and
disclosure of events that occur after the balance sheet date but before financial statements are
issued or are available to be issued. We adopted SFAS No. 165 for the period ending June 30, 2009,
which did not have an impact on our financial position or results of operations.
In June 2009, the FASB issued Statement of Financial Accounting Standards No. 167, Amendments to
FASB Interpretation No. 46(R), or SFAS No. 167. SFAS No. 167 amends FASB Interpretation No. 46(R),
Consolidation of Variable Interest Entities for determining whether an entity is a variable
interest entity (VIE) and requires an enterprise to perform an analysis to determine whether the
enterprises variable interest or interests give it a controlling financial interest in a VIE.
Under SFAS No. 167, an enterprise has a controlling financial interest when it has (i) the power to
direct the activities of a VIE that most significantly impact the entitys economic performance and
(ii) the obligation to absorb losses of the entity or the right to receive benefits from the entity
that could potentially be significant to the VIE. SFAS No. 167 also requires an enterprise to
assess whether it has an implicit financial responsibility to ensure that a VIE operates as
designed when determining whether it has power to direct the activities of the VIE that most
significantly impact the entitys economic performance. SFAS No. 167 also requires ongoing
assessments of whether an enterprise is the primary beneficiary of a VIE, requires enhanced
disclosures and eliminates the scope exclusion for qualifying special-purpose entities. SFAS No.
167 is effective for annual reporting periods beginning after November 15, 2009. We are currently
evaluating the impact the adoption of SFAS No. 167 will have on our financial position and
operating results.
In June 2009, the FASB issued Statement of Financial Accounting Standards No. 168, The FASB
Accounting Standards CodificationTM and Hierarchy of Generally Accepted
Accounting Principles, a replacement of FASB Statement No. 162, or SFAS No. 168. SFAS No. 168
establishes the FASB Standards Accounting Codification (Codification) as the source of
authoritative GAAP recognized by the FASB to be applied to nongovernmental entities and rules and
interpretive releases of the SEC as authoritative GAAP for SEC registrants. The Codification will
supersede all the existing non-SEC accounting and reporting standards upon its effective date and
subsequently, the FASB will not issue new standards in the form of Statements, FASB Staff Positions
or Emerging Issues Task Force Abstracts. Subsequent issuances of new standards will be in the form
of Accounting Standards Updates that will be included in the Codification. Generally, the
Codification is not expected to change U.S. GAAP. SFAS No. 168 is effective for financial
statements issued for interim and annual periods ending after September 15, 2009. Adoption of SFAS
No. 168 will require us to adjust references to authoritative accounting literature in our
financial statements, but will not affect our financial position or operating results.
8
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 2 STOCK-BASED COMPENSATION
Our net income (loss) for the three months ended June 30, 2009 and 2008 includes approximately $1.3
million and $1.8 million, respectively of compensation costs related to share-based payments. Our
net income (loss) for the six months ended June 30, 2009 and 2008 includes approximately $2.3
million and $4.4 million, respectively, of compensation costs related to share-based payments. As
of June 30, 2009 there was $1.0 million of unrecognized compensation expense related to non-vested
stock option grants. We expect approximately $456,000 to be recognized over the remainder of 2009
and 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 |
|
|
(207,000 |
) |
|
|
21.58 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at June 30, 2009 |
|
|
814,732 |
|
|
$ |
6.82 |
|
|
|
6.54 |
|
|
$ |
0.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at June 30, 2009 |
|
|
682,732 |
|
|
$ |
7.54 |
|
|
|
5.96 |
|
|
$ |
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 second
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
June 30, 2009.
We utilize the Black-Scholes model to determine fair value, which incorporates assumptions to value
stock-based awards. 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. The risk-free interest rate is
the related U.S. Treasury yield curve for periods within the expected term of the option at the
time of grant. We estimate forfeiture rates based on our historical experience. The following
summarizes the assumptions used for the options granted in the six months ended June 30, 2009
Black-Scholes model:
|
|
|
|
|
|
|
For the Six Months Ended |
|
|
|
June 30, 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 |
|
No options were granted during the three months ended June 30, 2009 or for the six months ended
June 30, 2008.
Restricted stock awards, or RSAs, activity during the six months ended June 30, 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 |
|
|
(39,645 |
) |
|
|
13.31 |
|
Forfeited |
|
|
(5,795 |
) |
|
|
16.69 |
|
|
|
|
|
|
|
|
Nonvested at June 30, 2009 |
|
|
924,662 |
|
|
$ |
15.16 |
|
|
|
|
|
|
|
|
|
9
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 2 STOCK-BASED COMPENSATION (Continued)
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 June 30, 2009, there was $6.8
million of total unrecognized compensation cost related to nonvested RSAs. We expect approximately
$2.0 million to be recognized over the remainder of 2009 and approximately $3.4 million, $1.2
million and $195,000 to be recognized during the years ended 2010, 2011 and 2012, respectively.
NOTE 3 INVENTORIES
Inventories consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Manufactured |
|
|
|
|
|
|
|
|
Finished goods |
|
$ |
3,407 |
|
|
$ |
2,821 |
|
Work in process |
|
|
1,972 |
|
|
|
1,654 |
|
Raw materials |
|
|
2,169 |
|
|
|
2,499 |
|
|
|
|
|
|
|
|
Total manufactured |
|
|
7,548 |
|
|
|
6,974 |
|
Hammers |
|
|
2,157 |
|
|
|
2,257 |
|
Drive pipe |
|
|
264 |
|
|
|
443 |
|
Rental supplies |
|
|
2,615 |
|
|
|
3,023 |
|
Chemicals and drilling fluids |
|
|
3,992 |
|
|
|
3,698 |
|
Rig parts and related inventory |
|
|
10,675 |
|
|
|
13,097 |
|
Coiled tubing and related inventory |
|
|
1,357 |
|
|
|
1,817 |
|
Shop supplies and related inventory |
|
|
7,953 |
|
|
|
7,778 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total inventories |
|
$ |
36,561 |
|
|
$ |
39,087 |
|
|
|
|
|
|
|
|
NOTE 4 GOODWILL AND INTANGIBLE ASSETS
In accordance with 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 June 30, 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 and six
months ended June 30, 2009 were $1.2 million and $2.4 million, respectively, compared to $1.1
million and $2.2 million for the same periods in the prior year. At June 30, 2009, intangible
assets totaled $35.0 million, net of $11.6 million of accumulated amortization.
10
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 5 DEBT
Our long-term debt consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Senior notes |
|
$ |
430,238 |
|
|
$ |
505,000 |
|
Term loans |
|
|
65,982 |
|
|
|
49,609 |
|
Revolving line of credit |
|
|
|
|
|
|
36,500 |
|
Seller notes |
|
|
|
|
|
|
750 |
|
Notes payable to former directors |
|
|
32 |
|
|
|
32 |
|
Insurance premium financing |
|
|
1,993 |
|
|
|
991 |
|
Capital lease obligations |
|
|
524 |
|
|
|
779 |
|
|
|
|
|
|
|
|
Total debt |
|
|
498,769 |
|
|
|
593,661 |
|
Less: current maturities |
|
|
15,559 |
|
|
|
14,617 |
|
|
|
|
|
|
|
|
Long-term debt, net of current maturities |
|
$ |
483,210 |
|
|
$ |
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. On June 29, 2009, we closed on a tender offer in
which we purchased $30.6 million aggregate principal of our 9.0% senior notes for a total
consideration of $650 per $1,000 principal amount.
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 June 29, 2009, we closed on a tender offer in which
we purchased $44.2 million aggregate principal of our 8.5% senior notes for a total consideration
of $600 per $1,000 principal amount.
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 June 30, 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. As of June 30, 2009, we had no borrowings under the facility
and at December 31, 2008 we had $36.5 million of borrowings outstanding. Availability under the
facility was reduced by outstanding letters of credit of $5.1 million and $5.8 million at June 30,
2009 and December 31, 2008, respectively. The credit agreement loan rates are based on prime or
LIBOR plus a margin. The weighted average interest rate was 4.6% at December 31, 2008.
11
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 5 DEBT (Continued)
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 3.3% and 5.1% as of June 30, 2009 and December 31, 2008, respectively. The bank
loans are denominated in U.S. dollars and the outstanding amount due as of June 30, 2009 and
December 31, 2008 was $1.8 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. 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
June 30, 2009 and December 31, 2008. The bank loan rates are based on LIBOR plus a margin. The
weighted average interest rate was 5.5% and 6.9% at June 30, 2009 and December 31, 2008,
respectively. The bank loans are denominated in U.S. dollars and the outstanding amount as of June
30, 2009 and December 31, 2008 was $23.0 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 June
30, 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 June 30, 2009 and December 31, 2008, the
outstanding amount of the loan was $16.2 million and $22.1 million and the interest rate was 3.8%
and 6.0%, respectively.
On May 22, 2009, we drew down $25.0 million on a new term loan credit facility with a lending
institution. The facility was utilized to fund a portion of the purchase price of two new drilling
rigs. The loan is secured by the equipment. The facility is repayable in quarterly installments
of approximately $1.4 million of principal and interest and matures in May 2015. The loan bears
interest at a fixed rate of 9.0%. At June 30, 2009, the outstanding amount of the loan was $25.0
million.
Notes payable
In connection with the acquisition of Rogers, we issued to the seller a note in the amount of
$750,000. The note bore interest at 5.0% and was paid in full in April 2009 in accordance with its
terms.
In 2000, we compensated directors, including current director Robert Nederlander, who served on the
board of directors from 1989 to June 30, 1999 without compensation, by issuing promissory notes
totaling $325,000. The notes bore interest at the rate of 5.0%. As of June 30, 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 $21,000 and $991,000 at June 30, 2009 and December 31, 2008,
respectively. In April 2009 and June 2009, we obtained insurance premium financings in the
aggregate amount of $2.4 million with a fixed average weighted interest rate of 4.9%. Under terms
of the agreements, the amount outstanding is paid over 10 and 11 month repayment schedules. The
outstanding balance of these notes was approximately $2.0 million as of June 30, 2009.
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 $524,000 at June 30, 2009 and
$779,000 at December 31, 2008.
12
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 6 STOCKHOLDERS EQUITY
We recognized approximately $2.3 million of compensation expense related to share-based payments in
the first six months of 2009 that was recorded as capital in excess of par value (see Note 2).
In June 2009, we closed our previously announced backstopped rights offering and private placement
of convertible preferred stock and received proceeds of approximately $120.3 million net of $5.3
million offering expenses. Pursuant to an Investment Agreement, Lime Rock Partners V, L.P., or
Lime Rock, agreed to backstop the rights offering by purchasing, at the subscription price, shares
of common stock not purchased by our existing stockholders. We sold 15,794,644 shares of our
common stock to existing stockholders who exercised their rights through the rights offering and
19,889,044 shares of common stock to Lime Rock, at a price of $2.50 per share.
We also issued 36,393 shares of 7.0% convertible perpetual preferred stock to Lime Rock and
received proceeds of approximately $34.2 million net of $2.2 million offering expenses. The
preferred stock has an initial liquidation preference of $1,000 per share and is adjusted to $3,000
per share solely upon ordinary liquidation events. Dividends on the preferred stock are declared
quarterly if approved by our Board of Directors and dividends accumulate if not paid. The
preferred stock is, with respect to dividend rights and rights upon liquidation, winding-up, or
dissolution: (1) senior to common stock; (2) on a parity with any class of capital stock
established after the original issue date when the terms of which provide that it will rank on a
parity with the preferred stock; (3) junior to each class of capital stock or series of preferred
stock established after the original issue date when the terms of such issuance expressly provide
that it will rank senior to the preferred stock; and (4) junior to all our existing and future debt
obligations and other liabilities, including claims of trade creditors.
Each share of the preferred stock is convertible at the holders option, at any time into 390.2439
shares of our common stock under certain conditions, subject to specified adjustments. This
conversion rate represents an equivalent conversion price of approximately $2.56 per share.
Conversion is limited to the earlier of June 26, 2012 or the date on which the transfer
restrictions included in the Investment Agreement expire, unless immediately after giving effect to
such conversion, such person or group would not beneficially own a number of shares of our common
stock exceeding 35% of the total number of issued and outstanding shares of common stock, unless we
have given prior written consent to such conversion. In addition, we will be able to cause the
preferred stock to be converted into common stock five years after issuance if our common stock is
trading at a premium of 300% to the conversion price for 30 consecutive trading days prior to our
issuance of a press release announcing the mandatory conversion. Generally, the preferred stock
vote together with the common stock on an as-converted basis, however, the preferred stock voting
rights held by any person or group when aggregated with common stock would be limited to 35% of all
the votes to be cast by all stockholders, including holders of common stock.
NOTE 7 LOSS ON ASSET DISPOSITION
During the three months ended June 30, 2009, we recorded a $1.9 million loss on asset disposition
in our Drilling and Completion segment. The insurance proceeds related to damages incurred on a
blow-out which destroyed one of our drilling rigs were not sufficient to cover the book value of
the rig and related assets.
NOTE 8 GAIN ON DEBT EXTINGUISHMENT
We recorded a gain of $26.4 million as a result of a tender offer that we completed on June 29,
2009. We purchased $30.6 million aggregate principal of our 9.0% senior notes and $44.2 million
aggregate principal of 8.5% senior notes for approximately $46.4 million. We also wrote-off $1.5
million of debt issuance costs related to the retired notes and we incurred approximately $466,000
in expenses related to the transactions.
13
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 9 INCOME PER COMMON 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. The
components of basic and diluted earnings per share are as follows (in thousands, except per share
amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended |
|
|
For the Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(90 |
) |
|
$ |
10,558 |
|
|
$ |
(2,695 |
) |
|
$ |
18,608 |
|
Preferred stock dividend |
|
|
(35 |
) |
|
|
|
|
|
|
(35 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributed to common
stockholders |
|
$ |
(125 |
) |
|
$ |
10,558 |
|
|
$ |
(2,730 |
) |
|
$ |
18,608 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding excluding nonvested
restricted stock |
|
|
36,959 |
|
|
|
35,018 |
|
|
|
36,087 |
|
|
|
34,928 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of potentially dilutive common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants and employee and director
stock options and restricted shares |
|
|
|
|
|
|
516 |
|
|
|
|
|
|
|
458 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding and assumed conversions |
|
|
36,959 |
|
|
|
35,534 |
|
|
|
36,087 |
|
|
|
35,386 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.00 |
|
|
$ |
.30 |
|
|
$ |
(0.08 |
) |
|
$ |
0.53 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
0.00 |
|
|
$ |
.30 |
|
|
$ |
(0.08 |
) |
|
$ |
0.53 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Potentially dilutive securities excluded
as anti-dilutive |
|
|
15,698 |
|
|
|
472 |
|
|
|
15,698 |
|
|
|
548 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible preferred stock and share based compensation shares of approximately 787,000 and
435,000 were excluded in the computation of diluted earnings per share for the three and six months
ended June 30, 2009, respectively as the effect would have been anti-dilutive (e.g., those that
increase income per share) due to the net loss for the period.
NOTE 10 SUPPLEMENTAL CASH FLOW INFORMATION
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended |
|
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
Cash paid for interest and income taxes: |
|
|
|
|
|
|
|
|
Interest |
|
$ |
28,329 |
|
|
$ |
23,087 |
|
Income taxes |
|
|
1,354 |
|
|
|
12,595 |
|
|
|
|
|
|
|
|
|
|
Non-cash activities: |
|
|
|
|
|
|
|
|
Insurance premium financed |
|
|
2,381 |
|
|
|
2,767 |
|
Assets transferred to joint venture investment |
|
|
1,330 |
|
|
|
|
|
Preferred stock dividend |
|
|
35 |
|
|
|
|
|
14
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 11 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).
CONDENSED CONSOLIDATING BALANCE SHEETS
June 30, 2009 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
|
|
|
$ |
51,929 |
|
|
$ |
7,430 |
|
|
$ |
|
|
|
$ |
59,359 |
|
Trade receivables, net |
|
|
|
|
|
|
47,898 |
|
|
|
53,497 |
|
|
|
(2,368 |
) |
|
|
99,027 |
|
Inventories |
|
|
|
|
|
|
18,751 |
|
|
|
17,810 |
|
|
|
|
|
|
|
36,561 |
|
Intercompany receivables |
|
|
|
|
|
|
37,423 |
|
|
|
|
|
|
|
(37,423 |
) |
|
|
|
|
Note receivable from affiliate |
|
|
23,495 |
|
|
|
|
|
|
|
|
|
|
|
(23,495 |
) |
|
|
|
|
Prepaid expenses and other |
|
|
477 |
|
|
|
8,032 |
|
|
|
12,242 |
|
|
|
|
|
|
|
20,751 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
23,972 |
|
|
|
164,033 |
|
|
|
90,979 |
|
|
|
(63,286 |
) |
|
|
215,698 |
|
Property and equipment, net |
|
|
|
|
|
|
513,150 |
|
|
|
254,515 |
|
|
|
|
|
|
|
767,665 |
|
Goodwill |
|
|
|
|
|
|
23,251 |
|
|
|
20,022 |
|
|
|
|
|
|
|
43,273 |
|
Other intangible assets, net |
|
|
483 |
|
|
|
27,182 |
|
|
|
7,332 |
|
|
|
|
|
|
|
34,997 |
|
Debt issuance costs, net |
|
|
10,460 |
|
|
|
151 |
|
|
|
|
|
|
|
|
|
|
|
10,611 |
|
Note receivable from affiliates |
|
|
7,230 |
|
|
|
|
|
|
|
|
|
|
|
(7,230 |
) |
|
|
|
|
Investments in affiliates |
|
|
938,127 |
|
|
|
|
|
|
|
|
|
|
|
(938,127 |
) |
|
|
|
|
Other assets |
|
|
9,455 |
|
|
|
19,279 |
|
|
|
2,543 |
|
|
|
|
|
|
|
31,277 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
989,727 |
|
|
$ |
747,046 |
|
|
$ |
375,391 |
|
|
$ |
(1,008,643 |
) |
|
$ |
1,103,521 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt |
|
$ |
32 |
|
|
$ |
5,290 |
|
|
$ |
10,237 |
|
|
$ |
|
|
|
$ |
15,559 |
|
Trade accounts payable |
|
|
|
|
|
|
14,858 |
|
|
|
22,767 |
|
|
|
(2,368 |
) |
|
|
35,257 |
|
Accrued salaries, benefits and
payroll taxes |
|
|
|
|
|
|
2,136 |
|
|
|
17,020 |
|
|
|
|
|
|
|
19,156 |
|
Accrued interest |
|
|
15,101 |
|
|
|
243 |
|
|
|
325 |
|
|
|
|
|
|
|
15,669 |
|
Accrued expenses |
|
|
4,733 |
|
|
|
7,431 |
|
|
|
9,342 |
|
|
|
|
|
|
|
21,506 |
|
Intercompany payables |
|
|
36,262 |
|
|
|
|
|
|
|
1,161 |
|
|
|
(37,423 |
) |
|
|
|
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
23,495 |
|
|
|
(23,495 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
56,128 |
|
|
|
29,958 |
|
|
|
84,347 |
|
|
|
(63,286 |
) |
|
|
107,147 |
|
Long-term debt, net of current
maturities |
|
|
430,238 |
|
|
|
21,703 |
|
|
|
31,269 |
|
|
|
|
|
|
|
483,210 |
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
7,230 |
|
|
|
(7,230 |
) |
|
|
|
|
Deferred income tax liability |
|
|
|
|
|
|
|
|
|
|
8,215 |
|
|
|
|
|
|
|
8,215 |
|
Other long-term liabilities |
|
|
|
|
|
|
26 |
|
|
|
1,562 |
|
|
|
|
|
|
|
1,588 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
486,366 |
|
|
|
51,687 |
|
|
|
132,623 |
|
|
|
(70,516 |
) |
|
|
600,160 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock |
|
|
34,183 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34,183 |
|
Common stock |
|
|
714 |
|
|
|
3,526 |
|
|
|
42,963 |
|
|
|
(46,489 |
) |
|
|
714 |
|
Capital in excess of par value |
|
|
422,775 |
|
|
|
570,512 |
|
|
|
136,839 |
|
|
|
(707,351 |
) |
|
|
422,775 |
|
Retained earnings |
|
|
45,689 |
|
|
|
121,321 |
|
|
|
62,966 |
|
|
|
(184,287 |
) |
|
|
45,689 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
503,361 |
|
|
|
695,359 |
|
|
|
242,768 |
|
|
|
(938,127 |
) |
|
|
503,361 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and
stockholders equity |
|
$ |
989,727 |
|
|
$ |
747,046 |
|
|
$ |
375,391 |
|
|
$ |
(1,008,643 |
) |
|
$ |
1,103,521 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 11 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Six Months Ended June 30, 2009 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
|
Revenues |
|
$ |
|
|
|
$ |
110,705 |
|
|
$ |
148,173 |
|
|
$ |
(1,270 |
) |
|
$ |
257,608 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs |
|
|
|
|
|
|
72,243 |
|
|
|
119,400 |
|
|
|
(1,270 |
) |
|
|
190,373 |
|
Depreciation |
|
|
|
|
|
|
28,222 |
|
|
|
10,330 |
|
|
|
|
|
|
|
38,552 |
|
Selling, general and
administrative |
|
|
1,986 |
|
|
|
19,956 |
|
|
|
7,223 |
|
|
|
|
|
|
|
29,165 |
|
Loss on asset disposition |
|
|
|
|
|
|
|
|
|
|
1,916 |
|
|
|
|
|
|
|
1,916 |
|
Amortization |
|
|
23 |
|
|
|
1,961 |
|
|
|
390 |
|
|
|
|
|
|
|
2,374 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs
and expenses |
|
|
2,009 |
|
|
|
122,382 |
|
|
|
139,259 |
|
|
|
(1,270 |
) |
|
|
262,380 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from
operations |
|
|
(2,009 |
) |
|
|
(11,677 |
) |
|
|
8,914 |
|
|
|
|
|
|
|
(4,772 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in
affiliates, net of tax |
|
|
(2,600 |
) |
|
|
|
|
|
|
|
|
|
|
2,600 |
|
|
|
|
|
Interest, net |
|
|
(24,486 |
) |
|
|
(21 |
) |
|
|
(2,207 |
) |
|
|
|
|
|
|
(26,714 |
) |
Gain on debt
extinguishment |
|
|
26,365 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,365 |
|
Other |
|
|
35 |
|
|
|
(106 |
) |
|
|
(197 |
) |
|
|
|
|
|
|
(268 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
(expense) |
|
|
(686 |
) |
|
|
(127 |
) |
|
|
(2,404 |
) |
|
|
2,600 |
|
|
|
(617 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)before
income taxes |
|
|
(2,695 |
) |
|
|
(11,804 |
) |
|
|
6,510 |
|
|
|
2,600 |
|
|
|
(5,389 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes |
|
|
|
|
|
|
4,046 |
|
|
|
(1,352 |
) |
|
|
|
|
|
|
2,694 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
(2,695 |
) |
|
|
(7,758 |
) |
|
|
5,158 |
|
|
|
2,600 |
|
|
|
(2,695 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividend |
|
|
(35 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(35 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
attributed to common
stockholders |
|
$ |
(2,730 |
) |
|
$ |
(7,758 |
) |
|
$ |
5,158 |
|
|
$ |
2,600 |
|
|
$ |
(2,730 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 11 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended June 30, 2009 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
|
Revenues |
|
$ |
|
|
|
$ |
44,738 |
|
|
$ |
68,384 |
|
|
$ |
(617 |
) |
|
$ |
112,505 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs |
|
|
|
|
|
|
30,948 |
|
|
|
56,908 |
|
|
|
(617 |
) |
|
|
87,239 |
|
Depreciation |
|
|
|
|
|
|
13,913 |
|
|
|
5,268 |
|
|
|
|
|
|
|
19,181 |
|
Selling, general and
administrative |
|
|
1,044 |
|
|
|
10,788 |
|
|
|
3,693 |
|
|
|
|
|
|
|
15,525 |
|
Loss on asset disposition |
|
|
|
|
|
|
|
|
|
|
1,916 |
|
|
|
|
|
|
|
1,916 |
|
Amortization |
|
|
11 |
|
|
|
981 |
|
|
|
195 |
|
|
|
|
|
|
|
1,187 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs
and expenses |
|
|
1,055 |
|
|
|
56,630 |
|
|
|
67,980 |
|
|
|
(617 |
) |
|
|
125,048 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from
operations |
|
|
(1,055 |
) |
|
|
(11,892 |
) |
|
|
404 |
|
|
|
|
|
|
|
(12,543 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in
affiliates, net of tax |
|
|
(13,212 |
) |
|
|
|
|
|
|
|
|
|
|
13,212 |
|
|
|
|
|
Interest, net |
|
|
(12,202 |
) |
|
|
(13 |
) |
|
|
(997 |
) |
|
|
|
|
|
|
(13,212 |
) |
Gain on debt
extinguishment |
|
|
26,365 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,365 |
|
Other |
|
|
14 |
|
|
|
(75 |
) |
|
|
(424 |
) |
|
|
|
|
|
|
(485 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
(expense) |
|
|
965 |
|
|
|
(88 |
) |
|
|
(1,421 |
) |
|
|
13,212 |
|
|
|
12,668 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)before
income taxes |
|
|
(90 |
) |
|
|
(11,980 |
) |
|
|
(1,017 |
) |
|
|
13,212 |
|
|
|
125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes |
|
|
|
|
|
|
(258 |
) |
|
|
43 |
|
|
|
|
|
|
|
(215 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
(90 |
) |
|
|
(12,238 |
) |
|
|
(974 |
) |
|
|
13,212 |
|
|
|
(90 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividend |
|
|
(35 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(35 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
attributed to common
stockholders |
|
$ |
(125 |
) |
|
$ |
(12,238 |
) |
|
$ |
(974 |
) |
|
$ |
13,212 |
|
|
$ |
(125 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 11 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Six Months Ended June 30, 2009 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
Cash Flows from Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(2,695 |
) |
|
$ |
(7,758 |
) |
|
$ |
5,158 |
|
|
$ |
2,600 |
|
|
$ |
(2,695 |
) |
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
23 |
|
|
|
30,183 |
|
|
|
10,720 |
|
|
|
|
|
|
|
40,926 |
|
Amortization and write-off of debt
issuance costs |
|
|
1,149 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
1,151 |
|
Stock based compensation |
|
|
2,345 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,345 |
|
Allowance for bad debts |
|
|
|
|
|
|
3,565 |
|
|
|
|
|
|
|
|
|
|
|
3,565 |
|
Equity earnings in affiliates |
|
|
2,600 |
|
|
|
|
|
|
|
|
|
|
|
(2,600 |
) |
|
|
|
|
Deferred taxes |
|
|
(4,783 |
) |
|
|
1 |
|
|
|
(1,306 |
) |
|
|
|
|
|
|
(6,088 |
) |
(Gain) on sale of equipment |
|
|
|
|
|
|
(543 |
) |
|
|
(59 |
) |
|
|
|
|
|
|
(602 |
) |
Loss on asset disposition |
|
|
|
|
|
|
|
|
|
|
1,916 |
|
|
|
|
|
|
|
1,916 |
|
Gain on debt extinguishment |
|
|
(26,365 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(26,365 |
) |
Changes in operating assets and
liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in trade receivables |
|
|
|
|
|
|
37,911 |
|
|
|
17,368 |
|
|
|
|
|
|
|
55,279 |
|
Decrease in inventories |
|
|
|
|
|
|
631 |
|
|
|
1,895 |
|
|
|
|
|
|
|
2,526 |
|
(Increase) decrease in prepaid
expenses and other current assets |
|
|
7,520 |
|
|
|
2,422 |
|
|
|
(2,531 |
) |
|
|
|
|
|
|
7,411 |
|
(Increase) decrease in other assets |
|
|
(34 |
) |
|
|
(902 |
) |
|
|
2,056 |
|
|
|
|
|
|
|
1,120 |
|
(Decrease) in trade accounts
payable |
|
|
|
|
|
|
(13,747 |
) |
|
|
(13,423 |
) |
|
|
|
|
|
|
(27,170 |
) |
(Decrease) increase in accrued
interest |
|
|
(2,831 |
) |
|
|
243 |
|
|
|
(366 |
) |
|
|
|
|
|
|
(2,954 |
) |
(Decrease) increase in accrued
expenses |
|
|
3,951 |
|
|
|
(6,410 |
) |
|
|
(3,301 |
) |
|
|
|
|
|
|
(5,760 |
) |
(Decrease) increase in accrued
salaries, benefits and payroll
taxes |
|
|
|
|
|
|
(1,797 |
) |
|
|
761 |
|
|
|
|
|
|
|
(1,036 |
) |
(Decrease) in other long- term
liabilities |
|
|
|
|
|
|
(38 |
) |
|
|
(567 |
) |
|
|
|
|
|
|
(605 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By (Used In)
Operating Activities |
|
|
(19,120 |
) |
|
|
43,763 |
|
|
|
18,321 |
|
|
|
|
|
|
|
42,964 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in affiliates |
|
|
(3,500 |
) |
|
|
|
|
|
|
|
|
|
|
3,500 |
|
|
|
|
|
Deposits on asset commitments |
|
|
|
|
|
|
10,616 |
|
|
|
(584 |
) |
|
|
|
|
|
|
10,032 |
|
Proceeds from sale of property and
equipment |
|
|
|
|
|
|
6,634 |
|
|
|
59 |
|
|
|
|
|
|
|
6,693 |
|
Purchase of property and equipment |
|
|
|
|
|
|
(49,089 |
) |
|
|
(8,904 |
) |
|
|
|
|
|
|
(57,993 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Investing
Activities |
|
|
(3,500 |
) |
|
|
(31,839 |
) |
|
|
(9,429 |
) |
|
|
3,500 |
|
|
|
(41,268 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 11 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Six Months Ended June 30, 2009 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
Cash Flows from Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable from affiliates |
|
|
|
|
|
|
13,615 |
|
|
|
|
|
|
|
(13,615 |
) |
|
|
|
|
Accounts payable to affiliates |
|
|
(13,591 |
) |
|
|
|
|
|
|
(24 |
) |
|
|
13,615 |
|
|
|
|
|
Proceeds from parent contributions |
|
|
|
|
|
|
|
|
|
|
3,500 |
|
|
|
(3,500 |
) |
|
|
|
|
Proceeds from issuance of stock, net |
|
|
120,337 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
120,337 |
|
Proceeds from long-term debt |
|
|
|
|
|
|
25,000 |
|
|
|
|
|
|
|
|
|
|
|
25,000 |
|
Net repayment under line of credit |
|
|
(36,500 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(36,500 |
) |
Payments on long-term debt |
|
|
(47,135 |
) |
|
|
(1,380 |
) |
|
|
(8,881 |
) |
|
|
|
|
|
|
(57,396 |
) |
Debt issuance costs |
|
|
(491 |
) |
|
|
(153 |
) |
|
|
|
|
|
|
|
|
|
|
(644 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By (Used
In) Financing Activities |
|
|
22,620 |
|
|
|
37,082 |
|
|
|
(5,405 |
) |
|
|
(3,500 |
) |
|
|
50,797 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash
equivalents |
|
|
|
|
|
|
49,006 |
|
|
|
3,487 |
|
|
|
|
|
|
|
52,493 |
|
Cash and cash equivalents at
beginning of period |
|
|
|
|
|
|
2,923 |
|
|
|
3,943 |
|
|
|
|
|
|
|
6,866 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of
period |
|
$ |
|
|
|
$ |
51,929 |
|
|
$ |
7,430 |
|
|
$ |
|
|
|
$ |
59,359 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 11 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 11 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Six Months Ended June 30, 2008 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
|
Revenues |
|
$ |
|
|
|
$ |
183,451 |
|
|
$ |
132,879 |
|
|
$ |
(13 |
) |
|
$ |
316,317 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs |
|
|
|
|
|
|
99,853 |
|
|
|
103,000 |
|
|
|
(13 |
) |
|
|
202,840 |
|
Depreciation |
|
|
|
|
|
|
23,167 |
|
|
|
6,560 |
|
|
|
|
|
|
|
29,727 |
|
Selling, general and
administrative |
|
|
3,890 |
|
|
|
21,380 |
|
|
|
5,043 |
|
|
|
|
|
|
|
30,313 |
|
Amortization |
|
|
23 |
|
|
|
2,147 |
|
|
|
17 |
|
|
|
|
|
|
|
2,187 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs
and expenses |
|
|
3,913 |
|
|
|
146,547 |
|
|
|
114,620 |
|
|
|
(13 |
) |
|
|
265,067 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from
operations |
|
|
(3,913 |
) |
|
|
36,904 |
|
|
|
18,259 |
|
|
|
|
|
|
|
51,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in
affiliates, net of tax |
|
|
43,700 |
|
|
|
|
|
|
|
|
|
|
|
(43,700 |
) |
|
|
|
|
Interest, net |
|
|
(21,221 |
) |
|
|
60 |
|
|
|
(226 |
) |
|
|
|
|
|
|
(21,387 |
) |
Other |
|
|
42 |
|
|
|
24 |
|
|
|
410 |
|
|
|
|
|
|
|
476 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
(expense) |
|
|
22,521 |
|
|
|
84 |
|
|
|
184 |
|
|
|
(43,700 |
) |
|
|
(20,911 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)before
income taxes |
|
|
18,608 |
|
|
|
36,988 |
|
|
|
18,443 |
|
|
|
(43,700 |
) |
|
|
30,339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes |
|
|
|
|
|
|
(4,449 |
) |
|
|
(7,282 |
) |
|
|
|
|
|
|
(11,731 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
18,608 |
|
|
$ |
32,539 |
|
|
$ |
11,161 |
|
|
$ |
(43,700 |
) |
|
$ |
18,608 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 11 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Three Months Ended June 30, 2008 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiary |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors |
|
|
Adjustments |
|
|
Total |
|
|
Revenues |
|
$ |
|
|
|
$ |
93,323 |
|
|
$ |
69,818 |
|
|
$ |
(6 |
) |
|
$ |
163,135 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct costs |
|
|
|
|
|
|
49,988 |
|
|
|
54,347 |
|
|
|
(6 |
) |
|
|
104,329 |
|
Depreciation |
|
|
|
|
|
|
11,834 |
|
|
|
3,391 |
|
|
|
|
|
|
|
15,225 |
|
Selling, general and
administrative |
|
|
1,514 |
|
|
|
10,647 |
|
|
|
2,681 |
|
|
|
|
|
|
|
14,842 |
|
Amortization |
|
|
11 |
|
|
|
1,052 |
|
|
|
8 |
|
|
|
|
|
|
|
1,071 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs
and expenses |
|
|
1,525 |
|
|
|
73,521 |
|
|
|
60,427 |
|
|
|
(6 |
) |
|
|
135,467 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from
operations |
|
|
(1,525 |
) |
|
|
19,802 |
|
|
|
9,391 |
|
|
|
|
|
|
|
27,668 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings in
affiliates, net of tax |
|
|
22,477 |
|
|
|
|
|
|
|
|
|
|
|
(22,477 |
) |
|
|
|
|
Interest, net |
|
|
(10,409 |
) |
|
|
(16 |
) |
|
|
(73 |
) |
|
|
|
|
|
|
(10,498 |
) |
Other |
|
|
15 |
|
|
|
(20 |
) |
|
|
374 |
|
|
|
|
|
|
|
369 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
(expense) |
|
|
12,083 |
|
|
|
(36 |
) |
|
|
301 |
|
|
|
(22,477 |
) |
|
|
(10,129 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)before
income taxes |
|
|
10,558 |
|
|
|
19,766 |
|
|
|
9,692 |
|
|
|
(22,477 |
) |
|
|
17,539 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes |
|
|
|
|
|
|
(2,938 |
) |
|
|
(4,043 |
) |
|
|
|
|
|
|
(6,981 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
10,558 |
|
|
$ |
16,828 |
|
|
$ |
5,649 |
|
|
$ |
(22,477 |
) |
|
$ |
10,558 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 11 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Six Months Ended June 30, 2008 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
Cash Flows from Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
18,608 |
|
|
$ |
32,539 |
|
|
$ |
11,161 |
|
|
$ |
(43,700 |
) |
|
$ |
18,608 |
|
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
23 |
|
|
|
25,314 |
|
|
|
6,577 |
|
|
|
|
|
|
|
31,914 |
|
Amortization and write-off of debt
issuance costs |
|
|
1,038 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,038 |
|
Stock based compensation |
|
|
4,385 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,385 |
|
Allowance for bad debts |
|
|
|
|
|
|
636 |
|
|
|
|
|
|
|
|
|
|
|
636 |
|
Equity earnings in affiliates |
|
|
(43,700 |
) |
|
|
|
|
|
|
|
|
|
|
43,700 |
|
|
|
|
|
Deferred taxes |
|
|
3,254 |
|
|
|
(114 |
) |
|
|
1,169 |
|
|
|
|
|
|
|
4,309 |
|
(Gain) on sale of property and
equipment |
|
|
|
|
|
|
(495 |
) |
|
|
(42 |
) |
|
|
|
|
|
|
(537 |
) |
Changes in operating assets and
liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Increase) in trade receivables |
|
|
|
|
|
|
(6,191 |
) |
|
|
(7,696 |
) |
|
|
|
|
|
|
(13,887 |
) |
(Increase) in inventories |
|
|
|
|
|
|
(3,086 |
) |
|
|
(1,412 |
) |
|
|
|
|
|
|
(4,498 |
) |
(Increase) decrease in prepaid
expenses and other current assets |
|
|
|
|
|
|
1,312 |
|
|
|
(1,490 |
) |
|
|
|
|
|
|
(178 |
) |
(Increase) decrease in other assets |
|
|
(4,897 |
) |
|
|
989 |
|
|
|
251 |
|
|
|
|
|
|
|
(3,657 |
) |
(Decrease) increase in trade
accounts payable |
|
|
|
|
|
|
(205 |
) |
|
|
8,872 |
|
|
|
|
|
|
|
8,667 |
|
Increase in accrued interest |
|
|
50 |
|
|
|
25 |
|
|
|
244 |
|
|
|
|
|
|
|
319 |
|
(Decrease) increase in accrued
expenses |
|
|
(1,605 |
) |
|
|
5,602 |
|
|
|
536 |
|
|
|
|
|
|
|
4,533 |
|
(Decrease) increase in accrued
salaries, benefits and payroll
taxes |
|
|
|
|
|
|
(143 |
) |
|
|
5,155 |
|
|
|
|
|
|
|
5,012 |
|
(Decrease) in other long- term
liabilities |
|
|
(31 |
) |
|
|
(56 |
) |
|
|
(162 |
) |
|
|
|
|
|
|
(249 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By (Used In)
Operating Activities |
|
|
(22,875 |
) |
|
|
56,127 |
|
|
|
23,163 |
|
|
|
|
|
|
|
56,415 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
(3,447 |
) |
|
|
|
|
|
|
(3,447 |
) |
Proceeds from sale of property and
equipment |
|
|
|
|
|
|
3,535 |
|
|
|
43 |
|
|
|
|
|
|
|
3,578 |
|
Purchase of property and equipment |
|
|
|
|
|
|
(34,968 |
) |
|
|
(39,695 |
) |
|
|
|
|
|
|
(74,663 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By (Used in)
Investing Activities |
|
|
(43,075 |
) |
|
|
(31,433 |
) |
|
|
(43,099 |
) |
|
|
3,075 |
|
|
|
(114,532 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 11 CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Six Months Ended June 30, 2008 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Allis-Chalmers |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
(Parent/ |
|
|
Subsidiary |
|
|
(Non- |
|
|
Consolidating |
|
|
Consolidated |
|
|
|
Guarantor) |
|
|
Guarantors |
|
|
Guarantors) |
|
|
Adjustments |
|
|
Total |
|
Cash Flows from Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable from affiliates |
|
|
55,290 |
|
|
|
|
|
|
|
|
|
|
|
(55,290 |
) |
|
|
|
|
Accounts payable to affiliates |
|
|
|
|
|
|
(55,290 |
) |
|
|
|
|
|
|
55,290 |
|
|
|
|
|
Note payable to affiliate |
|
|
|
|
|
|
|
|
|
|
3,075 |
|
|
|
(3,075 |
) |
|
|
|
|
Proceeds from exercises of options |
|
|
609 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
609 |
|
Tax benefit on stock-based
compensation plans |
|
|
72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72 |
|
Proceeds from long-term debt |
|
|
|
|
|
|
|
|
|
|
17,946 |
|
|
|
|
|
|
|
17,946 |
|
Net borrowing under line of credit |
|
|
10,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,000 |
|
Payments on long-term debt |
|
|
|
|
|
|
(2,914 |
) |
|
|
(1,188 |
) |
|
|
|
|
|
|
(4,102 |
) |
Debt issuance costs |
|
|
(21 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided By (Used
In) Financing Activities |
|
|
65,950 |
|
|
|
(58,204 |
) |
|
|
19,833 |
|
|
|
(3,075 |
) |
|
|
24,504 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash
equivalents |
|
|
|
|
|
|
(33,510 |
) |
|
|
(103 |
) |
|
|
|
|
|
|
(33,613 |
) |
Cash and cash equivalents at
beginning of period |
|
|
|
|
|
|
41,176 |
|
|
|
2,517 |
|
|
|
|
|
|
|
43,693 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end
of period |
|
$ |
|
|
|
$ |
7,666 |
|
|
$ |
2,414 |
|
|
$ |
|
|
|
$ |
10,080 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 12- 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 |
|
|
For the Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
29,473 |
|
|
$ |
68,653 |
|
|
$ |
73,923 |
|
|
$ |
136,556 |
|
Drilling and Completion |
|
|
67,792 |
|
|
|
69,818 |
|
|
|
146,938 |
|
|
|
132,879 |
|
Rental Services |
|
|
15,240 |
|
|
|
24,664 |
|
|
|
36,747 |
|
|
|
46,882 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
112,505 |
|
|
$ |
163,135 |
|
|
$ |
257,608 |
|
|
$ |
316,317 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
(10,277 |
) |
|
$ |
13,090 |
|
|
$ |
(11,490 |
) |
|
$ |
26,387 |
|
Drilling and Completion |
|
|
403 |
|
|
|
9,391 |
|
|
|
8,912 |
|
|
|
18,259 |
|
Rental Services |
|
|
588 |
|
|
|
9,266 |
|
|
|
4,536 |
|
|
|
15,488 |
|
General corporate |
|
|
(3,257 |
) |
|
|
(4,079 |
) |
|
|
(6,730 |
) |
|
|
(8,884 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(12,543 |
) |
|
$ |
27,668 |
|
|
$ |
(4,772 |
) |
|
$ |
51,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and Amortization: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
7,433 |
|
|
$ |
5,961 |
|
|
$ |
14,748 |
|
|
$ |
11,591 |
|
Drilling and Completion |
|
|
5,463 |
|
|
|
3,399 |
|
|
|
10,720 |
|
|
|
6,577 |
|
Rental Services |
|
|
7,395 |
|
|
|
6,795 |
|
|
|
15,299 |
|
|
|
13,464 |
|
General corporate |
|
|
77 |
|
|
|
141 |
|
|
|
159 |
|
|
|
282 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
20,368 |
|
|
$ |
16,296 |
|
|
$ |
40,926 |
|
|
$ |
31,914 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
4,028 |
|
|
$ |
9,390 |
|
|
$ |
8,060 |
|
|
$ |
23,817 |
|
Drilling and Completion |
|
|
39,069 |
|
|
|
21,165 |
|
|
|
43,708 |
|
|
|
39,694 |
|
Rental Services |
|
|
935 |
|
|
|
4,415 |
|
|
|
6,191 |
|
|
|
11,106 |
|
General corporate |
|
|
3 |
|
|
|
16 |
|
|
|
34 |
|
|
|
46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
44,035 |
|
|
$ |
34,986 |
|
|
$ |
57,993 |
|
|
$ |
74,663 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
40,622 |
|
|
$ |
88,959 |
|
|
$ |
102,823 |
|
|
$ |
172,942 |
|
Argentina |
|
|
52,871 |
|
|
|
69,809 |
|
|
|
115,654 |
|
|
|
132,450 |
|
Brazil |
|
|
10,012 |
|
|
|
|
|
|
|
20,778 |
|
|
|
|
|
Other international |
|
|
9,000 |
|
|
|
4,367 |
|
|
|
18,353 |
|
|
|
10,925 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
112,505 |
|
|
$ |
163,135 |
|
|
$ |
257,608 |
|
|
$ |
316,317 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 12 SEGMENT INFORMATION (Continued)
|
|
|
|
|
|
|
|
|
|
|
As of |
|
|
|
June 30, |
|
|
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 |
|
$ |
272,318 |
|
|
$ |
309,901 |
|
Drilling and Completion |
|
|
419,737 |
|
|
|
411,486 |
|
Rental Services |
|
|
333,565 |
|
|
|
360,376 |
|
General corporate |
|
|
77,901 |
|
|
|
33,288 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,103,521 |
|
|
$ |
1,115,051 |
|
|
|
|
|
|
|
|
Long Lived Assets: |
|
|
|
|
|
|
|
|
United States |
|
$ |
576,475 |
|
|
$ |
573,975 |
|
Argentina |
|
|
188,570 |
|
|
|
212,456 |
|
Brazil |
|
|
78,950 |
|
|
|
79,568 |
|
Other international |
|
|
43,828 |
|
|
|
23,814 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
887,823 |
|
|
$ |
889,813 |
|
|
|
|
|
|
|
|
NOTE 13 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.
26
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 41.
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, Bolivia 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. According to Baker Hughes, 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 Baker Hughes, the U.S. rig count was
943 as of July 24, 2009 compared to 1,957 one year earlier. 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 591 as of July 24, 2009 compared to 912 as of December 26, 2008 and 967 one
year earlier.
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.
27
Company Outlook
We believe that our revenue and operating income for our Oilfield Services and Rental Services
segment will continue to suffer throughout the remainder of 2009, due to the reduction of our
customers spending, the low price of natural gas and the resulting drop in the U.S. rig count. We
have already taken steps in 2009 to reduce costs, including laying off employees and closing
unprofitable operating locations. We have also attempted to convert our direct labor costs to a
variable job day-rate bonus structure, established a new customer account management system with
financial incentives for our sales force and executed on a strategy to deploy under-utilized assets
to the most attractive domestic and international markets. Even with these steps, our Oilfield
Services segment may continue to generate negative operating income in 2009 due to its reliance on
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 for the
remainder of 2009 will continue to be impacted by the decrease in the utilization of drilling rigs
in Argentina and one less available rig in Brazil due to a blow-out. We plan to redeploy rigs to
Brazil and other international locations. In addition, our two new domestic drilling rigs will
start operations in the third and fourth quarters of 2009 and we anticipate negative operating
income from that operation until we are able to achieve economies of scale by having both rigs
running at high utilization.
We expect to incur less general and administrative expenses in 2009 as we reduce our administrative
staff to reflect the decline in our activity. Our net interest expense is dependent upon our level
of debt and cash on hand, which are principally dependent on our capital expenditures and our cash
flows from operations. We anticipate our interest expense for the remainder of 2009 to decline as
we have repaid $74.8 million of our outstanding senior notes and all outstanding borrowings under
our revolving credit facility and have excess cash as a result of our backstopped rights offering
and private placement of preferred stock completed in June 2009. Offsetting some of those benefits
will be the interest on our new $25.0 million loan facility utilized to acquire two new drilling
rigs.
Demand for our services is dependent upon our customers capital spending plans. The capital
expenditures of our customers have been impacted by both the decrease in oil and natural gas
prices, which affects their cash flow and the decrease in the availability of capital resulting
from the recent banking and credit crisis. The slowdown in economic activity caused by the
recession has reduced demand for energy and resulted in lower oil and natural gas prices. 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
June 30, 2009, but further reserves may be necessary in 2009.
We continue to monitor the effect of the global economic downturn 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 reduced our planned capital spending significantly in 2009 compared to
2008. We believe that 2009 will be an extremely challenging year for our operations. We are
optimistic that our cost saving measures and the $125.6 million in gross equity proceeds received
in June 2009 from our backstopped rights offering and private placement of preferred stock, our
strategy of international growth, 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.
28
Comparison of Three Months Ended June 30, 2009 and 2008
Our revenues for the three months ended June 30, 2009 were $112.5 million, a decrease of 31.0%
compared to $163.1 million for the three months ended June 30, 2008. All of our operating segments
experienced a decline in revenue in the three months ended June 30, 2009 compared to the three
months ended June 30, 2008. Both our Oilfield Services segment and Rental Services segment have a
strong concentration in the U.S. domestic oil and natural gas market. Due to the decline in oil
and natural gas prices and drilling activity, we have experienced a significant deterioration in
both equipment utilization and pricing. Revenues in our Drilling and Completion segment declined
in spite of the contribution of $10.0 million in revenues during the three months ended June 30,
2009 from our December 2008 acquisition of BCH. Our Drilling and Completion revenues from
Argentina declined in the quarter ended June 30, 2009 due to decreased rig utilization and a
decrease in rig rates as a result of lower commodity prices.
Our direct costs for the three months ended June 30, 2009 decreased 16.4% to $87.2 million, or
77.5% of revenues, compared to $104.3 million, or 64.0%, of revenues for the three months ended
June 30, 2008. Our direct costs in our Oilfield Services and Rental Services segments decreased in
absolute dollars in the three months ended June 30, 2009 compared to the three months ended June
30, 2008, but our revenues in our Oilfield Services and Rental Services segments decreased faster
during the quarter than the reduction in direct costs. Our Oilfield Services segment revenues for
the three months ended June 30, 2009 decreased 57.1% from revenues for the three months ended June
30, 2008, while the direct costs decreased 40.5% 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. In addition, we had $868,000 of expenses recorded during the three
months ended June 30, 2009 related to severance payments, the closing of unprofitable locations and
downsizing other locations. Our Oilfield Services segment has also been impacted by pricing
pressure that decreases revenues but has no impact on direct costs.
Our Rental Services segment revenues for the three months ended June 30, 2009 decreased 38.2% from
revenues in the Rental Services segment for the three months ended June 30, 2008, while the direct
costs decreased 21.7% 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. Direct costs in our Drilling and Completion segment increased $2.0 million for the three
months ended June 30, 2009 compared to three months ended June 30, 2008. Direct costs related to
our December 2008 acquisition of BCH were $6.6 million during the three months ended June 30, 2009
and were offset by reduced costs as a result of reduced activity in our Drilling and Completion
operation in Argentina. Our Drilling and Completion segment revenues for the three months ended
June 30, 2009 decreased 2.9% from revenues for the three months ended June 30, 2008, while the
direct costs increased 3.6% over that same period. This unfavorable variance is primarily
attributed to lower utilization of our drilling and service rigs during the three months ended June
30, 2009 compared to the same period of the prior year. Additionally, workforce reductions in
response to market conditions are difficult to implement in the labor environment in Argentina.
Depreciation expense increased 26.0% to $19.2 million for the three months ended June 30, 2009 from
$15.2 million for the three months ended June 30, 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 17.0% for the second quarter of 2009, compared to
9.3% for the second 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 expense in the three months ended June 30, 2009.
Selling, general and administrative expense was $15.5 million for the three months ended June 30,
2009 compared to $14.8 million for the three months ended June 30, 2008. Selling, general and
administrative expense increased due to additional reserves for bad debts which were partially
offset by cost reduction steps that were made in the three months ended June 30, 2009 in response
to market conditions and a decrease related to the amortization of share-based compensation
arrangements. During the three months ended June 30, 2009, we recorded bad debt expense of $3.2
million compared to $369,000 for the three months ended June 30, 2008. Selling, general and
administrative expense includes share-based compensation expense of $1.3 million in the second
quarter of 2009 and $1.8 million in the second quarter of 2008. As a percentage of revenues,
selling, general and administrative expenses were 13.8% for the three months ended June 30, 2009
compared to 9.1% for the same period in the prior year.
During the three months ended June 30, 2009, we recorded a $1.9 million loss on an asset
disposition from the total loss of a rig from a blowout in our Drilling and Completion segment.
The anticipated insurance proceeds for the loss are not sufficient to cover the book value of the
rig and related assets.
29
Amortization expense was $1.2 million for the three months ended June 30, 2009 compared to $1.1
million for the three months ended June 30, 2008.
We had a $12.5 million loss from operations for the three months ended June 30, 2009, compared to
$27.7 million in income from operations for the three months ended June 30, 2008, for a total
decrease of $40.2 million. The loss from operations in the second quarter of 2009 is due to the
increase in direct costs and depreciation as a percentage of revenues, as revenues decreased more
quickly than our cost reductions. The three months ended June 30, 2009 was also negatively
affected by an additional $2.8 million of bad debt reserves compared to the three months ended June
30, 2008, a $1.9 million loss on an asset disposition and $1.6 million of restructuring costs.
Our interest expense was $13.2 million for the three months ended June 30, 2009, compared to $12.0
million for the three months ended June 30, 2008. During 2009, we increased borrowings under our
revolving credit facility. On June 29, 2009 we prepaid the then $35.0 million outstanding loan
balance under our revolving credit facility, except for $5.1 million in outstanding letters of
credit, with proceeds from the $125.6 million equity issuances. This compares to an outstanding
loan balance of $10.0 million at June 30, 2008 under our revolving credit facility. 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 which was reduced to $16.2 million at June 30,
2009. Interest expense includes amortization expense of debt issuance costs of $596,000 and
$519,000 for the three months ended June 30, 2009 and 2008, respectively.
Our interest income was $9,000 for the three months ended June 30, 2009, compared to $1.5 million
for the three months ended June 30, 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.
During the three months ended June 30, 2009, we recorded a gain of $26.4 million as a result of a
tender offer that we completed on June 29, 2009. We purchased $30.6 million aggregate principal of
our 9.0% senior notes and $44.2 million aggregate principal of 8.5% senior notes for approximately
$46.4 million. We also wrote-off $1.5 million of debt issuance costs related to the retired notes
and we incurred approximately $466,000 in expenses related to the transactions.
Our income tax expense for the three months ended June 30, 2009 was $215,000, compared to an income
tax expense of $7.0 million, or 39.8% of our net income before income taxes for 2008. The income
tax expense recorded for the three months ended June 30, 2009 exceeded our income before income
taxes for that same period. One of our international subsidiaries is generating a tax net
operating loss and the future utilization of such net operation loss for tax purposes is uncertain.
Our U.S. effective tax rate was 22.7% for the three months ended June 30, 2009, compared to 37.4%
for the same period in the prior year. Due to the gain on debt extinguishment, we have pre-tax
income from our U.S. operations in the three months ended June 30, 2009, but the tax computed on
that income was offset by a change in effective rate for the year from 33.0% at March 31, 2009 to
34.0% at June 30, 2009 being applied to our cumulative net loss from U.S. operations. Our
international effective tax rate was 4.3% for the three months ended June 30, 2009, compared to
41.7% for the same period in the prior year due to the impact of foreign currency losses and the
increase in the portion of income in the second quarter of 2009 that was generated in non-taxable
jurisdictions.
We had a net loss of $90,000 for the three months ended June 30, 2009, compared to net income of
$10.6 million for the three months ended June 30, 2008 due to the foregoing reasons.
30
The following table compares revenues and income (loss) from operations for each of our business
segments for the quarter ended June 30, 2009 and 2008. Income (loss) from operations consists of
our revenues and the loss on an asset disposition less direct costs, selling, general and
administrative expenses, depreciation and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
Income (Loss) from Operations |
|
|
|
Three Months Ended |
|
|
Three Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
Change |
|
|
2009 |
|
|
2008 |
|
|
Change |
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
29,473 |
|
|
$ |
68,653 |
|
|
$ |
(39,180 |
) |
|
$ |
(10,277 |
) |
|
$ |
13,090 |
|
|
$ |
(23,367 |
) |
Drilling and Completion |
|
|
67,792 |
|
|
|
69,818 |
|
|
|
(2,026 |
) |
|
|
403 |
|
|
|
9,391 |
|
|
|
(8,988 |
) |
Rental Services |
|
|
15,240 |
|
|
|
24,664 |
|
|
|
(9,424 |
) |
|
|
588 |
|
|
|
9,266 |
|
|
|
(8,678 |
) |
General corporate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,257 |
) |
|
|
(4,079 |
) |
|
|
822 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
112,505 |
|
|
$ |
163,135 |
|
|
$ |
(50,630 |
) |
|
$ |
(12,543 |
) |
|
$ |
27,668 |
|
|
$ |
(40,211 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services
Revenues for our Oilfield Services segment were $29.5 million for the three months ended June 30,
2009, a decrease of 57.1% compared to $68.7 million in revenues for the three months ended June 30,
2008. Income from operations decreased $23.4 million and resulted in loss from operations of $10.3
million in the second quarter of 2009 compared to income from operations of $13.1 million in the
second quarter of 2008. Our Oilfield Services segment revenues and operating income for the second
quarter of 2009 decreased compared to the second quarter of 2008 due to weak market conditions that
resulted in reduced demand for our services and a significant deterioration in the pricing for our
services. During the three months ended June 30, 2009, we incurred $868,000 of costs related to
closing unprofitable locations and downsizing other locations in our Oilfield Services segment. In
addition, we increased our bad debt reserve by recording $2.4 million of bad debt expense for the
Oilfield Services segment during the three months ended June 30, 2009 as a result of the decreased
oil and natural gas prices and the financial difficulties that some of our customers are facing.
Or bad debt expense for the three months ended June 30, 2008 was only $219,000. Depreciation and
amortization expense for the Oilfield Services segment increased by $1.5 million or 24.7% in the
second quarter of 2009 compared to the second 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 June 30, 2009 for the Drilling and Completion segment were $67.8
million, a decrease of 2.9% compared to $69.8 million in revenues for the quarter ended June 30,
2008. Income from operations decreased to $403,000 in the second quarter of 2009 compared to $9.4
million in the second quarter of 2008. This reduction was due to: (1) an increase of $2.1 million,
or 60.7%, in depreciation and amortization in the second quarter of 2009; (2) a $1.9 million
non-cash loss recorded in the three months ended June 30, 2009 on a rig destroyed in a blow-out;
(3) reduced rig utilization and rig rates in Argentina during the three months ended June 30, 2009;
(4) increased labor and other costs in Argentina during the three months ended June 30, 2009; and
(5) $329,000 of costs incurred to consolidate operating locations in Brazil during the three months
ended June 30, 2009. 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 for the second quarter of 2009 included $10.0 million of revenue generated from the
acquisition of BCH at the end of 2008.
Rental Services
Revenues for the quarter ended June 30, 2009 for the Rental Services segment were $15.2 million, a
decrease from $24.7 million in revenues for the quarter ended June 30, 2008. Income from
operations decreased to $588,000 in the second quarter of 2009 compared to $9.3 million in the
second quarter of 2008. Our Rental Services segment revenues and operating income for the second
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. The decrease in income from operations in the second quarter of 2009 is also
due to $800,000 of bad debt expense to increase the bad debt reserve for Rental Services segment
customers who are facing financial difficulties, and $235,000 of costs related to closing a rental
yard and reducing our workforce. Bad debt expense for the second quarter of 2008 was only
$150,000. In addition, depreciation and amortization expense for our Rental Services segment
increased $600,000, or 8.8%, in the second quarter of 2009 compared to the second quarter of 2008
due to capital expenditures made during 2008.
31
General Corporate
General corporate expenses decreased $0.8 million to $3.3 million for the three months ended June
30, 2009 compared to $4.1 million for the three months ended June 30, 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. Share-based
compensation expense included in general corporate expense was $1.0 million in the second quarter
of 2009 compared to $1.5 million in the second quarter of 2008.
Comparison of Six Months Ended June 30, 2009 and 2008
Our revenues for the six months ended June 30, 2009 were $257.6 million, a decrease of 18.6%
compared to $316.3 million for the six months ended June 30, 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 offset by lower rig
utilization and pricing in our Drilling and Completion operation conducted in Argentina. The
Drilling and Completion segment generated $146.9 million in revenues for the six months ended June
30, 2009 compared to $132.9 million for the six months ended June 30, 2008. BCH generated $20.8
million of revenues for the six months ended June 30, 2009. Our Oilfield Services segment revenues
decreased to $73.9 million for the six months ended June 30, 2009 compared to $136.6 million for
the six months ended June 30, 2008. Revenues for our Rental Services segment decreased to $36.7
million for the six months ended June 30, 2009 compared to $46.9 million for the six months ended
June 30, 2008. The decline in oil and natural gas prices and the resulting decrease in drilling
activity has caused a significant deterioration in both equipment utilization and pricing for our
Oilfield Services and Rental Services segments.
Our direct costs for the six months ended June 30, 2009 decreased 6.1% to $190.4 million, or 73.9%
of revenues, compared to $202.8 million, or 64.1%, of revenues for the six months ended June 30,
2008. Our direct costs in our Oilfield Services and Rental Services segments decreased in absolute
dollars in the six months ended June 30, 2009 compared to the six months ended June 30, 2008, but
our revenues in our Oilfield Services and Rental Services segments decreased faster during that
same period than the reduction in direct costs. Our Oilfield Services segment revenues for the six
months ended June 30, 2009 decreased 45.9% from revenues for the six months ended June 30, 2008,
while the direct costs decreased 31.3% 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. In addition, we had $1.0 million of expenses recorded during the six
months ended June 30, 2009 related to severance payments, the closing of unprofitable locations and
downsizing other locations. Our Oilfield Services segment has also been impacted by pricing
pressure that decreases revenues but has no impact on direct costs.
Our Rental Services segment revenues for the six months ended June 30, 2009 decreased 21.6% from
revenues in the Rental Services segment for the six months ended June 30, 2008, while the direct
costs decreased 3.7% 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. Direct costs in our Drilling and Completion segment increased $15.2 million for the six
months ended June 30, 2009 compared to six months ended June 30, 2008. Direct costs related to our
December 2008 acquisition of BCH were $13.4 million during the six months ended June 30, 2009. Our
Drilling and Completion segment revenues for the six months ended June 30, 2009 increased 10.6%
from revenues for the six months ended June 30, 2008, while the direct costs increased 14.7% over
that same period. This unfavorable variance is primarily attributed to lower utilization of our
drilling and service rigs during the six months ended June 30, 2009 compared to the same period of
the prior year. Additionally, workforce reductions in response to market conditions are difficult
to implement in the labor environment in Argentina.
Depreciation expense increased 29.7% to $38.6 million for the six months ended June 30, 2009 from
$29.7 million for the six months ended June 30, 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 15.0% for the first six months of 2009, compared
to 9.4% for the first six months 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 $1.8 million of depreciation expense in the six months ended June 30, 2009.
32
Selling, general and administrative expense was $29.2 million for the six months ended June 30,
2009 compared to $30.3 million for the six months ended June 30, 2008. Selling, general and
administrative expense decreased primarily due to cost reduction steps that were made in the six
months ended June 30, 2009 in response to market conditions, and a decrease related to the
amortization of share-based compensation arrangements, offset in part by additional bad debt
expense. During the six months ended June 30, 2009, we recorded bad debt expense of $3.6 million
compared to $636,000 for the six months ended June 30, 2008. Selling, general and administrative
expense includes share-based compensation expense of $2.3 million in the six months ended June 30,
2009 and $4.4 million in the six months ended June 30, 2008. As a percentage of revenues, selling,
general and administrative expenses were 11.3% for the six months ended June 30, 2009 compared to
9.6% for the same period in the prior year.
During the six months ended June 30, 2009, we recorded a $1.9 million loss on an asset disposition
from the total loss of a rig from a blow-out in our Drilling and Completion segment. The
anticipated insurance proceeds for the loss are not sufficient to cover the book value of the rig
and related assets.
Amortization expense was $2.4 million for the six months ended June 30, 2009 compared to $2.2
million for the six months ended June 30, 2008.
We had a $4.8 million loss from operations for the six months ended June 30, 2009, compared to
$51.3 million in income from operations for the six months ended June 30, 2008, for a total
decrease of $56.1 million. The loss from operations for the six months ended June 30, 2009 is due
to the increase in direct costs and depreciation as a percentage of revenues, as revenues decreased
more quickly than our cost reductions. The six months ended June 30, 2009 was also negatively
affected by an additional $2.9 million of bad debt expense compared to the six months ended June
30, 2008, a $1.9 million loss on an asset disposition and $1.8 million of restructuring costs.
Our interest expense was $26.7 million for the six months ended June 30, 2009, compared to $24.1
million for the six months ended June 30, 2008. During 2009, we increased the borrowings under our
revolving credit facility. On June 29, 2009 we prepaid the then $35.0 million outstanding loan
balance under our revolving credit facility, except for $5.1 million in outstanding letters of
credit, with proceeds from our $125.6 million in equity issuances. This compared to an outstanding
balance of $10.0 million at June 30, 2008 under our revolving credit facility. 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 which was reduced to $16.2 million at June 30, 2009.
Interest expense includes amortization expense of debt issuance costs of $1.2 million and $1.0
million for the six months ended June 30, 2009 and 2008, respectively.
Our interest income was $14,000 for the six months ended June 30, 2009, compared to $2.7 million
for the six months ended June 30, 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.
During the six months ended June 30, 2009, we recorded a gain of $26.4 million as a result of a
tender offer that we completed on June 29, 2009. We purchased $30.6 million aggregate principal of
our 9.0% senior notes and $44.2 million aggregate principal of 8.5% senior notes for approximately
$46.4 million. We also wrote-off $1.5 million of debt issuance costs related to the retired notes
and we incurred approximately $466,000 in expenses related to the transactions.
Our benefit for income taxes for the six months ended June 30, 2009 was $2.7 million, or 50.0% of
our net loss before income taxes, compared to an income tax expense of $11.7 million, or 38.7% 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 34.0% for the six months
ended June 30, 2009, compared to 37.4% 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 international operations was 20.8% for the six months ended June 30, 2009, compared
to 39.5% for the same period in the prior year due to the impact of foreign currency losses and the
increase in the portion of income in 2009 that was generated in non-taxable jurisdictions.
We had a net loss of $2.7 million for the six months ended June 30, 2009, compared to net income of
$18.6 million for the six months ended June 30, 2008 due to the foregoing reasons.
33
The following table compares revenues and income (loss) from operations for each of our business
segments for the six months ended June 30, 2009 and 2008. Income (loss) from operations consists
of our revenues and the loss on an asset disposition less direct costs, selling, general and
administrative expenses, depreciation and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
Income (Loss) from Operations |
|
|
|
Six Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
Change |
|
|
2009 |
|
|
2008 |
|
|
Change |
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services |
|
$ |
73,923 |
|
|
$ |
136,556 |
|
|
$ |
(62,633 |
) |
|
$ |
(11,490 |
) |
|
$ |
26,387 |
|
|
$ |
(37,877 |
) |
Drilling and Completion |
|
|
146,938 |
|
|
|
132,879 |
|
|
|
14,059 |
|
|
|
8,912 |
|
|
|
18,259 |
|
|
|
(9,347 |
) |
Rental Services |
|
|
36,747 |
|
|
|
46,882 |
|
|
|
(10,135 |
) |
|
|
4,536 |
|
|
|
15,488 |
|
|
|
(10,952 |
) |
General corporate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,730 |
) |
|
|
(8,884 |
) |
|
|
2,154 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
257,608 |
|
|
$ |
316,317 |
|
|
$ |
(58,709 |
) |
|
$ |
(4,772 |
) |
|
$ |
51,250 |
|
|
$ |
(56,022 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oilfield Services
Revenues for our Oilfield Services segment were $73.9 million for the six months ended June 30,
2009, a decrease of 45.9% compared to $136.6 million in revenues for the six months ended June 30,
2008. Income from operations decreased $37.9 million and resulted in loss from operations of $11.5
million in the first six months of 2009 compared to income from operations of $26.4 million in the
first six months of 2008. Our Oilfield Services segment revenues and operating income for the six
months ended June 30, 2009 decreased compared to the six months ended June 30, 2008 due to weak
market conditions that resulted in reduced demand for our services and a significant deterioration
in the pricing for our services. During the six months ended June 30, 2009, we incurred $1.0
million of costs related to closing unprofitable locations and downsizing other locations in our
Oilfield Services segment. In addition, we increased our bad debt reserve by recording $2.6
million of bad debt expense for the Oilfield Services segment during the six months ended June 30,
2009 as a result of the decreased oil and natural gas prices and the financial difficulties that
some of our customers are facing. Our bad debt expense recorded in the six months ended June 30,
2008 for the Oilfield Services segment was only $432,000. Depreciation and amortization expense
for the Oilfield Services segment increased by $3.2 million or 27.2% in the first six months of
2009 compared to the same period 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 six months ended June 30, 2009 for the Drilling and Completion segment were $146.9
million, an increase of 10.6% compared to $132.9 million in revenues for the six months ended June
30, 2008. Income from operations decreased to $8.9 million in the first six months of 2009
compared to $18.3 million for the first six months of 2008. This reduction was due to: (1) an
increase of $4.1 million, or 63.0%, in depreciation and amortization in the first half of 2009; (2)
a $1.9 million non-cash loss recorded in the six months ended June 30, 2009 on a rig destroyed in a
blow-out; (3) reduced rig utilization and rig rates in Argentina during the six months ended June
30, 2009; (4) increased labor and other costs in Argentina during the six months ended June 30,
2009; and (5) $329,000 of costs incurred to consolidate operating locations in Brazil during the
six months ended June 30, 2009. 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 for the first six months of 2009 included $20.8 million of revenue
generated from the acquisition of BCH at the end of 2008.
34
Rental Services
Revenues for the six months ended June 30, 2009 for the Rental Services segment were $36.7 million,
a decrease from $46.9 million in revenues for the six months ended June 30, 2008. Income from
operations decreased to $4.5 million in the first six months of 2009 compared to $15.5 million in
the first six months of 2008. Our Rental Services segment revenues and operating income for the
first half 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. The decrease in income from operations in the six months ended June
30, 2009 is also due to a $950,000 increase to the bad debt expense for Rental Services segment
customers who are facing financial difficulties, and $237,000 of costs related to closing a rental
yard and reducing our workforce. Our bad debt expense recorded in the six months ended June 30,
2008 for the Rental Services segment was only $204,000. In addition, depreciation and amortization
expense for our Rental Services segment increased $1.8 million or 13.6%, in the first six months of
2009 compared to the first six months 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 $2.2 million to $6.7 million for the six months ended June 30,
2009 compared to $8.9 million for the six months ended June 30, 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. Share-based compensation expense
included in general corporate was $1.8 million in the six months ended June 30, 2009 compared to
$3.7 million in the six months ended June 30, 2008.
Liquidity
In June 2009, we strengthened our balance sheet by raising approximately $125.6 million in gross
proceeds from the sale of common stock and a newly issued series of preferred stock. The
transactions were effected through a common stock rights offering to our existing stockholders, the
sale of common stock to Lime Rock through its backstop commitment of the rights offering, and the
sale of convertible perpetual preferred stock to Lime Rock. Approximately $46.4 million of the
proceeds were used to purchase an aggregate of $74.8 million principal amount of our existing
senior notes, approximately $35.0 million was used to repay all the borrowings under our revolving
bank credit facility due 2012, except for $5.1 million in outstanding letters of credit, and we
expect to use the remainder to repay additional debt and for general corporate purposes.
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 June 30, 2009, we had $84.9 million available for
borrowing under our amended and restated revolving credit facility. Our cash on hand and cash
flows from operations are expected to be our primary source of liquidity in fiscal 2009. We had
cash and cash equivalents of $59.4 million at June 30, 2009 compared to $6.9 million at December
31, 2008.
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 2009 and the resulting decrease in demand for our services
adversely impacts our ability to maintain or meet such financial ratios. We believe that the
$125.6 million in gross equity proceeds received in June 2009 has significantly improved our
liquidity and decreased our reliance on our revolving credit facility. We utilized a portion of
the equity proceeds to prepay of all borrowings under our revolving credit agreement, except for
the $5.1 million of outstanding letters of credit, and maintained $59.4 million of cash on hand as
of June 30, 2009. We do not plan any new borrowings under the revolving credit facility in the
near future.
35
Operating Activities
During the six months ended June 30, 2009, our operating activities provided $43.0 million in cash.
Our net loss for the six months ended June 30, 2009 was $2.7 million. Non-cash expenses totaled
$16.8 million during the first six months of 2009 consisting of $40.9 million of depreciation and
amortization, $2.3 million for share based compensation expense, $1.2 million in amortization of
debt issuance costs, $3.6 million related to increases to the allowance for doubtful accounts
receivables, a $1.9 million loss on a rig destroyed in a blow-out, less $26.4 million on the gain
from debt extinguishment, $6.1 million for deferred income taxes related to timing differences and
$602,000 on the gain from asset disposals.
During the six months ended June 30, 2009, changes in operating assets and liabilities provided
$28.8 million in cash, principally due to a decrease in accounts receivable of $55.3 million, a
decrease in prepaid expenses and other current assets of $7.4 million and a decrease in inventory
of $2.5 million, offset in part by a decrease in accounts payable of $27.2 million, a decrease in
accrued interest of $3.0 million, a decrease in accrued expenses of $5.8 million. Accounts
receivable, inventory, accounts payable and accrued expenses decreased primarily due to the drop in
our activity in the first six months of 2009. The decrease in prepaid expense and other current
assets was the result of tax refunds received. The decrease in accrued interest relates to the
semi-annual payment of interest on our senior notes. The decrease in accrued expenses related
primarily to the payment of a $3.0 million earn-out in conjunction with the acquisition of
substantially all of the assets of Diamondback Oilfield Services, Inc., as well as to the drop in
our activity for the first six months of 2009.
During the six months ended June 30, 2008, our operating activities provided $56.4 million in cash.
Net income for the six months ended June 30, 2008 was $18.6 million. Non-cash expenses totaled
$41.7 million during the first six months of 2008 consisting of $31.9 million of depreciation and
amortization, $4.3 million for deferred income taxes related to timing differences, $1.0 in
amortization of debt issuance costs, $4.4 million from the expensing of stock based compensation,
$636,000 related to increases to the allowance for doubtful accounts receivables, less $537,000 on
the gain from asset disposals.
During the six months ended June 30, 2008, changes in operating assets and liabilities used $3.9
million in cash, principally due to an increase of $13.9 million in accounts receivable, an
increase of $4.5 million in inventories, an increase of $3.7 million in other assets, offset in
part by an increase of $8.7 million in accounts payable, an increase of $5.0 million in accrued
salaries, benefits and payroll taxes and an increase of $4.5 million in accrued expenses. Accounts
receivable increased primarily due to the increase in our revenues in the first six months of 2008.
The increase in inventories is related to the additional supplies needed to support our increasing
rig and coiled tubing fleets. The increase in other assets primarily relates to $2.5 million of
interest income on our $40.0 million note receivable from BCH Ltd. and $2.2 million of costs
incurred to date on our proposed acquisition of Bronco Drilling Company, Inc., which terminated in
August 2008. The increase in accounts payable can be attributed to additional expenses related to
the growth of our Drilling and Completion segments rig fleet. The increase in accrued salaries,
benefits and payroll taxes is primarily related to a retroactive pay increase granted to our
Drilling and Completion segments workers based in Argentina due to labor negotiations. The
increase in accrued expenses is primarily related to an additional operational activities and new
rig purchases in our Drilling and Completion segment and in our Oilfield Services segment.
Investing Activities
During the six months ended June 30, 2009, we used $41.3 million in investing activities,
consisting of $58.0 million for capital expenditures, offset by a decrease of $10.0 million in
other assets and $6.7 million of proceeds from equipment sales Included in the $58.0 million for
capital expenditures was $8.1 million for our Oilfield Services segment, $34.8 million for our two
domestic drilling rigs and $8.9 million for additional equipment in our Drilling and Completion
segment and $6.2 million for drill pipe and other equipment used in our Rental Services segment.
The decrease in other assets was primarily due to the conversion of $9.4 million of deposits on
equipment purchases into capital expenditures for the drilling rigs and assets used in our
directional drilling services. A majority of our equipment sales relate to items lost in hole or
damaged beyond repair by our customers. We also transferred $1.3 million of rental assets as
part of our investment into our Saudi Arabia joint venture in a non-cash transaction.
During the six months ended June 30, 2008, we used $114.5 million in investing activities,
consisting of a $74.7 million for capital expenditures, $40.0 million convertible subordinated
secured note from BCH Ltd, $3.4 million for deposits on equipment purchases for our Drilling and
Completion segment, offset by $3.6 million of proceeds from equipment sales. Included in the $74.7
million for capital expenditures was $23.8 million for our Oilfield Services segment, including
additional casing and tubing equipment and coiled tubing support equipment, $39.7 million for
additional equipment in our Drilling and Completion segment and $11.1 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.
36
Financing Activities
During the six months ended June 30, 2009, financing activities provided $50.8 million in cash. We
raised $120.3 million net of expenses from the issuance of common and preferred stock, and borrowed
$25.0 million under a loan facility to acquire two drilling rigs, offset in part by repayments of
$57.4 million of long-term debt and a net repayment on our revolving credit facility of $36.5
million. The repayments of long-term debt consisted of $46.4 million on the senior notes as a
result of a tender offer and $11.0 million of scheduled debt repayment including prepayment on our
BCH loan facility. We also incurred $644,000 in debt issuance costs consisting of $513,000 on the
revolving credit facility, primarily to modify our loan covenants, and $131,000 on the rig
financing agreement. In addition, we financed our renewal of $2.4 million in insurance policy
premiums in non-cash transactions.
During the six months ended June 30, 2008, financing activities provided $24.5 million in cash. We
received $10.0 million from net borrowings under our revolving line of credit and an additional
$17.9 million in proceeds from long-term debt and repaid $4.1 million in borrowings under long-term
debt facilities. Proceeds from the additional $17.9 million in long-term borrowing were used for a
portion of the purchase price of the new drilling and service rigs ordered for our Drilling and
Completion segment. We also financed our renewal of $2.8 million in insurance policy premiums in a
non-cash transaction. The $4.1 million of repayment of long-term debt facilities were scheduled
repayments. We also received $609,000 in proceeds from the exercise of options and warrants.
At June 30, 2009, we had $498.8 million in outstanding indebtedness, of which $483.2 million was
long-term debt and $15.6 million is due within one year.
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. On June 29, 2009, we closed on a tender offer in
which we purchased $30.6 million aggregate principal of our 9.0% senior notes for a total
consideration of $650 per $1,000 principal amount.
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 June 29, 2009, we closed on a tender offer in which
we purchased $44.2 million aggregate principal of our 8.5% senior notes for a total consideration
of $600 per $1,000 principal amount.
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 June 30, 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. As of June 30, 2009, we had no borrowings under the facility
and at December 31, 2008 we had $36.5 million of borrowings outstanding. Availability under the
facility was reduced by outstanding letters of credit of $5.1 million and $5.8 million at June 30,
2009 and December 31, 2008, respectively. The credit agreement loan rates are based on prime or
LIBOR plus a margin. The weighted average interest rate was 4.6% at December 31, 2008.
37
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 3.3% and 5.1% as of June 30, 2009 and December 31, 2008, respectively. The bank
loans are denominated in U.S. dollars and the outstanding amount due as of June 30, 2009 and
December 31, 2008 was $1.8 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. 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
June 30, 2009 and December 31, 2008. The bank loan rates are based on LIBOR plus a margin. The
weighted average interest rate was 5.5% and 6.9% at June 30, 2009 and December 31, 2008,
respectively. The bank loans are denominated in U.S. dollars and the outstanding amount as of June
30, 2009 and December 31, 2008 was $23.0 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 June
30, 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 June 30, 2009 and December 31, 2008, the
outstanding amount of the loan was $16.2 million and $22.1 million and the interest rate was 3.8%
and 6.0%, respectively.
On May 22, 2009, we drew down $25.0 million on a new term loan credit facility with a financial
institution. The facility was utilized to fund a portion of the purchase price of two new drilling
rigs. The loan is secured by the equipment. The facility is repayable in quarterly installments
of approximately $1.4 million of principal and interest and matures in May 2015. The loan bears
interest at a fixed rate of 9.0%. At June 30, 2009, the outstanding amount of the loan was $25.0
million.
Notes payable
In connection with the acquisition of Rogers, we issued to the seller a note in the amount of
$750,000. The note bore interest at 5.0% and was paid in full in April 2009 in accordance with its
terms.
In 2000, we compensated directors, including current director Robert Nederlander, who served on the
board of directors from 1989 to June 30, 1999 without compensation, by issuing promissory notes
totaling $325,000. The notes bore interest at the rate of 5.0%. As of June 30, 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 $21,000 and $991,000 at June 30, 2009 and December 31, 2008,
respectively. In April 2009 and June 2009, we obtained insurance premium financings in the
aggregate amount of $2.4 million with a fixed average weighted interest rate of 4.9%. Under terms
of the agreements, the amount outstanding is paid over 10 and 11 month repayment schedules. The
outstanding balance of these notes was approximately $2.0 million as of June 30, 2009.
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 $524,000 at June 30, 2009 and
$779,000 at December 31, 2008.
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 June 30, 2009, we had a $90.0 million revolving line of credit with a maturity of
April 2012. At June 30, 2009, we had no borrowings on the facility but we had $5.1 million in
outstanding letters of credit.
38
Capital Resources
We have reduced our planned capital spending for 2009 compared to 2008. We currently expect to
spend a total of approximately $25.0 million of capital expenditures for the remainder of 2009.
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.
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 six months ended June 30, 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 position or results of
operations.
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 position or
results of operations.
In April 2008, the FASB issued FASB Staff Position Statement of Financial Accounting Standards No.
142-3, Determination of the Useful Life of Intangible Assets, or FSP SFAS No. 142-3. FSP SFAS No.
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 Statement of Financial
Accounting Standards No. 142, Goodwill and Other Intangible Assets, or SFAS No. 142. The objective
of FSP SFAS No. 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 No. 142-3 is
effective for fiscal years beginning after December 15, 2008. We adopted FSP SFAS No. 142-3 on
January 1, 2009 and there was no impact on our financial position or results of operations.
39
In April 2009, the FASB issued FASB Staff Position Statement of Financial Accounting Standards No.
141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That
Arise from Contingencies, or FSP SFAS No. 141(R)-1. FSP SFAS No. 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 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 SFAS No. 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 No. 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 No. 141(R)-1 on January 1, 2009
and there was no impact on our financial position or results of operations.
In April 2009, the FASB issued FASB Staff Position Statement of Financial Accounting Standards No.
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 No. 157-4.
FSP SFAS No. 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 No. 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 adopted the provisions of FSP SFAS No. 157-4 on
April 1, 2009 and there was no impact on our financial position or results of operations.
In April 2009, the FASB issued FASB Staff Position Statement of Financial Accounting Standards No.
107-1 and Accounting Principles Board Opinion No. 28-1, Interim Disclosures about Fair Value of
Financial Instruments or FSP SFAS 107-1 and APB 28-1. FSP SFAS No. 107-1 and APB No. 28-1 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 No. 107-1 and
APB No. 28-1 is effective for interim periods ending after June 15, 2009. We adopted the
additional disclosure requirements in our June 30, 2009 financial statements and there was no
impact on our financial position or results of operations.
In May 2009, the FASB issued Statement of Financial Accounting Standards No. 165, Subsequent
Events, or SFAS No. 165. SFAS No. 165 establishes general standards of accounting for and
disclosure of events that occur after the balance sheet date but before financial statements are
issued or are available to be issued. We adopted SFAS No. 165 for the period ending June 30, 2009,
which did not have an impact on our financial position or results of operations.
In June 2009, the FASB issued Statement of Financial Accounting Standards No. 167, Amendments to
FASB Interpretation No. 46(R), or SFAS No. 167. SFAS No. 167 amends FASB Interpretation No. 46(R),
Consolidation of Variable Interest Entities for determining whether an entity is a variable
interest entity (VIE) and requires an enterprise to perform an analysis to determine whether the
enterprises variable interest or interests give it a controlling financial interest in a VIE.
Under SFAS No. 167, an enterprise has a controlling financial interest when it has (i) the power to
direct the activities of a VIE that most significantly impact the entitys economic performance and
(ii) the obligation to absorb losses of the entity or the right to receive benefits from the entity
that could potentially be significant to the VIE. SFAS No. 167 also requires an enterprise to
assess whether it has an implicit financial responsibility to ensure that a VIE operates as
designed when determining whether it has power to direct the activities of the VIE that most
significantly impact the entitys economic performance. SFAS No. 167 also requires ongoing
assessments of whether an enterprise is the primary beneficiary of a VIE, requires enhanced
disclosures and eliminates the scope exclusion for qualifying special-purpose entities. SFAS No.
167 is effective for annual reporting periods beginning after November 15, 2009. We are currently
evaluating the impact the adoption of SFAS No. 167 will have on our financial position and
operating results.
40
In June 2009, the FASB issued Statement of Financial Accounting Standards No. 168, The FASB
Accounting Standards CodificationTM and Hierarchy of Generally Accepted
Accounting Principles, a replacement of FASB Statement No. 162, or SFAS No. 168. SFAS No. 168
establishes the FASB Standards Accounting Codification (Codification) as the source of
authoritative GAAP recognized by the FASB to be applied to nongovernmental entities and rules and
interpretive releases of the SEC as authoritative GAAP for SEC registrants. The Codification will
supersede all the existing non-SEC accounting and reporting standards upon its effective date and
subsequently, the FASB will not issue new standards in the form of Statements, FASB Staff Positions
or Emerging Issues Task Force Abstracts. Subsequent issuances of new standards will be in the form
of Accounting Standards Updates that will be included in the Codification. Generally, the
Codification is not expected to change U.S. GAAP. SFAS No. 168 is effective for financial
statements issued for interim and annual periods ending after September 15, 2009. Adoption of SFAS
No. 168 will require us to adjust references to authoritative accounting literature in our
financial statements, but will not affect our financial position or operating results.
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. These factors include, but are not limited to, the following:
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the impact of the weak economic conditions and the future impact of such conditions
on the oil and natural gas industry and demand for our services; |
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the unexpected future capital expenditures (including amount and nature thereof); |
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unexpected difficulties in integrating our operations as a result of any
significant acquisitions; |
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adverse weather conditions in certain regions; |
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the impact of political disturbances, war, or terrorist attacks and changes in
global trade policies; |
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the availability (or lack thereof) of capital to fund our business strategy and/or
operations; |
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the potential impact of the loss of one or more key employees; |
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the effect of environmental liabilities that are not covered by an effective
indemnity or insurance; the impact of current and future laws; |
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the effects of competition; and |
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the effects of our indebtedness, which could adversely restrict our ability to
operate, could make us vulnerable to general adverse economic and industry conditions,
could place us at a competitive disadvantage compared to our competitors that have
less debt, and could have other adverse consequences. |
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 annual 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 annual report or currently unknown facts or conditions or the
occurrence of unanticipated events.
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ITEM 3. |
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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. |
We are exposed to market risk primarily from changes in interest rates and foreign currency
exchange risks.
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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 $41.0 million of adjustable rate debt with a
weighted average interest rate of 4.7% at June 30, 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.
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ITEM 4. |
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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 June 30, 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.
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PART II. OTHER INFORMATION
Except as set forth below, there have been no material changes in the risk factors disclosed under
Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2008.
The DLS sellers and Lime Rock control substantial ownership stakes in us and have board nomination
rights, and they are therefore able to exert significant influence on our affairs and actions,
including matters submitted for a stockholder vote.
The DLS sellers collectively hold 11,792,186 shares of our common stock, representing
approximately 16.5% of our issued and outstanding shares as of August 1, 2009. Under the investors
rights agreement that we entered into in connection with the DLS acquisition, the DLS sellers have
the right to designate two nominees for election to our board of directors. Lime Rock currently
holds 19,889,044 shares of our common stock, representing approximately 27.9% of our issued and
outstanding shares as of August 1, 2009. In addition, Lime Rock owns 36,393 shares of preferred
stock which are convertible into 14,202,146 shares of our common stock. Through its ownership of
common and preferred stock, Lime Rock controls, in the aggregate, 35% of our stockholders voting
power. Pursuant to the investment agreement we entered into with Lime Rock, Lime Rock has the
right to designate up to four people to serve on our board of directors based upon the amount of
our common stock Lime Rock and its affiliates beneficially own (counting the preferred stock on an
as converted basis). Currently, Lime Rock has the right to designate four nominees for election to
our board of directors. As a result, the DLS sellers and Lime Rock each have considerable
influence over the composition of our board of directors, our future operations and strategy and
our future corporate actions, including matters submitted for a stockholder vote.
Following the earlier of June 26, 2012 and the date on which the transfer restrictions set forth in
the Investment Agreement expire, Lime Rock will not be prohibited from acquiring additional shares
of our common stock or converting its shares of preferred stock, even if such conversion will
result in its control of more than 35% of our stockholders voting power. As a result, Lime Rocks
influence over us may increase in the future.
Conflicts of interest between the DLS sellers and Lime Rock, on the one hand, and other
holders of our securities, on the other hand, may arise with respect to sales of shares of capital
stock owned by the DLS sellers or Lime Rock or other matters. In addition, the interests of the
DLS sellers or Lime Rock regarding any proposed merger or sale may differ from the interests of
other holders of our securities.
The board designation rights described above could have the effect of delaying or preventing a
change in our control or otherwise discouraging a potential acquirer from attempting to obtain
control of us, which in turn could have a material and adverse effect on the market price of our
securities and/or our ability to meet our obligations thereunder.
(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 August 6,
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
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3.1 |
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Certificate of Designations of 7% Convertible Perpetual Preferred Stock (incorporated by
reference to Exhibit 3.1 to the Registrants Form 8-K filed on July 1, 2009). |
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4.1 |
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Investment Agreement, dated May 20, 2009, between Allis-Chalmers Energy Inc. and Lime Rock
Partners V, L.P. (incorporated by reference to Exhibit 4.1 to the Registrants Form 8-K filed
on May 27, 2009). |
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4.2 |
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First Amendment to Investment Agreement, dated June 25, 2006, between Allis-Chalmers Energy
Inc. and Lime Rock Partners V, L.P. (incorporated by reference to Exhibit 4.1 to the
Registrants Form 8-K filed on July 1, 2009). |
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4.3 |
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Registration Rights Agreement, dated June 26, 2009, between Allis-Chalmers Energy Inc. and
Lime Rock Partners V, L.P. (incorporated by reference to Exhibit 4.2 to the Registrants Form
8-K filed on July 1, 2009). |
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10.1 |
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Third Amendment to Second Amended and Restated Credit Agreement, dated as of April 9, 2009,
by and among Allis-Chalmers Energy Inc., as borrower, certain subsidiaries of Allis-Chalmers
Energy Inc., 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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10.2 |
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Fourth Amendment to Second Amended and Restated Credit Agreement, dated May 20, 2009, by and
among Allis-Chalmers Energy Inc., the subsidiary guarantors party thereto, Royal Bank of
Canada, as Administrative Agent and Collateral Agent, and the lenders party thereto
(incorporate by reference to Exhibit 10.1 to the Registrants Form 8-K filed on May 27, 2009). |
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10.3 |
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Master Loan and Security Agreement, dated as of January 23, 2009, by and among Allis-Chalmers
Drilling LLC, as borrower, Allis-Chalmers Energy Inc., as guarantor, and Caterpillar Financial
Services Corporation, as lender (incorporated by reference to Exhibit 10.2 to the Registrants
Form 8-K filed on May 27, 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. |
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