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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2010
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE TRANSITION PERIOD FROM _______________ TO _______________
Commission file number 1-02199
ALLIS-CHALMERS ENERGY INC.
(Exact name of registrant as specified in its charter)
DELAWARE | 39-0126090 | |
(State or other jurisdiction of | (I.R.S. Employer | |
incorporation or organization) | Identification No.) | |
5075 WESTHEIMER, SUITE 890, HOUSTON, TEXAS | 77056 | |
(Address of principal executive offices) | (Zip Code) |
(713) 369-0550
Registrant’s telephone number, including area code
Registrant’s 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. Yesþ Noo
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). Yeso Noo
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:
Large accelerated filero | Accelerated filerþ | Non-accelerated filero | Smaller reporting companyo | |||
(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
At November 1, 2010 there were 73,426,715 shares of common stock, par value $0.01 per share, outstanding.
ALLIS-CHALMERS ENERGY INC.
FORM 10-Q
For the Quarterly Period Ended September 30, 2010
TABLE OF CONTENTS
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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)
CONSOLIDATED CONDENSED BALANCE SHEETS
(in thousands, except for share and per share amounts)
September 30, | December 31, | |||||||
2010 | 2009 | |||||||
(unaudited) | ||||||||
Assets | ||||||||
Cash and cash equivalents | $ | 15,322 | $ | 41,072 | ||||
Trade receivables, net | 140,123 | 105,059 | ||||||
Inventories | 38,993 | 34,528 | ||||||
Deferred income tax asset | 2,649 | 3,790 | ||||||
Prepaid expenses and other | 8,628 | 13,799 | ||||||
Total current assets | 205,715 | 198,248 | ||||||
Property and equipment, net | 732,857 | 746,478 | ||||||
Goodwill | 46,173 | 40,639 | ||||||
Other intangible assets, net | 35,138 | 32,649 | ||||||
Debt issuance costs, net | 8,073 | 9,545 | ||||||
Deferred income tax asset | 34,736 | 22,047 | ||||||
Other assets | 40,445 | 31,014 | ||||||
Total assets | $ | 1,103,137 | $ | 1,080,620 | ||||
Liabilities and Stockholders’ Equity | ||||||||
Current maturities of long-term debt | $ | 23,624 | $ | 17,027 | ||||
Trade accounts payable | 43,361 | 34,839 | ||||||
Accrued salaries, benefits and payroll taxes | 25,319 | 22,854 | ||||||
Accrued interest | 6,917 | 15,821 | ||||||
Accrued expenses | 27,674 | 21,918 | ||||||
Total current liabilities | 126,895 | 112,459 | ||||||
Long-term debt, net of current maturities | 497,100 | 475,206 | ||||||
Deferred income tax liability | 8,087 | 8,166 | ||||||
Other long-term liabilities | 452 | 1,142 | ||||||
Total liabilities | 632,534 | 596,973 | ||||||
Commitments and contingencies | ||||||||
Stockholders’ Equity | ||||||||
Preferred stock, $0.01 par value (25,000,000 shares authorized; 36,393 shares issued and outstanding at September 30, 2010 and at December 31, 2009) | 34,183 | 34,183 | ||||||
Common stock, $0.01 par value (200,000,000 shares authorized; | ||||||||
73,430,682 shares issued and outstanding at September 30, 2010 and 71,378,529 shares issued and outstanding at December 31, 2009) | 734 | 714 | ||||||
Capital in excess of par value | 429,146 | 422,823 | ||||||
Retained earnings | 6,540 | 25,927 | ||||||
Total stockholders’ equity | 470,603 | 483,647 | ||||||
Total liabilities and stockholders’ equity | $ | 1,103,137 | $ | 1,080,620 | ||||
The accompanying Notes are an integral part of the Consolidated Condensed Financial Statements.
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ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
(unaudited)
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
(unaudited)
For the Three Months Ended | For the Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Revenues | $ | 174,288 | $ | 120,016 | $ | 473,302 | $ | 377,624 | ||||||||
Operating costs and expenses | ||||||||||||||||
Direct costs | 127,622 | 90,763 | 356,060 | 281,136 | ||||||||||||
Depreciation | 21,094 | 19,709 | 61,799 | 58,261 | ||||||||||||
Selling, general and administrative | 12,772 | 11,430 | 36,949 | 40,595 | ||||||||||||
Loss on asset disposition | — | — | — | 1,916 | ||||||||||||
Amortization | 1,255 | 1,184 | 3,567 | 3,558 | ||||||||||||
Total operating costs and expenses | 162,743 | 123,086 | 458,375 | 385,466 | ||||||||||||
Income (loss) from operations | 11,545 | (3,070 | ) | 14,927 | (7,842 | ) | ||||||||||
Other income (expense) | ||||||||||||||||
Interest expense | (11,881 | ) | (10,764 | ) | (33,986 | ) | (37,492 | ) | ||||||||
Interest income | 45 | 39 | 499 | 53 | ||||||||||||
Gain on debt extinguishment | — | — | — | 26,365 | ||||||||||||
Other | (661 | ) | 37 | (2,479 | ) | (231 | ) | |||||||||
Total other income (expense) | (12,497 | ) | (10,688 | ) | (35,966 | ) | (11,305 | ) | ||||||||
Loss before income taxes | (952 | ) | (13,758 | ) | (21,039 | ) | (19,147 | ) | ||||||||
Provision for income taxes | (1,614 | ) | 4,108 | 3,563 | 6,802 | |||||||||||
Net loss | (2,566 | ) | (9,650 | ) | (17,476 | ) | (12,345 | ) | ||||||||
Preferred stock dividend | (637 | ) | (630 | ) | (1,911 | ) | (665 | ) | ||||||||
Net loss attributed to common stockholders | $ | (3,203 | ) | $ | (10,280 | ) | $ | (19,387 | ) | $ | (13,010 | ) | ||||
Net loss per common share: | ||||||||||||||||
Basic | $ | (0.04 | ) | $ | (0.14 | ) | $ | (0.27 | ) | $ | (0.27 | ) | ||||
Diluted | $ | (0.04 | ) | $ | (0.14 | ) | $ | (0.27 | ) | $ | (0.27 | ) | ||||
Weighted average shares outstanding: | ||||||||||||||||
Basic | 72,207 | 70,945 | 71,506 | 47,834 | ||||||||||||
Diluted | 72,207 | 70,945 | 71,506 | 47,834 |
The accompanying Notes are an integral part of the Consolidated Condensed Financial Statements.
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For the Nine Months Ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
Cash Flows from Operating Activities: | ||||||||
Net loss | $ | (17,476 | ) | $ | (12,345 | ) | ||
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||
Depreciation and amortization | 65,366 | 61,819 | ||||||
Amortization and write-off of debt issuance costs | 1,661 | 1,691 | ||||||
Stock-based compensation | 4,374 | 3,580 | ||||||
Allowance for bad debts | 43 | 4,065 | ||||||
Deferred income taxes | (12,016 | ) | (11,094 | ) | ||||
Loss on investment | 1,466 | — | ||||||
Equity in loss of unconsolidated affiliates | 409 | — | ||||||
Loss (gain) on sale of property and equipment | 150 | (1,180 | ) | |||||
Loss on asset disposition | — | 1,916 | ||||||
Gain on debt extinguishment | — | (26,365 | ) | |||||
Changes in operating assets and liabilities, net of acquisition: | ||||||||
Decrease (increase) in trade receivable | (30,361 | ) | 59,471 | |||||
Decrease (increase) in inventories | (2,697 | ) | 3,890 | |||||
Decrease in prepaid expenses and other current assets | 8,024 | 3,290 | ||||||
Decrease in other assets | 1,265 | 1,535 | ||||||
Increase (decrease) in trade accounts payable | 8,380 | (29,035 | ) | |||||
(Decrease) in accrued interest | (8,904 | ) | (12,479 | ) | ||||
Increase (decrease) in accrued expenses | 5,488 | (11,632 | ) | |||||
Increase in accrued salaries, benefits and payroll taxes | 2,401 | 1,228 | ||||||
(Decrease) in other long-term liabilities | (690 | ) | (836 | ) | ||||
Net Cash Provided By Operating Activities | 26,883 | 37,519 | ||||||
Cash Flows from Investing Activities: | ||||||||
Deposits on asset commitments | (12,967 | ) | 7,054 | |||||
Business acquisition, net of cash acquired | (18,237 | ) | — | |||||
Purchase of investment interests | 368 | (1,102 | ) | |||||
Proceeds from sale of property and equipment | 5,284 | 7,980 | ||||||
Proceeds from assets dispositions | — | 3,916 | ||||||
Purchase of property and equipment | (50,893 | ) | (67,266 | ) | ||||
Net Cash Used In Investing Activities | (76,445 | ) | (49,418 | ) | ||||
Cash Flows from Financing Activities: | ||||||||
Proceeds from issuance of stock, net | — | 120,337 | ||||||
Net proceeds from stock incentive plans | — | 14 | ||||||
Proceeds from long-term debt | 4,000 | 25,000 | ||||||
Net borrowings (repayments) under line of credit | 36,500 | (36,500 | ) | |||||
Payments on long-term debt | (14,588 | ) | (61,539 | ) | ||||
Payment of preferred stock dividend | (1,911 | ) | — | |||||
Debt issuance costs | (189 | ) | (644 | ) | ||||
Net Cash Provided By Financing Activities | 23,812 | 46,668 | ||||||
Net change in cash and cash equivalents | (25,750 | ) | 34,769 | |||||
Cash and cash equivalents at beginning of period | 41,072 | 6,866 | ||||||
Cash and cash equivalents at end of period | $ | 15,322 | $ | 41,635 | ||||
The accompanying Notes are an integral part of the Consolidated Condensed Financial Statements.
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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, Louisiana, Pennsylvania, Arkansas, West Virginia, Oklahoma, Colorado, 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.
Pending Merger
On August 12, 2010, we entered into a merger agreement with Seawell Limited, or Seawell, pursuant to which we will merge with and into a wholly owned subsidiary of Seawell. Completion of the merger is subject to customary closing conditions, including, but not limited to, (i) approval of the merger by our stockholders, (ii) applicable regulatory approvals, (iii) the effectiveness of a registration statement on Form F-4 relating to the Seawell common stock to be issued in the merger and, (iv) the listing of the Seawell common stock on the OSLO Stock Exchange.
Under terms of the merger, we agreed to conduct our business in the ordinary course while the merger is pending, and generally refrain, without the consent of Seawell, from entering into new lines of business, incurring new indebtedness, issuing new common stock or equity awards, or entering into new material contracts or commitments outside the normal course of business. We recorded approximately $0.6 million of costs related to the pending merger during the three months ended September 30, 2010, which are included in general and administrative expense in the General Corporate category of our segment presentation (see Note 13). If and when the merger is approved or completed, certain contractual obligations of ours will or may be triggered or accelerated under the “change of control” provisions of such contractual arrangements. Examples of such arrangements include stock-based compensation awards, severance and retention agreements applicable to executive officers, directors and certain other employees and certain debt obligations such as our senior notes.
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, 2009. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year.
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 1 — NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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; stock-based compensation; 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 or as our operating environment changes.
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 September 30, 2010. 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 recent trades we estimate the fair value of our senior notes to be approximately $432.9 million at September 30, 2010. 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.
Reclassification
Certain reclassifications have been made to the prior year’s consolidated condensed financial statements to conform with the current period presentation.
New Accounting Pronouncements
In June 2009, the Financial Accounting Standards Board, or the FASB, issued authoritative guidance that eliminates the qualifying special purpose entity concept, changes the requirements for derecognizing financial assets and requires enhanced disclosures about transfers of financial assets. The guidance also revises earlier guidance for determining whether an entity is a variable interest entity, requires a new approach for determining who should consolidate a variable interest entity, changes when it is necessary to reassess who should consolidate a variable interest entity, and requires enhanced disclosures related to an enterprise’s involvement in variable interest entities. We adopted this guidance effective January 1, 2010, which did not have a material effect on our financial statements.
In October 2009, the FASB issued authoritative guidance that amends earlier guidance addressing the accounting for contractual arrangements in which an entity provides multiple products or services (deliverables) to a customer. The amendments address the unit of accounting for arrangements involving multiple deliverables and how arrangement consideration should be allocated to the separate units of accounting, when applicable, by establishing a selling price hierarchy for determining the selling price of a deliverable. The selling price used for each deliverable will be based on vendor-specific objective evidence if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific nor third-party evidence is available. The amendments also require that arrangement consideration be allocated at the inception of an arrangement to all deliverables using the relative selling price method. This guidance is effective for fiscal years beginning on or after June 15, 2010, with earlier application permitted. We are currently evaluating the effects that this guidance may have on our financial statements.
In January 2010, the FASB issued authoritative guidance that changes the disclosure requirements for fair value measurements. Specifically, the changes require a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers. The changes also clarify existing disclosure requirements related to how assets and liabilities should be grouped by class and valuation techniques used for recurring and nonrecurring fair value measurements. We adopted this guidance in the first quarter 2010, which did not have a material effect on our financial position, results of operations or cash flows.
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 1 — NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
In February 2010, the FASB amended guidance on subsequent events to alleviate potential conflicts between FASB guidance and SEC requirements. Under this amended guidance, SEC filers are no longer required to disclose the date through which subsequent events have been evaluated in originally issued and revised financial statements. This guidance was effective immediately and we adopted these new requirements in the first quarter of 2010. The adoption of this guidance did not have a material effect on our financial statements.
NOTE 2– ACQUISITION
On July 12, 2010, we acquired American Well Control, Inc., or AWC, for a total consideration of approximately $21.5 million, which included approximately $19.5 million in cash and 1.0 million shares of our common stock. AWC is a leading manufacturer of premium high-pressure valves used in hydraulic fracturing in the unconventional gas shale plays. The following table summarizes the preliminary allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):
Current assets | $ | 7,745 | ||
Property and equipment | 2,756 | |||
Intangible assets, including goodwill | 11,589 | |||
Other long-term assets | 2 | |||
Total assets acquired | 22,092 | |||
Current liabilities | 444 | |||
Long-term liabilities | 181 | |||
Net assets acquired | $ | 21,467 | ||
AWC’s historical property and equipment values were increased by approximately $27,000 based on third-party valuations. Goodwill of $5.5 million was recognized for this acquisition and was calculated as the excess of the consideration transferred over the fair value of the net assets acquired. It includes the expected synergies and other benefits that we believe will result from the combined operations and intangible assets that do not qualify for separate recognition such as assembled workforce. Other intangible assets included approximately $5.6 million assigned to customer lists, $400,000 to trade name and $55,000 to non-competes. None of the intangibles are tax deductible. The amortizable intangibles have a weighted-average useful life of 9.9 years. We do not expect any material differences from the preliminary allocation of the purchase price. AWC’s financial results since the acquisition are included in our Rental Services segment.
NOTE 3 — STOCK-BASED COMPENSATION
We recognize all share-based payments to employees and directors in the financial statements based on their grant-date fair values. 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 on our common stock 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 United States 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 Black-Scholes model assumptions used for the options granted in the nine months ended September 30, 2010 and 2009 (no options were granted in the three months ended September 30, 2010 and 2009):
For the Nine Months Ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
Expected dividend yield | — | — | ||||||
Expected price volatility | 89.81 | % | 77.32 | % | ||||
Risk-free interest rate | 1.41 | % | 1.37 | % | ||||
Expected life of options | 5 years | 5 years | ||||||
Weighted-average fair value of options granted at market value | $ | 2.63 | $ | 0.77 |
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 3 — STOCK-BASED COMPENSATION (Continued)
Our net loss for the three months ended September 30, 2010 and 2009 includes approximately $1.4 million and $1.2 million, respectively, of compensation costs related to share-based payments. Our net loss for the nine months ended September 30, 2010 and 2009 includes approximately $4.4 million and $3.6 million, respectively, of compensation costs related to share-based payments. As of September 30, 2010, there was $2.3 million of unrecognized compensation expense related to non-vested stock option grants. We expect approximately $134,000 to be recognized over the remainder of 2010 and approximately $535,000, $511,000, $506,000, $506,000 and $129,000 to be recognized during the years ended 2011 through 2015, respectively.
A summary of our stock option activity during the nine months ended September 30, 2010 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, 2009 | 701,732 | $ | 6.31 | |||||||||||||
Granted | 1,072,253 | 3.78 | ||||||||||||||
Canceled | (21,967 | ) | 8.30 | |||||||||||||
Exercised | — | |||||||||||||||
Outstanding at September 30, 2010 | 1,752,018 | $ | 4.74 | 7.86 | $ | 0.85 | ||||||||||
Exercisable at September 30, 2010 | 586,432 | $ | 7.08 | 4.90 | $ | 0.14 | ||||||||||
The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between the closing price of our common stock on the last trading day of the third quarter of 2010 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on September 30, 2010.
Restricted stock awards, or RSAs, activity during the nine months ended September 30, 2010 were as follows:
Weighted-Average | ||||||||
Grant-Date Fair | ||||||||
Number of Shares | Value Per Share | |||||||
Nonvested at December 31, 2009 | 837,626 | $ | 15.63 | |||||
Granted | 2,061,750 | 3.78 | ||||||
Vested | (335,787 | ) | 17.48 | |||||
Forfeited | (3,333 | ) | 3.77 | |||||
Nonvested at September 30, 2010 | 2,560,256 | $ | 5.86 | |||||
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. During the nine months ended September 30, 2010, we granted 1,237,750 performance-based RSAs to executive officers and key employees that vest upon meeting certain financial performance conditions over the next five years. In connection with performance-based RSAs, compensation cost is based on the estimated number of shares expected to be issued. As of September 30, 2010, there was $7.1 million of total unrecognized compensation cost related to nonvested RSAs. We expect approximately $1.1 million to be recognized over the remainder of 2010 and approximately $2.3 million, $1.3 million, $1.2 million, $1.1 million and $88,000 to be recognized during the years ended 2011 through 2015, respectively.
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 4 — INVENTORIES
Inventories consisted of the following (in thousands):
September 30, | December 31, | |||||||
2010 | 2009 | |||||||
Manufactured | ||||||||
Finished goods | $ | 3,814 | $ | 2,983 | ||||
Work in process | 2,099 | 2,299 | ||||||
Raw materials | 2,355 | 884 | ||||||
Total manufactured | 8,268 | 6,166 | ||||||
Rig parts and related inventory | 11,991 | 10,654 | ||||||
Shop supplies and related inventory | 8,621 | 7,762 | ||||||
Chemicals and drilling fluids | 4,919 | 4,381 | ||||||
Rental supplies | 1,908 | 2,134 | ||||||
Hammers | 2,269 | 2,257 | ||||||
Coiled tubing and related inventory | 847 | 939 | ||||||
Drive pipe | 170 | 235 | ||||||
Total inventories | $ | 38,993 | $ | 34,528 | ||||
NOTE 5— GOODWILL AND INTANGIBLE ASSETS
Goodwill and other intangible assets with infinite lives are not amortized, but tested for impairment annually or more frequently if circumstances indicate that impairment may exist. Intangible assets with finite useful lives are amortized either on a straight-line basis over the asset’s estimated useful life or on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized. Goodwill and indefinite-lived intangible assets listed on the balance sheet totaled $46.2 million and $40.6 million at September 30, 2010 and December 31, 2009, respectively.
Definite-lived intangible assets that continue to be amortized relate to our purchase of customer-related and marketing-related intangibles, patents and non-compete agreements. These intangibles have useful lives ranging from three to 20 years. Amortization of intangible assets for the three and nine months ended September 30, 2010 were $1.3 million and $3.6 million, respectively, compared to $1.2 million and $3.6 million for the same periods in the prior year. At September 30, 2010, intangible assets totaled $35.1 million, net of $16.4 million of accumulated amortization.
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 6 — DEBT
Our long-term debt consisted of the following (in thousands):
September 30, | December 31, | |||||||
2010 | 2009 | |||||||
Senior notes | $ | 430,238 | $ | 430,238 | ||||
Revolving line of credit | 36,500 | — | ||||||
Term loans | 52,484 | 60,744 | ||||||
Insurance premium financing | 1,486 | 997 | ||||||
Capital lease obligations | 16 | 254 | ||||||
Total debt | 520,724 | 492,233 | ||||||
Less: current maturities | 23,624 | 17,027 | ||||||
Long-term debt, net of current maturities | $ | 497,100 | $ | 475,206 | ||||
Senior notes, line of credit agreements and term loans
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. 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 approximately $30.6 million aggregate principal amount 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 1933, 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. On June 29, 2009, we closed on a tender offer in which we purchased $44.2 million aggregate principal amount of our 8.5% senior notes for a total consideration of $600 per $1,000 principal amount.
We have a $90.0 million revolving line of credit with a final maturity date of April 26, 2012 pursuant to a revolving credit agreement that 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. On April 9, 2009, we amended our revolving credit agreement to modify the leverage and interest coverage ratio covenants. Effective December 31, 2009, we again amended the leverage and interest coverage ratio covenants of the revolving credit agreement. This amendment relaxed the required financial ratios for the quarter ended December 31, 2009 and for each of the quarters in 2010. 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 September 30, 2010 and December 31, 2009. As of September 30, 2010, we had $36.5 million of borrowings outstanding and $4.0 million in outstanding letters of credit under our revolving credit facility. As of December 31, 2009, the only usage of our revolving credit facility consisted of $4.2 million in outstanding letters of credit. The interest rate under our revolving credit facility is based on prime or LIBOR plus a margin. The weighted-average interest rate was 7.9% at September 30, 2010.
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 two to five years. The weighted-average interest rate on these loans was 2.0% and 2.1% as of September 30, 2010 and December 31, 2009, respectively. The outstanding amount due under these bank loans as of September 30, 2010 and December 31, 2009 was $350,000 and $1.1 million, respectively.
On February 15, 2008, through our DLS subsidiary, 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. The loan is repayable 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 September 30, 2010 and December 31, 2009. The bank loan rates are based on LIBOR plus a margin. The weighted-average interest rate was 4.3% and 4.4% at September 30, 2010 and December 31, 2009, respectively. The outstanding amount under the import finance facility as of September 30, 2010 and December 31, 2009 was $15.5 million and $20.1 million, respectively.
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 6 — DEBT (Continued)
As part of our acquisition of BCH Ltd, or BCH, we assumed a $23.6 million term loan credit facility with a bank. The BCH credit agreement is dated June 2007 and contains customary events of default and financial covenants which are based on BCH’s stand-alone financial statements. Obligations under the facility are secured by substantially all of the BCH assets. BCH was in compliance with all debt covenants as of December 31, 2009. The bank has waived certain financial ratio covenants for the September 30, 2010 and December 31, 2010 measurement periods. As we cannot be certain that BCH would attain compliance with the covenants within one year, we have classified the entire outstanding balance of the loan in the current portion of long-term debt. The facility is repayable in quarterly principal installments plus interest with the final payment due not later than August 2012. The interest rates under the credit facility are based on LIBOR plus a margin. At September 30, 2010 and December 31, 2009, the outstanding amount of the loan under the credit facility was $11.8 million and $16.2 million, respectively, and the interest rate was 3.5% at both dates.
On May 22, 2009, we drew down $25.0 million on a 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 September 30, 2010 and December 31, 2009, the outstanding amount of the loan was $20.8 million and $23.4 million, respectively.
On February 9, 2010, through our DLS subsidiary, we entered into a $4.0 million term loan facility. The loan is repayable in semi-annual installments beginning April 14, 2011 and bears interest at 8.5% per annum. The final maturity date is April 14, 2014 and the loan is unsecured.
Notes payable
In 2010, we obtained insurance premium financings in the aggregate amount of $2.6 million with a fixed weighted-average interest rate of 4.8%. Under terms of the agreements, amounts outstanding are paid over eight and 11 month repayment schedules. The outstanding balance of these notes was approximately $1.5 million at September 30, 2010. In 2009, we obtained insurance premium financings in the aggregate amount of $3.2 million with a fixed weighted-average interest rate of 4.8%. Under terms of these agreements, amounts outstanding are paid over 10 and 11 month repayment schedules. The outstanding balance of these notes was approximately $0 and $997,000 at September 30, 2010 and December 31, 2009, respectively.
Other debt
As part of our acquisition of BCH, we assumed various capital leases with terms of two to three years. The outstanding balance under these capital leases was $16,000 and $254,000 at September 30, 2010 and December 31, 2009, respectively.
NOTE 7 — STOCKHOLDERS’ EQUITY
We issued 1.0 million shares of our common stock in connection with the acquisition of AWC in July of 2010 (see Note 2).
During the nine months ended September 30, 2010, we had restricted stock award grants and vested performance-based restricted stock which resulted in the issuance of approximately 1.1 million shares of our common stock. We recognized approximately $4.4 million of compensation expense related to share-based payments in the first nine months of 2010 that was recorded as capital in excess of par value (see Note 3). During the nine months ended September 30, 2010, we declared approximately $1.9 million in dividends on our preferred stock. Accrued dividends of approximately $637,000 were included in our accrued expenses of $27.7 million as of September 30, 2010 and our accrued expenses of $21.9 million as of December 31, 2009. The accrued dividends were paid in October 2010 and February 2010, respectively.
NOTE 8 — LOSS ON ASSET DISPOSITION
During the nine months ended September 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 that destroyed one of our drilling rigs were not sufficient to cover the book value of the rig and related assets.
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 9 — GAIN ON DEBT EXTINGUISHMENT
During the nine months ended September 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 approximately $30.6 million aggregate principal amount of our 9.0% senior notes and $44.2 million aggregate principal amount of our 8.5% senior notes for approximately $46.4 million. The gain is net of a $1.5 million write-off of debt issuance costs related to the retired notes and we incurred approximately $466,000 in expenses related to the transactions.
NOTE 10 — INCOME (LOSS) 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 Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Numerator: | ||||||||||||||||
Net loss | $ | (2,566 | ) | $ | (9,650 | ) | $ | (17,476 | ) | $ | (12,345 | ) | ||||
Preferred stock dividend | (637 | ) | (630 | ) | (1,911 | ) | (665 | ) | ||||||||
Net loss attributed to common stockholders | $ | (3,203 | ) | $ | (10,280 | ) | $ | (19,387 | ) | $ | (13,010 | ) | ||||
Denominator: | ||||||||||||||||
Weighted-average common shares outstanding excluding nonvested restricted stock | 72,207 | 70,945 | 71,506 | 47,834 | ||||||||||||
Effect of potentially dilutive common shares: | ||||||||||||||||
Convertible preferred stock and stock-based compensation | — | — | — | — | ||||||||||||
Weighted-average common shares outstanding and assumed conversions | 72,207 | 70,945 | 71,506 | 47,834 | ||||||||||||
Net loss per common share | ||||||||||||||||
Basic | $ | (0.04 | ) | $ | (0.14 | ) | $ | (0.27 | ) | $ | (0.27 | ) | ||||
Diluted | $ | (0.04 | ) | $ | (0.14 | ) | $ | (0.27 | ) | $ | (0.27 | ) | ||||
Potentially dilutive securities excluded as anti-dilutive | 17,126 | 15,016 | 15,946 | 15,557 | ||||||||||||
Convertible preferred stock and share-based compensation shares of approximately 14.7 million and 14.5 million were excluded in the computation of diluted earnings per share for the three months ended September 30, 2010 and 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. Convertible preferred stock and share-based compensation shares of approximately 15.0 million and 5.1 million were excluded in the computation of diluted earnings per share for the nine months ended September 30, 2010 and 2009, respectively, as the effect would have been anti-dilutive.
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 11 — SUPPLEMENTAL CASH FLOW INFORMATION(in thousands)
For the Nine Months Ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
Cash paid for interest and income taxes: | ||||||||
Interest | $ | 41,507 | $ | 48,631 | ||||
Income taxes | 667 | 3,963 | ||||||
Non-cash investing and financing transactions in connection with an acquisition: | ||||||||
Goodwill | $ | (2,000 | ) | $ | — | |||
Value of common stock, issued | 2,000 | — | ||||||
Other non-cash investing and financing activities: | ||||||||
Insurance premium financed | $ | 2,579 | $ | 3,204 | ||||
Receivable from sale of investment | 274 | — | ||||||
Assets transferred to joint venture investment | — | 1,639 | ||||||
Preferred stock dividend | 1,911 | 665 |
NOTE 12 — 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).
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 12 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
September 30, 2010 (unaudited)
September 30, 2010 (unaudited)
Allis- | ||||||||||||||||||||
Chalmers | Subsidiary | |||||||||||||||||||
(Parent/ | Subsidiary | Non- | Consolidating | Consolidated | ||||||||||||||||
Guarantor) | Guarantors | Guarantors | Adjustments | Total | ||||||||||||||||
Assets | ||||||||||||||||||||
Cash and cash equivalents | $ | — | $ | 7,780 | $ | 7,542 | $ | — | $ | 15,322 | ||||||||||
Trade receivables, net | — | 77,263 | 73,454 | (10,594 | ) | 140,123 | ||||||||||||||
Inventories | — | 18,906 | 20,087 | — | 38,993 | |||||||||||||||
Intercompany receivables | — | 106,193 | — | (106,193 | ) | — | ||||||||||||||
Note receivable from affiliate | 23,551 | — | — | (23,551 | ) | — | ||||||||||||||
Prepaid expenses and other | 22 | 5,832 | 5,423 | — | 11,277 | |||||||||||||||
Total current assets | 23,573 | 215,974 | 106,506 | (140,338 | ) | 205,715 | ||||||||||||||
Property and equipment, net | — | 469,640 | 263,217 | — | 732,857 | |||||||||||||||
Goodwill | — | 28,784 | 17,389 | — | 46,173 | |||||||||||||||
Other intangible assets, net | 425 | 28,320 | 6,393 | — | 35,138 | |||||||||||||||
Debt issuance costs, net | 7,954 | 119 | — | — | 8,073 | |||||||||||||||
Note receivable from affiliates | 2,100 | — | — | (2,100 | ) | — | ||||||||||||||
Investments in affiliates | 981,488 | — | — | (981,488 | ) | — | ||||||||||||||
Other assets | 32,767 | 39,099 | 3,315 | — | 75,181 | |||||||||||||||
Total assets | $ | 1,048,307 | $ | 781,936 | $ | 396,820 | $ | (1,123,926 | ) | $ | 1,103,137 | |||||||||
Liabilities and Stockholders’ Equity | ||||||||||||||||||||
Current maturities of long-term debt | $ | — | $ | 5,172 | $ | 18,452 | $ | — | $ | 23,624 | ||||||||||
Trade accounts payable | — | 17,033 | 36,922 | (10,594 | ) | 43,361 | ||||||||||||||
Accrued salaries, benefits and payroll taxes | — | 1,976 | 23,343 | — | 25,319 | |||||||||||||||
Accrued interest | 6,356 | 203 | 358 | — | 6,917 | |||||||||||||||
Accrued expenses | 1,041 | 15,275 | 11,358 | — | 27,674 | |||||||||||||||
Intercompany payables | 103,569 | — | 2,624 | (106,193 | ) | — | ||||||||||||||
Note payable to affiliate | — | — | 23,551 | (23,551 | ) | — | ||||||||||||||
Total current liabilities | 110,966 | 39,659 | 116,608 | (140,338 | ) | 126,895 | ||||||||||||||
Long-term debt, net of current maturities | 466,738 | 17,146 | 13,216 | — | 497,100 | |||||||||||||||
Note payable to affiliate | — | — | 2,100 | (2,100 | ) | — | ||||||||||||||
Other long-term liabilities | — | — | 8,539 | — | 8,539 | |||||||||||||||
Total liabilities | 577,704 | 56,805 | 140,463 | (142,438 | ) | 632,534 | ||||||||||||||
Commitments and contingencies | ||||||||||||||||||||
Stockholders’ Equity | ||||||||||||||||||||
Preferred Stock | 34,183 | — | — | — | 34,183 | |||||||||||||||
Common stock | 734 | 3,527 | 42,963 | (46,490 | ) | 734 | ||||||||||||||
Capital in excess of par value | 429,146 | 591,978 | 137,439 | (729,417 | ) | 429,146 | ||||||||||||||
Retained earnings | 6,540 | 129,626 | 75,955 | (205,581 | ) | 6,540 | ||||||||||||||
Total stockholders’ equity | 470,603 | 725,131 | 256,357 | (981,488 | ) | 470,603 | ||||||||||||||
Total liabilities and stockholders’ equity | $ | 1,048,307 | $ | 781,936 | $ | 396,820 | $ | (1,123,926 | ) | $ | 1,103,137 | |||||||||
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 12 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended September 30, 2010 (unaudited)
For the Three Months Ended September 30, 2010 (unaudited)
Allis-Chalmers | Subsidiary | |||||||||||||||||||
(Parent/ | Subsidiary | Non- | Consolidating | Consolidated | ||||||||||||||||
Guarantor) | Guarantors | Guarantors | Adjustments | Total | ||||||||||||||||
Revenues | $ | — | $ | 78,034 | $ | 96,325 | $ | (71 | ) | $ | 174,288 | |||||||||
Operating costs and expenses | ||||||||||||||||||||
Direct costs | — | 47,152 | 80,541 | (71 | ) | 127,622 | ||||||||||||||
Selling, general and administrative | 1,176 | 7,677 | 3,919 | — | 12,772 | |||||||||||||||
Depreciation and amortization | 12 | 15,547 | 6,790 | — | 22,349 | |||||||||||||||
Total operating costs and expenses | 1,188 | 70,376 | 91,250 | (71 | ) | 162,743 | ||||||||||||||
Income (loss) from operations | (1,188 | ) | 7,658 | 5,075 | — | 11,545 | ||||||||||||||
Other income (expense): | ||||||||||||||||||||
Equity earnings in affiliates, net of tax | 9,376 | — | — | (9,376 | ) | — | ||||||||||||||
Interest, net | (10,769 | ) | (505 | ) | (562 | ) | — | (11,836 | ) | |||||||||||
Other | 15 | (166 | ) | (510 | ) | — | (661 | ) | ||||||||||||
Total other expense | (1,378 | ) | (671 | ) | (1,072 | ) | (9,376 | ) | (12,497 | ) | ||||||||||
Net income (loss) before income taxes | (2,566 | ) | 6,987 | 4,003 | (9,376 | ) | (952 | ) | ||||||||||||
Provision for income taxes | — | 811 | (2,425 | ) | — | (1,614 | ) | |||||||||||||
Net income (loss) | (2,566 | ) | 7,798 | 1,578 | (9,376 | ) | (2,566 | ) | ||||||||||||
Preferred stock dividend | (637 | ) | — | — | — | (637 | ) | |||||||||||||
Net income (loss) attributed to common stockholders | $ | (3,203 | ) | $ | 7,798 | $ | 1,578 | $ | (9,376 | ) | $ | (3,203 | ) | |||||||
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 12 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Nine Months Ended September 30, 2010 (unaudited)
For the Nine Months Ended September 30, 2010 (unaudited)
Allis-Chalmers | Subsidiary | |||||||||||||||||||
(Parent/ | Subsidiary | Non- | Consolidating | Consolidated | ||||||||||||||||
Guarantor) | Guarantors | Guarantors | Adjustments | Total | ||||||||||||||||
Revenues | $ | — | $ | 192,676 | $ | 282,025 | $ | (1,399 | ) | $ | 473,302 | |||||||||
Operating costs and expenses | ||||||||||||||||||||
Direct costs | — | 124,528 | 232,931 | (1,399 | ) | 356,060 | ||||||||||||||
Selling, general and administrative | 3,708 | 22,033 | 11,208 | — | 36,949 | |||||||||||||||
Depreciation and amortization | 35 | 45,779 | 19,552 | — | 65,366 | |||||||||||||||
Total operating costs and expenses | 3,743 | 192,340 | 263,691 | (1,399 | ) | 458,375 | ||||||||||||||
Income (loss) from operations | (3,743 | ) | 336 | 18,334 | — | 14,927 | ||||||||||||||
Other income (expense): | ||||||||||||||||||||
Equity earnings in affiliates, net of tax | 17,643 | — | — | (17,643 | ) | — | ||||||||||||||
Interest, net | (31,421 | ) | (291 | ) | (1,775 | ) | — | (33,487 | ) | |||||||||||
Other | 45 | (1,944 | ) | (580 | ) | — | (2,479 | ) | ||||||||||||
Total other expense | (13,733 | ) | (2,235 | ) | (2,355 | ) | (17,643 | ) | (35,966 | ) | ||||||||||
Net income (loss) before income taxes | (17,476 | ) | (1,899 | ) | 15,979 | (17,643 | ) | (21,039 | ) | |||||||||||
Provision for income taxes | — | 11,323 | (7,760 | ) | — | 3,563 | ||||||||||||||
Net income (loss) | (17,476 | ) | 9,424 | 8,219 | (17,643 | ) | (17,476 | ) | ||||||||||||
Preferred stock dividend | (1,911 | ) | — | — | — | (1,911 | ) | |||||||||||||
Net income (loss) attributed to common stockholders | $ | (19,387 | ) | $ | 9,424 | $ | 8,219 | $ | (17,643 | ) | $ | (19,387 | ) | |||||||
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 12 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Nine Months Ended September 30, 2010 (unaudited)
For the Nine Months Ended September 30, 2010 (unaudited)
Allis- | Other | |||||||||||||||||||
Chalmers | Subsidiaries | |||||||||||||||||||
(Parent/ | Subsidiary | (Non- | Consolidating | Consolidated | ||||||||||||||||
Guarantor) | Guarantors | Guarantors) | Adjustments | Total | ||||||||||||||||
Cash Flows from Operating Activities: | ||||||||||||||||||||
Net income (loss) | $ | (17,476 | ) | $ | 9,424 | $ | 8,219 | $ | (17,643 | ) | $ | (17,476 | ) | |||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||||||
Depreciation and amortization | 35 | 45,779 | 19,552 | — | 65,366 | |||||||||||||||
Amortization and write-off of debt issuance costs | 1,643 | 18 | — | — | 1,661 | |||||||||||||||
Stock-based compensation | 4,374 | — | — | — | 4,374 | |||||||||||||||
Allowance for bad debts | — | 43 | — | — | 43 | |||||||||||||||
Equity earnings in affiliates | (17,643 | ) | — | — | 17,643 | — | ||||||||||||||
Deferred taxes | (11,847 | ) | (332 | ) | 163 | — | (12,016 | ) | ||||||||||||
Loss on sale of equipment | — | 74 | 76 | — | 150 | |||||||||||||||
Loss on investment | — | 1,466 | — | — | 1,466 | |||||||||||||||
Equity in losses of unconsolidated affiliates | — | 409 | — | — | 409 | |||||||||||||||
Changes in operating assets and liabilities, net of acquisitions: | ||||||||||||||||||||
(Increase) in trade receivables | — | (15,869 | ) | (14,492 | ) | — | (30,361 | ) | ||||||||||||
(Increase) in inventories | — | (867 | ) | (1,830 | ) | — | (2,697 | ) | ||||||||||||
Decrease in prepaid expenses and other current assets | 129 | 3,791 | 4,104 | — | 8,024 | |||||||||||||||
Decrease in other assets | — | 549 | 716 | — | 1,265 | |||||||||||||||
(Decrease) increase in trade accounts payable | — | (4,637 | ) | 13,017 | — | 8,380 | ||||||||||||||
(Decrease) increase in accrued interest | (9,016 | ) | (25 | ) | 137 | — | (8,904 | ) | ||||||||||||
Increase in accrued expenses | 258 | 3,430 | 1,800 | — | 5,488 | |||||||||||||||
(Decrease) increase in accrued salaries, benefits and payroll taxes | — | (850 | ) | 3,251 | — | 2,401 | ||||||||||||||
(Decrease) in other long-term liabilities | — | — | (690 | ) | — | (690 | ) | |||||||||||||
Net Cash Provided By (Used In) Operating Activities | (49,543 | ) | 42,403 | 34,023 | — | 26,883 | ||||||||||||||
Cash Flows from Investing Activities: | ||||||||||||||||||||
Investment in affiliates | (19,467 | ) | — | — | 19,467 | — | ||||||||||||||
Notes receivable from affiliates | 8,328 | — | — | (8,328 | ) | — | ||||||||||||||
Deposits on asset commitments | — | (12,694 | ) | (273 | ) | — | (12,967 | ) | ||||||||||||
Proceeds from sale of investments | — | 368 | — | — | 368 | |||||||||||||||
Proceeds from sale of property and equipment | — | 4,911 | 373 | — | 5,284 | |||||||||||||||
Business acquisitions | — | (18,237 | ) | — | — | (18,237 | ) | |||||||||||||
Purchase of property and equipment | — | (30,158 | ) | (20,735 | ) | — | (50,893 | ) | ||||||||||||
Net Cash Used in Investing Activities | (11,139 | ) | (55,810 | ) | (20,635 | ) | 11,139 | (76,445 | ) | |||||||||||
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 12 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Nine Months Ended September 30, 2010 (unaudited)
For the Nine Months Ended September 30, 2010 (unaudited)
Allis- | Other | |||||||||||||||||||
Chalmers | Subsidiaries | |||||||||||||||||||
(Parent/ | Subsidiary | (Non- | Consolidating | Consolidated | ||||||||||||||||
Guarantor) | Guarantors | Guarantors) | Adjustments | Total | ||||||||||||||||
Cash Flows from Financing Activities: | ||||||||||||||||||||
Accounts receivable from affiliates | — | (25,492 | ) | (790 | ) | 26,282 | — | |||||||||||||
Accounts payable to affiliates | 26,282 | — | — | (26,282 | ) | — | ||||||||||||||
Notes payable to affiliates | — | — | (8,328 | ) | 8,328 | — | ||||||||||||||
Proceeds from parent contributions | — | 19,467 | — | (19,467 | ) | — | ||||||||||||||
Proceeds from long-term debt | — | — | 4,000 | — | 4,000 | |||||||||||||||
Borrowings under line of credit | 36,500 | — | — | — | 36,500 | |||||||||||||||
Payments on long-term debt | — | (4,646 | ) | (9,942 | ) | — | (14,588 | ) | ||||||||||||
Payment of preferred stock dividend | (1,911 | ) | — | — | — | (1,911 | ) | |||||||||||||
Debt issuance costs | (189 | ) | — | — | — | (189 | ) | |||||||||||||
Net Cash Provided By (Used In) Financing Activities | 60,682 | (10,671 | ) | (15,060 | ) | (11,139 | ) | 23,812 | ||||||||||||
Net change in cash and cash equivalents | — | (24,078 | ) | (1,672 | ) | — | (25,750 | ) | ||||||||||||
Cash and cash equivalents at beginning of period | — | 31,858 | 9,214 | — | 41,072 | |||||||||||||||
Cash and cash equivalents at end of period | $ | — | $ | 7,780 | $ | 7,542 | $ | — | $ | 15,322 | ||||||||||
19
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 12 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2009
December 31, 2009
Allis-Chalmers | Subsidiary | |||||||||||||||||||
(Parent/ | Subsidiary | Non- | Consolidating | Consolidated | ||||||||||||||||
Guarantor) | Guarantors | Guarantors | Adjustments | Total | ||||||||||||||||
Assets | ||||||||||||||||||||
Cash and cash equivalents | $ | — | $ | 31,858 | $ | 9,214 | $ | — | $ | 41,072 | ||||||||||
Trade receivables, net | — | 47,358 | 58,962 | (1,261 | ) | 105,059 | ||||||||||||||
Inventories | — | 16,271 | 18,257 | — | 34,528 | |||||||||||||||
Intercompany receivables | — | 79,521 | 767 | (80,288 | ) | — | ||||||||||||||
Note receivable from affiliate | 28,379 | — | — | (28,379 | ) | — | ||||||||||||||
Prepaid expenses and other | 891 | 6,826 | 9,872 | — | 17,589 | |||||||||||||||
Total current assets | 29,270 | 181,834 | 97,072 | (109,928 | ) | 198,248 | ||||||||||||||
Property and equipment, net | — | 489,921 | 256,557 | — | 746,478 | |||||||||||||||
Goodwill | — | 23,251 | 17,388 | — | 40,639 | |||||||||||||||
Other intangible assets, net | 460 | 25,236 | 6,953 | — | 32,649 | |||||||||||||||
Debt issuance costs, net | 9,408 | 137 | — | — | 9,545 | |||||||||||||||
Note receivable from affiliates | 4,415 | — | — | (4,415 | ) | — | ||||||||||||||
Investments in affiliates | 942,378 | — | — | (942,378 | ) | — | ||||||||||||||
Other assets | 24,366 | 25,039 | 3,656 | — | 53,061 | |||||||||||||||
Total assets | $ | 1,010,297 | $ | 745,418 | $ | 381,626 | $ | (1,056,721 | ) | $ | 1,080,620 | |||||||||
Liabilities and Stockholders’ Equity | ||||||||||||||||||||
Current maturities of long-term debt | $ | — | $ | 4,444 | $ | 12,583 | $ | — | $ | 17,027 | ||||||||||
Trade accounts payable | — | 12,195 | 23,905 | (1,261 | ) | 34,839 | ||||||||||||||
Accrued salaries, benefits and payroll taxes | — | 2,762 | 20,092 | — | 22,854 | |||||||||||||||
Accrued interest | 15,372 | 228 | 221 | — | 15,821 | |||||||||||||||
Accrued expenses | 752 | 11,608 | 9,558 | — | 21,918 | |||||||||||||||
Intercompany payables | 80,288 | — | — | (80,288 | ) | — | ||||||||||||||
Note payable to affiliate | — | — | 28,379 | (28,379 | ) | — | ||||||||||||||
Total current liabilities | 96,412 | 31,237 | 94,738 | (109,928 | ) | 112,459 | ||||||||||||||
Long-term debt, net of current maturities | 430,238 | 19,941 | 25,027 | — | 475,206 | |||||||||||||||
Note payable to affiliate | — | — | 4,415 | (4,415 | ) | — | ||||||||||||||
Other long-term liabilities | — | — | 9,308 | — | 9,308 | |||||||||||||||
Total liabilities | 526,650 | 51,178 | 133,488 | (114,343 | ) | 596,973 | ||||||||||||||
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 | 422,823 | 570,512 | 137,439 | (707,951 | ) | 422,823 | ||||||||||||||
Retained earnings | 25,927 | 120,202 | 67,736 | (187,938 | ) | 25,927 | ||||||||||||||
Total stockholders’ equity | 483,647 | 694,240 | 248,138 | (942,378 | ) | 483,647 | ||||||||||||||
Total liabilities and stockholders’ equity | $ | 1,010,297 | $ | 745,418 | $ | 381,626 | $ | (1,056,721 | ) | $ | 1,080,620 | |||||||||
20
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 12 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended September 30, 2009 (unaudited)
For the Three Months Ended September 30, 2009 (unaudited)
Allis-Chalmers | Subsidiary | |||||||||||||||||||
(Parent/ | Subsidiary | Non- | Consolidating | Consolidated | ||||||||||||||||
Guarantor) | Guarantors | Guarantors | Adjustments | Total | ||||||||||||||||
Revenues | $ | — | $ | 43,797 | $ | 76,840 | $ | (621 | ) | $ | 120,016 | |||||||||
Operating costs and expenses | ||||||||||||||||||||
Direct costs | — | 29,041 | 62,343 | (621 | ) | 90,763 | ||||||||||||||
Selling, general and administrative | 1,043 | 7,243 | 3,144 | — | 11,430 | |||||||||||||||
Depreciation and amortization | 12 | 15,446 | 5,435 | — | 20,893 | |||||||||||||||
Total operating costs and expenses | 1,055 | 51,730 | 70,922 | (621 | ) | 123,086 | ||||||||||||||
Income (loss) from operations | (1,055 | ) | (7,933 | ) | 5,918 | — | (3,070 | ) | ||||||||||||
Other income (expense): | ||||||||||||||||||||
Equity earnings in affiliates, net of tax | 1,499 | — | — | (1,499 | ) | — | ||||||||||||||
Interest, net | (10,109 | ) | 45 | (661 | ) | — | (10,725 | ) | ||||||||||||
Other | 15 | 3 | 19 | — | 37 | |||||||||||||||
Total other income (expense) | (8,595 | ) | 48 | (642 | ) | (1,499 | ) | (10,688 | ) | |||||||||||
Net income (loss) before income taxes | (9,650 | ) | (7,885 | ) | 5,276 | (1,499 | ) | (13,758 | ) | |||||||||||
Provision for income taxes | — | 6,471 | (2,363 | ) | — | 4,108 | ||||||||||||||
Net income (loss) | (9,650 | ) | (1,414 | ) | 2,913 | (1,499 | ) | (9,650 | ) | |||||||||||
Preferred stock dividend | (630 | ) | — | — | — | (630 | ) | |||||||||||||
Net income (loss) attributed to common stockholders | $ | (10,280 | ) | $ | (1,414 | ) | $ | 2,913 | $ | (1,499 | ) | $ | (10,280 | ) | ||||||
21
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 12 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Nine Months Ended September 30, 2009 (unaudited)
For the Nine Months Ended September 30, 2009 (unaudited)
Allis-Chalmers | Subsidiary | |||||||||||||||||||
(Parent/ | Subsidiary | Non- | Consolidating | Consolidated | ||||||||||||||||
Guarantor) | Guarantors | Guarantors | Adjustments | Total | ||||||||||||||||
Revenues | $ | — | $ | 154,502 | $ | 225,013 | $ | (1,891 | ) | $ | 377,624 | |||||||||
Operating costs and expenses | ||||||||||||||||||||
Direct costs | — | 101,284 | 181,743 | (1,891 | ) | 281,136 | ||||||||||||||
Selling, general and administrative | 3,029 | 27,199 | 10,367 | — | 40,595 | |||||||||||||||
Loss on asset disposition | — | — | 1,916 | — | 1,916 | |||||||||||||||
Depreciation and amortization | 35 | 45,629 | 16,155 | — | 61,819 | |||||||||||||||
Total operating costs and expenses | 3,064 | 174,112 | 210,181 | (1,891 | ) | 385,466 | ||||||||||||||
Income (loss) from operations | (3,064 | ) | (19,610 | ) | 14,832 | — | (7,842 | ) | ||||||||||||
Other income (expense): | ||||||||||||||||||||
Equity earnings in affiliates, net of tax | (1,101 | ) | — | — | 1,101 | — | ||||||||||||||
Interest, net | (34,595 | ) | 24 | (2,868 | ) | — | (37,439 | ) | ||||||||||||
Gain on debt extinguishment | 26,365 | — | — | — | 26,365 | |||||||||||||||
Other | 50 | (103 | ) | (178 | ) | — | (231 | ) | ||||||||||||
Total other income (expense) | (9,281 | ) | (79 | ) | (3,046 | ) | 1,101 | (11,305 | ) | |||||||||||
Net income (loss) before income taxes | (12,345 | ) | (19,689 | ) | 11,786 | 1,101 | (19,147 | ) | ||||||||||||
Provision for income taxes | — | 10,517 | (3,715 | ) | — | 6,802 | ||||||||||||||
Net income (loss) | (12,345 | ) | (9,172 | ) | 8,071 | 1,101 | (12,345 | ) | ||||||||||||
Preferred stock dividend | (665 | ) | — | — | — | (665 | ) | |||||||||||||
Net income (loss) attributed to common stockholders | $ | (13,010 | ) | $ | (9,172 | ) | $ | 8,071 | $ | 1,101 | $ | (13,010 | ) | |||||||
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 12 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Nine Months Ended September 30, 2009 (unaudited)
For the Nine Months Ended September 30, 2009 (unaudited)
Allis- | Other | |||||||||||||||||||
Chalmers | Subsidiaries | |||||||||||||||||||
(Parent/ | Subsidiary | (Non- | Consolidating | Consolidated | ||||||||||||||||
Guarantor) | Guarantors | Guarantors) | Adjustments | Total | ||||||||||||||||
Cash Flows from Operating Activities: | ||||||||||||||||||||
Net income (loss) | $ | (12,345 | ) | $ | (9,172 | ) | $ | 8,071 | $ | 1,101 | $ | (12,345 | ) | |||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||||||
Depreciation and amortization | 35 | 45,629 | 16,155 | — | 61,819 | |||||||||||||||
Amortization and write-off of debt issuance costs | 1,682 | 9 | — | — | 1,691 | |||||||||||||||
Stock-based compensation | 3,580 | — | — | — | 3,580 | |||||||||||||||
Allowance for bad debts | — | 4,065 | — | — | 4,065 | |||||||||||||||
Equity earnings in affiliates | 1,101 | — | — | (1,101 | ) | — | ||||||||||||||
Deferred taxes | (11,490 | ) | — | 396 | — | (11,094 | ) | |||||||||||||
(Gain) on sale of equipment | — | (1,059 | ) | (121 | ) | — | (1,180 | ) | ||||||||||||
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 | — | 41,296 | 18,175 | — | 59,471 | |||||||||||||||
Decrease in inventories | — | 2,621 | 1,269 | — | 3,890 | |||||||||||||||
(Increase) decrease in prepaid expenses and other current assets | 7,296 | 2,488 | (6,494 | ) | — | 3,290 | ||||||||||||||
(Increase) decrease in other assets | — | (798 | ) | 2,333 | — | 1,535 | ||||||||||||||
(Decrease) in trade accounts payable | — | (16,979 | ) | (12,056 | ) | — | (29,035 | ) | ||||||||||||
(Decrease) increase in accrued interest | (12,248 | ) | 236 | (467 | ) | — | (12,479 | ) | ||||||||||||
(Decrease) in accrued expenses | (300 | ) | (4,923 | ) | (6,409 | ) | — | (11,632 | ) | |||||||||||
(Decrease) increase in accrued salaries, benefits and payroll taxes | — | (2,050 | ) | 3,278 | — | 1,228 | ||||||||||||||
(Decrease) in other long- term liabilities | — | (57 | ) | (779 | ) | — | (836 | ) | ||||||||||||
Net Cash Provided By (Used In) Operating Activities | (49,054 | ) | 61,306 | 25,267 | — | 37,519 | ||||||||||||||
Cash Flows from Investing Activities: | ||||||||||||||||||||
Investment in affiliates | (4,100 | ) | — | — | 4,100 | — | ||||||||||||||
Notes receivable from affiliates | 693 | — | — | (693 | ) | — | ||||||||||||||
Deposits on asset commitments | — | 7,610 | (556 | ) | — | 7,054 | ||||||||||||||
Purchase of investment interests | (2,393 | ) | — | 1,291 | — | (1,102 | ) | |||||||||||||
Proceeds from sale of property and equipment | — | 7,859 | 121 | — | 7,980 | |||||||||||||||
Proceeds from assets dispositions | — | — | 3,916 | — | 3,916 | |||||||||||||||
Purchase of property and equipment | — | (53,716 | ) | (13,550 | ) | — | (67,266 | ) | ||||||||||||
Net Cash Used in Investing Activities | (5,800 | ) | (38,247 | ) | (8,778 | ) | 3,407 | (49,418 | ) | |||||||||||
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 12 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Nine Months Ended September 30, 2009 (unaudited)
For the Nine Months Ended September 30, 2009 (unaudited)
Allis- | Other | |||||||||||||||||||
Chalmers | Subsidiaries | |||||||||||||||||||
(Parent/ | Subsidiary | (Non- | Consolidating | Consolidated | ||||||||||||||||
Guarantor) | Guarantors | Guarantors) | Adjustments | Total | ||||||||||||||||
Cash Flows from Financing Activities: | ||||||||||||||||||||
Accounts receivable from affiliates | — | (18,637 | ) | — | 18,637 | — | ||||||||||||||
Accounts payable to affiliates | 18,661 | — | (24 | ) | (18,637 | ) | — | |||||||||||||
Notes payable to affiliates | — | — | (693 | ) | 693 | — | ||||||||||||||
Proceeds from parent contributions | — | — | 4,100 | (4,100 | ) | — | ||||||||||||||
Proceeds from issuance of stock, net | 120,337 | — | — | — | 120,337 | |||||||||||||||
Net proceeds from stock incentive plans | 14 | — | — | — | 14 | |||||||||||||||
Proceeds from long-term debt | — | 25,000 | — | — | 25,000 | |||||||||||||||
Net repayment under line of credit | (36,500 | ) | — | — | — | (36,500 | ) | |||||||||||||
Payments on long-term debt | (47,167 | ) | (3,011 | ) | (11,361 | ) | — | (61,539 | ) | |||||||||||
Debt issuance costs | (491 | ) | (153 | ) | — | — | (644 | ) | ||||||||||||
Net Cash Provided By (Used In) Financing Activities | 54,854 | 3,199 | (7,978 | ) | (3,407 | ) | 46,668 | |||||||||||||
Net change in cash and cash equivalents | — | 26,258 | 8,511 | — | 34,769 | |||||||||||||||
Cash and cash equivalents at beginning of period | — | 2,923 | 3,943 | — | 6,866 | |||||||||||||||
Cash and cash equivalents at end of period | $ | — | $ | 29,181 | $ | 12,454 | $ | — | $ | 41,635 | ||||||||||
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 13 — 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 Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Revenues: | ||||||||||||||||
Oilfield Services | $ | 56,705 | $ | 31,904 | $ | 146,070 | $ | 105,827 | ||||||||
Drilling and Completion | 96,295 | 76,299 | 280,772 | 223,237 | ||||||||||||
Rental Services | 21,288 | 11,813 | 46,460 | 48,560 | ||||||||||||
$ | 174,288 | $ | 120,016 | $ | 473,302 | $ | 377,624 | |||||||||
Operating Income (Loss): | ||||||||||||||||
Oilfield Services | $ | 7,462 | $ | (4,211 | ) | $ | 7,969 | $ | (15,701 | ) | ||||||
Drilling and Completion | 5,125 | 5,508 | 17,640 | 14,420 | ||||||||||||
Rental Services | 3,337 | (1,218 | ) | 1,596 | 3,318 | |||||||||||
General corporate | (4,379 | ) | (3,149 | ) | (12,278 | ) | (9,879 | ) | ||||||||
$ | 11,545 | $ | (3,070 | ) | $ | 14,927 | $ | (7,842 | ) | |||||||
Depreciation and Amortization: | ||||||||||||||||
Oilfield Services | $ | 7,925 | $ | 8,077 | $ | 23,622 | $ | 22,825 | ||||||||
Drilling and Completion | 6,793 | 5,462 | 19,619 | 16,182 | ||||||||||||
Rental Services | 7,565 | 7,281 | 21,929 | 22,580 | ||||||||||||
General corporate | 66 | 73 | 196 | 232 | ||||||||||||
$ | 22,349 | $ | 20,893 | $ | 65,366 | $ | 61,819 | |||||||||
Capital Expenditures: | ||||||||||||||||
Oilfield Services | $ | 7,339 | $ | 1,348 | $ | 18,370 | $ | 9,408 | ||||||||
Drilling and Completion | 8,371 | 7,067 | 20,212 | 50,775 | ||||||||||||
Rental Services | 3,840 | 851 | 11,592 | 7,042 | ||||||||||||
General corporate | 354 | 7 | 719 | 41 | ||||||||||||
$ | 19,904 | $ | 9,273 | $ | 50,893 | $ | 67,266 | |||||||||
Revenues: | ||||||||||||||||
United States | $ | 75,833 | $ | 37,625 | $ | 182,756 | $ | 140,448 | ||||||||
Argentina | 77,115 | 65,192 | 226,140 | 180,846 | ||||||||||||
Brazil | 10,031 | 11,034 | 30,033 | 31,812 | ||||||||||||
Other international | 11,309 | 6,165 | 34,373 | 24,518 | ||||||||||||
$ | 174,288 | $ | 120,016 | $ | 473,302 | $ | 377,624 | |||||||||
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ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 13 — SEGMENT INFORMATION (Continued)
As of | ||||||||
September 30, | December 31, | |||||||
2010 | 2009 | |||||||
Goodwill: | ||||||||
Oilfield Services | $ | 23,250 | $ | 23,250 | ||||
Drilling and Completion | 17,389 | 17,389 | ||||||
Rental Services | 5,534 | — | ||||||
$ | 46,173 | $ | 40,639 | |||||
Assets: | ||||||||
Oilfield Services | $ | 256,828 | $ | 255,899 | ||||
Drilling and Completion | 472,059 | 441,482 | ||||||
Rental Services | 315,827 | 307,283 | ||||||
General corporate | 58,423 | 75,956 | ||||||
$ | 1,103,137 | $ | 1,080,620 | |||||
Long Lived Assets: | ||||||||
United States | $ | 579,173 | $ | 572,727 | ||||
Argentina | 165,290 | 168,681 | ||||||
Brazil | 89,970 | 82,477 | ||||||
Other international | 62,989 | 58,487 | ||||||
$ | 897,422 | $ | 882,372 | |||||
NOTE 14 — LEGAL MATTERS
Shortly following the announcement of the merger agreement, ten putative stockholder class-action petitions and compliants were filed against various combinations of us, members of our board of directors, Seawell, and Wellco. Seven of the lawsuits were filed in the District Court of Harris County, Texas, which we refer to as the Texas Actions, and three lawsuits were filed in the Court of Chancery of the State of Delaware, which we refer to as the Delaware Actions. These lawsuits challenge the proposed merger and generally allege, among other things, that our directors have breached their fiduciary duties owed to our public stockholders by approving the proposed merger and failing to take steps to maximize our value to our public stockholders, that we, Seawell, and Wellco aided and abetted such breaches of fiduciary duties, and that the merger agreement unreasonably dissuades potential suitors from making competing offers and restricts us from considering competing offers. The lawsuits generally seek, among other things, compensatory damages, attorneys’ and experts’ fees, declaratory and injunctive relief concerning the alleged breaches of fiduciary duties, and injunctive relief prohibiting the defendants from consummating the merger.
Various plaintiffs in the Texas Actions filed competing motions to consolidate the suits, to appoint their counsel as interim class counsel and to compel expedited discovery. On September 16, 2010, the defendants filed joint motions to stay the Texas Actions in favor of a first-filed Delaware lawsuit, and opposing the motions for expedited discovery. There is no hearing date set for these motions.
On September 21, 2010, the plaintiffs in the Delaware Actions wrote the court seeking consolidation of the Delaware cases. Defendants did not oppose consolidation and took no position regarding lead plaintiff. On September 29, 2010, the Delaware court granted the motion to consolidate. Previously, on September 16, 2010, Seawell and Wellco answered the first-filed Girard Complaint, which is the operative complaint post-consolidation. We answered the consolidated complaint on October 4, 2010.
We believe all of these lawsuits are without merit and intend to defend them vigorously.
In addition, we are named from time to time in legal proceedings related to our activities prior to our bankruptcy in 1988. However, we believe that we were discharged from liability for all such claims in the bankruptcy and believe the likelihood of a material loss relating to any such legal proceeding is remote. We are also involved in various other legal proceedings in the ordinary course of business. The legal proceedings are at different stages; however, we believe that the likelihood of material loss relating to any such legal proceeding is remote.
26
Table of Contents
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTSOF 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 39.
Overview of Our Business
We are 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, Louisiana, Pennsylvania, Arkansas, West Virginia, Oklahoma, Colorado, 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.
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.
Merger Agreement with Seawell
On August 12, 2010, we entered into an Agreement and Plan of Merger with Seawell Limited, or Seawell, pursuant to which we will merge with and into a wholly owned subsidiary of Seawell, and each share of our common stock will be converted into the right to receive either 1.15 Seawell common shares, subject to adjustment to 1.20 Seawell common shares under certain circumstances, or $4.25 in cash. Completion of the merger is subject to customary closing conditions, including, but not limited to, (i) approval of the merger by our stockholders, (ii) applicable regulatory approvals, (iii) the effectiveness of a registration statement on Form F-4 relating to the Seawell common stock to be issued in the merger, and (iv) the listing of the Seawell common stock on the OSLO Stock Exchange.
Under the terms of the merger agreement, we agreed to conduct our business in the ordinary course while the merger is pending, and to generally refrain, without the consent of Seawell, from entering into new lines of business, incurring new indebtedness, issuing new common stock or equity awards, or entering into new material contracts or commitments outside the normal course of business. We recorded approximately $0.6 million of costs related to the merger during the three months ended September 30, 2010, which are included in selling, general and administrative expense on our Consolidated Statements of Operations. If and when the merger is approved or completed, certain contractual obligations of ours will or may be triggered or accelerated under the “change of control” provisions of such contractual arrangements. Examples of such arrangements include stock-based compensation awards, severance and retirement plan agreements applicable to executive officers, directors and certain employees and certain other debt obligations, including our senior notes.
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Our Industry
The oilfield services industry is highly cyclical. Demand for our products and services is substantially dependent upon activity levels in the oil and natural gas industry, particularly our customers’ willingness to spend capital on the exploration for and development of oil and natural gas reserves. 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. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices. As a result, demand for our products and services are highly sensitive to current and expected oil and natural gas prices. Other factors that can affect our business and financial results include the general global economic environment and regulatory changes in the United States and internationally.
Company Outlook
Throughout the first half of 2009, we saw a significant decline in the global economy which led to reduced activity in the energy sector. This reduced activity in the energy sector resulted in lower demand for our services and we incurred significant losses. Since the second quarter of 2009, we have experienced quarter over quarter improvement in both our total revenues and total operating income which has resulted in reduced net losses.
On April 20, 2010, a fire and explosion occurred onboard the semisubmersible drilling rig Deepwater Horizon, which was owned by Transocean Ltd. and under contract to a subsidiary of BP plc. The accident resulted in the loss of life and a significant oil spill. In response to this incident, the Minerals Management Service of the U.S. Department of Interior, or the MMS, issued a notice on May 30, 2010 implementing a six-month moratorium on certain drilling activities in the U.S. Gulf of Mexico. The notice also stated that the MMS would not consider drilling permits for new wells and related activities for specified water depths during the six-month moratorium period. In addition, entities in the process of drilling wells covered by the moratorium were required to halt drilling and take steps to secure such wells. On June 22, 2010, the U.S. District Court for the Eastern District of Louisiana issued a preliminary injunction prohibiting the enforcement of the moratorium, which the Department of the Interior appealed to the Fifth Circuit Court of Appeals. On July 8, 2010, the court of appeals denied the government’s request that the district court’s order be stayed while the appeal was pending.
On July 12, 2010, the Secretary of the Department of the Interior directed the Bureau of Ocean Energy Management, Regulation and Enforcement, or the BOEM (successor to the MMS), to issue a revised suspension of drilling activities for specified drilling configurations and technologies, rather than a moratorium based on water depths. The revised suspension is to last until November 30, 2010 or such earlier date as the U.S. Secretary of the Interior determines that the suspended operations can proceed safely. On August 16, 2010, the BOEM announced that it would restrict the use of certain categorical exclusions to environmental regulations for deepwater exploration while it analyzes the environmental impact of deepwater operations. On September 30, 2010, the BOEM announced two new rules, the Drilling Safety Rule and the Workplace Safety Rule, which are intended to strengthen requirements for safety equipment, well control systems and blowout prevention practices on offshore oil and natural gas operations, and to improve workplace safety by reducing the risk of human error. On October 12, 2010, the moratorium was lifted, and deepwater oil and natural gas drilling in the U.S. Gulf of Mexico has been allowed to resume, provided that operators certify compliance with all existing rules and requirements, including those that recently went into effect, and demonstrate the availability of adequate blowout containment resources.
Although the moratorium on oil and natural gas drilling in the U.S. Gulf of Mexico has been lifted, the BOEM is expected to continue to issue new guidelines and may take other steps that could increase the costs of exploration and production, reduce the area of operations and result in permitting delays. These may include new or additional bonding and safety requirements, and other requirements regarding certification of equipment. The enactment of stricter restrictions on offshore drilling or further regulation of offshore drilling or contracting services operations could materially affect our business, financial condition and results of operations.
We believe that our revenues and operating income for all of our segments for the fourth quarter of 2010 will be similar to our revenues and operating income for the third quarter of 2010. Our Oilfield Services segment is heavily dependent on oil and natural gas activity in the U.S. and a good indicator of that activity is the U.S. rig count. The Baker Hughes rig count in the U.S. for the first forty-three weeks of 2010 increased to an average of 1,514 compared to an average of 1,079 for the first forty-three weeks of 2009. This favorable trend in rig count is resulting in improved demand and pricing for our Oilfield Services segment. Our revenues and operating income in our Oilfield Services segment for the nine months ended September 30, 2010 exceed our revenues and operating income for that segment for the year ended December 31, 2009. Although the market for our drilling services in Brazil in 2010 has been slowed and remains price sensitive, we anticipate our Drilling and Completion segment will exceed 2009 results for both revenue and operating income as drilling activity in Argentina has improved with all of our available rigs in Argentina and Bolivia being utilized. However, we have two 1600 horsepower land drilling rigs under construction in the U.S. which we expect will be completed and delivered during the fourth quarter of 2010. Currently, we have no firm commitments of work for these two drilling rigs and we expect to incur start-up costs in the fourth quarter of 2010 as we get one or more of the rigs ready to operate in 2011. We have two additional rigs, which were substantially completed in
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2009, at a different manufacturer’s facility due to design or engineering problems encountered. We are currently in discussions with the manufacturer to resolve these issues and at this time we cannot be assured that these rigs will not require significant expenditures to bring them to satisfactory operational standards or that we will not incur a loss upon settlement. Our Rental Services segment has historically been very dependent on drilling activity in the U.S. Gulf of Mexico. The Baker Hughes average rig count in the U.S. Gulf of Mexico for the first forty-three weeks of 2010 decreased to 32 rigs compared to an average of 44 rigs for the first forty-three weeks of 2009. As of October 15, 2010, the Baker Hughes rig count in the U.S. Gulf of Mexico was 21 as a result of the effects of the oil spill in the U.S. Gulf of Mexico. Due to the decline in drilling activity in the Gulf of Mexico since the hurricanes in 2007, we had already begun to shift our focus to serving the onshore unconventional natural gas markets and redeploying rental equipment to the international markets such as Brazil, Saudi Arabia and Egypt. This strategy has partially offset the impact of decreased activity in the Gulf of Mexico on our Rental Services segment, and we believe that revenues and operating income for the year ended December 31, 2010 for our Rental Services segment will be improved compared to 2009 levels.
Our selling, general and administrative expenses for the nine months ended September 30, 2010 are less than the selling, general and administrative expenses in the comparable period in the prior year, because of $4.1 million in bad debt expense included for the nine months ended September 30, 2009 compared to $43,000 in bad debt expense in the nine months ended September 30, 2010. We expect our selling, general and administrative expenses for the fourth quarter of 2010 to be higher than the selling, general and administrative expenses for the fourth quarter of 2009 and expect selling, general and administrative expenses to be similar between the years ended December 31, 2010 and 2009. The expected increase in selling, general and administrative expenses in the fourth quarter of 2010 is due to costs related to our pending merger and because the fourth quarter of 2009 included a reversal of $1.8 million of bad debt expense.
Our net interest expense is dependent upon our level of debt and cash on hand, which are principally dependent on acquisitions we complete, our capital expenditures and our cash flows from operations. We expect our interest expense for 2010 to be below 2009 levels, but we do anticipate interest expense in the fourth quarter of 2010 to be higher than the fourth quarter of 2009 due to increased borrowings. We do not anticipate having the ability to record a gain on debt extinguishment in 2010 as our senior notes are trading close to or in excess of face value due to the pending merger.
As we incur more non-deductible merger related expenses, we anticipate our effective tax rate applied to our expected pre-tax income for the fourth quarter of 2010 to be greater than the effective tax rate of our tax benefit from losses generated in the first half of 2010. The effective tax rate is affected by the profitability and effective income tax rate of our operations in foreign jurisdictions which are effected by withholding taxes in excess of statutory income tax rates.
Our operating income is principally dependent on our level of revenues and the pricing environment of our services. In addition, demand for our services is dependent upon our customers’ capital spending plans, which are largely driven by current commodity prices and their expectations of future commodity prices.
Although 2010 has been a challenging year for our operations, increased rig count has increased the utilization and pricing for our equipment and services. We believe our cost cuts in 2009, our strategy of international growth, our commitment to offer new equipment and technology to our customers and our focus on the U.S. land shale plays will continue to result in improvements to our operating results for the remainder of 2010.
Results of Operations
In July 2010, we acquired all of the outstanding stock of American Well Control, Inc., or AWC, which is reported as part of our Rental Services segment. We consolidated the results of this transaction from the date it was effective.
The foregoing acquisition affects the comparability from period to period of our historical results, and our historical results may not be indicative of our future results.
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Comparison of Three Months Ended September 30, 2010 and 2009
Our revenues for the three months ended September 30, 2010 were $174.3 million, an increase of 45.2% compared to $120.0 million for the three months ended September 30, 2009. The increase in revenues is due to the increase in revenues in all of our operating segments. Our Oilfield Services segment revenues increased 77.7% to $56.7 million for the three months ended September 30, 2010 compared to $31.9 million for the three months ended September 30, 2009 due to increased utilization of our equipment and improved pricing. Our Drilling and Completion segment revenues increased 26.2% to $96.3 million for three months ended September 30, 2010 compared to $76.3 million for the three months ended September 30, 2009. The increase in revenues in our Drilling and Completion segment was due to increased utilization and rig rates in Argentina and Bolivia. Revenues for our Rental Services segment increased 80.2% to $21.3 million for the three months ended September 30, 2010 compared to $11.8 million for the three months ended September 30, 2009 due to $6.8 million of revenues from AWC since the date of acquisition, along with an increased emphasis of providing rental services in the domestic onshore unconventional natural gas markets which offset decreased equipment utilization in the U.S. Gulf of Mexico.
Our direct costs for the three months ended September 30, 2010 increased 40.6% to $127.6 million, or 73.2% of revenues, compared to $90.8 million, or 75.6%, of revenues for the three months ended September 30, 2009. Our direct costs in all of our segments increased in absolute dollars in the three months ended September 30, 2010 compared to the three months ended September 30, 2009. Our Oilfield Services segment revenues for the three months ended September 30, 2010 increased 77.7% from revenues for the three months ended September 30, 2009, while direct costs increased 57.9% over that same period, resulting in an improvement in gross margin as a percentage of revenues to 32.7% for the three months ended September 30, 2010 compared to 24.2% for the three months ended September 30, 2009. Our Oilfield Services segment began to realize price increases starting in the later part of the first quarter of 2010. Our Drilling and Completion segment revenues for the three months ended September 30, 2010 increased 26.2% from revenues for the three months ended September 30, 2009, while direct costs increased 29.4% over that same period, resulting in a reduction in gross margin as a percentage of revenues to 16.5% for the three months ended September 30, 2010 compared to 18.5% for the three months ended September 30, 2009. The reduction in the gross margin percentage in our Drilling and Completion segment is due to a decrease in utilization and pricing for our services in Brazil. Our Rental Services segment revenues for the three months ended September 30, 2010 increased 80.2% from revenues for the three months ended September 30, 2009, while direct costs increased 104.4% over that same period. While the acquisition of AWC provided $6.8 million of revenues during the three months ended September 30, 2010 it also increased direct costs by $4.1 million for the same period for an effective gross margin as a percentage of revenues of 40.6%. AWC’s gross margin as a percentage of revenues is less than our overall Rental Services gross margin percentage as AWC’s manufacturing operation has a higher labor component. In addition, we realize lower margins on revenues from land drilling utilization of our equipment as compared to revenues generated in the Gulf of Mexico as the average term of deployment of the assets is greater when utilized offshore and requires less handling. Gross margin as a percentage of revenues for our Rental Services segment for the three months ended September 30, 2010 was 57.8% compared to 62.8% for the three months ended September 30, 2009.
Depreciation expense increased 7.0% to $21.1 million for the three months ended September 30, 2010 from $19.7 million for the three months ended September 30, 2009. The increase in depreciation expense is primarily due to our capital expenditure programs for our Drilling and Completion segment. Depreciation expense as a percentage of revenues decreased to 12.1% for the third quarter of 2010, compared to 16.4% for the third quarter of 2009, due to the increase in our revenues.
Selling, general and administrative expense was $12.8 million for the three months ended September 30, 2010 compared to $11.4 million for the three months ended September 30, 2009. Selling, general and administrative expense increased primarily due to an increase in professional fees for the three months ended September 30, 2010 compared to the same period of the prior year. Professional fees for the three months ended September 30, 2010 included $578,000 of costs related to the pending merger, $140,000 of costs related to the acquisition of AWC and a $225,000 lawsuit settlement. As a percentage of revenues, selling, general and administrative expense was 7.3% for the three months ended September 30, 2010 compared to 9.5% for the same period in the prior year.
Amortization expense for the three months ended September 30, 2010 increased $71,000 to $1.3 million compared to $1.2 million for the three months ended September 30, 2009. The increase is primarily related to the amortization of intangibles recorded in connection with the acquisition of AWC.
We had $11.5 million in income from operations for the three months ended September 30, 2010, compared to a $3.1 million loss from operations for the three months ended September 30, 2009, for a total increase of $14.6 million. The income from operations in the third quarter of 2010 is due to the improvement in the performance of our Oilfield Services and Rental Services segments offset by a decrease in income from operations of our Drilling and Completion segment.
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Our interest expense was $11.9 million for the three months ended September 30, 2010, compared to $10.8 million for the three months ended September 30, 2009. During the three months ended September 30, 2010 we had borrowings of $36.5 million under our revolving credit facility compared to no borrowings at September 30, 2009. Of the $36.5 million borrowed under our revolving credit facility, $16.5 million was borrowed on the date we acquired AWC. Interest expense includes amortization expense of deferred financing costs of $555,000 and $539,000 for the three months ended September 30, 2010 and 2009, respectively.
Our income tax expense for the three months ended September 30, 2010 was $1.6 million on a net loss before income taxes, compared to an income tax benefit of $4.1 million for the three months ended September 30, 2009. The difference between the actual and expected income tax benefit as a percentage of our net loss was due to an increase in withholding taxes from foreign operations as a percentage of pre-tax income in the third quarter of 2010 and the effect of nondeductible items on our domestic tax rate. The consolidated effective income tax rate, or income tax benefit rate, is affected by the profitability and effective income tax rate of our operations in foreign jurisdictions.
We had a net loss of $2.6 million for the three months ended September 30, 2010, compared to net loss of $9.7 million for the three months ended September 30, 2009 due to the foregoing reasons.
The net loss attributed to common stockholders for the three months ended September 30, 2010 and 2009 was $3.2 million and $10.3 million, respectively, after $637,000 and $630,000 in preferred stock dividends, respectively. The preferred stock dividend relates to 36,393 shares of $1,000 par value preferred shares at 7.0% issued at the end of June 2009.
The following table compares revenues and income (loss) from operations for each of our business segments for the three months ended September 30, 2010 and 2009. Income (loss) from operations consists of our revenues less direct costs, selling, general and administrative expenses, depreciation and amortization:
Revenues | Income (Loss) from Operations | |||||||||||||||||||||||
Three Months Ended | Three Months Ended | |||||||||||||||||||||||
September 30, | September 30, | |||||||||||||||||||||||
2010 | 2009 | Change | 2010 | 2009 | Change | |||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Oilfield Services | $ | 56,705 | $ | 31,904 | $ | 24,801 | $ | 7,462 | $ | (4,211 | ) | $ | 11,673 | |||||||||||
Drilling and Completion | 96,295 | 76,299 | 19,996 | 5,125 | 5,508 | (383 | ) | |||||||||||||||||
Rental Services | 21,288 | 11,813 | 9,475 | 3,337 | (1,218 | ) | 4,555 | |||||||||||||||||
General corporate | — | — | — | (4,379 | ) | (3,149 | ) | (1,230 | ) | |||||||||||||||
Total | $ | 174,288 | $ | 120,016 | $ | 54,272 | $ | 11,545 | $ | (3,070 | ) | $ | 14,615 | |||||||||||
Oilfield Services
Revenues for our Oilfield Services segment were $56.7 million for the three months ended September 30, 2010, an increase of 77.7%, compared to $31.9 million in revenues for the three months ended September 30, 2009. Income from operations increased $11.7 million and resulted in income from operations of $7.5 million in the third quarter of 2010 compared to loss from operations of $4.2 million in the third quarter of 2009. Our Oilfield Services segment revenues and operating income for the third quarter of 2010 increased compared to the third quarter of 2009 due principally to improved pricing and utilization for our directional drilling services, tubular services and our coiled tubing units. Our capital expenditures in the Oilfield Services segment have emphasized new downhole directional drilling equipment, upgrading coiled tubing units and investing in pressure control units to serve unconventional natural gas drilling activity. Our Oilfield Services segment activity is impacted by the rig count in the U.S. and the Baker Hughes average rig count for the thirteen weeks in the third quarter of 2010 was 1,626 compared to an average rig count of 977 for the thirteen weeks in the third quarter of 2009.
Drilling and Completion
Revenues for the quarter ended September 30, 2010 for the Drilling and Completion segment were $96.3 million, an increase of 26.2%, compared to $76.3 million in revenues for the quarter ended September 30, 2009. In spite of improved rig utilization and pricing for our drilling rigs in Argentina and Bolivia, income from operations decreased to $5.1 million in the third quarter of 2010 compared to $5.5 million in the third quarter of 2009. This reduction was due to: (1) reduced rig utilization and rig rates in Brazil; (2) an increase of $1.3 million, or 24.4%, in depreciation and amortization; (3) increased labor and other costs in Argentina; offset by $1.1 million of severance costs during the three months ended September 30, 2009 related to workforce reductions in Argentina as a result of lower activity at that time. The increase in depreciation and amortization expense was the result of the capital spending programs over the last two years.
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Rental Services
Revenues for the quarter ended September 30, 2010 for the Rental Services segment increased 80.2% to $21.3 million from $11.8 million in revenues for the quarter ended September 30, 2009. Income from operations increased to $3.3 million in the third quarter of 2010 compared to $1.2 million operating loss in the third quarter of 2009. The acquisition of AWC provided our Rental Services segment with $6.8 million of additional revenues and $2.4 million of additional operating income during the third quarter of 2010. Our Rental Services segment revenues and operating income for the third quarter of 2010 also increased compared to the prior year due to our strategy of redeploying equipment and focusing our marketing efforts from the U.S. Gulf of Mexico to the onshore unconventional natural gas fields in the U.S. We have concentrated our capital expenditures in the Rental Services segment on equipment that is in strong demand in the unconventional gas shale plays in the U.S. and therefore has high utilization and improved pricing.
General Corporate
General corporate expenses increased $1.2 million to $4.4 million for the three months ended September 30, 2010 compared to $3.1 million for the three months ended September 30, 2009. The increase was due to an increase in professional fees for the three months ended September 30, 2009. Professional fees for the three months ended September 30, 2010 included $578,000 of costs related to the pending merger, $140,000 of costs related to the acquisition of AWC and a $225,000 lawsuit settlement.
Comparison of Nine Months Ended September 30, 2010 and 2009
Our revenues for the nine months ended September 30, 2010 were $473.3 million, an increase of 25.3% compared to $377.6 million for the nine months ended September 30, 2009. The increase in revenues is due to the increase in revenues in our Oilfield Services and Drilling and Completion segments, offset in part by a decrease in revenues in our Rental Services segment. Our Oilfield Services segment revenues increased 38.0% to $146.1 million for the nine months ended September 30, 2010 compared to $105.8 million for the nine months ended September 30, 2009 due to increased utilization of our equipment and improved pricing compared to the nine months ended September 30, 2009. Our Drilling and Completion segment revenues increased 25.8% to $280.8 million for the nine months ended September 30, 2010 compared to $223.2 million for the nine months ended September 30, 2009. The increase in revenues in our Drilling and Completion segment was due to increased utilization and rig rates in Argentina and Bolivia. Revenues for our Rental Services segment decreased 4.3% to $46.5 million for the nine months ended September 30, 2010 compared to $48.6 million for the nine months ended September 30, 2009 due to decreased equipment utilization due to a decline in drilling activity in the U.S. Gulf of Mexico compared to the nine months ended September 30, 2009.
Our direct costs for the nine months ended September 30, 2010 increased 26.7% to $356.1 million, or 75.2% of revenues, compared to $281.1 million, or 74.4% of revenues for the nine months ended September 30, 2009. Our direct costs in all of our segments increased in absolute dollars in the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009. Our Oilfield Services segment revenues for the nine months ended September 30, 2010 increased 38.0% from revenues for the nine months ended September 30, 2009, while direct costs increased 24.9% over that same period, resulting in an improvement in gross margin as a percentage of revenues to 28.3% for the nine months ended September 30, 2010 compared to 20.8% for the nine months ended September 30, 2009. Our Oilfield Services segment began to realize price increases starting in the later part of the first quarter of 2010. In addition, we had $1.2 million of expenses recorded during the nine months ended September 30, 2009 related to severance payments, the closing of unprofitable locations and downsizing other locations. Our Drilling and Completion segment revenues for the nine months ended September 30, 2010 increased 25.8% from revenues for the nine months ended September 30, 2009, while direct costs increased 28.8% over that same period. As a result, direct costs as a percentage of revenues increased to 82.7% for the nine months ended September 30, 2010 compared to 80.8% for the nine months ended September 30, 2009. Our Rental Services segment revenues for the nine months ended September 30, 2010 decreased 4.3% from revenues for the nine months ended September 30, 2009, while direct costs increased 12.3% over that same period. Gross margin as a percentage of revenues for our Rental Services segment for the nine months ended September 30, 2010 was 59.0% compared to 65.0% for the nine months ended September 30, 2009. The AWC acquisition completed in July 2010 contributed $6.8 million in revenues and $4.1 million in direct costs to the Rental Services segment for the nine month period ending September 30, 2010 for an effective gross margin as a percentage of revenues of 40.6%. 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, direct costs associated with the operations of AWC offset direct cost reductions in our other rental activities.
Depreciation expense increased 6.1% to $61.8 million for the nine months ended September 30, 2010 from $58.3 million for the nine months ended September 30, 2009. The increase in depreciation expense is primarily due to our capital expenditure programs for our Drilling and Completion segment. Depreciation expense as a percentage of revenues decreased to 13.1% for the first nine months of 2010, compared to 15.4% for the first nine months of 2009, due to the increase in revenues.
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Selling, general and administrative expense was $36.9 million for the nine months ended September 30, 2010 compared to $40.6 million for the nine months ended September 30, 2009. Selling, general and administrative expense decreased primarily due to a reduction in bad debt expense for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 and cost reduction steps that were made in the nine months ended September 30, 2009 in response to market conditions, offset in part by an increase in the amortization of share-based compensation arrangements and the increase in professional fees related to transactions. During the nine months ended September 30, 2010, we recorded bad debt expense of $43,000 compared to $4.1 million in bad debt expense for the nine months ended September 30, 2009. Professional fees for the nine months ended September 30, 2010 included $578,000 of costs related to the pending merger, $140,000 of costs related to the acquisition of AWC and a $225,000 lawsuit settlement. Selling, general and administrative expense includes share-based compensation expense of $4.4 million in the nine months ended September 30, 2010 and $3.6 million in the nine months ended September 30, 2009. As a percentage of revenues, selling, general and administrative expenses were 7.8% for the nine months ended September 30, 2010 compared to 10.8% for the same period in the prior year.
During the nine months ended September 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 insurance proceeds for the loss were not sufficient to cover the book value of the rig and related assets.
We had income from operations of $14.9 million for the nine months ended September 30, 2010, compared to a $7.8 million loss from operations for the nine months ended September 30, 2009, for a total increase of $22.8 million. The increase in income from operations for the nine months ended September 30, 2010 is due to the improved performance of our Oilfield Services and Drilling and Completion segments, partially offset by a decline in performance of the Rental Services segment. The nine months ended September 30, 2009 was also negatively affected by an additional $4.0 million of bad debt expense, a $1.9 million loss on an asset disposition and $3.2 million of expenses related to severance payments, the closing of unprofitable locations and downsizing other locations.
Our interest expense was $34.0 million for the nine months ended September 30, 2010, compared to $37.5 million for the nine months ended September 30, 2009. On June 29, 2009, we purchased approximately $74.8 million of our senior notes with approximately $125.6 million in proceeds from our backstopped common stock rights offering and preferred stock private placement. On June 29, 2009, we also prepaid our outstanding loan balance under our revolving credit facility of $35.0 million from those same equity proceeds. At September 30, 2010 we had an outstanding loan balance under our revolving credit facility of $36.5 million, all of which had been borrowed during the third quarter of 2010. We borrowed $16.5 million of the $36.5 million borrowed under our revolving credit facility on the date we acquired AWC. Interest expense includes amortization expense of deferred financing costs of $1.7 million for the nine months ended September 30, 2010 and 2009.
During the nine months ended September 30, 2009, we recorded a gain of $26.4 million as a result of tender offers that we completed on June 29, 2009. We purchased approximately $30.6 million aggregate principal amount of our 9.0% senior notes and $44.2 million aggregate principal amount of our 8.5% senior notes for approximately $46.4 million. The gain is net of a $1.5 million write-off of debt issuance costs related to the retired notes and we incurred approximately $466,000 in expenses related to the transactions.
Our income tax benefit for the nine months ended September 30, 2010 was $3.6 million, or 16.9% of our net loss before income taxes, compared to an income tax benefit of $6.8 million, or 35.5% of our net loss before income taxes for the nine months ended September 30, 2009. The decrease in income tax benefit as a percentage of our net loss was due to an increase in withholding taxes from foreign operations as a percentage of pre-tax income in 2010 and the effect of nondeductible items on our domestic tax. The consolidated effective income tax benefit rate is affected by the profitability and effective income tax rate of our operations in foreign jurisdictions.
We had a net loss of $17.5 million for the nine months ended September 30, 2010, compared to net loss of $12.3 million for the nine months ended September 30, 2009 due to the foregoing reasons.
The net loss attributed to common stockholders for the nine months ended September 30, 2010 and 2009 was $19.4 million and $13.0 million, respectively, after $1.9 million and $665,000 in preferred stock dividends, respectively. The preferred stock dividend relates to 36,393 shares of $1,000 par value preferred shares at 7.0% issued at the end of June 2009.
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The following table compares revenues and income (loss) from operations for each of our business segments for the nine months ended September 30, 2010 and 2009. 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 | |||||||||||||||||||||||
Nine Months Ended | Nine Months Ended | |||||||||||||||||||||||
September 30, | September 30, | |||||||||||||||||||||||
2010 | 2009 | Change | 2010 | 2009 | Change | |||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Oilfield Services | $ | 146,070 | $ | 105,827 | $ | 40,243 | $ | 7,969 | $ | (15,701 | ) | $ | 23,670 | |||||||||||
Drilling and Completion | 280,772 | 223,237 | 57,535 | 17,640 | 14,420 | 3,220 | ||||||||||||||||||
Rental Services | 46,460 | 48,560 | (2,100 | ) | 1,596 | 3,318 | (1,722 | ) | ||||||||||||||||
General corporate | — | — | — | (12,278 | ) | (9,879 | ) | (2,399 | ) | |||||||||||||||
Total | $ | 473,302 | $ | 377,624 | $ | 95,678 | $ | 14,927 | $ | (7,842 | ) | $ | 22,769 | |||||||||||
Oilfield Services
Revenues for our Oilfield Services segment were $146.1 million for the nine months ended September 30, 2010, an increase of 38.0% compared to $105.8 million in revenues for the nine months ended September 30, 2009. Income from operations increased $23.7 million and resulted in income from operations of $8.0 million in the first nine months of 2010 compared to a loss from operations of $15.7 million in the first nine months of 2009. Our Oilfield Services segment revenues and operating income for the nine months ended September 30, 2010 increased compared to the nine months ended September 30, 2009 due principally to improved pricing and utilization for our directional drilling services, tubular services and our coiled tubing units. Our capital expenditures in the Oilfield Services segment have emphasized new downhole directional drilling equipment, upgrading coil tubing units and investing in pressure control units to serve unconventional natural gas drilling activity. As stated earlier our Oilfield Services segment activity is tied to the rig count in the U.S. and the Baker Hughes average rig count for the thirty-nine weeks in the first nine months of 2010 was 1,498 compared to an average rig count of 1,067 for the thirty-nine weeks in the first nine months of 2009. During the nine months ended September 30, 2009, we incurred $1.2 million of costs related to severance payments, the closing of unprofitable locations and downsizing other locations in our Oilfield Services segment. In addition, we increased our bad debt reserve by recording $3.1 million of bad debt expense for the Oilfield Services segment during the nine months ended September 30, 2009 as a result of the decreased oil and natural gas prices and the financial difficulties that some of our customers were facing. We recorded $43,000 of bad debt expense for the nine months ended September 30, 2010 for the Oilfield Services segment.
Drilling and Completion
Revenues for the nine months ended September 30, 2010 for the Drilling and Completion segment were $280.8 million, an increase of 25.8% compared to $223.2 million in revenues for the nine months ended September 30, 2009. Income from operations increased to $17.6 million in the first nine months of 2010 compared to $14.4 million for the first nine months of 2009. This increase was due to: (1) improved rig utilization and rig rates in Argentina and Bolivia during the nine months ended September 30, 2010; (2) a $1.9 million non-cash loss recorded in the nine months ended September 30, 2009 on an asset disposition from the total loss of a rig from a blow-out; (3) $1.4 million of severance costs during the nine months ended September 30, 2009 related to workforce reductions in Argentina as a result of lower activity and (4) $329,000 of costs incurred to consolidate operating locations in Brazil during the nine months ended September 30, 2009. Partially offsetting the improved results in the first nine months of 2010 was decreased rig utilization and pricing in Brazil and an increase in depreciation and amortization expense of $3.4 million. The increase in depreciation and amortization was the result of our capital expenditures spending programs over the last two years.
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Rental Services
Revenues for the nine months ended September 30, 2010 for the Rental Services segment were $46.5 million, a decrease of 4.3% from $48.6 million in revenues for the nine months ended September 30, 2009. Our Rental Services segment generated an operating income of $1.6 million in the nine months ended September 30, 2010 compared to $3.3 million operating income for the first nine months of 2009. The decrease in segment revenues and operating income for the first nine months of 2010 compared to the same period of the prior year was due primarily to the decrease in utilization of our rental equipment due to a decline in drilling activity in the U.S. Gulf of Mexico. Offsetting a portion of the impact of the decline was the acquisition of AWC which provided our Rental Services segment with $6.8 million of additional revenues and $2.4 million of additional operating income during the nine months ended September 30, 2010. Also, our income from operations for the nine months ended September 30, 2009 included $950,000 of bad debt expense to increase the bad debt reserve for Rental Services segment customers who were facing financial difficulties, and $237,000 of costs related to closing a rental yard and reducing our workforce. We recorded no bad debt expense for the first nine months of 2010. In addition, depreciation and amortization expense for our Rental Services segment decreased $651,000 or 2.9%, in the first nine months of 2010 compared to the first nine months of 2009 due primarily to a $584,000 reduction in the carrying value of our airplane resulting from the sales proceeds received in April 2009.
General Corporate
General corporate expenses increased $2.4 million to $12.3 million for the nine months ended September 30, 2010 compared to $9.9 million for the nine months ended September 30, 2009. The increase was due to the increase in share-based compensation expense, increased professional fees related to transactions and increased insurance and travel costs to support our international business development initiatives. Share-based compensation expense included in general corporate expenses was $3.4 million in the nine months ended September 30, 2010 compared to $2.8 million in the nine months ended September 30, 2009. Professional fees for the nine months ended September 30, 2010 included $578,000 of costs related to the pending merger, $140,000 of costs related to the acquisition of AWC and a $225,000 lawsuit settlement.
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 Partners V, L.P., or 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 was used to purchase an aggregate of $74.8 million principal amount of our existing senior notes, approximately $35.0 million of the proceeds was used to repay all the borrowings under our revolving bank credit facility, except for $5.1 million in outstanding letters of credit, and the remainder of the proceeds was used for general corporate purposes.
Our on-going capital requirements arise primarily from our need to service our debt, to acquire and maintain equipment, fund our working capital requirements and 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 September 30, 2010, we had $49.5 million available for borrowing under our amended and restated revolving credit facility. Our cash on hand, cash flows from operations and revolving credit facility have been and are expected to continue to be our primary source of liquidity in 2010. We had cash and cash equivalents of $15.3 million at September 30, 2010 compared to $41.1 million at December 31, 2009.
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.
Operating Activities
During the nine months ended September 30, 2010, our operating activities provided $26.9 million in cash. Our net loss for the nine months ended September 30, 2010 was $17.5 million. Non-cash expenses totaled $61.5 million during the first nine months of 2010 consisting of $65.4 million of depreciation and amortization, $4.4 million for share-based compensation expense, $1.7 million in amortization of debt issuance costs, $1.5 million loss on the sale of an investment, $150,000 of losses from asset disposals, $409,000 equity in loss of unconsolidated affiliates, partly offset by deferred income tax benefit of $12.0 million related to timing differences.
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During the nine months ended September 30, 2010, changes in operating assets and liabilities used $17.1 million in cash, principally due to an increase in accounts receivable of $30.4 million, an increase in inventories of $2.7 million, a decrease in accrued interest of $8.9 million and a decrease in other long-term liabilities of $0.7 million, offset in part by an increase in accounts payable of $8.4 million, a decrease in prepaid expenses and other current assets of $8.0 million, an increase in accrued expenses of $5.5 million, an increase in accrued salaries, benefits and payroll taxes of $2.4 million and a decrease in other assets of $1.3 million. Accounts receivable, inventory, accounts payable, accrued expenses and accrued salaries, benefits and payroll taxes increased primarily due to the increase in our activity in the first nine months of 2010. The decrease in prepaid expense assets was the result of current operations in Argentina utilizing the prepaid taxes that existed at December 31, 2009, offset by a non-cash increase in prepaid expenses from the financing of $2.6 million of insurance premiums. Accrued interest decreased due to the scheduled interest payment on our senior notes in July of 2010.
During the nine months ended September 30, 2009, our operating activities provided $37.5 million in cash. Our net loss for the nine months ended September 30, 2009 was $12.3 million. Non-cash expenses totaled $34.4 million during the first nine months of 2009 consisting of $61.8 million of depreciation and amortization, $3.6 million for share-based compensation expense, $1.7 million in amortization of debt issuance costs, $4.1 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, $11.1 million for deferred income taxes related to timing differences and $1.2 million on the gain from asset disposals.
During the nine months ended September 30, 2009, changes in operating assets and liabilities provided $15.4 million in cash, principally due to a decrease in accounts receivable of $59.5 million, a decrease of $3.9 million in inventories and a decrease in prepaid expenses and other current assets of $3.3 million, offset in part by a decrease in accounts payable of $29.0 million, a decrease in accrued interest of $12.5 million and a decrease in accrued expenses of $11.6 million. Accounts receivable, inventory and accounts payable decreased primarily due to the drop in our activity in the first nine 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 nine months of 2009.
Investing Activities
During the nine months ended September 30, 2010, we used $76.4 million in investing activities, consisting of $50.9 million for capital expenditures, $18.2 million net for the acquisition of AWC, $13.0 million for other assets, offset in part by $5.3 million of proceeds from equipment sales and $368,000 from the sale of an investment. Included in the $50.9 million for capital expenditures was $18.4 million for our Oilfield Services segment, $20.2 million for additional equipment in our Drilling and Completion segment and $11.6 million for drill pipe and other equipment used in our Rental Services segment. The increase in other assets was primarily due to $12.7 million of advance payments made toward the construction of two drilling rigs. A majority of our equipment sales relate to items “lost in hole” or “damaged beyond repair” by our customers.
During the nine months ended September 30, 2009, we used $49.4 million in investing activities, consisting of $67.3 million for capital expenditures, $1.1 million of additional investments, offset in part by a decrease of $7.1 million in other assets, $8.0 million of proceeds from equipment sales and $3.9 million in insurance proceeds for a drilling rig destroyed by a blow-out. Included in the $67.3 million for capital expenditures was $9.4 million for our Oilfield Services segment, $37.2 million for our two domestic drilling rigs and $13.6 million for additional equipment in our Drilling and Completion segment and $7.0 million for drill pipe and other equipment used in our Rental Services segment. We contributed $2.4 million of cash and cash expenditures into our investment in our Saudi Arabia joint venture and we received $1.3 million from insurance proceeds related to a pre-acquisition contingency with respect to BCH. The decrease in other assets was due to the conversion 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 $1.6 million of rental assets as part of our investment in our Saudi Arabia joint venture in a non-cash transaction.
Financing Activities
During the nine months ended September 30, 2010, financing activities provided $23.8 million in cash. We borrowed $36.5 million under our revolving credit facility and borrowed an additional $4.0 million under a long-term debt facility and repaid $14.6 million in borrowings under long-term debt facilities. We also incurred $189,000 in debt issuance costs related to an amendment to our revolving credit facility to modify our loan covenants, and we paid $1.9 million in preferred stock dividends. In addition, we financed our renewal of $2.6 million in insurance policy premiums and issued $2.0 million of our common stock in the acquisition of AWC in non-cash transactions.
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During the nine months ended September 30, 2009, financing activities provided $46.7 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 $61.5 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 $15.1 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 $3.2 million in insurance policy premiums in non-cash transactions.
At September 30, 2010, we had $520.7 million in outstanding indebtedness, of which $497.1 million was long-term debt and $23.6 million is due within one year.
On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, of $160.0 and $95.0 million aggregate principal amount of our senior notes, respectively. The senior notes are due January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of Specialty Rental Tools, Inc. 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 approximately $30.6 million aggregate principal amount 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. On June 29, 2009, we closed on a tender offer in which we purchased $44.2 million aggregate principal amount of our 8.5% senior notes for a total consideration of $600 per $1,000 principal amount.
We have a $90.0 million revolving line of credit with a final maturity date of April 26, 2012 pursuant to a revolving credit agreement that 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. On April 9, 2009, we amended our revolving credit agreement to modify the leverage and interest coverage ratio covenants. Effective December 31, 2009, we again amended the leverage and interest coverage ratio covenants of the revolving credit agreement. This amendment relaxed the required financial ratios for the quarter ended December 31, 2009 and for each of the quarters in 2010. 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 September 30, 2010 and December 31, 2009. As of September 30, 2010, we had outstanding borrowing of $36.5 million and $4.0 million in outstanding letters of credit under our revolving credit facility. As of December 31, 2009, the only usage of our revolving credit facility consisted of $4.2 million in outstanding letters of credit. The interest rate under our revolving credit facility is based on prime or LIBOR plus a margin. The credit agreement loan rates are based on prime or LIBOR plus a margin. The weighted-average interest rate was 7.9% at September 30, 2010.
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 two to five years. The weighted-average interest rate on these loans was 2.0% and 2.1% as of September 30, 2010 and December 31, 2009, respectively. The outstanding amount due under these bank loans as of September 30, 2010 and December 31, 2009 was $350,000 and $1.1 million, respectively.
On February 15, 2008, through our DLS subsidiary, 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. The loan is repayable 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 September 30, 2010 and December 31, 2009. The bank loan rates are based on LIBOR plus a margin. The weighted-average interest rate was 4.3% and 4.4% at September 30, 2010 and December 31, 2009, respectively. The outstanding amount under the import finance facility as of September 30, 2010 and December 31, 2009 was $15.5 million and $20.1 million, respectively.
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As part of our acquisition of BCH Ltd, or BCH, we assumed a $23.6 million term loan credit facility with a bank. The BCH credit agreement is dated June 2007 and contains customary events of default and financial covenants which are based on BCH’s stand-alone financial statements. Obligations under the facility are secured by substantially all of the BCH assets. BCH was in compliance with all debt covenants as of December 31, 2009. The bank has waived certain financial ratio covenants for the September 30, 2010 and December 31, 2010 measurement periods. As we cannot be certain that BCH would attain compliance with the covenants within one year, we have classified the entire outstanding balance of the loan in the current portion of long-term debt. The facility is repayable in quarterly principal installments plus interest with the final payment due not later than August 2012. The interest rates under this credit facility are based on LIBOR plus a margin. At September 30, 2010 and December 31, 2009, the outstanding amount of the loan under this credit facility was $11.8 million and $16.2 million, respectively and the interest rate was 3.5%.
On May 22, 2009, we drew down $25.0 million on a 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 September 30, 2010 and December 31, 2009, the outstanding amount of the loan was $20.8 million and $23.4 million, respectively.
On February 9, 2010, through our DLS subsidiary, we entered into a $4.0 million term loan facility. The loan is repayable in semi-annual installments beginning April 14, 2011 and bears interest at 8.5% per annum. The final maturity date is April 14, 2014 and the loan is unsecured.
In 2010, we obtained insurance premium financings in the aggregate amount of $2.6 million with a fixed weighted-average interest rate of 4.8%. Under terms of the agreements, amounts outstanding are paid over an eight and 11 month repayment schedules. The outstanding balance of these notes was approximately $1.5 million at September 30, 2010. In 2009, we obtained insurance premium financings in the aggregate amount of $3.2 million with a fixed weighted-average interest rate of 4.8%. Under terms of the agreements, amounts outstanding are paid over 10 and 11 month repayment schedules. The outstanding balance of these notes was approximately $0 and $997,000 at September 30, 2010 and December 31, 2009, respectively.
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 $16,000 and $254,000 at September 30, 2010 and December 31, 2009, respectively.
Recent Events
In August 2010, we announced that our Board of Directors had approved a definitive merger agreement with Seawell in a transaction valued at approximately $890.0 million. The combined company would operate its Drilling and Well Services offerings with a global footprint covering more than 30 of the world’s key oil and natural gas regions, including the U.S., Gulf of Mexico, Brazil, Argentina, North Sea, Middle East, Africa and Southeast Asia/Pacific. The combined Drilling Services offering would include platform drilling, land contract drilling, modular rigs, maintenance of drilling systems, directional drilling technology, underbalanced drilling, facility engineering services, rig and riser inspections and oilfield rentals. The Well Services offering would include electrical and mechanical wireline services, production logging services, coil tubing services, ultrasonic investigation logging services, down-hole cameras and advanced well fishing services.
The merger is subject to the approval of our stockholders as well as other customary conditions. We anticipate that the transaction will close in early 2011.
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 September 30, 2010 we had a $90.0 million revolving line of credit with a maturity of April 2012. At September 30, 2010, we had $36.5 million of borrowings under the revolving credit facility and we had $4.0 million in outstanding letters of credit.
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Capital Resources
Exclusive of any acquisitions, we currently expect our capital spending for the remainder of 2010 to be approximately $20.0 million depending upon the market demand we experience, our operating performance during the remainder of the year and expenditures that may be associated with potential new contracts. These amounts are net of equipment deposits paid through September 30, 2010. This amount includes budgeted but unidentified expenditures that 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. Our ability to obtain capital for opportunistic acquisitions or additional projects to implement our growth strategy over the longer term will depend upon our future operating performance and financial condition, which will be dependent upon the prevailing conditions in our industry and the global market, including the availability of equity and debt financing, many of which are beyond our control. The pending merger with Seawell, if completed, would provide an additional source of capital.
Critical Accounting Policies
Please see our Annual Report on Form 10-K for the year ended December 31, 2009 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 Management’s Discussion and Analysis of Financial Condition and Results of Operations where such policies affect our reported and expected financial results. No material changes to such information have occurred during the nine months ended September 30, 2010.
Recently Issued Accounting Standards
For a discussion of new accounting standards, see the applicable section in Note 1 to our Unaudited Consolidated Condensed Financial Statements included in “Item 1. Financial Statements.”
For a discussion of new accounting standards, see the applicable section in Note 1 to our Unaudited Consolidated Condensed Financial Statements included in “Item 1. Financial Statements.”
Forward-Looking Statements
This quarterly report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, regarding our business, financial condition, results of operations and prospects. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements. However, these are not the exclusive means of identifying forward-looking statements. Although such forward-looking statements reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. These factors include, but are not limited to, the following:
• | our ability to consummate the merger; | ||
• | the possibility that the merger may involve unexpected costs; | ||
• | difficulties and delays in satisfying the conditions set forth in the merger agreement, including obtaining the necessary regulatory approvals for the merger; | ||
• | the effect of the announcement or completion of the merger on customer and supplier relationships, operating results and business generally; | ||
• | 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; | ||
• | risks that the merger disrupts current plans and operations, and the potential difficulties for employee retention as a result of the announcement or completion of the merger; | ||
• | fluctuations in the price of oil and natural gas; | ||
• | unexpected future capital expenditures (including the amount and nature thereof); | ||
• | unexpected difficulties in integrating our operations as a result of any significant acquisitions; | ||
• | adverse weather conditions in certain regions; | ||
• | the impact of political disturbances, war, or terrorist attacks and changes in global trade policies; | ||
• | the availability (or lack thereof) of capital to fund our business strategy and/or operations; | ||
• | the effect of environmental liabilities that are not covered by an effective indemnity or insurance; | ||
• | the impact of changes in existing, and the imposition of new, laws and governmental regulations; | ||
• | the outcome of any pending or future litigation and administrative claims; | ||
• | the effects of competition; and | ||
• | 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 competitors that have less debt, and could have other adverse consequences. |
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Further information about the risks and uncertainties that may impact us are described under “Item 1A—Risk Factors” included in this report and in our Annual Report on Form 10-K for the year ended December 31, 2009. You should read those sections carefully. You should not place undue reliance on forward-looking statements, which speak only as of the date of this quarterly report. We undertake no obligation to update publicly any forward-looking statements in order to reflect any event or circumstance occurring after the date of this quarterly report or currently unknown facts or conditions or the occurrence of unanticipated events.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are exposed to market risk primarily from changes in interest rates and foreign currency exchange rates.
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 $64.2 million of adjustable rate debt with a weighted-average interest rate of 6.2% at September 30, 2010.
Foreign Currency Exchange Rate Risk.
We have designated the U.S. dollar as the functional currency for our operations in international locations since 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 Operations in the line item labeled Other income (expense).
ITEM 4. CONTROLS AND PROCEDURES.
(a) Evaluation of Disclosure Controls and Procedures.
As of the end of the period covered by this quarterly report, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. This evaluation was carried out under the supervision and with the participation of our management, including our chief executive officer and chief financial officer. Based on this evaluation, these officers have concluded that, as of September 30, 2010, 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 or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s, or SEC’s, rules and forms.
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, 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
ITEM 1. LEGAL PROCEEDINGS.
Shortly following the announcement of the merger agreement, ten putative stockholder class-action petitions and compliants were filed against various combinations of us, members of our board of directors, Seawell, and Wellco. Seven of the lawsuits were filed in the District Court of Harris County, Texas, which we refer to as the Texas Actions, and three lawsuits were filed in the Court of Chancery of the State of Delaware, which we refer to as the Delaware Actions. These lawsuits challenge the proposed merger and generally allege, among other things, that our directors have breached their fiduciary duties owed to our public stockholders by approving the proposed merger and failing to take steps to maximize our value to our public stockholders, that we, Seawell, and Wellco aided and abetted such breaches of fiduciary duties, and that the merger agreement unreasonably dissuades potential suitors from making competing offers and restricts us from considering competing offers. The lawsuits generally seek, among other things, compensatory damages, attorneys’ and experts’ fees, declaratory and injunctive relief concerning the alleged breaches of fiduciary duties, and injunctive relief prohibiting the defendants from consummating the merger.
Various plaintiffs in the Texas Actions filed competing motions to consolidate the suits, to appoint their counsel as interim class counsel and to compel expedited discovery. On September 16, 2010, the defendants filed joint motions to stay the Texas Actions in favor of a first-filed Delaware lawsuit, and opposing the motions for expedited discovery. There is no hearing date set for these motions.
On September 21, 2010, the plaintiffs in the Delaware Actions wrote the court seeking consolidation of the Delaware cases. Defendants did not oppose consolidation and took no position regarding lead plaintiff. On September 29, 2010, the Delaware court granted the motion to consolidate. Previously, on September 16, 2010, Seawell and Wellco answered the first-filed Girard Complaint, which is the operative complaint post-consolidation. We answered the consolidated complaint on October 4, 2010.
We believe all of these lawsuits are without merit and intend to defend them vigorously.
ITEM 1A. RISK FACTORS.
Except as set forth in the following 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, 2009.
The recent Deepwater Horizon incident in the U.S. Gulf of Mexico and its consequences, including the potential enactment of further restrictions or regulations on offshore drilling, could have a material adverse effect on our business.
On April 20, 2010, a fire and explosion occurred onboard the semisubmersible drilling rig Deepwater Horizon, which was owned by Transocean Ltd. and under contract to a subsidiary of BP plc. The accident resulted in the loss of life and a significant oil spill. In response to this incident, the Minerals Management Service of the U.S. Department of Interior, or the MMS, issued a notice on May 30, 2010 implementing a six-month moratorium on certain drilling activities in the U.S. Gulf of Mexico. The notice also stated that the MMS would not consider drilling permits for new wells and related activities for specified water depths during the six-month moratorium period. In addition entities in the process of drilling wells covered by the moratorium were required to halt drilling and take steps to secure the well. On June 22, 2010, the U.S. District Court for the Eastern District of Louisiana issued a preliminary injunction prohibiting the enforcement of the moratorium, which the Department of the Interior appealed to the Fifth Circuit Court of Appeals. On July 8, 2010, the court of appeals denied the government’s request that the district court’s order be stayed while the appeal is pending.
On July 12, 2010, the Secretary of the Department of the Interior directed the Bureau of Ocean Energy Management, Regulation and Enforcement, or the BOEM (successor to the MMS), to issue a revised suspension of drilling activities for specified drilling configurations and technologies, rather than a moratorium based on water depths. The revised suspension is to last until November 30, 2010 or such earlier date as the U.S. Secretary of the Interior determines that the suspended operations can proceed safely. On August 16, 2010, the BOEM announced that it would restrict the use of certain categorical exclusions to environmental regulations for deepwater exploration while it analyzes the environmental impact of deepwater operations. On September 30, 2010, the BOEM announced two new rules, the Drilling Safety Rule and the Workplace Safety Rule, which are intended to strengthen requirements for safety equipment, well control systems and blowout prevention practices on offshore oil and natural gas operations, and to improve workplace safety by reducing the risk of human error. On October 12, 2010, the moratorium was lifted, and deepwater oil and natural gas drilling in the U.S. Gulf of Mexico has been allowed to resume, provided that operators certify compliance with all existing rules and requirements, including those that recently went into effect, and demonstrate the availability of adequate blowout containment resources.
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Our business has historically been very dependent on drilling activity in the U.S. Gulf of Mexico. Although the moratorium on oil and natural gas drilling in the U.S. Gulf of Mexico has been lifted, the BOEM is expected to continue to issue new guidelines and may take other steps that could increase the costs of exploration and production, reduce the area of operations and result in permitting delays. These may include new or additional bonding and safety requirements and other requirements regarding certification of equipment. The enactment of stricter restrictions on offshore drilling or further regulation of offshore drilling or contracting services operations could materially affect our business, financial condition and results of operations.
We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition and results of operations.
We provide services and equipment to oil and natural gas exploration and production companies. These operations are subject to inherent hazards that can cause personal injury or loss of life, damage to or destruction of property, equipment, the environment and marine life, and suspension of operations. Substantially all of our Drilling and Completion operations are subject to hazards that are customary for oil and natural gas drilling operations, including blowouts, reservoir damage, loss of well control, cratering, oil and gas well fires and explosions, natural disasters, pollution and mechanical failure. Any of these risks could result in damage to or destruction of drilling equipment, personal injury and property damage, suspension of operations or environmental damage.
We operate with our customers through Master Service Agreements, or MSAs. We endeavor to allocate potential liabilities and risks between the parties in the MSAs. Generally, our MSAs contain indemnification to us for liability for pollution or environmental claims arising from subsurface conditions or resulting from the drilling activities of our customers or their operators. We may have liability in such cases if we are grossly negligent or commit willful acts. In addition, any liability may be capped for either party to an MSA. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death, unless resulting from our gross negligence or willful misconduct. Similarly, we agree to indemnify our customers for liabilities arising from personal injury or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers agree to indemnify us for loss or destruction of customer-owned property or equipment, and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. However, for equipment we rent to our customers, our contracts generally provide that the customer is responsible for the replacement of any damaged or lost equipment in their care. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation or we might incur an unforeseen liability falling outside the scope of such allocation.
Litigation arising from an accident at a location where our products or services are used or provided may cause us to be named as a defendant in lawsuits asserting potentially large claims. We maintain customary insurance to protect our business against these potential losses. Our general liability policy would cover claims where we agreed to indemnify the customer, subject to any typical exclusions that may exist under the policy. However, we could become subject to material uninsured liabilities that could have a material adverse effect on our financial condition and results of operations. The limits and deductibles for our general liability policy are as follows:
• | General Aggregate $2,000,000; | ||
• | Products/Completed Operations Aggregate $2,000,000; | ||
• | Occurrence Limit $1,000,000; | ||
• | Personal/Advertising Injury Limit $1,000,000; | ||
• | Deductible (Bodily Injury & Property Damage Combined) Per Claim $100,000. |
In addition, our general liability policy is scheduled under a $30.0 million umbrella/excess liability policy (subject to the policy’s terms, conditions and exclusions). We also have workers compensation insurance coverage up to $1,000,000.
We have a contractors pollution liability policy of $10.0 million which has a $200,000 deductible, and all environmental claims would be subject to the terms, conditions and exclusions of that policy. Our umbrella policy does not apply to the contractors pollution liability policy.
There is no assurance that such insurance or indemnification agreements will adequately protect us against liability from all of the consequences of the hazards and risks described above. The occurrence of an event not fully insured or for which we are not indemnified against, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, there can be no assurance that insurance will continue to be available to cover any or all of these risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future so as to make the cost of such insurance prohibitive.
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Risks Related to the Merger
Our ability to complete the merger is subject to stockholder approval, certain closing conditions and the receipt of consents and approvals from government entities which may impose conditions that could adversely affect us or cause the merger to be abandoned.
The merger is subject to certain closing conditions, including approval of the merger by our stockholders, the absence of injunctions or other legal restrictions and that no material adverse effect shall have occurred to either company. In addition, we will be unable to complete the merger until approvals are received from various governmental entities. Regulatory agencies may impose certain requirements or obligations as conditions for their approval. The merger may require us or Seawell to accept conditions from these regulators that could adversely impact the combined company. We can provide no assurance that we will satisfy the various closing conditions and that the necessary approvals will be obtained or that any required conditions will not materially adversely affect the combined company following the merger. In addition, we can provide no assurance that these conditions will not result in the abandonment or delay of the merger.
Failure to complete the merger or delays in completing the merger could negatively effect us.
If the merger is not completed, our ongoing businesses and the market price of our common stock may be adversely affected and we will be subject to several risks, including having to pay certain costs relating to the merger, and diverting the focus of management from pursuing other opportunities that could be beneficial to us, in each case, without realizing any of the benefits of having the merger completed.
In addition, while the merger is pending, certain of our customers may delay or defer purchasing decisions, which could negatively impact our revenues, earnings and cash flows regardless of whether the merger is completed. Uncertainty about the effect of the merger could also cause employees, suppliers, partners, regulators and customers to act in a manner that would have an adverse effect on us. Additionally, we have agreed to refrain from taking certain actions with respect to our business and financial affairs during the pendency of the merger, which restrictions could be in place for an extended period of time if completion of the merger is delayed and thus could adversely affect our financial condition, results of operations or cash flows.
We have and will continue to incur transaction costs in connection with the merger.
We have incurred, and expect to continue to incur, significant costs in connection with the merger, including the fees of our respective professional advisors. Seawell will also incur integration and restructuring costs following the completion of the merger as our operations are integrated with Seawell’s operations. The efficiencies anticipated to arise from the merger may not be achieved in the near term or at all, and, if achieved, may not be sufficient to offset the costs associated with the merger. Unanticipated costs, or the failure to achieve expected efficiencies, may have an adverse impact on the results of operations of the combined company following the completion of the merger.
Following the merger, the combined company may be unable to successfully integrate our business into Seawell’s business and realize the anticipated benefits of the merger.
The merger involves the combination of two companies that currently operate as independent public companies. The combined company will be required to devote management attention and resources to integrating its business practices and operations. Potential difficulties that the combined company may encounter in the integration process include the following:
• | the inability to successfully integrate our business into Seawell’s business in a manner that permits the combined company to achieve the cost savings and operating synergies anticipated to result from the merger, which would result in the anticipated benefits of the merger not being realized partly or wholly in the time frame currently anticipated or at all; | ||
• | integrating personnel from the two companies while maintaining focus on providing consistent, high quality products and customer service; | ||
• | potential unknown liabilities and unforeseen increased expenses, delays or regulatory conditions associated with the merger; and | ||
• | performance shortfalls at one or both of the two companies as a result of the diversion of management’s attention caused by completing the merger and integrating the companies’ operations. |
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In addition, Seawell and Allis-Chalmers have each operated and, until the completion of the merger, will continue to operate, independently. It is possible that the integration process could result in the diversion of each company’s management attention, the disruption or interruption of, or the loss of momentum in, each company’s ongoing businesses or inconsistencies in standards, controls, procedures and policies, any of which could adversely affect our ability to maintain relationships with customers, suppliers and employees or our ability to achieve the anticipated benefits of the merger, or could reduce the earnings or otherwise adversely affect the business and financial results of the combined company.
We may be unable to attract or retain both current and potential key employees during the pendency of the merger.
In connection with the pending merger, our current and prospective employees may experience uncertainty about their future roles with the combined company following the merger, which may materially adversely affect our ability to attract and retain key personnel during the pendency of the merger. Key employees may depart because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company following the merger. Accordingly, no assurance can be given that we will be able to retain key employees to the same extent that we have been able to in the past.
Multiple lawsuits have been filed against us challenging the merger, and an adverse ruling in any such lawsuit may prevent the merger from being completed.
Subsequent to the announcement of the merger, ten putative class-actions petitions and complaints were commenced on behalf of our stockholders against us and our directors, and in certain cases against Seawell and Wellco, each challenging the merger. One of the conditions to the closing of the merger is that no law, order, injunction, judgment, decree, ruling or other similar requirement shall be in effect that prohibits the completion of the merger. Accordingly, if any of the plaintiffs is successful in obtaining an injunction prohibiting the completion of the merger, then such injunction may prevent the merger from becoming effective, or from becoming effective within the expected timeframe.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.
On July 12, 2010, we issued 1,000,000 shares of our common stock to Richard T. Mitchell, the seller in our acquisition of 100% of the equity interest in American Well Control, Inc. The transaction was exempt from the registration requirements of the Securities Act pursuant to Section 4(2) of the Securities Act as a transaction by the issuer not involving any public offering.
ITEM 6. EXHIBITS
(a) The exhibits listed on the Exhibit Index immediately following the signature page of this Quarterly Report on Form 10-Q are filed as part of this report.
SIGNATURES
Pursuant to the requirements of 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 November 5, 2010.
Allis-Chalmers Energy Inc. | ||||
(Registrant) | ||||
/s/ Munawar H. Hidayatallah | ||||
Munawar H. Hidayatallah | ||||
Chief Executive Officer and Chairman |
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EXHIBIT INDEX
2.1 | Agreement and Plan of Merger, dated as of August 12, 2010, by and among Seawell Limited, Wellco Sub Company and Allis-Chalmers Energy Inc. (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 8-K filed on August 13, 2010). | |
2.2 | Amendment Agreement, dated as of October 1, 2010, to Agreement and Plan of Merger, dated as of August 12, 2010, by and among Seawell Limited, Wellco Sub Company and Allis-Chalmers Energy Inc. (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 8-K filed on October 5, 2010). | |
4.1 | Fourth Amendment to Investment Agreement, dated as of July 14, 2010, between Allis-Chalmers Energy Inc. and Lime Rock Partners V, L.P. (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed on July 14, 2010). | |
4.2 | Fifth Amendment to Investment Agreement, dated as of September 27, 2010, between Allis-Chalmers Energy Inc. and Lime Rock Partners V, L.P. (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed on September 30, 2010). | |
10.1 | Executive Employment Agreement, dated effective as of August 1, 2010, by and between Allis-Chalmers Energy Inc. and Victor M. Perez (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on August 17, 2010). | |
10.2 | Executive Employment Agreement, dated effective as of August 1, 2010, by and between Allis-Chalmers Energy Inc. and Theodore F. Pound III (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed on August 17, 2010). | |
10.3 | Executive Employment Agreement, dated effective as of August 1, 2010, by and between Allis-Chalmers Energy Inc. and Terrence P. Keane (incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8-K filed on August 17, 2010). | |
10.4 | Executive Employment Agreement, dated effective as of August 1, 2010, by and between Allis-Chalmers Energy Inc. and Mark Patterson (incorporated by reference to Exhibit 10.4 to the Registrant’s Form 8-K filed on August 17, 2010). | |
10.5 | Executive Employment Agreement, dated effective as of August 1, 2010, by and between Allis-Chalmers Directional Drilling Services LLC and David K. Bryan (incorporated by reference to Exhibit 10.5 to the Registrant’s Form 8-K filed on August 17, 2010). | |
31.1* | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
31.2* | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
32.1* | 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. |
* | Filed herewith |
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