Attached files
file | filename |
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EX-31.1 - EX-31.1 - Allis Chalmers Energy Inc. | h77500exv31w1.htm |
EX-31.2 - EX-31.2 - Allis Chalmers Energy Inc. | h77500exv31w2.htm |
EX-32.1 - EX-32.1 - Allis Chalmers Energy Inc. | h77500exv32w1.htm |
Table of Contents
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
Registrants telephone number, including area code
Registrants telephone number, including area code
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12
months (or for such shorter period that the registrant was required to submit and post such files).
Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act:
Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o | Smaller reporting company o | |||
(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of
the latest practicable date.
At November 1, 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
2
Table of Contents
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.
3
Table of Contents
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.
4
Table of Contents
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
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.
5
Table of Contents
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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Table of Contents
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 years 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 enterprises 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.
7
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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 | ||
AWCs 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.
AWCs 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.
9
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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
assets 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.
10
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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.
11
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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 BCHs 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.
12
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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.
13
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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).
14
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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 | |||||||||
15
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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 | ) | |||||||
16
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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 | ) | |||||||
17
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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 | ) | |||||||||||
18
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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 | ) | |||||||
22
Table of Contents
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 | ) | |||||||||||
23
Table of Contents
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 | ||||||||||
24
Table of Contents
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.
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ITEM 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis should be read in conjunction with our consolidated financial
statements and the notes thereto included elsewhere in this report. This report contains
forward-looking statements that involve risks and uncertainties. Our actual results may differ
materially from the results discussed in such forward-looking statements. Factors that might cause
such differences include, but are not limited to, the general condition of the oil and natural gas
drilling industry, demand for our oil and natural gas service and rental products, and competition.
For more information on forward-looking statements, please refer to the section entitled
Forward-Looking Statements on page 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 governments request that the district courts
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 manufacturers 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%. AWCs gross margin as a percentage of revenues is less than our
overall Rental Services gross margin percentage as AWCs 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 BCHs 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 worlds 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 Managements Discussion and Analysis of Financial Condition and
Results of Operations where such policies affect our reported and expected financial results. No
material changes to such information have occurred during the nine months ended September 30, 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
1ARisk 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 Commissions, or SECs,
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 SECs rules and forms,
and that such information is accumulated and communicated to management, including our chief
executive officer and chief financial officer, as appropriate, to allow timely decisions regarding
required disclosures.
(b) Change in Internal Control Over Financial Reporting.
There have not been any changes in our internal control over financial reporting (as such term is
defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the period covered by this
report that have materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting.
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PART II. OTHER INFORMATION
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 governments request that the district courts
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 policys 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 Seawells 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 Seawells 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 Seawells 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 managements 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 companys management attention, the disruption or interruption of,
or the loss of momentum in, each companys 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 Registrants 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 Registrants 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 Registrants 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 Registrants 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 Registrants 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 Registrants 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 Registrants 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 Registrants 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 Registrants 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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