Edgar Filing: Allis Chalmers Energy Inc.

Form 10-Q

UNITED STATES
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 MARCH 31, 2009


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

Commission file number 1-02199

ALLIS-CHALMERS ENERGY INC.

(Exact name of registrant as specified in its charter)


DELAWARE		39-0126090

(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

5075 WESTHEIMER, SUITE 890, HOUSTON, TEXAS		77056

(Address of principal executive offices)		(Zip Code)

(713) 369-0550

Registrant’s telephone number, including area code

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 issuer’s classes of common stock, as of the latest practicable date. At May 1, 2009 there were 35,691,742 shares of common stock, par value $0.01 per share, outstanding.

ALLIS-CHALMERS ENERGY INC.

FORM 10-Q

For the Quarterly Period Ended March 31, 2009

TABLE OF CONTENTS


	PAGE
PART I

ITEM

1. Financial Statements

Consolidated Condensed Balance Sheets as of March 31, 2009 and December 31, 2008		3

Consolidated Condensed Income Statements for the three months ended March 31, 2009 and 2008		4

Consolidated Condensed Statements of Cash Flows for the three months ended March 31, 2009 and 2008		5

Notes to Consolidated Condensed Financial Statements		6

2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		23

3. Quantitative and Qualitative Disclosures about Market Risk		33

4. Controls and Procedures		33

PART II

6. Exhibits		33

Signatures		34

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1

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)


	March 31,		December 31,
	2009		2008
	(unaudited)
Assets
Cash and cash equivalents	$	10,860	$	6,866
Trade receivables, net		132,548		157,871
Inventories		37,324		39,087
Deferred income tax asset		5,182		6,176
Prepaid expenses and other		13,622		15,238

Total current assets		199,536		225,238

Property and equipment, net		754,109		760,990
Goodwill		43,273		43,273
Other intangible assets, net		36,184		37,371
Debt issuance costs, net		12,200		12,664
Deferred income tax asset		9,496		3,993
Other assets		31,113		31,522


Total assets	$	1,085,911	$	1,115,051


Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	13,568	$	14,617
Trade accounts payable		46,041		62,078
Accrued salaries, benefits and payroll taxes		19,869		20,192
Accrued interest		7,475		18,623
Accrued expenses		25,402		26,642

Total current liabilities		112,355		142,152

Long-term debt, net of current maturities		581,446		579,044
Deferred income taxes		8,388		8,253
Other long-term liabilities		1,838		2,193

Total liabilities		704,027		731,642

Commitments and contingencies

Stockholders’ Equity
Preferred stock, $0.01 par value (25,000,000 shares authorized, no shares issued)		—		—
Common stock, $0.01 par value (100,000,000 shares authorized; 35,691,742 issued and outstanding at March 31, 2008 and 35,674,742 issued and outstanding at December 31, 2008)		357		357
Capital in excess of par value		335,713		334,633
Retained earnings		45,814		48,419

Total stockholders’ equity		381,884		383,409


Total liabilities and stockholders’ equity	$	1,085,911	$	1,115,051

The accompanying Notes are an integral part of the Consolidated Condensed Financial Statements.

ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED CONDENSED INCOME STATEMENTS

(in thousands, except per share amounts)

(unaudited)


	For the Three Months Ended
	March 31,
	2009			2008
Revenues	$	145,103		$	153,182

Operating costs and expenses
Direct costs		103,134			98,511
Depreciation		19,371			14,502
Selling, general and administrative		13,640			15,471
Amortization		1,187			1,116

Total operating costs and expenses		137,332			129,600


Income from operations		7,771			23,582

Other income (expense):
Interest expense		(13,507	)		(12,041	)
Interest income		5			1,152
Other		217			107


Total other income (expense)		(13,285	)		(10,782	)


Income (loss) before income taxes		(5,514	)		12,800

Provision for income taxes		2,909			(4,750	)


Net income (loss)	$	(2,605	)	$	8,050


Net income (loss) per common share:
Basic	$	(0.07	)	$	0.23
Diluted	$	(0.07	)	$	0.23

Weighted average shares outstanding:
Basic		35,206			34,837
Diluted		35,206			35,173

The accompanying Notes are an integral part of the Consolidated Condensed Financial Statements.

ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)


	For the Three Months Ended
	March 31,
	2009			2008
Cash Flows from Operating Activities:
Net income (loss)	$	(2,605	)	$	8,050
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		20,558			15,618
Amortization and write-off of deferred financing fees		555			519
Stock-based compensation		1,080			2,612
Allowance for bad debts		385			267
Deferred taxes		(4,374	)		1,965
Gain on sale of property and equipment		(357	)		(130	)
Changes in operating assets and liabilities, net of acquisitions:
Decrease (increase) in trade receivable		24,938			(10,306	)
Decrease (increase) in inventories		1,763			(810	)
Decrease in prepaid expenses and other current assets		1,616			228
Decrease (increase) in other assets		657			(1,271	)
Increase (decrease) in trade accounts payable		(16,037	)		1,523
(Decrease) in accrued interest		(11,148	)		(10,926	)
Increase (decrease) in accrued expenses		(1,240	)		10,943
Increase (decrease) in accrued salaries, benefits and payroll taxes		(323	)		564
(Decrease) in other long-term liabilities		(355	)		(162	)


Net Cash Provided By Operating Activities		15,113			18,684


Cash Flows from Investing Activities:
Investment in note receivable		—			(40,000	)
Deposits on asset commitments		(248	)		(5,331	)
Proceeds from sale of property and equipment		1,825			1,488
Purchase of property and equipment		(13,958	)		(39,677	)

Net Cash Used In Investing Activities		(12,381	)		(83,520	)


Cash Flows from Financing Activities:
Proceeds from exercises of options		—			61
Proceeds from long-term debt		—			13,142
Net borrowings under line of credit		6,000			20,500
Payments on long-term debt		(4,647	)		(2,292	)
Debt issuance costs		(91	)		(21	)


Net Cash Provided By Financing Activities		1,262			31,390


Net change in cash and cash equivalents		3,994			(33,446	)

Cash and cash equivalents at beginning of year		6,866			43,693


Cash and cash equivalents at end of period	$	10,860		$	10,247


Supplemental information:
Interest paid	$	23,867		$	22,412
Income taxes paid	$	2,589		$	2,181

The accompanying Notes are an integral part of the Consolidated Condensed Financial Statements.

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 1 — NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Allis-Chalmers Energy Inc. and subsidiaries (“Allis-Chalmers”, “we”, “our” or “us”) is a multi-faceted oilfield service company that provides services and equipment to oil and natural gas exploration and production companies, throughout the United States including Texas, Oklahoma, Louisiana, Arkansas, Pennsylvania, New Mexico, offshore in the Gulf of Mexico, and internationally, primarily in Argentina, Brazil and Mexico. We operate in three sectors of the oil and natural gas service industry: Oilfield Services; Drilling and Completion and Rental Services.

We derive operating revenues from rates per day and rates per job that we charge for the labor and equipment required to provide a service and rates per day for equipment and tools that we rent to our customers. The price we charge for our services depends upon several factors, including the level of oil and natural gas drilling activity and the competitive environment in the particular geographic regions in which we operate. Contracts are awarded based on price, quality of service and equipment and general reputation and experience of our personnel. The principal operating costs are direct and indirect labor and benefits, repairs and maintenance of our equipment, insurance, equipment rentals, fuel, depreciation and general and administrative expenses.

Basis of Presentation

Our unaudited consolidated condensed financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission, or SEC. Accordingly, certain information and disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited consolidated condensed financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. These unaudited consolidated condensed financial statements should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2008. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year.

Certain reclassifications have been made to the prior year’s consolidated condensed financial statements to conform with the current period presentation.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Future events and their effects cannot be perceived with certainty. Accordingly, our accounting estimates require the exercise of judgment. While management believes that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. Estimates are used for, but are not limited to, determining the following: allowance for doubtful accounts, recoverability of long-lived assets and intangibles, useful lives used in depreciation and amortization, income taxes and valuation allowances. The accounting estimates used in the preparation of the consolidated financial statements may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.

In September 2006, the Financial Accounting Standards Board, or FASB, issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements, or SFAS No. 157. SFAS No. 157 clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with early adoption permitted. Subsequently, the FASB provided for a one-year deferral of the provisions of SFAS No. 157 for non-financial assets and liabilities that are recognized or disclosed at fair value in the consolidated financial statements on a non-recurring basis. As allowed under SFAS No. 157, we adopted all requirements of SFAS No. 157 on January 1, 2008, except as they relate to nonfinancial assets and liabilities, which were adopted on January 1, 2009 and neither adoption had any impact on our financial statements.

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 1 — NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141 (revised 2007), Business Combinations, or SFAS No. 141(R). SFAS No. 141(R) changes the requirements for an acquirer’s recognition and measurement of the assets acquired and the liabilities assumed in a business combination. Additionally, SFAS No. 141(R) requires that acquisition-related costs, including restructuring costs, be recognized as expense separately from the acquisition. We adopted SFAS No. 141(R) on January 1, 2009 and there was no impact on our financial statements.

In April 2008, the FASB issued FASB Staff Position SFAS 142-3, Determination of the Useful Life of Intangible Assets, or FSP SFAS 142-3. FSP SFAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142. The objective of FSP SFAS 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R, and other U.S. GAAP principles. FSP SFAS 142-3 is effective for fiscal years beginning after December 15, 2008. We adopted FSP SFAS 142-3 on January 1, 2009 and there was no impact on our financial statements.

In April 2009, the FASB issued FASB Staff Position SFAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies, or FSP SFAS 141(R)-1. FSP SFAS 141(R)-1 amends the guidance in SFAS No. 141(R) to require contingent assets acquired and liabilities assumed in a business combination to be recognized at fair value on the acquisition date if fair value can be reasonably estimated during the measurement period. If fair value cannot be reasonably estimated during the measurement period, the contingent asset or liability would be recognized in accordance with SFAS No. 5, Accounting for Contingencies, and FASB Interpretation (FIN) No. 14, Reasonable Estimation of the Amount of a Loss. Further, this FSP eliminated the specific subsequent accounting guidance for contingent assets and liabilities from Statement 141(R), without significantly revising the guidance in SFAS No. 141. However, contingent consideration arrangements of an acquiree assumed by the acquirer in a business combination would still be initially and subsequently measured at fair value in accordance with SFAS No. 141(R). FSP SFAS 141(R)-1 is effective for all business acquisitions occurring on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted the provisions of FSP SFAS 141(R)-1 on January 1, 2009 and there was no impact on our financial statements.

In April 2009, the FASB issued FASB Staff Position SFAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, or FSP SFAS 157-4. FSP SFAS 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability have significantly decreased. This FSP re-emphasizes that regardless of market conditions the fair value measurement is an exit price concept as defined in SFAS No. 157. This FSP clarifies and includes additional factors to consider in determining whether there has been a significant decrease in market activity for an asset or liability and provides additional clarification on estimating fair value when the market activity for an asset or liability has declined significantly. The scope of this FSP does not include assets and liabilities measured under level 1 inputs. FSP SFAS 157-4 is applied prospectively to all fair value measurements where appropriate and will be effective for interim and annual periods ending after June 15, 2009. We will adopt the provisions of FSP SFAS 157-4 on April 1, 2009 and do not expect the adoption to have a material impact on our financial statements.

In April 2009, the FASB issued FASB Staff Position SFAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments or FSP SFAS 107-1 and APB 28-1. FSP SFAS 107-1 and APB 281-1 amends SFAS No. 107, Disclosures about Fair Value of Financial Instruments, to require publicly-traded companies, as defined in APB Opinion No. 28, “Interim Financial Reporting,” to provide disclosures on the fair value of financial instruments in interim financial statements. FSP SFAS 107-1 and APB 28-1 is effective for interim periods ending after June 15, 2009. We will adopt the additional disclosure requirements in our June 30, 2009 financial statements.

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 2 — STOCK-BASED COMPENSATION

We adopted Statement of Financial Accounting Standards No. 123R, Share-Based Payment, effective January 1, 2006. This statement requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their grant-date fair values. We estimated forfeiture rates for the first three months of 2009 and 2008 based on our historical experience.

The Black-Scholes model incorporates assumptions to value stock-based awards. The risk-free rate of interest is the related U.S. Treasury yield curve for periods within the expected term of the option at the time of grant. The dividend yield on our common stock is assumed to be zero as we have historically not paid dividends and have no current plans to do so in the future. The expected volatility is based on historical volatility of our common stock.

Our net income (loss) for the three months ended March 31, 2009 and 2008 includes approximately $1.1 million and $2.6 million, respectively of compensation costs related to share-based payments. As of March 31, 2009 there is $1.3 million of unrecognized compensation expense related to non-vested stock option grants. We expect approximately $684,000 to be recognized over the remainder of 2009, approximately $538,000, $27,000 and $5,000 to be recognized during the years ended 2010, 2011 and 2012, respectively.

A summary of our stock option activity and related information is as follows:


				Weighted		Weighted
	Shares			Average		Average		Aggregate
	Under			Exercise		Contractual		Intrinsic Value
	Option			Price		Life (Years)		(millions)
Balance at December 31, 2008		901,732		$	10.95
Granted		120,000			1.23
Canceled		(206,000	)		21.66
Exercised		—

Outstanding at March 31, 2009		815,732			6.82		6.79	$	0.08


Exercisable at March 31, 2009		683,732		$	7.53		6.21	$	0.00

The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between the closing price of our common stock on the last trading day of the first quarter of 2009 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on March 31, 2009.

No options were granted during the three months ended March 31, 2008. The following summarizes the assumptions used for the options granted in the three months ended March 31, 2009 Black-Scholes model:


	For the Three Months Ended
	March 31,
	2009
Expected dividend yield		—
Expected price volatility		77.32	%
Risk free interest rate		1.37	%
Expected life of options	5 years
Weighted average fair value of options granted at market value	$	0.77

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 2 — STOCK-BASED COMPENSATION (Continued)

Restricted stock awards, or RSAs, activity during the three months ended March 31, 2009 were as follows:


				Weighted Average
	Number of			Grant-Date Fair Value
	Shares			Per Share
Nonvested at December 31, 2008		953,102		$	15.34
Granted		17,000			1.23
Vested		(6,740	)		10.42
Forfeited		(5,600	)		16.50

Nonvested at March 31, 2009		957,762		$	15.12

We determine the fair value of RSAs based on the market price of our common stock on the date of grant. Compensation cost for RSAs is primarily recognized on a straight-line basis over the vesting or service period and is net of forfeitures. As of March 31, 2009, there was $7.9 million of total unrecognized compensation cost related to nonvested RSAs. We expect approximately $3.0 million to be recognized over the remainder of 2009 and approximately $3.5 million, $1.2 million and $195,000 to be recognized during the years ended 2010, 2011 and 2012, respectively.

NOTE 3 — INCOME PER COMMON SHARE

We compute income per common share in accordance with the provisions of Statement of Financial Accounting Standards No. 128, Earnings Per Share, or SFAS No. 128. SFAS No. 128 requires companies with complex capital structures to present basic and diluted earnings per share. Basic earnings per share are computed on the basis of the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share is similar to basic earnings per share, but presents the dilutive effect on a per share basis of potential common shares (e.g., convertible preferred stock, stock options, etc.) as if they had been converted. Potential dilutive common shares that have an anti-dilutive effect (e.g., those that increase income per share) are excluded from diluted earnings per share.

The components of basic and diluted earnings per share are as follows (in thousands, except per share amounts):


	For the Three Months Ended
	March 31,
	2009			2008
Numerator:
Net income (loss)	$	(2,605	)	$	8,050


Denominator:
Weighted average common shares outstanding excluding nonvested restricted stock		35,206			34,837

Effect of potentially dilutive common shares:
Warrants and employee and director stock options and restricted shares		—			336


Weighted average common shares outstanding and assumed conversions		35,206			35,173


Net income (loss) per common share
Basic	$	(0.07	)	$	0.23

Diluted	$	(0.07	)	$	0.23

Potentially dilutive securities excluded as anti-dilutive		1,537			1,088

Warrants and share based compensation shares of approximately 70,000 were excluded in the computation of diluted earnings per share for the three months ended March 31, 2009 as the effect would have been anti-dilutive due to the net loss for the period.

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 4 — GOODWILL AND INTANGIBLE ASSETS

In accordance with Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, or SFAS No. 142, goodwill and indefinite-lived intangible assets are not permitted to be amortized. Goodwill and indefinite-lived intangible assets remain on the balance sheet and are tested for impairment on an annual basis, or when there is reason to suspect that their values may have been diminished or impaired. Goodwill and indefinite-lived intangible assets listed on the balance sheet totaled $43.3 million at March 31, 2009 and December 31, 2008. Based on impairment testing performed during 2008 pursuant to the requirements of SFAS No. 142, these assets were impaired to their current carrying values.

Intangible assets with definite lives continue to be amortized over their estimated useful lives. Definite-lived intangible assets that continue to be amortized under SFAS No. 142 relate to our purchase of customer-related and marketing-related intangibles. These intangibles have useful lives ranging from five to twenty years. Amortization of intangible assets for the three months ended March 31, 2009 were $1.2 million, compared to $1.1 million for the same period in the prior year. At March 31, 2009, intangible assets totaled $36.2 million, net of $10.4 million of accumulated amortization.

NOTE 5 — INVENTORIES

Inventories consisted of the following (in thousands):


	March 31,		December 31,
	2009		2008
Manufactured
Finished goods	$	3,298	$	2,821
Work in process		2,203		1,654
Raw materials		2,225		2,499

Total manufactured		7,726		6,974
Hammers		2,164		2,257
Drive pipe		485		443
Rental supplies		2,837		3,023
Chemicals and drilling fluids		3,733		3,698
Rig parts and related inventory		10,667		13,097
Coiled tubing and related inventory		1,729		1,817
Shop supplies and related inventory		7,983		7,778


Total inventories	$	37,324	$	39,087

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 6 — DEBT

Our long-term debt consisted of the following: (in thousands)


	March 31,		December 31,
	2009		2008
Senior notes	$	505,000	$	505,000
Bank term loans		46,048		49,609
Revolving line of credit		42,500		36,500
Seller notes		750		750
Notes payable to former directors		32		32
Insurance premium financing		85		991
Capital lease obligations		599		779

Total debt		595,014		593,661

Less: current maturities		13,568		14,617


Long-term debt obligations	$	581,446	$	579,044

Senior notes, bank loans and line of credit agreements

On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, of $160.0 and $95.0 million aggregate principal amount of our senior notes, respectively. The senior notes are due January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of Specialty Rental Tools, Inc., or Specialty, and DLS Drilling, Logistics & Services Company, or DLS, to repay existing debt and for general corporate purposes.

In January 2007, we closed on a private offering, to qualified institutional buyers pursuant to Rule 144A under the Securities Act, of $250.0 million principal amount of 8.5% senior notes due 2017. The proceeds of the senior notes offering, together with a portion of the proceeds of our concurrent common stock offering, were used to repay the debt outstanding under our $300.0 million bridge loan facility which we incurred to finance our acquisition of substantially all the assets of Oil & Gas Rental Services, Inc, or OGR.

On January 18, 2006, we also executed an amended and restated credit agreement which provided for a $25.0 million revolving line of credit with a maturity of January 2010. On April 26, 2007, we entered into a Second Amended and Restated Credit Agreement, which increased our revolving line of credit to $62.0 million, and had a final maturity date of April 26, 2012. On December 3, 2007, we entered into a First Amendment to Second Amended and Restated Credit Agreement, which increased our revolving line of credit to $90.0 million. The amended and restated credit agreement contains customary events of default and financial covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends or make other distributions, create liens and sell assets. Our obligations under the amended and restated credit agreement are secured by substantially all of our assets located in the U.S. We were in compliance with all debt covenants as of March 31, 2009 and December 31, 2008. On April 9, 2009, we, along with certain of our subsidiaries, entered into a Third Amendment to our existing Second Amended and Restated Credit Agreement dated as of April 26, 2007, with Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto. The Third Amendment, among other things, modifies the leverage ratio and interest coverage ratio covenants of the Credit Agreement. In addition, permitted maximum capital expenditures were reduced to $85.0 million for 2009 compared to the previous limit of $120.0 million, which is consistent with our previously announced plans to limit capital expenditures for the year. The credit agreement loan rates are based on prime or LIBOR plus a margin. The weighted average interest rate was 6.4% and 4.6% at March 31, 2009 and December 31, 2008, respectively. As of March 31, 2009 and December 31, 2008, amounts borrowed under the facility were $42.5 million and $36.5 and availability was reduced by outstanding letters of credit of $5.8 million.

As part of our acquisition of DLS, we assumed various bank loans with floating interest rates based on LIBOR plus a margin and terms ranging from 2 to 5 years. The weighted average interest rates on these loans was 3.4% and 5.1% as of March 31, 2009 and December 31, 2008, respectively. The bank loans are denominated in U.S. dollars and the outstanding amount due as of March 31, 2009 and December 31, 2008 was $1.9 million and $2.5 million, respectively.

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 6 — DEBT (Continued)

On February 15, 2008, through our DLS subsidiary in Argentina, we entered into a $25.0 million import finance facility with a bank. The facility was available for draws until December 31, 2008, but as of that date we had drawn down the whole facility. Borrowings under this facility were used to fund a portion of the purchase price of the new drilling and service rigs ordered for our Drilling and Completion segment. Each drawdown shall be repaid over four years in equal semi-annual installments beginning one year after each disbursement with the final principal payment due not later than March 15, 2013. The import finance facility is unsecured and contains customary events of default and financial covenants and limits DLS’ ability to incur additional indebtedness, make capital expenditures, create liens and sell assets. We were in compliance with all debt covenants as of March 31, 2009 and December 31, 2008. The bank loan rates are based on LIBOR plus a margin. The weighted average interest rate was 6.3% and 6.9% at March 31, 2009 and December 31, 2008, respectively. The bank loans are denominated in U.S. dollars and the outstanding amount as of March 31, 2009 and December 31, 2008 was $23.5 million and $25.0 million, respectively.

As part of our acquisition of BCH Ltd, or BCH, we assumed a $23.6 million term loan credit facility with a bank. The credit agreement is dated June 2007 and contains customary events of default and financial covenants. Obligations under the facility are secured by substantially all of the BCH assets. The facility is repayable in quarterly principal installments plus interest with the final payment due not later than August 2012. We were in compliance with all debt covenants as of March 31, 2009 and December 31, 2008. The credit facility loan is denominated in U.S. dollars and interest rates are based on LIBOR plus a margin. At March 31, 2009 and December 31, 2008, the outstanding amount of the loan was $20.6 million and $22.1 million and the interest rate was 4.5% and 6.0%, respectively.

Notes payable

In connection with the acquisition of Rogers, we issued to the seller a note in the amount of $750,000. The note bears interest at 5.0% and was paid in full in April 2009 in accordance with its terms.

In 2000 we compensated directors, including current directors Robert Nederlander and Leonard Toboroff, who served on the board of directors from 1989 to March 31, 1999 without compensation, by issuing promissory notes totaling $325,000. The notes bear interest at the rate of 5.0%. As of March 31, 2009 and December 31, 2008, the principal and accrued interest on these notes totaled approximately $32,000.

In April 2008 and August 2008, we obtained insurance premium financings in the aggregate amount of $3.0 million with a fixed average weighted interest rate of 4.9%. Under terms of the agreements, amounts outstanding are paid over 10 and 11 month repayment schedules. The outstanding balance of these notes was approximately $85,000 and $991,000 at March 31, 2009 and December 31, 2008, respectively.

Other debt

As part of our acquisition of BCH, we assumed various capital leases with terms of two to three years. The outstanding balance under these capital leases was $599,000 and $779,000 at March 31, 2009 and December 31, 2008, respectively.

NOTE 7 — STOCKHOLDERS’ EQUITY

We recognized approximately $1.1 million of compensation expense related to share-based payments in the first three months of 2009 that was recorded as capital in excess of par value (see Note 2).

NOTE 8 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Set forth on the following pages are the condensed consolidating financial statements of (i) Allis-Chalmers Energy Inc., (ii) its subsidiaries that are guarantors of the senior notes and revolving credit facility and (iii) the subsidiaries that are not guarantors of the senior notes and revolving credit facility (in thousands, except for share and per share amounts).

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 8 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS
March 31, 2009 (unaudited)


	Allis-Chalmers				Subsidiary
	Parent/		Subsidiary		Non-		Consolidating			Consolidated
	Guarantor)		Guarantors		Guarantors		Adjustments			Total
Assets
Cash and cash equivalents	$	—	$	6,736	$	4,124	$	—		$	10,860
Trade receivables, net		—		67,637		67,857		(2,946	)		132,548
Inventories		—		19,690		17,634		—			37,324
Intercompany receivables		—		70,595		—		(70,595	)		—
Note receivable from affiliate		22,087		—		—		(22,087	)		—
Prepaid expenses and other		6,208		7,175		5,421		—			18,804

Total current assets		28,295		171,833		95,036		(95,628	)		199,536
Property and equipment, net		—		493,506		260,603		—			754,109
Goodwill		—		23,251		20,022		—			43,273
Other intangible assets, net		494		28,163		7,527		—			36,184
Debt issuance costs, net		12,114		86		—		—			12,200
Note receivable from affiliates		8,638		—		—		(8,638	)		—
Investments in affiliates		947,839		—		—		(947,839	)		—
Other assets		9,444		27,430		3,735		—			40,609

Total assets	$	1,006,824	$	744,269	$	386,923	$	(1,052,105	)	$	1,085,911

Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	782	$	85	$	12,701	$	—		$	13,568
Trade accounts payable		—		20,160		28,827		(2,946	)		46,041
Accrued salaries, benefits and payroll taxes		—		4,628		15,241		—			19,869
Accrued interest		7,150		—		325		—			7,475
Accrued expenses		98		11,754		13,550		—			25,402
Intercompany payables		69,410		—		1,185		(70,595	)		—
Note payable to affiliate		—		—		22,087		(22,087	)		—

Total current liabilities		77,440		36,627		93,916		(95,628	)		112,355
Long-term debt, net of current maturities		547,500		—		33,946		—			581,446
Note payable to affiliate		—		—		8,638		(8,638	)		—
Deferred income taxes		—		—		8,388		—			8,388
Other long-term liabilities		—		45		1,793		—			1,838

Total liabilities		624,940		36,672		146,681		(104,266	)		704,027

Commitments and contingencies

Stockholders’ Equity
Common stock		357		3,526		42,963		(46,489	)		357
Capital in excess of par value		335,713		570,512		133,339		(703,851	)		335,713
Retained earnings		45,814		133,559		63,940		(197,499	)		45,814

Total stockholders’ equity		381,884		707,597		240,242		(947,839	)		381,884

Total liabilities and stockholders equity	$	1,006,824	$	744,269	$	386,923	$	(1,052,105	)	$	1,085,911

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 8 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Three Months Ended March 31, 2009 (unaudited)


	Allis-Chalmers						Subsidiary
	(Parent/			Subsidiary			Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors			Adjustments			Total

Revenues	$	—		$	65,967		$	79,789		$	(653	)	$	145,103
Operating costs and expenses
Direct costs		—			41,295			62,492			(653	)		103,134
Depreciation		—			14,309			5,062			—			19,371
Selling, general and administrative		942			9,168			3,530			—			13,640
Amortization		12			980			195			—			1,187

Total operating costs and expenses		954			65,752			71,279			(653	)		137,332


Income (loss) from operations		(954	)		215			8,510			—			7,771

Other income (expense):
Equity earnings in affiliates, net of tax		10,612			—			—			(10,612	)		—
Interest, net		(12,284	)		(8	)		(1,210	)		—			(13,502	)
Other		21			(31	)		227			—			217

Total other income (expense)		(1,651	)		(39	)		(983	)		(10,612	)		(13,285	)


Net income (loss)before income taxes		(2,605	)		176			7,527			(10,612	)		(5,514	)

Provision for income taxes		—			4,304			(1,395	)		—			2,909


Net income (loss)	$	(2,605	)	$	4,480		$	6,132		$	(10,612	)	$	(2,605	)

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 8 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Three Months Ended March 31, 2009 (unaudited)


	Allis-						Other
	Chalmers						Subsidiaries
	(Parent/			Subsidiary			(Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors)			Adjustments			Total
Cash Flows from Operating Activities:
Net income (loss)	$	(2,605	)	$	4,480		$	6,132		$	(10,612	)	$	(2,605	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		12			15,289			5,257			—			20,558
Amortization and write-off of deferred financing fees		555			—			—			—			555
Stock based compensation		1,080			—			—			—			1,080
Allowance for bad debts		—			385			—			—			385
Equity earnings in affiliates		(10,612	)		—			—			10,612			—
Deferred taxes		(4,702	)		1,177			(849	)		—			(4,374	)
(Gain) on sale of equipment		—			(343	)		(14	)		—			(357	)
Changes in operating assets and liabilities, net of acquisitions:
Decrease in trade receivables		—			21,930			3,008			—			24,938
(Increase) decrease in inventories		—			(308	)		2,071			—			1,763
(Increase) decrease in prepaid expenses and other current assets		1,789			(278	)		105			—			1,616
(Increase) decrease in other assets		(104	)		233			528			—			657
(Decrease) in trade accounts payable		—			(9,023	)		(7,014	)		—			(16,037	)
(Decrease) in accrued interest		(10,782	)		—			(366	)		—			(11,148	)
(Decrease) increase in accrued expenses		(183	)		(2,087	)		1,030			—			(1,240	)
(Decrease) increase in accrued salaries, benefits and payroll taxes		—			695			(1,018	)		—			(323	)
(Decrease) in other long- term liabilities		—			(19	)		(336	)		—			(355	)

Net Cash Provided By (Used In) Operating Activities		(25,552	)		32,131			8,534			—			15,113


Cash Flows from Investing Activities:
Deposits on asset commitments		—			—			(248	)		—			(248	)
Proceeds from sale of property and equipment		—			1,810			15			—			1,825
Purchase of property and equipment		—			(9,578	)		(4,380	)		—			(13,958	)

Net Cash Used in Investing Activities		—			(7,768	)		(4,613	)		—			(12,381	)

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 8 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Three Months Ended March 31, 2009 (unaudited)


	Allis-						Other
	Chalmers						Subsidiaries
	(Parent/			Subsidiary			(Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors)			Adjustments			Total

Cash Flows from Financing Activities:
Accounts receivable from affiliates		—			(19,557	)		—			19,557			—
Accounts payable to affiliates		19,557			—			—			(19,557	)		—
Net borrowing under line of credit		6,000			—			—			—			6,000
Payments on long-term debt		—			(907	)		(3,740	)		—			(4,647	)
Debt issuance costs		(5	)		(86	)		—			—			(91	)

Net Cash Provided By (Used In) Financing Activities		25,552			(20,550	)		(3,740	)		—			1,262


Net change in cash and cash equivalents		—			3,813			181			—			3,994
Cash and cash equivalents at beginning of year		—			2,923			3,943			—			6,866

Cash and cash equivalents at end of period	$	—		$	6,736		$	4,124		$	—		$	10,860

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 8 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2008


	Allis-Chalmers				Subsidiary
	(Parent/		Subsidiary		Non-		Consolidating			Consolidated
	Guarantor)		Guarantors		Guarantors		Adjustments			Total
Assets
Cash and cash equivalents	$	—	$	2,923	$	3,943	$	—		$	6,866
Trade receivables, net		—		88,528		70,865		(1,522	)		157,871
Inventories		—		19,382		19,705		—			39,087
Intercompany receivables		—		51,038		—		(51,038	)		—
Note receivable from affiliate		20,680		—		—		(20,680	)		—
Prepaid expenses and other		8,798		8,074		4,542		—			21,414

Total current assets		29,478		169,945		99,055		(73,240	)		225,238
Property and equipment, net		—		499,704		261,286		—			760,990
Goodwill		—		23,251		20,022		—			43,273
Other intangible assets, net		506		29,143		7,722		—			37,371
Debt issuance costs, net		12,664		—		—		—			12,664
Note receivable from affiliates		10,045		—		—		(10,045	)		—
Investments in affiliates		937,227		—		—		(937,227	)		—
Other assets		3,837		27,663		4,015		—			35,515


Total assets	$	993,757	$	749,706	$	392,100	$	(1,020,512	)	$	1,115,051


Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	782	$	992	$	12,843	$	—		$	14,617
Trade accounts payable		—		27,759		35,841		(1,522	)		62,078
Accrued salaries, benefits and payroll taxes		—		3,933		16,259		—			20,192
Accrued interest		17,932		—		691		—			18,623
Accrued expenses		281		13,841		12,520		—			26,642
Intercompany payables		49,853		—		1,185		(51,038	)		—
Note payable to affiliate		—		—		20,680		(20,680	)		—

Total current liabilities		68,848		46,525		100,019		(73,240	)		142,152
Long-term debt, net of current maturities		541,500		—		37,544		—			579,044
Note payable to affiliate		—		—		10,045		(10,045	)		—
Deferred income tax liability		—		—		8,253		—			8,253
Other long-term liabilities		—		64		2,129		—			2,193

Total liabilities		610,348		46,589		157,990		(83,285	)		731,642

Commitments and contingencies

Stockholders’ Equity
Common stock		357		3,526		42,963		(46,489	)		357
Capital in excess of par value		334,633		570,512		133,339		(703,851	)		334,633
Retained earnings		48,419		129,079		57,808		(186,887	)		48,419

Total stockholders’ equity		383,409		703,117		234,110		(937,227	)		383,409


Total liabilities and stock holders’ equity	$	993,757	$	749,706	$	392,100	$	(1,020,512	)	$	1,115,051

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 8 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Three Months Ended March 31, 2008 (unaudited)


	Allis-Chalmers						Subsidiary
	(Parent/			Subsidiary			Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors			Adjustments			Total
Revenues	$	—		$	90,128		$	63,061		$	(7	)	$	153,182
Operating costs and expenses
Direct costs		—			49,865			48,653			(7	)		98,511
Depreciation		—			11,333			3,169			—			14,502
Selling, general and administrative		2,376			10,733			2,362			—			15,471
Amortization		12			1,095			9			—			1,116

Total operating costs and expenses		2,388			73,026			54,193			(7	)		129,600


Income (loss) from operations		(2,388	)		17,102			8,868			—			23,582

Other income (expense):
Equity earnings in affiliates, net of tax		21,223			—			—			(21,223	)		—
Interest, net		(10,812	)		76			(153	)		—			(10,889	)
Other		27			44			36			—			107

Total other income (expense)		10,438			120			(117	)		(21,223	)		(10,782	)


Net income (loss)before income taxes		8,050			17,222			8,751			(21,223	)		12,800

Provision for income taxes		—			(1,511	)		(3,239	)		—			(4,750	)


Net income (loss)	$	8,050		$	15,711		$	5,512		$	(21,223	)	$	8,050

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 8 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Three Months Ended March 31, 2008 (unaudited)


	Allis-						Other
	Chalmers						Subsidiaries
	(Parent/			Subsidiary			(Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors)			Adjustments			Total
Cash Flows from Operating Activities:
Net income (loss)	$	8,050		$	15,711		$	5,512		$	(21,223	)	$	8,050
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		12			12,428			3,178			—			15,618
Amortization and write-off of deferred financing fees		519			—			—			—			519
Stock based compensation		2,612			—			—			—			2,612
Allowance for bad debts		—			267			—			—			267
Equity earnings in affiliates		(21,223	)		—			—			21,223			—
Deferred taxes		901			—			1,064			—			1,965
(Gain) on sale of equipment		—			(130	)		—			—			(130	)
Changes in operating assets and liabilities, net of acquisitions:
(Increase) in trade receivables		—			(2,800	)		(7,506	)		—			(10,306	)
(Increase) in inventories		—			(720	)		(90	)		—			(810	)
(Increase) decrease in prepaid expenses and other current assets		—			690			(462	)		—			228
(Increase) decrease in other assets		(1,457	)		36			150			—			(1,271	)
(Decrease) increase in trade accounts payable		—			(328	)		1,851			—			1,523
(Decrease) increase in accrued interest		(10,958	)		30			2			—			(10,926	)
(Decrease) increase in accrued expenses		(1,488	)		9,677			2,754			—			10,943
Increase in accrued salaries, benefits and payroll taxes		—			171			393			—			564
(Decrease) in other long- term liabilities		(31	)		(32	)		(99	)		—			(162	)

Net Cash Provided By (Used In) Operating Activities		(23,063	)		35,000			6,747			—			18,684


Cash Flows from Investing Activities:
Notes receivable from affiliates		(3,075	)		—			—			3,075			—
Investment in note receivable		(40,000	)		—			—			—			(40,000	)
Deposits on asset commitments		—			—			(5,331	)		—			(5,331	)
Proceeds from sale of property and equipment		—			1,488			—			—			1,488
Purchase of property and equipment		—			(21,149	)		(18,528	)		—			(39,677	)

Net Cash Provided By (Used in) Investing Activities		(43,075	)		(19,661	)		(23,859	)		3,075			(83,520	)

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 8 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Three Months Ended March 31, 2008 (unaudited)


	Allis-						Other
	Chalmers						Subsidiaries
	(Parent/			Subsidiary			(Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors)			Adjustments			Total

Cash Flows from Financing Activities:
Accounts receivable from affiliates		45,598			—			—			(45,598	)		—
Accounts payable to affiliates		—			(45,598	)		—			45,598			—
Note payable to affiliate		—			—			3,075			(3,075	)		—
Proceeds from exercises of options		61			—			—			—			61
Proceeds from long-term debt		—			—			13,142			—			13,142
Net borrowing under line of credit		20,500			—			—			—			20,500
Payments on long-term debt		—			(1,662	)		(630	)		—			(2,292	)
Debt issuance costs		(21	)		—			—			—			(21	)

Net Cash Provided By (Used In) Financing Activities		66,138			(47,260	)		15,587			(3,075	)		31,390


Net change in cash and cash equivalents		—			(31,921	)		(1,525	)		—			(33,446	)
Cash and cash equivalents at beginning of year		—			41,176			2,517			—			43,693

Cash and cash equivalents at end of period	$	—		$	9,255		$	992		$	—		$	10,247

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 9 — SEGMENT INFORMATION

All of our segments provide services to the energy industry. The revenues, operating income (loss), depreciation and amortization, capital expenditures and assets of each of the reporting segments, plus the corporate function, are reported below (in thousands):


	For the Three Months Ended
	March 31,
	2009			2008

Revenues
Oilfield Services	$	44,450		$	67,903
Drilling and Completion		79,146			63,061
Rental Services		21,507			22,218


	$	145,103		$	153,182


Operating Income (Loss):
Oilfield Services	$	(1,213	)	$	13,297
Drilling and Completion		8,509			8,868
Rental Services		3,948			6,222
General corporate		(3,473	)		(4,805	)


	$	7,771		$	23,582


Depreciation and Amortization:
Oilfield Services	$	7,315		$	5,630
Drilling and Completion		5,257			3,178
Rental Services		7,904			6,669
General corporate		82			141


	$	20,558		$	15,618


Capital Expenditures:
Oilfield Services	$	4,032		$	14,427
Drilling and Completion		4,639			18,529
Rental Services		5,256			6,691
General corporate		31			30


	$	13,958		$	39,677


Revenues:
United States	$	61,559		$	83,984
Argentina		63,425			62,641
Brazil		10,766			—
Other international		9,353			6,557


	$	145,103		$	153,182

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 9 — SEGMENT INFORMATION (Continued)


	As of
	March 31,		December 31,
	2009		2008
Goodwill:
Oilfield Services	$	23,250	$	23,250
Drilling and Completion		20,023		20,023
Rental Services		—		—


	$	43,273	$	43,273


Assets:
Oilfield Services	$	289,454	$	309,901
Drilling and Completion		405,236		411,486
Rental Services		352,317		360,376
General corporate		38,904		33,288


	$	1,085,911	$	1,115,051


Long Lived Assets:
United States	$	570,649	$	573,975
Argentina		190,200		212,456
Brazil		82,130		79,568
Other international		43,396		23,814


	$	886,375	$	889,813

NOTE 10 — LEGAL MATTERS

We are named from time to time in legal proceedings related to our activities prior to our bankruptcy in 1988. However, we believe that we were discharged from liability for all such claims in the bankruptcy and believe the likelihood of a material loss relating to any such legal proceeding is remote.

We have been named as a defendant in two lawsuits in connection with our proposed merger with Bronco Drilling, Inc., which was terminated August 2008. We do not believe that the suits have any merit.

We are also involved in various other legal proceedings in the ordinary course of business. The legal proceedings are at different stages; however, we believe that the likelihood of material loss relating to any such legal proceeding is remote.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this report. This report contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from the results discussed in such forward-looking statements. Factors that might cause such differences include, but are not limited to, the general condition of the oil and natural gas drilling industry, demand for our oil and natural gas service and rental products, and competition. For more information on forward-looking statements please refer to the section entitled “Forward-Looking Statements” on page 32.

Overview of Our Business

We are a multi-faceted oilfield services company that provides services and equipment to oil and natural gas exploration and production companies, throughout the United States including Texas, Oklahoma, Louisiana, Arkansas, Pennsylvania, New Mexico, offshore in the Gulf of Mexico and internationally primarily in Argentina, Brazil and Mexico. We currently operate in three sectors of the oil and natural gas service industry: Oilfield Services; Drilling and Completion and Rental Services.

We derive operating revenues from rates per day and rates per job that we charge for the labor and equipment required to provide a service and rates per day for equipment and tools that we rent to our customers. The price we charge for our services depends upon several factors, including the level of oil and natural gas drilling activity and the competitive environment in the particular geographic regions in which we operate. Contracts are awarded based on price, quality of service and equipment, and the general reputation and experience of our personnel. The demand for drilling services has historically been volatile and is affected by the capital expenditures of oil and natural gas exploration and development companies, which can fluctuate based upon the prices of oil and natural gas, or the expectation for the prices of oil and natural gas.

The number of active rigs drilling, or the rig count, is an important indicator of activity levels in the oil and natural gas industry. The rig count in the U.S. peaked at 2,031 in August 2008 but then declined to 1,721 as of December 26, 2008, according to the Baker Hughes rig count, and has continued to decline to 955 as of April 24, 2009. The rapid decline in the U.S. rig count is due to the economic slowdown in the U.S. and the decrease in natural gas and oil prices which has impacted the capital expenditures of our customers. The turmoil in the financial markets and its impact on the availability of capital for our customers has also affected drilling activity in the U.S. Directional and horizontal rig counts, according to the Baker Hughes rig count, have also decreased and were 557 as of April 24, 2009 compared to 912 as of December 26, 2008, which accounted for 58% and 53% of the total U.S. rig count, respectively.

While our revenue can be correlated to the rig count, our operating costs do not fluctuate in direct proportion to changes in revenues. Our operating expenses consist principally of our labor costs and benefits, equipment rentals, maintenance and repairs of our equipment, depreciation, insurance and fuel. Because many of our costs are fixed, our operating income as a percentage of revenues is generally affected by our level of revenues.

Our Industry

The oilfield services industry is highly cyclical. The most critical factor in assessing the outlook for the industry is the worldwide supply and demand for oil and the domestic supply and demand for natural gas. The industry is driven by commodity demand and corresponding price increases. As demand increases, producers raise their prices. The price escalation enables producers to increase their capital expenditures. The increased capital expenditures ultimately result in greater revenues and profits for services and equipment companies. The increased capital expenditures also ultimately result in greater production which historically has resulted in increased supplies and reduced prices.

Company Outlook

We believe that our revenue and operating income for our Oilfield Services and Rental Services segment will suffer significantly in 2009, due to the reduction of our customers’ spending and the drop in U.S. rig count. We have already taken steps in 2009 to reduce costs, including laying off employees and closing unprofitable operating locations. Even with these steps, our Oilfield Services segment may still generate negative operating income in 2009 due to its focus in the U.S. market. Although we expect our Rental Services segment to be negatively impacted in a material fashion by the industry wide reduction in drilling and completion activity, we believe that our Rental Services segment will still generate positive operating income, albeit on lower revenue and at reduced margins. We anticipate our Drilling and Completion segment results in 2009 will be stable or comparable with 2008 as we benefit from a full year of operations on rigs acquired during 2008 and from the acquisition of BCH at the end of 2008. Our Drilling and Completion segment primarily operates in Argentina and Brazil, but we have two rigs coming into service in 2009 in the U.S. market. Currently, we have no firm commitments of work for our U.S. rigs, so the impact of revenue and operating income from these rigs may be insignificant.

We expect to incur less general and administrative expenses in 2009 as we reduce our administrative staff to reflect the decline in activity. Our net interest expense is dependent upon our level of debt and cash on hand, which are principally dependent on acquisitions we complete, our capital expenditures and our cash flows from operations. Due to the tightness of credit in the financial markets, we may see an increase in our effective interest rate in 2009. In addition, the interest rate on our credit facilities may increase if we violate any of our financial covenants in 2009.

The sustainability and future growth in our operating income is principally dependent on our level of revenues and the pricing environment of our services. In addition, the demand for our services is dependent upon our customers’ capital spending plans, which are largely driven by current commodity prices and their expectations of future commodity prices. Recent declines in both natural gas and oil prices have caused our customers to delay or curtail capital spending plans. In addition to the impact of the decline in natural gas prices on our customers’ capital expenditures and overall liquidity, the recent credit crisis has limited the availability of funds, which has lead to decreased capital expenditures for our customers. The slowdown in economic activity caused by the recession has reduced demand for energy and resulted in lower oil and natural gas prices. Such a continued slowdown in economic activity could have a material adverse effect on our revenue and profitability. We are monitoring the credit worthiness of our customers, as well as outstanding receivables, in light of the current credit crisis and as such increased our reserve for doubtful accounts significantly at December 31, 2008, but further reserves may be necessary in 2009.

We continue to monitor the effect of the global financial crisis on our industry, and the resulting impact on the capital spending budgets of our customers in order to estimate the effect on our company. We have already reduced our planned capital spending significantly in 2009 compared to 2008. We believe that 2009 will be an extremely challenging year for our operations but we are optimistic that our cost saving cuts, coupled with our strategy of striving to mitigate cyclical risk through our international growth, by offering new equipment and technology to our customers and our focus on the U.S. land shale plays, will carry us through the current recession.

Results of Operations

In December 2008, we acquired all of the outstanding stock of BCH, which is reported as part of our Drilling and Completion segment. In August 2008, we sold our drill pipe tong manufacturing assets, which were reported in our Oilfield Services segment. We consolidated the results of these transactions from the date they were effective.

The foregoing acquisition and disposition affect the comparability from period to period of our historical results, and our historical results may not be indicative of our future results.

Comparison of Three Months Ended March 31, 2009 and 2008

Our revenues for the three months ended March 31, 2009 were $145.1 million, a decrease of 5.3% compared to $153.2 million for the three months ended March 31, 2008. The decrease in revenues is due to the decrease in revenues in our Oilfield Services and our Rental Services segments, offset in part by an increase in revenues in our Drilling and Completion segment. The increase in revenues in our Drilling and Completion segment was due to the acquisition of BCH and additional drilling and service rigs placed in service in 2008. The Drilling and Completion segment generated $79.1 million in revenues for the three months ended March 31, 2009 compared to $63.1 million for the three months ended March 31, 2008. BCH generated $10.8 million of revenues for the quarter ended March 31, 2009. Our Oilfield Services segment revenues decreased to $44.5 million for the three months ended March 31, 2009 compared to $67.9 million for the three months ended March 31, 2008 due to the decline in U.S. drilling activity. Revenues for our Rental Services segment decreased to $21.5 million for the three months ended March 31, 2009 compared to $22.2 million for the three months ended March 31, 2008 due to the reduction of drilling activity. The decrease in drilling activity has also caused the pricing for our Oilfield Services and Rental Services segment to become more competitive.

Our direct costs for the three months ended March 31, 2009 increased 4.7% to $103.1 million, or 71.1% of revenues, compared to $98.5 million, or 64.3%, of revenues for the three months ended March 31, 2008 due to the acquisition of BCH at the end of 2008 and because revenues in our Oilfield Services and Rental Services segments decreased faster during the quarter than the reduction in direct costs. The benefit of certain cost reduction steps, including layoffs and closure of certain operating locations, was not fully realized during the first quarter of 2009. On a percentage basis, the reduction in revenues in our Oilfield Services segment outpaced the reduction in direct costs for that segment when comparing the three months ended March 31, 2009 to the three months ended March 31, 2008. Oilfield Services revenues for the three months ended March 31, 2009 decreased 34.5% from revenues for the three months ended March 31, 2008, while the direct costs decreased 22.0% over that same period. This unfavorable variance was primarily associated with the fact that not all of our direct costs are variable and therefore do not fluctuate with revenues. Our Oilfield Services segment has also been impacted by pricing pressure that decreases revenues but has no impact on direct costs. On a percentage basis, direct costs in our Drilling and Completion segment outpaced the growth in our revenues for that segment. Drilling and Completion revenues for the three months ended March 31, 2009 increased 25.5% from revenues for the three months ended March 31, 2008, while the direct costs increased 27.1% over that same period. This unfavorable variance is primarily attributed to lower utilization of our drilling and service rigs during the three months ended March 31, 2009 compared to the same period of the prior year. Our direct costs in our Rental Services segment increased while our revenue declined for that segment. Rental Services revenues for the three months ended March 31, 2009 decreased 3.2% from revenues in the Rental Services segment for the three months ended March 31, 2008, while the direct costs increased 13.0% over that same period. Our direct costs for the Rental Services segment are largely fixed because they primarily relate to yard expenses to maintain the rental inventory. In addition, pricing pressure has reduced our Rental Services revenues but had no impact on our direct costs.

Depreciation expense increased 33.6% to $19.4 million for the three months ended March 31, 2009 from $14.5 million for the three months ended March 31, 2008. The primary increase in depreciation expense is due to our capital expenditure programs in 2008, principally the addition of new service rigs and one drilling rig in Argentina and the expansion of our coiled tubing fleet. Depreciation expense as a percentage of revenues increased to 13.3% for the first quarter of 2009, compared to 9.5% for the first quarter of 2008, due to the decrease in revenues as a result of the decline in U.S. drilling activity. The acquisition of BCH at the end of 2008 contributed an additional $0.9 million of depreciation in the first three months of March 31, 2009.

Selling, general and administrative expense was $13.6 million for the three months ended March 31, 2009 compared to $15.5 million for the three months ended March 31, 2008. Selling, general and administrative expense decreased primarily due to cost reduction steps that were made in the three months ended March 31, 2009 in response to market conditions and a decrease related to the amortization of share-based compensation arrangements. Selling, general and administrative expense includes share-based compensation expense of $1.1 million in the first quarter of 2009 and $2.6 million in the first quarter of 2008. As a percentage of revenues, selling, general and administrative expenses were 9.4% for the three months ended March 31, 2009 compared to 10.1% for the same period in the prior year.

Amortization expense was $1.2 million for the three months ended March 31, 2009 compared to $1.1 million for the three months ended March 31, 2008.

Our income from operations for the three months ended March 31, 2009 totaled $7.8 million, compared to $23.6 million in income from operations for the three months ended March 31, 2008, for a total decrease of $15.8 million. The decrease is primarily related to the decreased revenue combined with the increase in direct costs and depreciation from the three months ended March 31, 2009 compared to three months ended March 31, 2008.

Our interest expense was $13.5 million for the three months ended March 31, 2009, compared to $12.0 million for the three months ended March 31, 2008. During 2009, we increased our borrowing against our revolving credit facility and as of March 31, 2009, we had an outstanding balance of $42.5 million compared to an outstanding balance of $20.5 million at March 31, 2008. In 2008, through our DLS subsidiary in Argentina, we also entered into a new $25.0 million import finance facility with a bank to fund a portion of the purchase price of new drilling and service rigs. Interest expense also increased due to the acquisition of BCH at the end of 2008. BCH had a $22.1 million term loan facility at December 31, 2008. Interest expense includes amortization expense of deferred financing costs of $555,000 and $519,000 for the three months ended March 31, 2009 and 2008, respectively.

Our interest income was $5,000 for the three months ended March 31, 2009, compared to $1.1 million for the three months ended March 31, 2008. In January 2008, we invested $40.0 million into a 15% convertible subordinated secured debenture with BCH. We earned interest on this note up until December 31, 2008, when we acquired all of the outstanding stock of BCH.

Our benefit for income taxes for the three months ended March 31, 2009 was $2.9 million, or 52.8% of our net loss before income taxes, compared to an income tax expense of $4.8 million, or 37.1% of our net income before income taxes for 2008. The income tax benefit recorded in 2009 was the result of net loss before income taxes compared to net income before income taxes in the previous year and a higher effective tax rate. Our U.S. effective tax rate was 33.0% for the three months ended March 31, 2009, compared to 37.3% for the same period in the prior year. The lower effective tax rate on our U.S. operations was due to nondeductible expenses and state income taxes. Our tax rate from our DLS operations was 10.8% for the three months ended March 31, 2009, compared to 37.0% for the same period in the prior year due to the impact of foreign currency operations and the increase in the portion of income in the first quarter of 2009 that was generated in non-taxable jurisdictions.

We had a net loss of $2.6 million for the three months ended March 31, 2009, compared to net income of $8.1 million for the three months ended March 31, 2008 due to the foregoing reasons.

The following table compares revenues and income (loss) from operations for each of our business segments for the quarter ended March 31, 2009 and 2008. Income (loss) from operations consists of our revenues and the gain on asset dispositions less direct costs, selling, general and administrative expenses, depreciation and amortization:


	Revenues							Income (Loss) from Operations
	Three Months Ended							Three Months Ended
	March 31,							March 31,
	2009		2008		Change			2009			2008			Change
	(in thousands)

Oilfield Services	$	44,450	$	67,903	$	(23,453	)	$	(1,213)		$	13,297		$	(14,510	)
Drilling and Completion		79,146		63,061		16,085			8,509			8,868			(359	)
Rental Services		21,507		22,218		(711	)		3,948			6,222			(2,274	)
General corporate		—		—		—			(3,473	)		(4,805	)		1,332


Total	$	145,103	$	153,182	$	(8,079	)	$	7,771		$	23,582		$	(15,811	)

Oilfield Services

Revenues for our Oilfield Services segment were $44.5 million for the three months ended March 31, 2009, a decrease of 34.5% compared to $67.9 million in revenues for the three months ended March 31, 2008. Income from operations decreased $14.5 million and resulted in loss from operations of $1.2 million in the first quarter of 2009 compared to income from operations of $13.3 million in the first quarter of 2008. Our Oilfield Services segment revenues and operating income for the first quarter of 2009 decreased compared to the first quarter of 2008 due primarily to market conditions that resulted in lower utilization of our services and a reduction in the pricing for our services. Additionally, depreciation and amortization expense for the Oilfield Services segment increased by $1.7 million or 29.9% in the first quarter of 2009 compared to the first quarter of the previous year, due to capital expenditures completed during 2008, including six coiled tubing units delivered in the last half of 2008. We have not realized the benefits of these capital expenditures due to decreased utilization and pricing of our equipment as a result of the decline in U.S. drilling activity.

Drilling and Completion

Revenues for the quarter ended March 31, 2009 for the Drilling and Completion segment were $79.1 million, an increase of 25.5% compared to $63.1 million in revenues for the quarter ended March 31, 2008. Income from operations decreased to $8.5 million in the first quarter of 2009 compared to $8.9 million in the first quarter of 2008, due to an increase of $2.1 million, or 65.4%, in depreciation and amortization in the first quarter of 2009 compared to the first quarter of 2008. The increase in depreciation and amortization expense was the result of the addition of new rigs in Argentina and the acquisition of BCH. Our Drilling and Completion segment revenues increased in the first quarter of 2009 primarily due to the acquisition of BCH at the end of 2008, which generated $10.8 million of revenues during the three months ended March 31, 2009. We also benefited from 16 new service rigs and one drilling rig which were placed in service in Argentina at various dates in 2008 and one drilling rig placed in service in March 2009. The utilization and rates for our service and drilling rigs in Argentina declined in the first quarter of 2009 compared to the prior year.

Rental Services

Revenues for the quarter ended March 31, 2009 for the Rental Services segment were $21.5 million, a decrease from $22.2 million in revenues for the quarter ended March 31, 2008. Income from operations decreased to $3.9 million in the first quarter of 2009 compared to $6.2 million in the first quarter of 2008. Our Rental Services segment revenues and operating income for the first quarter of 2009 decreased compared to the prior year due primarily to the decrease in utilization of our rental equipment and a more competitive pricing environment due to a decrease in drilling activity in the U.S. Depreciation and amortization expense for our Rental Services segment increased $1.2 million, or 18.5%, in the first quarter of 2009 compared to the first quarter of 2008 due to capital expenditures made during 2008 and a $584,000 additional reduction in the carrying value of our airplane to its ultimate selling price received in April 2009.

General Corporate

General corporate expenses decreased $1.3 million to $3.5 million for the three months ended March 31, 2009 compared to $4.8 million for the three months ended March 31, 2008. The decrease was due to the decrease in payroll costs and benefits due to reduced management and accounting and administrative staff and the decrease in share-based compensation expense.

Liquidity

Our on-going capital requirements arise primarily from our need to service our debt, to acquire and maintain equipment, to fund our working capital requirements and to complete acquisitions. Our primary sources of liquidity are proceeds from the issuance of debt and equity securities and cash flows from operations. Our amended and restated revolving credit facility permits borrowings of up to $90.0 million in principal amount. As of March 31, 2009, we had $41.7 million available for borrowing under our amended and restated revolving credit facility. We also have up to $25.0 million available under a new credit agreement which we executed in February 2009 to fund a portion of the purchase price of two drilling rigs to be acquired in May 2009. Cash flows from operations are expected to be our primary source of liquidity in fiscal 2009. We had cash and cash equivalents of $10.9 million at March 31, 2009 compared to $6.9 million at December 31, 2008.

Our revolving credit agreement requires us to maintain specified financial ratios. If we fail to comply with the financial ratio covenants, it could limit or eliminate the availability under our revolving credit agreement. Our ability to maintain such financial ratios may be affected by events beyond our control, including changes in general economic and business conditions, and we cannot assure you that we will maintain or meet such ratios and tests or that the lenders under the credit agreement will waive any failure to meet such ratios or tests. The decrease in the U.S. rig count experienced late in 2008 and early 2009, the expectation of additional decreases in the U.S. rig count, and the resulting decrease in demand for our services adversely impacts our ability to maintain or meet such financial ratios.

Operating Activities

During the three months ended March 31, 2009, our operating activities provided $15.1 million in cash. Our net loss for the three months ended March 31, 2009 was $2.6 million. Non-cash expenses totaled $17.8 million during the first three months of 2009 consisting of $20.6 million of depreciation and amortization, $1.1 million for share based compensation expense, $555,000 in amortization of deferred financing fees, $385,000 related to increases to the allowance for doubtful accounts receivables, less $4.4 million for deferred income taxes related to timing differences and $357,000 on the gain from asset disposals.

During the three months ended March 31, 2009, changes in operating assets and liabilities used $129,000 in cash, principally due to a decrease in accounts payable of $16.0 million, a decrease in accrued interest of $11.1 million, a decrease in accrued expenses of $1.2 million, offset by a decrease in trade receivables of $24.9 million, a decrease of $1.8 million in inventory and a decrease in prepaid expenses and other current assets of $1.6 million. Accounts payable, accrued expenses, trade receivables and inventory decreased primarily due to the drop in our activity in the first three months of 2009. The decrease in accrued interest relates to the semi-annual payment of interest on our senior notes. The decrease in prepaid expense and other current assets primarily relates to amortization of prepaid expenses.

During the three months ended March 31, 2008, our operating activities provided $18.7 million in cash. Net income for the three months ended March 31, 2008 was $8.1 million. Non-cash expenses totaled $20.9 million during the first three months of 2008 consisting of $15.6 million of depreciation and amortization, $2.0 million for deferred income taxes related to timing differences, $519,000 in amortization of deferred financing fees, $2.6 million from the expensing of stock options, $267,000 related to increases to the allowance for doubtful accounts receivables, less $130,000 on the gain from asset disposals.

During the three months ended March 31, 2008, changes in operating assets and liabilities used $10.2 million in cash, principally due to an increase of $10.3 million in trade receivables, an increase of $810,000 in inventories, a decrease of $10.9 million in accrued interest, an increase in other assets of $1.3 million, offset in part by an increase of $1.5 million in accounts payable and an increase of $10.9 million in accrued expenses. Trade receivables increased primarily due to the increase in our revenues in the first three months of 2008. The decrease in accrued interest relates to the semi-annual payment of interest on our 8.5% senior notes. The increase in other assets primarily relates to $1.1 million of interest income on our $40.0 million note receivable from BCH. The increase in accounts payable can be attributed to additional expenses related to our growth. The increase in accrued expenses is primarily related to a $5.7 million accrual for rental equipment, along with an increase of our accrued income taxes payable of $1.6 million related to current period results, and a general increase due to our growth.

Investing Activities

During the three months ended March 31, 2009, we used $12.4 million in investing activities, consisting of $14.0 million for capital expenditures, offset by $1.8 million of proceeds from equipment sales. Included in the $14.0 million for capital expenditures was $4.0 million for our Oilfield Services segment, $4.6 million for additional equipment in our Drilling and Completion segment and $5.3 million for drill pipe and other equipment used in our Rental Services segment. A majority of our equipment sales relate to items “lost in hole” or “damaged beyond repair” by our customers.

During the three months ended March 31, 2008, we used $83.5 million in investing activities, consisting of a $40.0 million convertible subordinated secured note from BCH Ltd, $39.7 million for capital expenditures, $5.3 million for deposits on equipment purchases for our Drilling and Completion segment, offset by $1.5 million of proceeds from equipment sales. Included in the $39.7 million for capital expenditures was $14.4 million for our Oilfield Services segment, including additional casing and tubing equipment and coiled tubing support equipment, $18.5 million for additional equipment in our Drilling and Completion segment and $6.7 million for drill pipe and other equipment used in our Rental Services segment. A majority of our equipment sales relate to items “lost in hole” or “damaged beyond repair” by our customers.

Financing Activities

During the three months ended March 31, 2009, financing activities provided $1.3 million in cash. We borrowed $6.0 million under our revolving credit facility and repaid $4.6 million in borrowings under long-term debt facilities.

During the three months ended March 31, 2008, financing activities provided $31.4 million in cash. We received $20.5 million from borrowings under our revolving line of credit and an additional $13.1 million in proceeds from long-term debt and repaid $2.3 million in borrowings under long-term debt facilities. We also received $61,000 in proceeds from the exercise of options and warrants.

At March 31, 2009, we had $595.0 million in outstanding indebtedness, of which $581.4 million was long-term debt and $13.6 million is due within one year.

On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, of $160.0 and $95.0 million aggregate principal amount of our senior notes, respectively. The senior notes are due January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of Specialty and DLS, to repay existing debt and for general corporate purposes.

As part of our acquisition of BCH, we assumed a $23.6 million term loan credit facility with a bank. The credit agreement is dated June 2007 and contains customary events of default and financial covenants. Obligations under the facility are secured by substantially all of the BCH assets. The facility is repayable in quarterly principal installments plus interest with the final payment due not later than August 2012. We were in compliance with all debt covenants as of March 31, 2009 and December 31, 2008. The credit facility loan is denominated in U.S. dollars and interest rates are based on LIBOR plus a margin. At March 31, 2009 and December 31, 2008, the outstanding amount of the loan was $20.6 million and $22.1 million and the interest rate was 4.5% and 6.0%, respectively.

Notes payable

Other debt

Off Balance Sheet Arrangements

We have no off balance sheet arrangements, other than normal operating leases and employee contracts, that have or are likely to have a current or future material effect on our financial condition, changes in financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources. We do not guarantee obligations of any unconsolidated entities. At March 31, 2009, we had a $90.0 million revolving line of credit with a maturity of April 2012. At March 31, 2009, we borrowed $42.5 million on the facility and availability was further reduced by outstanding letters of credit of $5.8 million.

Capital Resources

We have reduced our planned capital spending for 2009 compared to 2008. We currently expect to spend a total of approximately $55.0 million for the remainder of 2009, which is net of equipment deposits paid in 2008. This amount includes budgeted but unidentified expenditures which may be required to enhance or extend the life of existing assets. We believe that our cash generated from operations, cash on hand and cash available under our credit facilities will provide sufficient funds for our identified projects and to service our debt. However, the decrease in drilling activity and the resulting decrease in demand and pricing for our services has an adverse impact on our cash flow from operations and our liquidity. This could require us to raise external capital and we cannot be assured such capital will be available to us, especially in the current tight credit market and volatility in the equity market. Our ability to obtain capital for opportunistic acquisitions or additional projects to implement our growth strategy over the longer term will depend upon our future operating performance and financial condition, which will be dependent upon the prevailing conditions in our industry and the global market, including the availability of equity and debt financing, many of which are beyond our control.

Recent Developments

On April 5, 2009, Carlos A. Bulgheroni resigned from our board of directors for personal reasons, effective April 7, 2009.

On April 9, 2009, we, along with certain of our subsidiaries, entered into a Third Amendment to our existing Second Amended and Restated Credit Agreement dated as of April 26, 2007, with Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto. The Third Amendment, among other things, modifies the leverage ratio and interest coverage ratio covenants of the Credit Agreement. In addition, permitted maximum capital expenditures were reduced to $85.0 million for 2009 compared to the previous limit of $120.0 million, which is consistent with our previously announced plans to limit capital expenditures for the year.

Critical Accounting Policies

Please see our Annual Report on Form 10-K for the year ended December 31, 2008 for a description of other policies that are critical to our business operations and the understanding of our results of operations. The impact and any associated risks related to these policies on our business operations is discussed throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations where such policies affect our reported and expected financial results. No material changes to such information have occurred during the three months ended March 31, 2009.

Recently Issued Accounting Standards

Forward-Looking Statements

This quarterly report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, regarding our business, financial condition, results of operations and prospects. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements. However, these are not the exclusive means of identifying forward-looking statements. Although such forward-looking statements reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Further information about the risks and uncertainties that may impact us are described under “Item 1A—Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008. You should read those sections carefully. You should not place undue reliance on forward-looking statements, which speak only as of the date of this quarterly report. We undertake no obligation to update publicly any forward-looking statements in order to reflect any event or circumstance occurring after the date of this quarterly report or currently unknown facts or conditions or the occurrence of unanticipated events.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are exposed to market risk primarily from changes in interest rates and foreign currency exchange risks.

Interest Rate Risk.

Fluctuations in the general level of interest rates on our current and future fixed and variable rate debt obligations expose us to market risk. We are vulnerable to significant fluctuations in interest rates affecting our adjustable rate debt, and any future refinancing of our fixed rate debt and our future debt. We have approximately $88.5 million of adjustable rate debt with a weighted average interest rate of 5.9% at March 31, 2009.

Foreign Currency Exchange Rate Risk.

We have designated the U.S. dollar as the functional currency for our operations in international locations as we contract with customers, purchase equipment and finance capital using the U.S. dollar. Local currency transaction gains and losses, arising from remeasurement of certain assets and liabilities denominated in local currency, are included in our consolidated statements of income. We conduct business in Mexico through our Mexican partner, Matyep. This business exposes us to foreign exchange risk. To control this risk, we provide for payment in U.S. dollars. However, we have historically provided our partner a discount upon payment equal to 50% of any loss suffered by our partner as a result of devaluation of the Mexican peso between the date of invoicing and the date of payment. To date, such payments have not been material in amount.

ITEM 4. CONTROLS AND PROCEDURES.

(a) Evaluation of Disclosure Controls and Procedures.

As of the end of the period covered by this quarterly report, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(e) and 15d — 15(e) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. This evaluation was carried out under the supervision and with the participation of our management, including our chief executive officer and chief financial officer. Based on this evaluation, these officers have concluded that, as of March 31, 2009, our disclosure controls and procedures are effective at a reasonable assurance level in ensuring that the information required to be disclosed by us in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission, or SEC, rules and forms.

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports under the Exchange Act, are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosures.

(b) Change in Internal Control Over Financial Reporting.

There have not been any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 6. EXHIBITS

(a) The exhibits listed on the Exhibit Index immediately following the signature page of this Quarterly Report on Form 10-Q are filed as part of this report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on May 8, 2009.


	Allis-Chalmers Energy Inc. (Registrant)
	/s/ Munawar H. Hidayatallah
	Munawar H. Hidayatallah
	Chief Executive Officer and Chairman

EXHIBIT INDEX

10.1		Amended and Restated Performance award Agreement, dated March 11, 2009, between Allis-Chalmers Energy Inc. and Munawar H. Hidayatallah (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on March 13, 2009).

10.2		Letter agreements dated March 9, 2009, by each of Munawar H. Hidayatallah, Victor M. Perez, Theodore F. Pound III, David Bryan, Terrence P. Keane and Mark Patterson (incorporate by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed on March 13, 2009).


10.3		Third Amendment to Second Amended and Restated Credit Agreement, dated as of April 9, 2009, by and among the Company, as borrower, certain subsidiaries of the Company, as guarantors, Royal Bank of Canada, as administrative agent, and the lenders named thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on April 9, 2009).

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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