Edgar Filing: Allis Chalmers Energy Inc.

e10vq

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, 2006

		OR


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

		FOR THE TRANSITION PERIOD FROM TO

Commission file number 1-2199

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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and larger accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

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 April 28, 2006 there were 17,355,115 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, 2006

TABLE OF CONTENTS


ITEM		PAGE

	PART I

1.	Financial Statements

	Consolidated Condensed Balance Sheets as of March 31, 2006 and December 31, 2005		3

	Consolidated Condensed Income Statements for the three months ended March 31, 2006 and 2005		4

	Consolidated Condensed Statements of Cash Flows for the three months ended March 31, 2006 and 2005		5

	Notes to Consolidated Condensed Financial Statements		6

2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		17

3.	Quantitative and Qualitative Disclosures about Market Risk		25

4.	Controls and Procedures		25

	PART II

1.	Legal Proceedings		26

2.	Unregistered Sales of Equity Securities and Use of Proceeds		26

6.	Exhibits		26

Signatures			27
Stock Purchase Agreement dated April 27, 2006
Certification of CEO pursuant to Section 302
Certification of CFO pursuant to Section 302
Certification of CEO and CFO pursuant to 18 U.S.C. 1350

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED CONDENSED BALANCE SHEETS
(in thousands, except for share amounts)


	March 31,		December 31,
	2006		2005
	(unaudited)
Assets
Cash and cash equivalents	$	10,661	$	1,920
Trade receivables, net		38,239		26,964
Inventory		7,777		5,945
Prepaid expenses and other		875		823

Total current assets		57,552		35,652

Property and equipment, net		174,329		80,574
Goodwill		12,417		12,417
Other intangible assets, net		6,399		6,783
Debt issuance costs, net		6,414		1,298
Other assets		719		631


Total assets	$	257,830	$	137,355


Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	3,144	$	5,632
Trade accounts payable		8,903		9,018
Accrued salaries, benefits and payroll taxes		2,064		1,271
Accrued interest		3,053		289
Accrued expenses		6,505		4,350
Accounts payable, related parties		—		60

Total current liabilities		23,669		20,620

Accrued postretirement benefit obligations		319		335
Long-term debt, net of current maturities		165,999		54,937
Other long-term liabilities		631		588

Total liabilities		190,618		76,480

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; 17,225,330 issued and outstanding at March 31, 2006 and 16,859,988 issued and outstanding at December 31, 2005)		172		169
Capital in excess of par value		60,800		58,889
Retained earnings		6,240		1,817

Total stockholders’ equity		67,212		60,875


Total liabilities and stockholders’ equity	$	257,830	$	137,355

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,
	2006			2005
				(Restated)
Revenues	$	47,028		$	19,334

Cost of revenues
Direct costs		27,032			12,785
Depreciation		3,330			914


Total cost of revenues		30,362			13,699


Gross margin		16,666			5,635

General and administrative		6,484			2,994
Stock option expense		942			—
Amortization		607			394


Income from operations		8,633			2,247
Other income (expense):
Interest, net		(3,628	)		(521	)
Other		25			148


Total other income (expense)		(3,603	)		(373	)


Income before minority interest and income taxes		5,030			1,874

Minority interest in income of subsidiaries		—			(144	)
Provision for taxes		(607	)		(163	)


Net income	$	4,423		$	1,567


Net income per common share:
Basic	$	0.26		$	0.12
Diluted	$	0.23		$	0.11

Weighted average shares outstanding:
Basic		17,105			13,632
Diluted		19,113			14,695

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,
	2006			2005
Cash Flows from Operating Activities:
Net income	$	4,423		$	1,567
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation		3,330			914
Amortization		607			394
Imputed interest		355			—
Stock option expense		942			—
Allowance for bad debts		180			—
Minority interest in income of subsidiaries		—			144
Gain on sale of property and equipment		(514	)		—
Changes in operating assets and liabilities, net of acquisitions:
(Increase) in trade receivable		(4,288	)		(3,416	)
(Increase) in inventory		(1,484	)		(91	)
Decrease (increase) in other current assets		7			(408	)
(Increase) in other assets		(88	)		(16	)
(Decrease) increase in accounts payable		(1,286	)		4
Increase (decrease) in accrued interest		2,764			(10	)
(Decrease) in accrued expenses		(11,017	)		(92	)
Increase in accrued salaries, benefits and payroll taxes		483			185
Increase in other long-term liabilities		27			3


Net Cash Used In Operating Activities		(5,559	)		(822	)


Cash Flows from Investing Activities:
Acquisition of businesses, net of cash received		(83,447	)		—
Proceeds from sale of property and equipment		1,200			—
Purchase of property and equipment		(7,586	)		(2,728	)


Net Cash Used In Investing Activities		(89,833	)		(2,728	)


Cash Flows from Financing Activities:
Proceeds from exercises of options and warrants		972			—
Proceeds from long-term debt		161,412			2,383
Repayments on long-term debt		(43,481	)		—
Repayments on related party debt		(3,031	)		—
Repayments on line of credit		(6,400	)		—
Debt issuance costs		(5,339	)		(178	)


Net Cash Provided By Financing Activities		104,133			2,205


Net change in cash and cash equivalents		8,741			(1,345	)

Cash and cash equivalents at beginning of year		1,920			7,344


Cash and cash equivalents at end of period	$	10,661		$	5,999

Supplemental information:
Interest paid	$	586		$	437
Income taxes paid	$	232		$	163

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

We are a multi-faceted oilfield service company that provides services and equipment to oil and natural gas exploration and production companies, domestically in Texas, Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Utah, Wyoming, offshore in the Gulf of Mexico, and internationally in Mexico. We operate in five sectors of the oil and natural gas service industry: directional drilling services; rental tools; casing and tubing services; compressed air drilling services; and production 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. 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, 2005. 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 May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections. SFAS No. 154 requires retroactive application of a voluntary change in accounting principle to prior period financial statements unless it is impracticable. SFAS No. 154 also requires that a change in method of depreciation, amortization or depletion for long-lived, non-financial assets be accounted for as a change in accounting estimate that is affected by a change in accounting principle. SFAS No. 154 replaces APB Opinion No. 20, Accounting Changes and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. SFAS No. 154 is effective for fiscal years beginning after December 15, 2005. We adopted the provisions of SFAS No. 154 as of January 1, 2006 and the adoption did not have a material impact on our results of operations.

ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

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

In November 2004, the FASB issued SFAS No. 151, Inventory Costs – an Amendment of ARB No. 43, Chapter 4, which amends the guidance in ARB No. 43 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. SFAS No. 151 requires that these items be recognized as current period charges. In addition, SFAS No. 151 requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. We adopted the provisions of SFAS 151, on a prospective basis, as of January 1, 2006 and the adoption did not have a material impact on our results of operations.

Effective January 1, 2006, we adopted SFAS No. 123R, Share-Based Payment. SFAS No. 123R revises SFAS No. 123, Accounting for Stock-Based Compensation, and focuses on accounting for share-based payments for services by employer to employee. 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. See Note 3 for a more detailed description of our adoption of SFAS No. 123R.

NOTE 2 — ACQUISITIONS

Effective January 1, 2006, we acquired 100% of the outstanding stock of Specialty Rental Tools, Inc., or Specialty, for $83.6 million in cash. The results of Specialty’s operations have been included in the consolidated financial statements since that date. Specialty, located in Lafayette, Louisiana, is engaged in the rental of high quality drill pipe, heavy weight spiral drill pipe, tubing work strings, blow-out preventors, choke manifolds and various valves and handling tools for oil and natural gas drilling. For the year ended December 31, 2005, Specialty had revenues of $29.6 million. The following table summarizes the allocation of the purchase price to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition:


Accounts receivable	$	7,167
Other current assets		425
Property and equipment		90,540

Total assets acquired		98,132

Current liabilities		14,458
Long-term debt		74

Total liabilities assumed		14,532

Net assets acquired	$	83,600

On September 1, 2005, we acquired the casing and tubing service assets of Patterson Services, Inc. for approximately $15.6 million. These assets are located in Corpus Christi, Texas; Kilgore, Texas; Lafayette, Louisiana and Houma, Louisiana.

Effective August 1, 2005, we acquired 100% of the outstanding capital stock of Target Energy Inc., or Target, for $1.3 million in cash and forgiveness of a lease receivable of approximately $0.6 million. The purchase price was allocated to the fixed assets of Target. The results of Target are included in our directional and horizontal drilling segment as their measurement while drilling, or MWD, equipment is utilized in that segment.

On July 11, 2005, we acquired the compressed air drilling assets of W.T. Enterprises, Inc., or WT, based in South Texas, for $6.0 million in cash. The equipment includes compressors, boosters, mist pumps and vehicles. Goodwill of $82,000 and other identifiable intangible assets of $1.5 million were recorded in connection with the acquisition.

On July 11, 2005, we acquired from M-I its 45% interest in AirComp L.L.C., or AirComp, and a subordinated note in the principal amount of $4.8 million issued by AirComp, for which we paid M-I $7.1 million in cash and issued to M-I a $4.0 million subordinated note bearing interest at 5% per annum. As a result, we now own 100% of AirComp.

On May 1, 2005, we acquired 100% of the outstanding capital stock of Capcoil Tubing Services, Inc., or Capcoil, for $2.7 million in cash, 168,161 shares of our common stock and the payment or assumption of approximately $1.3 million of debt. Capcoil, located in Kilgore, Texas, is engaged in downhole well servicing by providing coil tubing services to enhance production from existing wells. Goodwill of $184,000 and other identifiable intangible assets of $1.4 million were recorded in connection with the acquisition.

ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 2 – ACQUISITIONS (Continued)

On April 1, 2005, we acquired 100% of the outstanding stock of Delta Rental Service, Inc., or Delta, for $4.6 million in cash, 223,114 shares of our common stock and two promissory notes totaling $350,000. The purchase price was allocated to fixed assets and inventory. Delta, located in Lafayette, Louisiana, is a rental tool company providing specialty rental items to the oil and gas industry such as spiral heavy weight drill pipe, test plugs used to test blow-out preventors, well head retrieval tools, spacer spools and assorted handling tools.

These acquisitions were accounted for using the purchase method of accounting. The results of operations of the acquired entities since the date of acquisition are included in our consolidated condensed income statement. The following unaudited pro forma consolidated summary financial information illustrates the effects of the acquisition of Specialty, WT, the minority interest in AirComp, Capcoil and Delta as if the acquisitions had occurred as of January 1, 2005, based on the historical statements of operations (in thousands, except per share amounts).


	For the Three Months Ended
	March 31,
	2006		2005
Revenues	$	47,028	$	29,364
Operating income		8,633		4,245
Net income		4,423		1,331

Net income per common share:
Basic	$	0.26	$	0.09
Diluted	$	0.23	$	0.09

NOTE 3 – STOCK-BASED COMPENSATION

We adopted SFAS 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. Compensation cost for awards granted prior to, but not vested, as of January 1, 2006 would be based on the grant date attributes originally used to value those awards for pro forma purposes under SFAS No. 123. We adopted SFAS No. 123R using the modified prospective transition method, utilizing the Black-Scholes option pricing model for the calculation of the fair value of our employee stock options. Under the modified prospective method, we record compensation cost related to unvested stock awards as of December 31, 2005 by recognizing the unamortized grant date fair value of these awards over the remaining vesting periods of those awards with no change in historical reported earnings. We estimated forfeiture rates for the first quarter of 2006 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.

Prior to January 1, 2006, we accounted for our stock-based compensation using Accounting Principle Board Opinion No. 25. Under APB No. 25, compensation expense is recognized for stock options with an exercise price that is less than the market price on the grant date of the option. For stock options with exercise prices at or above the market value of the stock on the grant date, we adopted the disclosure-only provisions of SFAS No. 123, Accounting For Stock-Based Compensation. We also adopted the disclosure-only provisions of SFAS No. 123 for the stock options granted to our employees and directors. Accordingly, no compensation cost was recognized under APB No. 25.

ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 3 – STOCK-BASED COMPENSATION (Continued)

A summary of our stock option activity and related information as of March 31, 2006 is as follows:


				Weighted		Weighted-
	Shares			Average		Average		Aggregate
	Under			Exercise		Contractual		Intrinsic Value
	Option			Price		Life (Years)		(millions)
Balance at beginning of period		2,860,867		$	5.10
Granted		—			—
Canceled		(32,000	)		4.30
Exercised		(51,900	)		3.63

Outstanding at end of period		2,776,967			5.14		8.57	$	23.6

Exercisable at end of period		1,909,967			4.18		8.26	$	18.1

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 2006 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, 2006. The total intrinsic value of options exercised and cash received from option exercises during the three months ended March 31, 2006 was $588,000 and $188,000, respectively. There were no options exercised during the three months ended March 31, 2005.

No options were granted in the first quarter of 2006. The following summarizes the assumptions used in the March 31, 2005 Black-Scholes model:


Expected dividend yield		—
Expected price volatility		89.76	%
Risk-free interest rate		7.0	%
Expected life of options	7 years
Weighted average fair value of options granted at market value	$	3.86

The following table illustrates the pro-forma effect on net income and net income per share for the three months ended March 31, 2005 had we applied the fair value recognition provisions of SFAS No. 123R (in thousands, except per share amounts):


		Three Months Ended,
		March 31, 2005
Net income: As reported		$	1,567

Less total stock based employee compensation expense determined under fair value based method for all awards net of tax related effects			(2,902	)


Pro-forma net income (loss) to common stockholders		$	(1,335	)


Net income/ (loss) per share:
Basic	As reported	$	0.12

	Pro forma	$	(0.10	)


Diluted	As reported	$	0.11

	Pro forma	$	(0.10	)

ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 4 – INCOME PER COMMON SHARE

We compute income per common share in accordance with the provisions of SFAS No. 128, Earnings Per Share. 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,
	2006		2005
			(restated)
Numerator:
Net income	$	4,423	$	1,567


Denominator:
Basic earnings per share – weighted average shares outstanding		17,105		13,632

Effect of potentially dilutive common shares:
Warrants and employee and director stock options		2,008		1,063


Diluted earnings per share – weighted average shares outstanding and assumed conversions		19,113		14,695


Net income per share — basic	$	0.26	$	0.12


Net income per share — diluted	$	0.23	$	0.11

NOTE 5 – GOODWILL AND INTANGIBLE ASSETS

In accordance with SFAS No. 142, Goodwill and Other Intangible Assets, 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 $12.4 million at March 31, 2006 and December 31, 2005. Based on impairment testing performed during 2005 pursuant to the requirements of SFAS No. 142, these assets were not impaired.

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 ten years. Amortization of intangible assets for the three months ended March 31, 2006 and 2005 were $384,000 and $166,000, respectively. At March 31, 2006, intangible assets totaled $6.4 million, net of $3.1 million of accumulated amortization.

ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 6 — RESTATEMENT

A restated earnings per share calculation for the three months ended March 31, 2005 reflecting the above adjustments to our results as previously presented is presented below. The amounts are in thousands, except for per share amounts.


	Three Months Ended March 31, 2005
	As					As
	Reported		Adjustments			Restated
Income per common share- diluted	$	0.09	$	0.02		$	0.11

Weighted average number of common shares outstanding:
Diluted		17,789		(3,094	)		14,695

NOTE 7 — INVENTORY

Inventory is comprised of the following (in thousands):


	March 31,		December 31,
	2006		2005
Hammer bits
Finished goods	$	1,507	$	1,402
Work in process		948		787
Raw materials		471		233

Total hammer bits		2,926		2,422
Hammers		589		584
Drive pipe		663		666
Rental supplies		404		64
Chemicals		477		201
Coiled tubing and related inventory		1,672		1,145
Shop supplies and related inventory		1,046		863


Total inventory	$	7,777	$	5,945

ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 8 — DEBT

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


	March 31,		December 31,
	2006		2005
Senior notes	$	160,000	$	—
Bank term loans		—		42,090
Revolving line of credit		—		6,400
Subordinated note payable to M-1 LLC		4,000		4,000
Subordinated seller note		—		3,031
Seller note		850		850
Notes payable under non-compete agreements		615		698
Notes payable to former directors		96		96
Real estate loan		—		548
Equipment and vehicle installment notes		2,786		1,939
Capital lease obligations		796		917

Total debt		169,143		60,569
Less: short-term debt and current maturities		3,144		5,632

Long-term debt obligations	$	165,999	$	54,937

Senior notes, bank loans and line of credit agreements

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

Prior to January 18, 2006, we were party to a July 2005 credit agreement that provided for the following senior secured credit facilities:

	•		A $13.0 million revolving line of credit. Borrowings were limited to 85% of eligible accounts receivable plus 50% of eligible inventory (up to a maximum of $2.0 million of borrowings based on inventory). This line of credit was to be used to finance working capital requirements and other general corporate purposes, including the issuance of standby letters of credit. Outstanding borrowings under this line of credit were $6.4 million at a margin above prime and LIBOR rates plus margin averaging approximately 8.1% as of December 31, 2005.

	•		Two term loans totaling $42.0 million. Outstanding borrowings under these term loans were $42.0 million as of December 31, 2005. These loans were at LIBOR rates plus a margin which averages approximately 7.8% at December 31, 2005.

Borrowings under the July 2005 credit facilities were to mature in July 2007. Amounts outstanding under the term loans as of July 2006 were to be repaid in monthly principal payments based on a 48 month repayment schedule with the remaining balance due at maturity. Additionally, during the second year, we were to be required to prepay the remaining balance of the term loans by 75% of excess cash flow, if any, after debt service and capital expenditures. The interest rate payable on borrowings was based on a margin over the London Interbank Offered Rate, referred to as LIBOR, or the prime rate, and there was a 0.5% fee on the undrawn portion of the revolving line of credit. The margin over LIBOR was to increase by 1.0% in the second year.

ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 8 – DEBT (Continued)

All amounts outstanding under our July 2005 credit agreement were paid off with the proceeds of our senior notes offering on January 18, 2006. On January 18, 2006, we also executed an amended and restated credit agreement which provides for a $25.0 million revolving line of credit with a maturity of January 2010. Our January 2006 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 January 2006 amended and restated credit agreement are secured by substantially all of our assets.

Notes payable and real estate loan

On July 11, 2005, we acquired from M-I its 45% equity interest in AirComp and the subordinated note in the principal amount of $4.8 million issued by AirComp, for which we paid M-I $7.1 million in cash and issued a new $4.0 million subordinated note bearing interest at 5% per annum. The subordinated note issued to M-I requires quarterly interest payments and the principal amount is due October 9, 2007. Contingent upon a future equity offering, the subordinated note is convertible into up to 700,000 shares of our common stock at a conversion price equal to the market value of the common stock at the time of conversion.

As of December 31, 2005, Allis-Chalmers Tubular Services Inc., or Tubular, had a subordinated note outstanding and payable to Jens Mortensen, the seller of Tubular and one of our directors, in the amount of $4.0 million with a fixed interest rate of 7.5%. Interest was payable quarterly and the final maturity of the note was January 31, 2006. The subordinated note was subordinated to the rights of our bank lenders. The balance of this subordinated note was repaid in full in January 2006 with proceeds from our senior notes offering.

As part of the acquisition of Mountain Compressed Air Inc., or Mountain Air, in 2001, we issued a note to the sellers of Mountain Air in the original amount of $2.2 million accruing interest at a rate of 5.75% per annum. The note was reduced to $1.5 million as a result of the settlement of a legal action against the sellers in 2003. In March 2005, we reached an agreement with the sellers and holders of the note as a result of an action brought against us by the sellers. Under the terms of the agreement, we paid the holders of the note $1.0 million in cash, and agreed to pay an additional $350,000 on June 1, 2006, and an additional $150,000 on June 1, 2007, in settlement of all claims. At March 31, 2006 and December 31, 2005 the outstanding amounts due were $500,000.

In connection with the purchase of Delta, we issued to the sellers a note in the amount of $350,000. The note bears interest at 2% and the principal and accrued interest was repaid on its maturity of April 1, 2006.

In connection with the purchase of Tubular, we agreed to pay a total of $1.2 million to Mr. Mortensen in exchange for a non-compete agreement. Monthly payments of $20,576 are due under this agreement through January 31, 2007. In connection with the purchase of Safco-Oil Field Products, Inc., or Safco,, we also agreed to pay a total of $150,000 to the sellers in exchange for a non-compete agreement. We are required to make annual payments of $50,000 through September 30, 2007. In connection with the purchase of Capcoil, we agreed to pay a total of $500,000 to two management employees in exchange for non-compete agreements. We are required to make annual payments of $110,000 through May 2008. Total amounts due under non-compete agreements at March 31, 2006 and December 31, 2005 were $615,000 and $698,000, respectively.

In 2000 we compensated directors, including current directors Nederlander and 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%. At March 31, 2006 and December 31, 2005, the principal and accrued interest on these notes totaled approximately $96,000.

We also had a real estate loan which was payable in equal monthly installments of $4,344 with the remaining outstanding balance due on January 1, 2010. The loan has a floating interest rate based on prime plus 2.0%. The outstanding principal balance was $548,000 at December 31, 2005. The balance of this loan was repaid in full in January 2006 with proceeds from our senior notes offering.

ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 8 — DEBT (Continued)

Other debt

We have various equipment financing loans with interest rates ranging from 5% to 8.2% and terms ranging from 2 to 5 years. As of March 31, 2006 and December 31, 2005, the outstanding balances for equipment financing loans were $2.8 million and $1.9 million, respectively. We also have various capital leases with terms that expire in 2008. As of March 31, 2006 and December 31, 2005, amounts outstanding under capital leases were $796,000 and $917,000, respectively. In January 2006, we prepaid $350,000 of the outstanding equipment loans with proceeds from our senior notes offering.

NOTE 9 — STOCKHOLDERS’ EQUITY

We also had options and warrants exercised in the first quarter of 2006, those exercises resulted in 365,342 shares of our common stock being issued for approximately $972,000. We recognized $942,000 of compensation expense related to stock options in the first quarter of 2006 that was recorded as additional paid in capital (see Note 3).

NOTE 10 — SEGMENT INFORMATION

At March 31, 2006, we had five operating segments including Directional Drilling Services (Strata and Target), Rental Tools, Casing and Tubing Services (Tubular Service), Compressed Air Drilling Services (AirComp) and Production Services. All of the 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,
	2006			2005
Revenues
Directional drilling services	$	15,054		$	9,901
Rental tools		10,421			373
Casing and tubing services		9,459			3,560
Compressed air drilling services		9,099			4,181
Production services		2,995			1,319


	$	47,028		$	19,334


Operating Income (Loss):
Directional drilling services	$	2,605		$	1,878
Rental tools		4,998			(80	)
Casing and tubing services		1,851			1,327
Compressed air drilling services		2,237			527
Production services		277			(39	)
General corporate		(3,335	)		(1,366	)


	$	8,633		$	2,247


Depreciation and Amortization:
Directional drilling services	$	289		$	150
Rental tools		1,671			88
Casing and Tubing services		699			440
Compressed air drilling services		684			448
Production services		293			136
General corporate		301			46


	$	3,937		$	1,308

ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 10 – SEGMENT INFORMATION (Continued)


	For the Three Months Ended
	March 31,
	2006		2005
Capital Expenditures:
Directional drilling services	$	2,698	$	263
Rental tools		684		17
Casing and tubing services		1,127		1,640
Compressed air drilling services		2,224		779
Production services		681		20
General corporate		172		9


	$	7,586	$	2,728


	As of
	March 31,		December 31,
	2006		2005
Goodwill:
Directional drilling services	$	4,168	$	4,168
Rental tools		—		—
Casing and tubing services		3,673		3,673
Compressed air drilling services		3,950		3,950
Production services		626		626
General corporate		—		—


	$	12,417	$	12,417


Assets:
Directional drilling services	$	26,284	$	20,960
Rental tools		104,101		8,034
Casing and tubing services		46,803		45,351
Compressed air drilling services		48,645		46,045
Production services		13,392		12,282
General corporate		18,605		4,683


	$	257,830	$	137,355


	For the Three Months Ended
	March 31,
	2006		2005
Revenues:
United States	$	45,089	$	17,561
International		1,939		1,773


	$	47,028	$	19,334

ALLIS-CHALMERS ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 11 — 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.

On December 31, 2004, Mountain Air was a defendant in an action brought in April 2004 in the District Court of Mesa County, Colorado, by the former owner of Mountain Air Drilling Service Company, Inc., from whom Mountain Air acquired assets in 2001. The plaintiff sought to accelerate payment of the note issued in connection with the acquisition and sought $1.9 million in damages (representing principal and interest due under the note), on the basis that Mountain Air failed to provide financial statements required by the note. We raised several defenses to the plaintiff’s claim. In March 2005, we reached an agreement with the plaintiff to settle the action and paid to the plaintiff $1.0 million on April 1, 2005 and agreed to pay an additional $350,000 on June 1, 2006, and $150,000 on June 1, 2007, in settlement of all amounts due under the promissory note and all other claims.

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.

NOTE 12 — SUBSEQUENT EVENTS

On April 4, 2006, we completed the acquisition of Rogers Oil Tool Services, Inc., or Rogers, based in Lafayette, Louisiana, for a total consideration of approximately $13.7 million, which includes $11.3 million in cash, $1.6 million in our common stock and a $750,000 three-year promissory note. In addition, we purchased all the patents and proprietary technology that Tommie L. Rogers, Rogers’ founder and Chief Executive Officer, developed at Rogers. Rogers provides service for tubing tongs and casing tongs and by renting and selling specialized automated power tongs to the snubbing and well control markets. Rogers also rents and sells drill pipe tongs, accessories, hydraulic power units and hydraulic tong positioners.

In April 2006, we entered into a stock purchase agreement for the acquisition of all of the outstanding capital stock of DLS Drilling, Logistics & Services Corporation. We anticipate that the purchase price will consist of $102.3 million in cash and 2.5 million shares of our common stock. The stock purchase agreement provides that if we are unable to obtain the necessary financing by August 15, 2006, we must pay to the sellers a cash break-up fee equal to $1.0 million. DLS currently operates a fleet of 51 rigs, including 20 drilling rigs, 18 workover rigs and 12 pulling rigs in Argentina and one drilling rig in Bolivia.

In May of 2006, we filed a registration statement for an offering of common stock in the amount of $80.0 million to fund a portion of the cash purchase price of DLS.

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

This document 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. Other factors are identified in our SEC filings, including our Annual Report on Form 10-K for the year ended December 31, 2005 under the heading “Risk Factors” located at the end of “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The following discussion and analysis should be read in conjunction with our selected historical financial data and our accompanying financial statements and the notes to those financial statements included elsewhere in this document. The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that reflect our plans, estimates and beliefs. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of risks and uncertainties, including, but not limited to, those discussed above.

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, domestically in Texas, Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Utah, Wyoming, offshore in the Gulf of Mexico and internationally in Mexico. We currently operate in five sectors of the oil and natural gas service industry: directional drilling services; rental tools; casing and tubing services; compressed air drilling services; and production 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. 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 demand for drilling services has historically been volatile and is affected by the capital expenditures of oil and natural gas exploration and production 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 working drilling rigs, typically referred to as the “rig count,” is an important indicator of activity levels in the oil and natural gas industry. The rig count in the U.S. increased from 862 as of December 31, 2002 to 1,608 on April 30, 2006 according to the Baker Hughes rig count. Furthermore, directional and horizontal rig counts increased from 283 as of December 31, 2002 to 656 on April 30, 2006, which accounted for 32.8% and 40.8% of the total U.S. rig count, respectively. Currently, we believe that the number of available drillings rigs is insufficient to meet the demand for drilling rigs. Consequently, unless a significant number of additional drilling rigs are brought online, the rig count may not increase substantially despite the strong demand.

Our cost of revenues represents all direct and indirect costs associated with the operation and maintenance of our equipment. The principal elements of these costs are direct and indirect labor and benefits, repairs and maintenance of our equipment, insurance, equipment rentals, fuel and depreciation. Operating expenses do not fluctuate in direct proportion to changes in revenues because, among other factors, we have a fixed base of inventory of equipment and facilities to support our operations, and in periods of low drilling activity we may also seek to preserve labor continuity to market our services and maintain our equipment.

Restatement

We understated diluted earnings per share due to an incorrect calculation of our weighted shares outstanding for the third quarter of 2003, for each of the first three quarters of 2004, for the years ended December 31, 2003 and 2004 and for the quarter ended March 31, 2005. In addition, we understated basic earnings per share due to an incorrect calculation of our weighted average basic shares outstanding for the quarter ended September 30, 2004. Consequently, we have restated our financial statements for each of those periods. The incorrect calculation resulted from a mathematical error and an improper application of SFAS No. 128. The effect of the restatement is to reduce weighted average diluted shares outstanding for each period and to reduce weighted average basic shares outstanding for the quarter ended September 30, 2004. Therefore, diluted earnings per share were increased for each period and basic earnings per share were increased for the quarter ended September 30, 2004. Based on the proper allocation of SFAS No. 128, for the three months ended March 31, 2005, weighted average diluted shares outstanding was 14,695,000, compared to the previously reported weighted average diluted shares outstanding of 17,789,000 for the three months ended March 31, 2005. The effect is to increase diluted earnings per share to $0.11 for the three months ended March 31, 2005 compared to the $0.09 previously reported for the period (See Note 6 to the Consolidated Condensed Financial Statements).

Comparison of Three Months Ended March 31, 2006 and 2005

Our revenues for the three months ended March 31, 2006 were $47.0 million, an increase of 143.2% compared to $19.3 million for the three months ended March 31, 2005. Revenues increased in all of our business segments due to acquisitions completed in the second and third quarters of 2005 and the first quarter of 2006, improved pricing for our services, the addition of operations and sales personnel, the opening of new operations offices and the purchase of additional equipment. Revenues increased most significantly at our rental tools segment due to the acquisition of Specialty Rental Tools, Inc., or Specialty, effective January 1, 2006 and Delta Rental Services Inc., or Delta, on April 1, 2005, and at the compressed air drilling segment due to the acquisition of the air drilling assets of W.T. Enterprises, Inc., or WT, on July 11, 2005, and improved pricing for our services in West Texas. Our directional drilling services segment revenues increased in the 2006 period compared to the 2005 period due to improved pricing for directional drilling services, the acquisition of Target Energy, Inc., or Target, which provides measurement-while-drilling tools, or MWD, the addition of operations and sales personnel, the opening of new operations offices and the purchase of additional down-hole motors which increased our capacity and market presence.

Revenues also increased at our casing and tubing services segment due the acquisition of the casing and tubing assets of Patterson Services, Inc on September 1, 2005, along with improved market conditions and increased market penetration for our services in South Texas, East Texas, Louisiana and the U.S. Gulf of Mexico. Also contributing to increased revenues was the acquisition of Capcoil Tubing Services, Inc., or Capcoil, as of May 1, 2005 in our production services segment.

Our gross profit for the quarter ended March 31, 2006 increased 195.8% to $16.7 million, or 35.4% of revenues, compared to $5.6 million, or 29.1%, of revenues for the three months ended March 31, 2005. The increase in gross profit as a percentage of revenues is due to the acquisition of Specialty as of January 1, 2006 and the acquisition of Delta as of April 1, 2005, in the high margin rental tool business. The increase in gross profit is also due to increased revenues at our compressed air drilling services segment, including the acquisition of the air drilling assets of WT, increased revenues and improved pricing in the directional drilling services segment, improved market conditions for our domestic casing and tubing segment and the acquisition of additional casing and tubing assets in September 2005. The increase in gross profit was partially offset by an increase in depreciation expense of 264.3% to $3.3 million for the first quarter of 2006 compared to $0.9 million for the first quarter of 2005. The increase is due to additional depreciable assets resulting from the acquisitions and capital expenditures. Our cost of revenues consists 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 gross profit as a percentage of revenues is generally affected by our level of revenues.

General and administrative expense was $6.5 million in the first quarter of 2006 period compared to $3.0 million for the first quarter of 2005. General and administrative expense increased due to the additional expenses associated with the acquisitions, and the hiring of additional sales and administrative personnel. General and administrative expense also increased because of increased accounting and consulting fees and other expenses in connection with initiatives to strengthen our internal control processes, costs related to Sarbanes Oxley compliance efforts and increased corporate accounting and administrative staff. As a percentage of revenues, general and administrative expenses were 13.8% in the 2006 quarter and 15.5% in the 2005 quarter.

We adopted SFAS 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. With the adoption of SFAS no. 123R, we recorded $0.9 million of expense related to stock options during the three months ended March 31, 2006. We adopted SFAS No. 123R using the modified prospective transition method, utilizing the Black-Scholes option pricing model for the calculation of the fair value of our employee stock options. Under the modified prospective method, we record compensation cost related to unvested stock awards as of December 31, 2005 by recognizing the unamortized grant date fair value of these awards over the remaining vesting periods of those awards with no change in historical reported earnings. Therefore, we recorded an expense of $0.9 million related to stock options for the three months ended March 31, 2006. Prior to January 1, 2006, we accounted for our stock-based compensation using Accounting Principle Board Opinion No. 25. Under APB No. 25, compensation expense is recognized for stock options with an exercise price that is less than the market price on the grant date of the option. Accordingly, no compensation cost was recognized under APB No. 25.

Amortization expense was $607,000 in the first quarter of 2006 compared to $394,000 in the first quarter of 2005. The increase in amortization expense is due to the amortization of intangible assets in connection with our acquisitions and the amortization of deferred financing costs.

Income from operations for the three months ended March 31, 2006 totaled $8.6 million, a 284.2% increase over income from operations of $2.2 million for the three months ended March 31, 2005, reflecting the increase in our revenues and gross profit, offset in part by increased general and administrative expenses, stock option expense and amortization.

Our net interest expense was $3.6 million in the first quarter of 2006, compared to $521,000 for the first quarter of 2005. Interest expense increased in the 2006 quarter due to the increased borrowings at a higher average interest rate. In January of 2006 we issued $160.0 million of senior notes bearing interest at 9.0% to fund the acquisition of Specialty, pay off other outstanding debt and for working capital.

Minority interest in income of subsidiaries for the first quarter of 2006 was $0 compared to $144,000 for the first quarter of 2005 due to the acquisition of the minority interest in AirComp L.L.C., or AirComp, as of July 11, 2005.

We had net income of $4.4 million for the first quarter of 2006, an increase of 182.3%, compared to net income of $1.6 million for the first quarter of 2005.

The following table compares revenues and income from operations for each of our business segments. Income (loss) from operations consists of revenues less cost of revenues, general and administrative expenses, and depreciation and amortization:


	Revenues						Income (Loss) from Operations
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2006		2005		Change		2006			2005			Change
					(in thousands)
Directional drilling services	$	15,054	$	9,901	$	5,153	$	2,605		$	1,878		$	727
Rental tools		10,421		373		10,048		4,998			(80	)		5,078
Casing and tubing services		9,459		3,560		5,899		1,851			1,327			524
Compressed air drilling services		9,099		4,181		4,918		2,237			527			1,710
Production services		2,995		1,319		1,676		277			(39	)		316
General corporate		—		—		—		(3,335	)		(1,366	)		(1,969	)


Total	$	47,028	$	19,334	$	27,694	$	8,633		$	2,247		$	6,386

Directional Drilling Services Segment

Revenues for the quarter ended March 31, 2006 for our directional drilling services segment were $15.1 million, an increase of 52.0% from the $9.9 million in revenues for the quarter ended March 31, 2005. Income from operations increased 38.7% to $2.6 million for the first quarter of 2006 from $1.9 million for the comparable 2005 period. The improved results for this segment are due to the increase in drilling activity in the Texas and Gulf Coast areas, improved pricing for directional and horizontal drilling services, the acquisition of Target as of August 1, 2005, the establishment of new operations in West Texas and Oklahoma, and the addition of operations and sales personnel which increased our capacity and market presence. Our increased operating expenses as a result of the addition of operations and personnel were more than offset by the growth in revenues and improved pricing for our services.

Rental Tools Segment

Revenues for the quarter ended March 31, 2006 for the rental tools segment were $10.4 million, from $373,000 in revenues for the quarter ended March 31, 2005. Income from operations increased to $5.0 million in the 2006 period compared to loss from operations of $80,000 in the 2005 period. Our rental tools revenues and operating income for the first quarter of 2006 increased compared to the prior year due primarily due to the acquisitions of Specialty and Delta. The acquisition of Specialty increased the rental tool revenue by $8.9 million for the quarter ended March 31, 2006. Delta was acquired as of April 1, 2005, and Specialty was acquired as of January 1, 2006, the effective date of their respective acquisitions. Safco-Oil Field Products, Inc., or Safco, Delta and Specialty were merged in February 2006 to form Allis-Chalmers Rental Tools, Inc

Casing and Tubing Services Segment

Revenues for the quarter ended March 31, 2006 for the casing and tubing services segment were $9.5 million, an increase of 165.7% from the $3.6 million in revenues for the quarter ended March 31, 2005. Revenues from domestic operations increased to $8.0 million in the 2006 period from $1.9 million in the 2005 period as a result of the acquisition of the casing and tubing assets of Patterson Services on September 1, 2005, which resulted in increased market penetration for our services in South Texas, East Texas, Louisiana and the U.S. Gulf of Mexico. Revenues from Mexico operations decreased to $1.5 million in the first quarter of 2006 from $1.7 million in the 2005 period. Income from operations increased 39.5% to $1.9 million in the first quarter of 2006 from $1.3 million in the first quarter of 2005. The increase in this segment’s operating income is due to our increased revenues from domestic operations. The operating income as a percentage of revenue decreased to 19.6% for the three months ended March 31, 2006 compared to 37.3% for the same period of 2005. The decrease in operating income as a percentage of revenues is due to the increase in domestic revenues as compared to Mexico revenues, which have higher operating income margins.

Compressed Air Drilling Services Segment

Our compressed air drilling revenues were $9.1 million for the three months ended March 31, 2006, an increase of 117.6% compared to $4.2 million in revenues for the three months ended March 31, 2005. Income from operations increased to $2.2 million in the 2006 period compared to income from operations of $527,000 in the 2005 period. Our compressed air drilling revenues and operating income for the first quarter of 2006 increased compared to the prior year due primarily due to the acquisition of the air drilling assets of WT as of July 11, 2005, improved pricing for our services and our investment in additional equipment.

Production Services Segment

Operations for this segment consist of Downhole Injection Services, LLC, or Downhole which was acquired December 1, 2004, and Capcoil which was acquired May 1, 2005. Downhole and Capcoil were merged in February 2006, to form Allis-Chalmers Production Services, Inc. Revenues were $3.0 million for the three months ended March 31, 2006, an increase of 127.1% compared to $1.3 million in revenues for the three months ended March 31, 2005. Income from operations increased to $277,000 in the 2006 period compared to loss from operations of $39,000 in the 2005 period. Our production services revenues and operating income for the first quarter of 2006 increased compared to the prior year due primarily due to the acquisition of Capcoil.

General Corporate

General corporate expenses increased $1.9 million to $3.3 million for the three months ended March 31, 2006 compared to $1.4 million for the three months ended March 31, 2005. The increase was due to stock option expense of $0.9 million recorded in 2006 with the adoption of SFAS 123R, the increase in accounting and administrative staff to support the growing organization, increased franchise taxes based on our increased authorized shares and cost related to our Sarbanes-Oxley compliance effort.

Liquidity and Capital Resources

Our on-going capital requirements arise primarily from our need to service our debt, to complete acquisitions and acquire and maintain equipment, and to fund our working capital requirements. Our primary sources of liquidity are borrowings under our revolving lines of credit, proceeds from the issuance of debt and equity securities and cash flows from operations. We had cash and cash equivalents of $10.7 million at March 31, 2006 compared to $1.9 million at December 31, 2005.

Operating Activities

In the three months ended March 31, 2006, our operating activities used $5.6 million in cash compared to a use of $822,000 for the same period in 2005. Net income for the three months ended March 31, 2006 increased to $4.4 million, compared to $1.6 million in the 2005 period. The $4.4 million in net income for the 2006 period includes a charge of $0.9 million related to the expensing of stock options as required under SFAS No. 123R. Revenues and income from operations increased in the first three months of 2006 due to acquisitions completed in the first quarter of 2006 and the second and third quarters of 2005, the investment in additional equipment, the opening of new operations offices and the addition of operations and sales personnel. Non-cash expenses totaled $4.9 million during the first three months of 2006 consisting of $3.9 million of depreciation and amortization, $0.9 million from the expensing of stock options, $355,000 of imputed interest related to the effective date of the Specialty acquisition, $180,000 related to increases to the allowance for doubtful accounts receivables, offset by $514,000 on the gain from asset retirements. Non-cash expenses during the first three months of 2005 totaled $1.5 million, consisting of depreciation and amortization expense of $1.3 million and minority interest of $144,000.

During the three months ended March 31, 2006, changes in operating assets and liabilities used $14.9 million in cash, principally due to an increase of $4.3 million in accounts receivable, an increase of $1.5 million in inventory, a decrease of $1.3 million in accounts payable, and a decrease of $11.0 million in an accrued expense, offset in part by an increase of $2.8 million in accrued interest. Accounts receivable increased due to the increase in our revenues in the first three months of 2006. Other inventory increased primarily due to increased activity levels. The decrease in accrued expenses can be attributed to accrued bonuses of Specialty that we paid in connection with the acquisition. The increase in accrued interest relates to our 9.0% senior notes.

During the three months ended March 31, 2005, changes in operating assets and liabilities used $3.8 million in cash, principally due to an increase of $3.4 million in accounts receivable, an increase of $515,000 in inventory and other assets, and a decrease of $92,000 in accrued expenses, offset in part by an increase in accrued salaries, benefits and payroll taxes of $185,000. Accounts receivable increased by $3.4 million at March 31, 2005 due to the increase in our revenues in the first quarter of 2005. Other assets increased due primarily to an increase in prepaid insurance related to insurance premium deposits required for our policies that went into affect April 1, 2005.

Investing Activities

During the three months ended March 31, 2006, we used $89.8 million in investing activities, consisting of $83.4 million for the acquisition of Specialty, net of cash received and $7.6 million for capital expenditures, offset by $1.2 million of proceeds from equipment sales. Included in the $7.6 million for capital expenditures was $2.6 million for the expansion of our MWD equipment used in the directional drilling segment and $2.2 million for additional equipment in our compressed air drilling services segment. A majority of our equipment sales relate to items “lost in hole” by our customers. During the first three months of 2005, we used $2.7 million in investing activities, consisting principally of the purchase of equipment of $1.6 million for casing equipment, approximately $263,000 for the purchase of downhole motors and approximately $779,000 for new compressed air drilling equipment.

Financing Activities

During the three months ended March 31, 2006, financing activities provided $104.1 million in cash. We received $161.4 million in proceeds from long-term debt, repaid $43.5 million in borrowings under long-term debt facilities, repaid $3.0 million in related party debt, repaid $6.4 million under our line of credit and paid $5.3 in debt issuance costs. We also received $972,000 in proceeds from the exercise of options and warrants. On January 18, 2006, we closed on a private offering of $160.0 million aggregate principal amount of our senior notes. The notes are due January 15, 2014 and bear interest at 9.0%. The proceeds from the sale of the notes were used to fund the Specialty acquisition, to repay existing debt and for general corporate purposes. During the three months ended March 31, 2005, financing activities provided a net of $2.2 million in cash. We received $2.4 million, net, in borrowings under long-term debt facilities and paid $178,000 in debt issuance costs.

Prior to January 18, 2006, we were party to a July 2005 credit agreement that provided for the following senior secured credit facilities:

	•		A $13.0 million revolving line of credit. Borrowings were limited to 85% of eligible accounts receivable plus 50% of eligible inventory (up to a maximum of $2.0 million of borrowings based on inventory). This line of credit was to be used to finance working capital requirements and other general corporate purposes, including the issuance of standby letters of credit. Outstanding borrowings under this line of credit were $6.4 million at a margin above prime and LIBOR rates plus margin averaging approximately 8.1% as of December 31, 2005.

	•		Two term loans totaling $42.0 million. Outstanding borrowings under these term loans were $42.0 million as of December 31, 2005. These loans were at LIBOR rates plus a margin which averages approximately 7.8% at December 31, 2005.

At March 31, 2006, we had $169.1 million in outstanding indebtedness, of which $166.0 million was long term debt and $3.1 million was the current portion of long term debt.

In connection with the purchase of Tubular, we agreed to pay a total of $1.2 million to Mr. Mortensen in exchange for a non-compete agreement. Monthly payments of $20,576 are due under this agreement through January 31, 2007. In connection with the purchase of Safco, we also agreed to pay a total of $150,000 to the sellers in exchange for a non-compete agreement. We are required to make annual payments of $50,000 through September 30, 2007. In connection with the purchase of Capcoil, we agreed to pay a total of $500,000 to two management employees in exchange for non-compete agreements. We are required to make annual payments of $110,000 through May 2008. Total amounts due under non-compete agreements at March 31, 2006 and December 31, 2005 were $615,000 and $698,000, respectively.

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.

Capital Requirements

We have identified capital expenditure projects that will require up to approximately $10.0 million for the remainder of 2006, exclusive of any acquisitions. We believe that our current cash generated from operations, cash available under our credit facilities and cash on hand will provide sufficient funds for our identified projects.

We intend to implement a growth strategy of increasing the scope of services through both internal growth and acquisitions. We are regularly involved in discussions with a number of potential acquisition candidates. The acquisition of assets could require additional financing, which we currently anticipate would be borrowed under our bank facility. Any such borrowing would require the consent of our lenders under our bank credit facilities. We also expect to make capital expenditures to acquire and to maintain our existing equipment. Our performance and cash flow from operations will be determined by the demand for our services which in turn are affected by our customers’ expenditures for oil and gas exploration and development, and industry perceptions and expectations of future oil and natural gas prices in the areas where we operate. We will need to refinance our existing debt facilities as they become due and provide funds for capital expenditures and acquisitions. To effect our expansion plans, we will require additional equity or debt financing and the proceeds of the pending offering. There can be no assurance that we will be successful in raising the additional debt or equity capital or that we can do so on terms that will be acceptable to us.

Recent Developments

In May of 2006, we filed a registration statement for an offering of common stock in the amount of $80.0 million to fund a portion of the cash purchase price of DLS.

Critical Accounting Policies

Please see our Annual Report on Form 10-K for the year ended December 31, 2005 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, 2006.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections. SFAS No. 154 requires retroactive application of a voluntary change in accounting principle to prior period financial statements unless it is impracticable. SFAS No. 154 also requires that a change in method of depreciation, amortization or depletion for long-lived, non-financial assets be accounted for as a change in accounting estimate that is affected by a change in accounting principle. SFAS No. 154 replaces APB Opinion No. 20, Accounting Changes and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statement’. SFAS No. 154 is effective for fiscal years beginning after December 15, 2005. We adopted the provisions of SFAS No. 154 as of January 1, 2006 and the adoption did not have a material impact on our results of operations.

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment. SFAS No. 123R revises SFAS No. 123, Accounting for Stock-Based Compensation, and focuses on accounting for share-based payments for services by employer to employee. The statement requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. We adopted SFAS No. 123R as of January 1, 2006 and used the modified prospective transition method, utilizing the Black-Scholes option pricing model for the calculation of the fair value of our employee stock options. Under the modified prospective method, stock option awards that are granted, modified or settled after January 1, 2006 will be measured and accounted for in accordance with SFAS No. 123R. Compensation cost for awards granted prior to, but not vested, as of January 1, 2006 would be based on the grant date attributes originally used to value those awards for pro forma purposes under SFAS No. 123. See Note 3 of our unaudited consolidated condensed financial statements for a more detailed description of our adoption of SFAS No. 123R.

In November 2004, the FASB issued SFAS No. 151, Inventory Costs – an Amendment of ARB No. 43, Chapter 4, which amends the guidance in ARB No. 43 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. SFAS No. 151 requires that these items be recognized as current period charges. In addition, SFAS No. 151 requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. We adopted the provisions of SFAS No. 151, on a prospective basis, as of January 1, 2006 and the adoption did not have a material impact on our results of operations.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE 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.

At December 31, 2005, we were exposed to interest rate fluctuations on approximately $49.0 million of notes payable and bank credit facility borrowings carrying variable interest rates. During the three months ended March 31, 2006, we repaid all variable interest rate debt.

We have also been subject to interest rate market risk for short-term invested cash and cash equivalents. The principal of such invested funds would not be subject to fluctuating value because of their highly liquid short-term nature. As of March 31, 2006, we had $9.3 million invested in short-term investments.

Foreign Currency Exchange Rate Risk.

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.

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports under the Securities Exchange Act of 1934, as amended, 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.

Management, including our chief executive officer and our chief financial officer, has evaluated the effectiveness of our “disclosure controls and procedures” (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this Report, which we refer to as the Evaluation Date.

As disclosed in the notes to our consolidated financial statements included elsewhere in this report and under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Restatement,” we understated diluted earnings per share due to an incorrect calculation of our weighted shares outstanding for the third quarter of 2003, for each of the first three quarters of 2004, for the years ended December 31, 2003 and 2004 and for the quarter ended March 31, 2005. In addition, we understated basic earnings per share due to an incorrect calculation of our weighted average basic shares outstanding for the quarter ended September 30, 2004. Consequently, we have restated our financial statements for each of those periods. The incorrect calculation resulted from a mathematical error and an improper application of Statement of Financial Accounting Standards, or SFAS, No. 128, Earnings Per Share. Management has concluded that the need to restate our financial statements resulted, in part, from the lack of sufficient experienced accounting personnel, which in turn resulted in a lack of effective control over the financial reporting process.

As part of our growth strategy over the past five years, we have completed acquisitions of several privately-held businesses, including closely-held entities. Prior to becoming part of our consolidated company, these businesses were not required to implement or maintain, and did not implement or maintain, the disclosure controls and procedures or internal controls over financial reporting that federal law requires of publicly-held companies such as ours. We are in the process of creating and implementing appropriate disclosure controls and procedures and internal controls over financial reporting at each of our recently acquired businesses. However, we have not yet completed this process and cannot assure you as to when the process will be complete.

In addition, during the fourth quarter of 2005, we failed to timely file a Current Report on Form 8-K relating to the issuance of shares of our common stock in connection with recent stock option and warrant exercises. The current report, which was due to be filed in November 2005, was filed in February 2006.

As a result of the issues described above, our management has concluded that, as of the Evaluation Date, our disclosure controls and procedures were not effective to enable us to record, process, summarize, and report information required to be included in our SEC filings within the required time period, and to ensure that such information is accumulated and communicated to our management, including our chief executive officer and chief financial accounting officer, to allow timely decisions regarding required disclosure.

(b) Change in Internal Control Over Financial Reporting.

There were the following 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) that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting:

	•		We continued the engagement of an independent internal controls consulting firm which is in the process of documenting, analyzing, identifying and testing internal control.

	•		In January 2006, we hired a certified public accountant to be our new financial reporting manager, the existing financial reporting manager was promoted to manager of internal controls.

	•		During the quarter we replaced two divisional controllers with certified public accountants.

	•		During the quarter we consolidated most of our accounting functions into one office. We believe this has resulted in better utilization and supervision of accounting resources.

	•		During the quarter we began the process of consolidating our payroll functions to improve quality control over the process.

	•		During the quarter we completed the implementation of our new general ledger accounting software in all of our subsidiaries existing as of December 31, 2005. We continue to implement improvements in the way the software is utilized.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are involved in various 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. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

During the three months ended March 31, 2006, we issued 313,442 shares of our common stock to private investors upon the exercise of previously issued warrants. The exercise price of the warrants was $2.50 per share resulting in total proceeds to us of $783,605. The proceeds were used in the normal course of operations for general corporate purposes. The transaction was exempt from the registration requirements of the Securities Act of 1933, as amended, pursuant to Regulation D promulgated by the SEC under the Securities Act.

During the three months ended March 31, 2006, we also issued 400 shares of our common stock to Robert E. Nederlander, one of our directors, upon the exercise of previously granted stock options. The exercise price of the options was $13.75 per share resulting in total proceeds to us of $5,500. The proceeds were used in the normal course of operations for general corporate purposes. The transaction was exempt from the registration requirements of the Securities Act pursuant to Section 4(2) of the Securities Act.

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 Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on May 10, 2006.


		AllisChalmers Energy Inc.
		(Registrant)

		/S/ MUNAWAR H. HIDAYATALLAH

		Munawar H. Hidayatallah
		Chief Executive Officer and Chairman

EXHIBIT INDEX

2.1		Stock Purchase Agreement dated as of December 20, 2005 by and between the Registrant and Joe Van Matre (incorporated by reference to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2005).

2.2		Stock Purchase Agreement dated as of April 3, 2006 by and between the Registrant and Tommie L. Rogers (incorporated by reference to the Registrant’s Current Report on Form 8-K filed on April 6, 2006).

2.3*		Stock Purchase Agreement dated as of April 27, 2006 by and among the Registrant, Bridas International Holdings Ltd., Bridas Central Company Ltd., and Associated Petroleum Investors Limited.

4.1		Indenture dated as of January 18, 2006 by and among the Registrant, the Guarantors named therein and Wells Fargo Bank, N.A., as trustee (incorporated by reference to the Registrant’s Current Report on Form 8-K filed on January 24, 2006).

4.2		Form of 9.0% Senior Note due 2014 (incorporated by reference to the Registrant’s Current Report on Form 8-K filed on January 24, 2006).

10.1		Purchase Agreement dated as of January 12, 2006 by and among the Registrant, the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to the Registrant’s Current Report on Form 8-K filed on January 24, 2006).

10.2		Registration Rights Agreement dated as of January 18, 2006 by and among the Registrant, the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to the Registrant’s Current Report on Form 8-K filed on January 24, 2006).

10.3		Amended and Restated Credit Agreement dated as of January 18, 2006 by and among the Registrant, as borrower, Royal Bank of Canada, as administrative agent and collateral agent, RBC Capital Markets, as lead arranger and sole bookrunner, and the lenders party thereto (incorporated by reference to the Registrant’s Current Report on Form 8-K filed on January 24, 2006).

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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