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 JUNE 30, 2006

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

FOR THE TRANSITION PERIOD FROM                      TO                     

ALLIS-CHALMERS ENERGY INC.

(Exact name of registrant as specified in its charter)

DELAWARE		39-0126090
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

(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 August 8, 2006 there were 18,533,815 shares of common stock, par value $0.01 per share, outstanding.

 

 

ALLIS-CHALMERS ENERGY INC.

FORM 10-Q

For the Quarterly Period Ended June 30, 2006

TABLE OF CONTENTS

ITEM				PAGE
		PART I
1.		Financial Statements
		Consolidated Condensed Balance Sheets as of June 30, 2006 and December 31, 2005			3
		Consolidated Condensed Income Statements for the three and six months ended June 30, 2006 and 2005			4
		Consolidated Condensed Statements of Cash Flows for the six months ended June 30, 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			27
4.		Controls and Procedures			27
		PART II
1.		Legal Proceedings			28
2.		Unregistered Sales of Equity Securities and Use of Proceeds			28
6.		Exhibits			28
Signatures					29
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO and CFO Pursuant to Section 906

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALLIS-CHALMERS ENERGY INC.

(in thousands, except for share and per share amounts)

		June 30,				December 31,
		2006				2005
		(unaudited)
Assets
Cash and cash equivalents		$	6,208			$	1,920
Trade receivables, net			49,114				26,964
Inventory			9,897				5,945
Prepaid expenses and other			2,655				823
Total current assets			67,874				35,652
Property and equipment, net			185,750				80,574
Goodwill			12,417				12,417
Other intangible assets, net			7,131				6,783
Debt issuance costs, net			6,187				1,298
Other assets			1,327				631
Total assets		$	280,686			$	137,355
Liabilities and Stockholders’ Equity
Current maturities of long-term debt		$	4,059			$	5,632
Trade accounts payable			9,616				9,018
Accrued salaries, benefits and payroll taxes			2,270				1,271
Accrued interest			6,654				289
Accrued income taxes			1,686				668
Accrued expenses			6,095				3,682
Accounts payable, related parties			—				60
Total current liabilities			30,380				20,620
Accrued postretirement benefit obligations			319				335
Long-term debt, net of current maturities			165,957				54,937
Other long-term liabilities			749				588
Total liabilities			197,405				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; 18,516,714 issued and outstanding at June 30, 2006 and 16,859,988 issued and outstanding at December 31, 2005)			185				169
Capital in excess of par value			67,261				58,889
Retained earnings			15,835				1,817
Total stockholders’ equity			83,281				60,875
Total liabilities and stockholders’ equity		$	280,686			$	137,355

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

ALLIS-CHALMERS ENERGY INC.

(in thousands, except per share amounts)

(unaudited)

		For the Three Months Ended								For the Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
Revenues		$	60,470			$	23,588			$	107,498			$	42,922
Cost of revenues
Direct costs			31,966				15,691				59,081				28,476
Depreciation			3,828				1,092				7,158				2,006
Total cost of revenues			35,794				16,783				66,239				30,482
Gross margin			24,676				6,805				41,259				12,440
General and administrative			8,139				3,465				15,482				6,459
Amortization			666				426				1,273				820
Income from operations			15,871				2,914				24,504				5,161
Other income (expense):
Interest			(3,797	)			(645	)			(7,425	)			(1,166	)
Other			(6	)			10				20				158
Total other income (expense)			(3,803	)			(635	)			(7,405	)			(1,008	)
Net income before minority interest and income taxes			12,068				2,279				17,099				4,153
Minority interest in income of subsidiaries			—				(344	)			—				(488	)
Provision for income taxes			(2,474	)			(166	)			(3,081	)			(329	)
Net income		$	9,594			$	1,769			$	14,018			$	3,336
Net income per common share:
Basic		$	0.53			$	0.13			$	0.80			$	0.24
Diluted		$	0.50			$	0.12			$	0.74			$	0.22
Weighted average shares outstanding:
Basic			18,050				13,967				17,578				13,800
Diluted			19,140				15,103				19,000				14,900

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

ALLIS-CHALMERS ENERGY INC.

(in thousands)

(unaudited)

		For the Six Months Ended
		June 30,
		2006				2005
Cash Flows from Operating Activities:
Net income		$	14,018			$	3,336
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation			7,158				2,006
Amortization			1,273				820
Imputed interest			355				—
Stock option expense			1,778				—
Provision for bad debts			279				—
Minority interest in income of subsidiaries			—				488
Loss on sale of property and equipment			119				—
Changes in operating assets and liabilities, net of acquisitions:
(Increase) in trade receivable			(13,581	)			(3,024	)
(Increase) in inventory			(1,499	)			(1,090	)
Decrease in other current assets			278				201
(Increase) in other assets			(663	)			(375	)
(Decrease) increase in accounts payable			(1,517	)			610
Increase in accrued interest			6,365				35
Increase (decrease) in accrued expenses			1,818				(296	)
Increase in accrued salaries, benefits and payroll taxes			657				172
Increase in other long-term liabilities			145				6
Net Cash Provided By Operating Activities			16,983				2,889
Cash Flows from Investing Activities:
Acquisition of businesses, net of cash received			(106,564	)			(7,088	)
Proceeds from sale of property and equipment			1,814				—
Purchase of property and equipment			(14,246	)			(5,463	)
Net Cash Used In Investing Activities			(118,996	)			(12,551	)
Cash Flows from Financing Activities:
Proceeds from exercises of options and warrants			4,960				—
Proceeds from long-term debt			161,412				5,210
Proceeds from line of credit			5,000				—
Repayments on long-term debt			(45,291	)			—
Repayments on related party debt			(3,031	)			—
Repayments on line of credit			(11,400	)			—
Debt issuance costs			(5,349	)			(199	)
Net Cash Provided By Financing Activities			106,301				5,011
Net change in cash and cash equivalents			4,288				(4,651	)
Cash and cash equivalents at beginning of year			1,920				7,344
Cash and cash equivalents at end of period		$	6,208			$	2,693

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

ALLIS-CHALMERS ENERGY INC.

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 July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. It prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation is effective for fiscal years beginning after December 15, 2006. We are currently evaluating the provisions of FIN 48 and have not yet determined the impact, if any, on our financial statements.

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

NOTE 2 — ACQUISITIONS

Effective April 1, 2006, we acquired 100% of the outstanding stock of Rogers Oil Tools, 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 rents and sells 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. 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:

Current assets		$	4,520
Property and equipment			9,866
Intangible assets			1,131
Total assets acquired			15,517
Current liabilities			1,717
Other long-term liabilities			100
Total liabilities assumed			1,817
Net assets acquired		$	13,700

Approximately $380,000 of costs were incurred in relation to the Rogers acquisition. Rogers’ historical property and equipment values were increased by approximately $8.4 million based on third-party valuations. Intangible assets include $981,000 assigned to patents and $150,000 assigned to non-compete based on third-party valuations and employment contracts. The intangibles have a weighted-average useful life of 9 years.

Effective January 1, 2006, we acquired 100% of the outstanding stock of Specialty Rental Tools, Inc., or Specialty, for $96.0 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 $32.7 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			2,058
Long-term debt			74
Total liabilities assumed			2,132
Net assets acquired		$	96,000

Approximately $453,000 of costs were incurred in relation to the Specialty acquisition. Specialty’s historical property and equipment values were increased by approximately $71.5 million based on third-party valuations.

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.

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

NOTE 2 — ACQUISITIONS (Continued)

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.

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 Rogers, 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								For the Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
Revenues		$	60,470			$	35,572			$	109,583			$	65,567
Operating income			15,871				7,369				24,510				10,834
Net income			9,594				4,307				13,910				5,322
Net income per common share:
Basic		$	0.53			$	0.31			$	0.79			$	0.37
Diluted		$	0.50			$	0.28			$	0.73			$	0.35

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 six months 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.

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

NOTE 3 — STOCK-BASED COMPENSATION (Continued)

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. Our net income for the three and six months ended June 30, 2006 includes approximately $836,000 and $1,778,000 of compensation costs related to share-based payments. As of June 30, 2006 there is $2.3 million of unrecognized compensation expense related to non-vested stock option grants. We expect approximately $1.5 million to be recognized over the remainder of 2006 and approximately $860,000 to be recognized in 2007.

A summary of our stock option activity and related information as of June 30, 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			(38,333	)			4.52
Exercised			(1,217,999	)			3.43
Outstanding at end of period			1,604,535				6.39				8.74			$	11.6
Exercisable at end of period			782,702				5.34				8.46			$	6.5

The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between the closing price of our common stock on the last trading day of the second quarter of 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 June 30, 2006. The total intrinsic value of options exercised during the three and six months ended June 30, 2006 was $15.6 and $16.2 million, respectively. The total cash received from option exercises during the three and six months ended June 30, 2006 was $4.0 and $4.2 million, respectively.

No options were granted in the first six months of 2006. The following summarizes the assumptions used in the June 30, 2005 Black-Scholes model:

		For the Three				For the Six
		Months Ended				Months Ended
		June 30, 2005				June 30, 2005
Expected dividend yield			—				—
Expected price volatility			89.91	%			98.65	%
Risk-free interest rate			6.25	%			6.63	%
Expected life of options		7 years				7 years
Weighted average fair value of options granted at market value		$	4.01			$	3.12

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

NOTE 3 — STOCK-BASED COMPENSATION (Continued)

The following table illustrates the pro-forma effect on net income and net income per share for the three and six months ended June 30, 2005 had we applied the fair value recognition provisions of SFAS No. 123R (in thousands, except per share amounts):

				Three Months				Six Months
				Ended June 30,
				2005				2005
Net income: As reported				$	1,769			$	3,336
Less total stock based employee compensation expense determined under fair value based method for all awards net of tax related effects					(836	)			(1,505	)
Pro forma net income				$	933			$	1,831
Net income per share:
Basic		As reported		$	0.13			$	0.24
		Pro forma		$	0.07			$	0.13
Diluted		As reported		$	0.12			$	0.22
		Pro forma		$	0.06			$	0.12

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								For the Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
Numerator:
Net income		$	9,594			$	1,769			$	14,018			$	3,336
Denominator:
Basic earnings per share — weighted average shares outstanding			18,050				13,967				17,578				13,800
Effect of potentially dilutive common shares:
Warrants and employee and director stock options			1,090				1,136				1,422				1,100
Diluted earnings per share — weighted average shares
Outstanding and assumed conversions			19,140				15,103				19,000				14,900
Net income per share — basic		$	0.53			$	0.13			$	0.80			$	0.24
Net income per share — diluted		$	0.50			$	0.12			$	0.74			$	0.22

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

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 June 30, 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 and six months ended June 30, 2006 were $429,000 and $813,000, respectively, compared to $441,000 and $607,000, respectively for the same periods last year. At June 30, 2006, intangible assets totaled $7.1 million, net of $3.4 million of accumulated amortization.

NOTE 6 — INVENTORY

Inventory is comprised of the following (in thousands):

		June 30,				December 31,
		2006				2005
Hammer bits
Finished goods		$	1,507			$	1,402
Work in process			1,616				787
Raw materials			2,429				233
Total hammer bits			5,552				2,422
Hammers			801				584
Drive pipe			572				666
Rental supplies			355				64
Chemicals			132				201
Coiled tubing and related inventory			1,278				1,145
Shop supplies and related inventory			1,207				863
Total inventory		$	9,897			$	5,945

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

NOTE 7- DEBT

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

		June 30,				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 notes			900				850
Notes payable under non-compete agreements			443				698
Notes payable to former directors			32				96
Real estate loan			—				548
Equipment and vehicle installment notes			2,417				1,939
Insurance premium financing			1,553				—
Capital lease obligations			671				917
Total debt			170,016				60,569
Less: short-term debt and current maturities			4,059				5,632
Long-term debt obligations		$	165,957			$	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.

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.

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

NOTE 7 — DEBT (Continued)

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. This note was repaid from the proceeds of our offering of $95.0 million of 9.0% senior notes, which we completed in August 2006.

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 June 30, 2006 and December 31, 2005 the outstanding amounts due were $150,000 and $500,000, respectively.

In connection with the purchase of Delta, we issued to the sellers a note in the amount of $350,000. The note bore interest at 2% and the principal and accrued interest was repaid on its maturity of April 1, 2006. 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% and is due April 3, 2009.

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 these non-compete agreements at June 30, 2006 and December 31, 2005 were $443,000 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 June 30, 2006 and December 31, 2005, the principal and accrued interest on these notes totaled approximately $32,000 and $96,000, respectively.

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 had 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 7 — 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 June 30, 2006 and December 31, 2005, the outstanding balances for equipment financing loans were $2.4 million and $1.9 million, respectively. In April 2006, we obtained an insurance premium financing in the amount of $1.9 million with a fixed interest rate of 5.6%. Under terms of the agreement, amounts outstanding are paid over a 10 month repayment schedule. The outstanding balance of this note was approximately $1.6 million as of June 30, 2006. We also have various capital leases with terms that expire in 2008. As of June 30, 2006 and December 31, 2005, amounts outstanding under capital leases were $671,000 and $917,000, respectively. In January 2006, we prepaid $350,000 of the outstanding equipment loans with proceeds from our senior notes offering.

NOTE 8 — STOCKHOLDERS’ EQUITY

We issued 125,285 shares of our common stock in relation to the Roger’s acquisition (see Note 2). We also had options and warrants exercised in the first six months of 2006, which resulted in 1,531,441 shares of our common stock being issued for approximately $5.0 million. We recognized approximately $1.8 million of compensation expense related to stock options in the first six months of 2006 that was recorded as additional paid in capital (see Note 3).

NOTE 9 — SUPPLEMENTAL CASH FLOW INFORMATION

		For the Six Months Ended
		June 30,
		2006				2005
Cash paid for interest and income taxes:
Interest		$	832			$	1,166
Income taxes		$	2,063			$	329
Noncash activities:
Insurance premium financed		$	1,933			$	—
Common stock issued for acquisition of business		$	1,650			$	—
Note payable issued for acquisition of business		$	750			$	—
Non-compete payable in the future		$	150			$	—

NOTE 10- SEGMENT INFORMATION

At June 30, 2006, we had five operating segments including Directional Drilling Services (Strata and Target), Rental Tools, Casing and Tubing Services (Tubular Service and Rogers), 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								For the Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
Revenues
Directional drilling services		$	18,315			$	10,934			$	33,369			$	20,835
Rental tools			12,707				1,566				23,128				1,940
Casing and tubing services			14,569				3,933				24,028				7,493
Compressed air drilling services			10,949				4,866				20,048				9,047
Production services			3,930				2,289				6,925				3,607
		$	60,470			$	23,588			$	107,498			$	42,922

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

NOTE 10 — SEGMENT INFORMATION (Continued)

		For the Three Months Ended								For the Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
Operating Income (Loss):
Directional drilling services		$	4,367			$	1,495			$	6,972			$	3,373
Rental tools			7,308				405				12,306				326
Casing and tubing services			4,314				1,354				6,165				2,679
Compressed air drilling services			3,204				1,002				5,441				1,529
Production services			341				36				618				(2	)
General corporate			(3,663	)			(1,378	)			(6,998	)			(2,744	)
		$	15,871			$	2,914			$	24,504			$	5,161
Depreciation and Amortization:
Directional drilling services		$	359			$	207			$	648			$	357
Rental tools			1,715				176				3,386				265
Casing and tubing services			1,069				468				1,768				908
Compressed air drilling services			731				422				1,415				870
Production services			299				189				592				325
General corporate			321				56				622				101
		$	4,494			$	1,518			$	8,431			$	2,826
Capital Expenditures:
Directional drilling services		$	707			$	937			$	3,405			$	1,200
Rental tools			417				7				1,101				7
Casing and tubing services			4,373				217				5,500				1,857
Compressed air drilling services			792				1,147				3,016				1,926
Production services			365				253				1,046				290
General corporate			6				174				178				183
		$	6,660			$	2,735			$	14,246			$	5,463

		As of
		June 30,				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		$	28,496			$	20,960
Rental tools			105,994				8,034
Casing and tubing services			67,984				45,351
Compressed air drilling services			49,502				46,045
Production services			13,853				12,282
General corporate			14,857				4,683
		$	280,686			$	137,355

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

NOTE 10 — SEGMENT INFORMATION (Continued)

		For the Three Months Ended								For the Six Months Ended
		June 30,								June 30,
		2006				2005				2006				2005
Revenues:
United States		$	58,572			$	21,832			$	103,662			$	39,393
International			1,898				1,756				3,836				3,529
		$	60,470			$	23,588			$	107,498			$	42,922

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.

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 August 8, 2006, we entered into an amendment to our amended and restated credit agreement dated as of January 18, 2006. The amendment, among other things, amends the credit agreement to (a) allow us to (i) issue and sell $95.0 million aggregate principal amount of our 9.0% senior notes due 2014 and (ii) issue and sell 3,450,000 shares of our common stock, (b) allow us to use the net proceeds from the senior notes offering and the public offering to purchase all the outstanding capital stock of DLS Drilling Logistics and Services Corporation, or DLS, (c) exclude certain existing indebtedness and investments of DLS and investments and indebtedness related to the DLS Acquisition from the covenants contained in the Credit Agreement and (d) increase the amount of permitted lease obligations and capital expenditures.

On August 8, 2006, we priced a public offering of 3.0 million shares of our common stock at $14.50 per share. We have granted the underwriters a 30-day option to purchase up to an additional 450,000 shares to cover over-allotments, if any. On August 14, 2006, we closed the common stock offering and the underwriters elected to exercise the over-allotment option in full.

We also priced a private offering of $95.0 million aggregate principal amount of 9.0% senior notes on August 8, 2006. The notes were sold to investors at a price of 100% of the principal amount thereof, plus accrued interest from July 15, 2006. Fixed interest on the notes will be payable on January 15 and July 15 of each year, beginning on January 15, 2007 and the notes mature on January 15, 2014. The sale of the notes closed on August 14, 2006.

On August 14, 2006, we completed the acquisition of all of the outstanding capital stock of DLS. The purchase price of DLS consisted of $93.7 million in cash, 2.5 million shares of our common stock and approximately $8.6 million of assumed debt. DLS currently operates a fleet of 51 rigs, including 21 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 the offering of common stock described above to fund a portion of the cash purchase price of DLS. We ultimately raised approximately $47.0 million from such registered stock offering and applied all such amount toward the cash component of the purchase price of DLS. In August 2006, we also raised approximately $92.7 million through the issuance of additional 9.0% senior notes, and we applied a portion of such amount to the payment of the remainder of the cash component of the purchase price for DLS.

As part of the DLS acquisition, Carlos Alberto Bulgheroni and Alejandro Pedro Bulgheroni, of the Bridas Group, have joined our board of directors, filling vacancies created by the resignations of Jens H. Mortensen, Jr. and Thomas O. Whitener, Jr.

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 1,666 on June 30, 2006 according to the Baker Hughes rig count. Furthermore, directional and horizontal rig counts increased from 283 as of December 31, 2002 to 688 on June 30, 2006, which accounted for 32.8% and 41.0% 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.

Comparison of Three Months Ended June 30, 2006 and 2005

Our revenues for the three months ended June 30, 2006 were $60.5 million, an increase of 156.4% compared to $23.6 million for the three months ended June 30, 2005. Revenues increased in all of our business segments due to acquisitions completed in the second and third quarters of 2005 and the first and second quarters of 2006, the investment in additional equipment, improved pricing for our services, the addition of operations and sales personnel and the opening of new operations offices. Revenues increased most significantly at our rental tools segment due to the acquisition of Specialty Rental Tools, Inc., or Specialty, effective January 1, 2006. Our casing and tubing services segment also so a substantial increase in revenue, primarily due to the acquisitions of the casing and tubing assets of Patterson Services, Inc on September 1, 2005, and the acquisition of Rogers Oil Tool Services, Inc., or Rogers, as of April 1, 2006, 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. Revenue increased at our compressed air drilling segment due to the acquisition of the air drilling assets of W.T. Enterprises, Inc., or WT, on July 11, 2005, the purchase of additional equipment 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 and MWDs which increased our capacity and market presence. 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 June 30, 2006 increased 262.6% to $24.7 million, or 40.8% of revenues, compared to $6.8 million, or 28.8%, of revenues for the three months ended June 30, 2005. The increase in gross profit as a percentage of revenues is due to the acquisition of Specialty as of January 1, 2006, 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, the acquisition of additional casing and tubing assets in September 2005 and the acquisition of Rogers in April 2006 also contributed to the increase in gross profit. The increase in gross profit was partially offset by an increase in depreciation expense of 250.5% to $3.8 million for the second quarter of 2006 compared to $1.1 million for the second 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 $8.1 million in the second quarter of 2006 period compared to $3.5 million for the second 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 13.5% in the 2006 quarter and 14.7% 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. 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 $0.8 million related to stock options for the three months ended June 30, 2006, of which $764,000 was recorded in general and administrative expense with the balance being recorded as a direct cost. 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 $666,000 in the second quarter of 2006 compared to $426,000 in the second 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 June 30, 2006 totaled $15.9 million, a 444.6% increase over income from operations of $2.9 million for the three months ended June 30, 2005, reflecting the increase in our revenues and gross profit, offset in part by increased general and administrative expenses and amortization.

Our net interest expense was $3.8 million in the second quarter of 2006, compared to $645,000 for the second 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 second quarter of 2006 was $0 compared to $344,000 for the second 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 $9.6 million for the second quarter of 2006, an increase of 442.3%, compared to net income of $1.8 million for the second 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
						June 30,												June 30,
		2006				2005				Change				2006				2005				Change
		(in thousands)
Directional drilling services		$	18,315			$	10,934			$	7,381			$	4,367			$	1,495			$	2,872
Rental tools			12,707				1,566				11,141				7,308				405				6,903
Casing and tubing services			14,569				3,933				10,636				4,314				1,354				2,960
Compressed air drilling services			10,949				4,866				6,083				3,204				1,002				2,202
Production services			3,930				2,289				1,641				341				36				305
General corporate			—				—				—				(3,663	)			(1,378	)			(2,285	)
Total		$	60,470			$	23,588			$	36,882			$	15,871			$	2,914			$	12,957

Directional Drilling Services Segment

Revenues for the quarter ended June 30, 2006 for our directional drilling services segment were $18.3 million, an increase of 67.5% from the $10.9 million in revenues for the quarter ended June 30, 2005. Income from operations increased 192.1% to $4.4 million for the second quarter of 2006 from $1.5 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 purchase of an additional six MWDs, 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 June 30, 2006 for the rental tools segment were $12.7 million, from $1.6 million in revenues for the quarter ended June 30, 2005. Income from operations increased to $7.3 million in the 2006 period compared to $405,000 in the 2005 period. Our rental tools revenues and operating income for the second quarter of 2006 increased compared to the prior year due primarily due to the acquisition of Specialty. Specialty was acquired as of January 1, 2006, the effective date of the acquisition. Safco-Oil Field Products, Inc., or Safco, Delta Rental Service, Inc., or 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 June 30, 2006 for the casing and tubing services segment were $14.6 million, an increase of 270.4% from the $3.9 million in revenues for the quarter ended June 30, 2005. Revenues from domestic operations increased to $13.0 million in the 2006 period from $2.3 million in the 2005 period as a result of the acquisition of Rogers and 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 were $1.6 million for the second quarter of 2006 and in the second quarter of 2005. Income from operations increased 218.6% to $4.3 million in the second quarter of 2006 from $1.4 million in the second 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 29.6% for the three months ended June 30, 2006 compared to 34.4% 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 $10.9 million for the three months ended June 30, 2006, an increase of 125.0% compared to $4.9 million in revenues for the three months ended June 30, 2005. Income from operations increased to $3.2 million in the 2006 period compared to income from operations of $1.0 million in the 2005 period. Our compressed air drilling revenues and operating income for the second 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 $3.9 million for the three months ended June 30, 2006, an increase of 71.7% compared to $2.3 million in revenues for the three months ended June 30, 2005. Income from operations increased to $341,000 in the 2006 period compared to $36,000 in the 2005 period. Our production services revenues and operating income for the second quarter of 2006 increased compared to the prior year due to the acquisition of Capcoil and improved pricing for our services and improved utilization of out equipment..

General Corporate

General corporate expenses increased $2.3 million to $3.7 million for the three months ended June 30, 2006 compared to $1.4 million for the three months ended June 30, 2005. The increase was due to stock option expense of $0.8 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.

Comparison of Six Months Ended June 30, 2006 and 2005

Our revenues for the six months ended June 30, 2006 were $107.5 million, an increase of 150.4% compared to $42.9 million for the six months ended June 30, 2005. Revenues increased in all of our business segments due to acquisitions completed in the second and third quarters of 2005 and the first and second quarters of 2006, the investment in additional equipment, improved pricing for our services, the addition of operations and sales personnel and the opening of new operations offices. Revenues increased most significantly at our rental tools segment due to the acquisition of Specialty, effective January 1, 2006 and Delta, on April 1, 2005. Our casing and tubing services segment recorded substantial revenue growth due to the acquisitions of the casing and tubing assets of Patterson Services, Inc on September 1, 2005, and the acquisition of Rogers effective April 1, 2006, 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. 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, which provides MWD tools, the addition of operations and sales personnel, the opening of new operations offices and the purchase of additional down-hole motors and MWDs which increased our capacity and market presence. Revenues also increased at our compressed air drilling segment due to the acquisition of the air drilling assets of WT, on July 11, 2005, the purchase of additional equipment and improved pricing for our services in West Texas. Also contributing to increased revenues was the acquisition of Capcoil, as of May 1, 2005 in our production services segment.

Our gross profit for the six months ended June 30, 2006 increased 231.7% to $41.3 million, or 38.4% of revenues, compared to $12.4 million, or 29.0%, of revenues for the six months ended June 30, 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, the acquisition of additional casing and tubing assets in September 2005 and the acquisition of Rogers effective April 1, 2006 also contributed to the gross profit increase. The increase in gross profit was partially offset by an increase in depreciation expense of 256.8% to $7.2 million for the first six months of 2006 compared to $2.0 million for the first six months 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 $15.5 million in the first six months of 2006 period compared to $6.5 million for the first six months 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 14.4% for the six months ended June 30, 2006 and 15.0% in the same period of 2005.

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 $1.8 million of expense related to stock options during the six months ended June 30, 2006, of which $1.6 million was recorded as a general and administrative expense with the balance recorded as direct costs. 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. 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 $1.3 million in the first six months of 2006 compared to $820,000 in the first six months 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 six months ended June 30, 2006 totaled $24.5 million, a 374.8% increase over income from operations of $5.2 million for the six months ended June 30, 2005, reflecting the increase in our revenues and gross profit, offset in part by increased general and administrative expenses, and amortization.

Our net interest expense was $7.4 million in the first six months of 2006, compared to $1.2 million for the first six months of 2005. Interest expense increased in the 2006 period 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 six months ended June 30, 2006 was $0 compared to $488,000 for the six months ended June 30, 2005 due to the acquisition of the minority interest in AirComp, as of July 11, 2005.

We had net income of $14.0 million for the first six months of 2006, an increase of 320.2%, compared to net income of $3.3 million for the first six months 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
		Six Months Ended												Six Months Ended
		June 30,												June 30,
		2006				2005				Change				2006				2005				Change
		(in thousands)
Directional drilling services		$	33,369			$	20,835			$	12,534			$	6,972			$	3,373			$	3,599
Rental tools			23,128				1,940				21,188				12,306				326				11,980
Casing and tubing services			24,028				7,493				16,535				6,165				2,679				3,486
Compressed air drilling services			20,048				9,047				11,001				5,441				1,529				3,912
Production services			6,925				3,607				3,318				618				(2	)			620
General corporate			—				—				—				(6,998	)			(2,744	)			(4,254	)
Total		$	107,498			$	42,922			$	64,576			$	24,504			$	5,161			$	19,343

Directional Drilling Services Segment

Revenues for the six months ended June 30, 2006 for our directional drilling services segment were $33.4 million, an increase of 60.2% from the $20.8 million in revenues for the six months ended June 30, 2005. Income from operations increased 106.7% to $7.0 million for the first six months of 2006 from $3.4 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 purchase of an additional six MWDs, 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 six months ended June 30, 2006 for the rental tools segment were $23.1 million, from $1.9 million in revenues for the six months ended June 30, 2005. Income from operations increased to $12.3 million in the 2006 period compared to $326,000 in the 2005 period. Our rental tools revenues and operating income for the first six months of 2006 increased compared to the prior year due primarily due to the acquisitions of Specialty and Delta. 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, Delta and Specialty were merged in February 2006 to form Allis-Chalmers Rental Tools, Inc

Casing and Tubing Services Segment

Revenues for the six months ended June 30, 2006 for the casing and tubing services segment were $24.0 million, an increase of 220.7% from the $7.5 million in revenues for the six months ended June 30, 2005. Revenues from domestic operations increased to $20.8 million in the 2006 period from $4.2 million in the 2005 period as a result of the acquisitions of the casing and tubing assets of Patterson Services on September 1, 2005 and Rogers effective April 1, 2006, 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 $3.2 million in the first six months of 2006 from $3.3 million in the 2005 period. Income from operations increased 130.1% to $6.2 million in the first six months of 2006 from $2.7 million in the first six months 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 25.7% for the six months ended June 30, 2006 compared to 35.8% 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 $20.0 million for the six months ended June 30, 2006, an increase of 121.6% compared to $9.0 million in revenues for the six months ended June 30, 2005. Income from operations increased to $5.4 million in the 2006 period compared to income from operations of $1.5 million in the 2005 period. Our compressed air drilling revenues and operating income for the first six months 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 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 $6.9 million for the six months ended June 30, 2006, an increase of 92.0% compared to $3.6 million in revenues for the six months ended June 30, 2005. Income from operations increased to $618,000 in the 2006 period compared to loss from operations of $2,000 in the 2005 period. Our production services revenues and operating income for the first six months of 2006 increased compared to the prior year due to the acquisition of Capcoil and improved pricing for our services and improved utilization of our equipment.

General Corporate

General corporate expenses increased $4.3 million to $7.0 million for the six months ended June 30, 2006 compared to $2.7 million for the six months ended June 30, 2005. The increase was due to stock option expense of $1.8 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 $6.2 million at June 30, 2006 compared to $1.9 million at December 31, 2005.

Operating Activities

In the six months ended June 30, 2006, our operating activities provided $17.0 million in cash compared to $2.9 million for the same period in 2005. Net income for the six months ended June 30, 2006 increased to $14.0 million, compared to $3.3 million in the 2005 period. The $14.0 million in net income for the 2006 period includes a charge of $1.8 million related to the expensing of stock options as required under SFAS No. 123R. Revenues and income from operations increased in the first six months of 2006 due to acquisitions completed in the first and second quarters 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 $11.0 million during the first six months of 2006 consisting of $8.4 million of depreciation and amortization, $1.8 million from the expensing of stock options, $355,000 of imputed interest related to the effective date of the Specialty acquisition, $279,000 related to increases to the allowance for doubtful accounts receivables and $119,000 on the loss from asset retirements. Non-cash expenses during the first six months of 2005 totaled $3.3 million, consisting of depreciation and amortization expense of $2.8 million and minority interest of $488,000.

During the six months ended June 30, 2006, changes in operating assets and liabilities used $8.0 million in cash, principally due to an increase of $13.6 million in accounts receivable, an increase of $1.5 million in inventory, a decrease of $1.5 million in accounts payable, offset in part by an increase of $6.4 million in accrued interest and an increase of $1.8 million in accrued expenses. Accounts receivable increased due to the increase in our revenues in the first six months of 2006. Other inventory increased primarily due to increased activity levels. The increase in accrued interest relates to our 9.0% senior notes issued in 2006 which is only payable in January and July. The increase in accrued expenses can be attributed to additional income tax liability due to profitability and additional expenses related to higher activity levels.

During the six months ended June 30, 2005, changes in operating assets and liabilities used $3.8 million in cash, principally due to an increase of $3.0 million in accounts receivable, an increase of $1.1 million in inventory, and a decrease of $296,000 in accrued expenses, offset in part by an increase in accounts payable of $610,000. Accounts receivable increased due to the increase in our revenues in the first six months of 2005. The increase in inventory primarily relates to the acquisition of Capcoil. Accounts payable increased due to the increased level of activity.

Investing Activities

During the six months ended June 30, 2006, we used $119.0 million in investing activities, consisting of $95.8 million for the acquisition of Specialty, net of cash received, $10.7 million for the acquisition of Rogers, net of cash received and $14.2 million for capital expenditures, offset by $1.8 million of proceeds from equipment sales. Included in the $14.2 million for capital expenditures was $5.5 million for equipment used in our casing and tubing segment, $3.0 million for the expansion of our MWD equipment used in the directional drilling segment and $3.0 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 six months of 2005, we used $12.6 million in investing activities, consisting principally of the purchase of equipment of $5.5 million, the acquisition of Delta, net of cash received, for $4.5 million and the acquisition of Capcoil, net of cash received, for $2.6 million. Equipment purchases consisted primarily of $1.9 million for casing equipment, approximately $1.2 million for the purchase of downhole motors and approximately $1.9 million for new compressed air drilling equipment.

Financing Activities

During the six months ended June 30, 2006, financing activities provided $106.3 million in cash. We received $161.4 million in proceeds from long-term debt, repaid $45.3 million in borrowings under long-term debt facilities, repaid $3.0 million in related party debt, repaid $6.4 million net under our line of credit and paid $5.3 million in debt issuance costs. We also received $5.0 million in proceeds from the exercise of options and warrants. During the six months ended June 30, 2005, financing activities provided a net of $5.0 million in cash. We received $5.2 million, net, in borrowings under long-term debt facilities and paid $199,000 in debt issuance costs.

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.

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.

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.

At June 30, 2006, we had $170.0 million in outstanding indebtedness, of which $166.0 million was long term debt and $4.0 million was the current portion of long term debt.

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. This note was repaid from the proceeds of our 9.0% senior notes offering, which we completed in August 2006.

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 June 30, 2006 and December 31, 2005 the outstanding amounts due were $150,000 and $500,000, respectively.

In connection with the purchase of Delta, we issued to the sellers a note in the amount of $350,000. The note bore interest at 2% and the principal and accrued interest was repaid on its maturity of April 1, 2006. 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% and is due April 3, 2009.

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 these non-compete agreements at June 30, 2006 and December 31, 2005 were $443,000 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 June 30, 2006 and December 31, 2005, the principal and accrued interest on these notes totaled approximately $32,000 and $96,000, respectively.

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 had 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.

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 June 30, 2006 and December 31, 2005, the outstanding balances for equipment financing loans were $2.4 million and $1.9 million, respectively. In April 2006, we obtained an insurance premium financing in the amount of $1.9 million with a fixed interest rate of 5.6%. Under terms of the agreement, amounts outstanding are paid over a 10 month repayment schedule. The outstanding balance of this note was approximately $1.6 million as of June 30, 2006. We also have various capital leases with terms that expire in 2008. As of June 30, 2006 and December 31, 2005, amounts outstanding under capital leases were $671,000 and $917,000, respectively. In January 2006, we prepaid $350,000 of the outstanding equipment loans with proceeds from our senior notes offering.

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 $8.0 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

On August 8, 2006, we entered into an amendment to our amended and restated credit agreement dated as of January 18, 2006. The amendment, among other things, amends the credit agreement to (a) allow us to (i) issue and sell $95.0 million aggregate principal amount of our 9.0% senior notes due 2014 and (ii) issue and sell 3,450,000 shares of our common stock, (b) allow us to use the net proceeds from the senior notes offering and the public offering to purchase all the outstanding capital stock of DLS Drilling Logistics and Services Corporation, or DLS, (c) exclude certain existing indebtedness and investments of DLS and investments and indebtedness related to the DLS Acquisition from the covenants contained in the Credit Agreement and (d) increase the amount of permitted lease obligations and capital expenditures.

On August 8, 2006, we priced a public offering of 3.0 million shares of our common stock at $14.50 per share. We have granted the underwriters a 30-day option to purchase up to an additional 450,000 shares to cover over-allotments, if any. On August 14, 2006, we closed the common stock offering and the underwriters elected to exercise the over-allotment option in full.

We also priced a private offering of $95.0 million aggregate principal amount of 9.0% senior notes on August 8, 2006. The notes were sold to investors at a price of 100% of the principal amount thereof, plus accrued interest from July 15, 2006. Fixed interest on the notes will be payable on January 15 and July 15 of each year, beginning on January 15, 2007 and the notes mature on January 15, 2014. The sale of the notes closed on August 14, 2006.

On August 14, 2006, we completed the acquisition of all of the outstanding capital stock of DLS. The purchase price of DLS consisted of $93.7 million in cash, 2.5 million shares of our common stock and approximately $8.6 million of assumed debt. DLS currently operates a fleet of 51 rigs, including 21 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 the offering of common stock described above to fund a portion of the cash purchase price of DLS. We ultimately raised approximately $47.0 million from such registered stock offering and applied all such amount toward the cash component of the purchase price of DLS. In August 2006, we also raised approximately $92.7 million through the issuance of additional 9.0% senior notes, and we applied a portion of such amount to the payment of the remainder of the cash component of the purchase price for DLS.

As part of the DLS acquisition, Carlos Alberto Bulgheroni and Alejandro Pedro Bulgheroni, of the Bridas Group, have joined our board of directors, filling vacancies created by the resignations of Jens H. Mortensen, Jr. and Thomas O. Whitener, Jr.

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 six months ended June 30, 2006.

In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. It prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation is effective for fiscal years beginning after December 15, 2006. We are currently evaluating the provisions of FIN 48 and have not yet determined the impact, if any, on our financial statements.

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. At 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 June 30, 2006, we had $4.2 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.

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.
	•		During the quarter we continued the process of consolidating our payroll functions to improve quality control over the process. In addition we identified a new third party processor to handle our payroll calculations.
	•		We continue to implement improvements in the way the accounting 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 six months ended June 30, 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 six months ended June 30, 2006, we issued 400 and 100,400 shares of our common stock to Robert E. Nederlander and Leonard Toboroff, two of our directors, upon the exercise of previously granted stock options. The weighted average exercise price of the options was $2.59 per share resulting in total proceeds to us of $261,000. The proceeds were used in the normal course of operations for general corporate purposes. The transactions were exempt from the registration requirements of the Securities Act pursuant to Section 4(2) of the Securities Act, as transactions by the issuer not involving any public offering.

During the six months ended June 30, 2006, we also issued 125,285 shares of our common stock to Tommie L. Rogers, the seller in our acquisition of Rogers Oil Tool Services Inc. The transactions were exempt from the registration requirements of the Securities Act pursuant to Section 4(2) of the Securities Act, as transactions by the issuer not involving any public offering.

ITEM 6. EXHIBITS

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

SIGNATURES

Pursuant to the requirements of 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 August 14, 2006.

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

EXHIBIT INDEX

1.1		Underwriting Agreement dated as of August 8, 2006 by and between the Registrant and the underwriters listed on Schedule A thereto (incorporated by reference to Exhibit 1.1 to the Registrant’s Form 8-K filed on August 9, 2006).
4.1		First Supplemental Indenture dated as of August 8, 2006 by and among Allis-Chalmers GP, LLC, a Delaware limited liability company, Allis-Chalmers LP, LLC, a Delaware limited liability company, Allis-Chalmers Management, LP, a Texas limited partnership, Rogers Oil Tool Services, Inc., a Louisiana corporation, the Registrant, the other Guarantors (as defined in the Indenture referred to therein) and Wells Fargo Bank, N.A (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed on August 14, 2006).
4.2		Form of 9.0% Senior Note due 2014 (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed on August 14, 2006).
10.1		Purchase Agreement dated as of August 8, 2006 by and between the Registrant, the guarantors listed on Schedule B thereto and RBC Capital Markets Corporation (incorporated by reference to Exhibit 10.4 to the Registrant’s Form 8-K filed on August 14, 2006).
10.2		Registration Rights Agreement dated as of August 14, 2006 by and among the Registrant, the guarantors named thereto and RBC Capital Markets Corporation (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on August 14, 2006).
10.3		Investors Rights Agreement dated as of August 18, 2006 by and among the Registrant and the investors named on Schedule A thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on August 14, 2006).
10.4		First Amendment to Amended and Restated Credit Agreement dated as of August 8, 2006, by and among the Registrant, the guarantors named thereto and Royal Bank of Canada (incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8-K filed on August 14, 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.