Edgar Filing: Allis Chalmers Energy Inc.

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2008


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

FOR THE TRANSITION PERIOD FROM TO

Commission file number 1-02199

ALLIS-CHALMERS ENERGY INC.

(Exact name of registrant as specified in its charter)


DELAWARE		39-0126090

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

5075 WESTHEIMER, SUITE 890, HOUSTON, TEXAS		77056

(Address of principal executive offices)		(Zip Code)

(713) 369-0550

Registrant’s telephone number, including area code

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. At August 1, 2008 there were 35,511,072 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, 2008

TABLE OF CONTENTS


ITEM	PAGE
PART I

1. Financial Statements

Consolidated Condensed Balance Sheets as of June 30, 2008 and December 31, 2007		3

Consolidated Condensed Income Statements for the three and six months ended June 30, 2008 and 2007		4

Consolidated Condensed Statements of Cash Flows for the six months ended June 30, 2008 and 2007		5

Notes to Consolidated Condensed Financial Statements		6

2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		27

3. Quantitative and Qualitative Disclosures about Market Risk		37

4. Controls and Procedures		38

PART II

6. Exhibits		38

Signatures		39
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO & CFO Pursuant to Section 906

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED CONDENSED BALANCE SHEETS

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


	June 30,		December 31,
	2008		2007
	(unaudited)
Assets
Cash and cash equivalents	$	10,080	$	43,693
Trade receivables, net		143,345		130,094
Inventories		36,707		32,209
Prepaid expenses and other		14,843		11,898

Total current assets		204,975		217,894

Property and equipment, net		668,563		626,668
Goodwill		138,398		138,398
Other intangible assets, net		33,093		35,180
Debt issuance costs, net		13,211		14,228
Note receivable		40,000		—
Other assets		28,221		21,217


Total assets	$	1,126,461	$	1,053,585


Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	9,127	$	6,434
Trade accounts payable		46,131		37,464
Accrued salaries, benefits and payroll taxes		20,295		15,283
Accrued interest		18,136		17,817
Accrued expenses		25,078		20,545

Total current liabilities		118,767		97,543

Long-term debt, net of current maturities		532,218		508,300
Deferred income taxes		34,399		30,090
Other long-term liabilities		3,074		3,323

Total liabilities		688,458		639,256

Commitments and contingencies

Stockholders’ Equity
Preferred stock, $0.01 par value (25,000,000 shares authorized, no shares issued)		—		—
Common stock, $0.01 par value (100,000,000 shares authorized; 35,421,072 issued and outstanding at June 30, 2008 and 35,116,035 issued and outstanding at December 31, 2007)		354		351
Capital in excess of par value		331,158		326,095
Retained earnings		106,491		87,883

Total stockholders’ equity		438,003		414,329


Total liabilities and stockholders’ equity	$	1,126,461	$	1,053,585

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

ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED CONDENSED INCOME STATEMENTS

(in thousands, except per share amounts)

(unaudited)


	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Revenues	$	163,135		$	143,362		$	316,317		$	279,262

Cost of revenues
Direct costs		105,034			83,218			204,232			160,823
Depreciation		15,225			12,248			29,727			24,064


Gross margin		42,876			47,896			82,358			94,375

General and administrative		14,137			14,302			28,921			28,273
Gain on capillary asset sale		—			(8,868	)		—			(8,868	)
Amortization		1,071			988			2,187			2,026


Income from operations		27,668			41,474			51,250			72,944

Other income (expense):
Interest expense		(12,036	)		(11,845	)		(24,077	)		(25,866	)
Interest income		1,538			1,108			2,690			1,867
Other		369			92			476			276


Total other income (expense)		(10,129	)		(10,645	)		(20,911	)		(23,723	)


Income before income taxes		17,539			30,829			30,339			49,221

Provision for income taxes		(6,981	)		(11,325	)		(11,731	)		(17,552	)


Net income	$	10,558		$	19,504		$	18,608		$	31,669


Net income per common share:
Basic	$	0.30		$	0.56		$	0.53		$	0.95
Diluted	$	0.30		$	0.55		$	0.53		$	0.93

Weighted average shares outstanding:
Basic		35,018			34,662			34,928			33,502
Diluted		35,534			35,193			35,386			34,116

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

ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)


	For the Six Months Ended
	June 30,
	2008			2007
Cash Flows from Operating Activities:
Net income	$	18,608		$	31,669
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		31,914			26,090
Amortization and write-off of deferred financing fees		1,038			2,182
Stock-based compensation		4,385			1,104
Allowance for bad debts		636			279
Deferred taxes		4,309			6,746
Gain on sale of property and equipment		(537	)		(37	)
Gain on capillary asset sale		—			(8,868	)
Changes in operating assets and liabilities, net of acquisitions:
(Increase) in trade receivable		(13,887	)		(25,472	)
(Increase) in inventories		(4,498	)		(3,849	)
(Increase) decrease in prepaid expenses and other current assets		(178	)		9,495
(Increase) decrease in other assets		(3,657	)		109
Increase in trade accounts payable		8,667			3,991
Increase in accrued interest		319			7,856
Increase in accrued expenses		4,533			3,002
Increase in accrued salaries, benefits and payroll taxes		5,012			2,128
(Decrease) in other long-term liabilities		(249	)		(43	)


Net Cash Provided By Operating Activities		56,415			56,382


Cash Flows from Investing Activities:
Investment in note receivable		(40,000	)		—
Deposits on asset commitments		(3,447	)		—
Acquisition of businesses, net of cash received		—			(3,550	)
Purchase of investment interests					(440	)
Proceeds from sale of property and equipment		3,578			3,679
Proceeds from sale of capillary assets		—			16,250
Purchase of property and equipment		(74,663	)		(47,181	)


Net Cash Used In Investing Activities		(114,532	)		(31,242	)


Cash Flows from Financing Activities:
Proceeds from issuance of stock, net		—			100,055
Proceeds from exercises of options		609			3,138
Proceeds from long-term debt		17,946			250,000
Net borrowings under line of credit		10,000			—
Payments on long-term debt		(4,102	)		(305,199	)
Tax benefits on stock-based compensation plans		72			1,464
Debt issuance costs		(21	)		(7,581	)


Net Cash Provided By Financing Activities		24,504			41,877


Net change in cash and cash equivalents		(33,613	)		67,017

Cash and cash equivalents at beginning of year		43,693			39,745


Cash and cash equivalents at end of period	$	10,080		$	106,762

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

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

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

Nature of Operations

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

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

Basis of Presentation

Our unaudited consolidated condensed financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission, or SEC. Accordingly, certain information and disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited consolidated condensed financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. These unaudited consolidated condensed financial statements should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2007. 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.

On January 31, 2008, we created the positions of Senior Vice President – Oilfield Services and Senior Vice President – Rental Services. In conjunction with this organizational change, we reviewed the presentation of our reporting segments during the first quarter of 2008. Based on this review, we determined that our operational performance would be segmented and reviewed by the Oilfield Services, Drilling and Completion and Rental Services segments. The Oilfield Services segment includes our underbalanced drilling, directional drilling, tubular services and production services operations. The Drilling and Completion segment includes our international drilling operations. As a result, we realigned our financial reporting segments and now report the following operations as separate, distinct reporting segments: (1) Oilfield Services, (2) Drilling and Completion and (3) Rental Services. Our historical segment data previously reported for the three and six months ended June 30, 2007 and year ended December 31, 2007 have been restated to conform to the new presentation (see Note 10).

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

In September 2006, the Financial Accounting Standards Board, or FASB, issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements, or SFAS No. 157. SFAS No. 157 clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with early adoption permitted. Subsequently, the FASB provided for a one-year deferral of the provisions of SFAS No. 157 for non-financial assets and liabilities that are recognized or disclosed at fair value in the consolidated financial statements on a non-recurring basis. We adopted with no impact on our financial statements all requirements of SFAS No. 157 on January 1, 2008, except as they relate to nonfinancial assets and liabilities, which will be adopted on January 1, 2009, as allowed under SFAS No. 157. We have not yet determined the impact, if any, on our financial statements for nonfinancial assets and liabilities.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, or SFAS No. 159, which permits entities to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS No. 159, an entity may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option should only be made at the initial recognition of the asset or liability or upon a re-measurement event that gives rise to the new-basis of accounting. All subsequent changes in fair value for that instrument are reported in earnings. SFAS No. 159 does not affect any existing accounting literature that requires certain assets and liabilities to be recorded at fair value nor does it eliminate disclosure requirements included in other accounting standards. SFAS No. 159 is effective as of the beginning of each reporting entity’s first fiscal year that begins after November 15, 2007. We adopted SFAS No. 159 on January 1, 2008 and there was no impact on our financial statements.

In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141 (revised 2007), Business Combinations, or SFAS No. 141(R). SFAS No. 141(R) changes the requirements for an acquirer’s recognition and measurement of the assets acquired and the liabilities assumed in a business combination. SFAS No. 141(R) is effective for annual periods beginning after December 15, 2008 and should be applied prospectively for all business combinations entered into after the date of adoption.

In December 2007, the FASB issued Statement of Financial Accounting Standards No. 160, Non-controlling Interests in Consolidated Financial Statements — an amendment of ARB No. 51, or SFAS No. 160. SFAS No. 160 requires (i) that non-controlling (minority) interests be reported as a component of shareholders’ equity, (ii) that net income attributable to the parent and to the non-controlling interest be separately identified in the consolidated statement of operations, (iii) that changes in a parent’s ownership interest while the parent retains its controlling interest be accounted for as equity transactions, (iv) that any retained non-controlling equity investment upon the deconsolidation of a subsidiary be initially measured at fair value, and (v) that sufficient disclosures are provided that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. SFAS No. 160 is effective for annual periods beginning after December 15, 2008 and should be applied prospectively. The presentation and disclosure requirements of the statement shall be applied retrospectively for all periods presented. We will adopt SFAS No. 160 on January 1, 2009 and have not yet determined the impact, if any, on our financial statements.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133, or SFAS No. 161. SFAS No. 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in hedged positions. The statement also requires enhanced disclosures regarding how and why entities use derivative instruments, how derivative instruments and related hedged items are accounted and how derivative instruments and related hedged items affect entities’ financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008. We will adopt SFAS No. 161 on January 1, 2009 and do not expect the adoption to have a material impact on our financial statements.

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

In April 2008, the FASB issued FASB Staff Position SFAS 142-3, Determination of the Useful Life of Intangible Assets or FSP SFAS 142-3. FSP SFAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, Goodwill and Other Intangible Assets. The objective of this FSP is to improve the consistency between the useful life of a recognized intangible asset under Statement 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS 141R, Business Combinations, and other U.S. GAAP principles. FSP SFAS 142-3 is effective for fiscal years beginning after December 15, 2008. We will adopt FSP SFAS 142-3 on January 1, 2009 and have not yet determined the impact, if any, on our financial statements.

NOTE 2 – STOCK-BASED COMPENSATION

We adopted Statement of Financial Accounting Standards No. 123R, Share-Based Payment, effective January 1, 2006. This statement requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their grant-date fair values. We estimated forfeiture rates for the first six months of 2008 and 2007 based on our historical experience.

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

Our net income for the three months ended June 30, 2008 and 2007 includes approximately $1.8 million and $650,000, respectively, of compensation costs related to share-based payments. Our net income for the six months ended June 30, 2008 and 2007 includes approximately $4.4 million and $1.1 million, respectively, of compensation costs related to share-based payments. As of June 30, 2008, there is $1.9 million of unrecognized compensation expense related to non-vested stock option grants. We expect approximately $461,000 to be recognized over the remainder of 2008, and approximately $918,000 and $532,000 to be recognized during the years ended 2009 and 2010, respectively.

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


				Weighted		Weighted
	Shares			Average		Average		Aggregate
	Under			Exercise		Contractual		Intrinsic Value
	Option			Price		Life (Years)		(millions)
Balance at December 31, 2007		986,763		$	10.77
Granted		—			—
Canceled		(7,328	)		10.53
Exercised		(66,703	)		9.13

Outstanding at June 30, 2008		912,732			10.89		7.46	$	7.20


Exercisable at June 30, 2008		693,066		$	7.43		6.94	$	7.19

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 2008 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, 2008. The total intrinsic value of options exercised during the three months and six months ended June 30, 2008 was $449,000 and $478,000, respectively. The total cash received from option exercises during the three months and six months ended June 30, 2008 was $548,000 and $609,000, respectively.

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

No options were granted during the six months ended June 30, 2008 or for the three months ended March 31, 2007. The following summarizes the assumptions used for the options granted in the three months ended June 30, 2007 Black-Scholes model:


	For the Three Months Ended
	June 30,
	2007
Expected dividend yield		—
Expected price volatility		68.06	%
Risk free interest rate		4.48	%
Expected life of options	7 years
Weighted average fair value of options granted at market value	$	11.33

Restricted stock awards, or RSAs, activity during the six months ended June 30, 2008 were as follows:


				Weighted Average
	Number of			Grant-Date Fair Value
	Shares			Per Share
Nonvested at December 31, 2007		993,203		$	17.45
Granted		10,000			11.73
Vested		(249,574	)		17.00
Forfeited		—			—

Nonvested at June 30, 2008		753,629		$	17.52

We determine the fair value of RSAs based on the market price of our common stock on the date of grant. Compensation cost for RSAs is primarily recognized on a straight-line basis over the vesting or service period and is net of forfeitures. As of June 30, 2008, there was $10.2 million of total unrecognized compensation cost related to nonvested RSAs. We expect approximately $2.8 million to be recognized over the remainder of 2008, and approximately $5.1 million, $1.8 million, $278,000 and $209,000 to be recognized during fiscal years 2009, 2010, 2011 and 2012, respectively.

NOTE 3 – INCOME PER COMMON SHARE

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

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

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,
	2008		2007		2008		2007
Numerator:
Net income	$	10,558	$	19,504	$	18,608	$	31,669


Denominator:
Weighted average common shares outstanding excluding nonvested restricted stock		35,018		34,662		34,928		33,502

Effect of potentially dilutive common shares:
Warrants and employee and director stock options and restricted shares		516		531		458		614


Weighted average common shares outstanding and assumed conversions		35,534		35,193		35,386		34,116


Net income per common share
Basic	$	0.30	$	0.56	$	0.53	$	0.95

Diluted	$	0.30	$	0.55	$	0.53	$	0.93

Potentially dilutive securities excluded as anti-dilutive		472		91		548		92

NOTE 4 – GOODWILL AND INTANGIBLE ASSETS

In accordance with Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, or SFAS No. 142, goodwill and indefinite-lived intangible assets are not permitted to be amortized. Goodwill and indefinite-lived intangible assets remain on the balance sheet and are tested for impairment on an annual basis, or when there is reason to suspect that their values may have been diminished or impaired. Goodwill and indefinite-lived intangible assets listed on the balance sheet totaled $138.4 million at June 30, 2008 and December 31, 2007. Based on impairment testing performed during 2007 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, 2008 were $1.1 million and $2.2 million, respectively, compared to $1.0 million and $2.0 million for the same periods last year. At June 30, 2008, intangible assets totaled $33.1 million, net of $7.7 million of accumulated amortization.

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

NOTE 5 - INVENTORIES

Inventories consisted of the following (in thousands):


	June 30,		December 31,
	2008		2007
Manufactured
Finished goods	$	2,671	$	2,198
Work in process		2,247		1,781
Raw materials		4,511		4,464

Total manufactured		9,429		8,443
Hammers		1,967		1,434
Drive pipe		530		420
Rental supplies		2,262		2,261
Chemicals and drilling fluids		4,097		3,236
Rig parts and related inventory		10,747		9,985
Coiled tubing and related inventory		1,317		1,014
Shop supplies and related inventory		6,358		5,416


Total inventories	$	36,707	$	32,209

NOTE 6- NOTE RECEIVABLE

We invested $40.0 million in cash in BCH Ltd., or BCH, in the form of a 15% Convertible Subordinated Secured debenture. The debenture is convertible, at any time, at our option into 49% of the common equity of BCH. At the end of two years, we have the option to acquire the remaining 51% of BCH from its parent, BrazAlta Resources Corp., or BrazAlta, based on an independent valuation from a mutually acceptable investment bank. BrazAlta is a publicly traded Canadian-based international oil and gas corporation with operations in Brazil, Northern Ireland, and Canada (TSX.V:BRX).

BCH is a Canadian-based oilfield services company engaged in contract drilling operations exclusively in Brazil. BCH has six drilling rigs under two to three year contracts with Petroleo Brasileiro S.A., and a contract for one service rig with BrazAlta for a term of three years.

NOTE 7- DEBT

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


	June 30,		December 31,
	2008		2007
Senior notes	$	505,000	$	505,000
Bank term loans		21,684		4,926
Revolving line of credit		10,000		—
Seller notes		2,000		2,350
Notes payable to former directors		32		32
Equipment and vehicle installment notes		—		595
Insurance premium financing		2,629		1,707
Obligations under non-compete agreements		—		110
Capital lease obligations		—		14

Total debt		541,345		514,734

Less: current maturities		9,127		6,434


Long-term debt obligations	$	532,218	$	508,300

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

Senior notes, bank loans and line of credit agreements

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

In January 2007, we closed on a private offering, to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, of $250.0 million aggregate principal amount of 8.5% senior notes due 2017. The proceeds of the senior notes offering, together with a portion of the proceeds of our concurrent common stock offering, were used to repay the debt outstanding under our $300.0 million bridge loan facility which we incurred to finance our acquisition of substantially all the assets of Oil & Gas Rental Services, Inc., or OGR.

On January 18, 2006, we also executed an amended and restated credit agreement which provided for a $25.0 million revolving line of credit with a maturity of January 2010. On April 26, 2007, we entered into a Second Amended and Restated Credit Agreement, which increased our revolving line of credit to $62.0 million, and has a final maturity date of April 26, 2012. On December 3, 2007, we entered into a First Amendment to the Second Amended and Restated Credit Agreement, which increased our revolving line of credit to $90.0 million. The credit agreement contains customary events of default and financial covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends or make other distributions, create liens and sell assets. Our obligations under the amended and restated credit agreement are secured by substantially all of our assets located in the United States. We were in compliance with all debt covenants as of June 30, 2008. The credit agreement loan rates are based on prime or LIBOR plus a margin. The interest rate was 4.5% at June 30, 2008. The outstanding amount as of June 30, 2008 and December 31, 2007, was $10.0 million and $0, respectively.

As part of our acquisition of DLS, we assumed various bank loans with floating interest rates based on LIBOR plus a margin and terms ranging from two to five years. The weighted average interest rates were 4.3% and 6.7% at June 30, 2008 and December 31, 2007, respectively. The bank loans are denominated in U.S. dollars and the outstanding amount as of June 30, 2008 and December 31, 2007 were $3.7 million and $4.9 million, respectively.

On February 15, 2008, through our DLS subsidiary in Argentina, we entered into a $25.0 million import finance facility with a bank. Borrowings under this facility will be used to fund a portion of the purchase price of the new drilling and service rigs ordered for our Drilling and Completion segment. The facility is available for borrowings until December 31, 2008. Each drawdown shall be repaid over four years in equal semi-annual installments beginning one year after each disbursement with the final principal payment due not later than March 15, 2013. The import finance facility is unsecured and contains customary events of default and financial covenants and limits DLS’ ability to incur additional indebtedness, make capital expenditures, create liens and sell assets. We were in compliance with all debt covenants as of June 30, 2008. The bank loan rates are based on LIBOR plus a margin. The interest rate was 6.6% at June 30, 2008. The bank loans are denominated in U.S. dollars and the outstanding amount as of June 30, 2008 was $17.9 million.

Notes payable

In connection with the acquisition of Rogers Oil Tool Services, Inc., we issued to the seller a note in the amount of $750,000. The note bears interest at 5.0% and is due April 3, 2009. In connection with the acquisition of Coker Directional, Inc., we issued to the seller a note in the amount of $350,000. The interest rate on the note was 8.25% and was repaid on June 29, 2008. In connection with the acquisition of Diggar Tools, LLC, we issued to the seller a note in the amount of $750,000. The interest rate on the note was 6.0% and was repaid on July 28, 2008. In connection with the acquisition of Rebel Rentals, Inc., we issued to the sellers notes in the aggregate amount of $500,000. The notes bear interest at 5.0% and are due October 23, 2008.

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 bore interest at the rate of 5.0%. At June 30, 2008 and December 31, 2007, the principal and accrued interest on these notes totaled approximately $32,000.

We had various equipment and vehicle financing loans with interest rates ranging from 8.3% to 8.7% and two year terms. As of June 30, 2008 and December 31, 2007, the outstanding balances for equipment and vehicle financing loans were $0 and $595,000, respectively.

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

In April and August 2007, we obtained insurance premium financings in the aggregate amount of $4.4 million with a fixed weighted average interest rate of 5.9%. Under terms of the agreements, amounts outstanding are paid over 10 month and 11 month repayment schedules. The outstanding balance of these notes was approximately $124,000 and $1.7 million as of June 30, 2008 and December 31, 2007, respectively. In April 2008, we obtained an insurance premium financing in the amount of $2.8 million with a fixed interest rate of 4.9%. Under terms of the agreement, the amount outstanding is paid over a 10 month repayment schedule. The outstanding balance of this note was approximately $2.5 million as of June 30, 2008.

Other debt

In connection with the purchase of Capcoil Tubing Services, Inc., we agreed to pay a total of $500,000 to two management employees in exchange for non-compete agreements. We were required to make annual payments of $110,000 through May 2008. Total amounts due under these non-compete agreements at June 30, 2008 and December 31, 2007 were $0 and $110,000, respectively.

We also had various capital leases with terms that expire in 2008. As of June 30, 2008 and December 31, 2007, amounts outstanding under capital leases were $0 and $14,000, respectively.

NOTE 8 – STOCKHOLDERS’ EQUITY

We had options exercised in the first six months of 2008, which resulted in 66,703 shares of our common stock being issued for approximately $609,000. We recognized approximately $4.4 million of compensation expense related to share-based payments in the first six months of 2008 that was recorded as capital in excess of par value (see Note 2). We also recorded approximately $72,000 of tax benefit related to our stock compensation plans.

NOTE 9 – CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

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

CONDENSED CONSOLIDATING BALANCE SHEETS
June 30, 2008 (unaudited)


	Allis-Chalmers				Subsidiary
	(Parent/		Subsidiary		Non-		Consolidating			Consolidated
	Guarantor)		Guarantors		Guarantors		Adjustments			Total
Assets
Cash and cash equivalents	$	—	$	7,666	$	2,414	$	—		$	10,080
Trade receivables, net		—		88,678		54,669		(2	)		143,345
Inventories		—		18,785		17,922		—			36,707
Intercompany receivables		21,293		—		—		(21,293	)		—
Note receivable from affiliate		14,235		—		—		(14,235	)		—
Prepaid expenses and other		7,730		4,020		3,093		—			14,843

Total current assets		43,258		119,149		78,098		(35,530	)		204,975
Property and equipment, net		—		485,816		182,747		—			668,563
Goodwill		—		136,875		1,523		—			138,398
Other intangible assets, net		529		32,525		39		—			33,093
Debt issuance costs, net		13,211		—		—		—			13,211
Note receivable from affiliates		13,490		—		—		(13,490	)		—
Investments in affiliates		868,110		—		—		(868,110	)		—
Note receivable		40,000		—		—		—			40,000
Other assets		4,912		3,888		19,421		—			28,221


Total Assets	$	983,510	$	778,253	$	281,828	$	(917,130	)	$	1,126,461


Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	782	$	3,879	$	4,466	$	—		$	9,127
Trade accounts payable		—		16,607		29,526		(2	)		46,131
Accrued salaries, benefits and payroll taxes		—		3,569		16,726		—			20,295
Accrued interest		17,759		58		319		—			18,136
Accrued expenses		55		12,729		12,294		—			25,078
Intercompany payables		—		377,826		1,185		(379,011	)		—
Note payable to affiliate		—		—		14,235		(14,235	)		—

Total current liabilities		18,596		414,668		78,751		(393,248	)		118,767
Long-term debt, net of current maturities		515,000		—		17,218		—			532,218
Note payable to affiliate		—		—		13,490		(13,490	)		—
Deferred income taxes		11,911		13,696		8,792		—			34,399
Other long-term liabilities		—		186		2,888		—			3,074

Total liabilities		545,507		428,550		121,139		(406,738	)		688,458

Commitments and contingencies

Stockholders’ Equity
Common stock		354		3,526		42,963		(46,489	)		354
Capital in excess of par value		331,158		167,508		74,969		(242,477	)		331,158
Retained earnings		106,491		178,669		42,757		(221,426	)		106,491

Total stockholders’ equity		438,003		349,703		160,689		(510,392	)		438,003


Total liabilities and stockholders’ equity	$	983,510	$	778,253	$	281,828	$	(917,130	)	$	1,126,461

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

CONDENSED CONSOLIDATING INCOME STATEMENTS

For the Six Months Ended June 30, 2008 (unaudited)


	Allis-Chalmers						Subsidiary
	(Parent/			Subsidiary			Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors			Adjustments			Total
Revenues	$	—		$	183,451		$	132,879		$	(13	)	$	316,317

Cost of revenues
Direct costs		—			101,245			103,000			(13	)		204,232
Depreciation		—			23,167			6,560			—			29,727


Gross margin		—			59,039			23,319			—			82,358
General and administrative		3,890			19,988			5,043			—			28,921
Amortization		23			2,147			17			—			2,187


Income (loss) from operations		(3,913	)		36,904			18,259			—			51,250

Other income (expense):
Equity earnings in affiliates, net of tax		43,700			—			—			(43,700	)		—
Interest, net		(21,221	)		60			(226	)		—			(21,387	)
Other		42			24			410			—			476


Total other income (expense)		22,521			84			184			(43,700	)		(20,911	)


Net income (loss)before income taxes		18,608			36,988			18,443			(43,700	)		30,339

Provision for income taxes		—			(4,449	)		(7,282	)		—			(11,731	)


Net income (loss)	$	18,608		$	32,539		$	11,161		$	(43,700	)	$	18,608

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

CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Three Months Ended June 30, 2008 (unaudited)


	Allis-Chalmers						Subsidiary
	(Parent/			Subsidiary			Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors			Adjustments			Total
Revenues	$	—		$	93,323		$	69,818		$	(6	)	$	163,135

Cost of revenues
Direct costs		—			50,693			54,347			(6	)		105,034
Depreciation		—			11,834			3,391			—			15,225


Gross margin		—			30,796			12,080			—			42,876

General and administrative		1,514			9,942			2,681			—			14,137
Amortization		11			1,052			8			—			1,071


Income (loss) from operations		(1,525	)		19,802			9,391			—			27,668

Other income (expense):
Equity earnings in affiliates, net of tax		22,477			—			—			(22,477	)		—
Interest, net		(10,409	)		(16	)		(73	)		—			(10,498	)
Other		15			(20	)		374			—			369


Total other income (expense)		12,083			(36	)		301			(22,477	)		(10,129	)


Net income (loss)before income taxes		10,558			19,766			9,692			(22,477	)		17,539

Provision for income taxes		—			(2,938	)		(4,043	)		—			(6,981	)


Net income (loss)	$	10,558		$	16,828		$	5,649		$	(22,477	)	$	10,558

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

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Six Months Ended June 30, 2008 (unaudited)


	Allis-						Other
	Chalmers						Subsidiaries
	(Parent/			Subsidiary			(Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors)			Adjustments			Total
Cash Flows from Operating Activities:
Net income (loss)	$	18,608		$	32,539		$	11,161		$	(43,700	)	$	18,608
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		23			25,314			6,577			—			31,914
Amortization and write-off of deferred financing fees		1,038			—			—			—			1,038
Stock based compensation		4,385			—			—			—			4,385
Allowance for bad debts		—			636			—			—			636
Equity earnings in affiliates		(43,700	)		—			—			43,700			—
Deferred taxes		3,254			(114	)		1,169			—			4,309
(Gain) on sale of property and equipment		—			(495	)		(42	)		—			(537	)
Changes in operating assets and liabilities, net of acquisitions:
(Increase) in trade receivables		—			(6,191	)		(7,696	)		—			(13,887	)
(Increase) in inventories		—			(3,086	)		(1,412	)		—			(4,498	)
(Increase) decrease in prepaid expenses and other current assets		—			1,312			(1,490	)		—			(178	)
(Increase) decrease in other assets		(4,897	)		989			251			—			(3,657	)
(Decrease) increase in trade accounts payable		—			(205	)		8,872			—			8,667
Increase in accrued interest		50			25			244			—			319
(Decrease) increase in accrued expenses		(1,605	)		5,602			536			—			4,533
(Decrease) increase in accrued salaries, benefits and payroll taxes		—			(143	)		5,155			—			5,012
(Decrease) in other long- term liabilities		(31	)		(56	)		(162	)		—			(249	)

Net Cash Provided By (Used In) Operating Activities		(22,875	)		56,127			23,163			—			56,415


Cash Flows from Investing Activities:
Notes receivable from affiliates		(3,075	)		—			—			3,075			—
Investment in note receivable		(40,000	)		—			—			—			(40,000	)
Deposits on asset commitments		—			—			(3,447	)		—			(3,447	)
Proceeds from sale of property and equipment		—			3,535			43			—			3,578
Purchase of property and equipment		—			(34,968	)		(39,695	)		—			(74,663	)

Net Cash Provided By (Used in) Investing Activities		(43,075	)		(31,433	)		(43,099	)		3,075			(114,532	)

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

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Six Months Ended June 30, 2008 (unaudited)


	Allis-						Other
	Chalmers						Subsidiaries
	(Parent/			Subsidiary			(Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors)			Adjustments			Total
Cash Flows from Financing Activities:
Accounts receivable from affiliates		55,290			—			—			(55,290	)		—
Accounts payable to affiliates		—			(55,290	)		—			55,290			—
Note payable to affiliate		—			—			3,075			(3,075	)		—
Proceeds from exercises of options		609			—			—			—			609
Tax benefit on stock-based compensation plans		72			—			—			—			72
Proceeds from long-term debt		—			—			17,946			—			17,946
Net borrowing under line of credit		10,000			—			—			—			10,000
Payments on long-term debt		—			(2,914	)		(1,188	)		—			(4,102	)
Debt issuance costs		(21	)		—			—			—			(21	)

Net Cash Provided By (Used In) Financing Activities		65,950			(58,204	)		19,833			(3,075	)		24,504


Net change in cash and cash equivalents		—			(33,510	)		(103	)		—			(33,613	)
Cash and cash equivalents at beginning of year		—			41,176			2,517			—			43,693

Cash and cash equivalents at end of period	$	—		$	7,666		$	2,414		$	—		$	10,080

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

CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2007


	Allis-Chalmers				Subsidiary
	(Parent/		Subsidiary		Non-		Consolidating			Consolidated
	Guarantor)		Guarantors		Guarantors		Adjustments			Total
Assets
Cash and cash equivalents	$	—	$	41,176	$	2,517	$	—		$	43,693
Trade receivables, net		—		83,126		46,973		(5	)		130,094
Inventories		—		15,699		16,510		—			32,209
Intercompany receivables		76,583		—		—		(76,583	)		—
Note receivable from affiliate		8,270		—		—		(8,270	)		—
Prepaid expenses and other		7,731		2,564		1,603		—			11,898

Total current assets		92,584		142,565		67,603		(84,858	)		217,894
Property and equipment, net		—		477,055		149,613		—			626,668
Goodwill		—		136,875		1,523		—			138,398
Other intangible assets, net		552		34,572		56		—			35,180
Debt issuance costs, net		14,228		—		—		—			14,228
Note receivable from affiliates		16,380		—		—		(16,380	)		—
Investments in affiliates		824,410		—		—		(824,410	)		—
Other assets		15		4,977		16,225		—			21,217


Total Assets	$	948,169	$	796,044	$	235,020	$	(925,648	)	$	1,053,585


Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	32	$	4,026	$	2,376	$	—		$	6,434
Trade accounts payable		—		16,815		20,654		(5	)		37,464
Accrued salaries, benefits and payroll taxes		—		3,712		11,571		—			15,283
Accrued interest		17,709		33		75		—			17,817
Accrued expenses		1,660		7,127		11,758		—			20,545
Intercompany payables		—		433,116		1,185		(434,301	)		—
Note payable to affiliate		—		—		8,270		(8,270	)		—

Total current liabilities		19,401		464,829		55,889		(442,576	)		97,543
Long-term debt, net of current maturities		505,750		—		2,550		—			508,300
Note payable to affiliate		—		—		16,380		(16,380	)		—
Deferred income taxes		8,658		13,809		7,623		—			30,090
Other long-term liabilities		31		242		3,050		—			3,323

Total liabilities		533,840		478,880		85,492		(458,956	)		639,256

Commitments and contingencies

Stockholders’ Equity
Common stock		351		3,526		42,963		(46,489	)		351
Capital in excess of par value		326,095		167,508		74,969		(242,477	)		326,095
Retained earnings		87,883		146,130		31,596		(177,726	)		87,883

Total stockholders’ equity		414,329		317,164		149,528		(466,692	)		414,329


Total liabilities and stockholders’ equity	$	948,169	$	796,044	$	235,020	$	(925,648	)	$	1,053,585

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

CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Six Months Ended June 30, 2007 (unaudited)


	Allis-Chalmers						Subsidiary
	(Parent/			Subsidiary			Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors			Adjustments			Total
Revenues	$	—		$	177,540		$	101,749		$	(27	)	$	279,262

Cost of revenues
Direct costs		—			88,549			72,301			(27	)		160,823
Depreciation		—			18,633			5,431			—			24,064


Gross margin		—			70,358			24,017			—			94,375

General and administrative		1,017			23,088			4,168			—			28,273
Gain on capillary asset sale		—			(8,868	)		—			—			(8,868	)
Amortization		23			1,986			17			—			2,026


Income from operations		(1,040	)		54,152			19,832			—			72,944

Other income (expense):
Equity earnings in affiliates, net of tax		57,629			—			—			(57,629	)		—
Interest, net		(24,945	)		1,628			(682	)		—			(23,999	)
Other		25			115			136			—			276


Total other income (expense)		32,709			1,743			(546	)		(57,629	)		(23,723	)


Net income before income taxes		31,669			55,895			19,286			(57,629	)		49,221

Provision for income taxes		—			(11,012	)		(6,540	)		—			(17,552	)


Net income	$	31,669		$	44,883		$	12,746		$	(57,629	)	$	31,669

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

CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Three Months Ended June 30, 2007 (unaudited)


	Allis-Chalmers						Subsidiary
	(Parent/			Subsidiary			Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors			Adjustments			Total
Revenues	$	—		$	90,511		$	52,861		$	(10	)	$	143,362

Cost of revenues
Direct costs		—			45,514			37,714			(10	)		83,218
Depreciation		—			9,516			2,732			—			12,248


Gross margin		—			35,481			12,415			—			47,896

General and administrative		599			11,515			2,188			—			14,302
Gain on capillary asset sale		—			(8,868	)		—			—			(8,868	)
Amortization		11			968			9			—			988


Income from operations		(610	)		31,866			10,218			—			41,474

Other income (expense):
Equity earnings in affiliates, net of tax		31,507			—			—			(31,507	)		—
Interest, net		(11,406	)		976			(307	)		—			(10,737	)
Other		13			68			11			—			92


Total other income (expense)		20,114			1,044			(296	)		(31,507	)		(10,645	)


Net income before income taxes		19,504			32,910			9,922			(31,507	)		30,829

Provision for income taxes		—			(7,817	)		(3,508	)		—			(11,325	)


Net income	$	19,504		$	25,093		$	6,414		$	(31,507	)	$	19,504

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

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Six Months Ended June 30, 2007 (unaudited)


	Allis-						Other
	Chalmers						Subsidiaries
	(Parent/			Subsidiary			(Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors)			Adjustments			Total
Cash Flows from Operating Activities:
Net income	$	31,669		$	44,883		$	12,746		$	(57,629	)	$	31,669
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		22			20,620			5,448			—			26,090
Amortization and write-off of deferred financing fees		2,182			—			—			—			2,182
Stock-based compensation		1,104			—			—			—			1,104
Allowance for bad debts		—			279			—			—			279
Equity earnings in affiliates		(57,629	)		—			—			57,629			—
Deferred income taxes		6,699			1			46			—			6,746
(Gain) on sale of equipment		—			(34	)		(3	)		—			(37	)
Gain on capillary asset sale		—			(8,868	)								(8,868	)
Changes in operating assets and liabilities, net of acquisitions:
(Increase) in trade receivables		—			(19,084	)		(6,388	)		—			(25,472	)
(Increase) in inventories		—			(2,170	)		(1,679	)		—			(3,849	)
(Increase) decrease in other current assets		(271	)		9,631			135			—			9,495
(Increase) decrease in other assets		237			(98	)		(30	)		—			109
Increase in accounts payable		3			2,089			1,899			—			3,991
Increase (Decrease) in accrued interest		7,873			—			(17	)		—			7,856
(Decrease) increase in accrued expenses		(46	)		2,307			741			—			3,002
Increase in accrued salaries, benefits and payroll taxes		—			2			2,126			—			2,128
(Decrease) in other long- term liabilities		(15	)		(28	)		—			—			(43	)

Net Cash Provided By (Used In) Operating Activities		(8,172	)		49,530			15,024			—			56,382


Cash Flows from Investing Activities:
Notes receivable from affiliates		1,768			—			—			(1,768	)		—
Acquisition of businesses, net of cash received		—			(3,550	)		—			—			(3,550	)
Purchase of investment interests		—			(440	)		—			—			(440	)
Proceeds from sale of capillary assets		—			16,250			—			—			16,250
Proceeds from sale of property and equipment		—			3,672			7			—			3,679
Purchase of property and equipment		—			(41,311	)		(5,870	)		—			(47,181	)

Net Cash Provided By (Used in) Investing Activities		1,768			(25,379	)		(5,863	)		(1,768	)		(31,242	)

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

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Six Months Ended June 30, 2007 (unaudited)


	Allis-						Other
	Chalmers						Subsidiaries
	(Parent/			Subsidiary			(Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors)			Adjustments			Total
Cash Flows from Financing Activities:
Proceeds from long-term debt		250,000			—			—			—			250,000
Payments on long-term debt		(300,000	)		(3,229	)		(1,970	)		—			(305,199	)
Accounts receivable from affiliates		(40,672	)		10,859			—			29,813			—
Accounts payable to affiliates		—			29,830			(17	)		(29,813	)		—
Note payable to affiliate		—			—			(1,768	)		1,768			—
Proceeds from issuance of common stock		100,055			—			—			—			100,055
Proceeds from exercises of options and warrants		3,138			—			—			—			3,138
Tax benefits on stock plans		1,464			—			—			—			1,464
Debt issuance costs		(7,581	)		—			—			—			(7,581	)

Net Cash Provided By (Used In) Financing Activities		6,404			37,460			(3,755	)		1,768			41,877


Net change in cash and cash equivalents		—			61,611			5,406			—			67,017
Cash and cash equivalents at beginning of year		—			37,769			1,976			—			39,745

Cash and cash equivalents at end of period	$	—		$	99,380		$	7,382		$	—		$	106,762

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

NOTE 10- SEGMENT INFORMATION

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,
	2008			2007			2008			2007
Revenues
Oilfield Services	$	68,653		$	58,122		$	136,556		$	113,553
Drilling and Completion		69,818			52,861			132,879			101,749
Rental Services		24,664			32,379			46,882			63,960


	$	163,135		$	143,362		$	316,317		$	279,262


Operating Income (Loss):
Oilfield Services	$	13,090		$	20,595		$	26,387		$	32,287
Drilling and Completion		9,391			10,218			18,259			19,832
Rental Services		9,266			14,770			15,488			28,693
General corporate		(4,079	)		(4,109	)		(8,884	)		(7,868	)


	$	27,668		$	41,474		$	51,250		$	72,944


Depreciation and Amortization:
Oilfield Services	$	5,961		$	3,877		$	11,591		$	7,665
Drilling and Completion		3,399			2,741			6,577			5,448
Rental Services		6,795			6,490			13,464			12,751
General corporate		141			128			282			226


	$	16,296		$	13,236		$	31,914		$	26,090


Capital Expenditures:
Oilfield Services	$	9,390		$	11,091		$	23,817		$	21,854
Drilling and Completion		21,165			3,150			39,694			5,870
Rental Services		4,415			10,369			11,106			18,882
General corporate		16			226			46			575


	$	34,986		$	24,836		$	74,663		$	47,181

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


	As of
	June 30,		December 31,
	2008		2007
Goodwill:
Oilfield Services	$	30,493	$	30,493
Drilling and Completion		1,523		1,523
Rental Services		106,382		106,382


	$	138,398	$	138,398

Assets:
Oilfield Services	$	324,074	$	299,300
Drilling and Completion		281,829		235,020
Rental Services		444,113		454,216
General corporate		76,445		65,049


	$	1,126,461	$	1,053,585

Long Lived Assets:
United States	$	652,096	$	655,513
International		269,390		180,178


	$	921,486	$	835,691


	For the Three Months Ended				For the Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Revenues:
United States	$	88,959	$	86,232	$	172,942	$	170,466
International		74,176		57,130		143,375		108,796


	$	163,135	$	143,362	$	316,317	$	279,262

NOTE 11 - SUPPLEMENTAL CASH FLOW INFORMATION


	For the Six Months Ended
	June 30,
	2008		2007
Cash paid for interest and income taxes:
Interest	$	23,087	$	15,819
Income taxes		12,595		6,639

Non-cash activities:
Insurance premium financed		2,767		3,150
Note payable issued for acquisition of business		—		350

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

NOTE 12 - LEGAL MATTERS

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

We have been named as a defendant in three lawsuits in connection with our proposed merger with Bronco Drilling Company, Inc., or Bronco. We do not believe that the suits have any merit.

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

NOTE 13 – SUBSQUENT EVENTS

On July 25, 2008, we announced our intent to offer $350.0 million of senior notes in a private placement. We plan to use the net proceeds of the offering to fund the cash consideration payable by us in connection with our previously announced pending acquisition of Bronco. We would also use the proceeds to repay Bronco’s outstanding debt and working capital and other general corporate purposes. The notes are being offered to qualified institutional buyers in accordance with Rule 144A under the Securities Act of 1933, and outside the United States to person other than U.S. persons, in reliance on Regulation S.

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

The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this report. This report contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from the results discussed in such forward-looking statements. Factors that might cause such differences include, but are not limited to, the general condition of the oil and natural gas drilling industry, demand for our oil and natural gas service and rental products, and competition. For more information on forward-looking statements please refer to the section entitled “Forward-Looking Statements” on page 37.

Overview of Our Business

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

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

The number of 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 United States increased from 862 as of December 31, 2002, to 1,782 as of December 31, 2007 and to 1,957 on July 25, 2008, according to the Baker Hughes rig count. Furthermore, directional and horizontal rig counts increased from 283 as of December 31, 2002 to 967 on July 25, 2008, which accounted for 32.8% and 49.4% of the total U.S. rig count, respectively. The offshore Gulf of Mexico rig count however, decreased 14% to 67 rigs on July 25, 2008 compared to 78 rigs one year ago as oil and gas operators mobilized drilling rigs to the international markets.

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.

Cyclical Nature of Equipment Rental and Services Industry

The oilfield services industry is highly cyclical. The most critical factor in assessing the outlook for the industry is the worldwide supply and demand for oil and the domestic supply and demand for natural gas. The peaks and valleys of demand are further apart than those of many other cyclical industries. This is primarily a result of the industry being driven by commodity demand and corresponding price increases. As demand increases, producers raise their prices. The price escalation enables producers to increase their capital expenditures. The increased capital expenditures ultimately result in greater revenues and profits for services and equipment companies. The increased capital expenditures also ultimately result in greater production which historically has resulted in increased supplies and reduced prices.

Demand for our services has been strong for approximately the past four years, due to high oil and natural gas prices and increased demand and declining production costs for natural gas as compared to other energy sources. Management believes the current market fundamentals are indicative of a favorable long-term trend of activity in our markets. However, these factors could be more than offset by other developments affecting the worldwide supply and demand for oil and natural gas products. The price for natural gas in the U.S. can have a significant impact on the capital expenditures of our customers operating in the U.S. domestic market. Natural gas prices can be affected by such factors as the U.S. economy, new production or pipeline capacity and weather.

Results of Operations

In June 2007, we acquired all of the outstanding stock of Coker Directional, Inc., or Coker. In July 2007, we acquired all of the outstanding stock of Diggar Tools, LLC, or Diggar. In October 2007, we acquired all of the outstanding stock of Rebel Rentals, Inc., or Rebel. We report the operations of Coker, Diggar and Rebel in our Oilfield Services segment. We consolidated the results of these acquisitions from the day they were acquired.

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

Comparison of Three Months Ended June 30, 2008 and 2007

Our revenues for the three months ended June 30, 2008 were $163.1 million, an increase of 13.8% compared to $143.4 million for the three months ended June 30, 2007. The increase in revenues is due to the increase in revenues in our Oilfield Services and Drilling and Completion segments, partly offset by a decrease in revenues in our Rental Services segment. Revenues increased by $10.5 million in our Oilfield Services segment due to our investment in new equipment in 2007 and in the first quarter of 2008, the opening of new operating locations and small acquisitions completed in 2007, which added downhole motors, measurement-while-drilling, or MWD tools, and directional drilling personnel. Revenues increased in our Drilling and Completion segment by $17.0 million due to increased pricing for our drilling and workover services in Argentina and the activation of eight new service rigs during the first quarter of 2008 and two new service rigs during the second quarter of 2008. The $7.7 million decrease in revenues in our Rental Services segment is due to decreased utilization of our equipment and more competitive pricing due to the decrease in drilling activity in the Gulf of Mexico.

Our gross margin for the quarter ended June 30, 2008 decreased 10.5% to $42.9 million, or 26.3% of revenues, compared to $47.9 million, or 33.4%, of revenues for the three months ended June 30, 2007. The decrease in gross profit is principally due to the decrease in Rental Services revenue. Our gross margin also decreased due to the increase in depreciation expense associated with our capital expenditures. The decrease in gross profit as a percentage of revenues is primarily due to the decrease in Rental Services revenues, the decrease in our gross margin percentage in our Drilling and Completion segment and the increase in depreciation expense. The decrease in the gross margin in our Drilling and Completion segment is due to higher wages and the impact of labor strikes and work slowdowns as a result of the labor and political environment in Argentina and the significant increase in our labor force and labor related expenses in connection with the delivery of new rigs prior to their activation. Depreciation expense increased 24.3% to $15.2 million for the second quarter of 2008 compared to $12.2 million for the second quarter of 2007. The increase is due to additional depreciable assets resulting from capital expenditures and acquisitions. 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 $14.1 million in the three months ended June 30, 2008 compared to $14.3 million for the three months ended June 30, 2007. As a percentage of revenues, general and administrative expenses decreased to 8.7% in the second quarter of 2008 compared to 10.0% in the second quarter of 2007.

We recorded an expense of $1.8 million related to share-based compensation expense for the three months ended June 30, 2008 compared to $650,000 for the three months ended June 30, 2007. The amount of shared-based compensation expense recorded in general and administrative expense was $1.8 million for the second quarter of 2008 and $622,000 for the second quarter of 2007 with the balance being recorded as a direct cost.

On June 29, 2007, we sold our capillary tubing assets that were part of our Oilfield Services segment. The total sale agreement was $16.3 million in cash. We recognized a gain of $8.9 million related to the sale of these assets.

Amortization expense was $1.1 million in the three months ended June 30, 2008 compared to $1.0 million in the three months ended June 30, 2007. The increase in amortization expense is due to the amortization of intangible assets in connection with our acquisitions.

Income from operations for the three months ended June 30, 2008 totaled $27.7 million, a decrease of 33.3% compared to income from operations of $41.5 million for the three months ended June 30, 2007, due to the $8.9 million gain from the sale of our capillary tubing assets recognized in the second quarter of 2007 and the decrease in our gross margin in the second quarter of 2008. Our income from operations as a percentage of revenues decreased to 17.0% for the second quarter of 2008, from 28.9% for the second quarter of 2007, due to the $8.9 million gain in the second quarter of 2007 and the decrease in our gross margin as a percentage of revenues offset partially by the decrease in general and administrative expenses as a percentage of revenues.

Our net interest expense was $10.5 million in the three months ended June 30, 2008, compared to $10.7 million for the three months ended June 30, 2007. Interest expense decreased in the second quarter of 2008 due to an increase in interest income offset in part by an increase in our average outstanding debt. Our net interest expense includes interest income of $1.5 million in the second quarter of 2008 from our 15% $40.0 million subordinated convertible debenture due from BCH Ltd. which closed on January 31, 2008.

Our provision for income taxes for the three months ended June 30, 2008 was $7.0 million, or 39.8% of our net income before income taxes, compared to $11.3 million, or 36.7% of our net income before income taxes for the three months ended June 30, 2007. The increase in our effective tax rate is primarily attributable to our Drilling and Completion operations, which had an effective tax rate of 41.7% for the three months ended June 30, 2008 compared to 35.4% for three months ended June 30, 2007. This increase in effective tax rate percentage is attributable to the change in mix of operations by taxing jurisdictions.

We had net income of $10.6 million for the three months ended June 30, 2008, a decrease of 45.9% compared to net income of $19.5 million for the three months ended June 30, 2007.

The following table compares revenues and income from operations for each of our business segments and loss of income for general corporate purposes. 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,
	2008		2007		Change			2008			2007			Change
	(in thousands)
Oilfield Services	$	68,653	$	58,122	$	10,531		$	13,090		$	20,595		$	(7,505	)
Drilling and Completion		69,818		52,861		16,957			9,391			10,218			(827	)
Rental Services		24,664		32,379		(7,715	)		9,266			14,770			(5,504	)
General corporate		—		—		—			(4,079	)		(4,109	)		30


Total	$	163,135	$	143,362	$	19,773		$	27,668		$	41,474		$	(13,806	)

Oilfield Services

Revenues were $68.7 million for the three months ended June 30, 2008, an increase of 18.1% compared to $58.1 million in revenues for the three months ended June 30, 2007. Our Oilfield Services segment revenues for the second quarter of 2008 increased compared to the second quarter of 2007 due primarily to our investment in new equipment in 2007 and the first quarter of 2008, including air-drilling compressors, foam units, casing and tubing tools and coil tubing units. Results in the Oilfield Services segment also improved due to small acquisitions completed in 2007 which added downhole motors, MWD tools and directional drillers and enabled us to expand our directional drilling business in the Northern Rocky Mountains and the Mid-Continent areas. Income from operations decreased to $13.1 million in the second quarter of 2008 compared to $20.6 million in the second quarter of 2007 due to the $8.9 million gain on the sale of capillary assets recognized in the three months ended June 30, 2007. Without this gain in the year-ago quarter, operating income would have increased period over period for the reasons enumerated above.

Drilling and Completion

Revenues for the quarter ended June 30, 2008 for the Drilling and Completion segment were $69.8 million, an increase from $52.9 million in revenues for the quarter ended June 30, 2007. Income from operations decreased to $9.4 million in the second quarter of 2008 compared to $10.2 million in the second quarter of 2007. Our Drilling and Completion segment revenues increased in the second quarter of 2008 due to increased pricing for our drilling and workover services in Argentina and the activation of eight new service rigs during the first quarter of 2008 and two new service rigs during the second quarter of 2008. The ten new service rigs are part of our 20 rig order (16 service and 4 drilling rigs), which we expect to place in service throughout 2008. Operating income for the second quarter of 2008 decreased compared to the prior year. This was due primarily to higher wages, which included other payroll expenses, and the increase in administrative costs all relating to labor concessions in Argentina granted by the oil industry in the last half of 2007 and the impact of labor strikes and work slow-downs as a result of the labor and political environment in Argentina. Additionally, operating income was also impacted by a significant increase in our labor force and labor-related expenses in connection with the delivery of new rigs prior to their activation.

Rental Services

Revenues for the quarter ended June 30, 2008 for the Rental Services segment were $24.7 million, a decrease from $32.4 million in revenues for the quarter ended June 30, 2007. Income from operations decreased to $9.3 million in the second quarter of 2008 compared to $14.8 million in the second quarter of 2007. Our Rental Services segment revenues and operating income for the second quarter of 2008 decreased compared to the prior year due primarily to the decrease in utilization of our rental equipment and a more competitive pricing environment due to a decrease in drilling activity in the Gulf of Mexico.

General Corporate

General corporate expenses were flat at $4.1 million for the three months ended June 30, 2008 and for the three months ended June 30, 2007.

Comparison of Six Months Ended June 30, 2008 and 2007

Our revenues for the six months ended June 30, 2008 were $316.3 million, an increase of 13.3% compared to $279.3 million for the six months ended June 30, 2007. The increase in revenues is due to the increase in revenues in our Oilfield Services and Drilling and Completion segments, partly offset by a decrease in revenues in our Rental Services segment. Revenues increased in our Oilfield Services segment by $23.0 million due to our investment in new equipment in 2007 and in 2008, the opening of new operating locations and small acquisitions completed in 2007 which added downhole motors, MWD tools and directional drilling personnel. Revenues increased in our Drilling and Completion segment by $31.1 million due to increased pricing for our drilling and workover services in Argentina and the activation of eight new service rigs during the first quarter of 2008 and two new service rigs in the second quarter of 2008. The decrease of $17.1 million in revenues in our Rental Services segment is due to decreased utilization of our equipment and more competitive pricing due to the decrease in drilling activity in the Gulf of Mexico.

Our gross margin for the six months ended June 30, 2008 decreased 12.7% to $82.4 million, or 26.0% of revenues, compared to $94.4 million, or 33.8%, of revenues for the six months ended June 30, 2007. The decrease in gross profit is principally due to the decrease in Rental Services revenue. Our gross margin also decreased due to the increase in depreciation expense due to our capital expenditures. The decrease in gross profit as a percentage of revenues is primarily due to the decrease in Rental Services revenues, the decrease in our gross margin percentage in our Drilling and Completion segment and the increase in depreciation expense. The decrease in the gross margin in our Drilling and Completion segment is due to higher wages and the impact of labor strikes and work slowdowns as a result of the labor and political environment in Argentina and the significant increase in our labor force and labor related expenses in connection with the delivery of new rigs prior to their activation. Depreciation expense increased 23.5% to $29.7 million for the first six months of 2008 compared to $24.1 million for the first six months of 2007. The increase is due to additional depreciable assets resulting from capital expenditures and acquisitions. 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 $28.9 million in the first six months of 2008 compared to $28.3 million for the first six months of 2007. General and administrative expense increased due to the additional expenses associated with acquisitions, and the hiring of additional sales and administrative personnel. As a percentage of revenues, general and administrative expenses decreased to 9.1% in the first six months of 2008 compared to 10.1% in the first six months of 2007.

We recorded an expense of $4.4 million related to share-based compensation expense for the six months ended June 30, 2008 compared to $1.1 million for the six months ended June 30, 2007. The amount of share-based compensation expense recorded in general and administrative expense was $4.4 million for the first six months of 2008 and $1.0 million for the first six months of 2007 with the balance being recorded as a direct cost.

Amortization expense was $2.2 million in the first six months of 2008 compared to $2.0 million in the first six months of 2007. The increase in amortization expense is due to the amortization of intangible assets in connection with our acquisitions.

Income from operations for the six months ended June 30, 2008 totaled $51.3 million, a decrease of 29.7% compared to income from operations of $72.9 million for the six months ended June 30, 2007, reflecting the decrease in our gross margin and increased general and administrative expenses. Our income from operations as a percentage of revenues decreased to 16.2% for the first six months of 2008, from 26.1% for the first six months of 2007, due to the decrease in our gross margin as a percentage of revenues offset partially by the decrease in general and administrative expenses as a percentage of revenues.

Our net interest expense was $21.4 million in the first six months of 2008, compared to $24.0 million for the first six months of 2007. Interest expense decreased in the first six months of 2008 due to an increase in interest income, offset in part by an increase in our average outstanding debt. Our net interest expense includes interest income of $2.5 million in the first six months of 2008 from our 15% $40.0 million subordinated convertible debenture due from BCH Ltd. which closed on January 31, 2008. In January 2007, we issued $250.0 million of senior notes bearing interest at 8.5% to pay off, in part, the bridge loan utilized to complete the acquisition of the assets of Oil & Gas Rental Services, Inc., or OGR, and for working capital. The bridge loan was outstanding until January 29, 2007 and had an average interest rate of 10.6%. Interest expense for the first six months of 2007 includes the write-off of deferred financing fees of $1.2 million related to the repayment of the bridge loan.

Our provision for income taxes for the six months ended June 30, 2008 was $11.7 million, or 38.7% of our net income before income taxes, compared to $17.6 million, or 35.7% of our net income before income taxes for the six months ended June 30, 2007. The increase in our effective tax rate is primarily attributable to our Drilling and Completion operations, which had an effective tax rate of 39.5% for the six months ended June 30, 2008 compared to 33.9% for six months ended June 30, 2007. This increase in effective tax rate percentage is attributable to the change in mix of operations by taxing jurisdictions.

We had net income of $18.6 million for the six months ended June 30, 2008, a decrease of 41.2% compared to net income of $31.7 million for the six months ended June 30, 2007.


	Revenues							Income (Loss) from Operations
	Six Months Ended							Six Months Ended
	June 30,							June 30,
	2008		2007		Change			2008			2007			Change
	(in thousands)
Oilfield Services	$	136,556	$	113,553	$	23,003		$	26,387		$	32,287		$	(5,900	)
Drilling and Completion		132,879		101,749		31,130			18,259			19,832			(1,573	)
Rental Services		46,882		63,960		(17,078	)		15,488			28,693			(13,205	)
General corporate		—		—		—			(8,884	)		(7,868	)		(1,016	)


Total	$	316,317	$	279,262	$	37,055		$	51,250		$	72,944		$	(21,694	)

Oilfield Services

Revenues were $136.6 million for the six months ended June 30, 2008, an increase of 20.3% compared to $113.6 million in revenues for the six months ended June 30, 2007. Our Oilfield Services segment revenues for the first six months of 2008 increased compared to the first six months of 2007 due primarily to our investment in new equipment in 2007 and in 2008, including air-drilling compressors, foam units, casing and tubing tools and coil tubing units. Results in the Oilfield Services segment also improved due to small acquisitions completed in 2007 which added downhole motors, MWD tools and directional drillers and enabled us to expand our directional drilling business in the Northern Rocky Mountains and the Mid-Continent areas. Income from operations decreased to $26.4 million in the first six months of 2008 compared to $32.3 million in the first six months of 2007 due to the $8.9 million gain on the sale of capillary assets recognized in the three months ended June 30, 2007. Without this gain in the prior year, operating income would have increased period over period for the reasons enumerated above.

Drilling and Completion

Revenues for the six months ended June 30, 2008 for the Drilling and Completion segment were $132.9 million, an increase from $101.7 million in revenues for the six months ended June 30, 2007. Income from operations decreased to $18.3 million in the first six months of 2008 compared to $19.8 million in the first six months of 2007. Our Drilling and Completion segment revenues increased in the first six months of 2008 due to increased pricing for our drilling and workover services in Argentina and the activation of eight new service rigs during the first quarter of 2008 and two new service rigs during the second quarter of 2008. The ten new service rigs are part of our 20 rig order (16 service and 4 drilling rigs), which we expect to place in service throughout 2008. Operating income for the first six months of 2008 decreased compared to the prior year. This was due primarily to higher wages, other payroll expenses and the increase in administrative costs all relating to labor concessions in Argentina granted by the oil industry in the last half of 2007 and the impact of labor strikes and work slow-downs as a result of the labor and political environment in Argentina. Additionally, operating income was also impacted by a significant increase in our labor force and labor-related expenses in connection with the delivery of new rigs prior to their activation.

Rental Services

Revenues for the six months ended June 30, 2008 for the Rental Services segment were $46.9 million, a decrease from $64.0 million in revenues for the six months ended June 30, 2007. Income from operations decreased to $15.5 million in the first six months of 2008 compared to $28.7 million in the first six months of 2007. Our Rental Services segment revenues and operating income for the first six months of 2008 decreased compared to the prior year due primarily to the decrease in utilization of our rental equipment and a more competitive pricing environment due to a decrease in drilling activity in the Gulf of Mexico.

General Corporate

General corporate expenses increased $1.0 million to $8.9 million for the six months ended June 30, 2008 compared to $7.9 million for the six months ended June 30, 2007. The increase was due to the increase in payroll costs and benefits for additional management and accounting and administrative staff as a result of the acquisitions and the increase in share-based compensation expense.

Company Outlook

We believe the level of our revenues are sustainable dependent on a favorable oil and natural gas price environment, a stable rig count and the level of capital expenditures of our customers. All of our segments experienced an increase in revenue for the three months ended June 30, 2008 compared to the three months ended March 31, 2008, Drilling and Completion revenue increased $6.8 million, Rental Services increased $2.4 million and Oilfield Services increased $750,000. We expect our Rental Services revenues to continue to improve as we develop new markets for our equipment. Our gross margin for the three months ended June 30, 2008 compared to the three months ended March 31, 2008 increased $2.8 million for our Rental Services segment, and by $842,000 for our Drilling and Completion segment, while our Oilfield Services segment had a decrease of $255,000. We believe the increases in margin are evidence of improved utilization and pricing, while the decrease in Oilfield Services was related to a drop in our directional drilling activity and increased depreciation expense for the whole segment. The sustainability and future growth in our gross margin is principally dependent on our level of revenues and the pricing environment of our services. We expect our general and administrative and amortization expenses to remain stable throughout the balance of 2008, absent any significant acquisitions. Our net interest expense is dependent upon our level of debt and cash on hand, which are principally dependent on acquisitions we complete, our capital expenditures and our cash flows from operations.

Liquidity and Capital Resources

Our on-going capital requirements arise primarily from our need to service our debt, complete acquisitions, acquire and maintain equipment, and fund our working capital requirements. Our primary sources of liquidity are proceeds from the issuance of debt and equity securities and cash flows from operations. We had cash and cash equivalents of $10.1 million at June 30, 2008 compared to $43.7 million at December 31, 2007.

Operating Activities

In the six months ended June 30, 2008, our operating activities provided $56.4 million in cash. Net income for the six months ended June 30, 2008 was $18.6 million. Non-cash expenses totaled $41.7 million during the first six months of 2008 consisting of $31.9 million of depreciation and amortization, $4.3 million for deferred income taxes related to timing differences, $1.0 in amortization of deferred financing fees, $4.4 million from the expensing of stock based compensation, $636,000 related to increases to the allowance for doubtful accounts receivables, less $537,000 on the gain from asset disposals.

During the six months ended June 30, 2008, changes in operating assets and liabilities used $3.9 million in cash, principally due to an increase of $13.9 million in accounts receivable, an increase of $4.5 million in inventories, an increase of $3.7 million in other assets, offset in part by an increase of $8.7 million in accounts payable, an increase of $5.0 million in accrued salaries, benefits and payroll taxes and an increase of $4.5 million in accrued expenses. Accounts receivable increased primarily due to the increase in our revenues in the first six months of 2008. The increase in inventories is related to the additional supplies needed to support our increasing rig and coiled tubing fleets. The increase in other assets primarily relates to $2.5 million of interest income on our $40.0 million note receivable from BCH Ltd. and $2.2 million of costs incurred to date on our pending acquisition of Bronco Drilling Company, Inc. The increase in accounts payable can be attributed to additional expenses related to the growth of our Drilling and Completion segment’s rig fleet. The increase in accrued salaries, benefits and payroll taxes is primarily related to a retroactive pay increase granted to our Drilling and Completion segment’s workers based in Argentina due to labor negotiations. The increase in accrued expenses is primarily related to an additional operational activities and new rig purchases in our Drilling and Completion segment and in our Oilfield Services segment.

In the six months ended June 30, 2007, our operating activities provided $56.4 million in cash. Net income for the six months ended June 30, 2007 was $31.7 million. Non-cash expenses totaled $27.5 million during the first six months of 2007 consisting of $26.1 million of depreciation and amortization, $6.7 million for deferred taxes related to timing differences, $1.2 million for the write-off of loan fees related to the bridge loan that was repaid, $1.0 million in amortization of deferred financing fees, $1.1 million from the expensing of stock based compensation, $279,000 related to increases to the allowance for doubtful accounts receivables, less $8.9 million on the gain from asset disposals.

During the six months ended June 30, 2007, changes in operating assets and liabilities used $2.8 million in cash, principally due to an increase of $25.5 million in accounts receivable, an increase of $3.8 million in inventories, offset in part by a decrease in other current assets of $9.5 million, an increase of $4.0 million in accounts payable, an increase of $7.9 million in accrued interest, an increase of $3.0 million in accrued expenses and an increase in accrued salaries, benefits and payroll taxes of $2.1 million. Accounts receivable increased primarily due to the increase in our revenues in the first six months of 2007. Other inventory increased primarily due to the build-up of inventory to meet the demands of increased activity levels in our Drilling and Completion segment. The decrease in other current assets is principally due to the collection of the working capital adjustment from the OGR acquisition for approximately $7.1 million in the first quarter of 2007. The increase in accounts payable, accrued expenses and accrued salaries, benefits and payroll taxes is attributed to additional expenses related to higher activity levels. The increase in accrued interest is due to the semi-annual payment of interest on our 9.0% senior notes due in July 2007.

Investing Activities

During the six months ended June 30, 2008, we used $114.5 million in investing activities, consisting of a $74.7 million for capital expenditures, $40.0 million convertible subordinated secured note from BCH Ltd, $3.4 million for deposits on equipment purchases for our Drilling and Completion segment, offset by $3.6 million of proceeds from equipment sales. Included in the $74.7 million for capital expenditures was $23.8 million for our Oilfield Services segment, including additional casing and tubing equipment and coiled tubing support equipment, $39.7 million for additional equipment in our Drilling and Completion segment and $11.1 million for drill pipe and other equipment used in our Rental Services segment. A majority of our equipment sales relate to items “lost in hole” or “damaged beyond repair” by our customers.

During the six months ended June 30, 2007, we used $31.2 million in investing activities, consisting of $47.2 million for capital expenditures, $3.6 million for business acquisition and $440,000 for investment in oilfield prospects, offset by $19.9 million of proceeds from asset sales. Included in the $47.2 million for capital expenditures was $18.9 million for drill pipe and other equipment used in our Rental Services segment, $5.9 million for additional equipment in our Drilling and Completion segment and $21.9 million for our Oilfield Services segment, including additional MWD equipment and new compressor packages. We received proceeds of $16.3 million from the sale of our capillary assets and $3.7 million from the proceeds from asset sales in connection with items “lost in hole” by our customers or other asset sales.

Financing Activities

During the six months ended June 30, 2008, financing activities provided $24.5 million in cash. We received $10.0 million from net borrowings under our revolving line of credit and an additional $17.9 million in proceeds from long-term debt and repaid $4.1 million in borrowings under long-term debt facilities. Proceeds from the additional $17.9 million in long-term borrowing were used for a portion of the purchase price of the new drilling and service rigs ordered for our Drilling and Completion segment. We also financed our renewal of $2.8 million in insurance policy premiums in a non-cash transaction. The $4.1 million of repayment of long-term debt facilities were scheduled repayments. We also received $609,000 in proceeds from the exercise of options and warrants.

During the six months ended June 30, 2007, financing activities provided $41.9 million in cash. We received $250.0 million in proceeds from long-term debt, repaid $305.2 million in borrowings under long-term debt facilities, including repayments of the bridge loan, and paid $7.6 million in debt issuance costs. We also received $100.1 million from the issuance of our common stock in a public offering, net of expenses along with $3.1 million in proceeds from the exercise of options and warrants. We recognized a tax benefit of $1.5 million related to our stock compensation plans.

At June 30, 2008, we had $541.3 million in outstanding indebtedness, of which $532.2 million was long-term debt and $9.1 million is due within one year.

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

Notes payable

In 2000 we compensated directors, including current directors, who served on the board of directors from 1989 to March 31, 1999 without compensation, by issuing promissory notes totaling $325,000. The notes bore interest at the rate of 5.0%. At June 30, 2008 and December 31, 2007, the principal and accrued interest on these notes totaled approximately $32,000.

Other debt

We also had various capital leases with terms that expire in 2008. As of June 30, 2008 and December 31, 2007, amounts outstanding under capital leases were $0 and $14,000, respectively.

Off Balance Sheet Arrangements

We have no off balance sheet arrangements, other than normal operating leases and employee contracts, that have or are likely to have a current or future material effect on our financial condition, changes in financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources. We do not guarantee obligations of any unconsolidated entities. At June 30, 2008, we had a $90.0 million revolving line of credit with a maturity of April 2012 and we had borrowed $10.0 million on the facility and availability was further reduced by outstanding letters of credit of $7.0 million.

Capital Requirements

We have identified capital expenditure projects that will require approximately $75.0 million for the remainder of 2008, 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. 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 may require additional equity or debt financing. 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 June 1, 2008, we and Bronco entered into an amendment to our previously announced merger which provides that stockholders of Bronco will receive aggregate merger consideration comprised of $200.0 million in cash and 16,846,500 shares of our common stock.

Critical Accounting Policies

Please see our Annual Report on Form 10-K for the year ended December 31, 2007 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, 2008.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133, or SFAS No. 161. SFAS No. 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in hedged positions. The statement also requires enhanced disclosures regarding how and why entities use derivative instruments, how derivative instruments and related hedged items are accounted and how derivative instruments and related hedged items affect entities’ financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008. We will adopt SFAS No. 161 on January 1, 2009 and do not expect the adoption to have a material impact on our financial statements.

Forward-Looking Statements

This quarterly report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, regarding our business, financial condition, results of operations and prospects. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements. However, these are not the exclusive means of identifying forward-looking statements. Although such forward-looking statements reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Further information about the risks and uncertainties that may impact us are described under “Item 1A—Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007. You should read those sections carefully. You should not place undue reliance on forward-looking statements, which speak only as of the date of this quarterly report. We undertake no obligation to update publicly any forward-looking statements in order to reflect any event or circumstance occurring after the date of this quarterly report or currently unknown facts or conditions or the occurrence of unanticipated events.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

Interest Rate Risk.

Fluctuations in the general level of interest rates on our current and future fixed and variable rate debt obligations expose us to market risk. We are vulnerable to significant fluctuations in interest rates affecting our adjustable rate debt, and any future refinancing of our fixed rate debt and our future debt. We have approximately $31.7 million of adjustable rate debt with a weighted average interest rate of 5.6% at June 30, 2008.

Foreign Currency Exchange Rate Risk.

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

ITEM 4. CONTROLS AND PROCEDURES.

(a) Evaluation of Disclosure Controls and Procedures.

As of the end of the period covered by this quarterly report, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(e) and 15d — 15(e) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. This evaluation was carried out under the supervision and with the participation of our management, including our chief executive officer and chief financial officer. Based on this evaluation, these officers have concluded that, as of June 30, 2008, our disclosure controls and procedures are effective at a reasonable assurance level in ensuring that the information required to be disclosed by us in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission, or SEC, rules and forms.

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

(b) Change in Internal Control Over Financial Reporting.

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

PART II. OTHER INFORMATION

ITEM 6. EXHIBITS

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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on August 8, 2008.


		Allis-Chalmers Energy Inc.
		(Registrant)

		/s/ Munawar H. Hidayatallah Munawar H. Hidayatallah
		Chief Executive Officer and Chairman

EXHIBIT INDEX


3.1		Second Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed on April 3, 2008).

10.1		First Amendment, dated June 1, 2008, to the Agreement and Plan of Merger by and among Allis-Chalmers Energy Inc., Elway Merger Sub, Inc. and Bronco Drilling Company, Inc. (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on June 2, 2008).

10.2		First Amendment to Investor Rights Agreement, by and among Allis-Chalmers Energy Inc. and the holders named thereto, dated June 23, 2008. (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on June 26, 2008).

10.3		Amendment to Employment Agreement among Allis-Chalmers Energy Inc., AirComp LLC and Terrence P. Keane, effective April 1, 2008 (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on May 1, 2008).

31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Certification of the Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Filed herewith

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