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, 2010


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 incorporation or organization)		(I.R.S. Employer Identification No.)

5075 WESTHEIMER, SUITE 890, HOUSTON, TEXAS		77056

(Address of principal executive offices)		(Zip Code)

(713) 369-0550

Registrant’s telephone number, including area code

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

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


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

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 4, 2010 there were 72,415,682 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, 2010

TABLE OF CONTENTS


	PAGE
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Condensed Balance Sheets as of June 30, 2010 and December 31, 2009		3
Consolidated Condensed Statements of Operations for the three and six months ended June 30, 2010 and 2009		4
Consolidated Condensed Statements of Cash Flows for the six months ended June 30, 2010 and 2009		5
Notes to Consolidated Condensed Financial Statements		6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		25
Item 3. Quantitative and Qualitative Disclosures about Market Risk		36
Item 4. Controls and Procedures		37

PART II OTHER INFORMATION
Item 1A Risk Factors		37
Item 6. Exhibits		38
Signatures		38
EX-31.1
EX-31.2
EX-32.1

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED CONDENSED BALANCE SHEETS

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


	June 30,		December 31,
	2010		2009
	(unaudited)
Assets
Cash and cash equivalents	$	17,569	$	41,072
Trade receivables, net		130,904		105,059
Inventories		36,920		34,528
Deferred income tax asset		2,727		3,790
Prepaid expenses and other		7,667		13,799

Total current assets		195,787		198,248

Property and equipment, net		733,334		746,478
Goodwill		40,639		40,639
Other intangible assets, net		30,337		32,649
Debt issuance costs, net		8,628		9,545
Deferred income tax asset		33,900		22,047
Other assets		37,949		31,014


Total assets	$	1,080,574	$	1,080,620

Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	18,596	$	17,027
Trade accounts payable		45,592		34,839
Accrued salaries, benefits and payroll taxes		24,799		22,854
Accrued interest		15,969		15,821
Accrued expenses		25,743		21,918

Total current liabilities		130,699		112,459

Long-term debt, net of current maturities		470,623		475,206
Deferred income tax liability		8,136		8,166
Other long-term liabilities		676		1,142

Total liabilities		610,134		596,973

Commitments and contingencies

Stockholders’ Equity
Preferred stock, $0.01 par value (25,000,000 shares authorized, 36,393 shares issued and outstanding at June 30, 2010 and at December 31, 2009)		34,183		34,183
Common stock, $0.01 par value (200,000,000 shares authorized; 72,418,855 issued and outstanding at June 30, 2010 and 71,378,529 issued and outstanding at December 31, 2009)		724		714
Capital in excess of par value		425,790		422,823
Retained earnings		9,743		25,927

Total stockholders’ equity		470,440		483,647


Total liabilities and stockholders’ equity	$	1,080,574	$	1,080,620

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

ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)
(unaudited)


	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Revenues	$	158,644		$	112,505		$	299,014		$	257,608

Operating costs and expenses
Direct costs		120,723			87,239			228,438			190,373
Depreciation		20,517			19,181			40,705			38,552
Selling, general and administrative		12,114			15,525			24,177			29,165
Loss on asset disposition		—			1,916			—			1,916
Amortization		1,156			1,187			2,312			2,374

Total operating costs and expenses		154,510			125,048			295,632			262,380


Income (loss) from operations		4,134			(12,543	)		3,382			(4,772	)

Other income (expense):
Interest expense		(11,149	)		(13,221	)		(22,105	)		(26,728	)
Interest income		299			9			454			14
Gain on debt extinguishment		—			26,365			—			26,365
Other		(303	)		(485	)		(1,818	)		(268	)


Total other income (expense)		(11,153	)		12,668			(23,469	)		(617	)


Income (loss) before income taxes		(7,019	)		125			(20,087	)		(5,389	)

Provision for income taxes		1,640			(215	)		5,177			2,694


Net loss		(5,379	)		(90	)		(14,910	)		(2,695	)

Preferred stock dividend		(637	)		(35	)		(1,274	)		(35	)


Net loss attributed to common stockholders	$	(6,016	)	$	(125	)	$	(16,184	)	$	(2,730	)


Net loss per common share:
Basic	$	(0.08	)	$	0.00		$	(0.23	)	$	(0.08	)
Diluted	$	(0.08	)	$	0.00		$	(0.23	)	$	(0.08	)

Weighted average shares outstanding:
Basic		71,270			36,959			71,149			36,087
Diluted		71,270			36,959			71,149			36,087

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,
	2010			2009
Cash Flows from Operating Activities:
Net loss	$	(14,910	)	$	(2,695	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization		43,017			40,926
Amortization and write-off of debt issuance costs		1,106			1,151
Stock-based compensation		3,001			2,345
Allowance for bad debts		—			3,565
Deferred taxes		(10,821	)		(6,088	)
Loss (gain) on sale of property and equipment		807			(602	)
Loss on investment		1,466			—
Equity in loss of unconsolidated affiliates		260			—
Loss on asset disposition		—			1,916
Gain on debt extinguishment		—			(26,365	)
Changes in operating assets and liabilities:
Decrease (increase) in trade receivable		(25,845	)		55,279
Decrease (increase) in inventories		(2,392	)		2,526
Decrease in prepaid expenses and other current assets		8,838			7,411
Decrease in other assets		799			1,120
Increase (decrease) in trade accounts payable		10,753			(27,170	)
Increase (decrease) in accrued interest		148			(2,954	)
Increase (decrease) in accrued expenses		3,801			(5,760	)
Increase (decrease) in accrued salaries, benefits and payroll taxes		1,945			(1,036	)
(Decrease) in other long-term liabilities		(466	)		(605	)

Net Cash Provided By Operating Activities		21,507			42,964


Cash Flows from Investing Activities:
Deposits on asset commitments		(10,096	)		10,032
Proceeds from sale of investments		368			—
Proceeds from sale of property and equipment		2,616			6,693
Purchase of property and equipment		(30,989	)		(57,993	)

Net Cash Used In Investing Activities		(38,101	)		(41,268	)


Cash Flows from Financing Activities:
Proceeds from issuance of stock, net		—			120,337
Proceeds from long-term debt		4,000			25,000
Net repayments of line of credit		—			(36,500	)
Payments on long-term debt		(9,446	)		(57,396	)
Payment of preferred stock dividend		(1,274	)		—
Debt issuance costs		(189	)		(644	)

Net Cash (Used In) Provided By Financing Activities		(6,909	)		50,797

Net change in cash and cash equivalents		(23,503	)		52,493

Cash and cash equivalents at beginning of period		41,072			6,866


Cash and cash equivalents at end of period	$	17,569		$	59,359

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, Arkansas, Pennsylvania, Oklahoma, New Mexico, offshore in the Gulf of Mexico, and internationally, primarily in Argentina, Brazil, Bolivia and Mexico. We operate in three sectors of the oil and natural gas service industry: Oilfield Services; Drilling and Completion and Rental Services.

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

Basis of Presentation

Our unaudited consolidated condensed financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission, or SEC. Accordingly, certain information and disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited consolidated condensed financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. These unaudited consolidated condensed financial statements should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2009. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year.

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, stock-based compensation, income taxes and valuation allowances. The accounting estimates used in the preparation of the consolidated financial statements may change as new events occur, as more experience is acquired, as additional information is obtained or as our operating environment changes.

Financial Instruments

Financial instruments consist of cash and cash equivalents, accounts receivable and payable, and debt. The carrying value of cash and cash equivalents and accounts receivable and payable approximate fair value due to their short-term nature. We believe the fair values and the carrying value of our debt, excluding the senior notes, would not be materially different due to the instruments’ interest rates approximating market rates for similar borrowings at June 30, 2010. Our senior notes, in the approximate aggregate amount of $430.2 million, trade “over the counter” in limited amounts and on an infrequent basis. Based on recent trades we estimate the fair value of our senior notes to be approximately $385.4 million at June 30, 2010. The price at which our senior notes trade is based on many factors such as the level of interest rates, the economic environment, the outlook for the oilfield services industry and the perceived credit risk.

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

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

New Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board (FASB) issued authoritative guidance that eliminates the qualifying special purpose entity concept, changes the requirements for derecognizing financial assets and requires enhanced disclosures about transfers of financial assets. The guidance also revises earlier guidance for determining whether an entity is a variable interest entity, requires a new approach for determining who should consolidate a variable interest entity, changes when it is necessary to reassess who should consolidate a variable interest entity, and requires enhanced disclosures related to an enterprise’s involvement in variable interest entities. We adopted the guidance effective January 1, 2010, which did not have a material effect on our financial statements.

In October 2009, the FASB issued authoritative guidance that amends earlier guidance addressing the accounting for contractual arrangements in which an entity provides multiple products or services (deliverables) to a customer. The amendments address the unit of accounting for arrangements involving multiple deliverables and how arrangement consideration should be allocated to the separate units of accounting, when applicable, by establishing a selling price hierarchy for determining the selling price of a deliverable. The selling price used for each deliverable will be based on vendor-specific objective evidence if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific nor third-party evidence is available. The amendments also require that arrangement consideration be allocated at the inception of an arrangement to all deliverables using the relative selling price method. The guidance is effective for fiscal years beginning on or after June 15, 2010, with earlier application permitted. We are currently evaluating the effects that the guidance may have on our financial statements.

In January 2010, the FASB issued authoritative guidance that changes the disclosure requirements for fair value measurements. Specifically, the changes require a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers. The changes also clarify existing disclosure requirements related to how assets and liabilities should be grouped by class and valuation techniques used for recurring and nonrecurring fair value measurements. We adopted the guidance in the first quarter 2010, which did not have an impact on our financial position, results of operations or cash flows.

In February 2010, the FASB amended guidance on subsequent events to alleviate potential conflicts between FASB guidance and SEC requirements. Under this amended guidance, SEC filers are no longer required to disclose the date through which subsequent events have been evaluated in originally issued and revised financial statements. This guidance was effective immediately and we adopted these new requirements in the first quarter 2010. The adoption of this guidance did not have an impact on our financial statements.

NOTE 2 — STOCK-BASED COMPENSATION

We recognize all share-based payments to employees and directors in the financial statements based on their grant-date fair values. We utilize the Black-Scholes model to determine fair value, which incorporates assumptions to value stock-based awards. The dividend yield on our common stock is assumed to be zero as we have historically not paid dividends on our common stock and have no current plans to do so in the future. The expected volatility is based on historical volatility of our common stock. The risk-free interest rate is the related United States Treasury yield curve for periods within the expected term of the option at the time of grant. We estimate forfeiture rates based on our historical experience.

The following summarizes the Black-Scholes model assumptions used for the options granted in the three months ended June 30, 2010 and six months ended June 30, 2010 and 2009 (no options were granted in the three months ended June 30, 2009):


	For the Three Months			For the Six Months
	Ended			Ended
	June 30,			June 30,
	2010			2010			2009
Expected dividend yield		—			—			—
Expected price volatility		88.54	%		89.81	%		77.32	%
Risk free interest rate		1.51	%		1.41	%		1.37	%
Expected life of options	5 years			5 years			5 years
Weighted average fair value of options granted at market value	$	2.70		$	2.63		$	0.77

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

NOTE 2 — STOCK-BASED COMPENSATION (Continued)

Our net loss for the three months ended June 30, 2010 and 2009 includes approximately $1.6 million and $1.3 million, respectively, of compensation costs related to share-based payments. Our net loss for the six months ended June 30, 2010 and 2009 includes approximately $3.0 million and $2.3 million, respectively, of compensation costs related to share-based payments. As of June 30, 2010 there was $2.5 million of unrecognized compensation expense related to non-vested stock option grants. We expect approximately $340,000 to be recognized over the remainder of 2010 and approximately $535,000, $511,000, $506,000, $506,000 and $129,000 to be recognized during the years ended 2011 through 2015, respectively.

A summary of our stock option activity during the six months ended June 30, 2010 and related information is as follows:


				Weighted		Weighted
	Shares			Average		Average		Aggregate
	Under			Exercise		Contractual		Intrinsic Value
	Option			Price		Life (Years)		(millions)
Balance at December 31, 2009		701,732		$	6.31
Granted		1,072,253			3.78
Canceled		(21,967	)		8.30
Exercised		—

Outstanding at June 30, 2010		1,752,018		$	4.74		8.11	$	0.10


Exercisable at June 30, 2010		586,432		$	7.08		5.15	$	0.02

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 2010 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on June 30, 2010.

Restricted stock awards, or RSAs, activity during the six months ended June 30, 2010 were as follows:


				Weighted Average
				Grant-Date Fair
	Number of			Value
	Shares			Per Share
Nonvested at December 31, 2009		837,626		$	15.63
Granted		2,061,750			3.78
Vested		(294,253	)		17.30
Forfeited		(3,333	)		3.77

Nonvested at June 30, 2010		2,601,790		$	6.06

We determine the fair value of RSAs based on the market price of our common stock on the date of grant. Compensation cost for RSAs is primarily recognized on a straight-line basis over the vesting or service period and is net of forfeitures. During the six months ended June 30, 2010, we granted 1,237,750 performance based RSAs to executive officers and key employees that vest upon meeting certain financial performance conditions over the next five years. In connection with performance-based RSAs, compensation cost is based on estimated number of shares expected to be issued. As of June 30, 2010, there was $8.3 million of total unrecognized compensation cost related to nonvested RSAs. We expect approximately $2.3 million to be recognized over the remainder of 2010 and approximately $2.3 million, $1.3 million, $1.2 million, $1.1 million and $88,000 to be recognized during the years ended 2011 through 2105, respectively.

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

NOTE 3 — INVENTORIES

Inventories consisted of the following (in thousands):


	June 30,		December 31,
	2010		2009
Manufactured
Finished goods	$	3,401	$	2,983
Work in process		1,360		2,299
Raw materials		1,255		884

Total manufactured		6,016		6,166
Rig parts and related inventory		12,208		10,654
Shop supplies and related inventory		8,864		7,762
Chemicals and drilling fluids		4,599		4,381
Rental supplies		2,026		2,134
Hammers		2,191		2,257
Coiled tubing and related inventory		784		939
Drive pipe		232		235


Total inventories	$	36,920	$	34,528

NOTE 4— GOODWILL AND INTANGIBLE ASSETS

Goodwill and other intangible assets with infinite lives are not amortized, but tested for impairment annually or more frequently if circumstances indicate that impairment may exist. Intangible assets with finite useful lives are amortized either on a straight-line basis over the asset’s estimated useful life or on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized. Goodwill and indefinite-lived intangible assets listed on the balance sheet totaled $40.6 million at June 30, 2010 and December 31, 2009.

Definite-lived intangible assets that continue to be amortized relate to our purchase of customer-related and marketing-related intangibles, patents and non-compete agreements. These intangibles have useful lives ranging from three to twenty years. Amortization of intangible assets for the three and six months ended June 30, 2010 were $1.1 million and $2.3 million, respectively, compared to $1.2 million and $2.4 million for the same periods in the prior year. At June 30, 2010, intangible assets totaled $30.3 million, net of $15.1 million of accumulated amortization.

NOTE 5- DEBT

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


	June 30,		December 31,
	2010		2009
Senior notes	$	430,238	$	430,238
Revolving line of credit		—		—
Term loans		56,892		60,744
Insurance premium financing		1,998		997
Capital lease obligations		91		254

Total debt		489,219		492,233

Less: current maturities		18,596		17,027


Long-term debt, net of current maturities	$	470,623	$	475,206

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

NOTE 5 — DEBT (Continued)

Senior notes, line of credit agreements and term loans

On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, of $160.0 and $95.0 million aggregate principal amount of our senior notes, respectively. The senior notes are due January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of Specialty Rental Tools, Inc. and DLS Drilling, Logistics & Services Company, or DLS, to repay existing debt and for general corporate purposes. On June 29, 2009, we closed on a tender offer in which we purchased $30.6 million aggregate principal of our 9.0% senior notes for a total consideration of $650 per $1,000 principal amount.

In January 2007, we closed on a private offering, to qualified institutional buyers pursuant to Rule 144A under the Securities Act, of $250.0 million principal amount of 8.5% senior notes due 2017. The proceeds of the senior notes offering, together with a portion of the proceeds of our concurrent common stock offering, were used to repay the debt outstanding under our $300.0 million bridge loan facility which we incurred to finance our acquisition of substantially all the assets of Oil & Gas Rental Services, Inc. On June 29, 2009, we closed on a tender offer in which we purchased $44.2 million aggregate principal of our 8.5% senior notes for a total consideration of $600 per $1,000 principal amount.

We have a $90.0 million revolving line of credit with a final maturity date of April 26, 2012 which contains customary events of default and financial covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends or make other distributions, create liens and sell assets. On April 9, 2009, we amended our revolving credit agreement to modify the leverage and interest coverage ratio covenants. Effective December 31, 2009, we again amended the leverage and interest coverage ratio covenants of the revolving credit agreement. This amendment relaxed the required financial ratios for the quarter ended December 31, 2009 and for each of the quarters in 2010. Our obligations under the amended and restated credit agreement are secured by substantially all of our assets located in the U.S. We were in compliance with all debt covenants as of June 30, 2010 and December 31, 2009. As of June 30, 2010 and December 31, 2009, the only usage of our revolving facility consisted of $4.2 million in outstanding letters of credit. The credit agreement loan rates are based on prime or LIBOR plus a margin.

As part of our acquisition of DLS, we assumed various bank loans with floating interest rates based on LIBOR plus a margin and terms ranging from 2 to 5 years. The weighted average interest rates on these loans was 1.9% and 2.1% as of June 30, 2010 and December 31, 2009, respectively. The outstanding amount due as of June 30, 2010 and December 31, 2009 was $0.7 million and $1.1 million, respectively.

On February 15, 2008, through our DLS subsidiary, we entered into a $25.0 million import finance facility with a bank. Borrowings under this facility were used to fund a portion of the purchase price of the new drilling and service rigs ordered for our Drilling and Completion segment. The loan is repayable over four years in equal semi-annual installments beginning one year after each disbursement with the final principal payment due not later than March 15, 2013. The import finance facility is unsecured and contains customary events of default and financial covenants and limits DLS’ ability to incur additional indebtedness, make capital expenditures, create liens and sell assets. We were in compliance with all debt covenants as of June 30, 2010 and December 31, 2009. The bank loan rates are based on LIBOR plus a margin. The weighted average interest rate was 4.2% and 4.4% at June 30, 2010 and December 31, 2009, respectively. The outstanding amount as of June 30, 2010 and December 31, 2009 was $17.3 million and $20.1 million, respectively.

As part of our acquisition of BCH Ltd, or BCH, we assumed a $23.6 million term loan credit facility with a bank. The credit agreement is dated June 2007 and contains customary events of default and financial covenants. Obligations under the facility are secured by substantially all of the BCH assets. The facility is repayable in quarterly principal installments plus interest with the final payment due not later than August 2012. We were in compliance with all debt covenants as of June 30, 2010 and December 31, 2009. The credit facility loan interest rates are based on LIBOR plus a margin. At June 30, 2010 and December 31, 2009, the outstanding amount of the loan was $13.2 million and $16.2 million, respectively and the interest rate was 3.8% and 3.5%, respectively.

On May 22, 2009, we drew down $25.0 million on a new term loan credit facility with a lending institution. The facility was utilized to fund a portion of the purchase price of two new drilling rigs. The loan is secured by the equipment. The facility is repayable in quarterly installments of approximately $1.4 million of principal and interest and matures in May 2015. The loan bears interest at a fixed rate of 9.0%. At June 30, 2010 and December 31, 2009, the outstanding amount of the loan was $21.7 million and $23.4 million, respectively.

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

NOTE 5 — DEBT (Continued)

On February 9, 2010, through our DLS subsidiary, we entered into a $4.0 million term loan facility. The loan is repayable in semi-annual installments beginning April 14, 2011 with interest at 8.5% per annum. The final maturity date is April 14, 2014 and the loan is unsecured.

Notes payable

In April 2010, we obtained an insurance premium financing in the aggregate amount of $2.4 million with a fixed interest rate of 4.7%. Under terms of the agreement, amounts outstanding are paid over an 11 month repayment schedule. The outstanding balance of this note was approximately $2.0 million at June 30, 2010. In 2009, we obtained insurance premium financings in the aggregate amount of $3.2 million with a fixed average weighted interest rate of 4.8%. Under terms of the agreements, amounts outstanding are paid over 10 and 11 month repayment schedules. The outstanding balance of these notes was approximately $0 and $997,000 at June 30, 2010 and December 31, 2009, respectively.

Other debt

As part of our acquisition of BCH, we assumed various capital leases with terms of two to three years. The outstanding balance under these capital leases was $91,000 and $254,000 at June 30, 2010 and December 31, 2009, respectively.

NOTE 6 — STOCKHOLDERS’ EQUITY

During the six months ended June 30, 2010, we had restricted stock award grants and vested performance based restricted stock which resulted in the issuance of approximately 1 million shares of our common stock. We recognized approximately $3.0 million of compensation expense related to share-based payments in the first six months of 2010 that was recorded as capital in excess of par value (see Note 2). During the six months ended June 30, 2010, we declared approximately $1.3 million in dividends on our preferred stock. Accrued dividends of approximately $637,000 were included in our accrued expenses of $25.7 million as of June 30, 2010 and our accrued expenses of $21.9 million as of December 31, 2009. The accrued dividends were paid in July 2010 and February 2010, respectively.

NOTE 7 — LOSS ON ASSET DISPOSITION

During the three and six months ended June 30, 2009, we recorded a $1.9 million loss on asset disposition in our Drilling and Completion segment. The insurance proceeds related to damages incurred on a blow-out which destroyed one of our drilling rigs were not sufficient to cover the book value of the rig and related assets.

NOTE 8 — GAIN ON DEBT EXTINGUISHMENT

During the three and six months ended June 30, 2009, we recorded a gain of $26.4 million as a result of a tender offer that we completed on June 29, 2009. We purchased $30.6 million aggregate principal of our 9.0% senior notes and $44.2 million aggregate principal of 8.5% senior notes for approximately $46.4 million. The gain is net of a $1.5 million write-off of debt issuance costs related to the retired notes and we incurred approximately $466,000 in expenses related to the transactions.

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

NOTE 9 — LOSS PER COMMON SHARE

Basic earnings per share are computed on the basis of the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share is similar to basic earnings per share, but presents the dilutive effect on a per share basis of potential common shares (e.g., convertible preferred stock, stock options, etc.) as if they had been converted. The components of basic and diluted earnings per share are as follows (in thousands, except per share amounts):


	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Numerator:
Net loss	$	(5,379	)	$	(90	)	$	(14,910	)	$	(2,695	)
Preferred stock dividend		(637	)		(35	)		(1,274	)		(35	)

Net loss attributed to common stockholders	$	(6,016	)	$	(125	)	$	(16,184	)	$	(2,730	)


Denominator:
Weighted average common shares outstanding excluding nonvested restricted stock		71,270			36,959			71,149			36,087
Effect of potentially dilutive common shares:
Convertible preferred stock and stock-based compensation		—			—			—			—


Weighted average common shares outstanding and assumed conversions		71,270			36,959			71,149			36,087


Net loss per common share
Basic	$	(0.08	)	$	0.00		$	(0.23	)	$	(0.08	)

Diluted	$	(0.08	)	$	0.00		$	(0.23	)	$	(0.08	)

Potentially dilutive securities excluded as anti-dilutive		17,710			15,698			16,126			15,698

Convertible preferred stock and stock-based compensation shares of approximately 14.6 million and 14.9 million were excluded in the computation of diluted earnings per share for the three and six months ended June 30, 2010, respectively as the effect would have been anti-dilutive (e.g., those that increase income per share) due to the net loss for the period.

NOTE 10 — SUPPLEMENTAL CASH FLOW INFORMATION (in thousands)


	For the Six Months Ended
	June 30,
	2010		2009
Cash paid for interest and income taxes:
Interest	$	21,294	$	28,329
Income taxes		57		1,354

Non-cash activities:
Insurance premiums financed		2,432		2,381
Receivable from sale of investments		274		—
Assets transferred to joint venture investment		—		1,330
Preferred stock dividend		1,274		35

NOTE 11 — 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).

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

NOTE 11 – CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS
June 30, 2010 (unaudited)


	Allis-Chalmers
	(Parent/		Subsidiary		Subsidiary		Consolidating
	Guarantor)		Guarantors		Non-Guarantors		Adjustments			Consolidated Total
Assets
Cash and cash equivalents	$	—	$	13,324	$	4,245	$	—		$	17,569
Trade receivables, net		—		56,010		81,845		(6,951	)		130,904
Inventories		—		17,015		19,905		—			36,920
Intercompany receivables		—		104,356		1,096		(105,452	)		—
Note receivable from affiliate		28,286		—		—		(28,286	)		—
Prepaid expenses and other		93		6,754		3,547		—			10,394

Total current assets		28,379		197,459		110,638		(140,689	)		195,787
Property and equipment, net		—		474,477		258,857		—			733,334
Goodwill		—		23,250		17,389		—			40,639
Other intangible assets, net		437		23,320		6,580		—			30,337
Debt issuance costs, net		8,503		125		—		—			8,628
Note receivable from affiliates		2,400		—		—		(2,400	)		—
Investments in affiliates		950,645		—		—		(950,645	)		—
Other assets		31,932		36,736		3,181		—			71,849

Total assets	$	1,022,296	$	755,367	$	396,645	$	(1,093,734	)	$	1,080,574

Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	—	$	5,602	$	12,994	$	—		$	18,596
Trade accounts payable		—		19,170		33,373		(6,951	)		45,592
Accrued salaries, benefits and payroll taxes		—		2,567		22,232		—			24,799
Accrued interest		15,448		212		309		—			15,969
Accrued expenses		718		13,851		11,174		—			25,743
Intercompany payables		105,452		—		—		(105,452	)		—
Note payable to affiliate		—		—		28,286		(28,286	)		—

Total current liabilities		121,618		41,402		108,368		(140,689	)		130,699
Long-term debt, net of current maturities		430,238		18,099		22,286		—			470,623
Note payable to affiliate		—		—		2,400		(2,400	)		—
Other long-term liabilities		—		—		8,812		—			8,812

Total liabilities		551,856		59,501		141,866		(143,089	)		610,134

Commitments and Contingencies

Stockholders’ Equity
Preferred Stock		34,183		—		—		—			34,183
Common stock		724		3,526		42,963		(46,489	)		724
Capital in excess of par value		425,790		570,512		137,439		(707,951	)		425,790
Retained earnings		9,743		121,828		74,377		(196,205	)		9,743

Total stockholders’ equity		470,440		695,866		254,779		(950,645	)		470,440

Total liabilities and stockholders equity	$	1,022,296	$	755,367	$	396,645	$	(1,093,734	)	$	1,080,574

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

NOTE 11 – CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended June 30, 2010 (unaudited)


	Allis-Chalmers (Parent/			Subsidiary			Subsidiary			Consolidating
	Guarantor)			Guarantors			Non-Guarantors			Adjustments			Consolidated Total
Revenues	$	—		$	62,760		$	96,337		$	(453	)	$	158,644

Operating costs and expenses
Direct costs		—			42,300			78,876			(453	)		120,723
Depreciation		—			14,198			6,319			—			20,517
Selling, general and administrative		1,365			7,156			3,593			—			12,114
Amortization		11			959			186			—			1,156

Total operating costs and expenses		1,376			64,613			88,974			(453	)		154,510

Income (loss) from operations		(1,376	)		(1,853	)		7,363			—			4,134

Other income (expense):
Equity earnings in affiliates, net of tax		6,396			—			—			(6,396	)		—
Interest, net		(10,415	)		141			(576	)		—			(10,850	)
Other		16			(254	)		(65	)		—			(303	)

Total other income (expense)		(4,003	)		(113	)		(641	)		(6,396	)		(11,153	)


Net income (loss)before income taxes		(5,379	)		(1,966	)		6,722			(6,396	)		(7,019	)

Provision for income taxes		—			4,408			(2,768	)		—			1,640


Net income (loss)		(5,379	)		2,442			3,954			(6,396	)		(5,379	)

Preferred stock dividend		(637	)		—			—			—			(637	)


Net income (loss) attributed to common stockholders	$	(6,016	)	$	2,442		$	3,954		$	(6,396	)	$	(6,016	)

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

NOTE 11 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Six Months Ended June 30, 2010 (unaudited)


	Allis-Chalmers
	(Parent/			Subsidiary			Subsidiary			Consolidating
	Guarantor)			Guarantors			Non-Guarantors			Adjustments			Consolidated Total
Revenues	$	—		$	114,642		$	185,700		$	(1,328	)	$	299,014

Operating costs and expenses
Direct costs		—			77,376			152,390			(1,328	)		228,438
Depreciation		—			28,316			12,389			—			40,705
Selling, general and administrative		2,532			14,356			7,289			—			24,177
Amortization		23			1,916			373			—			2,312

Total operating costs and expenses		2,555			121,964			172,441			(1,328	)		295,632

Income (loss) from operations		(2,555	)		(7,322	)		13,259			—			3,382

Other income (expense):
Equity earnings in affiliates, net of tax		8,267			—			—			(8,267	)		—
Interest, net		(20,652	)		214			(1,213	)		—			(21,651	)
Other		30			(1,778	)		(70	)		—			(1,818	)

Total other income (expense)		(12,355	)		(1,564	)		(1,283	)		(8,267	)		(23,469	)


Net income (loss)before income taxes		(14,910	)		(8,886	)		11,976			(8,267	)		(20,087	)

Provision for income taxes		—			10,512			(5,335	)		—			5,177


Net income (loss)		(14,910	)		1,626			6,641			(8,267	)		(14,910	)

Preferred stock dividend		(1,274	)		—			—			—			(1,274	)


Net income (loss) attributed to common stockholders	$	(16,184	)	$	1,626		$	6,641		$	(8,267	)	$	(16,184	)

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

NOTE 11 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Six Months Ended June 30, 2010 (unaudited)


	Allis-Chalmers
	(Parent/			Subsidiary			Other Subsidiaries			Consolidating
	Guarantor)			Guarantors			(Non-Guarantors)			Adjustments			Consolidated Total
Cash Flows from Operating Activities:
Net income (loss)	$	(14,910	)	$	1,626		$	6,641		$	(8,267	)	$	(14,910	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		23			30,232			12,762			—			43,017
Amortization and write-off of debt issuance costs		1,094			12			—			—			1,106
Stock based compensation		3,001			—			—			—			3,001
Equity earnings in affiliates		(8,267	)		—			—			8,267			—
Deferred taxes		(10,954	)		—			133			—			(10,821	)
Loss (gain) on sale of equipment		—			965			(158	)		—			807
Loss on investment		—			1,466			—			—			1,466
Equity in losses of unconsolidated affiliates		—			260			—			—			260
Changes in operating assets and liabilities:

(Increase) in trade receivables		—			(2,962	)		(22,883	)		—			(25,845	)
(Increase) in inventories		—			(744	)		(1,648	)		—			(2,392	)
Decrease in prepaid expenses and other current assets		—			2,778			6,060			—			8,838
Decrease in other assets		—			127			672			—			799
Increase in trade accounts payable		—			1,285			9,468			—			10,753
(Decrease) increase in accrued interest		76			(16	)		88			—			148
(Decrease) increase in accrued expenses		(58	)		2,243			1,616			—			3,801
(Decrease) increase in accrued salaries, benefits and payroll taxes		—			(195	)		2,140			—			1,945
(Decrease) in other long- term liabilities		—			—			(466	)		—			(466	)

Net Cash Provided By (Used In) Operating Activities		(29,995	)		37,077			14,425			—			21,507


Cash Flows from Investing Activities:
Notes receivable from affiliates		3,293			—			—			(3,293	)		—
Deposits on asset commitments		—			(10,000	)		(96	)		—			(10,096	)
Proceeds from sale of investments		—			368			—			—			368
Proceeds from sale of property and equipment		—			2,416			200			—			2,616
Purchase of property and equipment		—			(18,069	)		(12,920	)		—			(30,989	)

Net Cash Provided By (Used In) Investing Activities		3,293			(25,285	)		(12,816	)		(3,293	)		(38,101	)

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

NOTE 11 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Six Months Ended June 30, 2010 (unaudited)


	Allis-Chalmers
	(Parent/			Subsidiary			Other Subsidiaries			Consolidating
	Guarantor)			Guarantors			(Non-Guarantors)			Adjustments			Consolidated Total
Cash Flows from Financing Activities:
Accounts receivable from affiliates		—			(27,210	)		(955	)		28,165			—
Accounts payable to affiliates		28,165			—			—			(28,165	)		—
Note payable to affiliate		—			—			(3,293	)		3,293			—
Proceeds from long-term debt		—			—			4,000			—			4,000
Payments on long-term debt		—			(3,116	)		(6,330	)		—			(9,446	)
Payment of preferred stock dividend		(1,274	)		—			—			—			(1,274	)
Debt issuance costs		(189	)		—			—			—			(189	)

Net Cash Provided By (Used In) Financing Activities		26,702			(30,326	)		(6,578	)		3,293			(6,909	)


Net change in cash and cash equivalents		—			(18,534	)		(4,969	)		—			(23,503	)
Cash and cash equivalents at beginning of period		—			31,858			9,214			—			41,072

Cash and cash equivalents at end of period	$	—		$	13,324		$	4,245		$	—		$	17,569

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

NOTE 11 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2009


	Allis-Chalmers
	(Parent/		Subsidiary		Subsidiary		Consolidating
	Guarantor)		Guarantors		Non-Guarantors		Adjustments			Consolidated Total
Assets
Cash and cash equivalents	$	—	$	31,858	$	9,214	$	—		$	41,072
Trade receivables, net		—		47,358		58,962		(1,261	)		105,059
Inventories		—		16,271		18,257		—			34,528
Intercompany receivables		—		79,521		767		(80,288	)		—
Note receivable from affiliate		28,379		—		—		(28,379	)		—
Prepaid expenses and other		891		6,826		9,872		—			17,589

Total current assets		29,270		181,834		97,072		(109,928	)		198,248
Property and equipment, net		—		489,921		256,557		—			746,478
Goodwill		—		23,251		17,388		—			40,639
Other intangible assets, net		460		25,236		6,953		—			32,649
Debt issuance costs, net		9,408		137		—		—			9,545
Note receivable from affiliates		4,415		—		—		(4,415	)		—
Investments in affiliates		942,378		—		—		(942,378	)		—
Other assets		24,366		25,039		3,656		—			53,061


Total assets	$	1,010,297	$	745,418	$	381,626	$	(1,056,721	)	$	1,080,620


Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	—	$	4,444	$	12,583	$	—		$	17,027
Trade accounts payable		—		12,195		23,905		(1,261	)		34,839
Accrued salaries, benefits and payroll taxes		—		2,762		20,092		—			22,854
Accrued interest		15,372		228		221		—			15,821
Accrued expenses		752		11,608		9,558		—			21,918
Intercompany payables		80,288		—		—		(80,288	)		—
Note payable to affiliate		—		—		28,379		(28,379	)		—

Total current liabilities		96,412		31,237		94,738		(109,928	)		112,459
Long-term debt, net of current maturities		430,238		19,941		25,027		—			475,206
Note payable to affiliate		—		—		4,415		(4,415	)		—
Other long-term liabilities		—		—		9,308		—			9,308

Total liabilities		526,650		51,178		133,488		(114,343	)		596,973

Commitments and Contingencies

Stockholders’ Equity
Preferred Stock		34,183		—		—		—			34,183
Common stock		714		3,526		42,963		(46,489	)		714
Capital in excess of par value		422,823		570,512		137,439		(707,951	)		422,823
Retained earnings		25,927		120,202		67,736		(187,938	)		25,927

Total stockholders’ equity		483,647		694,240		248,138		(942,378	)		483,647


Total liabilities and stock holders’ equity	$	1,010,297	$	745,418	$	381,626	$	(1,056,721	)	$	1,080,620

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

NOTE 11 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended June 30, 2009 (unaudited)


	Allis-Chalmers
	(Parent/			Subsidiary			Subsidiary			Consolidating
	Guarantor)			Guarantors			Non-Guarantors			Adjustments			Consolidated Total
Revenues	$	—		$	44,738		$	68,384		$	(617	)	$	112,505

Operating costs and expenses
Direct costs		—			30,948			56,908			(617	)		87,239
Depreciation		—			13,913			5,268			—			19,181
Selling, general and administrative		1,044			10,788			3,693			—			15,525
Loss on asset disposition		—			—			1,916			—			1,916
Amortization		11			981			195			—			1,187

Total operating costs and expenses		1,055			56,630			67,980			(617	)		125,048

Income (loss) from operations		(1,055	)		(11,892	)		404			—			(12,543	)

Other income (expense):
Equity earnings in affiliates, net of tax		(13,212	)		—			—			13,212			—
Interest, net		(12,202	)		(13	)		(997	)		—			(13,212	)
Gain on debt extinguishment		26,365			—			—			—			26,365
Other		14			(75	)		(424	)		—			(485	)

Total other income (expense)		965			(88	)		(1,421	)		13,212			12,668


Net income (loss) before income taxes		(90	)		(11,980	)		(1,017	)		13,212			125

Provision for income taxes		—			(258	)		43			—			(215	)


Net income (loss)		(90	)		(12,238	)		(974	)		13,212			(90	)

Preferred stock dividend		(35	)		—			—			—			(35	)


Net income (loss) attributed to common stockholders	$	(125	)	$	(12,238	)	$	(974	)	$	13,212		$	(125	)

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

NOTE 11 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Six Months Ended June 30, 2009 (unaudited)


	Allis-Chalmers						Subsidiary
	(Parent/			Subsidiary			Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors			Adjustments			Total
Revenues	$	—		$	110,705		$	148,173		$	(1,270	)	$	257,608

Operating costs and expenses
Direct costs		—			72,243			119,400			(1,270	)		190,373
Depreciation		—			28,222			10,330			—			38,552
Selling, general and administrative		1,986			19,956			7,223			—			29,165
Loss on asset disposition		—			—			1,916			—			1,916
Amortization		23			1,961			390			—			2,374

Total operating costs and expenses		2,009			122,382			139,259			(1,270	)		262,380

Income (loss) from operations		(2,009	)		(11,677	)		8,914			—			(4,772	)

Other income (expense):
Equity earnings in affiliates, net of tax		(2,600	)		—			—			2,600			—
Interest, net		(24,486	)		(21	)		(2,207	)		—			(26,714	)
Gain on debt extinguishment		26,365			—			—			—			26,365
Other		35			(106	)		(197	)		—			(268	)

Total other income (expense)		(686	)		(127	)		(2,404	)		2,600			(617	)


Net income (loss) before income taxes		(2,695	)		(11,804	)		6,510			2,600			(5,389	)

Provision for income taxes		—			4,046			(1,352	)		—			2,694


Net income (loss)		(2,695	)		(7,758	)		5,158			2,600			(2,695	)

Preferred stock dividend		(35	)		—			—			—			(35	)


Net income (loss) attributed to common stockholders	$	(2,730	)	$	(7,758	)	$	5,158		$	2,600		$	(2,730	)

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

NOTE 11 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Six Months Ended June 30, 2009 (unaudited)


	Allis-						Other
	Chalmers						Subsidiaries
	(Parent/			Subsidiary			(Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors)			Adjustments			Total
Cash Flows from Operating Activities:
Net income (loss)	$	(2,695	)	$	(7,758	)	$	5,158		$	2,600		$	(2,695	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		23			30,183			10,720			—			40,926
Amortization and write-off of debt issuance costs		1,149			2			—			—			1,151
Stock based compensation		2,345			—			—			—			2,345
Allowance for bad debts		—			3,565			—			—			3,565
Equity earnings in affiliates		2,600			—			—			(2,600	)		—
Deferred taxes		(4,783	)		1			(1,306	)		—			(6,088	)
(Gain) on sale of equipment		—			(543	)		(59	)		—			(602	)
Loss on asset disposition		—			—			1,916			—			1,916
Gain on debt extinguishment		(26,365	)		—			—			—			(26,365	)
Changes in operating assets and liabilities:
Decrease in trade receivables		—			37,911			17,368			—			55,279
Decrease in inventories		—			631			1,895			—			2,526
(Increase) decrease in prepaid expenses and other current assets		7,520			2,422			(2,531	)		—			7,411
(Increase) decrease in other assets		(34	)		(902	)		2,056			—			1,120
(Decrease) in trade accounts payable		—			(13,747	)		(13,423	)		—			(27,170	)
(Decrease) increase in accrued interest		(2,831	)		243			(366	)		—			(2,954	)
(Decrease) increase in accrued expenses		3,951			(6,410	)		(3,301	)		—			(5,760	)
(Decrease) increase in accrued salaries, benefits and payroll taxes		—			(1,797	)		761			—			(1,036	)
(Decrease) in other long- term liabilities		—			(38	)		(567	)		—			(605	)

Net Cash Provided By (Used In) Operating Activities		(19,120	)		43,763			18,321			—			42,964


Cash Flows from Investing Activities:
Investment in affiliates		(3,500	)		—			—			3,500			—
Deposits on asset commitments		—			10,616			(584	)		—			10,032
Proceeds from sale of property and equipment		—			6,634			59			—			6,693
Purchase of property and equipment		—			(49,089	)		(8,904	)		—			(57,993	)

Net Cash Used in Investing Activities		(3,500	)		(31,839	)		(9,429	)		3,500			(41,268	)

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

NOTE 11 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Six Months Ended June 30, 2009 (unaudited)


							Other
	Allis-Chalmers						Subsidiaries
	(Parent/			Subsidiary			(Non-			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors)			Adjustments			Total
Cash Flows from Financing Activities:
Accounts receivable from affiliates		—			13,615			—			(13,615	)		—
Accounts payable to affiliates		(13,591	)		—			(24	)		13,615			—
Proceeds from parent contributions		—			—			3,500			(3,500	)		—
Proceeds from issuance of stock, net		120,337			—			—			—			120,337
Proceeds from long-term debt		—			25,000			—			—			25,000
Net repayment under line of credit		(36,500	)		—			—			—			(36,500	)
Payments on long-term debt		(47,135	)		(1,380	)		(8,881	)		—			(57,396	)
Debt issuance costs		(491	)		(153	)		—			—			(644	)

Net Cash Provided By (Used In) Financing Activities		22,620			37,082			(5,405	)		(3,500	)		50,797


Net change in cash and cash equivalents		—			49,006			3,487			—			52,493
Cash and cash equivalents at beginning of period		—			2,923			3,943			—			6,866

Cash and cash equivalents at end of period	$	—		$	51,929		$	7,430		$	—		$	59,359

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

NOTE 12- SEGMENT INFORMATION

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


	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Revenues:
Oilfield Services	$	49,730		$	29,473		$	89,365		$	73,923
Drilling and Completion		95,977			67,792			184,477			146,938
Rental Services		12,937			15,240			25,172			36,747

	$	158,644		$	112,505		$	299,014		$	257,608


Operating Income (Loss):
Oilfield Services	$	2,055		$	(10,277	)	$	507		$	(11,490	)
Drilling and Completion		7,053			403			12,515			8,912
Rental Services		(831	)		588			(1,741	)		4,536
General corporate		(4,143	)		(3,257	)		(7,899	)		(6,730	)

	$	4,134		$	(12,543	)	$	3,382		$	(4,772	)


Depreciation and Amortization:
Oilfield Services	$	7,883		$	7,433		$	15,697		$	14,748
Drilling and Completion		6,498			5,463			12,826			10,720
Rental Services		7,226			7,395			14,364			15,299
General corporate		66			77			130			159

	$	21,673		$	20,368		$	43,017		$	40,926


Capital Expenditures:
Oilfield Services	$	6,968		$	4,028		$	11,031		$	8,060
Drilling and Completion		6,100			39,069			11,841			43,708
Rental Services		5,851			935			7,752			6,191
General corporate		312			3			365			34

	$	19,231		$	44,035		$	30,989		$	57,993


Revenues:
United States	$	59,795		$	40,622		$	106,923		$	102,823
Argentina		76,640			52,871			149,025			115,654
Brazil		10,502			10,012			20,002			20,778
Other international		11,707			9,000			23,064			18,353

	$	158,644		$	112,505		$	299,014		$	257,608

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

NOTE 12 — SEGMENT INFORMATION (Continued)


	As of
	June 30,		December 31,
	2010		2009
Goodwill:
Oilfield Services	$	23,250	$	23,250
Drilling and Completion		17,389		17,389
Rental Services		—		—

	$	40,639	$	40,639


Assets:
Oilfield Services	$	252,875	$	255,899
Drilling and Completion		464,479		441,482
Rental Services		299,945		307,283
General corporate		63,275		75,956

	$	1,080,574	$	1,080,620


Long Lived Assets:
United States	$	569,943	$	572,727
Argentina		164,842		168,681
Brazil		86,223		82,477
Other international		63,779		58,487

	$	884,787	$	882,372

NOTE 13 — LEGAL MATTERS

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

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

NOTE 14– SUBSEQUENT EVENTS

On July 12, 2010, we acquired 100% of the outstanding stock of American Well Control, Inc., or AWC, for a total consideration of approximately $19.5 million in cash and 1.0 million shares of our common stock. AWC is based in Conroe, Texas and is a leading manufacturer of premium high pressure valves used in hydraulic fracturing in the unconventional gas shale plays. The acquisition was funded from available cash and borrowings under our line of credit.

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 36.

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, Arkansas, Pennsylvania, Oklahoma, New Mexico, offshore in the Gulf of Mexico and internationally primarily in Argentina, Brazil, Bolivia and Mexico. We currently operate in three sectors of the oil and natural gas service industry: Oilfield Services; Drilling and Completion and Rental Services.

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

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

Our Industry

The oilfield services industry is highly cyclical. Demand for our products and services is substantially dependent upon activity levels in the oil and natural gas industry, particularly our customers’ willingness to spend capital on the exploration for and development of oil and natural gas reserves. The most critical factor in assessing the outlook for the industry is the worldwide supply and demand for oil and the domestic supply and demand for natural gas. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices. As a result, demand for our products and services are highly sensitive to current and expected oil and natural gas prices. Other factors that can affect our business and financial results include the general global economic environment and regulatory changes in the United States and internationally.

Company Outlook

Throughout the first half of 2009, we saw a significant decline in the global economy which led to reduced activity in the energy sector. Although there have been some indicators that suggest that economic improvement is underway, there remains a general weakness in the equity and credit capital markets that continues to generate a certain degree of uncertainty regarding the overall outlook of the global economy. Economic activity, generally, and exploration and development activities, specifically, have not returned to peak 2008 levels. Certain of our businesses continue to be negatively impacted by excess equipment and service capacity. However, our total revenues have increased sequentially in each of the past four quarters and in the first half of 2010 we saw increases in revenues in each of our business segments.

We believe that our revenue and operating income for our Oilfield Services and Drilling and Completion segments will continue to improve in 2010. Our Oilfield Services segment is heavily based on oil and natural gas activity in the U.S. and a good indicator of that activity is the U.S. rig count. The Baker Hughes rig count in the U.S. for the first thirty weeks of 2010 increased to an average of 1,453 compared to an average of 1,111 for the first thirty weeks of 2009. This favorable trend in rig count is resulting in improved demand and pricing for our Oilfield Services segment. We anticipate our Drilling and Completion segment will exceed 2009 results for both revenue and operating income as drilling activity in Argentina has improved with all of our available rigs in Argentina and Bolivia being utilized. Our Drilling and Completion segment currently operates in Argentina, Brazil and Bolivia. Currently, we have no firm commitments of work for four drilling rigs that are currently under construction or refurbishment, so the impact of revenue and operating income from these rigs may have a negative impact on our Drilling and Completion segment’s operating results.

In addition to the drilling moratorium, the DOI issued a directive calling for additional safety and performance standards as well as rigorous monitoring and testing requirements. Prior to these events, we embarked on an aggressive plan at the end of 2009 to certify and recertify our existing inventory of blow out preventors and components. We are monitoring legislative and regulatory developments; however, the full legislative and regulatory response to the oil spill is not yet known and an expansion of safety and performance regulations or an increase in liability for drilling activities may have a negative impact on our operating results.

The Baker Hughes average rig count in the Gulf of Mexico for the first thirty weeks of 2010 decreased to 38 rigs compared to an average of 50 rigs for the first thirty weeks of 2009. As of July 30, 2010, the Baker Hughes rig count in the Gulf of Mexico was 16 as a result of the effects of the oil spill in the Gulf of Mexico. Our Rental Services segment has historically been very dependent on drilling activity in the Gulf of Mexico. Due to the decline in drilling activity in the Gulf of Mexico since the hurricanes in 2007, we had already begun to shift our focus to serving the onshore unconventional gas markets and redeploying rental equipment to the international markets such as Brazil, Saudi Arabia and Egypt. We believe this strategy will partially offset the impact of decreased activity in the Gulf of Mexico on our Rental Services segment, but we anticipate that revenues and operating income for our Rental Services segment will be below 2009 levels.

Our general and administrative expenses in 2010 are less than 2009 levels primarily due to the six months ended June 30, 2009 including $3.6 million in bad debt expense compared to no bad debt expense in the six months ended June 30, 2010. We expect our general and administrative expenses for the second half of 2010 to remain consistent with results for the first six months of 2010.

Our net interest expense is dependent upon our level of debt and cash on hand, which are principally dependent on acquisitions we complete, our capital expenditures and our cash flows from operations. Due to the shortage of liquidity and credit in the U.S. financial markets, we may see an increase in our effective interest rate in 2010. We do not anticipate the ability to record a gain on debt extinguishment in 2010 as our senior notes are trading close to face value.

As our profitability continues to improve, we anticipate our effective tax rate to be greater than the effective tax rate of our tax benefit from losses generated in the first half of 2010. The effective rate is impacted by the profitability and effective income tax rate of our operations in foreign jurisdictions which are effected by withholding taxes in excess of statutory income tax rates.

Our operating income is principally dependent on our level of revenues and the pricing environment of our services. In addition, demand for our services is dependent upon our customers’ capital spending plans, which are largely driven by current commodity prices and their expectations of future commodity prices.

Although 2010 has been a challenging year for our operations, increased rig count has increased the utilization and pricing for our equipment and services. We believe our cost cuts in 2009, our strategy of international growth and our commitment to offer new equipment and technology to our customers and our focus on the U.S. land shale plays, will continue to result in improve our operating results for the remainder of 2010.

Comparison of Three Months Ended June 30, 2010 and 2009

Our revenues for the three months ended June 30, 2010 were $158.6 million, an increase of 41.0% compared to $112.5 million for the three months ended June 30, 2009. The increase in revenues is due to the increase in revenues in our Drilling and Completion and Oilfield Services segments, offset in part by a decrease in revenues in our Rental Services segment. The increase in revenues in our Drilling and Completion segment was due to increased utilization and rig rates in Argentina and Bolivia. The Drilling and Completion segment generated $96.0 million in revenues for the three months ended June 30, 2010 compared to $67.8 million for the three months ended June 30, 2009. Our Oilfield Services segment revenues increased to $49.7 million for the three months ended June 30, 2010 compared to $29.5 million for the three months ended June 30, 2009 due to increased utilization of our equipment and improved pricing compared to the three months ended June 30, 2009. Revenues for our Rental Services segment decreased to $12.9 million for the three months ended June 30, 2010 compared to $15.2 million for the three months ended June 30, 2009 due to decreased equipment utilization due to a decline in drilling activity in the U.S. Gulf of Mexico compared to the three months ended June 30, 2009

Our direct costs for the three months ended June 30, 2010 increased 38.4% to $120.7 million, or 76.1% of revenues, compared to $87.2 million, or 77.5%, of revenues for the three months ended June 30, 2009. Our direct costs in all of our segments increased in absolute dollars in the three months ended June 30, 2010 compared to the three months ended June 30, 2009. Our Oilfield Services segment revenues for the three months ended June 30, 2010 increased 68.7% from revenues for the three months ended June 30, 2009, while the direct costs increased 40.7% over that same period, resulting in an improvement in gross margin as a percentage of revenues to 26.4% for the three months ended June 30, 2010 compared to 11.8% for the three months ended June 30, 2009. Our Oilfield Services segment began to realize some price increases starting in the later part of the first quarter of 2010. In addition, we had $868,000 of expenses recorded during the three months ended June 30, 2009 related to severance payments, the closing of unprofitable locations and downsizing other locations. Our Drilling and Completion segment revenues for the three months ended June 30, 2010 increased 41.6% from revenues for the three months ended June 30, 2009, while the direct costs increased 40.0% over that same period, resulting in an improvement in gross margin as a percentage of revenues to 17.9% for the three months ended June 30, 2010 compared to 16.9% for the three months ended June 30, 2009. Part of the improvement in gross margin for our Drilling and Completion segment can be attributed to $329,000 of costs incurred during the three months ended June 30, 2009 to consolidate operating locations. Our Rental Services segment revenues for the three months ended June 30, 2010 decreased 15.1% from revenues for the three months ended June 30, 2009, while the direct costs increased 8.0% over that same period. Direct costs for the three months ended June 30, 2009 for our Rental Services segment included $235,000 to close a rental yard and to reduce our workforce. Our direct costs for the Rental Services segment are largely fixed because they primarily relate to yard expenses to maintain the rental inventory. In addition, we realize lower margins on revenues from land drilling utilization of our equipment as compared to revenues generated in the Gulf of Mexico as the average term of deployment of the assets is greater when utilized offshore and requires less handling.

Depreciation expense increased 7.0% to $20.5 million for the three months ended June 30, 2010 from $19.2 million for the three months ended June 30, 2009. The increase in depreciation expense is primarily due to our capital expenditure programs for our Drilling and Completion segment. Depreciation expense as a percentage of revenues decreased to 12.9% for the second quarter of 2010, compared to 17.0% for the second quarter of 2009, due to the increase in revenues from our Drilling and Completion and Oilfield Services segments.

Selling, general and administrative expense was $12.1 million for the three months ended June 30, 2010 compared to $15.5 million for the three months ended June 30, 2009. Selling, general and administrative expense decreased primarily due to a reduction of $3.2 million in bad debt expense from the three months ended June 30, 2009 offset by an increase related to the amortization of share-based compensation arrangements. Selling, general and administrative expense includes share-based compensation expense of $1.6 million in the second quarter of 2010 and $1.3 million in the second quarter of 2009. As a percentage of revenues, selling, general and administrative expenses were 7.6% for the three months ended June 30, 2010 compared to 13.8% for the same period in the prior year.

During the three months ended June 30, 2009, we recorded a $1.9 million loss on an asset disposition from the total loss of a rig from a blowout in our Drilling and Completion segment. The anticipated insurance proceeds for the loss were not sufficient to cover the book value of the rig and related assets.

We had $4.1 million in income from operations for the three months ended June 30, 2010, compared to a $12.5 million loss from operations for the three months ended June 30, 2009, for a total increase of $16.7 million. The income from operations in the second quarter of 2010 is due to the improvement in the performance of our Drilling and Completion and Oilfield Services segments. The three months ended June 30, 2009 was negatively affected by an additional $3.2 million of bad debt expense, a $1.9 million loss on an asset disposition and $1.6 million of restructuring costs.

Our interest expense was $11.1 million for the three months ended June 30, 2010, compared to $13.2 million for the three months ended June 30, 2009. On June 29, 2009, we purchased $74.8 million of our senior notes with $125.6 million in proceeds from our backstopped common stock rights offering and preferred stock private placement. On June 29, 2009, we also prepaid our outstanding loan balance under our revolving credit facility of $35.0 million from those same equity proceeds. Interest expense includes amortization expense of deferred financing costs of $554,000 and $596,000 for the three months ended June 30, 2010 and 2009, respectively.

During the three months ended June 30, 2009, we recorded a gain of $26.4 million as a result of a tender offer that we completed on June 29, 2009. We purchased $30.6 million aggregate principal of our 9.0% senior notes and $44.2 million aggregate principal of 8.5% senior notes for approximately $46.4 million. The gain is net of a $1.5 million write-off of debt issuance costs related to the retired notes and we incurred approximately $466,000 in expenses related to the transactions.

Our income tax benefit for the three months ended June 30, 2010 was $1.6 million, or 23.4% of our net loss before income taxes, compared to an income tax expense of $215,000 for the three months ended June 30, 2009. The difference between the actual and expected income tax benefit as a percentage of our net loss was due to an increase in withholding taxes from foreign operations as a percentage of pre-tax income in the second quarter of 2010. The consolidated effective income tax rate, or income tax benefit rate, is impacted by the profitability and effective income tax rate of our operations in foreign jurisdictions.

We had a net loss of $5.4 million for the three months ended June 30, 2010, compared to net loss of $90,000 for the three months ended June 30, 2009 due to the foregoing reasons.

The net loss attributed to common stockholders for the three months ended June 30, 2010 and 2009 was $6.0 million and $125,000, respectively, after $637,000 and $35,000 in preferred stock dividends, respectively. The preferred stock dividend relates to 36,393 shares of $1,000 par value preferred shares at 7.0%. The preferred stock was issued at the end of June 2009.

The following table compares revenues and income (loss) from operations for each of our business segments for the quarter ended June 30, 2010 and 2009. Income (loss) from operations consists of our revenues and the loss on an asset disposition less direct costs, selling, general and administrative expenses, depreciation and amortization:


	Revenues							Income (Loss) from Operations
	Three Months Ended										Three Months Ended
			June 30,								June 30,
	2010		2009		Change			2010			2009			Change
					(in thousands)
Oilfield Services	$	49,730	$	29,473	$	20,257		$	2,055		$	(10,277	)	$	12,332
Drilling and Completion		95,977		67,792		28,185			7,053			403			6,650
Rental Services		12,937		15,240		(2,303	)		(831	)		588			(1,419	)
General corporate		—		—		—			(4,143	)		(3,257	)		(886	)


Total	$	158,644	$	112,505	$	46,139		$	4,134		$	(12,543	)	$	16,677

Oilfield Services

Revenues for our Oilfield Services segment were $49.7 million for the three months ended June 30, 2010, an increase of 68.7% compared to $29.5 million in revenues for the three months ended June 30, 2009. Income from operations increased $12.3 million and resulted in income from operations of $2.1 million in the second quarter of 2010 compared to a loss from operations of $10.3 million in the second quarter of 2009. Our Oilfield Services segment revenues and operating income for the second quarter of 2010 increased compared to the second quarter of 2009 due to increased drilling activity in the U.S. which resulted in increased demand and improved pricing for our services. During the three months ended June 30, 2009, we incurred $868,000 of costs related to closing unprofitable locations and downsizing other locations in our Oilfield Services segment. In addition, we recorded bad debt expense of $2.4 million for the Oilfield Services segment during the three months ended June 30, 2009 as a result of the decreased oil and natural gas prices and the financial difficulties that some of our customers faced in 2009, compared to no bad debt expense for the three months ended June 30, 2010.

Drilling and Completion

Revenues for the quarter ended June 30, 2010 for the Drilling and Completion segment were $96.0 million, an increase of 41.6% compared to $67.8 million in revenues for the quarter ended June 30, 2009. Income from operations increased to $7.1 million in the second quarter of 2010 compared to $403,000 in the second quarter of 2009. This increase was due to: (1) improved rig utilization and rig rates in Argentina and Bolivia during the three months ended June 30, 2010; (2) a $1.9 million non-cash loss recorded in the three months ended June 30, 2009 on an asset disposition from the total loss of a rig from a blow-out; and (3) $329,000 of costs incurred to consolidate operating locations in Brazil during the three months ended June 30, 2009. Partially offsetting the improved results in the second quarter of 2010 was decreased rig utilization and pricing in Brazil during the three months ended June 30, 2010 and an increase in depreciation and amortization expense of $1.0 million. The increase in depreciation and amortization was the result of our capital expenditures.

Rental Services

Revenues for the quarter ended June 30, 2010 for the Rental Services segment were $12.9 million, a decrease from $15.2 million in revenues for the quarter ended June 30, 2009. Our Rental Services segment generated an operating loss of $0.8 million in the second quarter of 2010 compared to $588,000 of operating income in the second quarter of 2009. The decrease in revenues and operating income for the second quarter of 2010 compared to the prior year is due primarily to the decrease in utilization of our rental equipment due to a decline in drilling activity in the U.S. Gulf of Mexico. Our income from operations in the second quarter of 2009 included $800,000 of bad debt expense to increase the bad debt reserve for Rental Services segment customers who were facing financial difficulties, and $235,000 of costs related to closing a rental yard and reducing our workforce. We recorded no bad debt expense for the second quarter of 2010.

General Corporate

General corporate operating loss increased $0.9 million to $4.1 million for the three months ended June 30, 2010 compared to $3.3 million for the three months ended June 30, 2009. The increase was due to an increase in share-based compensation expense as well as increased travel and insurance expenses to support our international business development initiatives. Share-based compensation expense included in general corporate expense was $1.2 million in the second quarter of 2010 compared to $1.0 million in the second quarter of 2009.

Comparison of Six Months Ended June 30, 2010 and 2009

Our revenues for the six months ended June 30, 2010 were $299.0 million, an increase of 16.1% compared to $257.6 million for the six months ended June 30, 2009. The increase in revenues is due to the increase in revenues in our Drilling and Completion and Oilfield Services segments, offset in part by a decrease in revenues in our Rental Services segment. The increase in revenues in our Drilling and Completion segment was due to increased utilization and rig rates in Argentina and Bolivia. The Drilling and Completion segment generated $184.5 million in revenues for the six months ended June 30, 2010 compared to $146.9 million for the six months ended June 30, 2009. Our Oilfield Services segment revenues increased to $89.4 million for the six months ended June 30, 2010 compared to $73.9 million for the six months ended June 30, 2009 due to increased utilization of our equipment and improved pricing compared to the six months ended June 30, 2009. Revenues for our Rental Services segment decreased to $25.2 million for the six months ended June 30, 2010 compared to $36.7 million for the six months ended June 30, 2009 due to decreased equipment utilization due to a decline in drilling activity in the U.S. Gulf of Mexico compared to the six months ended June 30, 2009.

Our direct costs for the six months ended June 30, 2010 increased 20.0% to $228.4 million, or 76.4% of revenues, compared to $190.4 million, or 73.9%, of revenues for the six months ended June 30, 2009. Our direct costs in our Oilfield Services and Drilling and Completion segments increased in absolute dollars in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, but our direct costs for our Rental Services segment decreased over that same period. Our Oilfield Services segment revenues for the six months ended June 30, 2010 increased 20.9% from revenues for the six months ended June 30, 2009, while the direct costs increased 11.6% over that same period, resulting in an improvement in gross margin as a percentage of revenues to 25.6% for the six months ended June 30, 2010 compared to 19.3% for the six months ended June 30, 2009. Our Oilfield Services segment began to realize some price increases starting in the later part of the first quarter of 2010. In addition, we had $1.0 million of expenses recorded during the six months ended June 30, 2009 related to severance payments, the closing of unprofitable locations and downsizing other locations. Our Drilling and Completion segment revenues for the six months ended June 30, 2010 increased 25.5% from revenues for the six months ended June 30, 2009, while the direct costs increased 28.5% over that same period. As a result, direct costs as a percentage of revenues increased to 82.3% for the six months ended June 30, 2010 compared to 80.4% for the six months ended June 30, 2009. Our Rental Services segment revenues for the six months ended June 30, 2010 decreased 31.5% from revenues for the six months ended June 30, 2009, while the direct costs decreased 19.9% over that same period. Our direct costs for the Rental Services segment are largely fixed because they primarily relate to yard expenses to maintain the rental inventory. In addition, we realize lower margins on revenues from land drilling utilization of our equipment as compared to revenues generated in the Gulf of Mexico as the average term of deployment of the assets is greater when utilized offshore and requires less handling.

Depreciation expense increased 5.6% to $40.7 million for the six months ended June 30, 2010 from $38.6 million for the six months ended June 30, 2009. The increase in depreciation expense is primarily due to our capital expenditure programs for our Drilling and Completion segment. Depreciation expense as a percentage of revenues decreased to 13.6% for the first six months of 2010, compared to 15.0% for the first six months of 2009, due to the increase in revenues.

Selling, general and administrative expense was $24.2 million for the six months ended June 30, 2010 compared to $29.2 million for the six months ended June 30, 2009. Selling, general and administrative expense decreased primarily due to a reduction in bad debt expense for the six months ended June 30, 2010 compared to the six months ended June 30, 2009 and cost reduction steps that were made in the six months ended June 30, 2009 in response to market conditions, offset in part by an increase in the amortization of share-based compensation arrangements. During the six months ended June 30, 2009, we recorded bad debt expense of $3.6 million compared to no bad debt expense for the six months ended June 30, 2010. Selling, general and administrative expense includes share-based compensation expense of $3.0 million in the six months ended June 30, 2010 and $2.3 million in the six months ended June 30, 2009. As a percentage of revenues, selling, general and administrative expenses were 8.1% for the six months ended June 30, 2010 compared to 11.3% for the same period in the prior year.

During the six months ended June 30, 2009, we recorded a $1.9 million loss on an asset disposition from the total loss of a rig from a blow-out in our Drilling and Completion segment. The anticipated insurance proceeds for the loss were not sufficient to cover the book value of the rig and related assets.

We had income from operations of $3.4 million for the six months ended June 30, 2010, compared to a $4.8 million loss from operations for the six months ended June 30, 2009, for a total increase of $8.2 million. The increase in income from operations for the six months ended June 30, 2010 is due to the improved performance of our Oilfield Services and Drilling and Completion segments. The six months ended June 30, 2009 was also negatively affected by an additional $3.6 million of bad debt expense, a $1.9 million loss on an asset disposition and $1.8 million of restructuring costs.

Our interest expense was $22.1 million for the six months ended June 30, 2010, compared to $26.7 million for the six months ended June 30, 2009. On June 29, 2009, we purchased $74.8 million of our senior notes with $125.6 million in proceeds from our backstopped common stock rights offering and preferred stock private placement. On June 29, 2009, we also prepaid our outstanding loan balance under our revolving credit facility of $35.0 million from those same equity proceeds. Interest expense includes amortization expense of deferred financing costs of $1.1 million and $1.2 million for the six months ended June 30, 2010 and 2009, respectively.

During the six months ended June 30, 2009, we recorded a gain of $26.4 million as a result of a tender offer that we completed on June 29, 2009. We purchased $30.6 million aggregate principal of our 9.0% senior notes and $44.2 million aggregate principal of 8.5% senior notes for approximately $46.4 million. The gain is net of a $1.5 million write-off of debt issuance costs related to the retired notes and we incurred approximately $466,000 in expenses related to the transactions.

Our income tax benefit for the six months ended June 30, 2010 was $5.2 million, or 25.8% of our net loss before income taxes, compared to an income tax benefit of $2.7 million, or 50.0% of our net loss before income taxes for the six months ended June 30, 2009. The decrease in income tax benefit as a percentage of our net loss was due to an increase in withholding taxes from foreign operations as a percentage of pre-tax income in the first half of 2010. The consolidated effective income tax benefit rate is impacted by the profitability and effective income tax rate of our operations in foreign jurisdictions.

We had a net loss of $14.9 million for the six months ended June 30, 2010, compared to net loss of $2.7 million for the six months ended June 30, 2009 due to the foregoing reasons.

The net loss attributed to common stockholders for the six months ended June 30, 2010 and 2009 was $16.2 million and $2.7 million, respectively, after $1.3 million and $35,000 in preferred stock dividends, respectively. The preferred stock dividend relates to 36,393 shares of $1,000 par value preferred shares at 7.0%. The preferred stock was issued at the end of June 2009.

The following table compares revenues and income (loss) from operations for each of our business segments for the six months ended June 30, 2010 and 2009. Income (loss) from operations consists of our revenues and the loss on an asset disposition less direct costs, selling, general and administrative expenses, depreciation and amortization:


	Revenues							Income (Loss) from Operations
	Six Months Ended							Six Months Ended
			June 30,								June 30,
	2010		2009		Change			2010			2009			Change
					(in thousands)
Oilfield Services	$	89,365	$	73,923	$	15,442		$	507		$	(11,490	)	$	11,997
Drilling and Completion		184,477		146,938		37,539			12,515			8,912			3,603
Rental Services		25,172		36,747		(11,575	)		(1,741	)		4,536			(6,277	)
General corporate		—		—		—			(7,899	)		(6,730	)		(1,169	)


Total	$	299,014	$	257,608	$	41,406		$	3,382		$	(4,772	)	$	8,154

Oilfield Services

Revenues for our Oilfield Services segment were $89.4 million for the six months ended June 30, 2010, an increase of 20.9% compared to $73.9 million in revenues for the six months ended June 30, 2009. Income from operations increased $12.0 million and resulted in income from operations of $507,000 in the first six months of 2010 compared to a loss from operations of $11.5 million in the first six months of 2009. Our Oilfield Services segment revenues and operating income for the six months ended June 30, 2010 increased compared to the six months ended June 30, 2009 due to improved drilling activity in the U.S. that resulted in increased demand and pricing for our services. During the six months ended June 30, 2009, we incurred $1.0 million of costs related to closing unprofitable locations and downsizing other locations in our Oilfield Services segment. In addition, we increased our bad debt reserve by recording $2.6 million of bad debt expense for the Oilfield Services segment during the six months ended June 30, 2009 as a result of the decreased oil and natural gas prices and the financial difficulties that some of our customers are facing. We recorded no bad debt expense for the six months ended June 30, 2010 for the Oilfield Services segment.

Drilling and Completion

Revenues for the six months ended June 30, 2010 for the Drilling and Completion segment were $184.5 million, an increase of 25.5% compared to $146.9 million in revenues for the six months ended June 30, 2009. Income from operations increased to $12.5 million in the first six months of 2010 compared to $8.9 million for the first six months of 2009. This increase was due to: (1) improved rig utilization and rig rates in Argentina and Bolivia during the six months ended June 30, 2010; (2) a $1.9 million non-cash loss recorded in the six months ended June 30, 2009 on an asset disposition from the total loss of a rig from a blow-out; and (3) $329,000 of costs incurred to consolidate operating locations in Brazil during the six months ended June 30, 2009. Partially offsetting the improved results in the first six months of 2010 was decreased rig utilization and pricing in Brazil during the six months ended June 30, 2010 and an increase in depreciation and amortization expense of $2.1 million. The increase in depreciation and amortization was the result of our capital expenditures.

Rental Services

Revenues for the six months ended June 30, 2010 for the Rental Services segment were $25.2 million, a decrease from $36.7 million in revenues for the six months ended June 30, 2009. Our Rental Services segment generated an operating loss of $1.7 million in the six months ended June 30, 2010 compared to $4.5 million operating income for the first six months of 2009. The decrease in segment revenues and operating income for the second quarter of 2010 compared to the prior year’s was due primarily to the decrease in utilization of our rental equipment due to a decline in drilling activity in the U.S. Gulf of Mexico. Our income from operations in the second quarter of 2009 even included $950,000 of bad debt expense to increase the bad debt reserve for Rental Services segment customers who were facing financial difficulties, and $237,000 of costs related to closing a rental yard and reducing our workforce. We recorded no bad debt expense for the first half of 2010. In addition, depreciation and amortization expense for our Rental Services segment decreased $935,000 or 6.1%, in the first six months of 2010 compared to the first six months of 2009 due primarily to a $584,000 reduction in the carrying value of our airplane resulting from the sales proceeds received in April 2009.

General Corporate

General corporate operating loss increased $1.2 million to $7.9 million for the six months ended June 30, 2010 compared to $6.7 million for the six months ended June 30, 2009. The increase was due to the increase in share-based compensation expense and increased insurance and travel costs to support our international business development initiatives. Share-based compensation expense included in general corporate was $2.3 million in the six months ended June 30, 2010 compared to $1.8 million in the six months ended June 30, 2009.

Liquidity

In June 2009, we strengthened our balance sheet by raising approximately $125.6 million in gross proceeds from the sale of common stock and a newly issued series of preferred stock. The transactions were effected through a common stock rights offering to our existing stockholders, the sale of common stock to Lime Rock Partners V, L.P., or Lime Rock, through its backstop commitment of the rights offering, and the sale of convertible perpetual preferred stock to Lime Rock. Approximately $46.4 million of the proceeds were used to purchase an aggregate of $74.8 million principal amount of our existing senior notes, approximately $35.0 million was used to repay all the borrowings under our revolving bank credit facility due 2012, except for $5.1 million in outstanding letters of credit, and we used the remainder for general corporate purposes.

Our on-going capital requirements arise primarily from our need to service our debt, to acquire and maintain equipment, to fund our working capital requirements and to complete acquisitions. Our primary sources of liquidity are proceeds from the issuance of debt and equity securities and cash flows from operations. Our amended and restated revolving credit facility permits borrowings of up to $90.0 million in principal amount. As of June 30, 2010, we had $85.8 million available for borrowing under our amended and restated revolving credit facility. Our cash on hand, cash flows from operations and revolving credit facility are expected to be our primary source of liquidity in fiscal 2010. We had cash and cash equivalents of $17.6 million at June 30, 2010 compared to $41.1 million at December 31, 2009.

Our revolving credit agreement requires us to maintain specified financial ratios. If we fail to comply with the financial ratio covenants, it could limit or eliminate the availability under our revolving credit agreement. Our ability to maintain such financial ratios may be affected by events beyond our control, including changes in general economic and business conditions, and we cannot assure you that we will maintain or meet such ratios and tests or that the lenders under the credit agreement will waive any failure to meet such ratios or tests.

Operating Activities

During the six months ended June 30, 2010, our operating activities provided $21.5 million in cash. Our net loss for the six months ended June 30, 2010 was $14.9 million. Non-cash expenses totaled $38.8 million during the first six months of 2010 consisting of $43.0 million of depreciation and amortization, $3.0 million for share based compensation expense, $1.1 million in amortization of debt issuance costs, $1.5 million loss on the sale of an investment, $0.8 million of losses from asset disposals, $260,000 equity in loss of unconsolidated affiliates, partly offset by deferred income tax benefit of $10.8 million related to timing differences.

During the six months ended June 30, 2010, changes in operating assets and liabilities used $2.4 million in cash, principally due to an increase in accounts receivable of $25.8 million, an increase in inventory of $2.4 million and a decrease in other long-term liabilities of $466,000, offset in part by an increase in accounts payable of $10.8 million, a decrease in prepaid expenses and other current assets of $8.8 million, an increase in accrued expenses of $3.8 million, an increase in accrued salaries, benefits and payroll taxes of $1.9 million and a decrease in other assets of $0.8 million. Accounts receivable, inventory, accounts payable, accrued expenses and accrued salaries, benefits and payroll taxes increased primarily due to the increase in our activity in the first six months of 2010. The decrease in prepaid expense assets was the result of current operations in Argentina utilizing the prepaid taxes that existed at December 31, 2009.

During the six months ended June 30, 2009, our operating activities provided $43.0 million in cash. Our net loss for the six months ended June 30, 2009 was $2.7 million. Non-cash expenses totaled $16.8 million during the first six months of 2009 consisting of $40.9 million of depreciation and amortization, $2.3 million for share based compensation expense, $1.2 million in amortization of debt issuance costs, $3.6 million related to increases to the allowance for doubtful accounts receivables, a $1.9 million loss on a rig destroyed in a blow-out, less $26.4 million on the gain from debt extinguishment, $6.1 million for deferred income taxes related to timing differences and $602,000 on the gain from asset disposals.

During the six months ended June 30, 2009, changes in operating assets and liabilities provided $28.8 million in cash, principally due to a decrease in accounts receivable of $55.3 million, a decrease in prepaid expenses and other current assets of $7.4 million and a decrease in inventory of $2.5 million, offset in part by a decrease in accounts payable of $27.2 million, a decrease in accrued interest of $3.0 million and a decrease in accrued expenses of $5.8 million. Accounts receivable, inventory, accounts payable and accrued expenses decreased primarily due to the drop in our activity in the first six months of 2009. The decrease in prepaid expense and other current assets was the result of tax refunds received. The decrease in accrued interest relates to the payment of accrued interest upon the purchase of our senior notes in June 2009. The decrease in accrued expenses related primarily to the payment of a $3.0 million earn-out in conjunction with the acquisition of substantially all of the assets of Diamondback Oilfield Services, Inc., as well as to the drop in our activity for the first six months of 2009.

Investing Activities

During the six months ended June 30, 2010, we used $38.1 million in investing activities, consisting of $31.0 million for capital expenditures, $10.1 million for other assets, offset by $2.6 million of proceeds from equipment sales and $368,000 from the sale of an investment. Included in the $31.0 million for capital expenditures was $11.0 million for our Oilfield Services segment, $11.8 million for additional equipment in our Drilling and Completion segment and $7.8 million for drill pipe and other equipment used in our Rental Services segment. The increase in other assets was primarily due to $10.0 million of advance payments made toward the construction of a drilling rig. 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, 2009, we used $41.3 million in investing activities, consisting of $58.0 million for capital expenditures, offset by a decrease of $10.0 million in other assets and $6.7 million of proceeds from equipment sales. Included in the $58.0 million for capital expenditures was $8.1 million for our Oilfield Services segment, $34.8 million for our two domestic drilling rigs and $8.9 million for additional equipment in our Drilling and Completion segment and $6.2 million for drill pipe and other equipment used in our Rental Services segment. The decrease in other assets was primarily due to the conversion of $9.4 million of deposits on equipment purchases into capital expenditures for the drilling rigs and assets used in our directional drilling services. A majority of our equipment sales relate to items “lost in hole” or “damaged beyond repair” by our customers. We also transferred $1.3 million of rental assets as part of our investment into our Saudi Arabia joint venture in a non-cash transaction.

Financing Activities

During the six months ended June 30, 2010, financing activities used $6.9 million in cash. We borrowed $4.0 million under a long-term debt facility and repaid $9.4 million in borrowings under long-term debt facilities. We also incurred $189,000 in debt issuance costs related to an amendment to our revolving credit facility to modify our loan covenants and we paid $1.3 million in preferred stock dividends. In addition, we financed our renewal of $2.4 million in insurance policy premiums in non-cash transactions.

During the six months ended June 30, 2009, financing activities provided $50.8 million in cash. We raised $120.3 million net of expenses from the issuance of common and preferred stock, and borrowed $25.0 million under a loan facility to acquire two drilling rigs, offset in part by repayments of $57.4 million of long-term debt and a net repayment on our revolving credit facility of $36.5 million. The repayments of long-term debt consisted of $46.4 million on the senior notes as a result of a tender offer and $11.0 million of scheduled debt repayment including prepayment on our BCH loan facility. We also incurred $644,000 in debt issuance costs consisting of $513,000 on the revolving credit facility, primarily to modify our loan covenants, and $131,000 on the rig financing agreement. In addition, we financed our renewal of $2.4 million in insurance policy premiums in non-cash transactions.

At June 30, 2010, we had $489.2 million in outstanding indebtedness, of which $470.6 million was long-term debt and $18.6 million is due within one year.

Recent Events

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, 2010, we had a $90.0 million revolving line of credit with a maturity of April 2012. At June 30, 2010, our availability under the facility was reduced by $4.2 million in outstanding letters of credit.

Capital Resources

Exclusive of any acquisitions, we currently expect our capital spending for the remainder of 2010 to be between $38.0 million and $42.0 million depending upon the market demand we experience, our operating performance during the remainder of the year and expenditures which may be associated with potential new contracts. These amounts are net of equipment deposits paid through June 30, 2010. This amount includes budgeted but unidentified expenditures which may be required to enhance or extend the life of existing assets. We believe that our cash generated from operations, cash on hand and cash available under our credit facilities will provide sufficient funds for our identified projects and to service our debt. Our ability to obtain capital for opportunistic acquisitions or additional projects to implement our growth strategy over the longer term will depend upon our future operating performance and financial condition, which will be dependent upon the prevailing conditions in our industry and the global market, including the availability of equity and debt financing, many of which are beyond our control.

Critical Accounting Policies

Please see our Annual Report on Form 10-K for the year ended December 31, 2009 for a description of other policies that are critical to our business operations and the understanding of our results of operations. The impact and any associated risks related to these policies on our business operations is discussed throughout 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, 2010.

Recently Issued Accounting Standards

For a discussion of new accounting standards, see the applicable section in Note 1 to our Consolidated Financial Statements included in “Item 1. Financial Statements.”

Forward-Looking Statements

This quarterly report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, regarding our business, financial condition, results of operations and prospects. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements. However, these are not the exclusive means of identifying forward-looking statements. Although such forward-looking statements reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. These factors include, but are not limited to, the following:

•

the impact of the weak economic conditions and the future impact of such conditions on the oil and gas industry and demand for our services;

•

unexpected future capital expenditures (including the amount and nature thereof);

•

unexpected difficulties in integrating our operations as a result of any significant acquisitions;

•

adverse weather conditions in certain regions;

•

the impact of political disturbances, war, or terrorist attacks and changes in global trade policies;

•

the availability (or lack thereof) of capital to fund our business strategy and/or operations;

•

the potential impact of the loss of one or more key employees;

•

the effect of environmental liabilities that are not covered by an effective indemnity or insurance;

•

the impact of current and future laws;

•

the effects of competition; and

•

the effects of our indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a competitive disadvantage compared to competitors that have less debt, and could have other adverse consequences

Further information about the risks and uncertainties that may impact us are described under “Item 1A—Risk Factors” included in this report and in our Annual Report on Form 10-K for the year ended December 31, 2009. You should read those sections carefully. You should not place undue reliance on forward-looking statements, which speak only as of the date of this quarterly report. We undertake no obligation to update publicly any forward-looking statements in order to reflect any event or circumstance occurring after the date of this quarterly report or currently unknown facts or conditions or the occurrence of unanticipated events.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are exposed to market risk primarily from changes in interest rates and foreign currency exchange 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 $31.2 million of adjustable rate debt with a weighted average interest rate of 4.0% at June 30, 2010.

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.

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, 2010, our disclosure controls and procedures are effective at a reasonable assurance level in ensuring that the information required to be disclosed by us in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports that we file under the Exchange Act, is 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 1A. RISK FACTORS.

Except as set forth below, there have been no material changes in the risk factors disclosed under Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2009.

The recent Deepwater Horizon incident in the U.S. Gulf of Mexico and its consequences could have a material adverse effect on our business.

In April 2010, the Deepwater Horizon drilling rig experienced an explosion and fire, and later sank into the Gulf of Mexico. The accident resulted in the loss of life and a significant oil spill. As a result of this explosion, the resulting oil spill and the inability to stop the oil spill, a moratorium has been placed on offshore deepwater drilling in the U. S., which is currently scheduled to be in place effective through November 2010. Our Rental Services segment has historically been very dependent on drilling activity in the Gulf of Mexico. Due to the decline in drilling activity in the Gulf of Mexico since the hurricanes of 2007, we had already begun to shift our focus to serving the onshore unconventional gas markets and redeploying rental equipment to the international markets such as Brazil, Saudi Arabia and Egypt. We believe this strategy will partially offset the impact of decreased activity in the Gulf of Mexico on our Rental Services segment. The impact of the drilling moratorium was not substantial for the six months ended June 30, 2010, but we expect our results will be impacted to a greater extent by the moratorium in the third quarter and thereafter until the Gulf of Mexico drilling activity recovers from the effects of the oil spill. Therefore we continue to anticipate that revenues and operating income for our Rental Services segment will be below 2009 levels.

We cannot assure you that the moratorium will not be extended or expanded. If the moratorium is not lifted, and with respect to our rental services business, if our equipment is not successfully redeployed to other locations where we can provide our services at a profitable rate, our business, financial condition and results of operations could be materially affected.

The recent Deepwater Horizon incident in the U.S. Gulf of Mexico may lead to other restrictions or regulations on offshore drilling in the U.S. Gulf of Mexico, which could have a material adverse effect on our business.

We do not yet know the extent to which the Deepwater Horizon rig explosion in the Gulf of Mexico may cause the U. S. to restrict or further regulate offshore drilling. This event and its aftermath has resulted in proposed legislation and regulation in the U. S. that could result in additional governmental regulation of the offshore oil and natural gas exploration and production industry. We cannot predict with any certainty the substance or effect of any new or additional regulations. These may include new or additional bonding and safety requirements, and other requirements regarding certification of equipment. In addition, any safety requirements or governmental regulations could increase our costs of operation of our business. If the U. S. enacts stricter restrictions on offshore drilling or further regulate offshore drilling or contracting services operations, our business, financial condition and results of operations could be materially affected.

The Deepwater Horizon rig explosion in the U.S. Gulf of Mexico and resulting oil spill may make it difficult to buy adequate insurance.

The explosion in the Gulf of Mexico may lead to further tightening of an increasingly difficult market for insurance coverage. Insurers may not continue to offer the type and level of coverage which we currently maintain, and our costs may increase substantially as a result of increased premiums, potentially to the point where coverage is not available on economically manageable terms. In addition, should liability limits be increased via legislative or regulatory action, it is possible that we may not be able to insure certain activities to a desirable level. If liability limits are increased and/or the insurance market becomes more restricted, this could materially impact our business, financial condition and results of operations.

Historically, we have been dependent on several customers operating in a single industry; the loss of one or more customers could adversely affect our financial condition and results of operations.

Our customers are engaged in the oil and natural gas exploration business in the U.S., Argentina, Brazil, Bolivia, Mexico and elsewhere. Historically, we have been dependent upon a few customers for a significant portion of our revenues. For the six months ended June 30, 2010, one of our customers, Pan American Energy represented 33.7% of our consolidated revenues and represented 54.6% of our Drilling and Completion revenues.

In addition, Pan America Energy is owned 60% by British Petroleum. British Petroleum has stated that it plans to sell assets to help cover its costs related to the recent oil spill in the Gulf of Mexico. Although we have no indication that British Petroleum plans to do so, in the event that British Petroleum were to sell its interest in Pan American, such a sale may have an adverse effect on our agreement and long term relationship with Pan American.

This concentration of customers may increase our overall exposure to credit risk. Our customers will likely be similarly affected by changes in economic and industry conditions. Our financial condition and results of operations will be materially adversely affected if one or more of our significant customers fails to pay us or ceases to contract with us for our services on terms that are favorable to us or at all.

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 5, 2010.



	Allis-Chalmers Energy Inc.
	(Registrant)


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

EXHIBIT INDEX


4.1		Fourth Amendment to Investment Agreement, dated July 14, 2010, between Allis-Chalmers Energy Inc. and Lime Rock Partners V, L.P. (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed on July 14, 2010).

10.1		Employment Agreement, effective April 21, 2010, by and between DLS Argentina Limited and Carlos F. Etcheverry. (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on May 20, 2010).

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

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

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


*		Filed herewith

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents