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 ~~SEPTEMBER~~June 30, ~~2010~~2011


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

FOR THE TRANSITION PERIOD FROM ~~_______________ TO _______________~~to

Commission file number 1-02199

ALLIS-CHALMERS ENERGY INC.

(Exact name of registrant as specified in its charter)


DELAWARE		~~39-0126090~~27-33212

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

~~5075 WESTHEIMER, SUITE 890,~~11125 Equity Drive, Suite 200, HOUSTON, TEXAS		~~77056~~77041

(Address of principal executive offices)		(Zip Code)

(713) ~~369-0550~~856-4222

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. Yesþ Noo

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). Yesoþ Noo

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 filero	Accelerated filerþ	Non-accelerated filero	~~Smaller reporting company~~o
		(Do not check if a smaller reporting company)	Smaller reporting companyo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

~~At November 1, 2010 there were 73,426,715~~
As of August 26, 2011, all of the 1,000 issued and outstanding shares of ~~common stock, par value $0.01 per share, outstanding.~~Allis-Chalmers Energy Inc. are held by Archer Limited.

Allis-Chalmers Energy Inc. meets the conditions set forth in general instruction H(1)(a) and (b) ofForm 10-Q and is therefore filing thisForm 10-Q with the reduced disclosure format.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED CONDENSED BALANCE SHEETS

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


					Successor			Predecessor
	September 30,		December 31,		June 30,			December 31,
	2010		2009		2011			2010
	(unaudited)				(unaudited)
Assets
Cash and cash equivalents	$	15,322	$	41,072	$	13,416		$	20,940
Restricted cash						3,784			—
Trade receivables, net		140,123		105,059		174,380			144,960
Inventories		38,993		34,528		50,026			42,140
Deferred income tax asset		2,649		3,790		1,104			81
Prepaid expenses and other		8,628		13,799		18,734			9,192

Total current assets		205,715		198,248		261,444			217,313

Property and equipment, net		732,857		746,478		675,581			723,234
Goodwill		46,173		40,639		267,428			46,333
Other intangible assets, net		35,138		32,649		94,890			33,899
Debt issuance costs, net		8,073		9,545		—			7,405
Deferred income tax asset		34,736		22,047		—			1,969
Other assets		40,445		31,014		5,251			8,116


Total assets	$	1,103,137	$	1,080,620	$	1,304,594		$	1,038,269


Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	23,624	$	17,027	$	6,892		$	15,215
Trade accounts payable		43,361		34,839		60,760			46,042
Accrued salaries, benefits and payroll taxes		25,319		22,854		35,525			32,790
Accrued interest		6,917		15,821		15,199			15,524
Accrued expenses		27,674		21,918		41,912			30,676

Total current liabilities		126,895		112,459		160,288			140,247

Deferred income tax liability						16,989			8,240
Long-term debt, net of current maturities		497,100		475,206		454,689			478,225
Deferred income tax liability		8,087		8,166
Payable to parent						74,403			—
Other long-term liabilities		452		1,142		32			233

Total liabilities		632,534		596,973		706,401			626,945

Commitments and contingencies
Commitments and Contingencies

Stockholders’ Equity
Preferred stock, $0.01 par value (25,000,000 shares authorized; 36,393 shares issued and outstanding at September 30, 2010 and at December 31, 2009)		34,183		34,183
Common stock, $0.01 par value (200,000,000 shares authorized;
73,430,682 shares issued and outstanding at September 30, 2010 and 71,378,529 shares issued and outstanding at December 31, 2009)		734		714
Preferred stock, $0.01 par value (0 shares authorized, 0 issued and outstanding at June 30, 2011 and 25,000,000 authorized, 36,393 issued and outstanding at December 31, 2010)						—			34,183
Common stock, $0.01 par value (1,000 shares authorized, 1,000 issued and outstanding at June 30, 2011 and 200,000,000 authorized, 73,722,347 issued and outstanding at December 31, 2010)						—			737
Capital in excess of par value		429,146		422,823		600,885			429,924
Retained earnings		6,540		25,927
Accumulated deficit						(2,692	)		(53,520	)

Total stockholders’ equity		470,603		483,647		598,193			411,324


Total liabilities and stockholders’ equity	$	1,103,137	$	1,080,620	$	1,304,594		$	1,038,269

ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(~~in thousands, except per share amounts)~~
~~(unaudited)~~In thousands)

For the Three Months Ended For the Nine Months Ended
September 30, September 30,
2010 2009 2010 2009
Revenues $ 174,288 $ 120,016 $ 473,302 $ 377,624

Operating costs and expenses
Direct costs 127,622 90,763 356,060 281,136
Depreciation 21,094 19,709 61,799 58,261
Selling, general and administrative 12,772 11,430 36,949 40,595
Loss on asset disposition — — — 1,916
Amortization 1,255 1,184 3,567 3,558

Total operating costs and expenses 162,743 123,086 458,375 385,466

Income (loss) from operations 11,545 (3,070 ) 14,927 (7,842 )

Other income (expense)
Interest expense (11,881 ) (10,764 ) (33,986 ) (37,492 )
Interest income 45 39 499 53
Gain on debt extinguishment — — — 26,365
Other (661 ) 37 (2,479 ) (231 )

Total other income (expense) (12,497 ) (10,688 ) (35,966 ) (11,305 )

Loss before income taxes (952 ) (13,758 ) (21,039 ) (19,147 )

Provision for income taxes (1,614 ) 4,108 3,563 6,802

Net loss (2,566 ) (9,650 ) (17,476 ) (12,345 )

Preferred stock dividend (637 ) (630 ) (1,911 ) (665 )

Net loss attributed to common stockholders $ (3,203 ) $ (10,280 ) $ (19,387 ) $ (13,010 )

Net loss per common share:
Basic $ (0.04 ) $ (0.14 ) $ (0.27 ) $ (0.27 )
Diluted $ (0.04 ) $ (0.14 ) $ (0.27 ) $ (0.27 )

Weighted average shares outstanding:
Basic 72,207 70,945 71,506 47,834
Diluted 72,207 70,945 71,506 47,834
(Unaudited)

Successor Predecessor
Three Months Four Months Two Months Three Months Six Months
Ended Ended Ended Ended Ended
June 30, June 30, February 28, June 30, June 30,
2011 2011 2011 2010 2010
Revenues $ 220,138 $ 290,864 $ 126,885 $ 158,644 $ 299,014

Operating costs and expenses:
Direct costs 162,628 213,764 97,130 120,723 228,438
Depreciation 23,030 30,346 15,026 20,517 40,705
Selling, general and administrative 15,386 20,177 23,752 12,114 24,177
Impairment of intangible assets — 5,100 — — —
Amortization 4,357 5,810 811 1,156 2,312

Total operating costs and expenses 205,401 275,197 136,719 154,510 295,632

Income (loss) from operations 14,737 15,667 (9,834 ) 4,134 3,382

Other income (expense):
Interest expense (10,067 ) (13,813 ) (7,854 ) (11,149 ) (22,105 )
Interest income 8 11 5 299 454
Other (34 ) (21 ) 122 (303 ) (1,818 )

Total other expense (10,093 ) (13,823 ) (7,727 ) (11,153 ) (23,469 )

Income (loss) before income taxes 4,644 1,844 (17,561 ) (7,019 ) (20,087 )

Income tax benefit (expense) (2,955 ) (4,536 ) (1,736 ) 1,640 5,177

Net income (loss) 1,689 (2,692 ) (19,297 ) (5,379 ) (14,910 )

Preferred stock dividend — — (375 ) (637 ) (1,274 )

Net income (loss) attributed to common stockholders $ 1,689 $ (2,692 ) $ (19,672 ) $ (6,016 ) $ (16,184 )

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

ALLIS-CHALMERS ENERGY INC.

CONSOLIDATED CONDENSED ~~STATEMENTS~~STATEMENT OF ~~CASH FLOWS~~
STOCKHOLDERS’ EQUITY

(~~in thousands)~~
In thousands, except share amounts)

(unaudited)

For the Nine Months Ended
September 30,
2010 2009
Cash Flows from Operating Activities:

Net loss $ (17,476 ) $ (12,345 )
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization 65,366 61,819
Amortization and write-off of debt issuance costs 1,661 1,691
Stock-based compensation 4,374 3,580
Allowance for bad debts 43 4,065
Deferred income taxes (12,016 ) (11,094 )
Loss on investment 1,466 —
Equity in loss of unconsolidated affiliates 409 —
Loss (gain) on sale of property and equipment 150 (1,180 )
Loss on asset disposition — 1,916
Gain on debt extinguishment — (26,365 )
Changes in operating assets and liabilities, net of acquisition:
Decrease (increase) in trade receivable (30,361 ) 59,471
Decrease (increase) in inventories (2,697 ) 3,890
Decrease in prepaid expenses and other current assets 8,024 3,290
Decrease in other assets 1,265 1,535
Increase (decrease) in trade accounts payable 8,380 (29,035 )
(Decrease) in accrued interest (8,904 ) (12,479 )
Increase (decrease) in accrued expenses 5,488 (11,632 )
Increase in accrued salaries, benefits and payroll taxes 2,401 1,228
(Decrease) in other long-term liabilities (690 ) (836 )

Net Cash Provided By Operating Activities 26,883 37,519

Cash Flows from Investing Activities:

Deposits on asset commitments (12,967 ) 7,054
Business acquisition, net of cash acquired (18,237 ) —
Purchase of investment interests 368 (1,102 )
Proceeds from sale of property and equipment 5,284 7,980
Proceeds from assets dispositions — 3,916
Purchase of property and equipment (50,893 ) (67,266 )

Net Cash Used In Investing Activities (76,445 ) (49,418 )

Cash Flows from Financing Activities:

Proceeds from issuance of stock, net — 120,337
Net proceeds from stock incentive plans — 14
Proceeds from long-term debt 4,000 25,000
Net borrowings (repayments) under line of credit 36,500 (36,500 )
Payments on long-term debt (14,588 ) (61,539 )
Payment of preferred stock dividend (1,911 ) —
Debt issuance costs (189 ) (644 )

Net Cash Provided By Financing Activities 23,812 46,668

Net change in cash and cash equivalents (25,750 ) 34,769

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

Cash and cash equivalents at end of period $ 15,322 $ 41,635

Capital in Retained Total
Preferred Stock Common Stock Excess of Earnings Stockholders’
Shares Amount Shares Amount Par Value (Deficit) Equity
Predecessor

Balances, December 31, 2010 36,393 $ 34,183 73,722,347 $ 737 $ 429,924 $ (53,520 ) $ 411,324

Net loss — — — — — (19,297 ) (19,297 )
Preferred stock dividend — — — — — (375 ) (375 )

Issuance of common stock:
Issuance under stock plans, net of tax — — 650,727 7 (1,828 ) — (1,821 )

Stock-based compensation — — — — 6,084 — 6,084

Balances, February 28, 2011 36,393 $ 34,183 74,373,074 $ 744 $ 434,180 $ (73,192 ) $ 395,915

Successor

Capitalization at merger — $ — 1,000 $ — $ 600,885 $ — $ 600,885

Net loss — — — — — (2,692 ) (2,692 )

Balances, June 30, 2011 — $ — 1,000 $ — $ 600,885 $ (2,692 ) $ 598,193

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)

Successor Predecessor
Four Months Two Months Six Months
Ended Ended Ended
June 30, February 28, June 30,
2011 2011 2010
Cash Flows from Operating Activities:

Net loss $ (2,692 ) $ (19,297 ) $ (14,910 )
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization 36,156 15,837 43,017
Amortization of deferred issuance costs — 366 1,106
Debt premium amortization (1,050 ) — —
Stock-based compensation — 6,084 3,001
Impairment of intangible assets 5,100 — —
Allowance for bad debts — 195 —
Deferred income taxes (939 ) 140 (10,821 )
Loss on investment — — 1,466
Equity in loss of unconsolidated affiliates — — 260
Loss on sale of property and equipment 171 416 807
Changes in operating assets and liabilities, net of acquisitions:
Increase in trade receivable (14,908 ) (15,944 ) (25,845 )
Increase in inventories (6,076 ) (1,810 ) (2,392 )
Decrease (increase) in prepaid expenses and other assets (10,154 ) 550 8,838
Decrease (increase) in other assets (256 ) 674 799
Increase in trade accounts payable 1,764 12,954 10,753
(Decrease) increase in accrued interest 3,568 (3,893 ) 148
Increase in accrued expenses 2,943 8,555 3,801
Decrease in other liabilities (60 ) (141 ) (466 )
(Decrease) increase in accrued salaries, benefits and payroll taxes 4,414 (1,679 ) 1,945

Net cash provided by operating activities 17,981 3,007 21,507

Cash Flows from Investing Activities:

Decrease (increase) in restricted cash 357 (4,141 ) —
Purchases of investment interests — (1,177 ) —
Proceeds from sale of investments — — 368
Purchases of property and equipment (25,572 ) (22,758 ) (30,989 )
Deposits on asset commitments (46 ) 82 (10,096 )
Proceeds from sale of property and equipment 1,880 1,009 2,616

Net cash used in investing activities (23,381 ) (26,985 ) (38,101 )

Cash Flows from Financing Activities:

Proceeds from issuance of long-term debt — — 4,000
Payments on long-term debt (5,772 ) (7,819 ) (9,446 )
Net borrowings (repayments) on lines of credit — (36,500 ) —
Proceeds from parent 2,953 71,450
Payment of preferred stock dividend — (637 ) (1,274 )
Exercise of options and restricted stock awards, net of tax — (1,821 ) —
Debt issuance costs — — (189 )

Net cash (used) provided by financing activities (2,819 ) 24,673 (6,909 )

Net increase (decrease) in cash and cash equivalents (8,219 ) 695 (23,503 )
Cash and cash equivalents at beginning of period 21,635 20,940 41,072

Cash and cash equivalents at end of period $ 13,416 $ 21,635 $ 17,569

Supplemental information:
Interest paid (net of capitalized interest) $ 9,259 $ 10,991 $ 20,467
Income taxes paid (refunds) $ 2,865 $ (580 ) $ 57

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, Pennsylvania, Arkansas, West Virginia, Oklahoma, Colorado, offshore in the Gulf of Mexico, and internationally, primarily in Argentina, Brazil, Bolivia and Mexico. We operate in ~~three~~two sectors of the oil and natural gas service industry: ~~Oilfield Services;~~Well Services and 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.

~~Pending Merger~~Basis of Presentation

On ~~August 12, 2010, we entered into~~February 23, 2011, Allis-Chalmers Energy Inc., a Delaware corporation, completed its merger ~~agreement with Seawell Limited, or Seawell, pursuant to which we will merge~~(the “Merger”) with and into Wellco Sub Company (“Wellco”), a Delaware corporation and wholly owned subsidiary of ~~Seawell. Completion~~Seawell Limited (“Seawell”), with Wellco continuing as the surviving entity under the name Allis-Chalmers Energy Inc. The Merger was effected pursuant to the Agreement and Plan of Merger, dated as of August 10, 2010, by and among Allis-Chalmers, Seawell and Wellco, as amended by the Amendment Agreement, dated as of October 10, 2010, by and among Allis-Chalmers, Seawell and Wellco (as so amended, the “Merger Agreement”). Following the Merger, Seawell began operating under the name Archer Limited (“Archer” or “Parent”). As of the ~~merger~~Merger date, our assets and liabilities have been adjusted to their fair values (see Note 2) based on the purchase price resulting in changes to depreciation, amortization and interest in the successor period; therefore, the financial information for the period subsequent to the Merger is ~~subject~~not fully comparable. The financial statements and accompanying footnotes have been separated with a black line to ~~customary closing conditions, including, but not limited~~present pre-merger activity as the “Predecessor” company and post-merger activity as the “Successor” company. “Predecessor” refers to ~~(i) approval~~the operations of Allis-Chalmers prior to the consummation of the ~~merger by our stockholders, (ii) applicable regulatory approvals, (iii) the effectiveness of a registration statement on Form F-4 relating~~Merger and “Successor” refers to the ~~Seawell common stock to be issued in the merger and, (iv) the listing~~operations of ~~the Seawell common stock on the OSLO Stock Exchange.~~

Under terms of the merger, we agreed to conduct our business in the ordinary course while the merger is pending, and generally refrain, without the consent of Seawell, from entering into new lines of business, incurring new indebtedness, issuing new common stock or equity awards, or entering into new material contracts or commitments outside the normal course of business. We recorded approximately $0.6 million of costs relatedAllis-Chalmers subsequent to the pending merger during the three months ended September 30, 2010, which are included in general and administrative expense in the General Corporate category of our segment presentation (see Note 13). If and when the merger is approved or completed, certain contractual obligations of ours will or may be triggered or accelerated under the “change of control” provisions of such contractual arrangements. Examples of such arrangements include stock-based compensation awards, severance and retention agreements applicable to executive officers, directors and certain other employees and certain debt obligations suchMerger. The Merger date for accounting purposes has been designated as ~~our senior notes.~~

~~Basis of Presentation~~March 1, 2011.

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~~statement of the interim periods. These unaudited consolidated condensed financial statements should be read in conjunction with our restated audited consolidated financial statements included in Amendment No. 1 to our Annual Report on Form 10-K for the year ended December 31, ~~2009.~~2010 filed with the SEC on September 1, 2011 (the “Form 10-K/A”). The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year.

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

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

Financial Instruments

Financial instruments consist of cash and cash equivalents, restricted cash, accounts receivable and payable, and debt. The carrying value of cash and cash equivalents, restricted cash and accounts receivable and payable approximate fair value due to their short-term nature. Restricted cash relates to deposits at a financial institution to secure $3.8 million of outstanding letters of credit. 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 ~~September~~June 30, ~~2010.~~2011. Our senior notes, in the approximate aggregate amount of ~~$430.2~~$446.6 million, trade “over the counter” in limited amounts and on an infrequent basis. ~~Based on recent trades we estimate~~In connection with the Merger, the recorded fair value of our senior notes ~~to be approximately $432.9~~was increased by $19.3 million based on the traded value at ~~September 30, 2010.~~Merger date. 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.

~~Reclassification~~Recent Accounting Pronouncements

~~Certain reclassifications have been made~~We consider all newly issued but not yet adopted accounting pronouncements applicable to our operations and the ~~prior year’s~~preparation of our consolidated condensed financial ~~statements to conform with the current period presentation.~~

~~New Accounting Pronouncements~~

~~In June 2009, the Financial Accounting Standards Board, or the FASB,~~statements. We do not believe that any 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. Weaccounting pronouncements not yet adopted ~~this guidance effective January 1, 2010, which did not~~by us will have a material ~~effect~~impact on our consolidated condensed 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 allocatedNOTE 2 — BUSINESS COMBINATIONS

Merger with Archer

Pursuant to the ~~separate units~~Merger, each outstanding share of ~~accounting, when applicable,~~common stock of Allis-Chalmers was converted into the right to receive either $4.25 cash or 1.15 fully paid and nonassessable Archer common shares. The fair value of total consideration was approximately $600.9 million with approximately 95% of Allis-Chalmers stockholders electing to receive 97.1 million Archer common shares in the Merger and the remainder receiving an aggregate of approximately $18 million in cash. The following table summarizes the preliminary allocation of the purchase price to the estimated fair value of the assets at Merger (in thousands):

Current assets $ 237,873
Property and equipment 682,406
Intangible assets, including goodwill 373,227
Other long-term assets 4,949

Total assets acquired 1,298,455
Current liabilities 148,360
Long-term liabilities 549,210

Merger net assets $ 600,885

Our historical property and equipment values were decreased by ~~establishing a selling price hierarchy for determining~~$47.1 million, our Senior Notes were increased by $19.3 million, other assets were decreased by $13.8 million and other long-term liabilities were increased by $8.6 million. The fair value assigned to the ~~selling price of a deliverable. The selling price used for each deliverable will be~~debt was 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. This guidance is effective for fiscal years beginning on or after June 15, 2010, with earlier application permitted. We are currently evaluating the effects that this guidance may have on our financial statements.

~~In January 2010, the FASB issued authoritative guidance that~~actively traded prices and 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~~other assets and liabilities ~~should be grouped by class~~were based on third-party valuations or other market based approaches. Goodwill of $267.4 million was recognized for this acquisition and ~~valuation techniques used for recurring and nonrecurring~~was calculated as the excess of the consideration transferred over the fair value ~~measurements. We adopted this guidance in~~of the ~~first quarter 2010, which did~~net assets acquired. It includes the expected synergies and other benefits that we believe will result from the combined operations and intangible assets that do not qualify for separate recognition such as assembled workforce. Other intangible assets included approximately $91.2 million assigned to customer lists, $6.7 million to trade name, $5.6 million to patents and $2.3 million to backlogs (see note 4). Goodwill is not tax deductible. The amortizable intangibles have a ~~material effect on our financial position, results~~weighted-average useful life of ~~operations or cash flows.~~8.9 years. The allocation of the purchase price has been based upon preliminary fair values. Estimates and assumptions are subject to change upon management’s review of the final valuation.

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

NOTE 3 — STOCK-BASED COMPENSATION (Continued)

Our net loss for the three months ended September 30, 2010 and 2009 includes approximately $1.4 million and $1.2 million, respectively, of compensation costs related to share-based payments. Our net loss for the nine months ended September 30, 2010 and 2009 includes approximately $4.4 million and $3.6 million, respectively, of compensation costs related to share-based payments. As of September 30, 2010, there was $2.3 million of unrecognized compensation expense related to non-vested stock option grants. We expect approximately $134,000 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 nine months ended September 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 September 30, 2010 1,752,018 $ 4.74 7.86 $ 0.85

Exercisable at September 30, 2010 586,432 $ 7.08 4.90 $ 0.14

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 third 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 September 30, 2010.

Weighted
Shares Average
Under Exercise
Option Price
Balance at December 31, 2010 1,751,018 $ 4.74
Granted — —
Converted at Merger (1,750,018 ) 4.74
Exercised (1,000 ) 1.23

Outstanding at June 30, 2011 — —

Restricted stock awards, or RSAs, activity during the ~~nine~~three months ended ~~September~~June 30, ~~2010 were~~2011 is as follows:

Weighted-Average
Grant-Date Fair
Number of Shares Value Per Share
Nonvested at December 31, 2009 837,626 $ 15.63
Granted 2,061,750 3.78
Vested (335,787 ) 17.48
Forfeited (3,333 ) 3.77

Nonvested at September 30, 2010 2,560,256 $ 5.86

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 nine months ended September 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 the estimated number of shares expected to be issued. As of September 30, 2010, there was $7.1 million of total unrecognized compensation cost related to nonvested RSAs. We expect approximately $1.1 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 2015, respectively.

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

Weighted
Average Grant-
Date Fair Value
Number of Shares Per Share
Nonvested at December 31, 2010 1,702,067 $ 6.09
Granted — —
Vested (1,702,067 ) 6.09
Forfeited — —

Nonvested at June 30, 2011 — $ —

NOTE 4 — ~~INVENTORIES~~

~~Inventories consisted of the following (in thousands):~~

September 30, December 31,
2010 2009
Manufactured
Finished goods $ 3,814 $ 2,983
Work in process 2,099 2,299
Raw materials 2,355 884

Total manufactured 8,268 6,166
Rig parts and related inventory 11,991 10,654
Shop supplies and related inventory 8,621 7,762
Chemicals and drilling fluids 4,919 4,381
Rental supplies 1,908 2,134
Hammers 2,269 2,257
Coiled tubing and related inventory 847 939
Drive pipe 170 235

Total inventories $ 38,993 $ 34,528

~~NOTE 5—~~ 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 $46.2~~was $267.4 million and ~~$40.6~~$46.3 million at ~~September~~June 30, ~~2010~~2011 and December 31, ~~2009,~~2010, respectively.

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.~~backlogs. These intangibles have useful lives ranging from ~~three~~four months to 20twenty years. Amortization of intangible assets for the three and ~~nine~~four months ended ~~September 30, 2010 were $1.3~~June, 2011 and two months ended February 28, 2011 was $4.4 million, $5.8 million and ~~$3.6 million,~~$811,000, respectively, compared to $1.2 million and ~~$3.6~~$2.3 million for the ~~same periods in~~three and six months ended June 30, 2010, respectively. In connection with the ~~prior year.~~Merger, a $5.1 million value was assigned to the Allis-Chalmers tradename. Following the Merger, Seawell and its subsidiaries, including us, have begun operating under the name Archer. As a result, it was determined that there was no material remaining value associated with the Allis-Chalmers tradename and the results for the four months ended June 30, 2011 includes an intangible asset impairment charge of $5.1 million. At ~~September~~June 30, ~~2010,~~2011, intangible assets totaled ~~$35.1~~$94.9 million, net of ~~$16.4~~$5.8 million of accumulated amortization. Future amortization of intangible assets at June 30, 2011 is approximately $5.9 million for the remainder of 2011 and an average of approximately $11.6 million during the years ended 2012 through 2015.

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

NOTE 65 — INVENTORIES

Inventories consisted of the following (in thousands):

Successor Predecessor
June 30, December 31,
2011 2010
Manufactured
Finished goods $ 5,319 $ 4,238
Work in process 3,849 2,990
Raw materials 5,138 3,600

Total manufactured 14,306 10,828
Rig parts and related inventory 13,582 11,565
Shop supplies and related inventory 10,486 9,620
Chemicals and drilling fluids 5,621 4,814
Rental supplies 1,593 1,761
Hammers 2,604 2,380
Coiled tubing and related inventory 1,725 1,046
Drive pipe 109 126

Total inventories $ 50,026 $ 42,140

NOTE 6- INCOME TAXES

In accordance with generally accepted accounting principles, we estimate the full-year effective tax rate from continuing operations and apply this rate to our year-to-date income from continuing operations. In addition, we separately calculate the tax impact of unusual items, if any. The consolidated effective tax rate for the two months ended February 28, 2011, three and four months ended June 30, 2011 was (9.9)%, 63.6% and 246.0%, respectively, compared to 23.4% and 25.8% for the three and six months ended June 30, 2010. The fluctuations in the tax rates are principally the result of valuation allowances on losses generated in the United States and variances in withholding taxes from foreign operations as a percentage of pretax income (loss).

Income (loss) before income taxes which was subject to United States and non-United States income taxes was as follow (in thousands):

Successor Predecessor
Three Months Four Months Two Months Three Months Six Months
Ended Ended Ended Ended Ended
June 30, June 30, February 28, June 30, June 30,
2011 2011 2011 2010 2010

United States $ 4,422 $ 1,118 $ (17,544 ) $ (13,414 ) $ (31,393 )
Outside United States 222 726 (17 ) 6,395 11,306

$ 4,644 $ 1,844 $ (17,561 ) $ ( 7,019 ) $ ( 20,087 )

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

NOTE 6- INCOME TAXES (Continued)

The income tax provision consists of the following (in thousands):

Successor Predecessor
Three Months Four Months Two Months Three Months Six Months
Ended Ended Ended Ended Ended
June 30, June 30, February 28, June 30, June 30,
2011 2011 2011 2010 2010

Income tax expense (benefit):
United States $ 183 $ 240 $ 233 $ (4,408 ) $ (10,513 )
Outside United States 2,772 4,296 1,503 2,768 5,336

$ 2,955 $ 4,536 $ 1,736 $ (1,640 ) $ (5,177 )

The following table reconciles the statutory tax rates to our actual tax rate:

Successor Predecessor
Three Months Four Months Two Months Three Months Six Months
Ended Ended Ended Ended Ended
June 30, June 30, February 28, June 30, June 30,
2011 2011 2011 2010 2010

United States Statutory federal income tax rate 35.0 % 35.0 % 35.0 % 35.0 % 35.0 %
United States State income taxes, net of federal benefit 1.2 1.2 0.7 2.2 2.2
Non-United States income taxed at different rates 10.9 42.7 0.3 12.5 7.8
Valuation allowance, permanent differences and other 16.5 167.1 (45.9 ) (26.3 ) (19.2 )

Effective tax rate 63.6 % 246.0 % (9.9 )% 23.4 % 25.8 %

NOTE 7- DEBT

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

September 30, December 31,
2010 2009
Senior notes $ 430,238 $ 430,238
Revolving line of credit 36,500 —
Term loans 52,484 60,744
Insurance premium financing 1,486 997
Capital lease obligations 16 254

Total debt 520,724 492,233

Less: current maturities 23,624 17,027

Long-term debt, net of current maturities $ 497,100 $ 475,206

Successor Predecessor
June 30, December 31,
2011 2010
Senior notes $ 446,647 $ 430,238
Revolving line of credit — 36,500
Bank term loans 14,934 25,723
Insurance premium financing notes — 979

Total debt 461,581 493,440
Less: current maturities of long-term debt 6,892 15,215

Long-term debt $ 454,689 $ 478,225

Senior notes, bank loans and line of credit agreements ~~and term loans~~

OnIn 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. OnIn June ~~29,~~ 2009, we closed on a tender offer in which we purchased ~~approximately~~ $30.6 million aggregate principal ~~amount~~ of our 9.0% senior notes for a total consideration of $650 per $1,000 principal amount. In connection with the Merger and based on actively traded prices of our senior notes, we increased the fair value of the 9.0% senior notes to $1,022 per $1,000 principal amount. In May 2011, pursuant to the terms of change of

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

NOTE 7 — DEBT (Continued)

control provisions in the indentures governing the senior notes and as a result of the Merger, holders had the right to require us to purchase, all or a portion of such holders’ Notes. We purchased $1.8 million aggregate principal of our 9.0% senior notes for a total consideration of $1,010 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 1933, 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 ~~amount~~ of our 8.5% senior notes for a total consideration of $600 per $1,000 principal amount. In connection with the Merger and based on actively traded prices of our senior notes, we increased the fair value of the 8.5% senior notes to $1,070 per $1,000 principal amount. In May 2011, pursuant to the terms of change of control provisions in the indentures governing the senior notes and as a result of the Merger, we purchased $92,000 aggregate principal of our 8.5% senior notes for a total consideration of $1,010 per $1,000 principal amount.

We ~~have~~had a $90.0 million revolving line of credit with a final maturity date of April 26, 2012 pursuant to a revolving credit agreement that ~~contains~~contained customary events of default and financial covenants and ~~limits~~limited 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.~~United States. We were in compliance with all debt covenants as of ~~September 30, 2010 and~~ December 31, ~~2009.~~2010. As of ~~September 30,~~December 31, 2010, we had $36.5 million of borrowings outstanding and ~~$4.0~~$4.1 million in outstanding letters of credit under our revolving credit facility. As of December 31, 2009, the only usage of our revolving credit facility consisted of $4.2 million in outstanding letters of credit. The interest rate under our revolving credit facility is based on prime or LIBOR plus a margin. The weighted-average interest rate was ~~7.9%~~7.8% at ~~September 30,~~December 31, 2010. The revolving line of credit was repaid and terminated in connection with the Merger.

As part of our acquisition of DLS, we assumed various bank loans with floating interest rates based on LIBOR plus a margin and terms ranging from ~~two~~2 to ~~five~~5 years. The ~~weighted-average~~weighted average interest rate on these loans was 2.0% ~~and 2.1%~~ as of ~~September 30, 2010 and~~ December 31, ~~2009, respectively.~~2010. The outstanding amount due under these bank loans as of ~~September~~June 30, ~~2010~~2011 and December 31, ~~2009~~2010 was ~~$350,000~~$0 and ~~$1.1 million,~~$350,000, respectively.

On February 15, 2008, through our DLS subsidiary in Argentina, we entered into a $25.0 million import finance facility with a bank. Borrowings under this facility were used to fund a portion of the purchase price of the new drilling and service rigs ordered for our Drilling ~~and Completion~~Services 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 ~~September~~June 30, ~~2010~~2011 and December 31, ~~2009.~~2010. The bank loan rates are based on LIBOR plus a margin. The ~~weighted-average~~weighted average interest rate was ~~4.3% and 4.4%~~4.2% at ~~September~~June 30, ~~2010~~2011 and December 31, ~~2009, respectively.~~2010. The outstanding amount under the import finance facility as of ~~September~~June 30, ~~2010~~2011 and December 31, ~~2009~~2010 was ~~$15.5~~$11.5 million and ~~$20.1~~$14.4 million, respectively.

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

~~NOTE 6 — DEBT (Continued)~~

As part of our acquisition of ~~BCH Ltd, or~~ BCH, we assumed a $23.6 million term loan credit facility with a bank. The ~~BCH~~ credit agreement iswas dated June 2007 and ~~contains~~contained customary events of default and financial covenants which ~~are~~were based on BCH’s stand-alone financial statements. The facility was repayable in quarterly principal installments plus interest and was to mature in August 2012. Obligations under the facility ~~are~~were secured by substantially all of the BCH assets. ~~BCH was in compliance with all debt covenants as of December 31, 2009.~~ The bank ~~has~~ waived certain financial ratio covenants for the ~~September 30, 2010 and~~ December 31, 2010 measurement ~~periods. As~~period and we ~~cannot be certain that BCH would attain compliance with the covenants within one year, we have~~ classified the entire outstanding balance of the loan in the current portion of long-term debt. The ~~facility is repayable in quarterly principal installments plus interest with the final payment due not later than August 2012. The~~ interest rates ~~under the credit facility are~~were based on LIBOR plus a ~~margin. At September 30, 2010 and December 31, 2009, the outstanding amount of the loan under the credit facility was $11.8 million and $16.2 million, respectively,~~margin and the interest rate was 3.5% at ~~both dates.~~

On May 22, 2009, we drew down $25.0 million on a 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 September 30, 2010 and December 31, ~~2009, the~~2010. The outstanding amount of the loan as of December 31, 2010 was ~~$20.8 million and $23.4 million, respectively.~~$7.0 million. The term loan credit facility was paid in full in connection with the Merger.

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 and bears interest at 8.5% per annum. The final maturity date is April 14, 2014 and the loan is unsecured. The outstanding amount under the term loan facility as of June 30, 2011 and December 31, 2010 was $3.4 million and $4.0 million, respectively

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

NOTE 7 — DEBT (Continued)

Notes payable

In 2010, we obtained insurance premium financings in the aggregate amount of ~~$2.6~~$2.9 million with a fixed weighted-average interest rate of 4.8%. Under terms of the agreements, amounts outstanding are paid over eight and 11 month repayment schedules. The outstanding balance of these notes was approximately ~~$1.5~~$0 and $1.0 million at ~~September~~June 30, 2010. In 2009, we obtained insurance premium financings in the aggregate amount of $3.2 million with a fixed weighted-average interest rate of 4.8%. Under terms of these 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 September 30, 20102011 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 $16,000 and $254,000 at September 30,~~ 2010, ~~and December 31, 2009,~~ respectively.

NOTE 78 — STOCKHOLDERS’ EQUITY

~~We issued 1.0 million shares of our common stock in connection with the acquisition of AWC in July of 2010 (see Note 2).~~

During the ~~nine~~two months ended ~~September 30, 2010,~~February 28, 2011, we had option exercises and certain vesting in restricted stock ~~award~~ grants ~~and vested performance-based restricted stock~~ which resulted in the issuance of ~~approximately 1.1 million~~933,083 shares of our common stock. We retained 282,356 shares from employees in connection with the settlement of tax obligations arising from the vesting of restricted stock grants. We recognized approximately ~~$4.4~~$6.1 million of compensation expense related to share-based payments induring the ~~first nine~~two months ~~of 2010~~ended February 28, 2011 that was recorded as capital in excess of par value (see Note 3). ~~During~~

Pursuant to the nine months ended September 30, 2010, we declared approximately $1.9 million in dividends on our preferred stock. Accrued dividends of approximately $637,000 were included in our accrued expenses of $27.7 million as of September 30, 2010 and our accrued expenses of $21.9 million as of December 31, 2009. The accrued dividends were paid in October 2010 and February 2010, respectively.

~~NOTE 8 — LOSS ON ASSET DISPOSITION~~

During the nine months ended September 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 that destroyed oneMerger, each share of our ~~drilling rigs~~convertible preferred stock was converted to common stock and each outstanding share of common stock of Allis-Chalmers was converted into the right to receive either $4.25 cash or 1.15 fully paid and nonassessable Archer common shares. Holders of our outstanding stock options, whether or not then exercisable or vested, elected to receive, at the effective time of the merger, either cash or fully exercisable and vested stock options to purchase Archer common shares. In addition, all restrictions on time-lapse and performance-based restricted stock awards were ~~not sufficient~~deemed to ~~cover~~have lapsed and each restricted share was deemed to be an unrestricted share of our common stock. Subsequent to the ~~book~~Merger, we have 1,000 shares authorized all of which have been issued to Archer Limited at a par value of ~~the rig and related assets.~~

~~ALLIS-CHALMERS ENERGY INC.~~
~~NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS~~$0.01 per share.

NOTE 9 ~~— GAIN ON DEBT EXTINGUISHMENT~~

During the nine months ended September 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 approximately $30.6 million aggregate principal amount of our 9.0% senior notes and $44.2 million aggregate principal amount of our 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.

~~NOTE 10 — INCOME (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 Nine Months Ended
September 30, September 30,
2010 2009 2010 2009
Numerator:

Net loss $ (2,566 ) $ (9,650 ) $ (17,476 ) $ (12,345 )
Preferred stock dividend (637 ) (630 ) (1,911 ) (665 )

Net loss attributed to common stockholders $ (3,203 ) $ (10,280 ) $ (19,387 ) $ (13,010 )

Denominator:

Weighted-average common shares outstanding excluding nonvested restricted stock 72,207 70,945 71,506 47,834

Effect of potentially dilutive common shares:
Convertible preferred stock and stock-based compensation — — — —

Weighted-average common shares outstanding and assumed conversions 72,207 70,945 71,506 47,834

Net loss per common share
Basic $ (0.04 ) $ (0.14 ) $ (0.27 ) $ (0.27 )

Diluted $ (0.04 ) $ (0.14 ) $ (0.27 ) $ (0.27 )

Potentially dilutive securities excluded as anti-dilutive 17,126 15,016 15,946 15,557

Convertible preferred stock and share-based compensation shares of approximately 14.7 million and 14.5 million were excluded in the computation of diluted earnings per share for the three months ended September 30, 2010 and 2009, 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. Convertible preferred stock and share-based compensation shares of approximately 15.0 million and 5.1 million were excluded in the computation of diluted earnings per share for the nine months ended September 30, 2010 and 2009, respectively, as the effect would have been anti-dilutive.

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

NOTE 129 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS
~~September~~June 30, ~~2010~~ 2011 (Successor)
(unaudited)


	Allis-
	Chalmers				Subsidiary
	(Parent/		Subsidiary		Non-		Consolidating			Consolidated		Allis-Chalmers			Subsidiary		Subsidiary			Consolidating			Consolidated
	Guarantor)		Guarantors		Guarantors		Adjustments			Total		(Guarantor)			Guarantors		Non-Guarantors			Adjustments			Total
Assets
Cash and cash equivalents	$	—	$	7,780	$	7,542	$	—		$	15,322	$	—		$	9,286	$	4,130		$	—		$	13,416
Restricted cash													—			3,784		—			—			3,784
Trade receivables, net		—		77,263		73,454		(10,594	)		140,123		—			102,949		103,193			(31,762	)		174,380
Inventories		—		18,906		20,087		—			38,993		—			26,981		23,045			—			50,026
Intercompany receivables		—		106,193		—		(106,193	)		—		—			87,640		—			(87,640	)		—
Note receivable from affiliate		23,551		—		—		(23,551	)		—		21,085			—		—			(21,085	)		—
Prepaid expenses and other		22		5,832		5,423		—			11,277		12			5,638		14,188			—			19,838

Total current assets		23,573		215,974		106,506		(140,338	)		205,715		21,097			236,278		144,556			(140,487	)		261,444
Property and equipment, net		—		469,640		263,217		—			732,857		—			406,223		269,358			—			675,581
Goodwill		—		28,784		17,389		—			46,173		—			179,697		87,731			—			267,428
Other intangible assets, net		425		28,320		6,393		—			35,138		—			57,540		37,350			—			94,890
Debt issuance costs, net		7,954		119		—		—			8,073
Note receivable from affiliates		2,100		—		—		(2,100	)		—		1,500			—		—			(1,500	)		—
Investments in affiliates		981,488		—		—		(981,488	)		—		1,170,166			—		—			(1,170,166	)		—
Other assets		32,767		39,099		3,315		—			75,181		—			4,869		382			—			5,251

Total assets	$	1,048,307	$	781,936	$	396,820	$	(1,123,926	)	$	1,103,137	$	1,192,763		$	884,607	$	539,377		$	(1,312,153	)	$	1,304,594


Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	—	$	5,172	$	18,452	$	—		$	23,624	$	—		$	—	$	6,892		$	—		$	6,892
Trade accounts payable		—		17,033		36,922		(10,594	)		43,361		—			21,814		70,708			(31,762	)		60,760
Accrued salaries, benefits and payroll taxes		—		1,976		23,343		—			25,319		—			5,465		30,060			—			35,525
Accrued interest		6,356		203		358		—			6,917		15,020			—		179			—			15,199
Accrued expenses		1,041		15,275		11,358		—			27,674		570			16,882		24,460			—			41,912
Intercompany payables		103,569		—		2,624		(106,193	)		—		57,930			—		29,710			(87,640	)		—
Note payable to affiliate		—		—		23,551		(23,551	)		—		—			—		21,085			(21,085	)		—

Total current liabilities		110,966		39,659		116,608		(140,338	)		126,895		73,520			44,161		183,094			(140,487	)		160,288
Long-term debt, net of current maturities		466,738		17,146		13,216		—			497,100		446,647			—		8,042			—			454,689
Note payable to affiliate		—		—		2,100		(2,100	)		—		—			—		1,500			(1,500	)		—
Payable to parent													74,403			—		—			—			74,403
Other long-term liabilities		—		—		8,539		—			8,539		—			—		17,021			—			17,021

Total liabilities		577,704		56,805		140,463		(142,438	)		632,534		594,570			44,161		209,657			(141,987	)		706,401

Commitments and contingencies
Commitments and Contingencies

Stockholders’ Equity
Preferred Stock		34,183		—		—		—			34,183
Common stock		734		3,527		42,963		(46,490	)		734		—			3,527		42,963			(46,490	)		—
Capital in excess of par value		429,146		591,978		137,439		(729,417	)		429,146		600,885			823,395		290,090			(1,113,485	)		600,885
Retained earnings		6,540		129,626		75,955		(205,581	)		6,540
Retained earnings (deficit)													(2,692	)		13,524		(3,333	)		(10,191	)		(2,692	)

Total stockholders’ equity		470,603		725,131		256,357		(981,488	)		470,603		598,193			840,446		329,720			(1,170,166	)		598,193

Total liabilities and stockholders’ equity	$	1,048,307	$	781,936	$	396,820	$	(1,123,926	)	$	1,103,137	$	1,192,763		$	884,607	$	539,377		$	(1,312,153	)	$	1,304,594

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

NOTE 129 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended ~~September~~June 30, ~~2010~~ 2011 (Successor)
(unaudited)


	Allis-Chalmers						Subsidiary
	(Parent/			Subsidiary			Non-			Consolidating			Consolidated			Allis-Chalmers			Subsidiary			Subsidiary			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors			Adjustments			Total			(Guarantor)			Guarantors			Non-Guarantors			Adjustments			Total
Revenues	$	—		$	78,034		$	96,325		$	(71	)	$	174,288		$	—		$	96,934		$	123,446		$	(242	)	$	220,138

Operating costs and expenses
Operating costs and expenses:
Direct costs		—			47,152			80,541			(71	)		127,622			—			57,986			104,884			(242	)		162,628
Depreciation `																	—			15,843			7,187			—			23,030
Selling, general and administrative		1,176			7,677			3,919			—			12,772			65			7,995			7,326			—			15,386
Depreciation and amortization		12			15,547			6,790			—			22,349
Amortization																	—			1,592			2,765			—			4,357

Total operating costs and expenses		1,188			70,376			91,250			(71	)		162,743			65			83,416			122,162			(242	)		205,401

Income (loss) from operations		(1,188	)		7,658			5,075			—			11,545			(65	)		13,518			1,284			—			14,737

Other income (expense):
Equity earnings in affiliates, net of tax		9,376			—			—			(9,376	)		—			11,067			—			—			(11,067	)		—
Interest, net		(10,769	)		(505	)		(562	)		—			(11,836	)		(9,326	)		(1	)		(732	)		—			(10,059	)
Other		15			(166	)		(510	)		—			(661	)		13			107			(154	)		—			(34	)

Total other expense		(1,378	)		(671	)		(1,072	)		(9,376	)		(12,497	)		1,754			106			(886	)		(11,067	)		(10,093	)


Net income (loss) before income taxes		(2,566	)		6,987			4,003			(9,376	)		(952	)		1,689			13,624			398			(11,067	)		4,644

Provision for income taxes		—			811			(2,425	)		—			(1,614	)		—			(183	)		(2,772	)		—			(2,955	)


Net income (loss)		(2,566	)		7,798			1,578			(9,376	)		(2,566	)	$	1,689		$	13,441		$	(2,374	)	$	(11,067	)	$	1,689

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


Net income (loss) attributed to common stockholders	$	(3,203	)	$	7,798		$	1,578		$	(9,376	)	$	(3,203	)

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

NOTE 129 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the ~~Nine~~Four Months Ended ~~September~~June 30, ~~2010~~ 2011 (Successor)
(unaudited)


	Allis-Chalmers						Subsidiary
	(Parent/			Subsidiary			Non-			Consolidating			Consolidated			Allis-Chalmers			Subsidiary			Subsidiary			Consolidating			Consolidated
	Guarantor)			Guarantors			Guarantors			Adjustments			Total			(Guarantor)			Guarantors			Non-Guarantors			Adjustments			Total
Revenues	$	—		$	192,676		$	282,025		$	(1,399	)	$	473,302		$	—		$	130,882		$	160,271		$	(289	)	$	290,864

Operating costs and expenses
Operating costs and expenses:
Direct costs		—			124,528			232,931			(1,399	)		356,060			—			78,879			135,174			(289	)		213,764
Depreciation																	—			20,797			9,549			—			30,346
Selling, general and administrative		3,708			22,033			11,208			—			36,949			100			10,997			9,080			—			20,177
Depreciation and amortization		35			45,779			19,552			—			65,366
Impairment of intangible assets																	—			4,400			700			—			5,100
Amortization																	—			2,123			3,687			—			5,810

Total operating costs and expenses		3,743			192,340			263,691			(1,399	)		458,375			100			117,196			158,190			(289	)		275,197

Income (loss) from operations		(3,743	)		336			18,334			—			14,927			(100	)		13,686			2,081			—			15,667

Other income (expense):
Equity earnings in affiliates, net of tax		17,643			—			—			(17,643	)		—			10,191			—			—			(10,191	)		—
Interest, net		(31,421	)		(291	)		(1,775	)		—			(33,487	)		(12,801	)		(2	)		(999	)		—			(13,802	)
Other		45			(1,944	)		(580	)		—			(2,479	)		18			80			(119	)		—			(21	)

Total other expense		(13,733	)		(2,235	)		(2,355	)		(17,643	)		(35,966	)		(2,592	)		78			(1,118	)		(10,191	)		(13,823	)


Net income (loss) before income taxes		(17,476	)		(1,899	)		15,979			(17,643	)		(21,039	)		(2,692	)		13,764			963			(10,191	)		1,844

Provision for income taxes		—			11,323			(7,760	)		—			3,563			—			(240	)		(4,296	)		—			(4,536	)


Net income (loss)		(17,476	)		9,424			8,219			(17,643	)		(17,476	)

Preferred stock dividend		(1,911	)		—			—			—			(1,911	)


Net income (loss) attributed to common stockholders	$	(19,387	)	$	9,424		$	8,219		$	(17,643	)	$	(19,387	)	$	(2,692	)	$	13,524		$	(3,333	)	$	(10,191	)	$	(2,692	)

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

NOTE 129 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF ~~CASH FLOW~~OPERATIONS
For the ~~Nine~~Two Months Ended ~~September 30, 2010~~ February 28, 2011 (Predecessor)
(unaudited)

Allis- Other
Chalmers Subsidiaries
(Parent/ Subsidiary (Non- Consolidating Consolidated
Guarantor) Guarantors Guarantors) Adjustments Total
Cash Flows from Operating Activities:

Net income (loss) $ (17,476 ) $ 9,424 $ 8,219 $ (17,643 ) $ (17,476 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization 35 45,779 19,552 — 65,366
Amortization and write-off of debt issuance costs 1,643 18 — — 1,661
Stock-based compensation 4,374 — — — 4,374
Allowance for bad debts — 43 — — 43
Equity earnings in affiliates (17,643 ) — — 17,643 —
Deferred taxes (11,847 ) (332 ) 163 — (12,016 )
Loss on sale of equipment — 74 76 — 150
Loss on investment — 1,466 — — 1,466
Equity in losses of unconsolidated affiliates — 409 — — 409
Changes in operating assets and liabilities, net of acquisitions:
(Increase) in trade receivables — (15,869 ) (14,492 ) — (30,361 )
(Increase) in inventories — (867 ) (1,830 ) — (2,697 )
Decrease in prepaid expenses and other current assets 129 3,791 4,104 — 8,024
Decrease in other assets — 549 716 — 1,265
(Decrease) increase in trade accounts payable — (4,637 ) 13,017 — 8,380
(Decrease) increase in accrued interest (9,016 ) (25 ) 137 — (8,904 )
Increase in accrued expenses 258 3,430 1,800 — 5,488
(Decrease) increase in accrued salaries, benefits and payroll taxes — (850 ) 3,251 — 2,401
(Decrease) in other long-term liabilities — — (690 ) — (690 )

Net Cash Provided By (Used In) Operating Activities (49,543 ) 42,403 34,023 — 26,883

Cash Flows from Investing Activities:

Investment in affiliates (19,467 ) — — 19,467 —
Notes receivable from affiliates 8,328 — — (8,328 ) —
Deposits on asset commitments — (12,694 ) (273 ) — (12,967 )
Proceeds from sale of investments — 368 — — 368
Proceeds from sale of property and equipment — 4,911 373 — 5,284
Business acquisitions — (18,237 ) — — (18,237 )
Purchase of property and equipment — (30,158 ) (20,735 ) — (50,893 )

Net Cash Used in Investing Activities (11,139 ) (55,810 ) (20,635 ) 11,139 (76,445 )

Allis-Chalmers Subsidiary Subsidiary Consolidating Consolidated
(Guarantor) Guarantors Non-Guarantors Adjustments Total
Revenues $ — $ 59,044 $ 67,923 $ (82 ) $ 126,885

Operating costs and expenses:
Direct costs — 37,335 59,877 (82 ) 97,130
Depreciation — 10,174 4,852 — 15,026
Selling, general and administrative 5,998 15,034 2,720 — 23,752
Amortization 8 678 125 — 811

Total operating costs and expenses 6,006 63,221 67,574 (82 ) 136,719

Income (loss) from operations (6,006 ) (4,177 ) 349 — (9,834 )

Other income (expense):
Equity earnings in affiliates, net of tax (6,057 ) — — 6,057 —
Interest, net (7,253 ) (8 ) (588 ) — (7,849 )
Other 19 (232 ) 335 — 122

Total other expense (13,291 ) (240 ) (253 ) 6,057 (7,727 )

Net income (loss) before income taxes (19,297 ) (4,417 ) 96 6,057 (17,561 )

Provision for income taxes — (233 ) (1,503 ) — (1,736 )

Net loss (19,297 ) (4,650 ) (1,407 ) 6,057 (19,297 )

Preferred stock dividend (375 ) — — — (375 )

Net loss attributed to common stockholders $ (19,672 ) $ (4,650 ) $ (1,407 ) $ 6,057 $ (19,672 )

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

NOTE 129 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the ~~Nine~~Four Months Ended ~~September~~June 30, ~~2010~~ 2011 (Successor)
(unaudited)

Allis- Other
Chalmers Subsidiaries
(Parent/ Subsidiary (Non- Consolidating Consolidated
Guarantor) Guarantors Guarantors) Adjustments Total
Cash Flows from Financing Activities:

Accounts receivable from affiliates — (25,492 ) (790 ) 26,282 —
Accounts payable to affiliates 26,282 — — (26,282 ) —
Notes payable to affiliates — — (8,328 ) 8,328 —
Proceeds from parent contributions — 19,467 — (19,467 ) —
Proceeds from long-term debt — — 4,000 — 4,000
Borrowings under line of credit 36,500 — — — 36,500
Payments on long-term debt — (4,646 ) (9,942 ) — (14,588 )
Payment of preferred stock dividend (1,911 ) — — — (1,911 )
Debt issuance costs (189 ) — — — (189 )

Net Cash Provided By (Used In) Financing Activities 60,682 (10,671 ) (15,060 ) (11,139 ) 23,812

Net change in cash and cash equivalents — (24,078 ) (1,672 ) — (25,750 )
Cash and cash equivalents at beginning of period — 31,858 9,214 — 41,072

Cash and cash equivalents at end of period $ — $ 7,780 $ 7,542 $ — $ 15,322

Allis-Chalmers Subsidiary Subsidiary Consolidating Consolidated
(Guarantor) Guarantors Non-Guarantors Adjustments Total
Cash Flows from Operating Activities:

Net income (loss) $ (2,692 ) $ 13,524 $ (3,333 ) $ (10,191 ) $ (2,692 )
Adjustments to reconcile net income (loss) to net cash (used) provided by operating activities:
Depreciation and amortization — 22,920 13,236 — 36,156
Debt premium amortization (1,050 ) — — — (1,050 )
Equity earnings in affiliates (10,191 ) — — 10,191 —
Impairment of intangible assets — 4,400 700 — 5,100
Deferred income taxes — 1 (940 ) — (939 )
Loss on sale of equipment — 94 77 — 171
Changes in operating assets and liabilities, net of acquisitions:
Increase in trade receivables — (1,342 ) (13,566 ) — (14,908 )
Increase in inventories — (3,481 ) (2,595 ) — (6,076 )
Increase in prepaid expenses and other current assets (1 ) (2,655 ) (7,498 ) — (10,154 )
Decrease (increase) in other assets — (322 ) 66 — (256 )
(Decrease) increase in trade accounts payable — (5,455 ) 7,219 — 1,764
(Decrease) increase in accrued interest 3,741 — (173 ) — 3,568
(Decrease) increase in accrued expenses (345 ) (485 ) 3,773 — 2,943
(Decrease) increase in accrued salaries, benefits and payroll taxes — (3,501 ) 7,915 — 4,414
Decrease in other long- term liabilities — — (60 ) — (60 )

Net cash (used) provided by operating activities (10,538 ) 23,698 4,821 — 17,981

Cash Flows from Investing Activities:

Notes receivable from affiliates (2,312 ) — — 2,312 —
Decrease in restricted cash — 357 — — 357
Deposits on asset commitments — — (46 ) — (46 )
Proceeds from sale of property and equipment — 1,827 53 — 1,880
Purchases of property and equipment — (17,479 ) (8,093 ) — (25,572 )

Net cash used in investing activities (2,312 ) (15,295 ) (8,086 ) 2,312 (23,381 )

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

NOTE 129 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING ~~BALANCE SHEETS~~STATEMENTS OF CASH FLOW
~~December 31, 2009~~For the Four Months Ended June 30, 2011 (Successor)
(unaudited)

Allis-Chalmers Subsidiary
(Parent/ Subsidiary Non- Consolidating Consolidated
Guarantor) Guarantors Guarantors Adjustments 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 stockholders’ equity $ 1,010,297 $ 745,418 $ 381,626 $ (1,056,721 ) $ 1,080,620

Allis-Chalmers Subsidiary Subsidiary Consolidating Consolidated
(Guarantor) Guarantors Non-Guarantors Adjustments Total
Cash Flows from Financing Activities:

Accounts receivable from affiliates — (15,631 ) — 15,631 —
Accounts payable to affiliates 11,782 — 3,849 (15,631 ) —
Note payable to affiliate — — 2,312 (2,312 ) —
Payments on long-term debt (1,885 ) (350 ) (3,537 ) — (5,772 )
Proceeds from Parent 2,953 — — — 2,953

Net cash (used) provided by financing activities 12,850 (15,981 ) 2,624 (2,312 ) (2,819 )

Net change in cash and cash equivalents — (7,578 ) (641 ) — (8,219 )
Cash and cash equivalents at beginning of year — 16,864 4,771 — 21,635

Cash and cash equivalents at end of period $ — $ 9,286 $ 4,130 $ — $ 13,416

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

NOTE 129 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Two Months Ended February 28, 2011 (Predecessor)
(unaudited)

Allis-Chalmers Subsidiary Subsidiary Consolidating Consolidated
(Guarantor) Guarantors Non-Guarantors Adjustments Total
Cash Flows from Operating Activities:

Net loss $ (19,297 ) $ (4,650 ) $ (1,407 ) $ 6,057 $ (19,297 )
Adjustments to reconcile net loss to net cash (used) provided by operating activities:
Depreciation and amortization 8 10,852 4,977 — 15,837
Amortization of deferred issuance costs 366 — — — 366
Stock based compensation 6,084 — — — 6,084
Equity earnings in affiliates 6,057 — — (6,057 ) —
Allowance for bad debts — 195 — — 195
Deferred income taxes — 34 106 — 140
Loss on sale of equipment — 352 64 — 416
Changes in operating assets and liabilities, net of acquisitions:
Increase in trade receivables — (3,714 ) (12,230 ) — (15,944 )
Increase in inventories — (1,434 ) (376 ) — (1,810 )
Decrease (increase) in prepaid expenses and other current assets 2,057 235 (1,742 ) — 550
Decrease in other assets — 432 242 — 674
Increase in trade accounts payable — 8,417 4,537 — 12,954
(Decrease) increase in accrued interest (4,031 ) — 138 — (3,893 )
(Decrease) increase in accrued expenses (15 ) (1,137 ) 9,707 — 8,555
Decrease in accrued salaries, benefits and payroll taxes — (17 ) (1,662 ) — (1,679 )
Decrease in other long- term liabilities — — (141 ) — (141 )

Net cash (used) provided by operating activities (8,771 ) 9,565 2,213 — 3,007

Cash Flows from Investing Activities:

Notes receivable from affiliates (114 ) — — 114 —
Increase in restricted cash — (4,141 ) — — (4,141 )
Purchases of investment interests — (1,177 ) — — (1,177 )
Deposits on asset commitments — — 82 — 82
Proceeds from sale of property and equipment — 924 85 — 1,009
Purchase of property and equipment — (16,931 ) (5,827 ) — (22,758 )

Net cash used in investing activities (114 ) (21,325 ) (5,660 ) 114 (26,985 )

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

NOTE 9 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2010 (Predecessor)

Allis-Chalmers Subsidiary Subsidiary Consolidating Consolidated
(Guarantor) Guarantors Non-Guarantors Adjustments Total
Assets
Cash and cash equivalents $ — $ 16,380 $ 4,560 $ — $ 20,940
Trade receivables, net — 79,100 77,397 (11,537 ) 144,960
Inventories — 22,066 20,074 — 42,140
Intercompany receivables — 84,766 — (84,766 ) —
Note receivable from affiliate 18,359 — — (18,359 ) —
Prepaid expenses and other 2,068 3,280 3,925 — 9,273

Total current assets 20,427 205,592 105,956 (114,662 ) 217,313
Property and equipment, net — 461,187 262,047 — 723,234
Goodwill — 28,944 17,389 — 46,333
Other intangible assets, net 414 27,278 6,207 — 33,899
Debt issuance costs, net 7,405 — — — 7,405
Note receivable from affiliates 1,800 — — (1,800 ) —
Investments in affiliates 934,274 — — (934,274 ) —
Other assets — 7,390 2,695 — 10,085

Total assets $ 964,320 $ 730,391 $ 394,294 $ (1,050,736 ) $ 1,038,269

Liabilities and Stockholders’ Equity

Current maturities of long-term debt $ — $ 979 $ 14,236 $ — $ 15,215
Trade accounts payable — 18,634 38,945 (11,537 ) 46,042
Accrued salaries, benefits and payroll taxes — 8,983 23,807 — 32,790
Accrued interest 15,310 — 214 — 15,524
Accrued expenses 1,192 18,504 10,980 — 30,676
Intercompany payables 69,756 — 15,010 (84,766 ) —
Note payable to affiliate — — 18,359 (18,359 ) —

Total current liabilities 86,258 47,100 121,551 (114,662 ) 140,247
Long-term debt, net of current maturities 466,738 — 11,487 — 478,225
Note payable to affiliate — — 1,800 (1,800 ) —
Other long-term liabilities — — 8,473 — 8,473

Total liabilities 552,996 47,100 143,311 (116,462 ) 626,945

Commitments and contingencies

Stockholders’ Equity
Preferred Stock 34,183 — — — 34,183
Common stock 737 3,527 42,963 (46,490 ) 737
Capital in excess of par value 429,924 589,676 137,439 (727,115 ) 429,924
Retained earnings (deficit) (53,520 ) 90,088 70,581 (160,669 ) (53,520 )

Total stockholders’ equity 411,324 683,291 250,983 (934,274 ) 411,324

Total liabilities and stock holders’ equity $ 964,320 $ 730,391 $ 394,294 $ (1,050,736 ) $ 1,038,269

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

~~NOTE 12 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)~~

~~CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW~~
~~For the Nine Months Ended September 30, 2009 (unaudited)~~

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

~~NOTE 12 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)~~

~~CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW~~
~~For the Nine Months Ended September 30, 2009 (unaudited)~~

Allis- Other
Chalmers Subsidiaries
(Parent/ Subsidiary (Non- Consolidating Consolidated
Guarantor) Guarantors Guarantors) Adjustments Total
Cash Flows from Financing Activities:

Accounts receivable from affiliates — (18,637 ) — 18,637 —
Accounts payable to affiliates 18,661 — (24 ) (18,637 ) —
Notes payable to affiliates — — (693 ) 693 —
Proceeds from parent contributions — — 4,100 (4,100 ) —
Proceeds from issuance of stock, net 120,337 — — — 120,337
Net proceeds from stock incentive plans 14 — — — 14
Proceeds from long-term debt — 25,000 — — 25,000
Net repayment under line of credit (36,500 ) — — — (36,500 )
Payments on long-term debt (47,167 ) (3,011 ) (11,361 ) — (61,539 )
Debt issuance costs (491 ) (153 ) — — (644 )

Net Cash Provided By (Used In) Financing Activities 54,854 3,199 (7,978 ) (3,407 ) 46,668

Net change in cash and cash equivalents — 26,258 8,511 — 34,769
Cash and cash equivalents at beginning of period — 2,923 3,943 — 6,866

Cash and cash equivalents at end of period $ — $ 29,181 $ 12,454 $ — $ 41,635

Allis-Chalmers Subsidiary Subsidiary Consolidating Consolidated
(Guarantor) Guarantors Non-Guarantors Adjustments 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 139 — ~~SEGMENT~~CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

~~All of our segments provide services to~~CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For 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):Six Months Ended June 30, 2010 (Predecessor)
(unaudited)

For the Three Months Ended For the Nine Months Ended
September 30, September 30,
2010 2009 2010 2009
Revenues:

Oilfield Services $ 56,705 $ 31,904 $ 146,070 $ 105,827
Drilling and Completion 96,295 76,299 280,772 223,237
Rental Services 21,288 11,813 46,460 48,560

$ 174,288 $ 120,016 $ 473,302 $ 377,624

Operating Income (Loss):

Oilfield Services $ 7,462 $ (4,211 ) $ 7,969 $ (15,701 )
Drilling and Completion 5,125 5,508 17,640 14,420
Rental Services 3,337 (1,218 ) 1,596 3,318
General corporate (4,379 ) (3,149 ) (12,278 ) (9,879 )

$ 11,545 $ (3,070 ) $ 14,927 $ (7,842 )

Depreciation and Amortization:

Oilfield Services $ 7,925 $ 8,077 $ 23,622 $ 22,825
Drilling and Completion 6,793 5,462 19,619 16,182
Rental Services 7,565 7,281 21,929 22,580
General corporate 66 73 196 232

$ 22,349 $ 20,893 $ 65,366 $ 61,819

Capital Expenditures:

Oilfield Services $ 7,339 $ 1,348 $ 18,370 $ 9,408
Drilling and Completion 8,371 7,067 20,212 50,775
Rental Services 3,840 851 11,592 7,042
General corporate 354 7 719 41

$ 19,904 $ 9,273 $ 50,893 $ 67,266

Revenues:

United States $ 75,833 $ 37,625 $ 182,756 $ 140,448
Argentina 77,115 65,192 226,140 180,846
Brazil 10,031 11,034 30,033 31,812
Other international 11,309 6,165 34,373 24,518

$ 174,288 $ 120,016 $ 473,302 $ 377,624

Allis-Chalmers Subsidiary Subsidiary Consolidating Consolidated
(Guarantor) Guarantors Non-Guarantors Adjustments 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 139 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

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

Allis-Chalmers Subsidiary Other Subsidiaries Consolidating Consolidated
(Guarantor) Guarantors (Non-Guarantors) Adjustments 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 10 — SEGMENT INFORMATION

In conjunction with the Merger, we reviewed the presentation of our operating segments. Based on this review, we determined that our operational performance would be segmented and reviewed by the Drilling Services and Well Services segments. The split of our organization and aggregation of our business into two segments was based on differences in management structure and reporting, economic characteristics, customer base, asset class and contract structure. The Drilling Services segment includes our international and domestic drilling, directional drilling, underbalanced drilling, tubular services and rental services operations. The Well Services segment includes our production services and valve manufacturing operations. As a result, we realigned our financial reporting segments and now report the Drilling Services and Well Services operations as separate, distinct reporting segments. Our historical segment data previously reported for the three and six months ended June 30, 2010 and as of December 31, 2010 have been restated to conform to the new presentation.

All of our segments provide services to the energy industry. Indirect general and administrative expenses are allocated to each segment based on estimated use. The revenues, operating income (loss), depreciation and amortization, capital expenditures and assets of each of the reporting segments are reported below (in thousands):

Successor Predecessor
Three Months
Ended Four Months
Ended Two Months
Ended Three Months
Ended Six Months
Ended
June 30, June 30, February 28, June 30, June 30,
2011 2011 2011 2010 2010
Revenues:

Drilling Services $ 187,969 $ 247,277 $ 106,050 $ 146,913 $ 277,441
Well Services 32,169 43,587 20,835 11,731 21,573

Total revenues $ 220,138 $ 290,864 $ 126,885 $ 158,644 $ 299,014

Operating Income (Loss):

Drilling Services $ 8,084 $ 8,488 $ (9,943 ) $ 4,551 $ 4,307
Well Services 6,653 7,179 109 (417 ) (925 )

Total income (loss) from operations $ 14,737 $ 15,667 $ (9,834 ) $ 4,134 $ 3,382

Depreciation and Amortization Expense:

Drilling Services $ 24,023 $ 31,777 $ 13,792 $ 19,393 $ 38,581
Well Services 3,364 4,379 2,045 2,280 4,436

Total depreciation and amortization expense $ 27,387 $ 36,156 $ 15,837 $ 21,673 $ 43,017

Capital Expenditures:

Drilling Services $ 17,012 $ 21,619 $ 19,939 $ 17,417 $ 27,187
Well Services 1,493 3,953 2,819 1,814 3,802

Total capital expenditures $ 18,505 $ 25,572 $ 22,758 $ 19,231 $ 30,989

Revenues:

United States $ 93,595 $ 126,735 $ 57,651 $ 59,795 $ 106,923
Argentina 106,100 137,318 57,458 76,640 149,025
Brazil 9,306 12,004 5,250 10,502 20,002
Other international 11,137 14,807 6,526 11,707 23,064

Total revenues $ 220,138 $ 290,864 $ 126,885 $ 158,644 $ 299,014

ALLIS-CHALMERS ENERGY INC.

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 11 — LEGAL MATTERS (Continued)

of the well, activated and closed ‘blow out preventers’ rented from Allis-Chalmers Rental Services, LLC (ACRS) thereby sealing the well. Nexen then re-opened the blow out preventers to attempt an unsuccessful dynamic kill. Nexen alleges that it then again attempted to reseal the well using the blow out preventers but was unable to obtain a complete seal. The well allegedly then flowed uncontrolled for up to a day causing damage to the rig and other equipment, and the hole. The blow out preventers were manufactured by Cameron and Hydril and some of the components of the Cameron equipment were machined by Tri-City. Nexen alleges that the ~~likelihood~~blow out preventers failed due to the fault of ~~material loss relating~~the defendants. ACRS contends that Nexen actions in specifying the equipment for the well, designing the well, and operating the well including its acts and omissions for the well control event caused any failure of the equipment rented to Nexen by ACRS. There is conflicting evidence and expert testimony affecting several aspects of this case. It is impossible to predict the outcome with any ~~such~~degree of certainty. ACRS and its insurers are treating this case as highly defensible and continue to vigorously contest it.

NOTE 12 — TRANSACTIONS WITH PARENT

In connection with the Merger, we received approximately $71.4 million in funding from our Parent. The proceeds were mainly used to pay off debt, debt related interest and merger related expenses. The merger related expenses were primarily for legal ~~proceeding~~and professional fees and change of control provisions. The three and four months ended June 30, 2011 includes Parent allocations of interest charges of approximately $969,000 and $1.3 million, respectively, and other administrative charges of approximately $1.8 million. Parent administrative charges are allocated proportional to the average EBIT and revenue contribution. The allocation method used is ~~remote.~~considered reasonable by management and our estimated costs that would have been incurred on a stand alone basis would not have been materially different. The amount due to Parent was approximately $74.4 million at June 30, 2011 and balance is classified as a long-term liability. The interest rate used for allocation of interest charges was 5.3% as of June 30, 2011.

NOTE 13 — SUBSEQUENT EVENT

In July 2011, we purchased $125.0 million aggregate principal of our 9.0% senior notes for a total consideration of $1,023 per $1,000 principal amount. In connection with this purchase we have drawn $130.0 million on our Parent’s $550 million Multicurrency Term and Revolving Facility. The $550 million facility has a final maturity date of November 11, 2015 and interest rate is based on LIBOR plus a margin.

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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 39.

Overview of Our Business

We are 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, Pennsylvania, Arkansas, West Virginia, Oklahoma, Colorado, offshore in the Gulf of Mexico and internationally primarily in Argentina, Brazil, Bolivia and Mexico. We ~~currently~~ operate in ~~three~~two sectors of the oil and natural gas service industry: ~~Oilfield Services;~~Well Services and 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.

Merger ~~Agreement~~ with ~~Seawell~~Archer

On ~~August 12, 2010,~~February 23, 2011, we ~~entered into an Agreement and Plan of Merger with Seawell Limited, or Seawell, pursuant to which we will merge~~merged with and into Wellco Sub Company, a wholly owned subsidiary of ~~Seawell,~~Archer, and each share of our common stock ~~will be~~was converted into the right to receive either 1.15 ~~Seawell~~Archer common shares ~~subject to adjustment to 1.20 Seawell common shares under certain circumstances,~~ or $4.25 in cash. ~~Completion of~~In connection with the ~~merger is subject~~Merger, Wellco Sub Company changed its name to customary closing conditions, including, but not limited to, (i) approval of the merger by our stockholders, (ii) applicable regulatory approvals, (iii) the effectiveness of a registration statement on Form F-4 relating to the Seawell common stock to be issued in the merger, and (iv) the listing of the Seawell common stock on the OSLO Stock Exchange.Allis-Chalmers Energy Inc.

Under the terms of the merger agreement, we agreed to conduct our business in the ordinary course while the merger is pending, and to generally refrain, without the consent of Seawell, from entering into new lines of business, incurring new indebtedness, issuing new common stock or equity awards, or entering into new material contracts or commitments outside the normal course of business. We recorded approximately ~~$0.6~~$14.7 million, $1.6 million and $2.5 million of costs related to the merger during the ~~three~~two months ended ~~September~~February 28, 2011 and the three and four months ended June 30, ~~2010,~~2011, respectively, which are included in selling, general and administrative expense on our Consolidated Condensed Statements of Operations. ~~If and when~~Approval of the merger ~~is approved or completed,~~resulted in certain of our contractual obligations ~~of ours will or may be~~being triggered or accelerated under the “change of control” provisions of such contractual arrangements. Examples of such arrangements include stock-based compensation awards, severance and retirement plan agreements applicable to executive officers, directors and certain employees and certain other debt obligations, including our senior notes.

2731

~~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. This reduced activity in the energy sector resulted in lower demand for our services and we incurred significant losses. Since the second quarter of 2009, we have experienced quarter over quarter improvement in both our total revenues and total operating income which has resulted in reduced net losses.

On April 20, 2010, a fire and explosion occurred onboard the semisubmersible drilling rig Deepwater Horizon, which was owned by Transocean Ltd. and under contract to a subsidiary of BP plc. The accident resulted in the loss of life and a significant oil spill. In response to this incident, the Minerals Management Service of the U.S. Department of Interior, or the MMS, issued a notice on May 30, 2010 implementing a six-month moratorium on certain drilling activities in the U.S. Gulf of Mexico. The notice also stated that the MMS would not consider drilling permits for new wells and related activities for specified water depths during the six-month moratorium period. In addition, entities in the process of drilling wells covered by the moratorium were required to halt drilling and take steps to secure such wells. On June 22, 2010, the U.S. District Court for the Eastern District of Louisiana issued a preliminary injunction prohibiting the enforcement of the moratorium, which the Department of the Interior appealed to the Fifth Circuit Court of Appeals. On July 8, 2010, the court of appeals denied the government’s request that the district court’s order be stayed while the appeal was pending.

On July 12, 2010, the Secretary of the Department of the Interior directed the Bureau of Ocean Energy Management, Regulation and Enforcement, or the BOEM (successor to the MMS), to issue a revised suspension of drilling activities for specified drilling configurations and technologies, rather than a moratorium based on water depths. The revised suspension is to last until November 30, 2010 or such earlier date as the U.S. Secretary of the Interior determines that the suspended operations can proceed safely. On August 16, 2010, the BOEM announced that it would restrict the use of certain categorical exclusions to environmental regulations for deepwater exploration while it analyzes the environmental impact of deepwater operations. On September 30, 2010, the BOEM announced two new rules, the Drilling Safety Rule and the Workplace Safety Rule, which are intended to strengthen requirements for safety equipment, well control systems and blowout prevention practices on offshore oil and natural gas operations, and to improve workplace safety by reducing the risk of human error. On October 12, 2010, the moratorium was lifted, and deepwater oil and natural gas drilling in the U.S. Gulf of Mexico has been allowed to resume, provided that operators certify compliance with all existing rules and requirements, including those that recently went into effect, and demonstrate the availability of adequate blowout containment resources.

Although the moratorium on oil and natural gas drilling in the U.S. Gulf of Mexico has been lifted, the BOEM is expected to continue to issue new guidelines and may take other steps that could increase the costs of exploration and production, reduce the area of operations and result in permitting delays. These may include new or additional bonding and safety requirements, and other requirements regarding certification of equipment. The enactment of stricter restrictions on offshore drilling or further regulation of offshore drilling or contracting services operations could materially affect our business, financial condition and results of operations.

We believe that our revenues and operating income for all of our segments for the fourth quarter of 2010 will be similar to our revenues and operating income for the third quarter of 2010. Our Oilfield Services segment is heavily dependent 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 forty-three weeks of 2010 increased to an average of 1,514 compared to an average of 1,079 for the first forty-three weeks of 2009. This favorable trend in rig count is resulting in improved demand and pricing for our Oilfield Services segment. Our revenues and operating income in our Oilfield Services segment for the nine months ended September 30, 2010 exceed our revenues and operating income for that segment for the year ended December 31, 2009. Although the market for our drilling services in Brazil in 2010 has been slowed and remains price sensitive, 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. However, we have two 1600 horsepower land drilling rigs under construction in the U.S. which we expect will be completed and delivered during the fourth quarter of 2010. Currently, we have no firm commitments of work for these two drilling rigs and we expect to incur start-up costs in the fourth quarter of 2010 as we get one or more of the rigs ready to operate in 2011. We have two additional rigs, which were substantially completed in

2009, at a different manufacturer’s facility due to design or engineering problems encountered. We are currently in discussions with the manufacturer to resolve these issues and at this time we cannot be assured that these rigs will not require significant expenditures to bring them to satisfactory operational standards or that we will not incur a loss upon settlement. Our Rental Services segment has historically been very dependent on drilling activity in the U.S. Gulf of Mexico. The Baker Hughes average rig count in the U.S. Gulf of Mexico for the first forty-three weeks of 2010 decreased to 32 rigs compared to an average of 44 rigs for the first forty-three weeks of 2009. As of October 15, 2010, the Baker Hughes rig count in the U.S. Gulf of Mexico was 21 as a result of the effects of the oil spill in the U.S. 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 natural gas markets and redeploying rental equipment to the international markets such as Brazil, Saudi Arabia and Egypt. This strategy has partially offset the impact of decreased activity in the Gulf of Mexico on our Rental Services segment, and we believe that revenues and operating income for the year ended December 31, 2010 for our Rental Services segment will be improved compared to 2009 levels.

Our selling, general and administrative expenses for the nine months ended September 30, 2010 are less than the selling, general and administrative expenses in the comparable period in the prior year, because of $4.1 million in bad debt expense included for the nine months ended September 30, 2009 compared to $43,000 in bad debt expense in the nine months ended September 30, 2010. We expect our selling, general and administrative expenses for the fourth quarter of 2010 to be higher than the selling, general and administrative expenses for the fourth quarter of 2009 and expect selling, general and administrative expenses to be similar between the years ended December 31, 2010 and 2009. The expected increase in selling, general and administrative expenses in the fourth quarter of 2010 is due to costs related to our pending merger and because the fourth quarter of 2009 included a reversal of $1.8 million of bad debt expense.

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. We expect our interest expense for 2010 to be below 2009 levels, but we do anticipate interest expense in the fourth quarter of 2010 to be higher than the fourth quarter of 2009 due to increased borrowings. We do not anticipate having the ability to record a gain on debt extinguishment in 2010 as our senior notes are trading close to or in excess of face value due to the pending merger.

As we incur more non-deductible merger related expenses, we anticipate our effective tax rate applied to our expected pre-tax income for the fourth quarter of 2010 to be greater than the effective tax rate of our tax benefit from losses generated in the first half of 2010. The effective tax rate is affected 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, 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 improvements to our operating results for the remainder of 2010.

Results of Operations

In July 2010, we acquired all of the outstanding stock of American Well Control, Inc., or AWC, which is reported as part of our ~~Rental~~Well Services segment. We consolidated the results of this transaction from the date it was effective.

In connection with the Merger with Archer, our assets and liabilities have been adjusted to their fair values based on the purchase price resulting in changes to depreciation, amortization and interest in the successor period.

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

Comparison of Three Months Ended ~~September~~June 30, ~~2010~~2011 and ~~2009~~2010

Our revenues for the three months ended ~~September~~June 30, ~~2010~~2011 were ~~$174.3~~$220.1 million, an increase of ~~45.2%~~38.8% compared to ~~$120.0~~$158.6 million for the three months ended ~~September~~June 30, ~~2009.~~2010. The increase in revenues is due to the increase in revenues in ~~all~~both of our operating segments. Our ~~Oilfield~~Drilling Services segment revenues increased ~~77.7%~~27.9% to ~~$56.7~~$188.0 million for the three months ended ~~September~~June 30, ~~2010~~2011 compared to ~~$31.9~~$146.9 million for the three months ended ~~September~~June 30, ~~2009 due to increased utilization of our equipment and improved pricing. Our Drilling and Completion segment revenues increased 26.2% to $96.3 million for three months ended September 30,~~ 2010 ~~compared to $76.3 million for the three months ended September 30, 2009. The increase in revenues in our Drilling and Completion segment was~~ due to increased utilization and rig rates in Argentina and ~~Bolivia.~~Bolivia and increased utilization of our equipment and improved pricing domestically. Revenues for our ~~Rental~~Well Services segment increased ~~80.2%~~174.2% to ~~$21.3~~$32.2 million for the three months ended ~~September~~June 30, ~~2010~~2011 compared to ~~$11.8~~$11.7 million for the three months ended ~~September~~June 30, ~~2009~~2010 due to ~~$6.8~~$9.7 million of revenues from AWC ~~since~~in the ~~date of acquisition,~~current period, along with an increased ~~emphasis~~utilization of ~~providing rental services in the domestic onshore unconventional natural gas markets which offset decreased~~our equipment ~~utilization in the U.S. Gulf of Mexico.~~and improved pricing.

Our direct costs for the three months ended ~~September~~June 30, ~~2010~~2011 increased ~~40.6%~~34.7% to ~~$127.6~~$162.6 million, or ~~73.2%~~73.9% of revenues, compared to ~~$90.8~~$120.7 million, or ~~75.6%~~76.1%, of revenues for the three months ended ~~September~~June 30, ~~2009.~~2010. Our direct costs in all of our segments increased in absolute dollars in the three months ended ~~September~~June 30, ~~2010~~2011 compared to the three months ended ~~September~~June 30, ~~2009.~~2010. Our ~~Oilfield~~Drilling Services segment revenues for the three months ended ~~September~~June 30, ~~2010~~2011 increased ~~77.7%~~27.9% from revenues for the three months ended ~~September~~June 30, ~~2009, while~~2010 and direct costs increased ~~57.9%~~27.8% over that same period, resulting in an improvement in gross margin as a percentage of revenues to 32.7% for the three months ended September 30, 2010 compared to 24.2% for the three months ended September 30, 2009.period. Our Oilfield Services segment began to realize price increases starting in the later part of the first quarter of 2010. Our Drilling and Completion segment revenues for the three months ended September 30, 2010 increased 26.2% from revenues for the three months ended September 30, 2009, while direct costs increased 29.4% over that same period, resulting in a reduction in gross margin as a percentage of revenues to 16.5% for the three months ended September 30, 2010 compared to 18.5% for the three months ended September 30, 2009. The reduction in the gross margin percentage in our Drilling and Completion segment is due to a decrease in utilization and pricing for our services in Brazil. Our RentalWell Services segment revenues for the three months ended ~~September~~June 30, ~~2010~~2011 increased ~~80.2%~~174.2% from revenues for the three months ended ~~September~~June 30, ~~2009,~~2010, while direct costs increased ~~104.4%~~122.6% over that same period. ~~While~~The improvement in gross margin is due to improved utilization of equipment and pricing which was slightly offset by the impact of the acquisition of AWC. AWC provided ~~$6.8~~$9.7 million of revenues during the three months ended ~~September~~June 30, ~~2010~~2011 and it also increased direct costs by ~~$4.1~~$6.0 million for the same period for an effective gross margin as a percentage of revenues of ~~40.6%~~38.3%. AWC’s gross margin as a percentage of revenues is less than our overall ~~Rental~~Well Services gross margin percentage as AWC’s manufacturing operation has a higher labor component. 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. Gross margin as a percentage of revenues for our ~~Rental~~Well Services segment for the three months ended ~~September~~June 30, ~~2010~~2011 was ~~57.8%~~39.5% compared to ~~62.8%~~25.5% for the three months ended ~~September~~June 30, ~~2009.~~2010.

Depreciation expense increased ~~7.0%~~12.2% to ~~$21.1~~$23.0 million for the three months ended ~~September~~June 30, ~~2010~~2011 from ~~$19.7~~$20.5 million for the three months ended ~~September~~June 30, ~~2009.~~2010. The primary increase in depreciation expense is ~~primarily~~ due to our capital expenditure programs for our Drilling ~~and Completion~~Services segment. Depreciation expense as a percentage of revenues decreased to ~~12.1%~~10.5% for the ~~third~~second quarter of 2011, compared to 12.9% for the second quarter of 2010, ~~compared to 16.4% for the third quarter of 2009,~~ due to the ~~increase~~noted increases in ~~our~~ revenues.

Selling, general and administrative expense was ~~$12.8~~$15.4 million for the three months ended ~~September~~June 30, ~~2010~~2011 compared to ~~$11.4~~$12.1 million for the three months ended ~~September~~June 30, ~~2009.~~2010. Selling, general and administrative expense increased primarily due to an increase in severance expense and other professional fees for the three months ended ~~September~~June 30, ~~2010~~2011 compared to the same period of the prior ~~year. Professional~~year all due principally to the Merger and a general increase relating to additional operational activities which was partially offset by a reduction in stock based compensation. The three months ended June 30, 2011 includes approximately $1.6 million of severance expense and other professional fees relating to the Merger and $1.7 million of allocated general and administrative expenses from our Parent. Stock based compensation for the three months ended ~~September~~June 30, 2010 ~~included $578,000 of costs~~was $1.6 million with no related expense for the three months ended June 30, 2011 due to the ~~pending merger, $140,000~~acceleration of ~~costs related to~~stock based compensation expense as of the ~~acquisition of AWC and a $225,000 lawsuit settlement.~~Merger date. As a percentage of revenues, selling, general and administrative expense was ~~7.3%~~7.0% for the three months ended ~~September~~June 30, ~~2010~~2011 compared to ~~9.5%~~7.6% for the same period in the prior year.

~~Our interest expense was $11.9~~$14.7 million for the three months ended ~~September~~June 30, ~~2010,~~2011, compared to ~~$10.8~~income from operations of $4.1 million for the three months ended ~~September~~June 30, ~~2009. During~~2010. The increase in income from operations was mainly due to the increase in revenues and improved margins which was partially offset by the increases in depreciation, amortization and selling, general and administrative expenses.

Our interest expense was $10.1 million for the three months ended ~~September~~June 30, ~~2010 we had borrowings of $36.5 million under our revolving credit facility~~2011, compared to ~~no borrowings at September~~$11.1 million for the three months ended June 30, ~~2009. Of~~2010. Approximately $51.5 million of our debt was paid in connection with the ~~$36.5~~Merger. Interest expense for the three months ended June 30, 2011 was reduced by approximately $1.1 million ~~borrowed under our revolving credit facility, $16.5 million was borrowed on~~in connection with debt premium amortization and interest expense for the ~~date we acquired AWC. Interest expense~~three months ended June 20, 2010 includes amortization expense of deferred financing costs of ~~$555,000 and $539,000~~$554,000. Interest expense for the three months ended ~~September~~June 30, ~~2010 and 2009, respectively.~~2011 included approximately $969,000 of allocated interest charges from our Parent.

~~Our income~~Income tax expense for the three months ended ~~September~~June 30, ~~2010~~2011 was ~~$1.6~~$3.0 million ~~on a net loss~~or 63.6% of our income before income taxes compared to an income tax benefit of ~~$4.1~~$1.6 million ~~for the three months ended September 30, 2009. The difference between the actual and expected income tax benefit as a percentage~~or 23.4% of our net loss ~~was due to an increase~~before income taxes from 2010. The change in the tax rate is principally the result of valuation allowances on losses generated in the United States and variances in withholding taxes from foreign operations as a percentage of ~~pre-tax~~pretax income in the third quarter of 2010 and the effect of nondeductible items on our domestic tax rate. The consolidated effective income tax rate, or income tax benefit rate, is affected by the profitability and effective income tax rate of our operations in foreign jurisdictions.(loss).

We had a net ~~loss~~income of ~~$2.6~~$1.7 million for the three months ended ~~September~~June 30, ~~2010,~~2011, compared to net loss of ~~$9.7~~$5.4 million for the three months ended ~~September~~June 30, ~~2009~~2010 due to the foregoing reasons.

The net loss attributed to common stockholders for the three months ended ~~September~~June 30, 2010 ~~and 2009~~ was ~~$3.2~~$6.0 million ~~and $10.3 million, respectively,~~ after $637,000 ~~and $630,000~~ in preferred stock ~~dividends, respectively.~~dividends. The preferred stock dividend ~~relates~~related to our 36,393 shares of $1,000 par value preferred shares at 7.0% ~~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 ~~three months~~quarter ended ~~September~~June 30, ~~2010~~2011 and ~~2009.~~2010. Income (loss) from operations consists of our revenues less direct costs, selling, general and administrative expenses, depreciation and amortization:

Revenues Income (Loss) from Operations
Three Months Ended Three Months Ended
September 30, September 30,
2010 2009 Change 2010 2009 Change
(in thousands)
Oilfield Services $ 56,705 $ 31,904 $ 24,801 $ 7,462 $ (4,211 ) $ 11,673
Drilling and Completion 96,295 76,299 19,996 5,125 5,508 (383 )
Rental Services 21,288 11,813 9,475 3,337 (1,218 ) 4,555
General corporate — — — (4,379 ) (3,149 ) (1,230 )

Total $ 174,288 $ 120,016 $ 54,272 $ 11,545 $ (3,070 ) $ 14,615

Revenues Income (Loss) from Operations
Successor Predecessor Successor Predecessor
Three Months
Ended Three Months
Ended Three Months
Ended Three Months
Ended
June 30, June 30, June 30, June 30,
2011 2010 Change 2011 2010 Change
(in thousands)
Revenues:

Drilling Services $ 187,969 $ 146,913 $ 41,056 $ 8,084 $ 4,551 $ 3,533
Well Services 32,169 11,731 20,438 6,653 (417 ) 7,070

Total $ 220,138 $ 158,644 $ 61,494 $ 14,737 $ 4,134 $ 10,603

~~Oilfield~~Drilling Services

Revenues for ~~our Oilfield~~the quarter ended June 30, 2011 for the Drilling Services segment were ~~$56.7~~$188.0 million, ~~for the three months ended September 30, 2010,~~ an increase of ~~77.7%,~~27.9% compared to ~~$31.9~~$146.9 million in revenues for the ~~three months~~quarter ended ~~September~~June 30, ~~2009.~~2010. Income from operations increased ~~$11.7~~$3.5 million and resulted in income from operations of ~~$7.5~~$8.1 million for the quarter ended June 30, 2011 compared to income from operations of $4.6 million in the ~~third quarter of 2010 compared~~three months ended June 30, 2010. The revenue increase was due to ~~loss from operations of $4.2 million~~our investment in ~~the third quarter of 2009. Our Oilfield Services segment revenues~~new equipment, increased utilization and ~~operating income for the third quarter of 2010 increased compared to the third quarter of 2009 due principally to~~rig rates in Argentina and Bolivia and improved pricing and utilization for our directional drilling services, underbalanced services, rental services and tubular services domestically. The increase in income from operations was mainly due to the noted revenue increases which were partially offset by: (1) allocations of merger related costs consisting of severance expense and our coiled tubing units. Our capital expenditures in the Oilfield Services segment have emphasized new downhole directional drilling equipment, upgrading coiled tubing units and investing in pressure control units to serve unconventional natural gas drilling activity. Our Oilfield Services segment activity is impacted by the rig count in the U.S. and the Baker Hughes average rig countother professional fees of $1.2 million for the ~~thirteen weeks~~three months ended June 30, 2011; (2) allocations of $1.3 million of Parent general and administration charges; (3) decrease in ~~the third quarter of 2010 was 1,626 compared to an average rig count of 977 for the thirteen weeks in the third quarter of 2009.~~

~~Drilling and Completion~~

Revenues for the quarter ended September 30, 2010 for the Drilling and Completion segment were $96.3 million, an increase of 26.2%, compared to $76.3 million in revenues for the quarter ended September 30, 2009. In spite of improved rig utilization and pricing for our land drilling rigs in Argentina and Bolivia, income from operations decreased to $5.1 million in the third quarter of 2010 compared to $5.5 million in the third quarter of 2009. This reduction was due to: (1) reduced rig utilization and rig ratesservices in Brazil; ~~(2)~~and (4) an increase of ~~$1.3~~$4.6 million, or ~~24.4%~~23.9%, in depreciation and ~~amortization; (3) increased labor and other costs~~amortization in ~~Argentina; offset by $1.1 million~~the second quarter of ~~severance costs during~~2011 compared to the ~~three months ended September 30, 2009 related to workforce reductions in Argentina as a result~~second quarter of ~~lower activity at that time.~~2010. The increase in depreciation and amortization expense was the result of capital expenditure programs and Merger related adjustments to the ~~capital spending programs over the last two years.~~fair value of intangible assets.

3133

~~Rental~~Well Services

Revenues for the quarter ended ~~September~~June 30, ~~2010~~2011 for the ~~Rental~~Well Services segment ~~increased 80.2%~~were $32.2 million, an increase of 174.2% compared to ~~$21.3 million from $11.8~~$11.7 million in revenues for the quarter ended ~~September~~June 30, ~~2009.~~2010. Income from operations increased $7.1 million and resulted in income from operations of $6.7 million for the quarter ended June 30, 2011 compared to ~~$3.3 million~~a loss from operations of $417,000 in the ~~third quarter of 2010 compared to $1.2 million operating loss in the third quarter of 2009.~~three months ended June 30, 2010. The acquisition of AWC provided our ~~Rental~~Well Services segment with ~~$6.8~~$9.7 million of additional revenues and ~~$2.4~~$2.6 million of additional operating income during the ~~third~~second quarter of ~~2010. Our Rental Services segment revenues~~2011. We also had improved utilization and ~~operating income~~pricing for our coil tubing units. Partially offsetting the third quarter of 2010 also increased compared to the prior year due to our strategy of redeploying equipment and focusing our marketing efforts from the U.S. Gulf of Mexico to the onshore unconventional natural gas fieldsimproved results in the ~~U.S. We have concentrated our capital expenditures in the Rental Services segment on equipment that is in strong demand in the unconventional gas shale plays in the U.S.~~three months ended June 30, 2011 were: (1) allocations of merger related costs consisting of severance expense and ~~therefore has high utilization and improved pricing.~~

~~General Corporate~~

~~General corporate expenses increased $1.2 million to $4.4 million~~other professional fees of $400,000 for the three months ended ~~September~~June 30, ~~2010~~2011; (2) allocations of $400,000 of Parent general and administration charges and (3) an increase of $1.1 million, or 47.6%, in depreciation and amortization in the second quarter of 2011 compared to ~~$3.1 million for~~ the ~~three months ended September 30, 2009.~~second quarter of 2010. The increase in depreciation and amortization expense was ~~due to an increase in professional fees for~~ the ~~three months ended September 30, 2009. Professional fees for the three months ended September 30, 2010 included $578,000~~result of ~~costs~~capital expenditure programs and Merger related adjustments to the ~~pending merger, $140,000~~fair value of ~~costs related to the acquisition of AWC and a $225,000 lawsuit settlement.~~intangible assets.

Comparison of ~~Nine~~Six Months Ended ~~September~~June 30, ~~2010~~2011 and ~~2009~~2010

Our revenues for the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 were ~~$473.3~~$417.7 million, an increase of ~~25.3%~~39.7% compared to ~~$377.6~~$299.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2009.~~2010. The increase in revenues is due to the increase in revenues in both of our ~~Oilfield Services and~~operating segments. Our Drilling ~~and Completion segments, offset in part by a decrease in revenues in our Rental Services segment. Our Oilfield~~ Services segment revenues increased ~~38.0%~~27.4% to ~~$146.1~~$353.3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 compared to ~~$105.8~~$277.4 million for the ~~nine~~six months ended ~~September~~June 30, ~~2009~~2010 due to our investment in new equipment, increased utilization and rig rates in Argentina and Bolivia and increased utilization of our equipment and improved pricing ~~compared~~domestically. Revenues for our Well Services segment increased 198.6% to ~~the nine months ended September 30, 2009. Our Drilling and Completion segment revenues increased 25.8% to $280.8~~$64.4 million for the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 compared to ~~$223.2~~$21.6 million for the ~~nine~~six months ended ~~September 30, 2009. The increase in revenues in our Drilling and Completion segment was~~June, 2010 due to $19.8 million of revenues from AWC in the current period, along with an increased utilization of our equipment and rig rates in Argentina and Bolivia. Revenues for our Rental Services segment decreased 4.3% to $46.5 million for the nine months ended September 30, 2010 compared to $48.6 million for the nine months ended September 30, 2009 due to decreased equipment utilization due to a decline in drilling activity in the U.S. Gulf of Mexico compared to the nine months ended September 30, 2009.improved pricing.

Our direct costs for the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 increased ~~26.7%~~36.1% to ~~$356.1 million, or 75.2% of revenues, compared to $281.1~~$310.9 million, or 74.4% of revenues, compared to $228.4 million, or 76.4%, of revenues for the ~~nine~~six months ended ~~September~~June 30, ~~2009.~~2010. Our direct costs in all of our segments increased in absolute dollars in the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 compared to the ~~nine~~six months ended ~~September~~June 30, ~~2009.~~2010. Our ~~Oilfield~~Drilling Services segment revenues for the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 increased ~~38.0%~~27.4% from revenues for the ~~nine~~six months ended ~~September~~June 30, ~~2009,~~2010, while direct costs increased ~~24.9%~~27.9% over that same period, resulting in ~~an improvement~~a minor reduction in gross margin as a percentage of revenues to ~~28.3%~~23.0% for the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 compared to ~~20.8%~~23.4% for the ~~nine~~six months ended ~~September~~June 30, ~~2009.~~2010. Our ~~Oilfield~~Drilling Services segment began to realize price increases starting in the later part of the first quarter of ~~2010. In addition, we had $1.2 million of expenses recorded during~~2010 with the ~~nine months ended September 30, 2009~~ related ~~to severance payments, the closing of unprofitable locations~~improvement being offset by a decrease in utilization and ~~downsizing other locations.~~pricing for our land drilling services in Brazil. Our Drilling and Completion segment revenues for the nine months ended September 30, 2010 increased 25.8% from revenues for the nine months ended September 30, 2009, while direct costs increased 28.8% over that same period. As a result, direct costs as a percentage of revenues increased to 82.7% for the nine months ended September 30, 2010 compared to 80.8% for the nine months ended September 30, 2009. Our RentalWell Services segment revenues for the ~~nine~~six months ended ~~September~~June 30, ~~2010 decreased 4.3%~~2011 increased 198.6% from revenues for the ~~nine~~six months ended ~~September~~June 30, ~~2009,~~2010, while direct costs increased ~~12.3%~~145.0% over that same period. ~~Gross~~The improvement in gross margin ~~as a percentage~~is due to improved utilization of equipment and pricing which was partially offset by the impact of the acquisition of AWC. AWC provided $19.8 million of revenues ~~for our Rental Services segment~~during the six months ended June 30, 2011 and it also increased direct costs by $13.0 million for the nine months ended September 30, 2010 was 59.0% compared to 65.0% for the nine months ended September 30, 2009. The AWC acquisition completed in July 2010 contributed $6.8 million in revenues and $4.1 million in direct costs to the Rental Services segment for the nine monthsame period ~~ending September 30, 2010~~ for an effective gross margin as a percentage of revenues of ~~40.6%~~34.4%. ~~Our direct costs~~AWC’s gross margin as a percentage of revenues is less than our overall Well Services gross margin percentage as AWC’s manufacturing operation has a higher labor component. Gross margin as a percentage of revenues for our Well Services segment for the ~~Rental Services segment are largely fixed because they primarily relate~~six months ended June 30, 2011 was 39.6% compared to ~~yard expenses to maintain~~26.3% for the ~~rental inventory. In addition, direct costs associated with the operations of AWC offset direct cost reductions in our other rental activities.~~six months ended June 30, 2010.

Depreciation expense increased ~~6.1%~~11.5% to ~~$61.8~~$45.4 million for the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 from ~~$58.3~~$40.7 million for the ~~nine~~six months ended ~~September~~June 30, ~~2009.~~2010. The primary increase in depreciation expense is ~~primarily~~ due to our capital expenditure programs for our Drilling ~~and Completion~~Services segment. Depreciation expense as a percentage of revenues decreased to ~~13.1%~~10.9% for the first ~~nine months~~half of ~~2010,~~2011, compared to ~~15.4%~~13.6% for the first ~~nine months~~half of ~~2009,~~2010, due to the ~~increase~~noted increases in revenues.

Selling, general and administrative expense was ~~$36.9~~$43.9 million for the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 compared to ~~$40.6~~$24.2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2009.~~2010. Selling, general and administrative expense ~~decreased~~increased primarily due to ~~a reduction~~an increase in ~~bad debt~~stock based compensation expense, severance expenses and professional and other fees for the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 compared to the ~~nine~~same period of the prior year all due principally to the Merger. Stock based compensation for the six months ended ~~September~~June 30, ~~2009~~2011 was $6.1 million with approximately $5.4 million of this amount relating to the acceleration of stock based compensation expense associated with the Merger and ~~cost reduction steps that were made~~was $3.0 million in the ~~nine~~same period of the prior year. The six months ended ~~September~~June 30, ~~2009 in response~~2011 includes approximately $4.6 million of severance expense relating to ~~market conditions, offset in part by an increase in~~ the ~~amortization~~separation of ~~share-based compensation arrangements~~certain executives after the Merger. Professional and the increase in professional fees related to transactions. During the nine months ended September 30, 2010, we recorded bad debt expense of $43,000 compared to $4.1 million in bad debt expense for the nine months ended September 30, 2009. Professionalother fees for the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 included ~~$578,000~~$7.1 million of costs related to the ~~pending merger, $140,000~~Merger. The six months ended June 30, 2011 also includes $1.7 million of ~~costs related to the acquisition of AWC and a $225,000 lawsuit settlement. Selling,~~allocated general and administrative ~~expense includes share-based compensation expense of $4.4 million in the nine months ended September 30, 2010~~expenses from our Parent and ~~$3.6 million in the nine months ended September 30, 2009.~~other increases related to additional operating activities. As a percentage of revenues, selling, general and administrative ~~expenses were 7.8%~~expense was 10.5% for the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 compared to ~~10.8%~~8.1% for the same period in the prior year.

During the ~~nine~~six months ended ~~September~~June 30, ~~2009,~~2011, we recorded a ~~$1.9~~$5.1 million loss on ~~an asset disposition from~~ the ~~total loss~~impairment of intangible assets. In connection with the Merger, a ~~rig from~~$5.1 million value was assigned to the Allis-Chalmers tradename. Following the Merger, Seawell and its subsidiaries, including us, have begun operating under the name Archer. As a ~~blow-out in our Drilling and Completion segment. The insurance proceeds~~result, it was determined that there was no material remaining value associated with the Allis-Chalmers tradename.

Amortization expense for the ~~loss were not sufficient~~six months ended June 30, 2011 increased $4.3 million to ~~cover the book value of the rig and related assets.~~

~~We had income from operations of $14.9~~$6.6 million compared to $2.3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2010,~~2010. The increase is primarily related to the amortization of intangibles recorded in connection with the merger.

Income from operations was $5.8 million for the six months ended June 30, 2011 compared to ~~a $7.8~~$3.4 million ~~loss from operations~~ for the ~~nine~~six months ended ~~September~~June 30, ~~2009, for a total increase of $22.8 million.~~2010. The increase in income from operations ~~for the nine months ended September 30, 2010 is~~was mainly due to the increase in revenues and improved ~~performance of our Oilfield Services and Drilling and Completion segments,~~margins which was partially offset by ~~a decline~~the impairment of intangible assets and increases in performance of the Rental Services segment. The nine months ended September 30, 2009 was also negatively affected by an additional $4.0 million of bad debt expense, a $1.9 million loss on an asset dispositiondepreciation, amortization and ~~$3.2 million of expenses related to severance payments, the closing of unprofitable locations~~selling, general and ~~downsizing other locations.~~administrative expenses.

Our interest expense was ~~$34.0~~$21.7 million for the ~~nine~~six months ended ~~September~~June 30, ~~2010,~~2011, compared to ~~$37.5~~$22.1 million for the ~~nine~~six months ended ~~September~~June 30, ~~2009. On June 29, 2009, we purchased approximately $74.8~~2010. Approximately $51.5 million of our ~~senior notes~~debt was paid in connection with approximately $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. At September 30, 2010 we had an outstanding loan balance under our revolving credit facility of $36.5 million, all of which had been borrowed during the ~~third quarter of 2010. We borrowed $16.5 million of the $36.5 million borrowed under our revolving credit facility on the date we acquired AWC.~~Merger. Interest expense includes amortization expense of deferred financing costs of ~~$1.7~~$366,000 and $1.1 million for the ~~nine~~six months ended ~~September~~June 30, 2011 and 2010, ~~and 2009.~~

~~During~~respectively. Interest expense for the ~~nine~~six months ended ~~September~~June 30, ~~2009, we recorded~~2011 included approximately $1.3 million of allocated interest charges from our Parent and was reduced by approximately $1.1 million in connection with debt premium amortization.

Other income was $101,000 for the six months ended June 30, 2011 compared to other expense of $1.8 million for the six months ended June 30, 2010. Results for the first half of 2010 include a ~~gain~~pre-tax non-cash loss of $26.4 million as a result of tender offers that we completed on June 29, 2009. We purchased approximately $30.6 million aggregate principal amount of our 9.0% senior notes and $44.2 million aggregate principal amount of our 8.5% senior notes for approximately $46.4 million. The gain is net of a $1.5 million ~~write-off~~on the sale of ~~debt issuance costs related to the retired notes~~an investment in a private oil and ~~we incurred approximately $466,000~~gas company that was assumed as part of an acquisition in ~~expenses related to the transactions.~~2006.

~~Our income~~Income tax ~~benefit~~expense for the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 was ~~$3.6~~$6.3 million or ~~16.9%~~(39.9)% of our net loss before income taxes compared to an income tax benefit of ~~$6.8~~$5.2 million or ~~35.5%~~25.8% of our net loss before income taxes ~~for~~from 2010. The change in the ~~nine months ended September 30, 2009. The decrease~~tax rate is principally the result of valuation allowances on losses generated in ~~income tax benefit as a percentage of our net loss was due to an increase~~the United States and variances in withholding taxes from foreign operations as a percentage of ~~pre-tax~~pretax income in 2010 and the effect of nondeductible items on our domestic tax. The consolidated effective income tax benefit rate is affected by the profitability and effective income tax rate of our operations in foreign jurisdictions.(loss).

We had a net loss of ~~$17.5~~$22.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2010,~~2011, compared to net loss of ~~$12.3~~$14.9 million for the ~~nine~~six months ended ~~September~~June 30, ~~2009~~2010 due to the foregoing reasons.

The net loss attributed to common stockholders for the ~~nine~~six months ended ~~September~~June 30, 2011 and 2010 was $22.4 and ~~2009 was $19.4~~$16.2 million after $375,000 and ~~$13.0~~$1.3 million ~~respectively, after $1.9 million and $665,000~~ in preferred stock dividends, respectively. The preferred stock dividend ~~relates~~related to our 36,393 shares of $1,000 par value preferred shares at 7.0% ~~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 ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 and ~~2009.~~2010. Income (loss) from operations consists of our revenues ~~and the loss on an asset disposition~~ less direct costs, selling, general and administrative expenses, impairment of intangible assets, depreciation and amortization:

Revenues Income (Loss) from Operations
Nine Months Ended Nine Months Ended
September 30, September 30,
2010 2009 Change 2010 2009 Change
(in thousands)
Oilfield Services $ 146,070 $ 105,827 $ 40,243 $ 7,969 $ (15,701 ) $ 23,670
Drilling and Completion 280,772 223,237 57,535 17,640 14,420 3,220
Rental Services 46,460 48,560 (2,100 ) 1,596 3,318 (1,722 )
General corporate — — — (12,278 ) (9,879 ) (2,399 )

Total $ 473,302 $ 377,624 $ 95,678 $ 14,927 $ (7,842 ) $ 22,769

Successor Predecessor
Four Months Two Months
Ended Ended
June 30, February 28, Combined Predecessor
2011 2011 2011 2010 Change
Revenues:

Drilling Services $ 247,277 $ 106,050 $ 353,327 $ 277,441 $ 75,886
Well Services 43,587 20,835 64,422 21,573 42,849

Total $ 290,864 $ 126,885 $ 417,749 $ 299,014 $ 118,735

Income (Loss) from Operations:

Drilling Services $ 8,488 $ (9,943 ) $ (1,455 ) $ 4,307 $ (5,762 )
Well Services 7,179 109 7,288 (925 ) 8,213

Total $ 15,667 $ (9,834 ) $ 5,833 $ 3,382 $ 2,451

~~Oilfield~~Drilling Services

Revenues for ~~our Oilfield~~the Drilling Services segment ~~were $146.1 million~~ for the ~~nine~~six months ended ~~September~~June 30, ~~2010,~~2011 were $353.3 million, an increase of ~~38.0%~~27.4% compared to ~~$105.8~~$277.4 million in revenues for the ~~nine~~six months ended ~~September~~June 30, ~~2009. Income~~2010. Loss from operations ~~increased $23.7~~was $1.5 million ~~and resulted in~~compared to income from operations of ~~$8.0~~$4.3 million in the ~~first nine months of 2010 compared to a loss from operations of $15.7 million in the first nine months of 2009. Our Oilfield Services segment revenues and operating income for the nine~~six months ended ~~September~~June 30, ~~2010~~2010. The revenue increase was due to

our investment in new equipment, increased ~~compared to the nine months ended September 30, 2009 due principally to~~utilization and rig rates in Argentina and Bolivia and improved pricing and utilization for our directional drilling services, underbalanced services, rental services and tubular services ~~and our coiled tubing units. Our capital expenditures~~domestically. The increase in the Oilfield Services segment have emphasized new downhole directional drilling equipment, upgrading coil tubing units and investing in pressure control units to serve unconventional natural gas drilling activity. As stated earlier our Oilfield Services segment activity is tied to the rig count in the U.S. and the Baker Hughes average rig count for the thirty-nine weeks in the first nine months of 2010 was 1,498 compared to an average rig count of 1,067 for the thirty-nine weeks in the first nine months of 2009. During the nine months ended September 30, 2009, we incurred $1.2 million of costs related to severance payments, the closing of unprofitable locations and downsizing other locations in our Oilfield Services segment. In addition, we increased our bad debt reserve by recording $3.1 million of bad debt expense for the Oilfield Services segment during the nine months ended September 30, 2009 as a result of the decreased oil and natural gas prices and the financial difficulties that some of our customers were facing. We recorded $43,000 of bad debt expense for the nine months ended September 30, 2010 for the Oilfield Services segment.

~~Drilling and Completion~~

Revenues for the nine months ended September 30, 2010 for the Drilling and Completion segment were $280.8 million, an increase of 25.8% compared to $223.2 million in revenues for the nine months ended September 30, 2009. Incomeloss from operations ~~increased to $17.6~~was mainly due to: (1) allocations of merger related costs consisting of accelerated stock based compensation expense of $3.9 million, ~~in the first nine months~~severance expense of ~~2010 compared to $14.4~~$3.4 million and professional and other fees of $5.1 million for the ~~first nine~~six months ended June 30, 2011; (2) allocations of ~~2009. This increase was due to: (1) improved rig~~$1.3 million of Parent general and administration charges; (3) decrease in utilization and ~~rig rates~~pricing for our land drilling services in ~~Argentina and Bolivia during the nine months ended September 30, 2010; (2)~~Brazil; (4) a ~~$1.9~~$2.9 million non-cash loss recorded in the ~~nine~~six months ended ~~September~~June 30, ~~2009~~2011 on an intangible asset disposition from the total loss of a rig from a blow-out; (3) $1.4 million of severance costs during the nine months ended September 30, 2009 related to workforce reductions in Argentina as a result of lower activityimpairment and (4) $329,000 of costs incurred to consolidate operating locations in Brazil during the nine months ended September 30, 2009. Partially offsetting the improved results in the first nine months of 2010 was decreased rig utilization and pricing in Brazil and(5) an increase of $7.0 million, or 18.1%, in depreciation and amortization ~~expense of $3.4 million. The increase in depreciation and amortization was the result of our capital expenditures spending programs over the last two years.~~

~~Rental Services~~

~~Revenues~~ for the ~~nine~~six months ended September 30, 2010 for the Rental Services segment were $46.5 million, a decrease of 4.3% from $48.6 million in revenues for the nine months ended September 30, 2009. Our Rental Services segment generated an operating income of $1.6 million in the nine months ended September 30, 2010 compared to $3.3 million operating income for the first nine months of 2009. The decrease in segment revenues and operating income for the first nine months of 20102011 compared to the same period of the prior ~~year~~year. The increase in depreciation and amortization expense was ~~due primarily~~the result of capital expenditure programs and Merger related adjustments to the ~~decrease~~fair value of intangible assets.

Well Services

Revenues for the Well Services segment for the six months ended June 30, 2011 were $64.4 million, an increase of 198.6% compared to $21.6 million in ~~utilization~~revenues for the six months ended June 30, 2010. Income from operations increased $8.2 million and resulted in income from operations of ~~our rental equipment due~~$7.3 million for the six months ended June 30, 2011 compared to a ~~decline in drilling activity~~loss from operations of $925,000 in the ~~U.S. Gulf of Mexico. Offsetting a portion of the impact of the decline was the~~six months ended June 30, 2010. The acquisition of AWC ~~which~~ provided our ~~Rental~~Well Services segment with ~~$6.8~~$19.8 million of additional revenues and ~~$2.4~~$4.0 million of additional operating income during the ~~nine~~first half of 2011. We also had improved utilization and pricing for our coil tubing units. Partially offsetting the improved results in the six months ended ~~September~~June 30, ~~2010. Also, our income from operations~~2011 were: (1) allocations of merger related costs consisting of accelerated stock based compensation expense of $1.5 million, severance expense of $1.2 million and professional and other fees of $2.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2009 included $950,000~~2011; (2) allocations of ~~bad debt expense to~~$400,000 of Parent general and administration charges (3) a $2.2 million non-cash loss recorded in the six months ended June 30, 2011 on an intangible asset impairment and (4) an increase ~~the bad debt reserve for Rental Services segment customers who were facing financial difficulties,~~of $2.0 million, or 44.8%, in depreciation and ~~$237,000 of costs related to closing a rental yard and reducing our workforce. We recorded no bad debt expense for~~amortization in the first ~~nine months~~half of 2011 compared to the first half of 2010. ~~In addition,~~The increase in depreciation and amortization expense ~~for our Rental Services segment decreased $651,000 or 2.9%, in~~was the ~~first nine months~~result of ~~2010 compared~~capital expenditure programs and Merger related adjustments to the ~~first nine months of 2009 due primarily to a $584,000 reduction in the carrying~~fair value of ~~our airplane resulting from the sales proceeds received in April 2009.~~

~~General Corporate~~

General corporate expenses increased $2.4 million to $12.3 million for the nine months ended September 30, 2010 compared to $9.9 million for the nine months ended September 30, 2009. The increase was due to the increase in share-based compensation expense, increased professional fees related to transactions and increased insurance and travel costs to support our international business development initiatives. Share-based compensation expense included in general corporate expenses was $3.4 million in the nine months ended September 30, 2010 compared to $2.8 million in the nine months ended September 30, 2009. Professional fees for the nine months ended September 30, 2010 included $578,000 of costs related to the pending merger, $140,000 of costs related to the acquisition of AWC and a $225,000 lawsuit settlement.intangible assets.

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 was used to purchase an aggregate of $74.8 million principal amount of our existing senior notes, approximately $35.0 million of the proceeds was used to repay all the borrowings under our revolving bank credit facility, except for $5.1 million in outstanding letters of credit, and the remainder of the proceeds was used 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~~Parent contributions 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 September 30, 2010, we had $49.5 million available for borrowing under our amended and restated revolving credit facility. Our cash on hand, cashCash flows from operations ~~and revolving credit facility have been and~~ are expected ~~to continue~~ to be our primary source of liquidity in ~~2010.~~fiscal 2011. We had cash and cash equivalents and restricted cash of ~~$15.3~~$17.2 million at ~~September~~June 30, ~~2010~~2011 compared to ~~$41.1~~$20.9 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.2010.

Operating Activities

During the ~~nine~~six months ended ~~September~~June 30, ~~2010,~~2011, our operating activities provided ~~$26.9~~$21.0 million in cash. Our net loss for the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 was ~~$17.5~~$22.0 million. Non-cash expenses totaled ~~$61.5~~$62.5 million during the first ~~nine~~six months of 2011 consisting of $52.0 million of depreciation and amortization, $5.1 million on an impairment of intangible assets, $6.1 million for share based compensation expense, $366,000 in amortization of deferred financing fees, $587,000 loss on sale of property and equipment net of $1.1 million of debt premium amortization and $799,000 for deferred income taxes related to timing differences.

During the six months ended June 30, 2011, changes in operating assets and liabilities used $19.5 million in cash, principally due to an increase in accounts receivable of $30.9 million, an increase in inventories of 7.9 million, an increase in prepaid expenses and other assets of $9.6 million, offset by an increase in accounts payable of $14.7 million, an increase in accrued expenses of $11.5 million and an increase in accrued salaries, benefits and payroll taxes of $2.7 million. Accounts receivable, inventory, accounts payable, accrued expense and accrued salaries, benefits and payroll taxes increases primarily related to the increase in our activity in the first six months of 2011. The increase in prepaid expenses primarily relates to additional prepaid taxes in Argentina and Brazil.

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 ~~$65.4~~$43.0 million of depreciation and amortization, ~~$4.4~~$3.0 million for ~~share-based~~share based compensation expense, ~~$1.7~~$1.1 million in amortization of debt issuance costs, $1.5 million loss on the sale of an investment, ~~$150,000~~$0.8 million of losses from asset disposals, ~~$409,000~~$260,000 equity in loss of unconsolidated affiliates, partly offset by deferred income tax benefit of ~~$12.0~~$10.8 million related to timing differences.

due to an increase in accounts receivable of ~~$30.4~~$25.8 million, an increase in ~~inventories~~inventory of ~~$2.7 million, a decrease in accrued interest of $8.9~~$2.4 million and a decrease in other long-term liabilities of ~~$0.7 million,~~$466,000, offset in part by an increase in accounts payable of ~~$8.4~~$10.8 million, a decrease in prepaid expenses and other current assets of ~~$8.0~~$8.8 million, an increase in accrued expenses of ~~$5.5~~$3.8 million, an increase in accrued salaries, benefits and payroll taxes of ~~$2.4~~$1.9 million and a decrease in other assets of ~~$1.3~~$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 ~~nine~~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, offset by a non-cash increase in prepaid expenses from the financing of $2.6 million of insurance premiums. Accrued interest decreased due to the scheduled interest payment on our senior notes in July of 2010.

During the nine months ended September 30, 2009, our operating activities provided $37.5 million in cash. Our net loss for the nine months ended September 30, 2009 was $12.3 million. Non-cash expenses totaled $34.4 million during the first nine months of 2009 consisting of $61.8 million of depreciation and amortization, $3.6 million for share-based compensation expense, $1.7 million in amortization of debt issuance costs, $4.1 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, $11.1 million for deferred income taxes related to timing differences and $1.2 million on the gain from asset disposals.

During the nine months ended September 30, 2009, changes in operating assets and liabilities provided $15.4 million in cash, principally due to a decrease in accounts receivable of $59.5 million, a decrease of $3.9 million in inventories and a decrease in prepaid expenses and other current assets of $3.3 million, offset in part by a decrease in accounts payable of $29.0 million, a decrease in accrued interest of $12.5 million and a decrease in accrued expenses of $11.6 million. Accounts receivable, inventory and accounts payable decreased primarily due to the drop in our activity in the first nine 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 semi-annual payment of interest on our senior notes. 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 nine months of 2009.

Investing Activities

During the ~~nine~~six months ended ~~September 30, 2010,~~June 31, 2011, we used ~~$76.4~~$50.4 million in investing activities, consisting of ~~$50.9~~$48.3 million for capital expenditures, ~~$18.2~~$3.8 million ~~net for the acquisition~~increase in restricted cash relating to deposits at a financial institution to secure outstanding letters of ~~AWC, $13.0~~credit and a $1.2 million ~~for other assets,~~cash contribution into our investment in our Saudi Arabia joint venture, offset ~~in part~~ by ~~$5.3~~$2.9 million of proceeds from equipment ~~sales and $368,000 from the sale of an investment.~~sales. Included in the ~~$50.9~~$48.3 million for capital expenditures ~~was $18.4 million for our Oilfield Services segment, $20.2~~were $41.5 million for additional equipment in our Drilling ~~and Completion~~Services segment and ~~$11.6~~$6.8 million for ~~drill pipe and other~~additional equipment ~~used~~ in our ~~Rental~~Well Services segment. ~~The increase in other assets was primarily due to $12.7 million of advance payments made toward the construction of two drilling rigs.~~ A majority of our equipment sales relate to items “lost in hole” or “damaged beyond repair” by our customers.

During the ~~nine~~six months ended ~~September~~June 30, ~~2009,~~2010, we used ~~$49.4~~$38.1 million in investing activities, consisting of ~~$67.3~~$31.0 million for capital expenditures, ~~$1.1~~$10.1 million ~~of additional investments, offset in part by a decrease of $7.1 million in~~for other assets, ~~$8.0~~offset by $2.6 million of proceeds from equipment sales and ~~$3.9 million in insurance proceeds for a drilling rig destroyed by a blow-out.~~$368,000 from the sale of an investment. Included in the ~~$67.3~~$31.0 million for capital expenditures ~~was $9.4~~were $27.2 million for our ~~Oilfield~~Drilling Services segment ~~$37.2 million for our two domestic drilling rigs~~ and ~~$13.6~~$3.8 million for additional equipment in our ~~Drilling and Completion segment and $7.0 million for drill pipe and other equipment used in our Rental~~Well Services segment. We contributed $2.4 million of cash and cash expenditures into our investment in our Saudi Arabia joint venture and we received $1.3 million from insurance proceeds related to a pre-acquisition contingency with respect to BCH. The ~~decrease~~increase in other assets was primarily due to $10.0 million of advance payments made toward the ~~conversion~~construction of ~~deposits on equipment purchases into capital expenditures for the~~a drilling ~~rigs and assets used in our directional drilling services.~~rig. A majority of our equipment sales relate to items “lost in hole” or “damaged beyond repair” by our customers. ~~We also transferred $1.6 million of rental assets as part of our investment in our Saudi Arabia joint venture in a non-cash transaction.~~

Financing Activities

During the ~~nine~~six months ended ~~September~~June 30, 2011, financing activities provided $21.9 million in cash. In connection with the Merger, we received approximately $71.4 million in funding from our Parent. Proceeds were mainly used to pay off debt, debt related interest and merger related expenses. The merger related expenses were primarily for legal and professional fees and change of control provisions. An additional $3.0 million in funding was subsequently received from our Parent. We repaid $50.1 million in borrowings under long-term debt facilities. We had a net cash outlay of $1.8 million related to the payment of payroll taxes as a result of net exercises of restricted stock vestings and paid $637,000 in preferred stock dividends.

During the six months ended June 30, 2010, financing activities ~~provided $23.8~~used $6.9 million in cash. We borrowed ~~$36.5 million under our revolving credit facility and borrowed an additional~~ $4.0 million under a long-term debt facility and repaid ~~$14.6~~$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 ~~$1.9~~$1.3 million in preferred stock dividends. In addition, we financed our renewal of ~~$2.6 million in insurance policy premiums and issued $2.0 million of our common stock in the acquisition of AWC in non-cash transactions.~~

During the nine months ended September 30, 2009, financing activities provided $46.7 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 $61.5 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 $15.1 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 $3.2$2.4 million in insurance policy premiums in non-cash transactions.

At ~~September~~June 30, ~~2010,~~2011, we had ~~$520.7~~$461.6 million in outstanding indebtedness, of which ~~$497.1~~$454.7 million was long-term debt and ~~$23.6~~$6.9 million is due within one year.

Merger and based on actively traded prices of our senior notes, we increased the fair value of the 8.5% senior notes to $1,070 per $1,000 principal amount. In May 2011, pursuant to the terms of change of control provisions in the indentures governing the senior notes and as a result of the Merger, we purchased $92,000 aggregate principal of our 8.5% senior notes for a total consideration of $1,010 per $1,000 principal amount.

We ~~have~~had a $90.0 million revolving line of credit with a final maturity date of April 26, 2012 pursuant to a revolving credit agreement that ~~contains~~contained customary events of default and financial covenants and ~~limits~~limited 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.~~United States. We were in compliance with all debt covenants as of ~~September 30, 2010 and~~ December 31, ~~2009.~~2010. As of ~~September 30,~~December 31, 2010, we had ~~outstanding borrowing of~~ $36.5 million of borrowings outstanding and ~~$4.0~~$4.1 million in outstanding letters of credit under our revolving credit facility. As of December 31, 2009, the only usage of our revolving credit facility consisted of $4.2 million in outstanding letters of credit. The interest rate under our revolving credit facility is based on prime or LIBOR plus a margin. The credit agreement loan rates are based on prime or LIBOR plus a margin. The weighted-average interest rate was ~~7.9%~~7.8% at ~~September 30,~~December 31, 2010. The revolving line of credit was repaid and terminated in connection with the Merger.

As part of our acquisition of ~~BCH Ltd, or~~ BCH, we assumed a $23.6 million term loan credit facility with a bank. The ~~BCH~~ credit agreement iswas dated June 2007 and ~~contains~~contained customary events of default and financial covenants which ~~are~~were based on BCH’s stand-alone financial statements. The facility was repayable in quarterly principal installments plus interest and was to mature in August 2012. Obligations under the facility ~~are~~were secured by substantially all of the BCH assets. ~~BCH was in compliance with all debt covenants as of December 31, 2009.~~ The bank ~~has~~ waived certain financial ratio covenants for the ~~September 30, 2010 and~~ December 31, 2010 measurement ~~periods. As~~period and we ~~cannot be certain that BCH would attain compliance with the covenants within one year, we have~~ classified the entire outstanding balance of the loan in the current portion of long-term debt. The ~~facility is repayable in quarterly principal installments plus interest with the final payment due not later than August 2012. The~~ interest rates ~~under this credit facility are~~were based on LIBOR plus a ~~margin. At September 30, 2010~~margin and the interest rate was 3.5% at December 31, ~~2009, the~~2010. The outstanding amount of the loan ~~under this credit facility~~as of December 31, 2010 was ~~$11.8 million and $16.2 million, respectively and the interest rate was 3.5%.~~

~~On May 22, 2009, we drew down $25.0 million on a~~$7.0 million. The term loan credit facility was paid in full in connection 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 September 30, 2010 and December 31, 2009, the outstanding amount of the loan was $20.8 million and $23.4 million, respectively.Merger.

In 2010, we obtained insurance premium financings in the aggregate amount of ~~$2.6~~$2.9 million with a fixed weighted-average interest rate of 4.8%. Under terms of the agreements, amounts outstanding are paid over an eight and 11 month repayment schedules. The outstanding balance of these notes was approximately $1.5 million at September 30, 2010. In 2009, we obtained insurance premium financings in the aggregate amount of $3.2 million with a fixed weighted-average 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~~$1.0 million at ~~September~~June 30, ~~2010~~2011 and December 31, ~~2009,~~2010, respectively.

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 $16,000 and $254,000 at September 30, 2010 and December 31, 2009, respectively.

~~Recent Events~~

In August 2010, we announced that our Board of Directors had approved a definitive merger agreement with Seawell in a transaction valued at approximately $890.0 million. The combined company would operate its Drilling and Well Services offerings with a global footprint covering more than 30 of the world’s key oil and natural gas regions, including the U.S., Gulf of Mexico, Brazil, Argentina, North Sea, Middle East, Africa and Southeast Asia/Pacific. The combined Drilling Services offering would include platform drilling, land contract drilling, modular rigs, maintenance of drilling systems, directional drilling technology, underbalanced drilling, facility engineering services, rig and riser inspections and oilfield rentals. The Well Services offering would include electrical and mechanical wireline services, production logging services, coil tubing services, ultrasonic investigation logging services, down-hole cameras and advanced well fishing services.

~~The merger is subject to the approval of our stockholders as well as other customary conditions. We anticipate that the transaction will close in early 2011.~~

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 have $3.8 million of outstanding letters of credit that are secured by deposits at a financial institution. We do not guarantee obligations of any unconsolidated entities. At September 30, 2010 we had a $90.0 million revolving line of credit with a maturity of April 2012. At September 30, 2010, we had $36.5 million of borrowings under the revolving credit facility and we had $4.0 million in outstanding letters of credit.

policies affect our reported and expected financial results. No material changes to such information have occurred during the ~~nine~~six months ended ~~September~~June 30, ~~2010.~~2011.

Recently Issued Accounting Standards

For a discussion of new accounting standards, see the applicable section in Note 1 to our Unaudited Consolidated Condensed 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:

	•		~~our ability to consummate the merger;~~

	•		~~the possibility that the merger may involve unexpected costs;~~

	•		~~difficulties and delays in satisfying the conditions set forth in the merger agreement, including obtaining the necessary regulatory approvals for the merger;~~

	•		~~the effect of the announcement or completion of the merger on customer and supplier relationships, operating results and business generally;~~

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

	•		~~risks that the merger disrupts current plans and operations, and the potential difficulties for employee retention as a result of the announcement or completion of the merger;~~

	•		~~fluctuations in the price of oil and natural gas;~~

	•		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 ~~changes in existing,~~current and ~~the imposition of new, laws and governmental regulations;~~future laws;

	•		the ~~outcome~~impact of ~~any pending or future litigation~~customer defaults and ~~administrative claims;~~related bad debt expense;

	•		the potential impairment in the carrying value of goodwill and other acquired intangible assets;

	•		the risks associated with doing business outside the United States, including currency exchange rates; 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.~~consequences

~~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 rates.~~

~~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 $64.2 million of adjustable rate debt with a weighted-average interest rate of 6.2% at September 30, 2010.

~~Foreign Currency Exchange Rate Risk.~~

We have designated the U.S. dollar as the functional currency for our operations in international locations since 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 Operations in the line item labeled Other income (expense).

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)~~15d — 15(e) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Management recognizes that any disclosure controls and procedures no matter how well designed and operated, can only provide reasonable assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. 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 September~~for the period ending June 30, ~~2010,~~2011, our disclosure controls and procedures ~~are~~were not effective atto provide a reasonable assurance ~~level~~regarding the reliability of financial reporting and the preparation of financial statements for external purposes in ~~ensuring~~accordance with generally accepted accounting principles because of a material weakness in our internal control over financial reporting described below.

Material Weakness in Internal Control over Financial Reporting

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the ~~information required~~Company’s annual or interim financial statements will not be prevented or detected on a timely basis. Based on this assessment, management has concluded that we did not maintain effective internal control over financial reporting for the period ending June 30, 2011, because of a material weakness relating to accounting for income taxes. Specifically, we did not maintain effective controls over the identification and proper accounting treatment of the calculation and valuation of deferred tax assets. This material weakness resulted in a material misstatement of our income tax expense, deferred tax asset, net loss and accumulated deficit with accompanying notes and the restatement of our consolidated financial statements for the year ended December 31, 2010 as discussed in Note 2 to the consolidated financial statements included in our Form 10-K/A. Additionally, this deficiency could result in misstatements of the aforementioned accounts and disclosures that would result in a material misstatement of the consolidated financial statements that would not be ~~disclosed by us in reports filed~~prevented or ~~submitted~~detected.

Plan for Remediation of Material Weakness

Management has developed a plan to remediate the material weakness noted above. Controls over the preparation of tax calculations and associated deferred tax balances have been enhanced through the implementation of external advisory services from an independent source, under the ~~Exchange Act is recorded, processed, summarized~~oversight of management. In the third quarter the Company has hired a dedicated employee with tax expertise to oversee this area, along with enhanced procedural and ~~reported within the time periods specified in the Securities and Exchange Commission’s, or 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 or submit 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.review controls.

(b) ~~Change~~Changes in Internal Control Over Financial Reporting.

~~There have~~Except as described above, there were 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 1. LEGAL PROCEEDINGS.~~

Shortly following the announcement of the merger agreement, ten putative stockholder class-action petitions and compliants were filed against various combinations of us, members of our board of directors, Seawell, and Wellco. Seven of the lawsuits were filed in the District Court of Harris County, Texas, which we refer to as the Texas Actions, and three lawsuits were filed in the Court of Chancery of the State of Delaware, which we refer to as the Delaware Actions. These lawsuits challenge the proposed merger and generally allege, among other things, that our directors have breached their fiduciary duties owed to our public stockholders by approving the proposed merger and failing to take steps to maximize our value to our public stockholders, that we, Seawell, and Wellco aided and abetted such breaches of fiduciary duties, and that the merger agreement unreasonably dissuades potential suitors from making competing offers and restricts us from considering competing offers. The lawsuits generally seek, among other things, compensatory damages, attorneys’ and experts’ fees, declaratory and injunctive relief concerning the alleged breaches of fiduciary duties, and injunctive relief prohibiting the defendants from consummating the merger.

Various plaintiffs in the Texas Actions filed competing motions to consolidate the suits, to appoint their counsel as interim class counsel and to compel expedited discovery. On September 16, 2010, the defendants filed joint motions to stay the Texas Actions in favor of a first-filed Delaware lawsuit, and opposing the motions for expedited discovery. There is no hearing date set for these motions.

On September 21, 2010, the plaintiffs in the Delaware Actions wrote the court seeking consolidation of the Delaware cases. Defendants did not oppose consolidation and took no position regarding lead plaintiff. On September 29, 2010, the Delaware court granted the motion to consolidate. Previously, on September 16, 2010, Seawell and Wellco answered the first-filed Girard Complaint, which is the operative complaint post-consolidation. We answered the consolidated complaint on October 4, 2010.

~~We believe all of these lawsuits are without merit and intend to defend them vigorously.~~

~~ITEM 1A. RISK FACTORS.~~

~~Except as set forth in the following 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, including the potential enactment of further restrictions or regulations on offshore drilling, could have a material adverse effect on our business.

On April 20, 2010, a fire and explosion occurred onboard the semisubmersible drilling rig Deepwater Horizon, which was owned by Transocean Ltd. and under contract to a subsidiary of BP plc. The accident resulted in the loss of life and a significant oil spill. In response to this incident, the Minerals Management Service of the U.S. Department of Interior, or the MMS, issued a notice on May 30, 2010 implementing a six-month moratorium on certain drilling activities in the U.S. Gulf of Mexico. The notice also stated that the MMS would not consider drilling permits for new wells and related activities for specified water depths during the six-month moratorium period. In addition entities in the process of drilling wells covered by the moratorium were required to halt drilling and take steps to secure the well. On June 22, 2010, the U.S. District Court for the Eastern District of Louisiana issued a preliminary injunction prohibiting the enforcement of the moratorium, which the Department of the Interior appealed to the Fifth Circuit Court of Appeals. On July 8, 2010, the court of appeals denied the government’s request that the district court’s order be stayed while the appeal is pending.

Our business has historically been very dependent on drilling activity in the U.S. Gulf of Mexico. Although the moratorium on oil and natural gas drilling in the U.S. Gulf of Mexico has been lifted, the BOEM is expected to continue to issue new guidelines and may take other steps that could increase the costs of exploration and production, reduce the area of operations and result in permitting delays. These may include new or additional bonding and safety requirements and other requirements regarding certification of equipment. The enactment of stricter restrictions on offshore drilling or further regulation of offshore drilling or contracting services operations could materially affect our business, financial condition and results of operations.

~~We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition and results of operations.~~

We provide services and equipment to oil and natural gas exploration and production companies. These operations are subject to inherent hazards that can cause personal injury or loss of life, damage to or destruction of property, equipment, the environment and marine life, and suspension of operations. Substantially all of our Drilling and Completion operations are subject to hazards that are customary for oil and natural gas drilling operations, including blowouts, reservoir damage, loss of well control, cratering, oil and gas well fires and explosions, natural disasters, pollution and mechanical failure. Any of these risks could result in damage to or destruction of drilling equipment, personal injury and property damage, suspension of operations or environmental damage.

We operate with our customers through Master Service Agreements, or MSAs. We endeavor to allocate potential liabilities and risks between the parties in the MSAs. Generally, our MSAs contain indemnification to us for liability for pollution or environmental claims arising from subsurface conditions or resulting from the drilling activities of our customers or their operators. We may have liability in such cases if we are grossly negligent or commit willful acts. In addition, any liability may be capped for either party to an MSA. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death, unless resulting from our gross negligence or willful misconduct. Similarly, we agree to indemnify our customers for liabilities arising from personal injury or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers agree to indemnify us for loss or destruction of customer-owned property or equipment, and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. However, for equipment we rent to our customers, our contracts generally provide that the customer is responsible for the replacement of any damaged or lost equipment in their care. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation or we might incur an unforeseen liability falling outside the scope of such allocation.

Litigation arising from an accident at a location where our products or services are used or provided may cause us to be named as a defendant in lawsuits asserting potentially large claims. We maintain customary insurance to protect our business against these potential losses. Our general liability policy would cover claims where we agreed to indemnify the customer, subject to any typical exclusions that may exist under the policy. However, we could become subject to material uninsured liabilities that could have a material adverse effect on our financial condition and results of operations. The limits and deductibles for our general liability policy are as follows:

	•		~~General Aggregate $2,000,000;~~

	•		~~Products/Completed Operations Aggregate $2,000,000;~~

	•		~~Occurrence Limit $1,000,000;~~

	•		~~Personal/Advertising Injury Limit $1,000,000;~~

	•		~~Deductible (Bodily Injury & Property Damage Combined) Per Claim $100,000.~~

In addition, our general liability policy is scheduled under a $30.0 million umbrella/excess liability policy (subject to the policy’s terms, conditions and exclusions). We also have workers compensation insurance coverage up to $1,000,000.

We have a contractors pollution liability policy of $10.0 million which has a $200,000 deductible, and all environmental claims would be subject to the terms, conditions and exclusions of that policy. Our umbrella policy does not apply to the contractors pollution liability policy.

There is no assurance that such insurance or indemnification agreements will adequately protect us against liability from all of the consequences of the hazards and risks described above. The occurrence of an event not fully insured or for which we are not indemnified against, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, there can be no assurance that insurance will continue to be available to cover any or all of these risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future so as to make the cost of such insurance prohibitive.

~~Risks Related to the Merger~~

Our ability to complete the merger is subject to stockholder approval, certain closing conditions and the receipt of consents and approvals from government entities which may impose conditions that could adversely affect us or cause the merger to be abandoned.

The merger is subject to certain closing conditions, including approval of the merger by our stockholders, the absence of injunctions or other legal restrictions and that no material adverse effect shall have occurred to either company. In addition, we will be unable to complete the merger until approvals are received from various governmental entities. Regulatory agencies may impose certain requirements or obligations as conditions for their approval. The merger may require us or Seawell to accept conditions from these regulators that could adversely impact the combined company. We can provide no assurance that we will satisfy the various closing conditions and that the necessary approvals will be obtained or that any required conditions will not materially adversely affect the combined company following the merger. In addition, we can provide no assurance that these conditions will not result in the abandonment or delay of the merger.

~~Failure to complete the merger or delays in completing the merger could negatively effect us.~~

If the merger is not completed, our ongoing businesses and the market price of our common stock may be adversely affected and we will be subject to several risks, including having to pay certain costs relating to the merger, and diverting the focus of management from pursuing other opportunities that could be beneficial to us, in each case, without realizing any of the benefits of having the merger completed.

In addition, while the merger is pending, certain of our customers may delay or defer purchasing decisions, which could negatively impact our revenues, earnings and cash flows regardless of whether the merger is completed. Uncertainty about the effect of the merger could also cause employees, suppliers, partners, regulators and customers to act in a manner that would have an adverse effect on us. Additionally, we have agreed to refrain from taking certain actions with respect to our business and financial affairs during the pendency of the merger, which restrictions could be in place for an extended period of time if completion of the merger is delayed and thus could adversely affect our financial condition, results of operations or cash flows.

~~We have and will continue to incur transaction costs in connection with the merger.~~

We have incurred, and expect to continue to incur, significant costs in connection with the merger, including the fees of our respective professional advisors. Seawell will also incur integration and restructuring costs following the completion of the merger as our operations are integrated with Seawell’s operations. The efficiencies anticipated to arise from the merger may not be achieved in the near term or at all, and, if achieved, may not be sufficient to offset the costs associated with the merger. Unanticipated costs, or the failure to achieve expected efficiencies, may have an adverse impact on the results of operations of the combined company following the completion of the merger.

~~Following the merger, the combined company may be unable to successfully integrate our business into Seawell’s business and realize the anticipated benefits of the merger.~~

The merger involves the combination of two companies that currently operate as independent public companies. The combined company will be required to devote management attention and resources to integrating its business practices and operations. Potential difficulties that the combined company may encounter in the integration process include the following:

	•		the inability to successfully integrate our business into Seawell’s business in a manner that permits the combined company to achieve the cost savings and operating synergies anticipated to result from the merger, which would result in the anticipated benefits of the merger not being realized partly or wholly in the time frame currently anticipated or at all;

	•		~~integrating personnel from the two companies while maintaining focus on providing consistent, high quality products and customer service;~~

	•		~~potential unknown liabilities and unforeseen increased expenses, delays or regulatory conditions associated with the merger; and~~

	•		~~performance shortfalls at one or both of the two companies as a result of the diversion of management’s attention caused by completing the merger and integrating the companies’ operations.~~

In addition, Seawell and Allis-Chalmers have each operated and, until the completion of the merger, will continue to operate, independently. It is possible that the integration process could result in the diversion of each company’s management attention, the disruption or interruption of, or the loss of momentum in, each company’s ongoing businesses or inconsistencies in standards, controls, procedures and policies, any of which could adversely affect our ability to maintain relationships with customers, suppliers and employees or our ability to achieve the anticipated benefits of the merger, or could reduce the earnings or otherwise adversely affect the business and financial results of the combined company.

~~We may be unable to attract or retain both current and potential key employees during the pendency of the merger.~~

In connection with the pending merger, our current and prospective employees may experience uncertainty about their future roles with the combined company following the merger, which may materially adversely affect our ability to attract and retain key personnel during the pendency of the merger. Key employees may depart because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company following the merger. Accordingly, no assurance can be given that we will be able to retain key employees to the same extent that we have been able to in the past.

~~Multiple lawsuits have been filed against us challenging the merger, and an adverse ruling in any such lawsuit may prevent the merger from being completed.~~

Subsequent to the announcement of the merger, ten putative class-actions petitions and complaints were commenced on behalf of our stockholders against us and our directors, and in certain cases against Seawell and Wellco, each challenging the merger. One of the conditions to the closing of the merger is that no law, order, injunction, judgment, decree, ruling or other similar requirement shall be in effect that prohibits the completion of the merger. Accordingly, if any of the plaintiffs is successful in obtaining an injunction prohibiting the completion of the merger, then such injunction may prevent the merger from becoming effective, or from becoming effective within the expected timeframe.

~~ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.~~

On July 12, 2010, we issued 1,000,000 shares of our common stock to Richard T. Mitchell, the seller in our acquisition of 100% of the equity interest in American Well Control, Inc. The transaction was exempt from the registration requirements of the Securities Act pursuant to Section 4(2) of the Securities Act as a transaction by the issuer not involving any public offering.

ITEM 6. EXHIBITS

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

SIGNATURES

Pursuant to the requirements of 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 ~~November 5, 2010.~~August 31, 2011.


	~~Allis-Chalmers Energy Inc.~~
	~~(Registrant)~~Allis-Chalmers Energy Inc.
				(~~/s/ Munawar H. Hidayatallah~~Registrant)

	~~Munawar H. Hidayatallah~~/s/ Christoph Bausch
	Christoph Bausch
	Chief ~~Executive~~Financial Officer ~~and Chairman~~

4441

EXHIBIT INDEX


~~2.1~~		Agreement and Plan of Merger, dated as of August 12, 2010, by and among Seawell Limited, Wellco Sub Company and Allis-Chalmers Energy Inc. (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 8-K filed on August 13, 2010).

~~2.2~~		Amendment Agreement, dated as of October 1, 2010, to Agreement and Plan of Merger, dated as of August 12, 2010, by and among Seawell Limited, Wellco Sub Company and Allis-Chalmers Energy Inc. (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 8-K filed on October 5, 2010).

~~4.1~~		Fourth Amendment to Investment Agreement, dated as of 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).

~~4.2~~		Fifth Amendment to Investment Agreement, dated as of September 27, 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 September 30, 2010).

~~10.1~~		Executive Employment Agreement, dated effective as of August 1, 2010, by and between Allis-Chalmers Energy Inc. and Victor M. Perez (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed on August 17, 2010).

~~10.2~~		Executive Employment Agreement, dated effective as of August 1, 2010, by and between Allis-Chalmers Energy Inc. and Theodore F. Pound III (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed on August 17, 2010).

~~10.3~~		Executive Employment Agreement, dated effective as of August 1, 2010, by and between Allis-Chalmers Energy Inc. and Terrence P. Keane (incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8-K filed on August 17, 2010).

~~10.4~~		Executive Employment Agreement, dated effective as of August 1, 2010, by and between Allis-Chalmers Energy Inc. and Mark Patterson (incorporated by reference to Exhibit 10.4 to the Registrant’s Form 8-K filed on August 17, 2010).

~~10.5~~		Executive Employment Agreement, dated effective as of August 1, 2010, by and between Allis-Chalmers Directional Drilling Services LLC and David K. Bryan (incorporated by reference to Exhibit 10.5 to the Registrant’s Form 8-K filed on August 17, 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.

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document


*		Filed herewith

4542


	~~PAGE~~
PART I ~~FINANCIAL INFORMATION~~

~~Item~~ 1. Financial Statements

Consolidated Condensed Balance Sheets as of ~~September~~June 30, ~~2010~~2011 (Successor Company) and December ~~31, 2009~~31,2010 (Predecessor Company)		3

Consolidated Condensed Statements of Operations for the three and ~~nine~~four months ended ~~September~~June 30, 2011 (Successor Company), two months ended February 28, 2011, three and six months ended June 30, 2010 ~~and 2009~~(Predecessor Company)		4

Consolidated Condensed Statement of Stockholders’ Equity as of June 30, 2011(Successor Company), February 28, 2011 and December 31, 2010 (Predecessor Company)		5

Consolidated Condensed Statements of Cash Flows for the ~~nine~~four months ended ~~September~~June 30, 2011 (Successor Company), two months ended February 28, 2011 and six months ended June 30, 2010 ~~and 2009~~(Predecessor Company)		56

Notes to Unaudited Consolidated Condensed Financial Statements		67

~~Item~~ 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		2731

~~Item 3. Quantitative and Qualitative Disclosures about Market Risk~~		40

~~Item~~ 4. Controls and Procedures		40

PART II ~~OTHER INFORMATION~~

~~Item 1. Legal Proceedings~~6. Exhibits		41

~~Item 1A. Risk Factors~~Signatures		41

~~Item 2. Unregistered Sales of Equity Securities and Use of Proceeds~~		44

~~Item 6. Exhibits~~		44

~~Signatures~~		44
EX-31.1
EX-31.2
EX-32.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT


	As of				Successor		Predecessor
	September 30,		December 31,		June 30,		December 31,
	2010		2009		2011		2010
Goodwill:
Oilfield Services	$	23,250	$	23,250
Drilling and Completion		17,389		17,389
Rental Services		5,534		—
Goodwill:
Drilling Services					$	206,441	$	40,639
Well Services						60,987		5,694

Total goodwill					$	267,428	$	46,333


Assets:
Drilling Services					$	1,145,427	$	940,481
Well Services						159,167		97,788

Total assets					$	1,304,594	$	1,038,269
	$	46,173	$	40,639


Assets:
Oilfield Services	$	256,828	$	255,899
Drilling and Completion		472,059		441,482
Rental Services		315,827		307,283
General corporate		58,423		75,956


	$	1,103,137	$	1,080,620


Long Lived Assets:
Long Lived Assets:
United States	$	579,173	$	572,727	$	623,198	$	501,117
Argentina		165,290		168,681		293,721		167,137
Brazil		89,970		82,477		65,456		86,949
Other international		62,989		58,487		60,775		65,753

Total long lived assets					$	1,043,150	$	820,956

	$	897,422	$	882,372


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Revenues	$	174,288		$	120,016		$	473,302		$	377,624

Operating costs and expenses
Direct costs		127,622			90,763			356,060			281,136
Depreciation		21,094			19,709			61,799			58,261
Selling, general and administrative		12,772			11,430			36,949			40,595
Loss on asset disposition		—			—			—			1,916
Amortization		1,255			1,184			3,567			3,558

Total operating costs and expenses		162,743			123,086			458,375			385,466


Income (loss) from operations		11,545			(3,070	)		14,927			(7,842	)

Other income (expense)
Interest expense		(11,881	)		(10,764	)		(33,986	)		(37,492	)
Interest income		45			39			499			53
Gain on debt extinguishment		—			—			—			26,365
Other		(661	)		37			(2,479	)		(231	)


Total other income (expense)		(12,497	)		(10,688	)		(35,966	)		(11,305	)


Loss before income taxes		(952	)		(13,758	)		(21,039	)		(19,147	)

Provision for income taxes		(1,614	)		4,108			3,563			6,802


Net loss		(2,566	)		(9,650	)		(17,476	)		(12,345	)

Preferred stock dividend		(637	)		(630	)		(1,911	)		(665	)


Net loss attributed to common stockholders	$	(3,203	)	$	(10,280	)	$	(19,387	)	$	(13,010	)


Net loss per common share:
Basic	$	(0.04	)	$	(0.14	)	$	(0.27	)	$	(0.27	)
Diluted	$	(0.04	)	$	(0.14	)	$	(0.27	)	$	(0.27	)

Weighted average shares outstanding:
Basic		72,207			70,945			71,506			47,834
Diluted		72,207			70,945			71,506			47,834


	Successor						Predecessor
	Three Months			Four Months			Two Months			Three Months			Six Months
	Ended			Ended			Ended			Ended			Ended
	June 30,			June 30,			February 28,			June 30,			June 30,
	2011			2011			2011			2010			2010
Revenues	$	220,138		$	290,864		$	126,885		$	158,644		$	299,014

Operating costs and expenses:
Direct costs		162,628			213,764			97,130			120,723			228,438
Depreciation		23,030			30,346			15,026			20,517			40,705
Selling, general and administrative		15,386			20,177			23,752			12,114			24,177
Impairment of intangible assets		—			5,100			—			—			—
Amortization		4,357			5,810			811			1,156			2,312

Total operating costs and expenses		205,401			275,197			136,719			154,510			295,632


Income (loss) from operations		14,737			15,667			(9,834	)		4,134			3,382


Other income (expense):
Interest expense		(10,067	)		(13,813	)		(7,854	)		(11,149	)		(22,105	)
Interest income		8			11			5			299			454
Other		(34	)		(21	)		122			(303	)		(1,818	)

Total other expense		(10,093	)		(13,823	)		(7,727	)		(11,153	)		(23,469	)


Income (loss) before income taxes		4,644			1,844			(17,561	)		(7,019	)		(20,087	)

Income tax benefit (expense)		(2,955	)		(4,536	)		(1,736	)		1,640			5,177


Net income (loss)		1,689			(2,692	)		(19,297	)		(5,379	)		(14,910	)

Preferred stock dividend		—			—			(375	)		(637	)		(1,274	)


Net income (loss) attributed to common stockholders	$	1,689		$	(2,692	)	$	(19,672	)	$	(6,016	)	$	(16,184	)


									Capital in			Retained			Total
	Preferred Stock				Common Stock				Excess of			Earnings			Stockholders’
	Shares		Amount		Shares		Amount		Par Value			(Deficit)			Equity
Predecessor

Balances, December 31, 2010		36,393	$	34,183		73,722,347	$	737	$	429,924		$	(53,520	)	$	411,324

Net loss		—		—		—		—		—			(19,297	)		(19,297	)
Preferred stock dividend		—		—		—		—		—			(375	)		(375	)

Issuance of common stock:
Issuance under stock plans, net of tax		—		—		650,727		7		(1,828	)		—			(1,821	)

Stock-based compensation		—		—		—		—		6,084			—			6,084


Balances, February 28, 2011		36,393	$	34,183		74,373,074	$	744	$	434,180		$	(73,192	)	$	395,915

Successor

Capitalization at merger		—	$	—		1,000	$	—	$	600,885		$	—		$	600,885

Net loss		—		—		—		—		—			(2,692	)		(2,692	)


Balances, June 30, 2011		—	$	—		1,000	$	—	$	600,885		$	(2,692	)	$	598,193


Current assets	$	237,873
Property and equipment		682,406
Intangible assets, including goodwill		373,227
Other long-term assets		4,949

Total assets acquired		1,298,455
Current liabilities		148,360
Long-term liabilities		549,210

Merger net assets	$	600,885


Current assets	$	7,745	$	7,585
Property and equipment		2,756		2,756
Intangible assets, including goodwill		11,589		11,749
Other long-term assets		2		2

Total assets acquired		22,092		22,092
Current liabilities		444		1,527
Long-term liabilities		181		1,401

Net assets acquired	$	21,467	$	19,164


				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 September 30, 2010		1,752,018		$	4.74		7.86	$	0.85


Exercisable at September 30, 2010		586,432		$	7.08		4.90	$	0.14


				Weighted-Average
				Grant-Date Fair
	Number of Shares			Value Per Share
Nonvested at December 31, 2009		837,626		$	15.63
Granted		2,061,750			3.78
Vested		(335,787	)		17.48
Forfeited		(3,333	)		3.77

Nonvested at September 30, 2010		2,560,256		$	5.86


				Weighted
				Average Grant-
				Date Fair Value
	Number of Shares			Per Share
Nonvested at December 31, 2010		1,702,067		$	6.09
Granted		—			—
Vested		(1,702,067	)		6.09
Forfeited		—			—

Nonvested at June 30, 2011		—		$	—


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


	Successor				Predecessor
	Three Months Ended		Four Months Ended		Two Months Ended			Three Months Ended			Six Months Ended
	June 30,		June 30,		February 28,			June 30,			June 30,
	2011		2011		2011			2010			2010
Revenues:
Drilling Services	$	187,969	$	247,277	$	106,050		$	146,913		$	277,441
Well Services		32,169		43,587		20,835			11,731			21,573

Total revenues	$	220,138	$	290,864	$	126,885		$	158,644		$	299,014


Operating Income (Loss):
Drilling Services	$	8,084	$	8,488	$	(9,943	)	$	4,551		$	4,307
Well Services		6,653		7,179		109			(417	)		(925	)

Total income (loss) from operations	$	14,737	$	15,667	$	(9,834	)	$	4,134		$	3,382


Depreciation and Amortization Expense:
Drilling Services	$	24,023	$	31,777	$	13,792		$	19,393		$	38,581
Well Services		3,364		4,379		2,045			2,280			4,436

Total depreciation and amortization expense	$	27,387	$	36,156	$	15,837		$	21,673		$	43,017


Capital Expenditures:
Drilling Services	$	17,012	$	21,619	$	19,939		$	17,417		$	27,187
Well Services		1,493		3,953		2,819			1,814			3,802

Total capital expenditures	$	18,505	$	25,572	$	22,758		$	19,231		$	30,989


Revenues:
United States	$	93,595	$	126,735	$	57,651		$	59,795		$	106,923
Argentina		106,100		137,318		57,458			76,640			149,025
Brazil		9,306		12,004		5,250			10,502			20,002
Other international		11,137		14,807		6,526			11,707			23,064

Total revenues	$	220,138	$	290,864	$	126,885		$	158,644		$	299,014


	Revenues						Income (Loss) from Operations
	Three Months Ended						Three Months Ended
	September 30,						September 30,
	2010		2009		Change		2010			2009			Change
					(in thousands)
Oilfield Services	$	56,705	$	31,904	$	24,801	$	7,462		$	(4,211	)	$	11,673
Drilling and Completion		96,295		76,299		19,996		5,125			5,508			(383	)
Rental Services		21,288		11,813		9,475		3,337			(1,218	)		4,555
General corporate		—		—		—		(4,379	)		(3,149	)		(1,230	)


Total	$	174,288	$	120,016	$	54,272	$	11,545		$	(3,070	)	$	14,615


	Revenues							Income (Loss) from Operations
	Nine Months Ended							Nine Months Ended
	September 30,							September 30,
	2010		2009		Change			2010			2009			Change
	(in thousands)
Oilfield Services	$	146,070	$	105,827	$	40,243		$	7,969		$	(15,701	)	$	23,670
Drilling and Completion		280,772		223,237		57,535			17,640			14,420			3,220
Rental Services		46,460		48,560		(2,100	)		1,596			3,318			(1,722	)
General corporate		—		—		—			(12,278	)		(9,879	)		(2,399	)


Total	$	473,302	$	377,624	$	95,678		$	14,927		$	(7,842	)	$	22,769