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		3927-~~0126090~~33212
(State or other jurisdiction of		(I.R.S. Employer
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
incorporation or organization)		Identification No.)
11125 Equity Drive, Suite 200, HOUSTON, TEXAS		77041
5075 WESTHEIMER, SUITE 890, HOUSTON, TEXAS		77056
(Address of principal executive offices)		(Zip Code)

(713) ~~369~~856-~~0550 Registrant’s telephone number, including area code~~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. Yes þ No o

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

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

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. As of August 26, 2011, all of the 1,000 issued and outstanding shares of Allis-Chalmers Energy Inc. are held by Archer Limited.

At Allis-Chalmers ~~November 1,~~Energy ~~2010~~Inc. ~~there~~meets ~~were~~the ~~73,426,715~~conditions ~~shares~~set forth in general instruction H(1)(a) and (b) of ~~common~~Form ~~stock,~~10-Q ~~par~~and ~~value~~is ~~$0.01~~therefore ~~per~~filing ~~share, outstanding~~this Form 10-Q with the reduced disclosure format.

ALLIS-CHALMERS ENERGY INC.

FORM 10-Q

For the Quarterly Period Ended ~~September~~June 30, ~~2010~~2011

TABLE OF CONTENTS

	PAGE
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Condensed Balance Sheets as of September 30, 2010 and December 31, 2009		3
Consolidated Condensed Statements of Operations for the three and nine months ended September 30, 2010 and 2009		4
Consolidated Condensed Statements of Cash Flows for the nine months ended September 30, 2010 and 2009		5
Notes to Unaudited Consolidated Condensed Financial Statements		6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
Item 3. Quantitative and Qualitative Disclosures about Market Risk		40
Item 4. Controls and Procedures		40
PART II OTHER INFORMATION
Item 1. Legal Proceedings		41
Item 1A. Risk Factors		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

ITEM


PART I
1. Financial Statements
Consolidated Condensed Balance Sheets as of June 30, 2011 (Successor Company) and December 31,2010 (Predecessor Company)			3

Consolidated Condensed Statements of Operations for the three and four months ended June 30, 2011 (Successor Company), two months ended February 28, 2011, three and six months ended June 30, 2010 (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 four months ended June 30, 2011 (Successor Company), two months ended February 28, 2011 and six months ended June 30, 2010 (Predecessor Company)			6

Notes to Unaudited Consolidated Condensed Financial Statements			7

2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			31

4. Controls and Procedures			40

PART II
6. Exhibits			41

Signatures			41
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

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALLIS-CHALMERS ENERGY INC. ~~CONSOLIDATED CONDENSED BALANCE SHEETS (in thousands, except for share and per share amounts)~~

	September 30,		December 31,
	2010		2009
	(unaudited)
Assets
Cash and cash equivalents	$	15,322	$	41,072
Trade receivables, net		140,123		105,059
Inventories		38,993		34,528
Deferred income tax asset		2,649		3,790
Prepaid expenses and other		8,628		13,799
Total current assets		205,715		198,248
Property and equipment, net		732,857		746,478
Goodwill		46,173		40,639
Other intangible assets, net		35,138		32,649
Debt issuance costs, net		8,073		9,545
Deferred income tax asset		34,736		22,047
Other assets		40,445		31,014
Total assets	$	1,103,137	$	1,080,620
Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	23,624	$	17,027
Trade accounts payable		43,361		34,839
Accrued salaries, benefits and payroll taxes		25,319		22,854
Accrued interest		6,917		15,821
Accrued expenses		27,674		21,918
Total current liabilities		126,895		112,459
Long-term debt, net of current maturities		497,100		475,206
Deferred income tax liability		8,087		8,166
Other long-term liabilities		452		1,142
Total liabilities		632,534		596,973
Commitments and contingencies
Stockholders’ Equity
Preferred stock, $0.01 par value (25,000,000 shares authorized; 36,393 shares issued and outstanding at 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
Capital in excess of par value		429,146		422,823
Retained earnings		6,540		25,927
Total stockholders’ equity		470,603		483,647
Total liabilities and stockholders’ equity	$	1,103,137	$	1,080,620

CONSOLIDATED CONDENSED BALANCE SHEETS

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


	Successor			Predecessor
	June 30,			December 31,
	2011			2010
	(unaudited)
Assets
Cash and cash equivalents	$	13,416		$	20,940
Restricted cash		3,784			—
Trade receivables, net		174,380			144,960
Inventories		50,026			42,140
Deferred income tax asset		1,104			81
Prepaid expenses and other		18,734			9,192

Total current assets		261,444			217,313

Property and equipment, net		675,581			723,234
Goodwill		267,428			46,333
Other intangible assets, net		94,890			33,899
Debt issuance costs, net		—			7,405
Deferred income tax asset		—			1,969
Other assets		5,251			8,116


Total assets	$	1,304,594		$	1,038,269


Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	6,892		$	15,215
Trade accounts payable		60,760			46,042
Accrued salaries, benefits and payroll taxes		35,525			32,790
Accrued interest		15,199			15,524
Accrued expenses		41,912			30,676

Total current liabilities		160,288			140,247

Deferred income tax liability		16,989			8,240
Long-term debt, net of current maturities		454,689			478,225
Payable to parent		74,403			—
Other long-term liabilities		32			233

Total liabilities		706,401			626,945

Commitments and Contingencies

Stockholders’ Equity
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		600,885			429,924
Accumulated deficit		(2,692	)		(53,520	)

Total stockholders’ equity		598,193			411,324


Total liabilities and stockholders’ equity	$	1,304,594		$	1,038,269

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

ALLIS-CHALMERS ENERGY INC. ~~CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS (in thousands, except per share amounts) (unaudited)~~

	For the Three Months Ended						For the 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

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(In thousands)

(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 OF CASH FLOWS (in thousands) (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

CONSOLIDATED CONDENSED STATEMENT OF STOCKHOLDERS’ EQUITY

(In thousands, except share amounts)

(unaudited)


									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.

~~NOTES~~CONSOLIDATED TOCONDENSED ~~UNAUDITED~~STATEMENTS ~~CONSOLIDATED~~OF ~~CONDENSED~~CASH ~~FINANCIAL~~FLOWS (In ~~STATEMENTS~~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 of the oil and natural gas service industry: ~~Oilfield~~Well Services; ~~Drilling~~ and ~~Completion~~Drilling ~~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

On August 12, 2010, we entered into a merger agreement with Seawell Limited, or Seawell, pursuant to which we will merge with and into a wholly owned subsidiary of Seawell. Completion of the merger is subject 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.

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 related 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 such as our senior notes.

Basis of Presentation

~~Our~~On ~~unaudited~~February 23, ~~consolidated~~2011, ~~condensed~~Allis-Chalmers ~~financial~~Energy ~~statements~~Inc., ~~included~~a ~~herein~~Delaware ~~have~~corporation, ~~been~~completed ~~prepared~~its merger (the “Merger”) with and into Wellco Sub Company (“Wellco”), a Delaware corporation and wholly owned subsidiary of Seawell Limited (“Seawell”), with Wellco continuing as the surviving entity under the name Allis-Chalmers Energy Inc. The Merger was effected pursuant to the ~~rules~~Agreement and ~~regulations~~Plan of Merger, ~~the~~dated ~~Securities~~as of August 10, 2010, by and ~~Exchange~~among ~~Commission~~Allis-Chalmers, orSeawell ~~SEC.~~and Wellco, as amended by ~~Accordingly~~the Amendment Agreement, ~~certain~~dated ~~information~~as ~~and~~of ~~disclosures~~October 10, ~~normally~~2010, ~~included~~by inand ~~financial~~among ~~statements~~Allis-Chalmers, ~~prepared~~Seawell and inWellco ~~accordance~~(as ~~with~~so ~~generally~~amended, ~~accepted~~the ~~accounting~~“Merger ~~principles~~Agreement”). ~~have~~Following ~~been~~the ~~condensed~~Merger, Seawell began operating under the name Archer Limited (“Archer” or ~~omitted~~“Parent”). ~~We believe~~As ~~that~~of the ~~presentations~~Merger ~~and~~date, ~~disclosures~~our ~~herein~~assets ~~are~~and liabilities ~~adequate~~have been adjusted to ~~make~~their fair values (see Note 2) based on the ~~information~~purchase ~~not~~price ~~misleading.~~resulting ~~The~~in ~~unaudited~~changes ~~consolidated~~to ~~condensed~~depreciation, ~~financial~~amortization ~~statements~~and ~~reflect~~interest ~~all~~in ~~adjustments (consisting~~the ofsuccessor ~~normal~~period; ~~recurring~~therefore, the ~~adjustments)~~financial ~~necessary~~information for athe ~~fair~~period ~~presentation~~subsequent ofto the ~~interim periods.~~Merger ~~These~~is ~~unaudited~~not ~~consolidated~~fully ~~condensed~~comparable. The financial statements ~~should~~and beaccompanying ~~read~~footnotes inhave ~~conjunction with~~been ~~our~~separated ~~audited~~with ~~consolidated~~a ~~financial~~black ~~statements~~line ~~included~~to inpresent pre-merger ~~our~~activity ~~Annual~~as ~~Report~~the on“Predecessor” ~~Form~~company 10and post-Kmerger ~~for~~ activity as the ~~year~~“Successor” company. ~~ended~~“Predecessor” ~~December 31,~~refers ~~2009.~~to ~~The~~the ~~results~~operations of ~~operations~~Allis-Chalmers ~~for~~prior to the ~~interim~~consummation ~~periods~~of ~~are not~~the ~~necessarily~~Merger ~~indicative~~and of“Successor” refers to the ~~results~~operations of ~~operations~~Allis-Chalmers subsequent to bethe ~~expected~~Merger. The Merger date for ~~the~~accounting ~~full~~purposes ~~year~~has been designated as March 1, 2011.

6Our 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 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, 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)

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Future events and their effects cannot be perceived with certainty. Accordingly, our accounting estimates require the exercise of judgment. While management believes that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. Estimates are used for, but are not limited to, determining the following: allowance for doubtful accounts; recoverability of long-lived assets and intangibles; useful lives used in depreciation and amortization; stock-based compensation; income taxes and valuation allowances. The accounting estimates used in the preparation of the consolidated financial statements may change as new events occur, as more experience is acquired, as additional information is obtained or as our operating environment changes.

Financial Instruments

Financial instruments consist of cash and cash equivalents, accounts receivable and payable and debt. The carrying value of cash and cash equivalents and accounts receivable and payable approximate fair value due to their short-term nature. We believe the fair values and the carrying value of our debt, excluding the senior notes, would not be materially different due to the instruments’ interest rates approximating market rates for similar borrowings at September 30, 2010. Our senior notes, in the approximate aggregate amount of $430.2 million, trade “over the counter” in limited amounts and on an infrequent basis. Based on recent trades we estimate the fair value of our senior notes to be approximately $432.9 million at September 30, 2010. The price at which our senior notes trade is based on many factors such as the level of interest rates, the economic environment, the outlook for the oilfield services industry and the perceived credit risk.

Reclassification

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

In October 2009, the FASB issued authoritative guidance that amends earlier guidance addressing the accounting for contractual arrangements in which an entity provides multiple products or services (deliverables) to a customer. The amendments address the unit of accounting for arrangements involving multiple deliverables and how arrangement consideration should be allocated to the separate units of accounting, when applicable, by establishing a selling price hierarchy for determining the selling price of a deliverable. The selling price used for each deliverable will be based on vendor-specific objective evidence if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific nor third-party evidence is available. The amendments also require that arrangement consideration be allocated at the inception of an arrangement to all deliverables using the relative selling price method. 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 changes the disclosure requirements for fair value measurements. Specifically, the changes require a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers. The changes also clarify existing disclosure requirements related to how assets and liabilities should be grouped by class and valuation techniques used for recurring and nonrecurring fair value measurements. We adopted this guidance in the first quarter 2010, which did not have a material effect on our financial position, results of operations or cash flows.

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

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

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

~~NOTE~~Financial 2–instruments ~~ACQUISITION~~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 June 30, 2011. Our senior notes, in the approximate aggregate amount of $446.6 million, trade “over the counter” in limited amounts and on an infrequent basis. In connection with the Merger, the recorded fair value of our senior notes was increased by $19.3 million based on the traded value at 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.

OnRecent ~~July 12,~~Accounting ~~2010, we acquired American Well Control, Inc., or AWC, for a total consideration of~~Pronouncements approximately $21.5 million, which included approximately $19.5 million in cash and 1.0 million shares of our common stock. AWC is a leading manufacturer of premium high-pressure valves used in hydraulic fracturing in the unconventional gas shale plays. The following table summarizes the preliminary allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):

Current assets	$	7,745
Property and equipment		2,756
Intangible assets, including goodwill		11,589
Other long-term assets		2
Total assets acquired		22,092
Current liabilities		444
Long-term liabilities		181
Net assets acquired	$	21,467

We consider all newly issued but not yet adopted accounting pronouncements applicable to our operations and the preparation of our consolidated condensed financial statements. We do not believe that any issued accounting pronouncements not yet adopted by us will have a material impact on our consolidated condensed financial statements.

~~AWC’s~~NOTE ~~historical~~2 ~~property~~— ~~and~~BUSINESS ~~equipment values were increased by approximately $27,000 based on~~COMBINATIONS third-party valuations. Goodwill of $5.5 million was recognized for this acquisition and was calculated as the excess of the consideration transferred over the fair value of the 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 $5.6 million assigned to customer lists, $400,000 to trade name and $55,000 to non-competes. None of the intangibles are tax deductible. The amortizable intangibles have a weighted-average useful life of 9.9 years. We do not expect any material differences from the preliminary allocation of the purchase price. AWC’s financial results since the acquisition are included in our Rental Services segment.

~~NOTE~~Merger 3with ~~— STOCK-BASED COMPENSATION~~Archer

WePursuant ~~recognize all share-based payments~~ to ~~employees~~the ~~and~~Merger, ~~directors~~each inoutstanding ~~the~~share ~~financial~~of ~~statements~~common ~~based on~~stock ~~their~~of ~~grant~~Allis-~~date~~Chalmers ~~fair~~was ~~values.~~converted ~~We utilize~~ into the ~~Black-Scholes~~right ~~model~~ to ~~determine~~receive ~~fair~~either ~~value,~~$4.25 ~~which incorporates~~cash ~~assumptions~~or ~~to value stock-based awards~~1.15 ~~The~~fully ~~dividend~~paid ~~yield~~and onnonassessable ~~our~~Archer common ~~stock is~~shares. ~~assumed~~The tofair bevalue ~~zero~~of astotal weconsideration ~~have~~was ~~historically~~approximately ~~not~~$600.9 million ~~paid~~with ~~dividends~~approximately on95% ~~our~~of Allis-Chalmers ~~common~~stockholders ~~stock~~electing ~~and~~to ~~have~~receive ~~no current~~97.1 million ~~plans~~Archer tocommon doshares so in the ~~future.~~Merger ~~The~~and the ~~expected~~remainder ~~volatility~~receiving isan ~~based~~aggregate onof ~~historical~~approximately ~~volatility~~$18 million ~~of our~~in ~~common stock~~cash. The ~~risk-free~~following ~~interest~~table summarizes ~~rate is~~ the ~~related~~preliminary ~~United~~allocation ~~States~~of ~~Treasury yield curve for periods within~~ the ~~expected~~purchase ~~term~~price ofto the ~~option~~estimated atfair ~~the~~value ~~time~~ of ~~grant. We estimate forfeiture~~the ~~rates~~assets ~~based~~at onMerger ~~our~~(in ~~historical experience.~~thousands):

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


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

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

Our historical property and equipment values were decreased by $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 debt was based on actively traded prices and changes in other assets and liabilities were based on third-party valuations or other market based approaches. Goodwill of $267.4 million was recognized for this acquisition and was calculated as the excess of the consideration transferred over the fair value of the 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 weighted-average useful life of 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 32 — ~~STOCK-BASED~~BUSINESS ~~COMPENSATION~~COMBINATIONS (Continued)

~~Our~~Acquisition ~~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~~AWC 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.

AOn ~~summary~~July 12, of2010, ~~our~~we ~~stock~~acquired ~~option~~American ~~activity~~Well ~~during~~Control, ~~the~~Inc., ~~nine~~or ~~months~~AWC, ~~ended~~for ~~September~~a total consideration of approximately $19.2 30million, ~~2010~~which included approximately $17.2 million in cash and ~~related~~1.0 million ~~information~~shares of our common stock. AWC is asa ~~follows~~leading manufacturer of premium high-pressure valves used in hydraulic fracturing in the unconventional gas shale plays. The following table summarizes the allocation of the purchase price to the estimated fair value of the assets acquired at the date of acquisition (in thousands):

				Weighted		Weighted-
Current assets	$	7,585
	Shares			Average		Average		Aggregate
Property and equipment		2,756
	Under			Exercise		Contractual		Intrinsic Value
Intangible assets, including goodwill		11,749
	Option			Price		Life (Years)		(millions)
Other long-term assets		2
Balance at December 31, 2009		701,732		$	6.31
Total assets acquired		22,092
Granted		1,072,253			3.78
Current liabilities		1,527
Canceled		(21,967	)		8.30
Long-term liabilities		1,401
Exercised		—
Net assets acquired	$	19,164
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~~AWC’s ~~aggregate~~historical ~~intrinsic~~property ~~value~~and inequipment ~~the~~values ~~table~~were ~~above~~increased ~~represents~~by ~~the~~approximately ~~total~~$27,000 ~~pre~~based on third-~~tax~~party ~~intrinsic~~valuations. ~~value~~Goodwill ~~(the~~of $5.7 million was recognized for this acquisition and was ~~difference~~calculated ~~between~~as the ~~closing~~excess ~~price~~ of ~~our~~the ~~common~~consideration ~~stock~~transferred onover the ~~last~~fair ~~trading~~value ~~day~~ of the ~~third~~net assets ~~quarter~~acquired. ofIt ~~2010~~includes the expected synergies and ~~the~~other ~~exercise~~benefits ~~price,~~that ~~multiplied~~we bybelieve will result from the ~~number~~combined ofoperations ~~in-the-money~~and ~~options)~~intangible assets that ~~would~~ ~~have~~do ~~been~~not ~~received~~qualify byfor ~~the~~separate ~~option~~recognition ~~holders~~such ~~had~~as assembled ~~all~~workforce. ~~option~~Other ~~holders~~intangible ~~exercised~~assets ~~their~~included ~~options~~approximately ~~on September~~$5.6 30million assigned to customer lists, ~~2010~~$400,000 to trade name and $55,000 to non-competes. Goodwill is not tax deductible. The amortizable intangibles have a weighted-average useful life of 9.9 years.

~~Restricted~~NOTE ~~stock~~3 ~~awards,~~— orSTOCK-BASED ~~RSAs, activity during the nine months ended September 30, 2010 were as~~COMPENSATION ~~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

Under the Merger Agreement, 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 deemed to have lapsed and each restricted share was deemed to be an unrestricted share of our common stock. Our Incentive Stock Plans were terminated in connection with the Merger. Our net loss for the two months ended February 28, 2011 includes approximately $6.1 million of compensation costs related to share-based payments with approximately $5.4 million of this amount relating to the acceleration of stock based compensation expense associated with the Merger.

We ~~determine~~recognize ~~the~~all ~~fair value of RSAs~~ share-based onpayments ~~the~~to ~~market~~employees ~~price~~and ofdirectors ~~our~~in ~~common~~the ~~stock~~financial statements based on ~~the~~their grant-date ~~of grant~~fair values. ~~Compensation~~We ~~cost~~utilize ~~for~~the ~~RSAs~~Black-Scholes ismodel ~~primarily~~to ~~recognized~~determine onfair avalue, ~~straight-line basis over the~~which ~~vesting~~incorporates orassumptions ~~service~~to ~~period~~value ~~and~~stock-based isawards. ~~net~~The ofdividend ~~forfeitures.~~yield ~~During~~on ~~the~~our ~~nine~~common ~~months~~stock ~~ended~~is ~~September 30,~~assumed ~~2010,~~to webe ~~granted~~zero ~~1,237,750~~as ~~performance-based~~we ~~RSAs~~have tohistorically ~~executive~~not ~~officers~~paid dividends and ~~key employees~~have ~~that~~no ~~vest~~current ~~upon~~plans ~~meeting~~to ~~certain~~do ~~financial~~so ~~performance conditions over~~ in the ~~next five years~~future. InThe ~~connection~~expected ~~with~~volatility ~~performance-based RSAs, compensation cost~~ is based on ~~the estimated~~historical ~~number~~volatility of ~~shares~~our ~~expected~~common ~~to be issued~~stock. ~~As of September 30, 2010, there was $7.1 million~~The ofrisk-free ~~total~~interest ~~unrecognized~~rate ~~compensation~~is ~~cost~~the related toUnited ~~nonvested~~States ~~RSAs.~~Treasury Weyield ~~expect~~curve ~~approximately~~for ~~$1.1 million~~periods towithin bethe expected ~~recognized~~term ~~over~~of the ~~remainder~~option ofat ~~2010~~the ~~and~~time ~~approximately~~of $2grant.~~3 million,~~ ~~$1.3 million, $1.2 million,~~We ~~$1.1 million~~estimate ~~and~~forfeiture ~~$88,000~~rates tobased beon ~~recognized during the years ended 2011 through 2015,~~our ~~respectively~~historical experience.

The following summarizes the Black-Scholes model assumptions used for the options granted in the three and six months ended June 30, 2010 (no options were granted during the three and six months ended June 30, 2011):


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

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

NOTE 43 — ~~INVENTORIES~~STOCK-BASED COMPENSATION (Continued)

~~Inventories~~A ~~consisted~~summary of ~~the~~our ~~following~~stock ~~(in~~option ~~thousands)~~activity and related information is as follows:

	September 30,			December 31,
				Weighted
	2010			2009
	Shares			Average
Manufactured
	Under			Exercise
Finished goods	$	3,814		$	2,983
	Option			Price
Work in process		2,099			2,299
Balance at December 31, 2010		1,751,018		$	4.74
Raw materials		2,355			884
Granted		—			—
Total manufactured		8,268			6,166
Converted at Merger		(1,750,018	)		4.74
Rig parts and related inventory		11,991			10,654
Exercised		(1,000	)		1.23
Shop supplies and related inventory		8,621			7,762
Outstanding at June 30, 2011		—			—
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~~Restricted 5—stock ~~GOODWILL~~awards, ~~AND~~or ~~INTANGIBLE~~RSAs, ~~ASSETS~~activity during the three months ended June 30, 2011 is as follows:

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 million and $40.6 million at September 30, 2010 and December 31, 2009, respectively.


				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		—		$	—

~~Definite-lived~~NOTE ~~intangible~~4 ~~assets~~— ~~that~~GOODWILL ~~continue~~AND toINTANGIBLE ~~be amortized relate to our purchase of~~ASSETS customer-related and marketing-related intangibles, patents and non-compete agreements. These intangibles have useful lives ranging from three to 20 years. Amortization of intangible assets for the three and nine months ended September 30, 2010 were $1.3 million and $3.6 million, respectively, compared to $1.2 million and $3.6 million for the same periods in the prior year. At September 30, 2010, intangible assets totaled $35.1 million, net of $16.4 million of accumulated amortization.

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 was $267.4 million and $46.3 million at June 30, 2011 and December 31, 2010, respectively.

Definite-lived intangible assets that continue to be amortized relate to our purchase of customer-related and marketing-related intangibles patents and backlogs. These intangibles have useful lives ranging from four months to twenty years. Amortization of intangible assets for the three and four months ended June, 2011 and two months ended February 28, 2011 was $4.4 million, $5.8 million and $811,000, respectively, compared to $1.2 million and $2.3 million for the three and six months ended June 30, 2010, respectively. In connection with the 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 June 30, 2011, intangible assets totaled $94.9 million, net of $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 — ~~DEBT~~INVENTORIES

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

	September 30,		December 31,
	Successor		Predecessor
	2010		2009
	June 30,		December 31,
Senior notes	$	430,238	$	430,238
	2011		2010
Revolving line of credit		36,500		—
Manufactured
Term loans		52,484		60,744
Finished goods	$	5,319	$	4,238
Insurance premium financing		1,486		997
Work in process		3,849		2,990
Capital lease obligations		16		254
Raw materials		5,138		3,600
Total debt		520,724		492,233
Total manufactured		14,306		10,828
Less: current maturities		23,624		17,027
Rig parts and related inventory		13,582		11,565
Long-term debt, net of current maturities	$	497,100	$	475,206
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

~~Senior~~NOTE ~~notes,~~6- ~~line~~INCOME ~~of credit agreements and term loans~~TAXES

OnIn ~~January 18,~~accordance ~~2006~~with ~~and~~generally ~~August 14,~~accepted ~~2006~~accounting principles, we ~~closed~~estimate onthe ~~private~~full-year ~~offerings,~~effective tax torate ~~qualified~~from ~~institutional buyers~~continuing ~~pursuant~~operations toand ~~Rule 144A~~apply ~~under~~this ~~the~~rate ~~Securities~~to ~~Act~~our ofyear-to-date ~~1933,~~income offrom ~~$160~~continuing operations.0 ~~and~~In ~~$95.0 million aggregate~~addition, ~~principal~~we ~~amount~~separately ofcalculate ~~our~~the ~~senior~~tax ~~notes,~~impact ~~respectively.~~of ~~The~~unusual ~~senior~~items, ~~notes~~if ~~are~~any. ~~due January 15,~~The ~~2014~~consolidated ~~and~~effective ~~bear~~tax ~~interest~~rate atfor ~~9.0%.~~the ~~The~~two ~~proceeds~~months ~~were~~ended ~~used~~February 28, to2011, ~~fund~~three ~~the~~and ~~acquisitions~~four ~~of Specialty~~months ~~Rental~~ended ~~Tools~~June 30, ~~Inc.~~2011 ~~and~~was ~~DLS Drilling~~(9.9)%, ~~Logistics~~63.6% &and ~~Services Company~~246.0%, ~~or DLS~~respectively, compared to ~~repay~~23.4% ~~existing debt~~ and 25.8% for ~~general~~the three ~~corporate~~and ~~purposes.~~six Onmonths ended June 2930, ~~2009,~~2010. weThe ~~closed~~fluctuations onin athe ~~tender~~tax ~~offer~~rates inare ~~which~~principally wethe ~~purchased~~result ~~approximately~~of ~~$30.6 million~~valuation ~~aggregate~~allowances ~~principal~~on ~~amount~~losses ofgenerated ~~our~~in ~~9.0%~~the ~~senior~~United ~~notes~~States ~~for~~and avariances in ~~total~~withholding ~~consideration~~taxes offrom ~~$650~~foreign ~~per~~operations ~~$1,000~~as ~~principal~~a ~~amount~~percentage of pretax income (loss).

InIncome ~~January~~(loss) ~~2007,~~before weincome ~~closed~~taxes 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 wewas ~~incurred~~subject to ~~finance~~United ~~our~~States ~~acquisition~~and ofnon-United ~~substantially~~States ~~all the~~income ~~assets~~taxes ofwas ~~Oil~~as &follow ~~Gas Rental Services, Inc. On June 29, 2009, we closed on a tender offer~~ (in ~~which~~thousands): ~~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.~~

We have 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 customary events of default and financial covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends or make other distributions, create liens and sell assets. On April 9, 2009, we amended our revolving credit agreement to modify the leverage and interest coverage ratio covenants. Effective December 31, 2009, we again amended the leverage and interest coverage ratio covenants of the revolving credit agreement. This amendment relaxed the required financial ratios for the quarter ended December 31, 2009 and for each of the quarters in 2010. Our obligations under the amended and restated credit agreement are secured by substantially all of our assets located in the U.S. We were in compliance with all debt covenants as of September 30, 2010 and December 31, 2009. As of September 30, 2010, we had $36.5 million of borrowings outstanding and $4.0 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% at September 30, 2010.


	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	)

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

On February 15, 2008, through our DLS subsidiary, we entered into a $25.0 million import finance facility with a bank. Borrowings under this facility were used to fund a portion of the purchase price of the new drilling and service rigs ordered for our Drilling and Completion segment. The loan is repayable over four years in equal semi-annual installments beginning one year after each disbursement with the final principal payment due not later than March 15, 2013. The import finance facility is unsecured and contains customary events of default and financial covenants and limits DLS’ ability to incur additional indebtedness, make capital expenditures, create liens and sell assets. We were in compliance with all debt covenants as of September 30, 2010 and December 31, 2009. The bank loan rates are based on LIBOR plus a margin. The weighted-average interest rate was 4.3% and 4.4% at September 30, 2010 and December 31, 2009, respectively. The outstanding amount under the import finance facility as of September 30, 2010 and December 31, 2009 was $15.5 million and $20.1 million, respectively.

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

NOTE 6- —INCOME ~~DEBT~~TAXES (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~~income ~~credit~~tax ~~agreement~~provision isconsists ~~dated June 2007 and contains customary events~~ of ~~default and financial covenants which are based on BCH’s stand-alone financial statements. Obligations under~~ the ~~facility~~following ~~are secured by substantially all of the BCH assets. BCH was~~ (in ~~compliance with~~thousands): 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 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 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, 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 outstanding amount of the loan was $20.8 million and $23.4 million, respectively.


	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	)

~~On February 9, 2010, through our DLS subsidiary, we entered into a $4.0 million term loan facility.~~ The ~~loan~~following istable ~~repayable~~reconciles inthe ~~semi-annual~~statutory ~~installments~~tax ~~beginning~~rates ~~April 14,~~to ~~2011~~our ~~and~~actual ~~bears~~tax ~~interest at~~rate: ~~8.5% per annum. The final maturity date is April 14, 2014 and the loan is unsecured.~~

Notes payable


	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	%

InNOTE ~~2010, we obtained insurance premium financings in the aggregate amount of $2.6 million with a fixed weighted~~7-~~average~~ ~~interest rate of 4.8%. Under terms of the agreements, amounts outstanding~~DEBT are paid over 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 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, 2010 and December 31, 2009, respectively.

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

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.


	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

~~NOTE~~Senior 7notes, —bank ~~STOCKHOLDERS’~~loans ~~EQUITY~~and line of credit agreements

WeIn ~~issued~~January 2006 1and August 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 ~~shares~~aggregate principal amount of our ~~common~~senior ~~stock~~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, to repay existing debt and for general corporate purposes. In June 2009, we closed on a tender offer in which we purchased $30.6 million aggregate principal of our 9.0% senior notes for a total consideration of $650 per $1,000 principal amount. In connection with the ~~acquisition~~Merger and based on actively traded prices of ~~AWC~~our insenior ~~July~~ notes, we increased the fair value of ~~2010~~the ~~(see~~9.0% ~~Note~~senior notes 2)to $1,022 per $1,000 principal amount. In May 2011, pursuant to the terms of change of

During the nine months ended September 30, 2010, we had restricted stock award grants and vested performance-based restricted stock which resulted in the issuance of approximately 1.1 million shares of our common stock. We recognized approximately $4.4 million of compensation expense related to share-based payments in the first nine months of 2010 that was recorded as capital in excess of par value (see Note 3). During 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 one of our drilling rigs were not sufficient to cover the book value of the rig and related assets.

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

NOTE 97 — ~~GAIN ON~~ DEBT ~~EXTINGUISHMENT~~(Continued)

~~During~~control ~~the~~provisions ~~nine~~in ~~months~~the ~~ended~~indentures ~~September 30,~~governing ~~2009,~~the wesenior ~~recorded~~notes aand ~~gain of $26.4 million~~ as a result of a ~~tender~~the ~~offer~~Merger, holders ~~that~~had wethe ~~completed~~right onto ~~June 29,~~require ~~2009.~~us Weto ~~purchased~~purchase, ~~approximately~~all ~~$30.6 million aggregate~~or ~~principal~~a ~~amount~~portion of ~~our~~such 9holders’ Notes.0% ~~senior~~We purchased ~~notes and~~ $441.28 million aggregate principal ~~amount~~ of our 89.50% senior notes for ~~approximately~~a ~~$46.4 million.~~total ~~The~~consideration ~~gain is net~~ of a $1~~.5 million~~,010 ~~write-off of~~per ~~debt issuance costs related to the retired notes and we incurred approximately~~ $~~466~~1,000 ~~in expenses~~principal ~~related to the transactions~~amount.

~~NOTE~~In 10January 2007, —we ~~INCOME~~closed ~~(LOSS)~~on a private offering, to qualified institutional buyers pursuant to Rule ~~PER~~144A ~~COMMON~~under ~~SHARE~~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 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.

~~Basic~~We ~~earnings~~had ~~per~~a ~~share~~$90.0 million ~~are~~revolving ~~computed~~line onof ~~the~~credit ~~basis~~with ofa ~~the~~final ~~weighted-average~~maturity ~~number~~date of ~~shares~~April 26, of2012 ~~common~~pursuant ~~stock~~to ~~outstanding~~a ~~during~~revolving ~~the~~credit ~~period.~~agreement ~~Diluted~~that ~~earnings~~contained ~~per~~customary ~~share~~events isof ~~similar~~default and financial covenants and limited our ability to ~~basic~~incur additional indebtedness, make capital expenditures, pay ~~earnings~~dividends ~~per~~or ~~share~~make other distributions, ~~but~~create ~~presents~~liens and sell assets. Effective December 31, 2009, we amended the ~~dilutive~~leverage ~~effect~~and oninterest acoverage ~~per~~ratio ~~share~~covenants ~~basis~~of the revolving credit agreement. This amendment relaxed the required financial ratios for the quarter ended December 31, 2009 and for each of ~~potential~~the ~~common~~quarters in 2010. Our obligations under the amended and restated credit agreement ~~shares~~are (esecured by substantially all of our assets located in the United States.~~g.,~~ ~~convertible~~We ~~preferred~~were ~~stock,~~in ~~stock~~compliance with ~~options~~all debt covenants as of December 31, ~~etc~~2010.) asAs ifof ~~they~~December 31, ~~had~~2010, ~~been~~we ~~converted~~had $36.5 million ~~The~~of ~~components~~borrowings outstanding and $4.1 million in outstanding letters of ~~basic~~credit ~~and~~under ~~diluted~~our ~~earnings~~revolving ~~per~~credit facility. ~~share~~The ~~are~~weighted-average asinterest ~~follows~~rate ~~(in~~was ~~thousands~~7.8% at December 31, ~~except~~2010. ~~per~~The ~~share~~revolving line of ~~amounts):~~credit was repaid and terminated in connection with the Merger.

	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

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

~~Convertible~~On ~~preferred~~February 15, ~~stock~~2008, ~~and~~through ~~share-based~~our ~~compensation~~DLS ~~shares~~subsidiary ofin ~~approximately~~Argentina, 14we entered into a $25.70 million ~~and~~ 14import finance facility with a bank.~~5 million~~ Borrowings under this facility were ~~excluded~~used into fund a portion of the ~~computation~~purchase price of ~~diluted~~the ~~earnings~~new ~~per~~drilling ~~share~~and service rigs ordered for ~~the~~our ~~three~~Drilling ~~months~~Services segment. ~~ended~~The ~~September 30,~~loan ~~2010~~is ~~and~~repayable ~~2009,~~over ~~respectively~~four asyears ~~the~~in ~~effect~~equal ~~would~~semi-annual ~~have~~installments ~~been~~beginning ~~anti-dilutive~~one ~~(e.g.,~~year after ~~those~~each ~~that~~disbursement ~~increase~~with ~~income~~the ~~per~~final ~~share)~~principal payment due tonot ~~the~~later ~~net~~than ~~loss~~March 15, ~~for the period~~2013. ~~Convertible~~The ~~preferred~~import ~~stock~~finance facility is unsecured and ~~share-based~~contains ~~compensation~~customary ~~shares~~events of ~~approximately~~default ~~15.0 million~~and financial covenants and limits 5DLS’ ability to incur additional indebtedness, make capital expenditures, create liens and sell assets.~~1 million~~ We were ~~excluded~~ in ~~the~~compliance ~~computation~~with all debt covenants as of ~~diluted~~June 30, ~~earnings~~2011 ~~per~~and ~~share~~December 31, 2010. ~~for~~The ~~the~~bank ~~nine~~loan ~~months~~rates ~~ended~~are ~~September~~based on LIBOR plus a margin. The weighted average interest rate was 4.2% at June 30, ~~2010~~ 2011 and ~~2009~~December 31, ~~respectively,~~2010. asThe outstanding amount under the ~~effect~~import ~~would~~finance facility ~~have~~as ~~been~~of ~~anti-dilutive~~June 30, 2011 and December 31, 2010 was $11.5 million and $14.4 million, respectively.

As part of our acquisition of BCH, we assumed a $23.6 million term loan credit facility with a bank. The credit agreement was dated June 2007 and contained customary events of default and financial covenants which 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 were secured by substantially all of the BCH assets. The bank waived certain financial ratio covenants for the December 31, 2010 measurement period and we classified the entire outstanding balance of the loan in the current portion of long-term debt. The interest rates were based on LIBOR plus a margin and the interest rate was 3.5% at December 31, 2010. The outstanding amount of the loan as of December 31, 2010 was $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 117 — ~~SUPPLEMENTAL~~DEBT ~~CASH FLOW INFORMATION~~ (~~in thousands~~Continued)

	For the Nine Months Ended
	September 30,
	2010			2009
Cash paid for interest and income taxes:
Interest	$	41,507		$	48,631
Income taxes		667			3,963
Non-cash investing and financing transactions in connection with an acquisition:
Goodwill	$	(2,000	)	$	—
Value of common stock, issued		2,000			—
Other non-cash investing and financing activities:
Insurance premium financed	$	2,579		$	3,204
Receivable from sale of investment		274			—
Assets transferred to joint venture investment		—			1,639
Preferred stock dividend		1,911			665

Notes payable

~~NOTE~~In 122010, —we ~~CONDENSED~~obtained ~~CONSOLIDATING~~insurance ~~FINANCIAL~~premium ~~INFORMATION~~financings in the aggregate amount of $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 $0 and $1.0 million at June 30, 2011 and December 31, 2010, respectively.

~~Set~~NOTE ~~forth~~8 on— ~~the~~STOCKHOLDERS’ ~~following pages are the condensed consolidating financial statements of (i)~~EQUITY Allis-Chalmers Energy Inc., (ii) its subsidiaries that are guarantors of the senior notes and revolving credit facility and (iii) the subsidiaries that are not guarantors of the senior notes and revolving credit facility (in thousands).

During the two months ended February 28, 2011, we had option exercises and certain vesting in restricted stock grants which resulted in the issuance of 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 $6.1 million of compensation expense related to share-based payments during the two months ended February 28, 2011 that was recorded as capital in excess of par value (see Note 3).

Pursuant to the Merger, each share of our 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 deemed to have lapsed and each restricted share was deemed to be an unrestricted share of our common stock. Subsequent to the Merger, we have 1,000 shares authorized all of which have been issued to Archer Limited at a par value of $0.01 per share.

NOTE 9 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

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-
	Allis-Chalmers			Subsidiary		Subsidiary			Consolidating			Consolidated
	Chalmers					Subsidiary
	(Guarantor)			Guarantors		Non-Guarantors			Adjustments			Total
	(Parent/			Subsidiary		Non-			Consolidating			Consolidated
	Guarantor)			Guarantors		Guarantors			Adjustments			Total
Assets
Cash and cash equivalents	$	—		$	79,~~780~~286	$	74,~~542~~130		$	—		$	1513,~~322~~416
Trade receivables, net		—			77,263		73,454			(10,594	)		140,123
Restricted cash		—			3,784		—			—			3,784
Inventories		—			18,906		20,087			—			38,993
Trade receivables, net		—			102,949		103,193			(31,762	)		174,380
Intercompany receivables		—			106,193		—			(106,193	)		—
Inventories		—			26,981		23,045			—			50,026
Note receivable from affiliate		23,551			—		—			(23,551	)		—
Intercompany receivables		—			87,640		—			(87,640	)		—
Prepaid expenses and other		22			5,832		5,423			—			11,277
Note receivable from affiliate		21,085			—		—			(21,085	)		—
Total current assets		23,573			215,974		106,506			(140,338	)		205,715
Prepaid expenses and other		12			5,638		14,188			—			19,838
Property and equipment, net		—			469,640		263,217			—			732,857
Total current assets		21,097			236,278		144,556			(140,487	)		261,444
Goodwill		—			28,784		17,389			—			46,173
Property and equipment, net		—			406,223		269,358			—			675,581
Other intangible assets, net		425			28,320		6,393			—			35,138
Goodwill		—			179,697		87,731			—			267,428
Debt issuance costs, net		7,954			119		—			—			8,073
Other intangible assets, net		—			57,540		37,350			—			94,890
Note receivable from affiliates		21,~~100~~500			—		—			(21,~~100~~500	)		—
Investments in affiliates		~~981~~1,~~488~~170,166			—		—			(~~981~~1,~~488~~170,166	)		—
Other assets		~~32,767~~—			394,~~099~~869		~~3,315~~382			—			755,~~181~~251
Total assets	$	1,~~048~~192,~~307~~763		$	~~781~~884,~~936~~607	$	~~396~~539,~~820~~377		$	(1,~~123~~312,~~926~~153	)	$	1,~~103~~304,~~137~~594
Liabilities and Stockholders’ Equity
Current maturities of long-term debt	$	—		$	~~5,172~~—	$	186,~~452~~892		$	—		$	236,~~624~~892
Trade accounts payable		—			1721,~~033~~814		3670,~~922~~708			(1031,~~594~~762	)		4360,~~361~~760
Accrued salaries, benefits and payroll taxes		—			15,~~976~~465		2330,~~343~~060			—			2535,~~319~~525
Accrued interest		615,~~356~~020			~~203~~—		~~358~~179			—			615,~~917~~199
Accrued expenses		~~1,041~~570			1516,~~275~~882		1124,~~358~~460			—			2741,~~674~~912
Intercompany payables		~~103~~57,~~569~~930			—		229,~~624~~710			(~~106~~87,~~193~~640	)		—
Note payable to affiliate		—			—		2321,~~551~~085			(2321,~~551~~085	)		—
Total current liabilities		~~110~~73,~~966~~520			3944,~~659~~161		~~116~~183,~~608~~094			(140,~~338~~487	)		~~126~~160,~~895~~288
Long-term debt, net of current maturities		~~466~~446,~~738~~647			~~17,146~~—		138,~~216~~042			—			~~497~~454,~~100~~689
Note payable to affiliate		—			—		21,~~100~~500			(21,~~100~~500	)		—
Other long-term liabilities		—			—		8,539			—			8,539
Payable to parent		74,403			—		—			—			74,403
Total liabilities		577,704			56,805		140,463			(142,438	)		632,534
Other long-term liabilities		—			—		17,021			—			17,021
Commitments and contingencies
Total liabilities		594,570			44,161		209,657			(141,987	)		706,401
Commitments and Contingencies
Stockholders’ Equity
Preferred Stock		34,183			—		—			—			34,183
Common stock		—			3,527		42,963			(46,490	)		—
Common stock		734			3,527		42,963			(46,490	)		734
Capital in excess of par value		600,885			823,395		290,090			(1,113,485	)		600,885
Capital in excess of par value		429,146			591,978		137,439			(729,417	)		429,146
Retained earnings (deficit)		(2,692	)		13,524		(3,333	)		(10,191	)		(2,692	)
Retained earnings		6,540			129,626		75,955			(205,581	)		6,540
Total stockholders’ equity		598,193			840,446		329,720			(1,170,166	)		598,193
Total stockholders’ equity		470,603			725,131		256,357			(981,488	)		470,603
Total liabilities and stockholders’ equity	$	1,192,763		$	884,607	$	539,377		$	(1,312,153	)	$	1,304,594
Total liabilities and stockholders’ equity	$	1,048,307		$	781,936	$	396,820		$	(1,123,926	)	$	1,103,137

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			Subsidiary			Consolidating			Consolidated
	(Parent/			Subsidiary			Non-			Consolidating			Consolidated
	(Guarantor)			Guarantors			Non-Guarantors			Adjustments			Total
	Guarantor)			Guarantors			Guarantors			Adjustments			Total
Revenues	$	—		$	96,934		$	123,446		$	(242	)	$	220,138
Revenues	$	—		$	78,034		$	96,325		$	(71	)	$	174,288
Operating costs and expenses:
Operating costs and expenses
Direct costs		—			57,986			104,884			(242	)		162,628
Direct costs		—			47,152			80,541			(71	)		127,622
Depreciation `		—			15,843			7,187			—			23,030
Selling, general and administrative		~~1,176~~65			7,~~677~~995			37,~~919~~326			—			1215,~~772~~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~~65			7083,~~376~~416			91122,~~250~~162			(71242	)		~~162~~205,~~743~~401
Income (loss) from operations		(~~1,188~~65	)		713,~~658~~518			51,~~075~~284			—			1114,~~545~~737
Other income (expense):
Equity earnings in affiliates, net of tax		911,~~376~~067			—			—			(911,~~376~~067	)		—
Interest, net		(109,~~769~~326	)		(~~505~~1	)		(~~562~~732	)		—			(1110,~~836~~059	)
Other		1513			~~(166~~107	)		(~~510~~154	)		—			(~~661~~34	)
Total other expense		(1,~~378~~754	)		~~(671~~106	)		(~~1,072~~886	)		(911,~~376~~067	)		(1210,~~497~~093	)
Net income (loss) before income taxes		(21,~~566~~689	)		613,~~987~~624			~~4,003~~398			(911,~~376~~067	)		~~(952~~4,644	)
Provision for income taxes		—			~~811~~(183	)		(2,~~425~~772	)		—			(12,~~614~~955	)
Net income (loss)	$	(21,~~566~~689	)	$	713,~~798~~441		$	1(2,~~578~~374	)	$	(911,~~376~~067	)	$	(21,~~566~~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			Subsidiary			Consolidating			Consolidated
	(Parent/			Subsidiary			Non-			Consolidating			Consolidated
	(Guarantor)			Guarantors			Non-Guarantors			Adjustments			Total
	Guarantor)			Guarantors			Guarantors			Adjustments			Total
Revenues	$	—		$	130,882		$	160,271		$	(289	)	$	290,864
Revenues	$	—		$	192,676		$	282,025		$	(1,399	)	$	473,302
Operating costs and expenses:
Operating costs and expenses
Direct costs		—			78,879			135,174			(289	)		213,764
Direct costs		—			124,528			232,931			(1,399	)		356,060
Depreciation		—			20,797			9,549			—			30,346
Selling, general and administrative		~~3,708~~100			2210,~~033~~997			119,~~208~~080			—			3620,~~949~~177
Depreciation and amortization		35			45,779			19,552			—			65,366
Impairment of intangible assets		—			4,400			700			—			5,100
Total operating costs and expenses		3,743			192,340			263,691			(1,399	)		458,375
Amortization		—			2,123			3,687			—			5,810
Income (loss) from operations		(3,743	)		336			18,334			—			14,927
Total operating costs and expenses		100			117,196			158,190			(289	)		275,197
Income (loss) from operations		(100	)		13,686			2,081			—			15,667
Other income (expense):
Equity earnings in affiliates, net of tax		1710,~~643~~191			—			—			(1710,~~643~~191	)		—
Interest, net		(3112,~~421~~801	)		(~~291~~2	)		(~~1,775~~999	)		—			(3313,~~487~~802	)
Other		4518			~~(1,944~~80	)		(~~580~~119	)		—			(~~2,479~~21	)
Total other expense		(132,~~733~~592	)		~~(2,235~~78	)		(21,~~355~~118	)		(1710,~~643~~191	)		(3513,~~966~~823	)
Net income (loss) before income taxes		(172,~~476~~692	)		(113,~~899~~764	)		~~15,979~~963			(1710,~~643~~191	)		~~(21~~1,~~039~~844	)
Provision for income taxes		—			~~11,323~~(240	)		(74,~~760~~296	)		—			3(4,~~563~~536	)
Net income (loss)		(17,476	)		9,424			8,219			(17,643	)		(17,476	)
Net income (loss) attributed to common stockholders	$	(2,692	)	$	13,524		$	(3,333	)	$	(10,191	)	$	(2,692	)
Preferred stock dividend		(1,911	)		—			—			—			(1,911	)
Net income (loss) attributed to common stockholders	$	(19,387	)	$	9,424		$	8,219		$	(17,643	)	$	(19,387	)

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~~February 3028, ~~2010~~2011 (Predecessor) (unaudited)

	Allis-						Other
	Allis-Chalmers			Subsidiary			Subsidiary			Consolidating			Consolidated
	Chalmers						Subsidiaries
	(Guarantor)			Guarantors			Non-Guarantors			Adjustments			Total
	(Parent/			Subsidiary			(Non-			Consolidating			Consolidated
Revenues	$	—		$	59,044		$	67,923		$	(82	)	$	126,885
	Guarantor)			Guarantors			Guarantors)			Adjustments			Total
Operating costs and expenses:
Cash Flows from Operating Activities:
Direct costs		—			37,335			59,877			(82	)		97,130
Net income (loss)	$	(17,476	)	$	9,424		$	8,219		$	(17,643	)	$	(17,476	)
Depreciation		—			10,174			4,852			—			15,026
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Selling, general and administrative		5,998			15,034			2,720			—			23,752
Depreciation and amortization		35			45,779			19,552			—			65,366
Amortization		8			678			125			—			811
Amortization and write-off of debt issuance costs		1,643			18			—			—			1,661
Total operating costs and expenses		6,006			63,221			67,574			(82	)		136,719
Stock-based compensation		4,374			—			—			—			4,374
Income (loss) from operations		(6,006	)		(4,177	)		349			—			(9,834	)
Allowance for bad debts		—			43			—			—			43
Other income (expense):
Equity earnings in affiliates		(17,643	)		—			—			17,643			—
Equity earnings in affiliates, net of tax		(6,057	)		—			—			6,057			—
Deferred taxes		(11,847	)		(332	)		163			—			(12,016	)
Interest, net		(7,253	)		(8	)		(588	)		—			(7,849	)
Loss on sale of equipment		—			74			76			—			150
Other		19			(232	)		335			—			122
Loss on investment		—			1,466			—			—			1,466
Total other expense		(13,291	)		(240	)		(253	)		6,057			(7,727	)
Equity in losses of unconsolidated affiliates		—			409			—			—			409
Net income (loss) before income taxes		(19,297	)		(4,417	)		96			6,057			(17,561	)
Changes in operating assets and liabilities, net of acquisitions:
Provision for income taxes		—			(233	)		(1,503	)		—			(1,736	)
(Increase) in trade receivables		—			(15,869	)		(14,492	)		—			(30,361	)
Net loss		(19,297	)		(4,650	)		(1,407	)		6,057			(19,297	)
(Increase) in inventories		—			(867	)		(1,830	)		—			(2,697	)
Preferred stock dividend		(375	)		—			—			—			(375	)
Decrease in prepaid expenses and other current assets		129			3,791			4,104			—			8,024
Net loss attributed to common stockholders	$	(19,672	)	$	(4,650	)	$	(1,407	)	$	6,057		$	(19,672	)
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 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
	Allis-Chalmers			Subsidiary			Subsidiary			Consolidating			Consolidated
	Chalmers						Subsidiaries
	(Guarantor)			Guarantors			Non-Guarantors			Adjustments			Total
	(Parent/			Subsidiary			(Non-			Consolidating			Consolidated
Cash Flows from Operating Activities:
	Guarantor)			Guarantors			Guarantors)			Adjustments			Total
Net income (loss)	$	(2,692	)	$	13,524		$	(3,333	)	$	(10,191	)	$	(2,692	)
Cash Flows from Financing Activities:
Adjustments to reconcile net income (loss) to net cash (used) provided by operating activities:
Accounts receivable from affiliates		—			(25,492	)		(790	)		26,282			—
Depreciation and amortization		—			22,920			13,236			—			36,156
Accounts payable to affiliates		26,282			—			—			(26,282	)		—
Debt premium amortization		(1,050	)		—			—			—			(1,050	)
Notes payable to affiliates		—			—			(8,328	)		8,328			—
Equity earnings in affiliates		(10,191	)		—			—			10,191			—
Proceeds from parent contributions		—			19,467			—			(19,467	)		—
Impairment of intangible assets		—			4,400			700			—			5,100
Proceeds from long-term debt		—			—			4,000			—			4,000
Deferred income taxes		—			1			(940	)		—			(939	)
Borrowings under line of credit		36,500			—			—			—			36,500
Loss on sale of equipment		—			94			77			—			171
Payments on long-term debt		—			(4,646	)		(9,942	)		—			(14,588	)
Changes in operating assets and liabilities, net of acquisitions:
Payment of preferred stock dividend		(1,911	)		—			—			—			(1,911	)
Increase in trade receivables		—			(1,342	)		(13,566	)		—			(14,908	)
Debt issuance costs		(189	)		—			—			—			(189	)
Increase in inventories		—			(3,481	)		(2,595	)		—			(6,076	)
Net Cash Provided By (Used In) Financing Activities		60,682			(10,671	)		(15,060	)		(11,139	)		23,812
Increase in prepaid expenses and other current assets		(1	)		(2,655	)		(7,498	)		—			(10,154	)
Net change in cash and cash equivalents		—			(24,078	)		(1,672	)		—			(25,750	)
Decrease (increase) in other assets		—			(322	)		66			—			(256	)
Cash and cash equivalents at beginning of period		—			31,858			9,214			—			41,072
(Decrease) increase in trade accounts payable		—			(5,455	)		7,219			—			1,764
Cash and cash equivalents at end of period	$	—		$	7,780		$	7,542		$	—		$	15,322
(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~~STATEMENTS ~~SHEETS~~OF CASH FLOW ~~December~~For the Four Months Ended June 3130, ~~2009~~2011 (Successor) (unaudited)

	Allis-Chalmers			Subsidiary			Subsidiary			Consolidating			Consolidated
	(Parent/			Subsidiary			Non-			Consolidating			Consolidated
	(Guarantor)			Guarantors			Non-Guarantors			Adjustments			Total
	Guarantor)			Guarantors			Guarantors			Adjustments			Total
Cash Flows from Financing Activities:
Assets
Accounts receivable from affiliates		—			(15,631	)		—			15,631			—
Cash and cash equivalents	$	—		$	31,858		$	9,214		$	—		$	41,072
Accounts payable to affiliates		11,782			—			3,849			(15,631	)		—
Trade receivables, net		—			47,358			58,962			(1,261	)		105,059
Note payable to affiliate		—			—			2,312			(2,312	)		—
Inventories		—			16,271			18,257			—			34,528
Payments on long-term debt		(1,885	)		(350	)		(3,537	)		—			(5,772	)
Intercompany receivables		—			79,521			767			(80,288	)		—
Proceeds from Parent		2,953			—			—			—			2,953
Note receivable from affiliate		28,379			—			—			(28,379	)		—
Net cash (used) provided by financing activities		12,850			(15,981	)		2,624			(2,312	)		(2,819	)
Prepaid expenses and other		891			6,826			9,872			—			17,589
Net change in cash and cash equivalents		—			(7,578	)		(641	)		—			(8,219	)
Total current assets		29,270			181,834			97,072			(109,928	)		198,248
Cash and cash equivalents at beginning of year		—			16,864			4,771			—			21,635
Property and equipment, net		—			489,921			256,557			—			746,478
Cash and cash equivalents at end of period	$	—		$	9,286		$	4,130		$	—		$	13,416
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 ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 129 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF ~~OPERATIONS~~CASH FLOW For the ~~Three~~Two Months Ended ~~September~~February 3028, ~~2009~~2011 (Predecessor) (unaudited)

	Allis-Chalmers			Subsidiary			Subsidiary			Consolidating			Consolidated
	(Parent/			Subsidiary			Non-			Consolidating			Consolidated
	(Guarantor)			Guarantors			Non-Guarantors			Adjustments			Total
	Guarantor)			Guarantors			Guarantors			Adjustments			Total
Cash Flows from Operating Activities:
Revenues	$	—		$	43,797		$	76,840		$	(621	)	$	120,016
Net loss	$	(19,297	)	$	(4,650	)	$	(1,407	)	$	6,057		$	(19,297	)
Operating costs and expenses
Adjustments to reconcile net loss to net cash (used) provided by operating activities:
Direct costs		—			29,041			62,343			(621	)		90,763
Depreciation and amortization		8			10,852			4,977			—			15,837
Selling, general and administrative		1,043			7,243			3,144			—			11,430
Amortization of deferred issuance costs		366			—			—			—			366
Depreciation and amortization		12			15,446			5,435			—			20,893
Stock based compensation		6,084			—			—			—			6,084
Total operating costs and expenses		1,055			51,730			70,922			(621	)		123,086
Equity earnings in affiliates		6,057			—			—			(6,057	)		—
Income (loss) from operations		(1,055	)		(7,933	)		5,918			—			(3,070	)
Allowance for bad debts		—			195			—			—			195
Other income (expense):
Deferred income taxes		—			34			106			—			140
Equity earnings in affiliates, net of tax		1,499			—			—			(1,499	)		—
Loss on sale of equipment		—			352			64			—			416
Interest, net		(10,109	)		45			(661	)		—			(10,725	)
Changes in operating assets and liabilities, net of acquisitions:
Other		15			3			19			—			37
Increase in trade receivables		—			(3,714	)		(12,230	)		—			(15,944	)
Total other income (expense)		(8,595	)		48			(642	)		(1,499	)		(10,688	)
Increase in inventories		—			(1,434	)		(376	)		—			(1,810	)
Net income (loss) before income taxes		(9,650	)		(7,885	)		5,276			(1,499	)		(13,758	)
Decrease (increase) in prepaid expenses and other current assets		2,057			235			(1,742	)		—			550
Provision for income taxes		—			6,471			(2,363	)		—			4,108
Decrease in other assets		—			432			242			—			674
Net income (loss)		(9,650	)		(1,414	)		2,913			(1,499	)		(9,650	)
Increase in trade accounts payable		—			8,417			4,537			—			12,954
Preferred stock dividend		(630	)		—			—			—			(630	)
(Decrease) increase in accrued interest		(4,031	)		—			138			—			(3,893	)
Net income (loss) attributed to common stockholders	$	(10,280	)	$	(1,414	)	$	2,913		$	(1,499	)	$	(10,280	)
(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 129 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF ~~OPERATIONS~~CASH FLOW For the ~~Nine~~Two Months Ended ~~September~~February 3028, ~~2009~~2011 (Predecessor) (unaudited)

	Allis-Chalmers			Subsidiary			Subsidiary			Consolidating			Consolidated
	(Parent/			Subsidiary			Non-			Consolidating			Consolidated
	(Guarantor)			Guarantors			Non-Guarantors			Adjustments			Total
	Guarantor)			Guarantors			Guarantors			Adjustments			Total
Cash Flows from Financing Activities:
Revenues	$	—		$	154,502		$	225,013		$	(1,891	)	$	377,624
Accounts receivable from affiliates		—			12,811			—			(12,811	)		—
Operating costs and expenses
Accounts payable to affiliates		(23,607	)		—			10,796			12,811			—
Direct costs		—			101,284			181,743			(1,891	)		281,136
Note payable to affiliate		—			—			114			(114	)		—
Selling, general and administrative		3,029			27,199			10,367			—			40,595
Payments on long-term debt		—			(567	)		(7,252	)		—			(7,819	)
Loss on asset disposition		—			—			1,916			—			1,916
Net borrowings (repayments) on line of credit		(36,500	)		—			—			—			(36,500	)
Depreciation and amortization		35			45,629			16,155			—			61,819
Proceeds from Parent		71,450			—			—			—			71,450
Total operating costs and expenses		3,064			174,112			210,181			(1,891	)		385,466
Payment of preferred stock dividend		(637	)		—			—			—			(637	)
Income (loss) from operations		(3,064	)		(19,610	)		14,832			—			(7,842	)
Exercise of options and restricted stock awards, net of tax		(1,821	)		—			—			—			(1,821	)
Other income (expense):
Net cash provided by financing activities		8,885			12,244			3,658			(114	)		24,673
Equity earnings in affiliates, net of tax		(1,101	)		—			—			1,101			—
Net change in cash and cash equivalents		—			484			211			—			695
Interest, net		(34,595	)		24			(2,868	)		—			(37,439	)
Cash and cash equivalents at beginning of year		—			16,380			4,560			—			20,940
Gain on debt extinguishment		26,365			—			—			—			26,365
Cash and cash equivalents at end of period	$	—		$	16,864		$	4,771		$	—		$	21,635
Other		50			(103	)		(178	)		—			(231	)
Total other income (expense)		(9,281	)		(79	)		(3,046	)		1,101			(11,305	)
Net income (loss) before income taxes		(12,345	)		(19,689	)		11,786			1,101			(19,147	)
Provision for income taxes		—			10,517			(3,715	)		—			6,802
Net income (loss)		(12,345	)		(9,172	)		8,071			1,101			(12,345	)
Preferred stock dividend		(665	)		—			—			—			(665	)
Net income (loss) attributed to common stockholders	$	(13,010	)	$	(9,172	)	$	8,071		$	1,101		$	(13,010	)

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

NOTE 129 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING ~~STATEMENTS~~BALANCE ~~OF CASH FLOW~~SHEETS ~~For the Nine Months Ended September~~December 3031, ~~2009~~2010 (~~unaudited~~Predecessor)

	Allis-						Other
	Allis-Chalmers			Subsidiary			Subsidiary			Consolidating			Consolidated
	Chalmers						Subsidiaries
	(Guarantor)			Guarantors			Non-Guarantors			Adjustments			Total
	(Parent/			Subsidiary			(Non-			Consolidating			Consolidated
Assets
	Guarantor)			Guarantors			Guarantors)			Adjustments			Total
Cash and cash equivalents	$	—		$	16,380		$	4,560		$	—		$	20,940
Cash Flows from Operating Activities:
Trade receivables, net		—			79,100			77,397			(11,537	)		144,960
Net income (loss)	$	(12,345	)	$	(9,172	)	$	8,071		$	1,101		$	(12,345	)
Inventories		—			22,066			20,074			—			42,140
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Intercompany receivables		—			84,766			—			(84,766	)		—
Depreciation and amortization		35			45,629			16,155			—			61,819
Note receivable from affiliate		18,359			—			—			(18,359	)		—
Amortization and write-off of debt issuance costs		1,682			9			—			—			1,691
Prepaid expenses and other		2,068			3,280			3,925			—			9,273
Stock-based compensation		3,580			—			—			—			3,580
Total current assets		20,427			205,592			105,956			(114,662	)		217,313
Allowance for bad debts		—			4,065			—			—			4,065
Property and equipment, net		—			461,187			262,047			—			723,234
Equity earnings in affiliates		1,101			—			—			(1,101	)		—
Goodwill		—			28,944			17,389			—			46,333
Deferred taxes		(11,490	)		—			396			—			(11,094	)
Other intangible assets, net		414			27,278			6,207			—			33,899
(Gain) on sale of equipment		—			(1,059	)		(121	)		—			(1,180	)
Debt issuance costs, net		7,405			—			—			—			7,405
Loss on asset disposition		—			—			1,916			—			1,916
Note receivable from affiliates		1,800			—			—			(1,800	)		—
Gain on debt extinguishment		(26,365	)		—			—			—			(26,365	)
Investments in affiliates		934,274			—			—			(934,274	)		—
Changes in operating assets and liabilities, net of acquisitions:
Other assets		—			7,390			2,695			—			10,085
Decrease in trade receivables		—			41,296			18,175			—			59,471
Total assets	$	964,320		$	730,391		$	394,294		$	(1,050,736	)	$	1,038,269
Decrease in inventories		—			2,621			1,269			—			3,890
Liabilities and Stockholders’ Equity
(Increase) decrease in prepaid expenses and other current assets		7,296			2,488			(6,494	)		—			3,290
Current maturities of long-term debt	$	—		$	979		$	14,236		$	—		$	15,215
(Increase) decrease in other assets		—			(798	)		2,333			—			1,535
Trade accounts payable		—			18,634			38,945			(11,537	)		46,042
(Decrease) in trade accounts payable		—			(16,979	)		(12,056	)		—			(29,035	)
Accrued salaries, benefits and payroll taxes		—			8,983			23,807			—			32,790
(Decrease) increase in accrued interest		(12,248	)		236			(467	)		—			(12,479	)
Accrued interest		15,310			—			214			—			15,524
(Decrease) in accrued expenses		(300	)		(4,923	)		(6,409	)		—			(11,632	)
Accrued expenses		1,192			18,504			10,980			—			30,676
(Decrease) increase in accrued salaries, benefits and payroll taxes		—			(2,050	)		3,278			—			1,228
Intercompany payables		69,756			—			15,010			(84,766	)		—
(Decrease) in other long- term liabilities		—			(57	)		(779	)		—			(836	)
Note payable to affiliate		—			—			18,359			(18,359	)		—
Net Cash Provided By (Used In) Operating Activities		(49,054	)		61,306			25,267			—			37,519
Total current liabilities		86,258			47,100			121,551			(114,662	)		140,247
Cash Flows from Investing Activities:
Long-term debt, net of current maturities		466,738			—			11,487			—			478,225
Investment in affiliates		(4,100	)		—			—			4,100			—
Note payable to affiliate		—			—			1,800			(1,800	)		—
Notes receivable from affiliates		693			—			—			(693	)		—
Other long-term liabilities		—			—			8,473			—			8,473
Deposits on asset commitments		—			7,610			(556	)		—			7,054
Total liabilities		552,996			47,100			143,311			(116,462	)		626,945
Purchase of investment interests		(2,393	)		—			1,291			—			(1,102	)
Commitments and contingencies
Proceeds from sale of property and equipment		—			7,859			121			—			7,980
Stockholders’ Equity
Proceeds from assets dispositions		—			—			3,916			—			3,916
Preferred Stock		34,183			—			—			—			34,183
Purchase of property and equipment		—			(53,716	)		(13,550	)		—			(67,266	)
Common stock		737			3,527			42,963			(46,490	)		737
Net Cash Used in Investing Activities		(5,800	)		(38,247	)		(8,778	)		3,407			(49,418	)
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 129 — CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF ~~CASH FLOW~~OPERATIONS For the ~~Nine~~Three Months Ended ~~September~~June 30, ~~2009~~2010 (Predecessor) (unaudited)

	Allis-						Other
	Allis-Chalmers			Subsidiary			Subsidiary			Consolidating			Consolidated
	Chalmers						Subsidiaries
	(Guarantor)			Guarantors			Non-Guarantors			Adjustments			Total
	(Parent/			Subsidiary			(Non-			Consolidating			Consolidated
Revenues	$	—		$	62,760		$	96,337		$	(453	)	$	158,644
	Guarantor)			Guarantors			Guarantors)			Adjustments			Total
Operating costs and expenses
Cash Flows from Financing Activities:
Direct costs		—			42,300			78,876			(453	)		120,723
Accounts receivable from affiliates		—			(18,637	)		—			18,637			—
Depreciation		—			14,198			6,319			—			20,517
Accounts payable to affiliates		18,661			—			(24	)		(18,637	)		—
Selling, general and administrative		1,365			7,156			3,593			—			12,114
Notes payable to affiliates		—			—			(693	)		693			—
Amortization		11			959			186			—			1,156
Proceeds from parent contributions		—			—			4,100			(4,100	)		—
Total operating costs and expenses		1,376			64,613			88,974			(453	)		154,510
Proceeds from issuance of stock, net		120,337			—			—			—			120,337
Income (loss) from operations		(1,376	)		(1,853	)		7,363			—			4,134
Net proceeds from stock incentive plans		14			—			—			—			14
Other income (expense):
Proceeds from long-term debt		—			25,000			—			—			25,000
Equity earnings in affiliates, net of tax		6,396			—			—			(6,396	)		—
Net repayment under line of credit		(36,500	)		—			—			—			(36,500	)
Interest, net		(10,415	)		141			(576	)		—			(10,850	)
Payments on long-term debt		(47,167	)		(3,011	)		(11,361	)		—			(61,539	)
Other		16			(254	)		(65	)		—			(303	)
Debt issuance costs		(491	)		(153	)		—			—			(644	)
Total other income (expense)		(4,003	)		(113	)		(641	)		(6,396	)		(11,153	)
Net Cash Provided By (Used In) Financing Activities		54,854			3,199			(7,978	)		(3,407	)		46,668
Net income (loss) before income taxes		(5,379	)		(1,966	)		6,722			(6,396	)		(7,019	)
Net change in cash and cash equivalents		—			26,258			8,511			—			34,769
Provision for income taxes		—			4,408			(2,768	)		—			1,640
Cash and cash equivalents at beginning of period		—			2,923			3,943			—			6,866
Net income (loss)		(5,379	)		2,442			3,954			(6,396	)		(5,379	)
Cash and cash equivalents at end of period	$	—		$	29,181		$	12,454		$	—		$	41,635
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~~CONDENSED ofCONSOLIDATING ~~our~~STATEMENTS ~~segments~~OF ~~provide~~OPERATIONS For ~~services to~~ the ~~energy~~Six ~~industry.~~Months ~~The~~Ended ~~revenues~~June 30, ~~operating~~2010 ~~income~~ (~~loss~~Predecessor)~~, depreciation and amortization, capital expenditures and assets of each of the reporting~~ ~~segments, plus the corporate function, are reported below~~ (~~in thousands~~unaudited):

	For the Three Months Ended						For the Nine Months Ended
	Allis-Chalmers			Subsidiary			Subsidiary			Consolidating			Consolidated
	September 30,						September 30,
	(Guarantor)			Guarantors			Non-Guarantors			Adjustments			Total
	2010			2009			2010			2009
Revenues	$	—		$	114,642		$	185,700		$	(1,328	)	$	299,014
Revenues:
Operating costs and expenses
Oilfield Services	$	56,705		$	31,904		$	146,070		$	105,827
Direct costs		—			77,376			152,390			(1,328	)		228,438
Drilling and Completion		96,295			76,299			280,772			223,237
Depreciation		—			28,316			12,389			—			40,705
Rental Services		21,288			11,813			46,460			48,560
Selling, general and administrative		2,532			14,356			7,289			—			24,177
	$	174,288		$	120,016		$	473,302		$	377,624
Amortization		23			1,916			373			—			2,312
Operating Income (Loss):
Total operating costs and expenses		2,555			121,964			172,441			(1,328	)		295,632
Oilfield Services	$	7,462		$	(4,211	)	$	7,969		$	(15,701	)
Income (loss) from operations		(2,555	)		(7,322	)		13,259			—			3,382
Drilling and Completion		5,125			5,508			17,640			14,420
Other income (expense):
Rental Services		3,337			(1,218	)		1,596			3,318
Equity earnings in affiliates, net of tax		8,267			—			—			(8,267	)		—
General corporate		(4,379	)		(3,149	)		(12,278	)		(9,879	)
Interest, net		(20,652	)		214			(1,213	)		—			(21,651	)
	$	11,545		$	(3,070	)	$	14,927		$	(7,842	)
Other		30			(1,778	)		(70	)		—			(1,818	)
Depreciation and Amortization:
Total other income (expense)		(12,355	)		(1,564	)		(1,283	)		(8,267	)		(23,469	)
Oilfield Services	$	7,925		$	8,077		$	23,622		$	22,825
Net income (loss) before income taxes		(14,910	)		(8,886	)		11,976			(8,267	)		(20,087	)
Drilling and Completion		6,793			5,462			19,619			16,182
Provision for income taxes		—			10,512			(5,335	)		—			5,177
Rental Services		7,565			7,281			21,929			22,580
Net income (loss)		(14,910	)		1,626			6,641			(8,267	)		(14,910	)
General corporate		66			73			196			232
Preferred stock dividend		(1,274	)		—			—			—			(1,274	)
	$	22,349		$	20,893		$	65,366		$	61,819
Net income (loss) attributed to common stockholders	$	(16,184	)	$	1,626		$	6,641		$	(8,267	)	$	(16,184	)
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 ENERGY INC.
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

NOTE 139 — ~~SEGMENT~~CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

	As of
	September 30,		December 31,
	2010		2009
Goodwill:
Oilfield Services	$	23,250	$	23,250
Drilling and Completion		17,389		17,389
Rental Services		5,534		—
	$	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:
United States	$	579,173	$	572,727
Argentina		165,290		168,681
Brazil		89,970		82,477
Other international		62,989		58,487
	$	897,422	$	882,372

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

NOTE 14 — LEGAL MATTERS


	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	)

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.

In addition, we are named from time to time in legal proceedings related to our activities prior to our bankruptcy in 1988. However, we believe that we were discharged from liability for all such claims in the bankruptcy and believe the likelihood of a material loss relating to any such legal proceeding is remote. We are also involved in various other legal proceedings in the ordinary course of business. The legal proceedings are at different stages; however, we believe that the likelihood of material loss relating to any such legal proceeding is remote.

~~ITEM~~ALLIS-CHALMERS 2ENERGY INC. NOTES ~~MANAGEMENT’S~~TO ~~DISCUSSION~~UNAUDITED ~~AND~~CONSOLIDATED ~~ANALYSIS~~CONDENSED OF FINANCIAL ~~CONDITION AND RESULTS~~STATEMENTS ~~OF OPERATIONS~~

~~The~~NOTE ~~following~~9 ~~discussion~~— ~~and~~CONDENSED ~~analysis~~CONSOLIDATING ~~should~~FINANCIAL beINFORMATION ~~read in conjunction with our consolidated financial~~(Continued) 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~~CONDENSED ofCONSOLIDATING ~~Our~~STATEMENTS ~~Business~~OF CASH FLOW For the Six Months Ended June 30, 2010 (Predecessor) (unaudited)

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 sectors of the oil and natural gas service industry: Oilfield Services; Drilling and Completion and Rental Services.


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

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


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

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

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

On August 12, 2010, we entered into an Agreement and Plan of Merger with Seawell Limited, or Seawell, pursuant to which we will merge with and into a wholly owned subsidiary of Seawell, and each share of our common stock will be converted into the right to receive either 1.15 Seawell common shares, subject to adjustment to 1.20 Seawell common shares under certain circumstances, or $4.25 in cash. Completion of the merger is subject 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.

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 million of costs related to the merger during the three months ended September 30, 2010, which are included in selling, general and administrative expense on our Consolidated Statements of Operations. 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 retirement plan agreements applicable to executive officers, directors and certain employees and certain other debt obligations, including our senior notes.

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

~~The oilfield services industry is highly cyclical. Demand for our products and services is~~NOTE ~~substantially~~10 ~~dependent~~— ~~upon~~SEGMENT ~~activity levels in the oil and natural gas industry, particularly our~~INFORMATION 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~~In ~~Outlook~~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.

~~Throughout~~All ~~the first half~~ of ~~2009,~~our wesegments ~~saw~~provide aservices ~~significant decline in the global economy which led~~ to ~~reduced~~ ~~activity in~~ the energy ~~sector~~industry. ~~This~~Indirect ~~reduced~~general ~~activity~~and ~~in the energy sector resulted in lower~~administrative ~~demand~~expenses ~~for~~are ~~our~~allocated ~~services~~to ~~and~~each wesegment ~~incurred~~based ~~significant~~on ~~losses~~estimated use. ~~Since~~The ~~the~~revenues, ~~second~~operating ~~quarter of 2009~~income (loss), ~~we have~~depreciation ~~experienced~~and ~~quarter~~amortization, ~~over~~capital ~~quarter~~expenditures ~~improvement~~and inassets ~~both~~of ~~our~~each ~~total~~of ~~revenues~~the ~~and total operating~~reporting ~~income~~segments ~~which~~are ~~has~~reported ~~resulted~~below (in ~~reduced net losses.~~thousands):

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.


	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

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 fortyALLIS-~~three weeks~~CHALMERS ofENERGY ~~2010 decreased to 32 rigs compared to an average of 44 rigs for the first forty-three weeks of 2009~~INC. ~~As of October 15, 2010, the Baker Hughes rig count in the U.S. Gulf of Mexico was~~ 21NOTES asTO aUNAUDITED ~~result~~CONSOLIDATED ofCONDENSED ~~the~~FINANCIAL ~~effects of the oil spill in the U.S. Gulf of Mexico. Due to the decline in~~STATEMENTS 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~~NOTE ~~selling,~~10 ~~general~~— ~~and~~SEGMENT ~~administrative~~INFORMATION ~~expenses for the nine months ended September 30, 2010 are~~(Continued) 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.


	Successor		Predecessor
	June 30,		December 31,
	2011		2010
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


Long Lived Assets:
United States	$	623,198	$	501,117
Argentina		293,721		167,137
Brazil		65,456		86,949
Other international		60,775		65,753

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

AsNOTE we11 ~~incur~~— ~~more~~LEGAL ~~non-deductible merger related expenses, we anticipate our effective tax rate~~MATTERS 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~~We ~~operating~~are ~~income~~named isfrom ~~principally~~time ~~dependent~~to ontime ~~our~~in ~~level~~legal ofproceedings ~~revenues~~related ~~and~~to ~~the~~our ~~pricing~~activities ~~environment of~~prior to our bankruptcy ~~services~~in 1988. ~~In addition~~However, ~~demand~~we ~~for~~believe ~~our~~that ~~services~~we iswere ~~dependent~~discharged ~~upon~~from ~~our~~liability ~~customers’~~for ~~capital~~all such claims ~~spending~~in ~~plans,~~the ~~which~~bankruptcy ~~are~~and ~~largely~~believe ~~driven~~the bylikelihood ~~current~~of ~~commodity~~a ~~prices~~material ~~and~~loss ~~their~~relating ~~expectations~~to ofany such legal ~~future~~proceeding ~~commodity~~is ~~prices~~remote.

~~Although~~We ~~2010~~are ~~has~~also ~~been~~involved ain ~~challenging~~litigation ~~year~~or ~~for~~proceedings that have arisen in our ~~operations,~~ordinary ~~increased~~business activities. ~~rig~~We ~~count~~insure ~~has~~against ~~increased~~these risks to the extent deemed prudent by our management and to ~~utilization~~the extent insurance is available, but no assurance can be given that the nature and ~~pricing~~amount ~~for~~of ~~our~~that insurance ~~equipment~~will be sufficient to fully indemnify us against liabilities arising out of pending and future ~~services~~legal proceedings. WeMany ~~believe~~of ~~our~~these ~~cost~~insurance ~~cuts~~policies contain deductibles or self-insured retentions in ~~2009~~amounts we deem prudent and for which we are responsible for payment. If there is a claim, ~~our~~dispute or pending litigation in which we believe a negative outcome is probable and a loss ~~strategy~~by ofthe ~~international~~Company ~~growth~~can be reasonably estimated, ~~our~~we ~~commitment~~record toa ~~offer~~liability ~~new~~for ~~equipment~~the ~~and~~expected ~~technology~~loss tobut ~~our~~at this ~~customers~~time ~~and~~any such expected loss are immaterial to our ~~focus~~financial oncondition ~~the~~and Uresults of operations.S. In ~~land~~addition ~~shale~~we ~~plays~~have ~~will~~certain ~~continue~~claims, todisputes ~~result~~and pending litigation in ~~improvements~~which towe ~~our~~do not believe a ~~operating~~negative ~~results~~outcome is probable or for which the ~~remainder~~loss ofcannot ~~2010~~be reasonably estimated.

~~Results~~Shortly following the announcement of ~~Operations~~the merger agreement with Seawell (now Archer) in August 2010, ten putative stockholder class-action petitions and complaints were filed against various combinations of us, members of our board of directors and the Archer parties to the merger agreement. Seven of the lawsuits were filed in Texas and three lawsuits were filed in Delaware. These lawsuits had challenged 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 merger and failing to take steps to maximize our value to our public stockholders. The lawsuits generally sought, 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. In February 2011, the plaintiffs’ request for an injunction was denied by the Delaware court and the merger closed on February 23, 2011. In July 2011, plaintiffs and defendants jointly filed a stipulation and order for the dismissal of all claims as moot with the plaintiffs reserving only their application for attorney’s fees and expenses, which the Company and other defendants oppose. The proposed stipulation and order is pending before the court.

InThe ~~July 2010~~case of Nexen Petroleum U.S.A., weInc. ~~acquired~~et ~~all~~al ofv. ~~the~~Allis-Chalmers ~~outstanding~~Rental ~~stock~~Services, ofLLC, ~~American~~Cameron, Hydril ~~Well~~and ~~Control~~Tri-City Pipe & Machine, ~~Inc~~Cause No., 88810 orin ~~AWC~~the 15th Judicial District, State of ~~which~~Louisiana is ~~reported~~presently asscheduled ~~part~~for oftrial ~~our~~in ~~Rental~~September 2011. ~~Services~~The ~~segment.~~case Weinvolves ~~consolidated~~a ~~the~~blow ~~results~~out ofon ~~this~~a ~~transaction~~well ~~from~~operated ~~the~~by ~~date~~Nexen itin ~~was~~Vermilion ~~effective~~Parish. During drilling operations, Nexen lost control

The foregoing acquisition affects 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 30, 2010 and 2009~~ALLIS-CHALMERS ENERGY INC.

~~Our~~NOTES ~~revenues~~TO ~~for~~UNAUDITED ~~the~~CONSOLIDATED ~~three~~CONDENSED ~~months~~FINANCIAL ~~ended September 30, 2010 were $174.3 million, an increase of~~STATEMENTS 45.2% compared to $120.0 million for the three months ended September 30, 2009. The increase in revenues is due to the increase in revenues in all of our operating segments. Our Oilfield Services segment revenues increased 77.7% to $56.7 million for the three months ended September 30, 2010 compared to $31.9 million for the three months ended September 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. Revenues for our Rental Services segment increased 80.2% to $21.3 million for the three months ended September 30, 2010 compared to $11.8 million for the three months ended September 30, 2009 due to $6.8 million of revenues from AWC since the date of acquisition, along with an increased emphasis of providing rental services in the domestic onshore unconventional natural gas markets which offset decreased equipment utilization in the U.S. Gulf of Mexico.

~~Our~~NOTE ~~direct~~11 ~~costs~~— ~~for~~LEGAL ~~the~~MATTERS ~~three months ended September 30, 2010 increased 40.6% to $127.6 million,~~(Continued) or 73.2% of revenues, compared to $90.8 million, or 75.6%, of revenues for the three months ended September 30, 2009. Our direct costs in all of our segments increased in absolute dollars in the three months ended September 30, 2010 compared to the three months ended September 30, 2009. Our Oilfield Services segment revenues for the three months ended September 30, 2010 increased 77.7% from revenues for the three months ended September 30, 2009, while direct costs increased 57.9% 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. 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 Rental Services segment revenues for the three months ended September 30, 2010 increased 80.2% from revenues for the three months ended September 30, 2009, while direct costs increased 104.4% over that same period. While the acquisition of AWC provided $6.8 million of revenues during the three months ended September 30, 2010 it also increased direct costs by $4.1 million for the same period for an effective gross margin as a percentage of revenues of 40.6%. AWC’s gross margin as a percentage of revenues is less than our overall Rental 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 Services segment for the three months ended September 30, 2010 was 57.8% compared to 62.8% for the three months ended September 30, 2009.

~~Depreciation~~of ~~expense~~the ~~increased~~well, ~~7.0%~~activated toand ~~$21.1~~closed ‘blow out preventers’ rented from Allis-Chalmers Rental Services, LLC (ACRS) ~~million~~thereby ~~for~~sealing the ~~three~~well. ~~months~~Nexen ~~ended~~then ~~September 30,~~re-opened ~~2010~~the blow out preventers to attempt an ~~from~~unsuccessful ~~$19~~dynamic kill.~~7 million~~ ~~for~~Nexen alleges that it then again attempted to reseal the ~~three~~well ~~months~~using ~~ended~~the blow ~~September 30,~~out ~~2009~~preventers but was unable to obtain a complete seal. The ~~increase~~well inallegedly ~~depreciation~~then flowed ~~expense~~uncontrolled isfor ~~primarily~~up ~~due~~to a day causing damage to ~~our~~the ~~capital~~rig ~~expenditure~~and ~~programs~~other ~~for~~equipment, ~~our~~and ~~Drilling~~the hole. The blow out preventers were manufactured by Cameron and ~~Completion~~Hydril and some of the components of the Cameron ~~segment~~equipment were machined by Tri-City. ~~Depreciation~~Nexen ~~expense~~alleges asthat athe ~~percentage~~blow ofout ~~revenues~~preventers ~~decreased~~failed due to 12the fault of the defendants.1% ACRS contends that Nexen actions in specifying the equipment for the well, ~~third~~designing ~~quarter~~the well, and operating the well including its acts and omissions for the well control event caused any failure of ~~2010,~~the ~~compared~~equipment rented to 16Nexen by ACRS.4% ~~for~~There ~~the~~is ~~third~~conflicting evidence ~~quarter~~and expert testimony affecting several aspects of ~~2009,~~this ~~due~~case. It is impossible to predict the ~~increase~~outcome inwith ~~our~~any ~~revenues~~degree of certainty. ACRS and its insurers are treating this case as highly defensible and continue to vigorously contest it.

~~Selling,~~NOTE ~~general and administrative expense was $~~12~~.8 million~~ ~~for~~— ~~the~~TRANSACTIONS ~~three~~WITH ~~months ended September~~PARENT 30, 2010 compared to $11.4 million for the three months ended September 30, 2009. Selling, general and administrative expense increased primarily due to an increase in professional fees for the three months ended September 30, 2010 compared to the same period of the prior year. Professional fees for the three 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. As a percentage of revenues, selling, general and administrative expense was 7.3% for the three months ended September 30, 2010 compared to 9.5% for the same period in the prior year.

~~Amortization~~In ~~expense~~connection ~~for~~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 and professional fees and change of control provisions. The three and four months ended ~~September~~June 30, ~~2010~~2011 ~~increased~~includes Parent allocations of interest charges of approximately $71969,000 toand $1.3 million, ~~compared~~respectively, toand other administrative charges of approximately $1.28 million. ~~for~~Parent ~~the~~administrative ~~three~~charges ~~months~~are ~~ended~~allocated ~~September 30,~~proportional ~~2009~~to the average EBIT and revenue contribution. The ~~increase~~allocation method used is considered reasonable by ~~primarily~~management ~~related~~and our estimated costs that would have been incurred on a stand alone basis would not have been materially different. The amount due to ~~the~~Parent ~~amortization~~was ofapproximately ~~intangibles~~$74.4 million ~~recorded~~at inJune 30, ~~connection~~2011 ~~with~~and ~~the~~balance ~~acquisition~~is ofclassified as a long-term liability. The interest rate used for allocation ~~AWC~~of interest charges was 5.3% as of June 30, 2011.

WeNOTE ~~had~~13 ~~$11.5 million~~— inSUBSEQUENT ~~income from operations for the three months ended September 30, 2010,~~EVENT compared to a $3.1 million loss from operations for the three months ended September 30, 2009, for a total increase of $14.6 million. The income from operations in the third quarter of 2010 is due to the improvement in the performance of our Oilfield Services and Rental Services segments offset by a decrease in income from operations of our Drilling and Completion segment.

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.

~~Our~~ITEM ~~interest expense was $11~~2.~~9 million~~ ~~for~~MANAGEMENT’S ~~the~~DISCUSSION ~~three~~AND ~~months~~ANALYSIS ~~ended~~OF ~~September 30,~~FINANCIAL ~~2010,~~CONDITION ~~compared~~AND toRESULTS $10.8 million for the three months ended September 30, 2009. During the three months ended September 30, 2010 we had borrowings of $36.5 million under our revolving credit facility compared to no borrowings at September 30, 2009. Of the $36.5 million borrowed under our revolving credit facility, $16.5 million was borrowed on the date we acquired AWC. Interest expense includes amortization expense of deferred financing costs of $555,000 and $539,000 for the three months ended September 30, 2010 and 2009, respectively.

~~Our~~OF ~~income tax expense for the three months ended September 30, 2010 was $1.6 million on a net loss~~OPERATIONS before income taxes, compared to an income tax benefit of $4.1 million for the three months ended September 30, 2009. The difference between the actual and expected income tax benefit as a percentage of our net loss was due to an increase in withholding taxes from foreign operations as a percentage of pre-tax income in the 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.

WeThe ~~had~~following adiscussion ~~net~~and ~~loss~~analysis ofshould $2be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this report.~~6 million~~ ~~for~~This report contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from the ~~three~~results ~~months~~discussed ~~ended~~in ~~September 30,~~such ~~2010~~forward-looking statements. Factors that might cause such differences include, ~~compared~~but are not limited to, ~~net loss~~the general condition of ~~$9.7 million~~the oil and natural gas drilling industry, demand for ~~the~~our ~~three~~oil ~~months~~and ~~ended~~natural ~~September 30~~gas service and rental products, ~~2009~~and ~~due~~competition. For more information on forward-looking statements please refer to the ~~foregoing~~section ~~reasons~~entitled “Forward-Looking Statements” on page 39.

~~The~~Overview net loss attributed to common stockholders for the three months ended September 30, 2010 and 2009 was $3.2 million and $10.3 million, respectively, after $637,000 and $630,000 in preferred stock dividends, respectively. The preferred stock dividend relates to 36,393 shares of ~~$1,000~~Our ~~par~~Business ~~value preferred shares at 7.0% issued at the end of June 2009.~~

~~The~~We ~~following~~are ~~table~~a ~~compares~~multi-faceted ~~revenues~~oilfield ~~and~~service ~~income~~company ~~(loss) from~~that ~~operations~~provides ~~for~~services ~~each~~and ofequipment ~~our~~to ~~business~~oil and ~~segments~~natural ~~for~~gas exploration and production companies, throughout the ~~three~~United ~~months~~States ~~ended~~including ~~September 30~~Texas, Louisiana, ~~2010~~Pennsylvania, ~~and~~Arkansas, ~~2009.~~West ~~Income~~Virginia, ~~(loss) from~~Oklahoma, ~~operations consists~~Colorado, offshore in the Gulf of Mexico ~~our~~and ~~revenues~~internationally ~~less~~primarily ~~direct~~in ~~costs~~Argentina, ~~selling~~Brazil, ~~general~~Bolivia and ~~administrative~~Mexico. ~~expenses,~~We operate in two ~~depreciation~~sectors of the oil and ~~amortization~~natural gas service industry: Well Services and Drilling Services.

	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

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.

~~Oilfield~~Our ~~Services~~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.

~~Revenues~~Merger ~~for~~with ~~our Oilfield Services segment were $56.7 million for the three months ended September~~Archer 30, 2010, an increase of 77.7%, compared to $31.9 million in revenues for the three months ended September 30, 2009. Income from operations increased $11.7 million and resulted in income from operations of $7.5 million in the third quarter of 2010 compared to loss from operations of $4.2 million in the third quarter of 2009. Our Oilfield Services segment revenues and operating income for the third quarter of 2010 increased compared to the third quarter of 2009 due principally to improved pricing and utilization for our directional drilling services, tubular services 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 count for the thirteen weeks 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~~On February 23, 2011, we merged with and ~~Completion~~into Wellco Sub Company, a wholly owned subsidiary of Archer, and each share of our common stock was converted into the right to receive either 1.15 Archer common shares or $4.25 in cash. In connection with the Merger, Wellco Sub Company changed its name to Allis-Chalmers Energy Inc.

~~Revenues~~We ~~for~~recorded ~~the~~approximately ~~quarter ended September~~$14.7 30million, ~~2010~~$1.6 million ~~for the Drilling~~ and ~~Completion segment were~~ $962.35 million, ~~an increase~~ of ~~26.2%,~~costs ~~compared~~related to ~~$76.3 million~~the merger induring ~~revenues for~~ the ~~quarter~~two months ended ~~September~~ February 3028, ~~2009.~~2011 Inand ~~spite~~the ofthree ~~improved rig utilization~~ and ~~pricing~~four ~~for~~months ~~our~~ended ~~drilling rigs in~~June 30, ~~Argentina~~2011, ~~and Bolivia~~respectively, ~~income~~which ~~from~~are ~~operations~~included ~~decreased~~in toselling, ~~$5.1 million~~general inand ~~the~~administrative ~~third~~expense ~~quarter~~on ofour ~~2010~~Consolidated ~~compared~~Condensed toStatements ~~$5.5 million in the third quarter~~ of ~~2009~~Operations. ~~This~~Approval ~~reduction~~of ~~was~~the ~~due~~merger ~~to:~~resulted ~~(1) reduced rig utilization and rig rates~~ in ~~Brazil;~~certain ~~(2) an increase~~ of ~~$1.3 million, or 24.4%, in depreciation~~our ~~and~~contractual ~~amortization;~~obligations ~~(3) increased~~being ~~labor~~triggered ~~and~~or ~~other~~accelerated ~~costs~~under inthe ~~Argentina;~~“change ~~offset~~of bycontrol” ~~$1.1 million~~provisions of ~~severance~~such ~~costs~~contractual ~~during~~arrangements. ~~the~~Examples ~~three~~of ~~months~~such ~~ended~~arrangements ~~September 30,~~include ~~2009~~stock-based ~~related to workforce reductions in~~compensation ~~Argentina~~awards, asseverance aand ~~result~~retirement ofplan ~~lower~~agreements ~~activity~~applicable atto ~~that~~executive ~~time.~~officers, ~~The~~directors ~~increase in depreciation~~ and ~~amortization~~certain ~~expense~~employees ~~was~~and ~~the~~certain ~~result~~other ofdebt ~~the~~obligations, ~~capital~~including ~~spending~~our ~~programs~~senior ~~over the last two years~~notes.

~~Rental~~Results ~~Services~~of Operations

~~Revenues~~In ~~for the quarter ended September~~July ~~30,~~ 2010 ~~for the Rental Services segment increased 80.2% to $21.3 million from $11.8 million in revenues for the quarter ended September 30~~, ~~2009.~~we ~~Income from~~acquired ~~operations~~all ~~increased~~of ~~to $3.3 million in~~ the ~~third~~outstanding ~~quarter~~stock of ~~2010~~American ~~compared~~Well toControl, $1Inc.~~2 million operating~~, ~~loss~~or ~~in the third quarter of 2009. The acquisition of~~ AWC ~~provided our Rental Services~~, ~~segment~~which ~~with~~is ~~$6.8 million~~reported ofas ~~additional~~part ~~revenues and $2.4 million~~ of ~~additional~~our ~~operating~~Well ~~income during the third quarter of 2010. Our Rental~~ Services segment. ~~revenues~~We ~~and~~consolidated ~~operating income for~~ the ~~third~~results ~~quarter~~ of ~~2010 also increased compared to the prior year due to our strategy of~~this ~~redeploying~~transaction ~~equipment and focusing our marketing efforts~~ from the ~~U.S.~~date ~~Gulf~~it ofwas ~~Mexico to the onshore unconventional natural gas fields in the U~~effective.~~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. and therefore has high utilization and improved pricing.~~

~~General~~In ~~Corporate~~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.

~~General~~The ~~corporate~~foregoing ~~expenses~~business ~~increased~~combinations ~~$1.2 million~~affect ~~to $4.4 million for~~ the ~~three~~comparability ~~months~~from ~~ended September 30,~~period ~~2010 compared~~ to ~~$3.1 million~~period ~~for~~of ~~the three months ended September 30, 2009. The~~our ~~increase~~historical ~~was due to an increase in professional fees for the three months ended September 30~~results, ~~2009. Professional~~and ~~fees~~our ~~for~~historical ~~the~~results ~~three~~may ~~months~~not ~~ended~~be ~~September 30,~~indicative ~~2010 included $578,000~~ of ~~costs~~our ~~related to~~future ~~the pending merger, $140,000 of costs related to the acquisition of AWC and a $225,000 lawsuit settlement~~results.

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

Our revenues for the ~~nine~~three months ended ~~September~~June 30, ~~2010~~2011 were $~~473~~220.31 million, an increase of 2538.38% compared to $~~377~~158.6 million for the ~~nine~~three months ended ~~September~~June 30, ~~2009~~2010. The increase in revenues is is due to the increase in revenues in ~~our~~both ~~Oilfield~~of ~~Services and Drilling and Completion segments, offset in part by a decrease in revenues in~~ our ~~Rental~~operating ~~Services segment~~segments. Our ~~Oilfield~~Drilling Services ~~segment~~ segment revenues increased 3827.09% to $~~146~~188.10 million for the ~~nine~~three months ended ~~September~~June 30, ~~2010~~ 2011 compared to $~~105~~146.89 million for the ~~nine~~three months ended ~~September~~June 30, ~~2009~~2010 due to increased utilization ~~of our equipment~~ and ~~improved~~rig ~~pricing compared to the nine months ended September 30,~~rates ~~2009.~~in ~~Our~~Argentina ~~Drilling~~ and ~~Completion~~Bolivia ~~segment~~and ~~revenues~~ increased ~~25.8%~~utilization toof ~~$280.8 million for the nine months ended September 30, 2010 compared to $223.2 million for the nine months ended September 30, 2009. The increase in revenues in~~ our ~~Drilling~~equipment and ~~Completion~~improved ~~segment was due to increased~~pricing ~~utilization and rig rates in Argentina and Bolivia~~domestically. Revenues for our ~~Rental~~Well Services segment ~~decreased~~ 4increased 174.32% to $4632.52 million for the three ~~nine~~ months ended ~~September~~June 30, ~~2010~~2011 compared to $4811.6 7 million for the ~~nine~~three months ended ~~September~~ June 30, ~~2009~~ 2010 due to ~~decreased~~$9.7 million ~~equipment~~of ~~utilization~~revenues ~~due~~from ~~to a~~AWC ~~decline~~ in ~~drilling activity in~~ the ~~U.S.~~current ~~Gulf~~period, ofalong ~~Mexico~~with ~~compared~~an toincreased ~~the~~utilization of ~~nine~~our ~~months~~equipment ~~ended September 30,~~and ~~2009~~improved pricing.

Our direct costs for the ~~nine~~three months ended ~~September~~June 30, ~~2010~~2011 increased 2634.7% to $~~356~~162.16 million, or 7573.29% of revenues, compared to $~~281~~120.17 million, or 7476.41%, of revenues for the ~~nine~~three months ended ~~September~~June 30, ~~2009~~2010. Our direct costs in all of our segments increased in absolute dollars in the ~~nine~~ three months ended ~~September~~June 30, ~~2010~~2011 compared to the ~~nine~~three months ended ~~September~~June 30, ~~2009~~2010. Our ~~Oilfield~~ ~~Services~~Drilling Services segment revenues for the ~~nine~~three months ended ~~September~~June 30, ~~2010~~2011 increased 3827.09% from revenues for the three ~~nine~~ months ended ~~September~~June 30, ~~2009,~~2010 ~~while~~and direct costs increased 2427.98% over that same period,. ~~resulting~~Our inWell Services ansegment ~~improvement in gross margin as a percentage of~~ revenues ~~to 28.3%~~ for the ~~nine~~three months ended ~~September~~June 30, ~~2010~~2011 ~~compared~~increased ~~to 20~~174.82% from revenues for the ~~nine~~three months ended ~~September~~ June 30, ~~2009.~~2010, ~~Our~~while ~~Oilfield~~direct ~~Services~~costs ~~segment~~increased ~~began~~122.6% toover ~~realize~~that ~~price~~same period. ~~increases~~The ~~starting~~improvement in ~~the~~gross ~~later part~~margin ofis ~~the~~due ~~first~~to ~~quarter~~improved ofutilization ~~2010. In addition, we had $1.2 million~~ of ~~expenses~~equipment ~~recorded~~and ~~during~~pricing ~~the~~which ~~nine~~was ~~months~~slightly ~~ended~~offset ~~September 30,~~by ~~2009~~the ~~related~~impact toof ~~severance payments,~~ the ~~closing~~acquisition of ~~unprofitable locations~~AWC. ~~and~~AWC ~~downsizing~~provided ~~other locations~~$9.7 million ~~Our Drilling and Completion segment~~ of revenues ~~for~~during the ~~nine~~ three months ended ~~September~~June 30, ~~2010~~2011 ~~increased~~and ~~25.8%~~it ~~from~~also ~~revenues~~increased ~~for the nine months ended September 30, 2009, while~~ direct costs ~~increased~~by 28$6.8%0 million ~~over~~for ~~that~~the same period. Asfor aan ~~result,~~effective ~~direct costs~~gross margin as a percentage of revenues ~~increased~~of ~~to 82~~38.73% ~~for the nine months ended September 30, 2010~~. ~~compared~~AWC’s togross ~~80.8%~~margin ~~for~~as ~~the~~a ~~nine~~percentage ~~months~~of ~~ended September 30, 2009. Our Rental Services segment~~ revenues ~~for~~is ~~the~~less ~~nine~~than ~~months~~our ~~ended~~overall ~~September 30,~~Well ~~2010~~Services ~~decreased~~gross ~~4.3% from revenues for the nine~~margin ~~months~~percentage ~~ended~~as ~~September 30,~~AWC’s ~~2009,~~manufacturing ~~while~~operation ~~direct~~has ~~costs~~a ~~increased~~higher ~~12.3%~~labor ~~over that same period~~component. Gross margin as a percentage of revenues for our ~~Rental~~Well Services segment for the ~~nine~~three months ended ~~September~~ June 30, ~~2010~~2011 was 5939.05% compared to 6525.05% for the ~~nine~~three months ended ~~September~~June 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 month period ending September 30, 2010 for an effective gross margin as a percentage of revenues of 40.6%. Our direct costs for the Rental Services segment are largely fixed because they primarily relate to yard expenses to maintain the rental inventory. In addition, direct costs associated with the operations of AWC offset direct cost reductions in our other rental activities.

Depreciation expense increased 612.12% to $6123.80 million for the ~~nine~~three months ended ~~September~~June 30, ~~2010 from~~2011 from $5820.35 million for the ~~nine~~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~~Services ~~Completion~~ segment. Depreciation expense as a percentage of revenues decreased to 1310.15% for the ~~first~~second ~~nine months~~quarter of ~~2010~~2011, compared to 15 12.49% for the ~~first~~second ~~nine~~quarter ~~months~~ of ~~2009~~2010, due to the ~~increase~~noted increases in revenues.

Selling, general and administrative expense was $15.4 million for the three months ended June 30, 2011 compared to $12.1 million for the three months ended June 30, 2010. Selling, general and administrative expense increased primarily due to an increase in severance expense and other professional fees for the three months ended June 30, 2011 compared to the same period of the prior 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 June 30, 2010 was $1.6 million with no related expense for the three months ended June 30, 2011 due to the acceleration of stock based compensation expense as of the Merger date. As a percentage of revenues, selling, general and administrative expense was 7.0% for the three months ended June 30, 2011 compared to 7.6% for the same period in the prior year.

~~Selling,~~Amortization ~~general and administrative~~ expense ~~was $36.9 million~~ for the ~~nine~~three months ended ~~September~~ June 30, ~~2010~~2011 ~~compared~~increased to $403.62 million ~~for the nine months ended September 30, 2009. Selling, general and administrative expense decreased primarily due~~ to a reduction in bad debt expense for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 and cost reduction steps that were made in the nine months ended September 30, 2009 in response to market conditions, offset in part by an increase in the amortization of share-based compensation arrangements and the increase in professional fees related to transactions$4. ~~During the nine months~~4 ~~ended~~million ~~September 30, 2010, we recorded bad debt expense of $43,000~~ compared to $4.1 .2 million ~~in bad debt expense~~ for the ~~nine~~three months ended ~~September~~June 30, ~~2009~~2010. ~~Professional~~The ~~fees~~increase ~~for~~is ~~the~~primarily ~~nine months ended September 30, 2010 included $578,000 of costs~~ related to the ~~pending merger, $140,000 of~~ ~~costs~~amortization ~~related to the acquisition~~ of ~~AWC~~intangibles ~~and~~recorded ~~a $225,000 lawsuit settlement. Selling, general and administrative expense includes share-based compensation expense of $4.4 million~~ in ~~the~~connection ~~nine~~with ~~months ended September 30, 2010 and $3.6 million in~~ the ~~nine months ended September 30, 2009~~Merger. ~~As a~~ ~~percentage of revenues, selling, general and administrative expenses were 7.8% for the nine months ended September 30, 2010 compared to 10.8% for the same period in the prior year.~~

~~During~~We had income from operations of $14.7 million for the ~~nine~~three months ended ~~September~~June 30, ~~2009~~2011, wecompared to ~~recorded~~income afrom operations of $14.91 million ~~loss~~for onthe anthree ~~asset disposition~~months ~~from~~ended ~~the~~June 30, ~~total~~2010. ~~loss~~The ofincrease in aincome ~~rig~~ from aoperations ~~blow-out~~was inmainly ~~our~~due ~~Drilling~~to ~~and~~the ~~Completion~~increase ~~segment. The~~in ~~insurance~~revenues ~~proceeds~~and ~~for~~improved ~~the~~margins ~~loss~~which ~~were~~was partially ~~not~~offset ~~sufficient~~by tothe ~~cover~~increases ~~the~~in ~~book~~depreciation, ~~value~~amortization ofand ~~the~~selling, ~~rig~~general and ~~related~~administrative ~~assets~~expenses.

WeOur ~~had~~interest ~~income~~expense ~~from~~was ~~operations of~~ $1410.91 million for the ~~nine~~three months ended ~~September~~June 30, ~~2010~~2011, compared to a $711.8 1 million ~~loss from operations~~ for the ~~nine~~three months ended ~~September~~June 30, ~~2009,~~2010. ~~for~~Approximately ~~a total increase of~~ $2251.85 million. ~~The~~of ~~increase~~our debt was paid in ~~income~~connection ~~from~~with ~~operations~~the Merger. Interest expense for the ~~nine~~three months ended ~~September~~ June 30, ~~2010~~2011 iswas reduced ~~due~~by toapproximately ~~the~~$1.1 million ~~improved~~in ~~performance~~connection ofwith ~~our~~debt ~~Oilfield~~premium ~~Services~~amortization and ~~Drilling and~~interest ~~Completion~~expense ~~segments,~~for ~~partially offset by a decline in performance of~~ the ~~Rental~~three ~~Services segment. The nine~~ months ended ~~September~~June 3020, ~~2009~~2010 ~~was~~includes ~~also~~amortization ~~negatively~~expense ~~affected~~of bydeferred financing ancosts ~~additional~~of $4554,000.~~0 million of~~ ~~bad~~Interest ~~debt~~ expense, afor ~~$1.9 million~~the ~~loss~~three onmonths anended ~~asset disposition and $3.2~~June ~~million~~30, of2011 ~~expenses~~included ~~related~~approximately ~~to severance payments~~$969,000 ~~the closing~~ of ~~unprofitable~~allocated ~~locations~~interest ~~and~~charges ~~downsizing~~from ~~other locations~~our Parent.

~~Our~~Income ~~interest~~tax expense ~~was $34.0 million~~ for the ~~nine~~three months ended ~~September~~June 30, ~~2010,~~2011 ~~compared~~was to $373.50 million ~~for~~or ~~the nine months ended September 30, 2009~~63.6% ~~On June 29, 2009, we purchased approximately $74.8 million~~ of our ~~senior notes with approximately $125.6 million in proceeds from~~income ~~our~~before ~~backstopped~~income ~~common~~taxes ~~stock~~compared ~~rights~~to ~~offering~~an ~~and~~income ~~preferred~~tax ~~stock~~benefit ~~private placement. On June 29, 2009, we also prepaid our outstanding loan balance under our revolving credit facility~~ of $351.0 6 million ~~from~~or ~~those same equity proceeds~~23.4% Atof ~~September 30,~~our ~~2010~~net ~~we had an outstanding loan balance~~loss ~~under~~before ~~our~~income ~~revolving~~taxes ~~credit~~from ~~facility of $36~~2010.~~5 million,~~ ~~all~~The ofchange ~~which~~in ~~had been borrowed during~~ the ~~third~~ ~~quarter~~tax ofrate ~~2010.~~is Weprincipally ~~borrowed~~the ~~$16.5 million~~result of ~~the~~valuation allowances ~~$36.5 million~~on ~~borrowed~~losses ~~under~~generated ~~our~~in ~~revolving credit facility on~~ the ~~date~~United weStates ~~acquired~~and ~~AWC.~~variances ~~Interest~~in ~~expense~~withholding ~~includes~~taxes ~~amortization~~from ~~expense of~~foreign ~~deferred~~operations ~~financing~~as ~~costs~~a percentage of ~~$1.7 million~~pretax ~~for~~income ~~the nine months ended September 30, 2010 and 2009~~(loss).

~~During~~We ~~the~~had ~~nine~~net ~~months~~income ~~ended September 30, 2009, we recorded a gain~~ of $261.47 million asfor athe ~~result~~three ~~of tender~~months ~~offers~~ended ~~that we completed on~~ June 2930, ~~2009.~~2011, Wecompared ~~purchased~~to ~~approximately~~net ~~$30.6 million aggregate~~loss ~~principal amount~~ of ~~our 9.0% senior notes and $44.2 million aggregate principal amount of~~ ~~our 8.5% senior notes for approximately~~ $465.4 million. ~~The~~for ~~gain is net of a $1.5 million write-off of debt issuance costs related to~~ the ~~retired~~three ~~notes~~months ~~and~~ended ~~we incurred approximately $466~~June 30,~~000~~ ~~in expenses~~2010 ~~related~~due to the ~~transactions~~foregoing reasons.

~~Our~~The ~~income~~net ~~tax~~loss ~~benefit~~attributed to common stockholders for the ~~nine~~three months ended ~~September~~June 30, 2010 was $3.6 ~~million, or 16~~.~~9% of~~0 ~~our~~million ~~net~~after ~~loss before income taxes, compared to an income tax benefit of~~ $~~6.8 million~~637,000 orin ~~35.5%~~preferred ~~of our~~stock ~~net loss before income taxes for the nine months ended September 30, 2009~~dividends. The ~~decrease~~preferred ~~in income~~stock ~~tax~~dividend ~~benefit~~related ~~as a percentage of our net loss was due~~ to ~~an increase in withholding taxes from~~our ~~foreign~~36,393 ~~operations~~shares ~~as a percentage~~ of ~~pre-tax~~$1,000 ~~income~~par invalue ~~2010~~preferred ~~and~~shares ~~the~~at ~~effect of nondeductible items on our domestic tax~~7. ~~The consolidated effective income tax benefit rate is affected by the profitability and effective income tax rate of our operations in foreign jurisdictions~~0%.

WeThe ~~had~~following atable ~~net~~compares revenues and income (loss) from operations for each of ~~$17.5 million~~our business segments for the ~~nine~~quarter ~~months~~ ended ~~September~~June 30, ~~2010,~~2011 ~~compared~~and to2010. ~~net~~ Income (loss) from ofoperations ~~$12.3 million~~consists ~~for~~of our ~~the~~revenues ~~nine~~less ~~months~~direct ~~ended~~costs, ~~September 30~~selling, ~~2009~~general ~~due~~and toadministrative ~~the~~expenses, ~~foregoing~~depreciation ~~reasons.~~and amortization:

The net loss attributed to common stockholders for the nine months ended September 30, 2010 and 2009 was $19.4 million and $13.0 million, respectively, after $1.9 million and $665,000 in preferred stock dividends, respectively. The preferred stock dividend relates to 36,393 shares of $1,000 par value preferred shares at 7.0% issued at the end of June 2009.


	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

Drilling Services

Revenues for the quarter ended June 30, 2011 for the Drilling Services segment were $188.0 million, an increase of 27.9% compared to $146.9 million in revenues for the quarter ended June 30, 2010. Income from operations increased $3.5 million and resulted in income from operations of $8.1 million for the quarter ended June 30, 2011 compared to income from operations of $4.6 million in the three months ended June 30, 2010. The revenue increase was due to our investment in new equipment, increased 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 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 other professional fees of $1.2 million for the three months ended June 30, 2011; (2) allocations of $1.3 million of Parent general and administration charges; (3) decrease in utilization and pricing for our land drilling services in Brazil; and (4) an increase of $4.6 million, or 23.9%, in depreciation and amortization in the second quarter of 2011 compared to the second quarter of 2010. The increase in depreciation and amortization expense was the result of capital expenditure programs and Merger related adjustments to the fair value of intangible assets.

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

	Revenues							Income (Loss) from Operations
	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

Revenues for the quarter ended June 30, 2011 for the Well Services segment were $32.2 million, an increase of 174.2% compared to $11.7 million in revenues for the quarter ended June 30, 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 a loss from operations of $417,000 in the three months ended June 30, 2010. The acquisition of AWC provided our Well Services segment with $9.7 million of additional revenues and $2.6 million of additional operating income during the second quarter of 2011. We also had improved utilization and pricing for our coil tubing units. Partially offsetting the improved results in the three months ended June 30, 2011 were: (1) allocations of merger related costs consisting of severance expense and other professional fees of $400,000 for the three months ended June 30, 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 the second quarter of 2010. The increase in depreciation and amortization expense was the result of capital expenditure programs and Merger related adjustments to the fair value of intangible assets.

~~Oilfield~~Comparison ~~Services~~of Six Months Ended June 30, 2011 and 2010

~~Revenues~~Our ~~for~~revenues ~~our Oilfield Services segment were $146.1 million~~ for the ~~nine~~six months ended ~~September~~ June 30, ~~2010~~2011 were $417.7 million, an increase of 3839.07% compared to $~~105~~299.80 million ~~in revenues~~ for the ~~nine~~six months ended ~~September~~ June 30, ~~2009~~2010. ~~Income~~The ~~from~~increase ~~operations increased $23.7 million and resulted~~ in ~~income~~revenues ~~from~~is due ~~operations~~to ofthe ~~$8.0 million~~increase in ~~the~~revenues ~~first~~in ~~nine~~both ~~months~~ of ~~2010~~our ~~compared~~operating ~~to a loss from operations of $15~~segments.~~7 million~~ ~~in the first nine months of 2009.~~ Our ~~Oilfield~~Drilling Services segment revenues ~~and operating~~increased ~~income~~27.4% to $353.3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 ~~increased~~ compared to $277.4 million for the ~~nine~~six months ended ~~September~~June 30, ~~2009~~2010 due ~~principally~~ to ~~improved pricing and utilization for~~ our ~~directional drilling~~investment ~~services, tubular services and our coiled tubing units. Our capital expenditures~~ in ~~the Oilfield Services segment have emphasized~~ new ~~downhole directional drilling~~ equipment, ~~upgrading~~ ~~coil~~increased ~~tubing~~utilization ~~units~~ and ~~investing~~rig rates in ~~pressure~~Argentina ~~control~~and ~~units~~Bolivia toand ~~serve~~increased ~~unconventional~~utilization ~~natural~~of ~~gas drilling activity. As stated earlier~~ our ~~Oilfield Services segment activity is tied to the rig~~ ~~count~~equipment ~~in the U.S.~~ and ~~the~~improved ~~Baker~~pricing ~~Hughes~~domestically. ~~average~~Revenues ~~rig count~~ for ~~the~~our ~~thirty-nine~~Well ~~weeks~~Services insegment ~~the first~~increased ~~nine~~198.6% ~~months of 2010 was 1,498 compared~~ to an$64.4 million ~~average rig count of 1,067~~ for the ~~thirty-nine~~six ~~weeks in the first nine~~ months ~~of 2009. During the nine months~~ ended ~~September~~June 30, ~~2009,~~2011 wecompared ~~incurred~~ to $121.26 million offor ~~costs related to severance payments,~~ the ~~closing of unprofitable locations and~~ ~~downsizing~~six ~~other~~months ~~locations~~ended ~~in our Oilfield Services segment. In addition~~June, we2010 ~~increased~~due ~~our~~to ~~bad debt reserve by recording~~ $319.18 million of ~~bad~~revenues ~~debt~~from ~~expense~~AWC ~~for~~in the ~~Oilfield~~current ~~Services segment during the nine months ended September 30~~period, ~~2009 as a result of the decreased oil and natural gas prices~~along ~~and~~with ~~the~~an ~~financial~~increased ~~difficulties~~utilization ~~that some~~ of our ~~customers~~equipment ~~were~~and ~~facing.~~improved ~~We recorded $43,000 of bad debt expense for the nine months ended September 30, 2010 for the Oilfield Services segment~~pricing.

Our direct costs for the six months ended June 30, 2011 increased 36.1% to $310.9 million, or 74.4% of revenues, compared to $228.4 million, or 76.4%, of revenues for the six months ended June 30, 2010. Our direct costs in all of our segments increased in absolute dollars in the six months ended June 30, 2011 compared to the six months ended June 30, 2010. Our Drilling Services segment revenues for the six months ended June 30, 2011 increased 27.4% from revenues for the six months ended June 30, 2010, while direct costs increased 27.9% over that same period, resulting in a minor reduction in gross margin as a percentage of revenues to 23.0% for the six months ended June 30, 2011 compared to 23.4% for the six months ended June 30, 2010. Our Drilling Services segment began to realize price increases starting in the later part of the first quarter of 2010 with the related improvement being offset by a decrease in utilization and ~~Completion~~pricing for our land drilling services in Brazil. Our Well Services segment revenues for the six months ended June 30, 2011 increased 198.6% from revenues for the six months ended June 30, 2010, while direct costs increased 145.0% over that same period. The improvement in gross margin 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 during the six months ended June 30, 2011 and it also increased direct costs by $13.0 million for the same period for an effective gross margin as a percentage of revenues of 34.4%. 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 six months ended June 30, 2011 was 39.6% compared to 26.3% for the six months ended June 30, 2010.

~~Revenues~~Depreciation ~~for~~expense ~~the~~increased ~~nine months ended September 30, 2010 for the Drilling and Completion segment were $280~~11.~~8 million, an increase of 25.8~~5% ~~compared~~ to $~~223~~45.24 million ~~in revenues~~ for the ~~nine~~six months ended ~~September~~June 30, ~~2009.~~2011 ~~Income~~ from ~~operations increased to $17.6 million in the first nine~~ ~~months of 2010 compared to~~ $1440.47 million for the ~~first~~six ~~nine~~ months ~~of 2009. This increase was due to: (1) improved rig utilization and rig rates in Argentina and Bolivia during the nine months~~ ended ~~September~~June 30, 2010~~; (2) a $1~~.~~9 million~~ ~~non-cash~~The ~~loss~~primary ~~recorded~~increase in ~~the~~depreciation ~~nine months ended~~expense ~~September 30,~~is ~~2009~~due onto anour ~~asset~~capital ~~disposition~~expenditure ~~from~~programs ~~the~~for ~~total~~our ~~loss~~Drilling ofServices ~~a rig from a blow-out; (3) $1~~segment.~~4 million~~ ofDepreciation ~~severance costs during the nine months ended September 30, 2009 related to workforce~~expense ~~reductions in Argentina~~ as a ~~result~~percentage of ~~lower~~revenues ~~activity~~decreased ~~and (4) $329,000 of costs incurred~~ to ~~consolidate~~ ~~operating~~10.9% ~~locations~~for ~~in Brazil during~~ the ~~nine~~first ~~months~~half ~~ended~~of ~~September 30~~2011, ~~2009. Partially~~compared ~~offsetting~~to ~~the~~13.6% ~~improved results in~~ for the first ~~nine~~half ~~months~~ of 2010, ~~was~~due ~~decreased~~to ~~rig utilization~~the ~~and~~noted ~~pricing~~increases in ~~Brazil and an increase in depreciation and amortization expense of $3~~revenues.4 ~~million. The increase in depreciation and amortization was the result of our capital expenditures spending programs over the last two years.~~

Selling, general and administrative expense was $43.9 million for the six months ended June 30, 2011 compared to $24.2 million for the six months ended June 30, 2010. Selling, general and administrative expense increased primarily due to an increase in stock based compensation expense, severance expenses and professional and other fees for the six months ended June 30, 2011 compared to the same period of the prior year all due principally to the Merger. Stock based compensation for the six months ended June 30, 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 was $3.0 million in the same period of the prior year. The six months ended June 30, 2011 includes approximately $4.6 million of severance expense relating to the separation of certain executives after the Merger. Professional and other fees for the six months ended June 30, 2011 included $7.1 million of costs related to the Merger. The six months ended June 30, 2011 also includes $1.7 million of allocated general and administrative expenses from our Parent and other increases related to additional operating activities. As a percentage of revenues, selling, general and administrative expense was 10.5% for the six months ended June 30, 2011 compared to 8.1% for the same period in the prior year.

~~Rental~~During ~~Services~~the six months ended June 30, 2011, we recorded a $5.1 million loss on the impairment of intangible assets. In connection with the 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.

~~Revenues~~Amortization expense for the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 ~~for~~increased ~~the Rental Services segment were~~ $~~46.5 million, a decrease of~~ 4.3~~% from $48.6~~ million into ~~revenues for the nine months ended September 30, 2009. Our Rental Services segment generated an operating income of~~ $16.6 million ~~in the nine months~~ ~~ended September 30, 2010~~ compared to $32.3 million ~~operating income~~ for the ~~first~~six ~~nine~~ months of 2009. The decrease in segment revenues and operating income for the first nine months of 2010 compared to the same period of the prior year was due primarily to the decrease in utilization of our rental equipment due to a decline in drilling activity in the U.S. Gulf of Mexico. Offsetting a portion of the impact of the decline was the acquisition of AWC which provided our Rental Services segment with $6.8 million of additional revenues and $2.4 million of additional operating income during the nine months ended ~~September~~June 30, 2010. ~~Also,~~The ~~our income from operations for the nine months ended September 30, 2009 included $950,000 of bad debt expense to~~ increase ~~the~~is ~~bad~~primarily ~~debt reserve for Rental Services segment customers who were facing financial difficulties, and $237,000 of costs~~ related to ~~closing a rental yard and reducing our workforce. We recorded no bad debt expense for~~ the ~~first nine months of 2010. In addition, depreciation and~~ amortization ~~expense for our Rental Services segment decreased $651,000 or 2.9%, in the first nine months~~ of ~~2010~~intangibles ~~compared to~~recorded ~~the first nine months of 2009 due primarily to a $584,000 reduction~~ in ~~the~~connection ~~carrying~~with ~~value of our airplane resulting from~~ the ~~sales proceeds received in April 2009~~merger.

~~General~~Income ~~Corporate~~from operations was $5.8 million for the six months ended June 30, 2011 compared to $3.4 million for the six months ended June 30, 2010. The increase in income from operations was mainly due to the increase in revenues and improved margins which was partially offset by the impairment of intangible assets and increases in depreciation, amortization and selling, general and administrative expenses.

~~General~~Our ~~corporate~~interest ~~expenses~~expense ~~increased~~was $221.47 million ~~to $12.3 million~~ for the ~~nine~~six months ended ~~September~~ June 30, ~~2010~~2011, compared to $922.9 1 million for the ~~nine~~six months ended ~~September~~June 30, ~~2009~~2010. ~~The increase~~Approximately ~~was~~$51.5 million ~~due~~of toour ~~the~~debt ~~increase~~was paid in ~~share-based~~connection ~~compensation~~with ~~expense,~~the ~~increased~~Merger. ~~professional~~Interest ~~fees related~~expense toincludes ~~transactions~~amortization ~~and~~expense ~~increased~~of ~~insurance~~deferred financing ~~and travel~~ costs toof ~~support~~$366,000 ~~our~~and ~~international business development initiatives. Share-based compensation expense included in general corporate expenses was~~ $31.41 million infor the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 ~~compared~~and ~~to $2.8 million in the nine months ended September 30~~2010, ~~2009~~ respectively. ~~Professional~~Interest ~~fees~~expense for the ~~nine~~six months ended ~~September~~ June 30, ~~2010~~2011 included approximately $~~578,000~~1.3 million of ~~costs~~allocated ~~related~~interest tocharges ~~the~~from ~~pending~~our ~~merger,~~Parent ~~$140,000~~and ofwas ~~costs~~reduced ~~related~~by toapproximately ~~the~~$1.1 million ~~acquisition~~in ofconnection ~~AWC~~with ~~and~~debt apremium ~~$225,000 lawsuit settlement~~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 pre-tax non-cash loss of $1.5 million on the sale of an investment in a private oil and gas company that was assumed as part of an acquisition in 2006.

Income tax expense for the six months ended June 30, 2011 was $6.3 million or (39.9)% of our net loss before income taxes compared to an income tax benefit of $5.2 million or 25.8% of our net loss 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 pretax income (loss).

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

The net loss attributed to common stockholders for the six months ended June 30, 2011 and 2010 was $22.4 and $16.2 million after $375,000 and $1.3 million in preferred stock dividends, respectively. The preferred stock dividend related to our 36,393 shares of $1,000 par value preferred shares at 7.0%.

The following table compares revenues and income (loss) from operations for each of our business segments for the six months ended June 30, 2011 and 2010. Income (loss) from operations consists of our revenues less direct costs, selling, general and administrative expenses, impairment of intangible assets, depreciation and amortization:


	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

Drilling Services

Revenues for the Drilling Services segment for the six months ended June 30, 2011 were $353.3 million, an increase of 27.4% compared to $277.4 million in revenues for the six months ended June 30, 2010. Loss from operations was $1.5 million compared to income from operations of $4.3 million in the six months ended June 30, 2010. The revenue increase was due to

our investment in new equipment, increased 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 domestically. The increase in loss from operations was mainly due to: (1) allocations of merger related costs consisting of accelerated stock based compensation expense of $3.9 million, severance expense of $3.4 million and professional and other fees of $5.1 million for the six months ended June 30, 2011; (2) allocations of $1.3 million of Parent general and administration charges; (3) decrease in utilization and pricing for our land drilling services in Brazil; (4) a $2.9 million non-cash loss recorded in the six months ended June 30, 2011 on an intangible asset impairment and (5) an increase of $7.0 million, or 18.1%, in depreciation and amortization for the six months ended 2011 compared to the same period of the prior year. The increase in depreciation and amortization expense was the result of capital expenditure programs and Merger related adjustments to the 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 revenues for the six months ended June 30, 2010. Income from operations increased $8.2 million and resulted in income from operations of $7.3 million for the six months ended June 30, 2011 compared to a loss from operations of $925,000 in the six months ended June 30, 2010. The acquisition of AWC provided our Well Services segment with $19.8 million of additional revenues and $4.0 million of additional operating income during the 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 June 30, 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 six months ended June 30, 2011; (2) allocations of $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 of $2.0 million, or 44.8%, in depreciation and amortization in the first half of 2011 compared to the first half of 2010. The increase in depreciation and amortization expense was the result of capital expenditure programs and Merger related adjustments to the fair value of intangible assets.

Liquidity

InOur ~~June 2009,~~on-going wecapital ~~strengthened~~requirements ~~our~~arise ~~balance~~primarily ~~sheet by raising approximately $125.6 million in gross proceeds~~ from ~~the~~our ~~sale~~need ofto ~~common~~service ~~stock~~our ~~and~~debt, ato ~~newly~~acquire ~~issued series of preferred stock. The~~and ~~transactions~~maintain ~~were~~equipment, ~~effected~~to ~~through~~fund aour ~~common~~working ~~stock~~capital ~~rights~~requirements ~~offering~~and to ~~our~~complete ~~existing~~acquisitions. ~~stockholders, the~~Our ~~sale~~primary sources of ~~common~~liquidity ~~stock~~are toproceeds ~~Lime~~from ~~Rock~~Parent ~~Partners~~contributions V,and ~~L.P.,~~cash orflows ~~Lime~~from ~~Rock,~~operations. Cash ~~through~~flows ~~its~~from ~~backstop~~operations ~~commitment of~~are ~~the~~expected ~~rights~~to ~~offering,~~be ~~and~~our ~~the~~primary ~~sale~~source of ~~convertible~~liquidity ~~perpetual~~in ~~preferred~~fiscal ~~stock to Lime Rock~~2011. We ~~Approximately~~had ~~$46.4 million~~cash ofand ~~the~~cash ~~proceeds~~equivalents ~~was~~and ~~used~~restricted tocash ~~purchase an aggregate~~ of $7417.82 million ~~principal~~ ~~amount~~at ~~of our existing senior notes, approximately $35.0~~June ~~million of the proceeds was used to repay all the borrowings under our revolving bank credit facility~~30, ~~except~~2011 ~~for~~compared to $520.19 million ~~in outstanding~~at ~~letters of credit~~December 31, ~~and the remainder of the proceeds was used for general corporate purposes~~2010.

Our on-going capital requirements arise primarily from our need to service our debt, to acquire and maintain equipment, fund our working capital requirements and complete acquisitions. Our primary sources of liquidity are proceeds from the issuance of debt and equity securities and cash flows from operations. Our amended and restated revolving credit facility permits borrowings of up to $90.0 million in principal amount. As of September 30, 2010, we had $49.5 million available for borrowing under our amended and restated revolving credit facility. Our cash on hand, cash flows from operations and revolving credit facility have been and are expected to continue to be our primary source of liquidity in 2010. We had cash and cash equivalents of $15.3 million at September 30, 2010 compared to $41.1 million at December 31, 2009.

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

Operating Activities

During the ~~nine~~six months ended ~~September~~ June 30, ~~2010~~2011, our operating activities provided $2621.90 million in cash. Our net loss for the ~~nine~~six months ended ~~September~~June 30, ~~2010~~2011 was $1722.50 million. Non-cash expenses totaled $6162.5 million during the first ~~nine~~six months of ~~2010~~2011 consisting of $6552.40 million of depreciation and amortization, $45.41 million on an impairment of intangible assets, $6.1 million for share~~-based~~ based compensation expense, $~~1.7 million~~366,000 in amortization of ~~debt~~deferred ~~issuance~~financing ~~costs~~fees, $~~1.5 million~~587,000 loss on ~~the~~ sale of property anand ~~investment,~~equipment ~~$150,000~~net of ~~losses~~ ~~from asset disposals,~~ $~~409,000~~1.1 million ~~equity~~of indebt ~~loss~~premium ofamortization ~~unconsolidated~~and ~~affiliates~~$799,000 ~~partly~~for ~~offset by~~ deferred income ~~tax~~taxes ~~benefit of $12.0 million~~ related to timing differences.

35During 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 $43.0 million of depreciation and amortization, $3.0 million for share based compensation expense, $1.1 million in amortization of debt issuance costs, $1.5 million loss on the sale of an investment, $0.8 million of losses from asset disposals, $260,000 equity in loss of unconsolidated affiliates, partly offset by deferred income tax benefit of $10.8 million related to timing differences.

During the six months ended June 30, 2010, changes in operating assets and liabilities used $2.4 million in cash, principally

~~During the nine months ended September 30, 2010, changes in operating assets and liabilities used $17.1 million in cash, principally~~ due to an increase in accounts receivable of $3025.48 million, an increase in ~~inventories~~inventory of $2.7 4 million, ~~a decrease in accrued interest of $8.9 million~~ and a decrease in other long-term liabilities of $~~0.7 million~~466,000, offset in part by an increase in ~~accounts~~ accounts payable of $810.48 million, a decrease in prepaid expenses and other current assets of $8.0 8 million, an increase in accrued expenses of $53.58 million, an increase in accrued salaries, benefits ~~and~~ and payroll taxes of $21.49 million and a decrease in other assets of $10.38 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~~June 3031, ~~2010~~2011, we used $7650.4 million in investing activities, consisting of $5048.93 million for capital expenditures, $183.28 million ~~net~~increase ~~for~~in ~~the~~restricted ~~acquisition~~cash relating to deposits at a financial institution to secure outstanding letters of ~~AWC,~~ credit and a $131.0 2 million ~~for~~cash ~~other~~contribution ~~assets,~~into ~~offset~~our investment in ~~part~~our Saudi Arabia joint venture, offset by $52.3 9 million of proceeds from equipment sales ~~and $368,000 from the sale of an investment~~. Included in the $5048.93 million for capital expenditures ~~was~~were $1841.45 million for ~~our Oilfield Services segment, $20.2 million for~~ additional equipment in our Drilling ~~and~~Services ~~Completion~~ segment and $~~11.~~6.8 million for additional ~~drill pipe and other~~ 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 $4938.41 million in investing activities, consisting of $6731.30 million for capital expenditures, $110.1 million offor ~~additional~~other ~~investments~~assets, offset ~~in part~~ by ~~a decrease of~~ $72.16 million ~~in other assets, $8.0 million~~ of proceeds from equipment sales and $~~3.9 million~~368,000 infrom ~~insurance~~the ~~proceeds~~sale ~~for~~of aan ~~drilling rig destroyed by a blow-out~~investment. Included in the $6731.30 million for capital expenditures ~~was~~were $927.42 million for our ~~Oilfield~~Drilling Services segment, ~~$37.2 million for our two domestic drilling rigs~~ and $133.68 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. WeThe ~~contributed~~increase ~~$2.4 million of cash and cash~~in ~~expenditures~~other ~~into~~assets ~~our~~was ~~investment~~primarily indue ~~our~~to ~~Saudi Arabia joint venture and we received~~ $110.30 million ~~from~~ ~~insurance~~of ~~proceeds~~advance ~~related~~payments tomade atoward ~~pre-acquisition contingency with respect to BCH. The decrease in other assets was due to~~ the ~~conversion~~construction of ~~deposits on equipment purchases into capital~~ ~~expenditures~~a ~~for the~~ 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, ~~2010~~2011, financing activities provided $2321.89 million in cash. WeIn connection ~~borrowed~~with ~~$36.5 million~~the ~~under~~Merger, ~~our~~we ~~revolving~~received ~~credit~~approximately ~~facility and borrowed an additional~~ $471.04 million ~~under~~in afunding ~~long-term~~from ~~debt~~our ~~facility~~Parent. Proceeds ~~and~~were ~~repaid~~mainly ~~$14.6 million~~used into ~~borrowings~~pay ~~under~~off ~~long-term~~ debt, ~~facilities.~~debt Werelated ~~also~~interest ~~incurred~~and ~~$189,000~~merger inrelated ~~debt~~expenses. ~~issuance~~The merger ~~costs~~ related toexpenses anwere ~~amendment~~primarily tofor ~~our revolving~~legal ~~credit~~and ~~facility~~professional tofees ~~modify~~and ~~our~~change ~~loan~~of ~~covenants,~~control provisions. ~~and~~An weadditional ~~paid~~ $13.90 million in ~~preferred~~funding ~~stock dividends.~~was Insubsequently ~~addition,~~received wefrom ~~financed~~ our ~~renewal~~Parent. ofWe repaid $250.61 million in ~~insurance~~borrowings ~~policy~~under ~~premiums~~long-term ~~and issued~~debt facilities. We had a net cash outlay of $21.08 million related to the payment of ~~our~~payroll ~~common~~taxes ~~stock~~as ina ~~the~~result ~~acquisition~~of net exercises of ~~AWC~~restricted stock vestings and paid $637,000 in ~~non-cash~~preferred ~~transactions~~stock dividends.

36During the six months ended June 30, 2010, financing activities used $6.9 million in cash. We borrowed $4.0 million under a long-term debt facility and repaid $9.4 million in borrowings under long-term debt facilities. We also incurred $189,000 in debt issuance costs related to an amendment to our revolving credit facility to modify our loan covenants and we paid $1.3 million in preferred stock dividends. In addition, we financed our renewal of $2.4 million in insurance policy premiums in non-cash transactions.

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

~~During~~In ~~the~~January 2006 ~~nine~~and ~~months ended September~~August 302006, ~~2009~~we closed on private offerings, ~~financing~~to ~~activities~~qualified ~~provided~~institutional ~~$46.7~~buyers pursuant to Rule ~~million~~144A ~~in cash.~~under Wethe ~~raised~~Securities Act of 1933, of $~~120~~160.30 and $95.0 million ~~net~~aggregate principal amount of ~~expenses~~our ~~from~~senior ~~the~~notes, ~~issuance~~respectively. ofThe ~~common~~senior ~~and~~notes ~~preferred~~are ~~stock~~due January 15, 2014 and bear ~~borrowed~~interest ~~$25~~at 9.0 ~~million~~%. ~~under~~The aproceeds ~~loan~~were ~~facility~~used to ~~acquire~~fund ~~two~~the ~~drilling~~acquisitions ~~rigs,~~of ~~offset~~Specialty inRental ~~part by~~Tools, ~~repayments~~Inc. ofand ~~$61.5 million~~DLS, ofto ~~long-term~~repay existing debt and afor ~~net~~general ~~repayment~~corporate onpurposes. ~~our~~In ~~revolving~~June 2009, ~~credit~~we ~~facility~~closed ofon ~~$36.5 million.~~a ~~The~~tender ~~repayments~~offer ofin ~~long-term~~which ~~debt~~we ~~consisted~~purchased of $4630.46 million onaggregate ~~the~~principal of our 9.0% senior notes asfor a ~~result~~total consideration of a$650 ~~tender~~per ~~offer~~$1,000 ~~and~~principal ~~$15~~amount.~~1 million~~ ofIn ~~scheduled~~connection ~~debt~~with ~~repayment~~the ~~including~~Merger ~~prepayment~~and based on ~~our~~ ~~BCH~~actively ~~loan~~traded ~~facility.~~prices Weof ~~also~~our ~~incurred~~senior ~~$644~~notes,~~000~~ inwe ~~debt~~increased ~~issuance~~the ~~costs~~fair ~~consisting~~value of the 9.0% senior notes to $~~513~~1,022 per $1,000 ~~on the~~principal ~~revolving~~amount. ~~credit~~In ~~facility~~May 2011, ~~primarily~~pursuant to ~~modify~~the ~~our~~terms ~~loan~~of ~~covenants,~~change of control provisions in the indentures governing the senior notes and ~~$131,000~~as ona result of the ~~rig~~Merger, ~~financing~~holders ~~agreement.~~had Inthe ~~addition~~right to require us to purchase, weall ~~financed~~or ~~our~~a ~~renewal~~portion of such holders’ notes. We purchased $31.28 million inaggregate ~~insurance~~principal ~~policy~~of our 9.0% senior notes for a total consideration of ~~premiums~~$1,010 inper ~~non-cash~~$1,000 ~~transactions~~principal amount.

AtIn ~~September~~January 302007, ~~2010~~we closed on a private offering, weto ~~had~~qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, of $~~520~~250.70 million inprincipal ~~outstanding~~amount ~~indebtedness~~of 8.5% senior notes due 2017. The proceeds of the senior notes offering, together with a portion of ~~which~~the proceeds of our concurrent common stock offering, were used to repay the debt outstanding under our $~~497~~300.1 0 million bridge loan facility which we incurred to finance our acquisition of substantially all the ~~was~~assets ~~long-term~~of ~~debt~~Oil ~~and~~& Gas Rental Services, Inc. On June 29, 2009, we closed on a tender offer in which we purchased $2344.62 million isaggregate ~~due~~principal ~~within~~of ~~one~~our ~~year~~8.5% senior notes for a total consideration of $600 per $1,000 principal amount. In connection with the

On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, of $160.0 and $95.0 million aggregate principal amount of our senior notes, respectively. The senior notes are due January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of Specialty Rental Tools, Inc. and DLS Drilling, Logistics & Services Company, or DLS, to repay existing debt and for general corporate purposes. On June 29, 2009, we closed on a tender offer in which we purchased 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 January 2007, we closed on a private offering, to qualified institutional buyers pursuant to Rule 144A under the Securities Act, of $250.0 million principal amount of 8.5% senior notes due 2017. The proceeds of the senior notes offering, together with a portion of the proceeds of our concurrent common stock offering, were used to repay the debt outstanding under our $300.0 million bridge loan facility which we incurred to finance our acquisition of substantially all the assets of Oil & Gas Rental Services, Inc. On June 29, 2009, we closed on a tender offer in which we purchased $44.2 million aggregate principal amount of our 8.5% senior notes for a total consideration of $600 per $1,000 principal amount.

We have a $90.0 million revolving line of credit with a final maturity date of April 26, 2012 pursuant to a revolving credit agreement that contains customary events of default and financial covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends or make other distributions, create liens and sell assets. On April 9, 2009, we amended our revolving credit agreement to modify the leverage and interest coverage ratio covenants. Effective December 31, 2009, we again amended the leverage and interest coverage ratio covenants of the revolving credit agreement. This amendment relaxed the required financial ratios for the quarter ended December 31, 2009 and for each of the quarters in 2010. Our obligations under the amended and restated credit agreement are secured by substantially all of our assets located in the U.S. We were in compliance with all debt covenants as of September 30, 2010 and December 31, 2009. As of September 30, 2010, we had outstanding borrowing of $36.5 million and $4.0 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% at September 30, 2010.

AsMerger ~~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 is dated June 2007~~ and ~~contains customary events of default and financial covenants which are~~ based on ~~BCH’s~~actively ~~stand-alone~~traded ~~financial~~prices ~~statements.~~of ~~Obligations under~~our ~~the~~senior ~~facility~~notes, ~~are~~we ~~secured~~increased bythe ~~substantially~~fair ~~all~~value of the ~~BCH assets. BCH was in compliance with~~ ~~all debt covenants as of December 31, 2009~~8.5% ~~The~~senior ~~bank~~notes ~~has~~to ~~waived certain financial ratio covenants for the September 30~~$1,070 ~~2010~~per ~~and December 31~~$1,000 ~~2010~~principal ~~measurement periods~~amount. AsIn ~~we cannot be certain that BCH would attain compliance with the covenants within one year~~May 2011, wepursuant ~~have~~to ~~classified~~ the ~~entire~~terms of ~~outstanding~~change ~~balance~~ of ~~the~~control ~~loan~~provisions in the ~~current~~indentures ~~portion~~governing ofthe ~~long-term~~senior ~~debt.~~notes ~~The~~and ~~facility~~as ~~is repayable~~a inresult ~~quarterly~~of ~~principal installments plus interest with~~ the ~~final payment due not later~~ ~~than~~Merger, ~~August 2012.~~we ~~The~~purchased ~~interest~~$92,000 ~~rates~~aggregate ~~under~~principal ~~this~~of ~~credit~~our ~~facility~~8.5% ~~are~~senior ~~based~~notes onfor ~~LIBOR plus~~ a ~~margin. At~~total ~~September 30, 2010 and December 31, 2009, the outstanding amount~~ consideration of ~~the loan under this credit facility was~~ $~~11.8 million~~1,010 ~~and~~per $~~16.2 million~~1,000 ~~respectively~~principal ~~and the interest rate was 3~~amount.~~5%.~~

OnWe ~~May 22,~~had ~~2009,~~a ~~we drew down~~ $2590.0 million onrevolving aline ~~term~~of ~~loan~~ credit ~~facility~~ with a ~~lending institution.~~final ~~The~~maturity ~~facility~~date ~~was~~of ~~utilized~~April 26, 2012 pursuant to ~~fund~~ a ~~portion~~revolving ofcredit ~~the~~agreement ~~purchase~~that ~~price~~contained customary events of ~~two~~default ~~new~~and ~~drilling~~financial ~~rigs.~~covenants ~~The~~and ~~loan~~limited isour ~~secured~~ability byto ~~the~~incur ~~equipment.~~additional ~~The~~indebtedness, ~~facility~~make iscapital ~~repayable~~expenditures, inpay dividends ~~quarterly~~or ~~installments of~~make ~~approximately~~other $1distributions, create liens and sell assets.4 Effective December ~~million~~31, of2009, we ~~principal~~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 ~~matures~~each of the quarters in ~~May 2015~~2010. ~~The~~Our ~~loan~~obligations ~~bears~~under the amended and restated credit agreement ~~interest~~are atsecured aby ~~fixed~~substantially ~~rate~~all of 9our assets located in the United States.~~0%.~~ AtWe ~~September~~were in compliance with all debt covenants as of December 3031, 2010. ~~and~~As of December 31, ~~2009~~2010, ~~the~~we ~~outstanding amount~~had $36.5 million of borrowings ~~the~~outstanding ~~loan~~and ~~was~~ $204.81 million ~~and~~in ~~$23~~outstanding letters of credit under our revolving credit facility.4 The weighted-average interest rate was 7.8% at December ~~million~~31, ~~respectively~~2010. The revolving line of credit was repaid and terminated in connection with the Merger.

OnAs ~~February 9,~~part ~~2010,~~of ~~through~~ our ~~DLS~~acquisition ~~subsidiary~~of DLS, we ~~entered~~assumed ~~into~~various abank ~~$4.0 million~~loans ~~term~~with ~~loan~~floating ~~facility.~~interest rates based ~~The~~on ~~loan~~LIBOR isplus ~~repayable~~a inmargin ~~semi-annual~~and ~~installments~~terms ~~beginning~~ranging ~~April~~from 2 to 5 ~~14,~~years. ~~2011~~The ~~and~~weighted ~~bears~~average interest atrate on 8these loans was 2.50% ~~per~~as ~~annum~~of December 31, 2010. The ~~final~~outstanding ~~maturity~~amount ~~date~~due isunder ~~April~~these bank loans as of June 1430, ~~2014~~2011 and ~~the~~December 31, ~~loan~~2010 iswas ~~unsecured~~$0 and $350,000, respectively.

InOn ~~2010~~February 15, we2008, ~~obtained~~through ~~insurance~~our ~~premium~~DLS ~~financings~~subsidiary in ~~the~~Argentina, ~~aggregate~~we ~~amount~~entered ofinto a $225.60 million import finance facility with a ~~fixed~~ ~~weighted-average~~bank. ~~interest~~Borrowings ~~rate~~under ofthis ~~4.8%.~~facility ~~Under~~were ~~terms~~used ofto ~~the~~fund ~~agreements,~~a ~~amounts~~portion ~~outstanding~~of ~~are~~the ~~paid~~purchase ~~over~~price anof ~~eight~~the new drilling and ~~11 month~~service ~~repayment~~rigs ~~schedules.~~ordered for our Drilling Services segment. The ~~outstanding~~loan ~~balance~~is ofrepayable ~~these~~over ~~notes~~four years in equal semi-annual installments beginning one year after ~~was~~each ~~approximately~~disbursement ~~$1.5 million~~with atthe ~~September~~final principal payment due not later than March 3015, ~~2010~~2013. InThe ~~2009,~~import finance wefacility ~~obtained~~is ~~insurance~~unsecured ~~premium financings~~and incontains ~~the~~customary ~~aggregate~~events ~~amount~~ of ~~$3.2 million~~default ~~with~~and afinancial ~~fixed~~covenants ~~weighted-average~~and limits ~~interest~~DLS’ ~~rate~~ability ofto incur additional indebtedness, make capital expenditures, create liens and 4sell assets.~~8%.~~ ~~Under~~We ~~terms~~were ofin ~~the~~compliance ~~agreements,~~with ~~amounts~~all ~~outstanding~~debt ~~are~~covenants ~~paid~~as ~~over~~of 10June 30, 2011 and 11December ~~month repayment~~31, ~~schedules~~2010. The ~~outstanding~~bank ~~balance~~loan ofrates ~~these~~are ~~notes~~based on LIBOR plus a margin. The weighted average interest rate was ~~approximately~~4.2% $0at June 30, 2011 and ~~$997~~December 31,~~000~~ at2010. ~~September~~The outstanding amount under the import finance facility as of June 30, ~~2010~~2011 and December 31, ~~2009,~~2010 was $11.5 million and $14.4 million, respectively.

As part of our acquisition of BCH, we assumed ~~various~~a ~~capital~~$23.6 million ~~leases~~term loan credit facility with ~~terms~~a bank. The credit agreement was dated June 2007 and contained customary events of ~~two~~default and financial covenants which were based on BCH’s stand-alone financial statements. The facility was repayable in quarterly principal installments plus interest and was to ~~three~~mature in August 2012. ~~years~~Obligations under the facility were secured by substantially all of the BCH assets. The ~~outstanding~~bank waived ~~balance~~certain ~~under~~financial ~~these~~ratio ~~capital~~covenants ~~leases~~for ~~was~~the ~~$16~~December 31,~~000~~ 2010 measurement period and ~~$254,000~~we classified atthe ~~September~~entire outstanding balance of the loan in the current portion of long-term debt. ~~30,~~The ~~2010~~interest rates were based on LIBOR plus a margin and the interest rate was 3.5% at December 31, 2010. ~~2009~~The outstanding amount of the loan as of December 31, ~~respectively~~2010 was $7.0 million. The term loan credit facility was paid in full in connection with the Merger.

~~Recent~~On ~~Events~~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

In ~~August~~ 2010, we ~~announced~~obtained ~~that~~insurance ~~our~~premium ~~Board~~financings ~~of Directors had approved a definitive merger agreement with Seawell~~ in athe ~~transaction~~aggregate ~~valued~~amount atof ~~approximately~~ $~~890~~2.09 million. ~~The combined company would operate its Drilling and Well Services offerings~~ with a fixed ~~global~~weighted-average ~~footprint~~interest ~~covering~~rate ~~more than 30~~ of ~~the~~ ~~world’s key oil and natural gas regions, including the U~~4.S8%., ~~Gulf~~Under terms of ~~Mexico,~~the ~~Brazil~~agreements, ~~Argentina,~~amounts outstanding ~~North~~are ~~Sea,~~paid ~~Middle~~over ~~East,~~eight ~~Africa~~ and ~~Southeast~~11 month ~~Asia/Pacific~~repayment schedules. The ~~combined~~outstanding ~~Drilling~~balance ~~Services offering would include platform drilling, land contract drilling, modular rigs, maintenance~~ of ~~drilling systems,~~these ~~directional~~notes ~~drilling technology, underbalanced drilling, facility engineering services,~~was ~~rig~~approximately ~~and~~$0 ~~riser inspections~~ and ~~oilfield rentals~~$1.0 million ~~The~~at ~~Well~~June 30, ~~Services~~2011 ~~offering would include electrical~~ and ~~mechanical wireline services~~December 31, ~~production logging services~~2010, ~~coil tubing services, ultrasonic investigation logging services, down-hole cameras and advanced well fishing services~~respectively.

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 dohave ~~not guarantee obligations of any unconsolidated entities. At September 30, 2010 we had a~~ $903.08 million ~~revolving~~of ~~line~~outstanding letters of credit that ~~with~~are asecured ~~maturity~~by ~~of April 2012.~~deposits Atat ~~September 30,~~a ~~2010,~~financial ~~we had $36~~institution.~~5 million~~ ofWe ~~borrowings~~do ~~under~~not ~~the~~guarantee ~~revolving~~obligations ~~credit~~of any ~~facility~~unconsolidated ~~and we had $4~~entities.~~0 million in outstanding letters of credit.~~

Critical Accounting Policies

Please see our Form 10-K/A for a description of other policies that are critical to our business operations and the understanding of our results of operations. The impact and any associated risks related to these policies on our business operations is discussed throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations where such

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

~~Exclusive~~Recently ofIssued ~~any~~Accounting ~~acquisitions, we currently expect our capital spending for the remainder of 2010~~Standards to be approximately $20.0 million depending upon the market demand we experience, our operating performance during the remainder of the year and expenditures that may be associated with potential new contracts. These amounts are net of equipment deposits paid through September 30, 2010. This amount includes budgeted but unidentified expenditures that may be required to enhance or extend the life of existing assets. We believe that our cash generated from operations, cash on hand and cash available under our credit facilities will provide sufficient funds for our identified projects and to service our debt. Our ability to obtain capital for opportunistic acquisitions or additional projects to implement our growth strategy over the longer term will depend upon our future operating performance and financial condition, which will be dependent upon the prevailing conditions in our industry and the global market, including the availability of equity and debt financing, many of which are beyond our control. The pending merger with Seawell, if completed, would provide an additional source of capital.

~~Critical~~For ~~Accounting~~a ~~Policies~~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.”

Please see our Annual Report on Form 10-K for the year ended December 31, 2009 for a description of other policies that are critical to our business operations and the understanding of our results of operations. The impact and any associated risks related to these policies on our business operations is discussed throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations where such policies affect our reported and expected financial results. No material changes to such information have occurred during the nine months ended September 30, 2010.

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~~current inand ~~existing,~~future ~~and~~laws; • the ~~imposition~~impact of ~~new,~~customer ~~laws~~defaults and ~~governmental~~related ~~regulations~~bad debt expense; • the ~~outcome~~potential ofimpairment ~~any~~in ~~pending~~the orcarrying ~~future~~value ~~litigation~~of goodwill and ~~administrative~~other ~~claims~~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.

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are exposed to market risk primarily from changes in interest rates and foreign currency exchange 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) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Management ~~This~~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, asfor ofthe ~~September~~period ending June 30, ~~2010~~2011, our disclosure controls and procedures ~~are~~ were not effective atto provide a reasonable assurance ~~level~~regarding ~~in ensuring that~~ the reliability ~~information~~of ~~required~~financial toreporting beand ~~disclosed by~~the uspreparation inof ~~reports~~financial ~~filed~~statements orfor ~~submitted~~external purposes ~~under~~in ~~the~~accordance ~~Exchange~~with ~~Act~~generally isaccepted ~~recorded,~~accounting ~~processed,~~principles ~~summarized~~because ~~and reported~~of ~~within~~a ~~the~~material ~~time periods specified~~ weakness in ~~the~~our ~~Securities~~internal ~~and~~control ~~Exchange~~over ~~Commission’s,~~financial orreporting ~~SEC’s, rules~~described ~~and forms~~below.

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

~~(b)~~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 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 ~~Change~~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 ~~Internal~~a ~~Control~~material ~~Over~~misstatement ~~Financial~~of ~~Reporting~~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 prevented or detected.

~~There~~Plan ~~have~~for ~~not~~Remediation ~~been~~of ~~any~~Material ~~changes in our internal control over financial reporting (as such term is~~Weakness 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.

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 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 review controls.

(b) Changes in Internal Control Over Financial Reporting.

Except as described above, there were not 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.

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~~August 31, ~~2010~~2011.

Allis-Chalmers Energy Inc. (Registrant) /s/ ~~Munawar~~Christoph H.Bausch ~~Hidayatallah~~Christoph ~~Munawar~~Bausch ~~H. Hidayatallah~~ Chief ~~Executive~~Financial Officer ~~and Chairman~~

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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

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Filing Compare · Allis Chalmers Energy Inc.