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 30, 2010~~March 31, 2011


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

Commission file number: 001-08038

KEY ENERGY SERVICES, INC.

(Exact name of registrant as specified in its charter)


Maryland		04-2648081
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

~~1301 McKinney Street, Suite 1800, Houston, Texas 77010~~
~~(Address of principal executive offices) (Zip~~


1301 McKinney Street, Suite 1800, Houston, Texas		77010
(Address of principal executive offices)		(Zip Code)

(713) 651-4300
(Registrant’s telephone number, including area code)

None
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yesþ Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 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).

Yesþ Noo

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


Large accelerated filerþ	Non-accelerated filero	Accelerated filero	~~Non-accelerated filer~~ Smaller reporting companyo
		(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).

Yeso Noþ

As of ~~October 27, 2010,~~April 29, 2011, the number of outstanding shares of common stock of the registrant was ~~141,427,042.~~142,753,498.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

In addition to statements of historical fact, this report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Statements that are not historical in nature or that relate to future events and conditions are, or may be deemed to be, forward-looking statements. These “forward-looking statements” are based on our current expectations, estimates and projections about Key Energy Services, Inc. and its wholly-owned and controlled subsidiaries, our industry and management’s beliefs and assumptions concerning future events and financial trends affecting our financial condition and results of operations. In some cases, you can identify these statements by terminology such as “may,” “will,” “predicts,” “expects,” “projects,” “potential” or “continue” or the negative of such terms and other comparable terminology. These statements are only predictions and are subject to substantial risks and ~~uncertainties.~~uncertainties and not guarantees of performance. Future actions, events and conditions and future results of operations may differ materially from those expressed in these statements. In evaluating those statements, you should carefully consider the information above as well as the risks outlined in ~~this Quarterly Report on Form 10-Q and~~“Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2009, in our Quarterly Report on Form 10-Q for the periods ended March 31, 2010 and June 30, 2010, in our recent Current Reports on Form 8-K and in our other filings with the Securities and Exchange Commission. Actual performance or results may differ materially and adversely.2010.

We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date of this report except as required by law. All of our written and oral forward-looking statements are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements.

PART I—FINANCIAL INFORMATION

ITEM 1.FINANCIAL STATEMENTS

Key Energy Services, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
(In thousands, except share amounts)


	September 30,			December 31,			March 31,			December 31,
	2010			2009			2011			2010
	(unaudited)						(unaudited)
*ASSETS*
Current assets:
Cash and cash equivalents	$	34,053		$	37,394		$	13,184		$	56,628
Accounts receivable, net of allowance for doubtful accounts of $6,996 and $5,441, respectively		301,592			214,662
Inventory		22,064			23,478
Accounts receivable, net of allowance for doubtful accounts of $7,939 and $7,791, respectively								311,644			261,818
Inventories								29,991			23,516
Other current assets		48,342			104,624			73,778			72,058
Current assets held for sale		9,251			3,974

Total current assets		415,302			384,132			428,597			414,020


Property and equipment		1,650,025			1,647,718			1,924,778			1,832,443
Accumulated depreciation		(863,173	)		(853,449	)		(928,200	)		(895,699	)

Property and equipment, net		786,852			794,269			996,578			936,744


Goodwill		349,779			346,102			460,177			447,609
Other intangible assets, net		33,365			41,048			53,971			58,151
Deferred financing costs, net		8,460			10,421			14,558			7,806
Equity method investments		6,146			5,203			7,012			5,940
Other noncurrent assets		13,807			12,896
Noncurrent assets held for sale		67,264			70,339
Other non-current assets								26,486			22,666

TOTAL ASSETS	$	1,680,975		$	1,664,410		$	1,987,379		$	1,892,936


*LIABILITIES AND EQUITY*
Current liabilities:
Accounts payable	$	54,227		$	46,086		$	69,596		$	56,310
Current portion of capital leases, notes payable and long-term debt		4,397			10,152
Other current liabilities		158,395			133,531			146,750			221,346
Current portion of capital leases								3,438			3,979

Total current liabilities		217,019			189,769			219,784			281,635

Capital leases, notes payable and long-term debt		515,876			523,949
Other noncurrent liabilities		200,654			207,552

Capital leases and long-term debt								580,127			427,121
Other non-current liabilities								216,590			202,377

Commitments and contingencies

Equity:
Common stock, $0.10 par value; 200,000,000 shares authorized, 125,618,228 and 123,993,480 shares issued and outstanding, respectively		12,562			12,399
Common stock, $0.10 par value; 200,000,000 shares authorized, 142,699,781 and 141,656,426 shares issued and outstanding								14,270			14,166
Additional paid-in capital		619,151			608,223			781,377			775,601
Accumulated other comprehensive loss		(51,511	)		(50,763	)		(52,009	)		(51,334	)
Retained earnings		134,114			137,158			192,518			210,653

Total equity attributable to Key		714,316			707,017			936,156			949,086
Noncontrolling interest		33,110			36,123			34,722			32,717

Total equity		747,426			743,140			970,878			981,803


TOTAL LIABILITIES AND EQUITY	$	1,680,975		$	1,664,410		$	1,987,379		$	1,892,936

Key Energy Services, Inc. and Subsidiaries
Condensed Consolidated Statements of Operations
(In thousands, except per share data)
(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,						Three Months Ended March 31,
	2010			2009			2010			2009			2011			2010
*REVENUES*	$	283,739		$	215,349		$	803,483		$	718,059		$	390,984		$	251,959

*COSTS AND EXPENSES:*
Direct operating expenses		198,158			156,444			583,531			497,091			271,800			189,202
Depreciation and amortization expense		32,565			38,680			98,367			114,685			39,923			33,324
General and administrative expenses		46,833			39,350			130,726			129,815			52,779			39,028
Asset retirements and impairments		—			97,035			—			97,035
Loss on early extinguishment of debt														46,451			—
Interest expense, net of amounts capitalized		10,626			9,137			31,614			29,240			10,311			10,259
Other, net		(780	)		1,534			(1,556	)		(688	)		(2,385	)		(1,243	)

Total costs and expenses, net		287,402			342,180			842,682			867,178			418,879			270,570

Loss from continuing operations before tax		(3,663	)		(126,831	)		(39,199	)		(149,119	)		(27,895	)		(18,611	)
Income tax benefit		1,383			47,751			14,979			56,228			9,183			7,709

Loss from continuing operations		(2,280	)		(79,080	)		(24,220	)		(92,891	)		(18,712	)		(10,902	)
Income (loss) from discontinued operations, net of tax (expense) benefit of $(5,515), $25,438, $(11,044) and $27,394, respectively		8,283			(45,937	)		18,360			(49,695	)
Income from discontinued operations, net of tax benefit (expense) of $0 and $(1,217), respectively														—			1,895

Net income (loss)		6,003			(125,017	)		(5,860	)		(142,586	)
Net loss														(18,712	)		(9,007	)

Loss attributable to noncontrolling interest		769			75			2,816			75			(577	)		(1,427	)

*INCOME (LOSS) ATTRIBUTABLE TO KEY*	$	6,772		$	(124,942	)	$	(3,044	)	$	(142,511	)
*LOSS ATTRIBUTABLE TO KEY*													$	(18,135	)	$	(7,580	)


*Basic and diluted (loss) income per share:*
*Basic and diluted (loss) earnings per share attributable to Key:*
Loss per share from continuing operations attributable to Key	$	(0.01	)	$	(0.65	)	$	(0.17	)	$	(0.77	)	$	(0.13	)	$	(0.08	)
Income (loss) per share from discontinued operations		0.06			(0.38	)		0.15			(0.41	)
Earnings per share from discontinued operations attributable to Key													$	—		$	0.02

Income (loss) per share attributable to Key	$	0.05		$	(1.03	)	$	(0.02	)	$	(1.18	)
Loss per share attributable to Key													$	(0.13	)	$	(0.06	)


*Loss from continuing operations attributable to Key:*
Loss from continuing operations	$	(2,280	)	$	(79,080	)	$	(24,220	)	$	(92,891	)	$	(18,712	)	$	(10,902	)
Loss attributable to noncontrolling interest		769			75			2,816			75			(577	)		(1,427	)

Loss from continuing operations attributable to Key	$	(1,511	)	$	(79,005	)	$	(21,404	)	$	(92,816	)	$	(18,135	)	$	(9,475	)


*Weighted average shares outstanding:*
Basic and diluted		125,637			121,277			125,336			120,983			142,206			124,952

Key Energy Services, Inc. and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income
(In thousands)
(Unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
2010 2009 2010 2009
LOSS FROM CONTINUING OPERATIONS
$ (2,280 ) $ (79,080 ) $ (24,220 ) $ (92,891 )

Other comprehensive income (loss), net of tax:
Foreign currency translation gain (loss) 446 (1,026 ) (945 ) (5,516 )
Deferred gain from available for sale investments — — — 30

Total other comprehensive income (loss), net of tax 446 (1,026 ) (945 ) (5,486 )

COMPREHENSIVE LOSS FROM CONTINUING OPERATIONS, NET OF TAX
(1,834 ) (80,106 ) (25,165 ) (98,377 )

Comprehensive income (loss) from discontinued operations 8,283 (45,937 ) 18,360 (49,695 )

COMPREHENSIVE INCOME (LOSS)
6,449 (126,043 ) (6,805 ) (148,072 )

Comprehensive (income) loss attributable to noncontrolling interest (189 ) 206 3,013 206

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO KEY
$ 6,260 $ (125,837 ) $ (3,792 ) $ (147,866 )


	Three Months Ended March 31,
	2011			2010
*LOSS FROM CONTINUING OPERATIONS*	$	(18,712	)	$	(10,902	)

Other comprehensive income, net of tax:
Foreign currency translation gain		1,907			194

Total other comprehensive income, net of tax		1,907			194


*COMPREHENSIVE LOSS FROM CONTINUING OPERATIONS, NET OF TAX*		(16,805	)		(10,708	)

Comprehensive income from discontinued operations		—			1,895

*COMPREHENSIVE LOSS*		(16,805	)		(8,813	)

Comprehensive (income) loss attributable to noncontrolling interest		(2,005	)		1,444


*COMPREHENSIVE LOSS ATTRIBUTABLE TO KEY*	$	(18,810	)	$	(7,369	)

See the accompanying notes which are an integral part of these condensed consolidated financial statements.

Key Energy Services, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows
(In thousands)
(Unaudited)


	Nine Months Ended September 30,						Three Months Ended March 31,
	2010			2009			2011			2010
*CASH FLOWS FROM OPERATING ACTIVITIES:*

Net loss	$	(5,860	)	$	(142,586	)	$	(18,712	)	$	(9,007	)

Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization expense		105,125			132,424			39,923			36,703
Asset retirements and impairments		—			159,802
Bad debt expense		452			3,293			843			(32	)
Accretion of asset retirement obligations		388			405			143			128
(Income) loss from equity method investments		(723	)		796
Income from equity method investments								(838	)		(577	)
Loss on early extinguishment of debt								46,451			—
Amortization of deferred financing costs and discount		1,967			1,568			465			662
Deferred income tax benefit		(5,953	)		(55,359	)
Deferred income tax expense (benefit)								5,972			(4,579	)
Capitalized interest		(3,055	)		(3,556	)		(626	)		(952	)
Loss on disposal of assets, net		492			1,284
Loss on sale of available for sale investments, net		—			30
(Gain) loss on disposal of assets, net								(669	)		335
Share-based compensation		9,001			4,881			3,950			2,679
Excess tax benefits from share-based compensation		(1,966	)		—			(3,968	)		—
Changes in working capital:
Accounts receivable		(86,530	)		195,976			(49,842	)		(38,040	)
Other current assets		51,532			11,798			(7,416	)		55,132
Accounts payable, accrued interest and accrued expenses		26,809			(113,069	)
Accounts payable and accrued liabilities								(52,975	)		21,972
Share-based compensation liability awards		733			517			104			438
Other assets and liabilities		(1,985	)		(623	)		(2,719	)		892

Net cash provided by operating activities		90,427			197,581
Net cash (used in) provided by operating activities								(39,914	)		65,754


*CASH FLOWS FROM INVESTING ACTIVITIES:*

Capital expenditures		(101,065	)		(102,971	)		(107,439	)		(32,415	)
Proceeds from sale of fixed assets		20,502			5,184			5,201			1,006
Acquisitions, net of cash acquired of $0 and $28,362		—			12,007
Dividend from equity method investments		165			199			—			165

Net cash used in investing activities		(80,398	)		(85,581	)		(102,238	)		(31,244	)


*CASH FLOWS FROM FINANCING ACTIVITIES:*

Repayments of long-term debt		(6,970	)		(1,539	)		(460,509	)		(513	)
Proceeds from long-term debt								475,000			—
Repayments of capital lease obligations		(6,891	)		(8,505	)		(1,120	)		(2,077	)
Proceeds from borrowings on revolving credit facility		30,000			—			126,000			30,000
Repayments on revolving credit facility		(30,000	)		(100,000	)		(26,000	)		(30,000	)
Payment of deferred financing costs								(14,640	)		—
Repurchases of common stock		(2,357	)		(248	)		(4,784	)		(2,180	)
Proceeds from exercise of stock options		2,248			1,192			2,747			1,600
Excess tax benefits from share-based compensation		1,966			—			3,968			—

Net cash used in financing activities		(12,004	)		(109,100	)
Net cash provided by (used in) financing activities								100,662			(3,170	)


Effect of changes in exchange rates on cash		(1,366	)		(2,508	)		(1,954	)		(1,920	)


Net (decrease) increase in cash and cash equivalents		(3,341	)		392			(43,444	)		29,420

Cash and cash equivalents, beginning of period		37,394			92,691			56,628			37,394

Cash and cash equivalents, end of period	$	34,053		$	93,083		$	13,184		$	66,814

Key Energy Services, Inc., and Subsidiaries
NOTES TO ~~UNAUDITED~~ CONDENSED CONSOLIDATED UNAUDITED FINANCIAL STATEMENTS

NOTE 1. GENERAL

Key Energy Services, Inc., its wholly-owned subsidiaries and its controlled subsidiaries (collectively, “Key,” the “Company,” “we,” “us,” “its,” and “our”) provide a ~~complete~~full range of well ~~intervention~~ services to major oil companies, foreign national oil companies and independent oil and natural gas production ~~companies to complete, maintain and enhance the flow of oil and natural gas throughout the life of a well. These~~companies. Our services include rig-based and coiled tubing-based well maintenance and workover services, well completion and recompletion services, fluid management ~~services, pressure pumping services, coiled tubing~~ services, fishing and rental services, and ~~wireline~~other ancillary oilfield services. ~~On October 1, 2010, we completed the sale~~In addition, certain of our ~~pressure pumping and wireline businesses to Patterson-UTI Energy (“Patterson-UTI”), which significantly reduced our involvement in these lines~~rigs are capable of ~~business in the United States.~~specialty drilling applications. We operate in most major oil and natural gas producing regions of the continental United States ~~as well as internationally~~and have operations based in ~~Latin America,~~Mexico, Colombia, the Middle East, Russia and ~~the Russian Federation. We also own~~Argentina. In addition, we have a technology development ~~company~~group based in Canada and ~~have~~at March 31, 2011 we had ownership interests in two oilfield service companies based in Canada. We sold our ownership interest in one of the Canadian oilfield service companies in April 2011.

The accompanying unaudited condensed consolidated financial statements were prepared using generally accepted accounting principles in the United States of America (“GAAP”) for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”). The condensed December 31, ~~2009~~2010 balance sheet was prepared from audited financial statements included in our Annual Report on Form 10-K for the year ended December 31, ~~2009.~~2010 (the “2010 Form 10-K”). Certain information relating to our organization and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted in this Quarterly Report on Form 10-Q. These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our ~~Annual Report on~~2010 Form ~~10-K~~10-K.

Certain reclassifications have been made to prior period amounts to conform to current period financial statement classifications. We revised our reportable business segments effective in the first quarter of 2011, and in connection with the revision, have restated the corresponding items of segment information for all periods presented. The new operating segments are U.S. and International. We revised our segments to reflect changes in management’s resource allocation and performance assessment in making decisions regarding the ~~year ended December 31, 2009.~~Company. Our fluid management services, fishing and rental services, intervention services and domestic rig services businesses are aggregated within our U.S. segment. Our international rig services business and our Canadian technology development group are now aggregated within our International segment. These changes reflect our current operating focus in compliance with Accounting Standards Codification (“ASC”) No. 280,Segment Reporting(“ASC 280”).See “Note 15. Segment Information”for a full description of our segment realignment. Also, as a result of the sale of our pressure pumping and wireline businesses in 2010, we now show the results of operations of these businesses as discontinued operations for all periods presented. These presentation changes did not impact our consolidated net income, earnings per share, total current assets, total assets or total stockholders’ equity.

The unaudited condensed consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair presentation of our financial position, results of operations and cash flows for the interim periods presented herein. The results of operations for the three ~~and nine~~ month ~~periods~~period ended ~~September 30, 2010~~March 31, 2011 are not necessarily indicative of the results expected for the full year or any other interim period, due to fluctuations in demand for our services, timing of maintenance and other expenditures, and other factors.

We have evaluated events occurring after the balance sheet date included in this Quarterly Report on Form 10-Q for possible disclosure as a subsequent event. Management monitored for subsequent events through the date these financial statements were available to be issued. ~~After the balance sheet date included in this Quarterly Report on Form 10-Q but before the financial statements~~Subsequent events that were ~~issued, we closed the sale of our pressure pumping and wireline business to Patterson-UTI that required~~identified by management as requiring disclosure ~~as a subsequent event. In addition, we closed the acquisition of certain subsidiaries of OFS Energy Services, LLC (“OFS ES”) and related assets. See~~~~“Note 17. Subsequent Events”~~~~for further discussion.~~

Certain reclassifications have been made to prior period information contained in this report in order to conform to current year presentation. As a result of the sale of our pressure pumping and wireline businesses, we now show the results of operations of these businesses as discontinued operations for all periods presented. The reclassifications had no effect on total assets or the income or loss attributable to Key for any period. See further discussionare described in“Note ~~16. Discontinued Operations”and~~~~“Note 17.~~19. Subsequent ~~Events.”~~Event”.

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES

The preparation of these unaudited condensed consolidated financial statements requires us to develop estimates and to make assumptions that affect our financial position, results of operations and cash flows. These estimates may also impact the nature and extent of our disclosure, if any, of our contingent liabilities. Among other things, we use estimates to (i) analyze assets for possible impairment, (ii) determine depreciable lives for our assets, (iii) assess future tax exposure and realization of deferred tax assets, (iv) determine amounts to accrue for contingencies, (v) value tangible and intangible assets, (vi) assess workers’ compensation, vehicular liability, self-insured risk accruals and other insurance reserves, (vii)

differ materially from these estimates. We believe that the estimates used in the preparation of these interim financial statements are reasonable.

There have been no material changes or developments in our evaluation of accounting estimates and underlying assumptions or methodologies that we believe to be a “Critical Accounting Policy or Estimate” as disclosed in our ~~Annual Report on~~2010 Form ~~10-K for the year ended December 31, 2009.~~10-K.

New Accounting Standards ~~Adopted in this Report~~

~~ASU 2009-16~~~~. In December 2009, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2009-16,~~~~Transfers and Servicing (Topic 860) – Accounting for Transfers of Financial Assets~~~~. ASU 2009-16 revises the provisions of former FASB Statement No. 140,~~~~Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities,~~and requires more disclosure regarding transfers of financial assets. ASU 2009-16 also eliminates the concept of a “qualifying special purpose entity,” changes the requirements for derecognizing financial assets, and increases disclosure requirements about transfers of financial assets and a reporting entity’s continuing involvement in transferred financial assets. We adopted the provisions of ASU 2009-16 on January 1, 2010 and the adoption of this standard did not have a material effect on our financial condition, results of operations, or cash flows.

~~ASU 2009-17.~~~~In December 2009, the FASB issued ASU 2009-17,~~~~Consolidations (Topic 810) – Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities.~~ASU 2009-17 replaces the quantitative-based risk and rewards calculation for determining which reporting entity, if any, has a controlling financial interest in a variable interest entity with an approach focused on identifying which reporting entity has the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance and (1) the obligation to absorb losses of the entity or (2) the right to receive benefits from the entity. ASU 2009-17 also requires additional disclosures about a reporting entity’s involvement in variable interest entities. We adopted ASU 2009-17 on January 1, 2010 and the adoption of this standard did not have a material effect on our financial position, results of operations, or cash flows.

~~ASU 2010-02.~~~~In January 2010, the FASB issued ASU 2010-02,~~~~Consolidation (Topic 810) – Accounting and Reporting for Decreases in Ownership of a Subsidiary – A Scope Clarification.~~ASU 2010-02 clarifies that the scope of previous guidance in the accounting and disclosure requirements related to decreases in ownership of a subsidiary apply to (i) a subsidiary or a group of assets that is a business or nonprofit entity; (ii) a subsidiary that is a business or nonprofit entity that is transferred to an equity method investee or joint venture; and (iii) an exchange of a group of assets that constitutes a business or nonprofit activity for a noncontrolling interest in an entity. ASU 2010-02 also expands the disclosure requirements about deconsolidation of a subsidiary or derecognition of a group of assets to include (i) the valuation techniques used to measure the fair value of any retained investment; (ii) the nature of any continuing involvement with the subsidiary or entity acquiring a group of assets; and (iii) whether the transaction that resulted in the deconsolidation or derecognition was with a related party or whether the former subsidiary or entity acquiring the assets will become a related party after the transaction. We adopted the provisions of ASU 2010-02 on January 1, 2010 and the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

~~ASU 2010-06.~~~~In January 2010 the FASB issued ASU 2010-06,~~~~Fair Value Measurements and Disclosures (Topic 820) – Improving Disclosures About Fair Value Measurements.~~ASU 2010-06 clarifies the requirements for certain disclosures around fair value measurements and also requires registrants to provide certain additional disclosures about those measurements. The new disclosure requirements include (i) the significant amounts of transfers into and out of Level 1 and Level 2 fair value measurements during the period, along with the reason for those transfers, and (ii) separate presentation of information about purchases, sales, issuances and settlements of fair value measurements with significant unobservable inputs. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009. We adopted the provisions of ASU 2010-06 on January 1, 2010 and the adoption of this standard had a disclosure only impact on our financial statements.

~~ASU 2010-09.~~~~In February 2010 the FASB issued ASU 2010-09,~~~~Subsequent Events (Topic 855): Amendments to~~

~~Certain Recognition and Disclosure Requirements.~~This update provides amendments to Subtopic 855-10 as follows: (i) an entity that either (a) is an SEC filer or (b) is a conduit bond obligor for conduit debt securities that are traded in a public market (a domestic or foreign stock exchange or an over-the-counter-market, including local or regional markets) is required to evaluate subsequent events through the date that the financial statements are issued; (ii) the glossary of Topic 855 is amended to include the definition of SEC filer. An SEC filer is an entity that is required to file or furnish its financial statements with either the SEC or, with respect to an entity subject to Section 12(i) of the Securities Exchange Act of 1934, as amended, the appropriate agency under that Section; (iii) an entity that is an SEC filer is not required to disclose the date through which subsequent events have been evaluated; (iv) the glossary of Topic 855 is amended to remove the definition of public entity. The definition of a public entity in Topic 855 was used to determine the date through which subsequent events should be evaluated; and (v) the scope of the reissuance disclosure requirements is refined to include revised financial statements only. The term revised financial statements is added to the glossary of Topic 855. Revised financial statements include financial statements revised either as a result of correction of an error or retrospective application of U.S. generally accepted accounting principles. We adopted the provisions of ASU 2010-09 on March 1, 2010 and the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

~~Accounting Standards Not Yet~~ Adopted in this Report

ASU 2009-13.In October 2009, the FASB issued ASU 2009-13,Revenue Recognition (Topic 605) –— Multiple-Deliverable Revenue Arrangements, a consensus of the FASB Emerging Issues Task Force(“ASU 2009-13”). ASU 2009-13 addresses the accounting for multiple-deliverable arrangements where products or services are accounted for separately rather than as a combined unit, and addresses how to separate deliverables and how to measure and allocate arrangement consideration to one or more units of accounting. Existing GAAP requires an entity to use objective and reliable evidence of fair value for the undelivered items or the residual method to separate deliverables in a multiple-deliverable selling arrangement. As a result of ASU 2009-13, multiple-deliverable arrangements will be separated in more circumstances than under ~~current~~prior guidance. ASU 2009-13 establishes a selling price hierarchy for determining the selling price of a deliverable. The selling price will be based on ~~Vendor-Specific Objective Evidence (“VSOE”)~~VSOE if it is available, on third-party evidence if VSOE is not available, or on an estimated selling price if neither VSOE nor third-party evidence is available. ASU 2009-13 also requires that an entity determine its best estimate of selling price in a manner that is consistent with that used to determine the selling price of the deliverable on a stand-alone basis, and increases the disclosure requirements related to an entity’s multiple-deliverable revenue arrangements. ASU 2009-13 must be prospectively applied to all revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, ~~2010, and early adoption is permitted.~~2010. Entities may elect, but are not required, to adopt the amendments retrospectively for all periods presented. We ~~expect to prospectively adopt~~adopted the provisions of ASU 2009-13 on January 1, 2011 and ~~do not believe that~~ the adoption of this standard ~~will~~did not have a material impact on our financial position, results of operations, or cash flows.

ASU 2009-14.In October 2009, the FASB issued ASU 2009-14,Software (Topic 985) — Certain Revenue Arrangements That Include Software Elements — a consensus of the FASB Emerging Issues Task Force(“ASU 2009-14”). ASU 2009-14 was issued to address concerns relating to the accounting for revenue arrangements that contain tangible products and software that is “more than incidental” to the product as a whole. ASU 2009-14 changes the accounting model for revenue arrangements that include both tangible products and software elements to exclude those where the software components are essential to the tangible products’ core functionality. In addition, ASU 2009-14 also requires that hardware components of a tangible product containing software components always be excluded from the software revenue recognition guidance, and provides guidance on how to determine which software, if any, relating to tangible products is considered essential to the tangible products’ functionality and should be excluded from the scope of software revenue recognition guidance. ASU 2009-14 also provides guidance on how to allocate arrangement consideration to deliverables in an arrangement that contains tangible products and software that is not essential to the product’s functionality. ASU 2009-14 was issued concurrently with ASU 2009-13 and also requires entities to provide the disclosures required by ASU 2009-13 that are included within the scope of ASU 2009-14. ASU 2009-14 is effective prospectively for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010. Entities may also elect, but are not required, to adopt ASU 2009-14 retrospectively to prior periods, and must adopt ASU 2009-14 in the same period and using the same transition methods that it uses to adopt ASU 2009-13. We adopted the provisions of ASU 2009-14 on January 1, 2011 and the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

ASU 2010-13.In April 2010, the FASB issued ASU No. 2010-13,Compensation — Stock Compensation (Topic 718): Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades. This ASU codifies the consensus reached in EITF Issue No. 09-J, “Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades.” The amendments to the Codification clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity shares trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. ASU 2010-13 is effective for fiscal years

beginning on or after December 15, 2010. The amendments in this update should be applied by recording a cumulative-effect adjustment to the opening balance of retained earnings. The cumulative-effect adjustment should be calculated for all awards outstanding as of the beginning of the fiscal year in which the amendments are initially applied, as if the amendments had been applied consistently since the inception of the award. The cumulative-effect adjustment should be presented separately. We adopted the provisions of ASU 2010-13 on January 1, 2011 and the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

ASU 2010-28. In December 2010, the FASB issued ASU No. 2010-28,Intangibles — Goodwill and Other (Topic 350): When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts. This ASU reflects the decision reached in EITF Issue No. 10-A. The amendments in this ASU modify Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist. The qualitative factors are consistent with the existing guidance and examples, which require that goodwill of a reporting unit be tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. For public entities, the amendments in this ASU are effective for fiscal years, and interim periods within those years, beginning after December 15, 2010. We adopted the provisions of ASU 2010-28 on January 1, 2011 and the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

ASU 2010-29. In December 2010, the FASB issued ASU 2010-29,Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations. This ASU reflects the decision reached in EITF Issue No. 10-G. The amendments in this ASU affect any public entity as defined by Topic 805, Business Combinations, that enters into business combinations that are material on an individual or aggregate basis. The amendments in this ASU specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. ASU 2010-29 is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. We adopted the provisions of ASU 2010-29 on January 1, 2011 and the adoption of this standard may result in additional disclosures related to future acquisitions, but it will not have a material impact on our financial position, results of operations, or cash flows.

Accounting Standards Not Yet Adopted in this Report

There were no new accounting standards that had not been adopted in this report.

NOTE 3. ACQUISITIONS

2011 Acquisitions

Equity Energy Company (“EEC”).In January 2011, we acquired 10 saltwater disposal ("SWD") wells from Equity Energy Company for approximately $14.3 million. Most of these SWD wells are located in North Dakota. We accounted for this purchase as an asset acquisition.

2010 Acquisitions

OFS Energy Services, LLC (“OFS”).In October 2010, we acquired certain subsidiaries, together with associated assets, owned by OFS, an oilfield services company owned by ArcLight Capital Partners, LLC. The total consideration for the acquisition was 15.8 million shares of our common stock and a cash payment of $75.8 million subject to certain working capital and other adjustments at closing. We accounted for this acquisition as a business combination. The results of operations for the acquired businesses have been included in our consolidated financial statements since the date of acquisition. Our third-party valuation of certain tangible and intangible assets was not finalized as of December 31, 2010.

The acquisition-date fair value of the consideration transferred totaled $229.7 million which consisted of the following (in thousands):


Cash	$	75,775
Key common stock		153,963

Total	$	229,738

The following table summarizes the changes in the estimated fair values of the assets acquired and liabilities assumed through March 31, 2011. We are still in the process of finalizing third-party valuations of the tangible and certain intangible assets; thus, the provisional measurements of tangible assets, intangible assets, goodwill and deferred income tax assets are preliminary and subject to change.


	March 31, 2011		December 31, 2010
	(in thousands)
At October 1, 2010:
Cash and cash equivalents	$	539	$	539
Accounts receivable		23,386		23,384
Other current assets		1,372		1,372
Property and equipment		101,734		108,152
Intangible assets		17,696		20,988
Deferred tax asset		1,851		1,851


Total identifiable assets acquired		146,578		156,286


Current liabilities		18,881		18,498
Other liabilities		707		1,134


Total liabilities assumed		19,588		19,632



Net identifiable assets acquired		126,990		136,654


Goodwill		102,748		93,084


Net assets acquired	$	229,738	$	229,738

Of the $17.7 million of acquired intangible assets, $16.7 million was preliminarily assigned to customer relationships that will be amortized as the value of the relationships are realized using rates of 30.0%, 21.0%, 14.7%, 10.3%, 7.2%, 5.0% and 3.6% through 2017. The remaining $1.0 million of acquired intangible assets was assigned to non-compete agreements that will be amortized on a straight-line basis over 18 months. As noted above, the fair value of the acquired identifiable intangible assets is preliminary pending receipt of the final valuation for these assets. All of the goodwill acquired has been assigned to our U.S. reportable segment.

Five J.A.B., Inc. and Affiliates, (“5 JAB”).In November 2010, we acquired 13 rigs and associated equipment from 5 JAB for cash consideration of approximately $14.6 million. We initially accounted for this transaction as an asset acquisition. However, after preparing the preliminary valuation, we determined this transaction should be accounted for as a business combination. The following table summarizes the changes in the estimated fair values of the assets acquired through March 31, 2011. We are in the process of finalizing third-party valuations of the property and equipment and intangible assets acquired; thus, the provisional measurements of fixed assets, intangible assets and goodwill are preliminary and subject to change.


	March 31, 2011		December 31, 2010
	(in thousands)
At November 15, 2010:
Property and equipment	$	9,560	$	14,583
Intangible assets		2,512		—


Total identifiable assets acquired		12,072		14,583


Total liabilities assumed		—		—


Net identifiable assets acquired		12,072		14,583


Goodwill		2,511		—


Net assets acquired	$	14,583	$	14,583

Enhanced Oilfield Technologies, LLC (“EOT”).In December 2010, we acquired 100% of the equity interests in EOT, a privately-held oilfield technology company for a cash payment of $11.7 million. We accounted for this acquisition as a business combination. The acquired business was still in the developmental stage at the time of acquisition and continues to be in the developmental stage. Since December 31, 2010, there have been no changes in the estimated fair values of the assets acquired. We are in the process of finalizing third-party valuations of the intangible assets acquired; thus, the provisional measurements of intangible assets and goodwill are preliminary and subject to change.

NOTE 3.4. OTHER BALANCE SHEET INFORMATION

The table below presents comparative detailed information about other current assets at ~~September 30, 2010~~March 31, 2011 and December 31, ~~2009:~~2010:


	September 30,		December 31,			March 31,		December 31,
	2010		2009			2011		2010
	(in thousands)					(in thousands)
Other Current Assets:
Deferred tax assets	$	20,410	$	25,323		$	32,926	$	32,046
Prepaid current assets		10,313		14,212			17,596		20,478
Income tax refund receivable		1,055		50,025			356		847
Reinsurance receivable		8,904		8,136			7,320		6,827
Other		7,660		6,928			15,580		11,860

Total	$	48,342	$	104,624		$	73,778	$	72,058


The table below presents comparative detailed information about other current liabilities at March 31, 2011 and December 31, 2010:					The table below presents comparative detailed information about other current liabilities at March 31, 2011 and December 31, 2010:

						March 31,		December 31,
						2011		2010
						(in thousands)
Other Current Liabilities:
Accrued payroll, taxes and employee benefits						$	49,071	$	35,453
Accrued operating expenditures							41,200		39,399
Income, sales, use and other taxes							9,326		93,820
Self-insurance reserve							30,526		30,195
Accrued interest							2,541		4,097
Insurance premium financing							4,641		7,443
Unsettled legal claims							2,651		3,768
Share-based compensation liabilities							1,745		1,146
Other							5,049		6,025

Total						$	146,750	$	221,346


The table below presents comparative detailed information about other noncurrent assets at March 31, 2011 and December 31, 2010:					The table below presents comparative detailed information about other noncurrent assets at March 31, 2011 and December 31, 2010:

						March 31,		December 31,
						2011		2010
						(in thousands)
Other Noncurrent Assets:
Deposits						$	1,580	$	1,478
Reinsurance receivable							8,152		7,650
Other							16,754		13,538

Total						$	26,486	$	22,666

The table below presents comparative detailed information about other ~~current~~noncurrent liabilities at ~~September 30, 2010~~March 31, 2011 and December 31, ~~2009:~~2010:

September 30, December 31,
2010 2009
(in thousands)
Other Current Liabilities:

Accrued payroll, taxes and employee benefits $ 42,490 $ 33,953
Accrued operating expenditures 38,511 24,194
Income, sales, use and other taxes 21,470 30,447
Self-insurance reserve 32,238 24,366
Accrued interest 12,247 3,014
Insurance premium financing 1,602 7,282
Unsettled legal claims 2,240 2,665
Share-based compensation liabilities 1,581 1,518
Other 6,016 6,092

Total $ 158,395 $ 133,531


			December 31,
	March 31, 2011		2010
	(in thousands)
Other Noncurrent Liabilities:
Deferred tax liabilities	$	156,393	$	144,309
Accrued insurance costs		30,135		30,110
Asset retirement obligations		11,761		11,003
Environmental liabilities		5,745		4,011
Income, sales, use and other taxes		8,889		8,398
Accrued rent		1,889		1,998
Share-based compensation liabilities		506		1,106
Other		1,272		1,442

Total	$	216,590	$	202,377

~~The table below presents comparative detailed information about other noncurrent assets at September 30, 2010 and December 31, 2009:~~

September 30, December 31,
2010 2009
(in thousands)
Other Noncurrent Assets:

Deposits $ 1,117 $ 1,008
Reinsurance receivable 8,896 9,050
Other 3,794 2,838

Total $ 13,807 $ 12,896

~~The table below presents comparative detailed information about other noncurrent liabilities at September 30, 2010 and December 31, 2009:~~

September 30, December 31,
2010 2009
(in thousands)
Other Noncurrent Liabilities:

Deferred tax liabilities $ 138,171 $ 146,980
Accrued insurance costs 33,868 40,855
Asset retirement obligations 10,118 10,045
Environmental liabilities 3,035 3,353
Income, sales, use and other taxes 9,090 2,813
Accrued rent 2,107 2,399
Share-based compensation liabilities 713 508
Other 3,552 599

Total $ 200,654 $ 207,552

NOTE 4.5. GOODWILL AND OTHER INTANGIBLE ASSETS

We revised our reportable business segments effective in the first quarter of 2011, and accordingly, have restated goodwill by segment as of December 31, 2010. The changes in the carrying amount of goodwill for the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 are as follows:


	U.S.		International		Total
			(in thousands)
December 31, 2010	$	418,047	$	29,562	$	447,609
Purchase price and other adjustments, net		10,811		—		10,811
Impact of foreign currency translation		—		1,757		1,757

March 31, 2011	$	428,858	$	31,319	$	460,177

1113

Production
Well Servicing Services Total
(in thousands)
December 31, 2009 $ 342,023 $ 4,079 $ 346,102
Purchase price and other adjustments, net 3,750 — 3,750
Impact of foreign currency translation (151 ) 78 (73 )

September 30, 2010 $ 345,622 $ 4,157 $ 349,779

The components of our other intangible assets as of ~~September 30, 2010~~March 31, 2011 and December 31, ~~2009~~2010 are as follows:


	September 30,			December 31,			March 31,			December 31,
	2010			2009			2011			2010
	(In thousands)						(in thousands)
Noncompete agreements:
Non-compete agreements:
Gross carrying value	$	14,009		$	14,010		$	15,058		$	15,058
Accumulated amortization		(7,559	)		(5,618	)		(9,232	)		(8,224	)

Net carrying value	$	6,450		$	8,392		$	5,826		$	6,834


Patents, trademarks and tradename:
Gross carrying value	$	10,606		$	10,481		$	18,118		$	17,461
Accumulated amortization		(891	)		(917	)		(965	)		(927	)

Net carrying value	$	9,715		$	9,564		$	17,153		$	16,534


Customer relationships and contracts:
Gross carrying value	$	41,371		$	41,389		$	60,756		$	60,057
Accumulated amortization		(25,180	)		(19,947	)		(30,327	)		(26,059	)

Net carrying value	$	16,191		$	21,442		$	30,429		$	33,998


Developed technology:
Gross carrying value	$	2,976		$	3,073		$	3,014		$	3,106
Accumulated amortization		(2,160	)		(1,724	)		(2,536	)		(2,476	)

Net carrying value	$	816		$	1,349		$	478		$	630


Customer backlog:
Gross carrying value	$	722		$	724		$	739		$	762
Accumulated amortization		(529	)		(423	)		(654	)		(607	)

Net carrying value	$	193		$	301		$	85		$	155

IROC Energy Services Corp.

As of ~~September 30, 2010,~~March 31, 2011, we owned 8.7 million shares of IROC Energy Services Corp. (“IROC”), an Alberta-based oilfield services company. The carrying value of our investment in IROC totaled ~~$4.7~~$5.9 million and ~~$4.0~~$5.1 million as of ~~September 30, 2010~~March 31, 2011 and December 31, ~~2009,~~2010, respectively. The carrying value of our investment in IROC is less than our proportionate share of the book value of the net assets of IROC as of ~~September 30, 2010.~~March 31, 2011. This difference is attributable to certain long-lived assets of IROC, and our proportionate share of IROC’s net income or loss for each period is being adjusted over the estimated remaining useful life of those long-lived assets. As of ~~September 30, 2010,~~March 31, 2011, the difference between the carrying value of our investment in IROC and our proportionate share of the book value of IROC’s net assets was ~~$4.6~~$7.9 million.

We recorded ~~$0.1 million and $0.2 million of~~ equity ~~losses~~income related to our investment in IROC of $0.6 million for the three months ended ~~September 30, 2010~~March 31, 2011 and ~~2009, respectively, and $0.8 million and $0.1 million of equity income~~none for the ~~nine~~three months ended ~~September 30, 2010 and 2009, respectively.~~March 31, 2010.

In April 2011, we sold our 8.7 million shares of IROC for $12.0 million, net of fees. See“Note 19. Subsequent Event”for further discussion.

NOTE 6.7. LONG-TERM DEBT

As of ~~September 30, 2010~~March 31, 2011 and December 31, ~~2009,~~2010, the components of our long-term debt were as follows:

September 30, December 31,
2010 2009
(in thousands)
8.375% Senior Notes due 2014 $ 425,000 $ 425,000
Senior Secured Credit Facility revolving loans due 2012 87,813 87,813
Other long-term indebtedness — 1,044
Notes payable -related parties, net of discount of $69 — 5,931
Capital lease obligations 7,460 14,313

520,273 534,101

Less current portion 4,397 10,152

Total capital leases, notes payable and long-term debt $ 515,876 $ 523,949

~~Related Party Note~~

On May 13, 2010, we repaid the remaining $6.0 million principal balance of a promissory note, plus accrued and unpaid interest, that we entered into with related parties in connection with an acquisition in 2007 (the “Related Party Note”). No gain or loss on debt extinguishment was recognized in connection with the repayment.


	March 31,		December
	2011		31, 2010
	(in thousands)
6.75% Senior Notes due 2021	$	475,000	$	—
8.375% Senior Notes due 2014		3,573		425,000
Senior Secured Credit Facility revolving loans due 2016		100,000		—
Capital lease obligations		4,992		6,100

		583,565		431,100
Less current portion		3,438		3,979

Total capital leases and long-term debt	$	580,127	$	427,121

8.375% Senior Notes due 2014

~~We have~~On November 29, 2007, we issued $425.0 million aggregate principal amount of 8.375% Senior Notes due 2014 (the ~~“Senior~~“2014 Notes”). On March 4, 2011, we repurchased $421.3 million of our 2014 Notes at a purchase price of $1,090 per $1,000 principal amount. On March 15, 2011, we repurchased an additional $0.1 million at a purchase price of $1,060 per $1,000 principal amount. In connection with the repurchase of the 2014 Notes, we incurred a loss of $44.3 million on the early extinguishment of debt related to the premium paid on the tender, the payment of related fees and the write-off of unamortized loan fees. Interest on the remaining $3.6 million aggregate principal amount of 2014 Notes outstanding is payable on June 1 and December 1 of each year.

6.75% Senior Notes due 2021

On March 4, 2011, we issued $475.0 million aggregate principal amount of 6.75% Senior Notes due 2021 (the “2021 Notes”). Net proceeds, after deducting underwriters’ fees and offering expenses, were $466.0 million. We used the net proceeds to repurchase the 2014 Notes, including accrued and unpaid interest and fees and expenses. We capitalized $10.0 million of financing costs associated with the issuance of the 2021 Notes that will be amortized over the term of the notes.

The ~~Senior~~2021 Notes are general unsecured senior obligations and are subordinate to all of our existing and future secured indebtedness. The ~~Senior~~2021 Notes are or will be jointly and severally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. Interest on the ~~Senior~~2021 Notes is payable on ~~June~~March 1 and ~~December~~September 1 of each ~~year.~~year, beginning on September 1, 2011. The ~~Senior~~2021 Notes mature on ~~December~~March 1, ~~2014.~~2021.

~~The~~On or after March 1, 2016, the 2021 Notes will be subject to redemption at any time and from time to time at our option, in whole or in part, at the redemption prices below (expressed as percentages of the principal amount redeemed), plus accrued and unpaid interest to the applicable redemption date, if redeemed during the twelve-month period beginning on March 1 of the years indicated below:


Year	Percentage
2016		103.375	%
2017		102.250	%
2018		101.125	%
2019 and thereafter		100.000	%

At any time and from time to time before March 1, 2014, we may on any one or more occasions redeem up to 35% of the aggregate principal amount of the outstanding 2021 Notes at a redemption price of 106.750% of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cash proceeds from any one or more equity offerings; provided that at least 65% of the aggregate principal amount of the 2021 Notes remains outstanding immediately after each

such redemption; and provided, further, that each such redemption shall occur within 180 days of the date of the closing of such equity offering.

In addition, at any time and from time to time prior to March 1, 2016, we may, at our option, redeem all or a portion of the 2021 Notes at a redemption price equal to 100% of the principal amount plus a premium with respect to the 2021 Notes plus accrued and unpaid interest to the redemption date. If we experience a change of control, subject to certain exceptions, we must give holders of the 2021 Notes the opportunity to sell to us their 2021 Notes, in whole or in part, at a purchase price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest to the date of purchase.

We are subject to certain negative covenants under the indenture governing the ~~Senior~~2021 Notes ~~contains various covenants.~~(the “Indenture”). The Indenture limits our ability to, among other things:

	•		incur additional indebtedness and issue preferred equity interests;

	•		pay dividends or make other distributions or repurchase or redeem equity interests;

	•		make loans and investments;

	•		enter into sale and leaseback transactions;

	•		sell, transfer or otherwise convey assets;

	•		create liens;

	•		enter into transactions with affiliates;

	•		enter into agreements restricting subsidiaries’ ability to pay dividends;

	•		designate future subsidiaries as unrestricted subsidiaries; and

	•		consolidate, merge or sell all or substantially all of the applicable entities’ assets.

These covenants are subject to certain exceptions and qualifications, and contain cross-default provisions ~~tied~~relating to the covenants of our ~~Senior Secured~~2011 Credit

Facility ~~(defined below).~~discussed below. Substantially all of the covenants will terminate before the 2021 Notes mature if one of two specified ratings agencies assigns the 2021 Notes an investment grade rating in the future and no events of default exist under the Indenture. As of March 31, 2011, the 2021 Notes were below investment grade. Any covenants that cease to apply to us as a result of achieving an investment grade rating will not be restored, even if the credit rating assigned to the 2021 Notes later falls below an investment grade rating. We were in compliance with these covenants at ~~September 30, 2010.~~March 31, 2011.

Senior Secured Credit Facility

~~We maintain~~On March 31, 2011, we simultaneously terminated (without pre-payment penalty) our $300 million credit agreement dated November 29, 2007, as amended, which was to mature no later than November 29, 2012, and entered into a new credit agreement with several lenders and JPMorgan Chase Bank, N.A., as Administrative Agent and Swing Line Lender, Bank of America, N.A., as Syndication Agent, and Capital One, N.A. and Wells Fargo Bank, N.A., as Co-Documentation Agents. In connection with the termination of our previous credit agreement, we incurred a loss of $2.2 million on early extinguishment of debt related to the write-off of the unamortized portion of deferred financing costs. The new 2011 credit agreement provides for a senior secured credit facility ~~pursuant to a revolving credit agreement with a syndicate of banks of which Bank of America, N.A. and Wells Fargo Bank, N.A. are the administrative agents~~ (the ~~“Senior Secured~~“2011 Credit Facility”)~~. The Senior Secured Credit Facility (which was amended October 27, 2009) consists~~ consisting of a revolving credit facility, letter of credit sub-facility and swing line facility of up to an aggregate principal amount of ~~$300.0~~$400 million, all of which will mature no later than ~~November 29, 2012.~~March 31, 2016. The 2011 Credit Facility and the obligations thereunder are secured by substantially all of our assets and our subsidiary guarantors and are guaranteed by certain of our existing and future domestic subsidiaries.

In connection with the execution of the 2011 Credit Facility, we capitalized $4.7 million of financing costs that will be amortized over the term of the debt.

to ~~350~~300 basis points, and the applicable margin for all other loans ranges from 125 to 200 basis points, depending onupon our consolidated total leverage ~~ratio.~~ratio as defined in the 2011 Credit Facility. Unused commitment fees on the facility ~~range from~~equal 0.50% ~~to 0.75%, depending upon our consolidated leverage ratio.~~.

The ~~Senior Secured~~2011 Credit Facility contains certain financial covenants, which, among other things, ~~require us to maintain certain financial ratios, limit~~limits our annual capital expenditures, ~~restrict~~restricts our ability to repurchase shares and requires us to maintain certain financial ratios. The financial ratios require that:

	•		our consolidated funded indebtedness be no greater than 45% of our adjusted total capitalization;

	•		our senior secured leverage ratio of senior secured funded debt to trailing four quarters of earnings before interest, taxes, depreciation and amortization (as calculated pursuant to the terms of the 2011 Credit Facility, “EBITDA”) be no greater than 2.00 to 1.00;

	•		we maintain a collateral coverage ratio, the ratio of the aggregate book value of the collateral to the amount of the total commitments, as of the last day of any fiscal quarter of at least;


*Fiscal Quarter Ending*		*Ratio*
June 30, 2011 through June 30, 2012		1.85 to 1.00
September 30, 2012 and thereafter		2.00 to 1.00

	•		we maintain a consolidated interest coverage ratio of trailing four quarters EBITDA to interest expense of at least 3.00 to 1.00; and

	•		we limit our capital expenditures and investments in foreign subsidiaries to $250.0 million per fiscal year, up to 50% of which amount may be carried over for expenditure in the following fiscal year, if after giving pro forma effect thereto the consolidated total leverage ratio exceeds 3.00 to 1.00.

In addition, the ~~assets owned by domestic subsidiaries that may be located outside the United States.~~

~~The Senior Secured~~2011 Credit Facility ~~also~~ contains certain ~~other~~affirmative and negative covenants, including, without limitation, restrictions ~~related to~~on (i) liens; (ii) debt, guarantees and other contingent obligations; (iii) mergers and consolidations; (iv) sales, transfers and other dispositions of property or assets; (v) loans, acquisitions, joint ventures and other ~~investments;~~investments (with acquisitions permitted so long as, after giving pro forma effect thereto, no default or event of default exists under the 2011 Credit Facility, the pro forma consolidated total leverage ratio does not exceed 4.00 to 1.00, we are in compliance with other financial covenants and we have at least $25 million of availability under the 2011 Credit Facility); (vi) dividends and other distributions to, and redemptions and repurchases from, ~~equity holders;~~equityholders; (vii) making investments, loans or advances; (viii) selling properties; (ix) prepaying, redeeming or repurchasing ~~the Senior Notes~~subordinated (contractually or ~~other unsecured debt incurred; (viii)~~structurally) debt; (x) engaging in transactions with affiliates; (xi) entering into hedging arrangements; (xii) entering into sale and leaseback transactions; (xiii) granting negative pledges other than to the lenders; ~~(ix)~~(xiv) changes in the nature of ~~our~~ business; ~~(x)~~(xv) amending organizational documents, or amending or otherwise modifying any debt if such amendment or modification would have a material adverse effect, or amending the Senior Notes or other unsecured debt incurred if the effect of such amendment is to shorten the maturity of the Senior Notes or such other unsecured debt;documents; and ~~(xi)~~(xvi) changes in accounting policies or reporting practices; in each of the foregoing cases, with certain exceptions. Furthermore, the 2011 Credit Facility provides that share repurchases in excess of $200 million can be made only if our debt to capitalization ratio is below 45%.

We were in compliance with these covenants ~~on September 30, 2010.~~at March 31, 2011. We may prepay the ~~Senior Secured~~2011 Credit Facility in whole or in part at any time without premium or penalty, subject to ~~our obligation~~certain reimbursements to ~~reimburse~~ the lenders for breakage and redeployment costs. As of ~~September 30, 2010,~~March 31, 2011, we had borrowings of ~~$87.8~~$100.0 million under the revolving credit facility and ~~committed~~$59.4 million of letters of credit ~~of $58.8 million~~ outstanding, leaving ~~$153.4~~$240.6 million of available borrowing capacity under the ~~Senior Secured~~2011 Credit Facility. ~~On October 1, 2010 we borrowed $80.0 million under the credit facility to acquire certain subsidiaries of OFS ES (see “~~~~Note 17. Subsequent Events~~”). We subsequently repaid the entire $167.8 million outstanding balance of the revolving credit facility as of October 4, 2010 with a portion of the proceeds from the Patterson-UTI transaction (see “~~Note 17. Subsequent Events”~~). The weighted average interest rate on the outstanding borrowings under the ~~Senior Secured~~2011 Credit Facility at ~~September 30, 2010~~March 31, 2011 was ~~4.12%~~4.75%.

~~Capital Leases~~

During the third quarter of 2010, we repaid $1.3 million of capital leases that we had incurred to acquire vehicles pursuant to the terms of the Patterson-UTI sale agreement. See further discussion of the Patterson-UTI transaction in “~~Note 16. Discontinued Operations”~~~~and “~~~~Note 17. Subsequent Events”~~.

NOTE 7.8. OTHER INCOME AND EXPENSE

The table below presents comparative detailed information about our other income and expense, shown on the condensed consolidated statements of operations as ~~“other,~~“Other, net” for the periods indicated:

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We ~~recorded $1.4 million~~are subject to U.S. federal income tax as well as income taxes in multiple state and ~~$47.8 million of~~foreign jurisdictions. Our effective tax ~~benefit on pretax losses of $3.7 million and $126.8 million for continuing operations~~rates for the three months ended ~~September 30,~~March 31, 2011 and 2010 were 32.9% and ~~2009,~~41.4%, respectively. Our effective tax rates for our continuing operations for the three months ended September 30, 2010 and 2009 were 37.8% and 37.6%, respectively. We recorded $15.0 million and $56.2 million of tax benefit on pretax losses of $39.2 million and $149.1 million from our continuing operations for the nine months ended September 30, 2010 and 2009, respectively. Our effective tax rates for our continuing operations for the nine months ended September 30, 2010 and 2009 were 38.2% and 37.7%, respectively. The variance quarter over quarter israte varies due to the mix of pre-tax profit between the U.S. and international taxing jurisdictions with varying statutory rates, differences in permanent items impacting mainly the U.S. effective rate, and differences between discrete items, ~~including accrual~~mainly due to ~~return adjustments, increases or decreases to valuation allowances, and~~ tax expense or benefits recognized for uncertain tax positions. The variance between our effective rate and the U.S. statutory rate reflects the impact of permanent items, mainly non-deductible expenses such as fines and penalties, and expenses subject to statutorily imposed limitations such as meals and entertainment expenses, plus the impact of state income taxes.

additional loss materially in excess of amounts that have been recorded. During the ~~third~~first quarter of ~~2010,~~2011, we ~~increased~~recorded a net decrease in our ~~reserves by $0.5~~liability of $1.1 million ~~associated with~~related to the settlement and revision of our ~~assessment of the ultimate liability~~exposures related to ongoing legal matters. ~~We paid $0.3 million during the quarter related to the settlement of legal matters for a net increase to our reserve of $0.2 million during the quarter.~~

~~Litigation with a Former Officer~~

Our former general counsel, Jack D. Loftis, Jr., filed a lawsuit against us in the U.S. District Court, District of New Jersey, on April 21, 2006, in which he alleged a “whistle-blower” claim under the Sarbanes-Oxley Act, breach of contract, breach of duties of good faith and fair dealing, breach of fiduciary duty and wrongful termination. Following the transfer of the case to the District of Pennsylvania, on August 17, 2007, we filed counterclaims against Mr. Loftis alleging attorney malpractice, breach of contract and breach of fiduciary duties. In our counterclaims, we sought repayment of all severance paid to Mr. Loftis (approximately $0.8 million) plus benefits paid during the period July 8, 2004 to September 21, 2004, and damages relating to the allegations of malpractice and breach of fiduciary duties. On September 2, 2010, we reached a settlement with Mr. Loftis regarding the alleged claims, and recorded an additional charge related to the settlement. The resolution of this claim did not have a material effect on our results of operations for the nine months ended September 30, 2010.

~~UMMA Verdict~~

~~On May 3, 2010, a jury returned a verdict in the case of~~~~UMMA Resources, LLC v. Key Energy Services, Inc~~. The lawsuit involved pipe recovery and workover operations performed between September 2003 through December 2004. The plaintiff alleged that we breached an oral contract and negligently performed the work. We countersued for our unpaid invoices for work performed. The jury found that Key was in breach of contract, that Key was negligent in performing the work, and that Key was not entitled to damages under its counterclaims. We believe that, as a matter of law, the jury erred in its decision. The judge in this case delayed rendering his judgment and requested both parties to file motions on the jury’s verdict. Our motion for judgment notwithstanding the verdict has been filed and is pending final ruling by the court. Because the court has not yet rendered judgment in this case, the ultimate outcome of this litigation and our potential liability, if any, cannot be predicted at this time. As of September 30, 2010, we have not taken any provision for this matter. We believe the range of possible damage awards, if the matter is decided adversely to us, could be between zero and $13.0 million, plus attorney’s fees. We currently expect to receive the court’s judgment during the fourth quarter of 2010.

Self-Insurance Reserves

We maintain reserves for workers’ compensation and vehicle liability on our balance sheet based on our judgment and estimates using an actuarial method based on claims incurred. We estimate general liability claims on a case-by-case basis. We maintain insurance policies for workers’ compensation, vehicle liability and general liability claims. These insurance policies carry self-insured retention limits or deductibles on a per occurrence basis. The retention limits or deductibles are accounted for in our accrual process for all workers’ compensation, vehicular liability and general liability claims. As of ~~September 30, 2010~~March 31, 2011 and December 31, ~~2009,~~2010, we have recorded ~~$66.1 million~~$60.7 and ~~$65.2~~$60.3 million, respectively, of self-insurance ~~liabilities~~reserves related to workers’ compensation, vehicular liabilities and general liability claims. Partially offsetting these liabilities, we had ~~$17.8~~

$16.3 million and $15.4 million of insurance receivables as of ~~September 30, 2010~~March 31, 2011 and ~~$17.2 million~~December 31, 2010. These insurance receivables are recorded under other assets and accounts receivable as of March 31, 2011 and December 31, ~~2009.~~2010. We ~~feel~~believe that the liabilities we have recorded are appropriate based on the known facts and circumstances and do not expect further losses materially in excess of the amounts already accrued for existing claims.

Environmental Remediation Liabilities

For environmental reserve matters, including remediation efforts for current locations and those relating to ~~previously-disposed~~previously disposed properties, we record liabilities when our remediation efforts are probable and the costs to conduct such remediation efforts can be reasonably estimated. While our litigation reserves reflect the application of our insurance coverage, our environmental reserves do not reflect management’s assessment of the insurance coverage that may apply to the matters at issue. As of ~~September 30, 2010~~March 31, 2011 and December 31, ~~2009,~~2010, we have recorded ~~$3.0~~$5.7 million and ~~$3.4~~$4.0 million, respectively, for our environmental remediation liabilities. We ~~feel~~believe that the liabilities we have recorded are appropriate based on the known facts and circumstances and do not expect further losses materially in excess of the amounts already accrued.

NOTE ~~10.~~11. EARNINGS PER SHARE

Basic earnings per common share is determined by dividing net earnings attributable to Key by the weighted average number of common shares actually outstanding during the period. Diluted earnings per common share is based on the increased number of shares that would be outstanding assuming conversion of potentially dilutive outstanding securities using the treasury stock and “as if converted” methods.

The components of our earnings per share are as follows:

Three Months Ended Nine Months Ended
September 30, September 30,
2010 2009 2010 2009
(in thousands, except per share amounts)
Basic EPS Calculation:

Numerator

Loss from continuing operations attributable to Key $ (1,511 ) $ (79,005 ) $ (21,404 ) $ (92,816 )
Income (loss) from discontinued operations, net of tax 8,283 (45,937 ) 18,360 (49,695 )

Income (loss) attributable to Key $ 6,772 $ (124,942 ) $ (3,044 ) $ (142,511 )

Denominator

Weighted average shares outstanding 125,637 121,277 125,336 120,983

Basic loss per share from continuing operations attributable to Key $ (0.01 ) $ (0.65 ) $ (0.17 ) $ (0.77 )
Basic income (loss) per share from discontinued operations 0.06 (0.38 ) 0.15 (0.41 )

Basic income (loss) per share attributable to Key $ 0.05 $ (1.03 ) $ (0.02 ) $ (1.18 )

Diluted EPS Calculation:

Numerator

Loss from continuing operations attributable to Key $ (1,511 ) $ (79,005 ) $ (21,404 ) $ (92,816 )
Income (loss) from discontinued operations, net of tax 8,283 (45,937 ) 18,360 (49,695 )

Income (loss) attributable to Key $ 6,772 $ (124,942 ) $ (3,044 ) $ (142,511 )

Denominator

Weighted average shares outstanding 125,637 121,277 125,336 120,983

Diluted loss per share from continuing operations attributable to Key $ (0.01 ) $ (0.65 ) $ (0.17 ) $ (0.77 )
Diluted income (loss) per share from discontinued operations 0.06 (0.38 ) 0.15 (0.41 )

Diluted income (loss) per share attributable to Key $ 0.05 $ (1.03 ) $ (0.02 ) $ (1.18 )


	Three Months Ended March 31,
	2011			2010
	(in thousands, except per share amounts)
Basic and Diluted EPS Calculation:
Numerator
Loss from continuing operations attributable to Key	$	(18,135	)	$	(9,475	)
Income from discontinued operations, net of tax		—			1,895

Loss attributable to Key	$	(18,135	)	$	(7,580	)


Denominator
Weighted average shares outstanding		142,206			124,952

Basic and diluted loss per share from continuing operations attributable to Key	$	(0.13	)	$	(0.08	)
Basic and diluted income per share from discontinued operations		—			0.02

Basic and diluted loss per share attributable to Key	$	(0.13	)	$	(0.06	)

Because of our loss from continuing operations for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2011 and 2010, 2.5 million and ~~2009, all potentially dilutive securities~~3.5 million stock options, respectively, and 0.4 million stock appreciation rights (“SARS”) were excluded from the calculation of our diluted earnings per share, as the potential exercise of those securities would be anti-dilutive. ~~On October 1, 2010 we completed~~There were no events occurring after March 31, 2011 that would materially affect the ~~acquisition~~number of certain subsidiaries and related assets of OFS ES. Upon the closing of this transaction, we issued approximately 15.8 million shares of our common stock (the “Consideration Shares”) as part of the total purchase price. The Consideration Shares will impact our basic and diluted weighted average shares ~~outstanding beginning in the fourth quarter of 2010. See~~~~“Note 17. Subsequent Events”~~~~for further discussion.~~outstanding.

NOTE ~~11.~~12. SHARE-BASED COMPENSATION

We recognized employee share-based compensation expense of ~~$3.2~~$4.0 million and ~~$2.4~~$3.1 million during the three months ended ~~September 30,~~March 31, 2011 and 2010, ~~and 2009,~~ respectively, and the related income tax benefit recognized was ~~$1.2 million and $0.8 million, respectively. We recognized employee share-based compensation expense of $9.7 million and $5.3~~$1.3 million for ~~the nine months ended September 30, 2010 and 2009, respectively, and the related income tax benefit recognized was $3.8 million and $1.9 million, respectively.~~each period. We did not capitalize any share-based compensation during the three ~~or nine~~ month periods ended ~~September 30, 2010~~March 31, 2011 and ~~2009.~~2010.

During February 2011, we issued 1.1 million shares of restricted common stock to certain of our employees and officers, which vest in equal installments over the next three years. These shares had an issuance price of $13.08 per share.

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The unrecognized compensation cost related to our unvested stock options, restricted shares and phantom shares as of ~~September 30, 2010~~March 31, 2011 is estimated to be less than $0.1 million, ~~$13.3~~$22.2 million and ~~$0.5~~$0.4 million, respectively and is expected to be recognized over a weighted-average period of 1.2 years, ~~1.2~~1.4 years and ~~0.7~~0.6 years, respectively.

During March ~~2010, we issued a total of 0.6~~2011, approximately 0.2 million performance units subject to certain of our employees and officers. Performance units provide a cash incentive award, the unit value of which is determined with reference to our common stock. The performance units are measured based on two performance periods. One half of the performance ~~units are measured based on a performance~~ period consisting of the first year after the grant date, and the other half are measured based on a performance period consisting of the second year after the grant date. At the end of each performance period, 100%, 50%, or 0% of an individual’s performance units for that period will vest, based on the relative placement of our total shareholder return within a peer group consisting of Key and five other companies. If we are in the top third of the peer group, 100% of the performance units will vest; if we are in the middle third, 50% will vest; and if we are in the bottom third, the performance units will expire unvested and no payment will be made. If any performance units vest for a given performance period, the award holder will be paid a cash amount equalfrom March 2010 to the vested percentage of the performance units multiplied by the closing price of our common stock on the last trading day of the performance period. We account for the performance units as a liability-type award as they are settled in cash.March 2011 expired unvested. As of ~~September 30, 2010,~~March 31, 2011, the fair value of ~~outstanding~~the remaining performance units ~~issued in March 2010~~ was ~~$2.2~~$2.0 million, and is being accreted to compensation expense over the vesting terms of the awards. ~~During the three and nine months ended September 30, 2010, we recognized $0.2 million and $0.9 million, respectively, of pre-tax compensation expense associated with these awards.~~ As of ~~September 30, 2010,~~March 31, 2011, the unrecognized compensation cost related to our unvested performance units is estimated to be ~~$1.3~~$0.8 million and is expected to be recognized over a weighted-average period of ~~1.1~~0.9 years.

In October 2010, pursuant to the terms of the sale agreement, we accelerated the vesting period of 0.1 million shares of restricted stock held by certain of our employees who became employees of Patterson-UTI as part of this transaction. Compensation expense of $1.2 million was recognized related to this accelerated vesting. See “~~Note 17. Subsequent Events”~~~~for further discussion.~~

NOTE ~~12.~~13. TRANSACTIONS WITH RELATED PARTIES

~~Related Party Notes Payable~~Employee Loans and Advances

~~On May 13,~~From time to time, we have made certain retention loans and relocation loans to employees other than executive officers. The retention loans are forgiven over various time periods, so long as the employees continue their employment with us. The relocation loans are repaid upon the employees selling their prior residence. As of March 31, 2011 and December 31, 2010, ~~we repaid~~these loans, in the ~~outstanding principal balance of $6.0~~aggregate, totaled less than $0.1 million, of the Related Party Note, plus accrued and unpaid interest. This note was repaid concurrently with the sale of six operational barge rigs and related equipment to the holders of the note for total consideration of $17.9 million. We received net proceeds, after repayment of the note, of $11.9 million and recorded a $0.6 million loss on the sale of these assets.respectively.

Transactions with ~~Employees~~Affiliates

In ~~connection~~October 2010, we acquired certain subsidiaries, together with associated assets, from OFS, an ~~acquisition in 2008, the former owner of the acquiree became one of our employees.~~oilfield services company owned by ArcLight Capital Partners, LLC. At the time of the acquisition, ~~the~~OFS conducted business with companies owned by a former owner and employee ~~owned, and continues to own,~~of an ~~exploration and production company.~~OFS subsidiary that we had previously purchased. Subsequent to the acquisition, we continued to provide services to ~~this company.~~these companies. The prices charged to these companies for our services are at rates that are equivalent to the prices charged to our other customers in the U.S. market. As of March 31, 2011 and December 31, 2010, our receivables from these related parties totaled $0.9 million and $1.0 million, respectively. Revenues from these customers for the three month periods ended March 31, 2011 and 2010 totaled $1.5 million and $0.2 million, respectively.

We provide services to an exploration and production company owned by one of our employees who had been the owner of a business we acquired. The prices charged to this company for these services are at rates that are an average of the prices charged to our other customers in the California market where the services are provided. As of ~~September 30,~~March 31, 2011 and December 31, 2010, our receivables ~~with~~from this company totaled ~~$0.4 million.~~$0.3 million and $0.2 million, respectively. Revenues from this company totaled $0.6 million for each of the three month periods ended March 31, 2011 and 2010.

Board of Director ~~Relationship~~Relationships with ~~Customer~~Customers

~~One~~A member of our board of directors is the Senior Vice President, General Counsel and Chief Administrative Officer of Anadarko Petroleum Corporation (“Anadarko”), which is one of our customers. Sales to Anadarko were approximately ~~4% and~~ 2% of our total revenues for ~~the nine months ended September 30, 2010 and 2009, respectively. Sales to Anadarko were approximately 6% and 2%~~each of ~~our total revenues for~~ the three ~~months~~month periods ended ~~September 30, 2010~~March 31, 2011 and ~~2009, respectively.~~2010. Receivables outstanding from Anadarko were approximately ~~6% and 1%~~2% of our total accounts receivable as of ~~September 30, 2010~~March 31, 2011 and December 31, ~~2009,~~2010, respectively. Transactions with Anadarko for our services are made on terms consistent with other customers.

Another member of our board of directors is a member and managing director of the general partner of the indirect, majority owner of Element Petroleum, LP (“Element”), which is one of our customers. Sales to Element were less than 1% of our total revenues for the three months ended March 31, 2011 and 2010. Receivables outstanding from Element were less than 1% of our total accounts receivable as of March 31, 2011 and December 31, 2010. Transactions with Element for our services are made on terms consistent with other customers.

NOTE ~~13.~~14. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

~~As of September 30, 2010, we operate in two~~We revised our reportable business segments ~~Well Servicing~~effective beginning with the first quarter of 2011. The new operating segments are U.S. and ~~Production Services.~~International. We also have a “Functional Support” segment associated with managing each of our reportable operating segments. Financial results as of and for the three months ended March 31, 2010 have been restated to reflect the change in operating segments. We revised our segments to reflect changes in management’s resource allocation and performance assessment in making decisions regarding our business. Our domestic rig services, ~~and~~ fluid management ~~services are aggregated within our Well Servicing segment. Our pressure pumping~~ services, fishing and rental services, and ~~wireline~~intervention services ~~as well as~~are now aggregated within our U.S. reportable segment. Our international rig services business and our Canadian technology development group ~~in Canada,~~ are now aggregated within our ~~Production Services~~International reportable segment. ~~The~~These changes reflect our current operating focus in compliance with ASC 280. We aggregate services that create our reportable segments in accordance with ASC 280, and the accounting policies for our segments are the same as those described in“Note 1. Organization and Summary of Significant Accounting Policies”of the notes to our consolidated financial statements included in Item 8 of our ~~Annual Report~~2010 Form 10-K. We evaluate the performance of our operating segments based on ~~Form 10-K for the year ended December 31, 2009.~~revenue and income measures. All inter-segment sales pricing is based on current market conditions. ~~As mentioned in “~~~~Note 1. General~~,” on October 1, 2010, we completed the sale of our pressure pumping and wireline businesses to Patterson-UTI, which significantly reduced our involvement in these lines of business. We anticipate revising our reportable segments in the fourth quarter of 2010 to realign our current business and management structure. The following is a description of ~~our segments as of September 30, 2010:~~the segments:

The maintenance services ~~provided by~~that our rig fleet provides are generally required throughout the life cycle of an oil or natural gas ~~well to ensure efficient and continuous production.~~well. Examples of the maintenance services ~~provided by~~that we provide as part of our ~~rigs~~rig-based services include routine mechanical repairs to the pumps, tubing and other equipment, ~~in a well,~~ removing debris and formation material from ~~the wellbore,~~wellbores, and pulling the rods and other downhole equipment ~~out of the wellbore~~from wellbores to identify and resolve a production ~~problem.~~problems. Maintenance services generally take less than 48 hours to ~~complete and, in general, the demand for these services is closely related to the total number of producing oil and gas wells in a given market.~~complete.

The workover services ~~provided by our rig fleet~~that we provide are ~~performed~~designed to enhance the production of existing wells and generally are more complex and time consuming than normal maintenance services. Workover services can include deepening or extending wellbores into new formations by drilling horizontal or lateral ~~wellbore sections,~~wellbores, sealing off depleted production zones and accessing previously bypassed production zones, converting former production wells into injection wells for enhanced recovery operations and conducting major subsurface repairs due to equipment failures. Workover services may last from a few days to several weeks, depending on the complexity of the workover.

The completion and recompletion services provided by our rigs prepare a newly drilled well, or a well that was recently extended through a workover, for production. The completion process may involve selectively perforating the well casing to access production zones, stimulating and testing these zones, and installing tubular and downhole equipment. We typically provide a well service rig and may also provide other equipment to assist in the completion process. The completion process ~~typically~~usually takes a few days to several weeks, depending on the nature of the completion.

Our rig fleet is also used in the process of permanently shutting-in an oil or natural gas well that is at the end of its productive life. These plugging and abandonment services generally require auxiliary equipment in addition to a ~~Well Servicing~~well servicing rig. The demand for plugging and abandonment services is not significantly impacted by the demand for oil and natural gas because well operators are required by state regulations to plug wells that are no longer productive.

Fluid Management Services

We provide fluid management services, including oilfield transportation and produced water disposal services, with ~~a very large~~our fleet of ~~heavy-~~heavy and medium-duty trucks. The specific services offered include vacuum truck services, fluid transportation services and disposal services for operators whose wells produce saltwater or other non-hydrocarbon fluids. We also supply frac tanks which are used for temporary storage of fluids associated with fluid hauling operations. In addition, we provide equipment trucks that are used to move large pieces of equipment from one well site to the next, and we operate a fleet of hot oilers which are capable of pumping heated fluids that are used to clear soluble restrictions in a wellbore.

Fluid hauling trucks are utilized in connection with drilling and workover projects, which tend to use large amounts of various fluids. In connection with drilling, maintenance or workover activity at a well site, we transport fresh and brine water to the well site and provide temporary storage and disposal of produced saltwater and drilling or workover fluids. These fluids are removed from the well site and transported for disposal in a saltwater disposal well that is either owned by us or a third party.

~~Production Services Segment~~

~~Pressure Pumping~~Intervention Services

Our ~~pressure pumping~~intervention services include ~~fracturing, nitrogen, acidizing, cementing and~~our coiled tubing ~~services. These~~ services ~~(which may be utilized during the completion or workover of a well) are provided to oil~~business and natural gas producers and are used to enhance the production of oil and natural gas from formations which exhibit restricted flow. In the fracturing process, we typically pump fluid and sized sand, or proppants, into a well at high pressure in order to fracture the formation and thereby increase the flow of oil and natural gas. With our ~~cementing services, we pump cement into a well~~

~~between the casing and the wellbore.~~specialty pumping business. Coiled tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts, and ~~through tubing~~through-tubing fishing and formation stimulations utilizing acid, chemical treatments and ~~sand~~ fracturing. Coiled tubing is also used for a number of horizontal well ~~applications.~~

~~On October 1, 2010, we closed the sale of our U.S. based pressure pumping and wireline businesses to Patterson-UTI. For the periods presented in this report, we show these assets~~applications such as ~~held for sale and the results of operations for pressure pumping operations as discontinued operations for all periods presented. See~~~~“Note 16. Discontinued Operations”~~~~and~~~~“Note 17. Subsequent Events”.~~~~Our coiled tubing operations were not sold as part of this transaction, and are still reported in the Production Services segment.~~milling temporary plugs between frac stages.

Fishing ~~and~~& Rental Services

We offer a full line of services and rental equipment designed for use in providing both onshore and offshore drilling and workover services. Fishing services involve recovering lost or stuck equipment in the wellbore utilizing a broad array of “fishing tools.” Our rental tool inventory consists of drill pipe, tubulars, handling tools (including our patented Hydra-Walk^® pipe-handling units and services), pressure-control equipment, power swivels and foam air units.

~~Wireline Services~~International Segment

Our international operations include Mexico, Colombia, the Middle East, the Russian Federation and Argentina. Services in these locations include rig-based services such as the maintenance, workover, and recompletion of existing oil and natural gas wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful

lives. We ~~have a fleet~~also provide drilling services in the regions where we work and we provide engineering services for the development of ~~wireline units that perform services at various times throughout~~reservoirs.

Our operations in Mexico consist mainly of drilling, workover, project management and consulting services. We generate significant revenue from our contract with the life of the well including perforating, completion logging, production logging and casing integrity services. After the wellbore is cased and cemented, we can provide a number of services. Perforating creates the flow path between the reservoir and the wellbore. Production logging can be performed throughout the life of the well to measure temperature, fluid type, flow rate, pressure and other reservoir characteristics. This service helps the operator analyze and monitor well performance and determine when a well may need a workover or further stimulation.Mexican national oil company Petróleos Mexicanos.

In ~~addition, wireline services may involve wellbore remediation, which could include the positioning~~Argentina and ~~installation~~Colombia, our operations consist of ~~various plugs~~drilling and ~~packers to maintain production or repair well problems, and casing inspection for internal or external abnormalities~~workover services. Our operations in Colombia commenced in the ~~casing string. Wireline services~~third quarter of 2010 and we expect to increase activity during 2011.

In Russia, we provide drilling, workover, and reservoir engineering services. Our Russian operations are ~~provided from surface logging units,~~structured as a joint venture in which ~~lower tools~~we have a controlling financial interest.

In the Middle East, we formed a joint venture in the first quarter of 2010 in which we have a controlling financial interest. We commenced operations in the Middle East in the fourth quarter of 2010. Our operations in the Middle East consist mainly of drilling and ~~sensors into the wellbore. We use advanced wireline instruments to evaluate well integrity~~workover services.

Advanced Measurements, Inc. (“AMI”)

Also included in our International segment is AMI, our technology development company based in Canada. AMI is focused on oilfield service equipment controls, data acquisition and ~~perform cement evaluations and production logging. As discussed above and in~~~~“Note 16. Discontinued Operations”~~ ~~and~~~~“Note 17. Subsequent Events,”~~we closed the sale of our U.S. based pressure pumping and wireline businesses to Patterson-UTI. For the periods presented in this report, we show these assets as held for sale and the results of operations for our wireline operations as discontinued operations for all periods presented.digital information flow.

Functional Support Segment

~~We have aggregated all of~~Our Functional Support segment manages our ~~operating segments that do not meet the aggregation criteria to form a “Functional Support” segment. These services include expenses associated with managing all of our reportable~~U.S. and International operating segments. Functional Support assets consist primarily of cash and cash equivalents, accounts and notes receivable and investments in subsidiaries, deferred financing costs, our equity-method investments and deferred income tax assets.

The following tables set forth our segment information as of and for the three ~~and nine~~ month periods ended ~~September 30, 2010~~March 31, 2011 and ~~2009:~~

~~For the three months ended September 30,~~ 2010:

Production Functional Reconciling
Well Servicing Services Support Eliminations Total
Revenues from external customers $ 244,288 $ 39,451 $ — $ — $ 283,739
Intersegment revenues 82 2,834 — (2,916 ) —
Depreciation and amortization 24,213 5,719 2,633 — 32,565
Operating income (loss) 25,348 9,660 (28,825 ) — 6,183
Interest expense, net of amounts capitalized (21 ) (88 ) 10,735 — 10,626
Income (loss) from continuing operations before tax 25,380 9,593 (38,636 ) — (3,663 )

Total assets 1,350,262 325,242 223,055 (217,584 ) 1,680,975
Capital expenditures, excluding acquisitions 17,520 6,889 8,733 — 33,142

~~For the three months ended September 30, 2009:~~

Production Functional Reconciling
Well Servicing Services Support Eliminations Total
Revenues from external customers $ 194,071 $ 21,278 $ — $ — $ 215,349
Intersegment revenues — 2,014 — (2,014 ) —
Depreciation and amortization 28,757 7,578 2,345 — 38,680
Asset retirements and impairments 65,869 31,166 — — 97,035
Operating (loss) income (57,953 ) (31,732 ) (26,475 ) — (116,160 )
Interest expense, net of amounts capitalized (607 ) (62 ) 9,806 — 9,137
Loss from continuing operations before tax (58,889 ) (31,487 ) (36,455 ) — (126,831 )

Total assets 1,155,860 252,483 648,956 (388,472 ) 1,668,827
Capital expenditures, excluding acquisitions 24,125 7,705 3,732 — 35,562

~~For the nine months ended September 30, 2010:~~

Production Functional Reconciling
Well Servicing Services Support Eliminations Total
Revenues from external customers $ 701,025 $ 102,458 $ — $ — $ 803,483
Intersegment revenues 233 5,825 — (6,058 ) —
Depreciation and amortization 74,599 16,534 7,234 — 98,367
Operating income (loss) 56,882 15,494 (81,517 ) — (9,141 )
Interest expense, net of amounts capitalized (845 ) (154 ) 32,613 — 31,614
Income (loss) from continuing operations before tax 57,947 15,046 (112,192 ) — (39,199 )

Total assets 1,350,262 325,242 223,055 (217,584 ) 1,680,975
Capital expenditures, excluding acquisitions 48,742 29,898 22,425 — 101,065

~~For the nine months ended September 30, 2009:~~

Production Functional Reconciling
Well Servicing Services Support Eliminations Total
Revenues from external customers $ 648,277 $ 69,782 $ — $ — $ 718,059
Intersegment revenues 6 3,910 — (3,916 ) —
Depreciation and amortization 88,009 19,956 6,720 — 114,685
Asset retirements and impairments 65,869 31,166 — — 97,035
Operating loss (1,416 ) (38,888 ) (80,263 ) — (120,567 )
Interest expense, net of amounts capitalized (1,494 ) (390 ) 31,124 — 29,240
Loss from continuing operations before tax (617 ) (37,559 ) (110,943 ) — (149,119 )

Total assets 1,155,860 252,483 648,956 (388,472 ) 1,668,827
Capital expenditures, excluding acquisitions 56,709 36,532 9,730 — 102,971

~~The following table presents information related to our operations on a geographical basis as of and for the three and nine month periods ended September 30, 2010 and 2009:~~

U.S. International Eliminations Total
(in thousands)
As of and for the three months ended September 30, 2010

Revenue from external customers $ 242,142 $ 41,597 $ — $ 283,739
Long-lived assets 1,158,994 106,679 — 1,265,673

As of and for the three months ended September 30, 2009

Revenue from external customers $ 168,601 $ 46,748 $ — $ 215,349
Long-lived assets 1,240,845 131,940 (88,881 ) 1,283,904

As of and for the nine months ended September 30, 2010

Revenue from external customers $ 662,671 $ 140,812 $ — $ 803,483
Long-lived assets 1,158,994 106,679 — 1,265,673

As of and for the nine months ended September 30, 2009

Revenue from external customers $ 579,881 $ 138,178 $ — $ 718,059
Long-lived assets 1,240,845 131,940 (88,881 ) 1,283,904
As of and for the three months ended March 31, 2011:


					Functional			Reconciling
	U.S.		International		Support			Eliminations			Total
Revenues from external customers	$	329,904	$	61,080	$	—		$	—		$	390,984
Intersegment revenues		—		1,863		—			(1,863	)		—
Depreciation and amortization		32,429		4,495		2,999			—			39,923
Other operating expenses		238,828		55,017		30,734			—			324,579
Loss on early extinguishment of debt		—		—		46,451			—			46,451
Operating income (loss)		58,647		1,568		(80,184	)		—			(19,969	)
Operating income (loss), excluding loss on early extinguishment of debt		58,647		1,568		(33,733	)		—			26,482
Interest expense, net of amounts capitalized		41		419		9,851			—			10,311
Income (loss) from continuing operations before tax		59,501		1,986		(89,382	)		—			(27,895	)

Long-lived assets¹		1,433,781		186,899		179,975			(241,873	)		1,558,782
Total assets		1,637,853		344,947		468,601			(464,022	)		1,987,379
Capital expenditures, excluding acquisitions		95,723		8,960		2,756			—			107,439

As of and for the three months ended March 31, 2010:


							Functional			Reconciling
	U.S.			International			Support			Eliminations			Total
Revenues from external customers	$	196,308		$	55,651		$	—		$	—		$	251,959
Intersegment revenues		885			—			—			(885	)		—
Depreciation and amortization		27,297			3,747			2,280			—			33,324
Other operating expenses		155,845			50,564			21,821			—			228,230
Intersegment expenses		(207	)		207			—			—			—
Operating income (loss)		13,373			1,133			(24,101	)		—			(9,595	)
Interest (income) expense, net of amounts capitalized		(467	)		(156	)		10,882			—			10,259
Income (loss) from continuing operations before tax		13,641			2,576			(34,828	)		—			(18,611	)

Long-lived assets¹		1,135,307			148,681			121,414			(128,682	)		1,276,720
Total assets		1,344,089			290,126			633,187			(584,310	)		1,683,092
Capital expenditures, excluding acquisitions		20,864			5,957			5,594			—			32,415


¹		Long lived assets include: fixed assets, goodwill, intangibles and other assets.

NOTE ~~15.~~16. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

During the ~~fourth~~first quarter of ~~2007,~~2011, we issued the ~~Senior~~2021 Notes, which are guaranteed by virtually all of our domestic subsidiaries, all of which are wholly-owned. These guarantees are joint and several, full, complete and unconditional. There are no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company.

As a result of these guaranteed arrangements, we are required to present the following condensed consolidating financial information pursuant to SEC Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered.” The information presented below for the year ended December 31, 2010 reflects our previous guarantee arrangements under the 2014 Notes which were issued in the fourth quarter of 2007 and of which an aggregate principal amount of $3.6 million remains outstanding as of March 31, 2011.

CONDENSED CONSOLIDATING BALANCE SHEETS


													March 31, 2011
	September 30, 2010														Guarantor		Non-Guarantor
			Guarantor		Non-Guarantor								Parent Company		Subsidiaries		Subsidiaries			Eliminations			Consolidated
	Parent Company		Subsidiaries		Subsidiaries			Eliminations			Consolidated						(in thousands)
	(in thousands) (unaudited)																(unaudited)
Assets:
Current assets	$	19,232	$	294,348	$	101,722		$	—		$	415,302	$	19,579	$	330,042	$	78,976		$	—		$	428,597
Property and equipment, net		—		738,598		48,254			—			786,852		—		918,960		77,618			—			996,578
Goodwill		—		320,264		29,515			—			349,779		—		428,858		31,319			—			460,177
Deferred financing costs, net		8,460		—		—			—			8,460		14,558		—		—			—			14,558
Intercompany notes and accounts receivable and investment in subsidiaries		1,879,726		625,135		5,033			(2,509,894	)		—		2,237,618		797,230		(9,607	)		(3,025,241	)		—
Other assets		4,818		36,218		12,282			—			53,318		6,024		55,830		25,615			—			87,469
Noncurrent assets held for sale		—		67,264		—			—			67,264


TOTAL ASSETS	$	1,912,236	$	2,081,827	$	196,806		$	(2,509,894	)	$	1,680,975	$	2,277,779	$	2,530,920	$	203,921		$	(3,025,241	)	$	1,987,379


Liabilities and equity:
Current liabilities		16,356		151,385		49,278			—			217,019	$	50,280	$	108,355	$	61,149		$	—		$	219,784
Long-term debt and capital leases, less current portion		512,813		3,053		10			—			515,876		578,573		1,554		—			—			580,127
Intercompany notes and accounts payable		481,207		1,583,966		103,323			(2,168,496	)		—		590,155		1,849,378		11,990			(2,451,523	)		—
Deferred tax liabilities		153,037		—		(14,866	)		—			138,171		86,223		70,162		8			—			156,393
Other long-term liabilities		1,398		61,085		—			—			62,483		1,671		58,545		(19	)		—			60,197
Equity		747,425		282,338		59,061			(341,398	)		747,426		970,877		442,926		130,793			(573,718	)		970,878


TOTAL LIABILITIES AND EQUITY	$	1,912,236	$	2,081,827	$	196,806		$	(2,509,894	)	$	1,680,975	$	2,277,779	$	2,530,920	$	203,921		$	(3,025,241	)	$	1,987,379

CONDENSED CONSOLIDATING UNAUDITED STATEMENTS OF OPERATIONS


																Three Months Ended March 31, 2011
	Three Months Ended September 30, 2010																		Guarantor			Non-Guarantor
				Guarantor			Non-Guarantor									Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated									(in thousands)
	(in thousands) (unaudited)																					(unaudited)
Revenues	$	—		$	253,076		$	43,635		$	(12,972	)	$	283,739		$	—		$	360,661		$	41,253		$	(10,930	)	$	390,984

Costs and expenses:
Direct operating expense		—			162,640			45,546			(10,028	)		198,158			—			245,755			33,852			(7,807	)		271,800
Depreciation and amortization expense		—			30,315			2,250			—			32,565			—			37,372			2,551			—			39,923
General and administrative expense		337			41,178			6,677			(1,359	)		46,833			313			46,290			7,182			(1,006	)		52,779
Interest expense, net of amounts capitalized		11,361			(949	)		214			—			10,626			10,499			(607	)		419			—			10,311
Loss on early extinguishment of debt																	46,451			—			—			—			46,451
Other, net		18			(1,348	)		2,135			(1,585	)		(780	)		(749	)		(1,083	)		1,519			(2,072	)		(2,385	)

Total costs and expenses, net		11,716			231,836			56,822			(12,972	)		287,402			56,514			327,727			45,523			(10,885	)		418,879

(Loss) income from continuing operations before taxes		(11,716	)		21,240			(13,187	)		—			(3,663	)		(56,514	)		32,934			(4,270	)		(45	)		(27,895	)
Income tax (expense) benefit		(12,031	)		5,759			7,655			—			1,383
Income tax benefit																	8,022			1,008			153			—			9,183

(Loss) income from continuing operations		(23,747	)		26,999			(5,532	)		—			(2,280	)		(48,492	)		33,942			(4,117	)		(45	)		(18,712	)
Discontinued operations		—			8,283			—			—			8,283			—			—			—			—			—

Net (loss) income		(23,747	)		35,282			(5,532	)		—			6,003			(48,492	)		33,942			(4,117	)		(45	)		(18,712	)
Loss attributable to noncontrolling interest		—			—			769			—			769			—			—			(577	)		—			(577	)

(LOSS) INCOME ATTRIBUTABLE TO KEY	$	(23,747	)	$	35,282		$	(4,763	)	$	—		$	6,772		$	(48,492	)	$	33,942		$	(3,540	)	$	(45	)	$	(18,135	)

Nine Months Ended September 30, 2010
Guarantor Non-Guarantor
Parent Company Subsidiaries Subsidiaries Eliminations Consolidated
(in thousands)
(unaudited)
Revenues
$ — $ 702,221 $ 144,187 $ (42,925 ) $ 803,483

Costs and expenses:

Direct operating expense — 459,021 156,333 (31,823 ) 583,531
Depreciation and amortization expense — 91,410 6,957 — 98,367
General and administrative expense 1,630 114,383 17,981 (3,268 ) 130,726
Interest expense, net of amounts capitalized 34,034 (2,659 ) 239 — 31,614
Other, net (997 ) (730 ) 8,005 (7,834 ) (1,556 )

Total costs and expenses, net
34,667 661,425 189,515 (42,925 ) 842,682

(Loss) income from continuing operations before taxes (34,667 ) 40,796 (45,328 ) — (39,199 )
Income tax (expense) benefit (5,068 ) 11,287 8,760 — 14,979

(Loss) income from continuing operations (39,735 ) 52,083 (36,568 ) — (24,220 )
Discontinued operations — 18,360 — — 18,360

Net (loss) income (39,735 ) 70,443 (36,568 ) — (5,860 )
Net loss attributable to noncontrolling interest — — 2,816 — 2,816

(LOSS) INCOME ATTRIBUTABLE TO KEY
$ (39,735 ) $ 70,443 $ (33,752 ) $ — $ (3,044 )

Nine Months Ended September 30, 2009
Guarantor Non-Guarantor
Parent Company Subsidiaries Subsidiaries Eliminations Consolidated
(in thousands)
(unaudited)
Revenues
$ — $ 609,167 $ 141,520 $ (32,628 ) $ 718,059

Costs and expenses:

Direct operating expense — 409,243 112,532 (24,684 ) 497,091
Depreciation and amortization expense — 110,091 4,594 — 114,685
General and administrative expense 58 116,593 13,136 28 129,815
Asset retirements and impairments — 97,035 — — 97,035
Interest expense, net of amounts capitalized 31,828 (2,738 ) 150 — 29,240
Other, net 551 224 7,504 (8,967 ) (688 )

Total costs and expenses, net
32,437 730,448 137,916 (33,623 ) 867,178

(Loss) income from continuing operations before taxes (32,437 ) (121,281 ) 3,604 995 (149,119 )
Income tax benefit (expense) 83,815 (27,394 ) (193 ) — 56,228

Income (loss) from continuing operations 51,378 (148,675 ) 3,411 995 (92,891 )
Discontinued operations — (49,695 ) — — (49,695 )

Net income (loss) 51,378 (198,370 ) 3,411 995 (142,586 )
Net loss attributable to noncontrolling interest — — 75 — 75

INCOME (LOSS) ATTRIBUTABLE TO KEY
$ 51,378 $ (198,370 ) $ 3,486 $ 995 $ (142,511 )

CONDENSED CONSOLIDATING UNAUDITED STATEMENTS OF CASH FLOWS


	Nine Months Ended September 30, 2010															Three Months Ended March 31, 2011
				Guarantor			Non-Guarantor									Parent			Guarantor			Non-Guarantor
	Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated			Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)																					(in thousands)
	(unaudited)																					(unaudited)
Net cash provided by (used in) operating activities	$	—		$	98,362		$	(7,935	)	$	—		$	90,427

Net cash (used in) provided by operating activities																$	—		$	(38,599	)	$	(1,315	)	$	—		$	(39,914	)
Cash flows from investing activities:
Capital expenditures		—			(100,620	)		(445	)		—			(101,065	)		—			(101,261	)		(6,178	)		—			(107,439	)
Intercompany notes and accounts		(165	)		(5,034	)		—			5,199			—			—			116,422			—			(116,422	)		—
Other investing activities, net		165			20,502			—						20,667			—			5,201			—			—			5,201


Net cash (used in) provided by investing activities		—			(85,152	)		(445	)		5,199			(80,398	)

Net cash used in investing activities																	—			20,362			(6,178	)		(116,422	)		(102,238	)

Cash flows from financing activities:
Repayments of long-term debt		—			(6,970	)		—			—			(6,970	)		(460,509	)		—			—			—			(460,509	)
Proceeds from long-term debt																	475,000			—			—			—			475,000
Repayment of capital lease obligations																	—			(1,120	)		—			—			(1,120	)
Proceeds from borrowings on revolving credit facility																	126,000			—			—			—			126,000
Repayments on revolving credit facility																	(26,000	)		—			—			—			(26,000	)
Payment of deferred financing costs																	—			(14,640	)		—			—			(14,640	)
Repurchases of common stock		(2,357	)		—			—			—			(2,357	)		(4,784	)		—			—			—			(4,784	)
Intercompany notes and accounts		5,034			165			—			(5,199	)		—			(116,422	)		—			—			116,422			—
Other financing activities, net		(2,677	)		—			—			—			(2,677	)		6,715			—			—			—			6,715
																					��

Net cash used in financing activities		—			(6,805	)		—			(5,199	)		(12,004	)
Net cash provided by (used in) financing activities																	—			(15,760	)		—			116,422			100,662


Effect of changes in exchange rates on cash		—			—			(1,366	)		—			(1,366	)		—			—			(1,954	)		—			(1,954	)

Net increase (decrease) in cash		—			6,405			(9,746	)		—			(3,341	)

Net decrease in cash and cash equivalents																	—			(33,997	)		(9,447	)		—			(43,444	)

Cash and cash equivalents at beginning of period		—			19,391			18,003			—			37,394			—			42,973			13,655			—			56,628


Cash and cash equivalents at end of period	$	—		$	25,796		$	8,257		$	—		$	34,053		$	—		$	8,976		$	4,208		$	—		$	13,184


	Nine Months Ended September 30, 2009															Three Months Ended March 31, 2010
				Guarantor			Non-Guarantor									Parent			Guarantor			Non-Guarantor
	Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated			Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)																					(in thousands)
	(unaudited)																					(unaudited)
Net cash provided by (used in) operating activities	$	—		$	189,119		$	8,462		$	—		$	197,581

Net cash provided by operating activities																$	—		$	57,629		$	8,125		$	—		$	65,754
Cash flows from investing activities:
Capital expenditures		—			(100,255	)		(2,716	)		—			(102,971	)		—			(27,493	)		(4,922	)		—			(32,415	)
Intercompany notes and accounts		82,389			(1,168	)		(6,067	)		(75,154	)		—			(165	)		(580	)		—			745			—
Other investing activities, net		199			5,184			12,007			—			17,390			165			1,006			—			—			1,171


Net cash provided by (used in) investing activities		82,588			(96,239	)		3,224			(75,154	)		(85,581	)

Net cash (used in) provided by investing activities																	—			(27,067	)		(4,922	)		745			(31,244	)

Cash flows from financing activities:
Repayment of long-term debt		(100,000	)		—			—			—			(100,000	)
Repayments on long-term debt																	—			(2,590	)		—			—			(2,590	)
Repurchases of common stock																	(2,180	)		—			—			—			(2,180	)
Intercompany notes and accounts		16,468			(92,677	)		1,055			75,154			—			580			165			—			(745	)		—
Other financing activities, net		944			(10,044	)		—			—			(9,100	)		1,600			—			—			—			1,600


Net cash (used in) provided by financing activities		(82,588	)		(102,721	)		1,055			75,154			(109,100	)
Net cash used in financing activities																	—			(2,425	)		—			(745	)		(3,170	)


Effect of changes in exchange rates on cash		—			—			(2,508	)		—			(2,508	)		—			—			(1,920	)		—			(1,920	)

Net (decrease) increase in cash		—			(9,841	)		10,233			—			392

Net increase in cash and cash equivalents																	—			28,137			1,283			—			29,420

Cash and cash equivalents at beginning of period		—			75,847			16,844			—			92,691			—			19,391			18,003			—			37,394


Cash and cash equivalents at end of period	$	—		$	66,006		$	27,077		$	—		$	93,083		$	—		$	47,528		$	19,286		$	—		$	66,814

Three Months Ended Nine Months Ended
September 30, September 30,
2010 2009 2010 2009
(in thousands)
Revenues $ 76,348 $ 22,322 $ 197,704 $ 93,059

Costs and expenses:
Direct operating expenses 59,111 23,457 154,369 83,890
Depreciation and amortization — 5,797 6,758 17,739
General and administrative expenses 3,589 1,721 7,510 5,357
Asset retirements and impairments — 62,767 — 62,767
Other, net (150 ) (45 ) (337 ) 395

Total costs and expenses, net 62,550 93,697 168,300 170,148

Income (loss) before tax 13,798 (71,375 ) 29,404 (77,089 )
Income tax (expense) benefit (5,515 ) 25,438 (11,044 ) 27,394

Income (loss) from discontinued operations $ 8,283 $ (45,937 ) $ 18,360 $ (49,695 )

NOTE 18. VARIABLE INTEREST ENTITIES

~~In connection~~On March 7, 2010, we entered into an agreement with ~~our closing~~AlMansoori Petroleum Services LLC to form the joint venture AlMansoori Key Energy Services LLC. We hold three of the ~~Patterson-UTI transaction, we recorded pre-tax charges~~five board of ~~$0.5 million~~directors seats and a controlling financial interest in the ~~third quarter~~joint venture; accordingly, we consolidate the entity in our financial statements.

For the periods ended March 31, 2011 and 2010, respectively, we recognized $1.7 million and zero of revenue and $0.3 million and zero of net income associated with this joint venture. Also, during 2010 ~~related to transaction costs. We also anticipate recording a pre-tax gain on~~we guaranteed the ~~sale~~timely performance of ~~these~~the joint venture under its sole contract valued at $2 million. At March 31, 2011, there was approximately $3.6 million of assets in the ~~fourth quarter of 2010.~~joint venture.

NOTE ~~17.~~19. SUBSEQUENT ~~EVENTS~~

~~Sale of Pressure Pumping and Wireline Businesses~~EVENT

~~On October 1, 2010,~~In April 2011, we ~~closed the sale of~~sold our pressure pumping and wireline businesses to Patterson-UTI for cash consideration of $237.7 million and our retention of working capital associated with the businesses (subject to certain adjustments based on closing inventory).

~~Acquisition~~

On October 1, 2010, we completed the purchase of 100% of the ownership interests in three of OFS ES’s subsidiaries, Davis Energy Services, LLC, QCP Energy Services, LLC and Swan Energy Services, LLC (and indirectly their related subsidiaries). In addition, we acquired certain incidental assets from OFS ES and its parent company, OFS Holdings, LLC, that are used in the purchased businesses, and we agreed to assume certain specified liabilities. We will account for this acquisition as a business combination. The results of operations for the acquired businesses will be included in our consolidated financial statements from the date of acquisition.

The OFS ES subsidiaries are privately held oilfield services companies that provide well workover and stimulation services as well as nitrogen pumping, coiled tubing, fluid handling and wellsite construction and preparation services. In addition to complementing our existing rig and fluids management businesses, closing this transaction will result in Key having a total of 41 coiled tubing units, two-thirds of which are large diameter units. This will represent a total fleet increase of 78%.

~~The total consideration for the acquisition was approximately 15.8~~8.7 million shares of ~~our common stock and~~IROC at a ~~cash payment~~price of ~~$75.8~~$1.40 CAD per share. Our net proceeds were $12.0 million. We will record a gain on sale of $6.0 million ~~subject to certain working capital and other adjustments. We are required to register~~during the ~~shares~~second quarter of ~~common stock issued in~~2011, as the ~~transaction under~~proceeds received exceeded the ~~Securities Act of 1933, as amended, subject to certain conditions.~~

~~The acquisition-date fair~~carrying value of ~~the consideration transferred totaled $229.7 million, which consisted of the following (in thousands):~~our investment.

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

OVERVIEW

Key Energy Services, Inc., its wholly-owned subsidiaries and its controlled subsidiaries (collectively, “Key,” the “Company,” “we,” “us,” “its,” and “our”) provide a ~~complete~~full range of well ~~intervention~~ services to major oil companies, foreign national oil companies and independent oil and natural gas production ~~companies to complete, maintain and enhance the flow of oil and natural gas throughout the life of a well. These~~companies. Our services include rig-based and coiled tubing-based well maintenance and workover services, well completion and recompletion services, fluid management ~~services, pressure pumping services, coiled tubing~~ services, fishing and rental services, and ~~wireline~~other ancillary oilfield services. ~~On October 1, 2010, we completed the sale~~Additionally, certain of our ~~pressure pumping and wireline businesses to Patterson-UTI Energy (“Patterson-UTI”) which significantly reduced our involvement in these lines~~rigs are capable of ~~business, specifically in the U.S.~~specialty drilling applications. We operate in most major oil and natural gas producing regions of the continental United States ~~as well as internationally~~and have operations based in ~~Latin America~~Mexico, Colombia, the Middle East, Russia and ~~the Russian Federation. We also own~~Argentina. In addition, we have a technology development ~~company~~group based in Canada and ~~have~~at March 31, 2011 we had ownership interests in two oilfield service companies based in Canada. We sold our ownership interest in one of the Canadian oilfield service companies in April 2011.

The following discussion and analysis should be read in conjunction with the accompanying unaudited condensed consolidated financial statements and related notes as of and for the three months ended March 31, 2011 and 2010, included elsewhere herein, and the audited consolidated financial statements and notes thereto included in our ~~Annual Report on~~2010 Form ~~10-K for the year ended December 31, 2009 (“2009 Annual Report”).~~10-K.

~~Through September 30, 2010, we operated~~We operate in two business ~~segments, Well Servicing~~segments; U.S. and ~~Production Services.~~International. We also have a “Functional Support” segment associated with managing ~~all of~~ our ~~reportable~~U.S. and International operating segments. See“Note ~~14.~~15. Segment Information”in“Item 1. Financial Statements”of Part I of this report for a summary of our business segments.

PERFORMANCE MEASURES

We believe that the Baker Hughes U.S. land drilling rig count is the best barometer of overall oilfield capital spending and activity levels in our primary U.S. onshore market, since this data is made publicly available on a weekly basis. Historically, our activity levels have been highly correlated to capital spending by oil and natural gas producers. When oil and natural gas prices are strong, capital spending by our customers tends to increase. Similarly, as oil and natural gas prices fall, the Baker Hughes U.S. land drilling rig count tends to decline.


			NYMEX Henry		Average Baker				NYMEX Henry		Average Baker
	WTI Cushing Oil		Hub Natural Gas		Hughes U.S. Land		WTI Cushing Oil		Hub Natural Gas		Hughes U.S. Land
							(1)		(1)		Drilling Rigs (2)
2011:
First Quarter							$	94.07	$	4.20		1,695
	(1)		(1)		Drilling Rigs (2)
2010:
First Quarter	$	74.78	$	5.14		1,354	$	74.78	$	5.14		1,354
Second Quarter	$	74.79	$	4.30		1,513	$	74.79	$	4.30		1,513
Third Quarter	$	72.46	$	4.30		1,626	$	72.46	$	4.30		1,626

2009:
First Quarter	$	40.16	$	4.60		1,344
Second Quarter	$	55.84	$	3.71		934
Third Quarter	$	66.02	$	3.17		970
Fourth Quarter	$	71.67	$	4.38		1,108	$	85.16	$	3.98		1,688

MARKET CONDITIONS AND OUTLOOK

Market Conditions — Quarter Ended ~~September 30, 2010~~March 31, 2011

~~Overall,~~Market conditions during the first quarter of 2011 continued to improve, especially in the oil markets we serve. Many of our major customers increased oil-directed activity during the quarter. As a result of higher oil prices and improving overall market conditions during the ~~third~~quarter ended March 31, 2011 compared with fiscal year 2010, overall demand for our services continues to increase. Our activity in the first quarter of 2011 exceeded quarterly activity levels in both 2010 ~~continued their recovery from the lows experienced~~and 2009.

Demand for our services in the ~~second and third~~U.S. was strong in all our oil-driven markets. We saw improvement in pricing compared to previous quarters due largely to price increases implemented in the first quarter of ~~2009. Within~~2011. However, our U.S. ~~well servicing~~rig business experienced higher labor, fuel and other costs, which limited additional margin expansion. Dynamics in our fluid management services business were consistent with those in the rig ~~hours~~business. We implemented price increases for these services but also experienced increases in costs. Our fishing and rental and intervention services businesses experienced increased ~~for the fifth consecutive quarter~~revenue and our trucking hours increased for the fourth consecutive quarter. Although oil and natural gas prices have remained relatively flat over the last several quarters, we continued to see moderate pricing improvements for our rig-based servicesprofitability during the quarter ~~primarily~~due to the deployment of additional equipment, increased utilization and better pricing. Results for our ~~larger equipment~~intervention services improved in ~~selected oil and shale markets.~~the first quarter of 2011 as the assets we acquired in 2010 were more effectively utilized. We continue to redeploy assets across all our domestic lines of business to more profitable regions to offset our rising costs.

Our ~~fluid management business continued~~international segment returned to ~~expand during~~profitability in the first quarter ~~with much~~of 2011. Our assets in Mexico were fully utilized by the end of the ~~increase located in the Bakken Shale.~~

In our Production Services segment, our fishing and rental services business also improved during the quarter, with higher activity levels and revenues coming from equipment rentals. Our coiled tubing business, in which we have been investing heavily over the last twelve months, continued to expand during the quarter. Strong customer demand for new horizontal well completion has driven the activity increases. Our pressure pumping and wireline businesses, both of which were sold to Patterson-UTI on October 1, 2010, and which are presented as discontinued operations, contributed additional operating income during the third quarter as compared to the second quarter.

~~Internationally, we continued our expansion strategy during the third quarter of 2010. We began operations in Colombia during the quarter under our~~ first project award in this country. Additionally, we received an award for a 3-year, 2-rig commitment in Bahrain through our Middle East joint venture, although operations have not yet commenced. In Russia, activity levels increased during the quarter as our customers there resumed work, and several rigs that we sold to our joint venture earlier in 2010 became available for work during the quarter. In Argentina, activity levels improved moderately during the quarter, and we ~~were able to secure~~achieved some activity and price ~~increases~~improvement in ~~that country.~~Argentina. In ~~Mexico, third~~Colombia, we had a full quarter activity continued to be negatively impacted by Petroleos Mexicanos’ (“Pemex”) budget cuts for 2010. A work stoppage in Mexico’s North Region during September negatively impacted utilization and profitability.of operations with profitable results.

Market Outlook

We ~~expect trends~~believe that we will continue to see steady growth in our U.S. and international markets during the remainder of 2011 due to increased ~~customer spending~~activity and pricing relative to 2010. Driven by higher commodity prices, we anticipate that our core businesses will continue to show improvement, as our customers increase capital expenditures to increase production.

In the U.S., with the largest fleet of onshore well servicing rigs, we believe we are well positioned to benefit from increasing demand for conventional well maintenance and repair. Given our recent and ongoing investments in larger, higher capability rigs and coiled tubing units, as well as fluid transportation, frac tanks, and fishing and rental equipment, we believe we are well positioned to benefit from increased horizontal well drilling activity, which is driving a higher level of revenue and margin intensity per well.

We also believe that our international operations will play an increasing role in the ~~U.S.~~growth of our business. We intend to deploy additional assets internationally during 2011. We expect our activity in the Middle East and Russia to grow in 2011, combined with our full utilization of assets in Mexico and continued improvements in Argentina and Colombia, and should result in positive contributions to our revenues and earnings for the remainder of 2011.

We also continue through the end of 2010, offset by typical seasonality, such as reduced daylight, more holidays and weather. The fourth quarter of 2010 will also be a transition period as we integrate new businesses recently acquired and continueto explore opportunities for expanding our ~~expansion~~service footprint into new international markets. We believe that the recent strategic moves we have made domestically better position us to capture increased activity related to more complex horizontal drilling and completion techniques.markets or new lines of business as those opportunities present themselves.

3432

As we enter new markets in Latin America and the Middle East, and with the commencement of operations for our new equipment in Russia, we believe our outlook for our international businesses is positive. We believe that additional international opportunities will arise to expand our footprint in large oil producing regions with mature fields facing production declines.

On October 1, 2010, we closed the sale of our pressure pumping and wireline businesses to Patterson-UTI for cash consideration of $237.7 million and our retention of working capital associated with the businesses (subject to certain adjustments based on closing inventory). Management determined to sell these businesses because they were not aligned with our core business strategy of well intervention and international expansion.

Also, on October 1, 2010, we completed the purchase of 100% of the ownership interests in three subsidiaries of OFS Energy Services, LLC (“OFS ES”): Davis Energy Services, LLC; QCP Energy Services; LLC and Swan Energy Services, LLC (and indirectly their related subsidiaries). In addition, we acquired certain incidental assets from OFS ES and its parent company, OFS Holdings, LLC, that are used in the purchased businesses and agreed to assume certain specified liabilities. The total consideration of $229.7 million consisted of 15.8 million shares of our common stock (valued at $9.74 per share, based on the closing price on October 1, 2010) and a cash payment of $75.8 million. The purchase price is subject to certain post closing working capital and other adjustments. We are required to register the shares of common stock issued in the transaction under the Securities Act of 1933, as amended, subject to certain conditions. We will account for this acquisition as a business combination. The results of operations for the acquired businesses will be included in our consolidated financial statements beginning October 1, 2010.

RESULTS OF OPERATIONS

The following table shows our consolidated results of operations for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2011 and 2010, ~~and 2009~~respectively (in ~~thousands, except per share data)~~thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,						Three Months Ended March 31,
	2010			2009			2010			2009			2011			2010
*REVENUES*	$	283,739		$	215,349		$	803,483		$	718,059		$	390,984		$	251,959

*COSTS AND EXPENSES:*
Direct operating expenses		198,158			156,444			583,531			497,091			271,800			189,202
Depreciation and amortization expense		32,565			38,680			98,367			114,685			39,923			33,324
General and administrative expenses		46,833			39,350			130,726			129,815			52,779			39,028
Asset retirements and impairments		—			97,035			—			97,035
Loss on early extinguishment of debt														46,451			—
Interest expense, net of amounts capitalized		10,626			9,137			31,614			29,240			10,311			10,259
Other, net		(780	)		1,534			(1,556	)		(688	)		(2,385	)		(1,243	)

Total costs and expenses, net		287,402			342,180			842,682			867,178			418,879			270,570

Loss from continuing operations before tax		(3,663	)		(126,831	)		(39,199	)		(149,119	)		(27,895	)		(18,611	)
Income tax benefit		1,383			47,751			14,979			56,228			9,183			7,709

Loss from continuing operations		(2,280	)		(79,080	)		(24,220	)		(92,891	)		(18,712	)		(10,902	)
Income (loss) from discontinued operations, net of tax (expense) benefit of $(5,515), $25,438, $(11,044) and $27,394, respectively		8,283			(45,937	)		18,360			(49,695	)
Income from discontinued operations, net of tax														—			1,895

Net income (loss)		6,003			(125,017	)		(5,860	)		(142,586	)
Net loss														(18,712	)		(9,007	)

Loss attributable to noncontrolling interest		769			75			2,816			75			(577	)		(1,427	)

*INCOME (LOSS) ATTRIBUTABLE TO KEY*	$	6,772		$	(124,942	)	$	(3,044	)	$	(142,511	)
*LOSS ATTRIBUTABLE TO KEY*													$	(18,135	)	$	(7,580	)

Our direct operating expenses increased ~~$41.7~~$82.6 million, to ~~$198.2~~$271.8 million ~~(69.8%~~(69.5% of revenues), for the three months ended March 31, 2011, compared to $189.2 million (75.1% of revenues) for the three months ended ~~September 30, 2010, compared to $156.4 million (72.6% of revenues) for the three months ended September 30, 2009.~~March 31, 2010. The increase in direct operating expenses ~~is directly attributable~~was a direct result of activity increases in our business and inflation. Fuel and salary expenses have increased compared to ~~increased activity.~~the first quarter of the prior year due to rising prices and the reinstatement of employee benefits which were suspended in prior years.

Depreciation and Amortization Expense

Depreciation and amortization expense ~~decreased $6.1~~increased $6.6 million, or 19.8%, to ~~$32.6~~$39.9 million ~~(11.5% of revenues)~~ during the ~~third~~first quarter of ~~2010,~~2011, compared to ~~$38.7~~$33.3 million ~~(18.0% of revenues)~~ for the ~~third~~first quarter of ~~2009.~~2010. The ~~decrease~~increase in our depreciation and amortization expense is primarily attributable to the increase in our fixed asset ~~retirements~~base through our acquisitions during 2010, as well as increased capital expenditures in 2010 and ~~impairments we recognized during~~ the ~~third~~first quarter of ~~2009, which decreased the basis of our depreciable fixed assets.~~2011.

General and Administrative Expenses

General and administrative expenses increased ~~$7.5~~$13.8 million, to ~~$46.8~~$52.8 million ~~(16.5%~~(13.5% of revenues), for the three months ended March 31, 2011, compared to $39.0 million (15.5% of revenues) for the three months ended ~~September 30, 2010, compared to $39.4 million (18.3% of revenues) for the three months ended September 30, 2009.~~March 31, 2010. The increase in general and administrative expenses for the ~~third~~first quarter of ~~2010~~2011 was primarily due to ~~higher stock-based~~an increase in employee compensation resulting from the rescission of temporary employee salary and benefit reductions as well as increased headcount due to our growth. We also incurred additional professional fees related to ~~new equity awards and implementation costs for a new Enterprise Resource Planning (“ERP”) system conversion. Transaction costs incurred in the third quarter of 2010 related to our~~ acquisition ~~of OFS ES also contributed to the increase.~~activity.

Interest Expense, ~~Net~~net of Amounts Capitalized

Interest expense ~~was $10.6~~increased less than $0.1 million, ~~(3.7% of revenues)~~to $10.3 million for the three months ended ~~September 30, 2010, an increase~~March 31, 2011. We repurchased 99.2%, or $421.4 million, the aggregate principal amount of ~~$1.5~~our 8.375% Notes due 2014 during the first quarter pursuant to a tender offer for the notes and simultaneously issued $475.0 million ~~or 16.3%,~~aggregate principal amount of our 6.75% Notes due 2021. During the first quarter, we also borrowed $126.0 million and repaid $26.0 million on our revolving credit facility, leaving $100.0 million outstanding at March 31, 2011.

Loss on Extinguishment of Debt

Loss on extinguishment of debt was $46.5 million for the three months ended March 31, 2011, compared to ~~$9.1 million (4.2% of revenues)~~zero for the same period in ~~2009,~~2010, due to ~~higher interest rates~~our tender offer for the 2014 Notes and the termination of the 2007 Credit Facility during the first quarter of 2011. The loss primarily consisted of the tender premium on ~~our borrowings under our amended revolving credit facility.~~the 2014 Notes, as well as transaction fees and the write-off of the unamortized portion of deferred financing costs.

Other, net

The following table summarizes the components of other, net for the periods indicated:


	Three Months Ended September 30,						Three Months Ended March 31,
	2010			2009			2011			2010
	(in thousands)						(in thousands)
(Gain) loss on disposal of assets, net	$	(146	)	$	1,942		$	(669	)	$	335
Interest income		(5	)		(42	)		(20	)		(15	)
Foreign exchange loss (gain), net		30			(1,305	)
Other (income) expense, net		(659	)		939
Foreign exchange gain								(1,467	)		(1,364	)
Other income, net								(229	)		(199	)

Total	$	(780	)	$	1,534		$	(2,385	)	$	(1,243	)

~~Production Services~~International

Revenues ~~from external customers~~ for our ~~Production Services~~international segment increased ~~$18.2~~$5.4 million, or ~~85.4%~~9.8%, to ~~$39.5~~$61.1 million for the three months ended ~~September 30, 2010,~~March 31, 2011, compared to ~~$21.3~~$55.7 million for the three months ended ~~September 30, 2009.~~March 31, 2010. The increase in revenue for this segment is primarily attributable to ~~an increase~~our international expansion during 2010 to Colombia and the Middle East, in addition to increased activity in Argentina and Russia, offset by a decrease in revenues ~~from~~attributable to our ~~fishing and rental~~Mexican operations ~~as well as expansion of our coiled tubing services along with improved pricing~~ during the ~~period.~~first quarter of 2011 compared to the same period last year.

Operating expenses for our ~~Production Services~~international segment increased ~~$8.3~~$5.0 million, or ~~34.8%~~9.2%, to ~~$32.1~~$59.5 million for the ~~third~~first quarter of 2011, compared to $54.5 million for the first quarter of 2010 ~~compared to $23.8 million for the third quarter of 2009. Operating expenses~~and increased ~~due to expenses associated with the expansion of our coiled tubing operations. However, increased activity and improved pricing contributed to better operating income (excluding impairment charges)~~ as a ~~percentage~~direct result of ~~revenue from external customers compared to the same period in 2009.~~

~~During the three months ended September 30, 2009, due to market overcapacity, continued and prolonged depression of natural gas prices, decreased~~additional activity levels from our major customer base related to stimulation work and consecutive quarterly operating losses in our Production Services segment, we determined that events and changes in circumstances occurred indicating that the carrying value of the asset groups under this segment may not be recoverable. We performed an asset impairment test which resulted in the recording of a pre-tax impairment charge of approximately $30.7 million during the ~~third quarter of 2009. In addition, we impaired $0.5 million of goodwill related to this segment.~~period.

Functional Support

~~Operating~~Excluding the loss on early extinguishment of debt, operating expenses for Functional Support, which represent expenses associated with managing our ~~other reportable~~U.S. and International operating segments, increased ~~$1.6~~$9.6 million, or ~~6.0%~~40.0%, to ~~$28.8~~ $33.7

million ~~(10.2%~~(8.6% of consolidated revenues) for the three months ended ~~September 30, 2010~~March 31, 2011 compared to ~~$27.2~~$24.1 million ~~(12.6%~~(9.6% of consolidated revenues) for the same period in ~~2009.~~2010. The primary reason for the increase in costs is higher stock based compensation expense related to new equity awards and support costs related to our new ERP system during the third quarter of 2010. Transaction costs incurred in the third quarter of 2010 related to our acquisition of OFS ES also contributed to the increase.

~~Consolidated Results of Operations — Nine Months Ended September 30, 2010 and 2009~~

~~Revenues~~

~~Our revenues for the nine months ended September 30, 2010 increased $85.4 million, or 11.9%, to $803.5 million from $718.1 million for the nine months ended September 30, 2009. See~~~~“Segment Operating Results — Nine Months Ended September 30, 2010 and 2009”~~~~below for a more detailed discussion of the change in our revenues.~~

~~Direct Operating Expenses~~

Our direct operating expenses increased $86.4 million to $583.5 million (72.6% of revenues) for the nine months ended September 30, 2010, compared to $497.1 million (69.2% of revenues) for the nine months ended September 30, 2009. The increase in direct operating expenses is directly attributable to increased activity during the period, higher repairs and maintenance expenses as we mobilized idle equipment in the first part of the year to support the increases in activity, expansion into new domestic and international markets, and increases in fuel costs due to higher fuel prices.

~~Depreciation and Amortization Expense~~

Depreciation and amortization expense decreased $16.3 million to $98.4 million (12.2% of revenues) during the first nine months of 2010, compared to $114.7 million (16.0% of revenues) for the first nine months of 2009. The decrease in our depreciation and amortization expense is attributable to the asset retirements and impairments we recognized during the third quarter of 2009, which decreased the basis of our depreciable fixed assets.

~~General and Administrative Expenses~~

~~General and administrative expenses increased $0.9 million to $130.7 million (16.3% of revenues) for the nine~~

months ended September 30, 2010, compared to $129.8 million (18.1% of revenues) for the nine months ended September 30, 2009. General and administrative expenses increased due to additional stock based compensation expense related to new equity awards in 2010 offset by less professional fees during 2010 related to our cost reduction efforts. Transaction costs incurred during 2010 related to our acquisition of OFS ES also contributed to the increase.

~~Interest Expense, Net of Amounts Capitalized~~

Interest expense increased $2.4 million to $31.6 million (3.9% of revenues) for the nine months ended September 30, 2010, compared to $29.2 million (4.1% of revenues) for the same period in 2009, due to higher interest rates on our borrowings under our amended revolving credit facility, combined with lower capitalized interest due to lower capital expenditures related to the construction of equipment.

~~Other, net~~

~~The following table summarizes the components of other, net for the periods indicated:~~

Nine Months Ended September 30,
2010 2009
(in thousands)
Loss on disposal of assets, net $ 509 $ 566
Interest income (41 ) (459 )
Foreign exchange gain, net (479 ) (1,358 )
Other (income) expense, net (1,545 ) 563

Total $ (1,556 ) $ (688 )

~~Income Tax Benefit~~

We recorded an income tax benefit of $15.0 million on a pretax loss of $39.2 million for the nine months ended September 30, 2010, compared to an income tax benefit of $56.2 million on a pretax loss of $149.1 million for the nine months ended September 30, 2009. Our effective tax rate was 38.2% for the nine months ended September 30, 2010, compared to 37.7% for the nine months ended September 30, 2009. Our effective tax rate for 2010 differs from the statutory rate of 35% due to the mix of profit and loss between various taxing jurisdictions, such as foreign, state and local taxes, the impact of permanent items that affect book income but do not affect taxable income, and discrete adjustments such as accrual to return adjustments, changes in valuation allowances, and expenses or benefits recognized for uncertain tax positions.

~~Discontinued Operations~~

We recorded net income from discontinued operations of $18.4 million for the nine months ended September 30, 2010, compared to a net loss from discontinued operations of $49.7 million for the nine months ended September 30, 2009. The loss in 2009 mostly related to the asset impairment recorded on out pressure pumping equipment recorded in the third quarter of 2009. Excluding the impairment, results of discontinued operations improved in 2010, compared to the same period in 2009, for our fracturing and cementing services within our pressure pumping operations, due to higher activity, expansion into new markets and better pricing.

~~Noncontrolling Interest~~

For the nine months ended September 30, 2010, we recorded a benefit of $2.8 million, compared to a benefit of $0.1 million for the nine months ended September 30, 2009, associated with the net loss incurred by our joint venture in the Russian Federation with Geostream.

~~Segment Operating Results — Nine Months Ended September 30, 2010 and 2009~~

~~The following table shows operating results for each of our segments for the nine month periods ended September~~

~~30, 2010 and 2009, respectively (in thousands, except for percentages):~~

~~For the nine months ended September 30, 2010:~~

Well Production Functional
Servicing Services Support
Revenues from external customers $ 701,025 $ 102,458 $ —
Operating expenses 638,939 91,867 81,818
Net intersegment expense (income) 5,204 (4,903 ) (301 )
Operating income (loss) 56,882 15,494 (81,517 )

~~For the nine months ended September 30, 2009:~~

Well Production Functional
Servicing Services Support
Revenues from external customers $ 648,277 $ 69,782 $ —
Operating expenses 579,989 81,193 80,409
Asset retirements and impairments 65,869 31,166 —
Net intersegment expense (income) 3,835 (3,689 ) (146 )
Operating loss (1,416 ) (38,888 ) (80,263 )

~~Well Servicing~~

Revenues from external customers for our Well Servicing segment increased $52.7 million, or 8.1%, to $701.0 million for the nine months ended September 30, 2010, compared to $648.3 million for the nine months ended September 30, 2009. The overall increase in revenues resulted from sequential improvements in U.S. activity since June 2009, offset by lower revenues attributable to our operations in Mexico due to a decrease in activity of our work for Pemex.

Operating expenses for our Well Servicing segment were $638.9 million during the nine months ended September 30, 2010, which represented an increase of $59.0 million, or 10.2%, compared to $580.0 million for the same period in 2009. The increase in operating expenses is attributable to higher activity levels in the U.S. and severance costs incurred in Mexico due to a decrease in activity of our work for Pemex.

~~Production Services~~

Revenues for our Production Services segment increased $32.7 million, or 46.8%, to $102.5 million for the nine months ended September 30, 2010, compared to $69.8 million for the nine months ended September 30, 2009. The increase in revenue for this segment is attributable to an increase in revenues from our fishing and rental operations, as well as expansion of our coiled tubing services along with improved pricing during 2010.

Operating expenses for our Production Services segment increased $10.7 million, or 13.1%, to $91.9 million for the first nine months of 2010, compared to $81.2 million for the first nine months of 2009. Operating expenses increased due to expenses associated with the expansion of our coiled tubing operations. However, increased activity and improved pricing contributed to better operating income (excluding the impairment charges) as a percentage of revenues from external customers compared to the same period in 2009.

~~Functional Support~~

Operating expenses for Functional Support increased $1.4 million, or 1.8%, to $81.8 million (10.2% of consolidated revenues) for the nine months ended September 30, 2010 compared to $80.4 million (11.2% of consolidated revenues) for the same period in 2009. The primary reason for the increase in costs relates to higher equity compensation expense due to

new equity awards ~~and implementation costs for a new ERP system conversion~~granted during the ~~second~~first quarter of 2011, as well as the reinstatement in late 2010 ~~and overall increases~~of certain employee benefits that had been suspended in ~~activity. Transaction~~2009 as part of our cost savings effort. Additionally, the first quarter of 2011 includes a legal charge related to an injury claim as well as costs ~~incurred~~related to managing our new financial system implemented in 2010 ~~related to our acquisition~~that were not present in the first quarter of ~~OFS ES also contributed to the increase.~~2010.

LIQUIDITY AND CAPITAL RESOURCES

Current Financial Condition and Liquidity

As of ~~September 30, 2010,~~March 31, 2011, we had cash and cash equivalents of ~~$34.1~~$13.2 million. Our working capital (excluding the current portion of capital leases ~~notes payable~~ and long-term debt) was ~~$202.7~~$212.3 million, compared to ~~$204.5~~$136.4 million as of December 31, ~~2009.~~2010. Our working capital ~~decreased~~increased from the prior year end primarily as a result of ~~increased current liabilities~~the payment of income taxes during the period through borrowings on our long-term revolving credit facility and an increase in accounts receivable due to activity increases associated with improving market conditions during the first ~~nine months~~quarter of ~~2010.~~2011. Our total outstanding debt (including capital leases) was ~~$520.3~~$583.6 million, and we have no significant debt maturities until ~~2012.~~2016. As of ~~September 30, 2010,~~March 31, 2011, we ~~had $87.8~~have $100.0 million in borrowings and ~~$58.8~~$59.4 million in committed letters of credit outstanding under our ~~revolving credit facility,~~2011 Credit Facility, leaving ~~$153.4~~$240.6 million of available borrowing ~~capacity. On October 1, 2010 we borrowed $80.0 million~~capacity (as discussed further below under the credit facility to fund a portion of the purchase price of the OFS ES entities. Using a portion of the proceeds from the Patterson-UTI transaction, we subsequently repaid the entire balance of $167.8 million on October 4, 2010, bringing our total revolving facility borrowings outstanding to zero (see “~~Note 17. Subsequent Events”~~in~~“Item 1. Financial Statements"~~“Senior Secured Credit Facility”).

Cash Flows

The following table summarizes our cash flows for the ~~nine~~three month periods ended ~~September 30, 2010~~March 31, 2011 and ~~2009:~~2010:


	Nine Months Ended September						Three Months Ended March 31,
	30,						2011			2010
	2010			2009			(in thousands)
	(in thousands)
Net cash provided by operating activities	$	90,427		$	197,581
Net cash (used in) provided by operating activities							$	(39,914	)	$	65,754
Cash paid for capital expenditures		(101,065	)		(102,971	)		(107,439	)		(32,415	)
Proceeds received from sale of fixed assets		20,502			5,184
Other investing activities, net		165			12,206			5,201			1,171
Repayments of capital lease obligations		(6,891	)		(8,505	)		(1,120	)		(2,077	)
Repayments on long-term debt		(6,970	)		(1,539	)
Net repayment on revolving credit facility		—			(100,000	)
Repayments of long-term debt								(460,509	)		(513	)
Proceeds from long-term debt								475,000			—
Proceeds from borrowings on revolving credit facility								126,000			30,000
Repayments on revolving credit facility								(26,000	)		(30,000	)
Repurchases of common stock		(2,357	)		(248	)		(4,784	)		(2,180	)
Other financing activities, net		4,214			1,192			(7,925	)		1,600
Effect of exchange rates on cash		(1,366	)		(2,508	)		(1,954	)		(1,920	)

Net (decrease) increase in cash and cash equivalents	$	(3,341	)	$	392		$	(43,444	)	$	29,420

Cash used in financing activities was $12.0 million during the nine months ended September 30, 2010 and $109.1 million for the nine months ended September 30, 2009. Financing cash outflows during the first nine months of 2010 primarily consisted of repayments on capital lease obligations, and the repayment of the $6.0 million outstanding principal balance of a related party note and repurchases of common stock related to tax withholding on vesting restricted stock awards. These outflows were partially offset by the proceeds we received from the exercise of stock options.

Sources of Liquidity and Capital Resources

Our sources of liquidity include our current cash and cash equivalents, availability under our ~~Senior Secured~~2011 Credit Facility (defined below), and internally generated cash flows from operations. We received net cash proceeds of $237.7 million as a result of the Patterson-UTI transaction. We subsequently used $75.8 million to complete the purchase of the OFS ES entities. In addition, we paid off the outstanding revolver balance of $87.8 million as of September 30, 2010. These transactions resulted in a net pre-tax cash inflow of $74.1 million.

Debt Service

We do not have any significant maturities of debt ~~until 2012.~~in 2011. Interest on our ~~Senior Notes (defined below)~~revolving credit facility is due ~~on June 1 and December 1 of~~ each ~~year.~~quarter. Interest on ~~the Senior~~our 2021 Notes ~~of $17.8 million was paid on June 1, 2010 and~~(as defined below) is estimated to be ~~$17.8~~$26.9 million for ~~December 1, 2010.~~2011. We expect to fund interest payments from cash generated by operations. At ~~September 30, 2010,~~March 31, 2011, our annual debt maturities for our ~~Senior~~2014 Notes and 2021 Notes and borrowings under our ~~Senior Secured~~2011 Credit Facility ~~are~~were as follows:


	Principal Payments		Principal Payments
	(in thousands)		(in thousands)
Remainder of 2010	$	—
2011		—	$	—
2012		87,813		—
2013		—		—
2014		425,000		3,573
2015 and thereafter				575,000

Total principal payments	$	512,813	$	578,573

plus accrued and unpaid interest ~~thereon~~ to the redemption date, with the net cash proceeds offrom any one or more equity offerings; provided that at least 65% of the aggregate principal amount of the ~~Senior~~2021 Notes ~~issued under the indenture~~ remains outstanding immediately after each such redemption; and provided, further, that each such redemption shall occur within 180 days of the date of the closing of such equity offering.

In addition, at any time and from time to time prior to ~~December~~March 1, ~~2011,~~2016, we may, at our option, redeem all or a portion of the ~~Senior~~2021 Notes at a redemption price equal to 100% of the principal amount ~~thereof~~ plus ~~the “applicable premium” (as defined in the indenture governing the Senior Notes)~~a premium with respect to the ~~Senior~~2021 Notes ~~and~~ plus accrued and unpaid interest ~~thereon~~ to the redemption date. If we experience a change of control, subject to certain exceptions, we must give holders of the ~~Senior~~2021 Notes the opportunity to sell to us their ~~Senior~~2021 Notes, in whole or in part, at a purchase price equal to 101% of the aggregate principal amount, ~~thereof,~~ plus accrued and unpaid interest ~~thereon~~ to the date of purchase.

We are subject to certain negative covenants under the indenture governing the ~~Senior Notes.~~2021 Notes (the “Indenture”). The ~~indenture~~Indenture limits our ability to, among other things:

	•		~~sell assets;~~incur additional indebtedness and issue preferred equity interests;

	•		pay dividends or make other distributions ~~on capital stock~~ or ~~subordinated indebtedness;~~repurchase or redeem equity interests;

	•		make loans and investments;

	•		~~incur additional indebtedness~~enter into sale and leaseback transactions;

	•		sell, transfer or ~~issue preferred stock;~~otherwise convey assets;

	•		create ~~certain~~ liens;

	•		enter into transactions with affiliates;

	•		enter into agreements ~~that restrict dividends or other payments from our~~restricting subsidiaries’ ability to pay dividends;

	•		designate future subsidiaries ~~to us;~~as unrestricted subsidiaries; and

	•		consolidate, merge or ~~transfer~~sell all or substantially all of ~~our assets;~~

	•		~~engage in transactions with affiliates; and~~

	•		~~create unrestricted subsidiaries.~~the applicable entities’ assets.

These covenants are subject to certain exceptions and qualifications and contain cross-default provisions ~~tied~~relating to the covenants of our ~~Senior Secured~~2011 Credit ~~Facility. In addition, substantially~~Facility, discussed below. Substantially all of the covenants will terminate before the ~~Senior~~2021 Notes mature if one of two specified ratings agencies assigns the ~~Senior~~2021 Notes an investment grade rating in the future and no events of default exist under the ~~indenture governing~~Indenture. As of March 31, 2011, the ~~Senior Notes.~~2021 Notes were below investment grade. Any covenants that cease to apply to us as a result of achieving an investment grade rating will not be restored, even if the credit rating assigned to the ~~Senior~~2021 Notes later falls below an investment grade rating. ~~As of September 30, 2010, the Senior Notes were below investment grade and have never been assigned an investment grade rating, and we~~We were in compliance with ~~all the~~these covenants ~~under the Senior Notes.~~at March 31, 2011.

Senior Secured Credit Facility

~~We maintain~~On March 31, 2011, we simultaneously terminated (without pre-payment penalty) our $300 million credit agreement dated November 29, 2007, as amended, which was to mature no later than November 29, 2012, and entered into a new credit agreement with several lenders and JPMorgan Chase Bank, N.A., as Administrative Agent and Swing Line Lender, Bank of America, N.A., as Syndication Agent, and Capital One, N.A. and Wells Fargo Bank, N.A., as Co-Documentation Agents. In connection with the termination of our previous credit agreement, we incurred a loss of $2.2 million on early extinguishment of debt related to the write-off of the unamortized portion of deferred financing costs. The new 2011 credit agreement provides for a senior secured credit facility ~~pursuant to a revolving credit agreement with a syndicate of banks of which Bank of America, N.A. and Wells Fargo Bank, N.A. are the administrative agents~~ (the ~~“Senior Secured~~“2011 Credit Facility”). We entered into the Senior Secured Credit Facility on November 29, 2007, simultaneously with the offering of the Senior Notes, and entered into an amendment (the “Amendment”) to the Senior Secured Credit Facility on October 27, 2009. As amended, the Senior Secured Credit Facility consists consisting of a revolving credit facility, letter of credit sub-facility and swing line facility of up to an aggregate principal amount of ~~$300.0~~$400 million, all of which will mature no later than ~~November 29, 2012.~~March 31, 2016. The 2011 Credit Facility and the obligations thereunder are secured by substantially all of our assets and those of our subsidiary guarantors and are guaranteed by certain of our existing and future domestic subsidiaries.

~~The Amendment reduced~~In connection with the ~~total credit commitments under the facility from $400.0 million to $300.0 million, effected by a pro rata reduction~~execution of the ~~commitment~~2011 Credit Facility, we capitalized $4.7 million of ~~each lender under~~financing costs that will be amortized over the ~~facility. We have~~term of the ability to request increases in the total commitments under the facility by up to $100.0 million in the aggregate, with any such increases being subject to certain requirements as well as lenders’ approval. Pursuant to the Amendment, we also modified thedebt.

4338

~~applicable interest rates and some of the financial covenants, among other changes.~~

The interest rate per annum applicable to the ~~Senior Secured~~2011 Credit Facility ~~(as amended)~~ is, at our option, (i) adjusted LIBOR plus athe applicable margin ~~of 350 to 450 basis points, depending on our consolidated leverage ratio,~~ or (ii) ~~the base rate (defined as~~ the higher of (x) ~~Bank of America’s~~JPMorgan’s prime rate, ~~and~~ (y) the Federal Funds rate plus 0.5%) and (z) one-month adjusted LIBOR plus 1.0%, plus ain each case the applicable margin ~~of 250~~for all other loans. The applicable margin for LIBOR loans ranges from 225 to ~~350~~300 basis points, and the applicable margin for all other loans ranges from 125 to 200 basis points, depending onupon our consolidated total leverage ~~ratio.~~ratio as defined in the 2011 Credit Facility. Unused commitment fees on the facility ~~range from~~equal 0.50% ~~to 0.75%, depending upon our consolidated leverage ratio.~~.

The ~~Senior Secured~~2011 Credit Facility contains certain financial covenants, which, among other things, ~~require~~limits our annual capital expenditures, restricts our ability to repurchase shares and requires us to maintain certain financial ratios. The financial ratios and limit our annual capital expenditures. In addition to covenants that impose restrictions on our ability to repurchase shares, have assets owned by domestic subsidiaries located outside the United States and other such limitations, the amended Senior Secured Credit Facility also requires:require that:

	•		~~that~~ our consolidated funded indebtedness be no greater than 45% of our adjusted total capitalization;

	•		~~that~~ our senior secured leverage ratio of senior secured funded debt to trailing four quarters of earnings before interest, taxes, depreciation and amortization (as calculated pursuant to the terms of the ~~Senior Secured~~2011 Credit Facility, “EBITDA”) be no greater than ~~(i) 2.50 to 1.00 for the fiscal quarter ended March 31, 2010 through and including the fiscal quarter ending December 31, 2010 and, (ii) thereafter,~~ 2.00 to 1.00;

	•		~~that~~ we maintain a collateral coverage ratio, the ratio of the aggregate book value of the collateral to the amount of the total commitments, as of the last day of any fiscal quarter of at least;


*Fiscal Quarter Ending*	*Ratio*
June 30, 2011 through June 30, 2012		1.85 to 1.00
September 30, 2012 and thereafter		2.00 to 1.00

•

we maintain a consolidated interest coverage ratio of trailing four quarters EBITDA to interest expense of at least ~~the following amounts during each corresponding period:~~


~~through the fiscal quarter ending September 30, 2010~~			~~2.00 to 1.00~~

~~for the fiscal quarter ending December 31, 2010~~			~~2.50 to 1.00~~

~~thereafter~~			3.00 to 1.00;

	•		that we limit our capital expenditures (not including any made by foreign subsidiaries that are not wholly-owned) to (i) $120.0 million during each fiscal year if our consolidated leverage ratio of total funded debt to trailing four quarters EBITDA is greater than 3.50 to 1.00; or (ii) $250.0 million if our consolidated leverage ratio of total funded debt to trailing four quarters EBITDA is equal to or less than 3.50 to 1.00, subject to certain adjustments;

	•		that we only make acquisitions that either (i) are completed for equity consideration, without regard to leverage, or (ii) are completed for cash consideration, but only (A) if the consolidated leverage ratio of total funded debt to trailing four quarters EBITDA is 2.75 to 1.00 or less, (x) there is an aggregate amount of $25.0 million in unused credit commitments under the facility and (y) we are in pro forma compliance with the financial covenants contained in the credit agreement; and (B) if the consolidated leverage ratio of total funded debt to trailing four quarters EBITDA is greater than 2.75 to 1.00, in addition to the requirements in sub clauses (x) and (y) in clause (A) above, the cash amount paid with respect to acquisitions is limited to $25.0 million per fiscal year (subject to potential increase using amounts then available for capital expenditures and any net cash proceeds we receive after October 27, 2009 in connection with the issuance or sale of equity interests or the incurrence or issuance of certain unsecured debt securities that are identified as being used for such purpose); and

	•		~~that~~ we limit our ~~investment~~capital expenditures and investments in foreign subsidiaries ~~(including by way of loans made by us and our domestic subsidiaries~~ to ~~foreign subsidiaries and guarantees made by us and our domestic subsidiaries of debt of foreign subsidiaries) to $75.0~~$250.0 million ~~during any~~per fiscal year, ~~or an aggregate~~up to 50% of which amount may be carried over for expenditure in the following fiscal year, if after ~~October 27, 2009 equal~~giving pro forma effect thereto the consolidated total leverage ratio exceeds 3.00 to (i) the greater of $200.0 million or 25% of our consolidated net worth, plus (ii) any net cash proceeds we receive after October 27, 2009, in connection with the issuance or sale of equity interests or the incurrence of certain unsecured debt securities that are identified as being used for such purpose.1.00.

In addition, the ~~amended Senior Secured~~2011 Credit Facility contains certain affirmative and negative covenants, including, without limitation, restrictions ~~related to~~on (i) liens; (ii) debt, guarantees and other contingent obligations; (iii) mergers and consolidations; (iv) sales, transfers and other dispositions of property or assets; (v) loans, acquisitions, joint ventures and other ~~investments;~~

investments (with acquisitions permitted so long as, after giving pro forma effect thereto, no default or event of default exists under the 2011 Credit Facility, the pro forma consolidated total leverage ratio does not exceed 4.00 to 1.00, we are in compliance with other financial covenants and we have at least $25 million of availability under the 2011 Credit Facility); (vi) dividends and other distributions to, and redemptions and repurchases from, ~~equity holders;~~equityholders; (vii) making investments, loans or advances; (viii) selling properties; (ix) prepaying, redeeming or repurchasing ~~the Senior Notes~~subordinated (contractually or ~~other unsecured debt incurred pursuant to the sixth bullet point listed above; (viii)~~structurally) debt; (x) engaging in transactions with affiliates; (xi) entering into hedging arrangements; (xii) entering into sale and leaseback transactions; (xiii) granting negative pledges other than to the lenders; ~~(ix)~~(xiv) changes in the nature of ~~our~~ business; ~~(x)~~(xv) amending organizational documents, or amending or otherwise modifying any debt if such amendment or modification would have a material adverse effect, or amending the Senior Notes or any other unsecured debt incurred pursuant to the sixth bullet point listed above if the effect of such amendment is to shorten the maturity of the Senior Notes or such other unsecured debt;documents; and ~~(xi)~~(xvi) changes in accounting policies or reporting practices; in each of the foregoing cases, with certain exceptions. Furthermore, the 2011 Credit Facility provides that share repurchases in excess of $200 million can be made only if our debt to capitalization ratio is below 45%.

We may prepay the ~~Senior Secured~~2011 Credit Facility in whole or in part at any time without premium or penalty, subject to ~~our obligation~~certain reimbursements to ~~reimburse~~ the lenders for breakage and redeployment costs. The highest amount outstanding under the credit facility during the quarter was $87.8 million. On October 1, 2010 we borrowed $80.0 million against the credit facility to facilitate the purchase of the OFS ES entities (see “~~Note 17. Subsequent Events~~~~” in~~~~“Item 1. Financial Statements”~~) which brought our total borrowings outstanding under the revolver to $167.8 million. Using a portion of the proceeds from the Patterson-UTI transaction, we subsequently repaid the entire balance on October 4, 2010, bringing our total revolving facility borrowings outstanding to zero (see “~~Note 17. Subsequent Events”~~in~~“Item 1. Financial Statements”). We were in compliance with the covenants of the Senior Secured Credit Facility at September 30, 2010.~~

~~Related Party Notes Payable~~

Concurrently with the sale of six barge rigs and related equipment in May 2010, we repaid the remaining $6.0 million outstanding under a note payable to a related party. This was the second of two notes payable with related parties (each, a “Related Party Note”) entered into on October 25, 2007. The first Related Party Note was an unsecured note in the amount of $12.5 million, and was repaid on October 25, 2009. The second Related Party Note was an unsecured note in the amount of $10.0 million and was payable in annual installments of $2.0 million.

Capital Lease Agreements

We lease equipment, such as vehicles, tractors, trailers, frac tanks and forklifts, from financial institutions under master lease agreements. As ~~discussed in “~~~~Note 6. Long-Term Debt~~~~” in~~~~“Item 1. Financial Statements”~~~~, during the third quarter~~ of ~~2010, we repaid $1.3 million of outstanding capital leases in connection with the Patterson — UTI transaction. As of September 30, 2010,~~March 31, 2011, there was ~~$7.5~~$5.0 million outstanding under such equipment leases.

Off-Balance Sheet Arrangements

At ~~September 30, 2010,~~March 31, 2011 we did not, and we currently do not, have any off-balance sheet arrangements that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Liquidity Outlook and Future Capital Requirements

As of March 31, 2011, we had cash and cash equivalents of $13.2 million, available borrowing capacity of $240.6 million under our 2011 Credit Facility, and no significant debt maturities until 2016. We believe that our internally generated cash flows from operations, ~~net cash inflows from~~availability under the ~~purchase and sale transactions occurring on October 1, 2010,~~2011 Credit Facility and current reserves of cash and cash equivalents will be sufficient to finance the majority of our cash requirements for current and future operations, budgeted capital expenditures, and debt service for the next twelve months. Also, as we have historically done, we may, from time to time, access available funds under our Senior Secured Credit Facility to supplement our liquidity to meet cash requirements for day-to-day operations and times of peak needs throughout the year. Our planned capital expenditures, as well as any acquisitions we choose to pursue, could be financed through a combination of cash on hand, cash flow from operations, borrowings under our ~~Senior Secured~~2011 Credit Facility and, in the case of acquisitions, equity.

Capital Expenditures

During the ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2011, our capital expenditures totaled ~~$101.1~~$107.4 million, primarily related to fluid management expansion in the Bakken Shale, the deployment of heavy duty workover rigs, the purchase of ~~coiled tubing units, the addition of larger well service rigs,~~premium drill pipe and major maintenance of our existing fleet and ~~equipment, and capitalized costs associated with our new ERP system.~~equipment. Our capital expenditures program is

expected to total ~~approximately $190.0~~$240.0 million during ~~2010, with capital expenditures during the remainder of the year~~2011, focusing mainly on ~~the maintenance of our fleet and~~expansion to selected growth ~~opportunities~~regions in the U.S. market, as well as customer driven requirements. This projected capital expenditure amount does not include the acquisition of certain subsidiaries of OFS ES accounted for as a business combination or other potential growth opportunities related to strategic investments and acquisitions that may be in preliminary stages or unplanned at this point.market. Our ~~remaining~~ capital expenditure program for ~~2010~~2011 is subject to market conditions, including activity levels, commodity prices, and industry capacity. During 2011, we plan to focus on maximizing our current equipment fleet, although we may choose to increase our capital expenditures in 2011 to increase market share or expand our presence into a new market. We currently anticipate funding our ~~remaining 2010~~2011 capital expenditures through a combination of cash on hand, operating cash flow, ~~net cash inflows from the transactions completed in October 2010, or~~and borrowings under our ~~Senior Secured~~2011 Credit Facility.

~~Divestitures and Acquisitions~~

~~On October 1, 2010, we closed the sale of~~ Should our pressure pumping and wireline businesses to Patterson-UTI for cash consideration of $237.7 million and our retention of working capital associated with the businesses (subject to certain adjustments based on closing inventory).

On October 1, 2010, we completed the purchase of 100% of the ownership interests in three of OFS ES’s subsidiaries (and indirectly their related subsidiaries). In addition, we acquired certain incidental assets from OFS ES and its parent company, OFS Holdings, LLC, that are used in the purchased businesses, and we agreed to assume certain specified liabilities. The total consideration consisted of approximately 15.8 million shares of our common stock (which had a closing price of $9.74 on October 1, 2010) and a cash payment of $75.8 million. The purchase price is subject to certain post closing working capital and other adjustments, and was funded by cash on hand and borrowings on our Senior Secured Credit Facility.

We used a portion of the net proceeds from the Patterson-UTI transaction to pay down the outstanding balance on the revolving portion of our Senior Secured Credit Facility, with the remainder being available for use for general corporate purposes.

~~The~~operating cash flows ~~from the businesses being sold have not been separately identified in~~or activity levels prove to be insufficient to warrant our ~~consolidated statements of cash flows~~currently planned capital spending levels, management expects it will adjust our capital spending plans accordingly. We may also incur capital expenditures for ~~the nine month periods ended September 30, 2010~~strategic investments and 2009. We believe that the reduction in cash flows expected after the closing of the Patterson-UTI transaction will not have a material adverse impact on our liquidity or our ability to fund future operations and capital expenditures. We expect that the proceeds and investment of proceeds from the Patterson-UTI transaction, as well as anticipated cash flows from the OFS ES businesses, will have offset such reduction. Additionally, as we used a portion of the net proceeds from the divestiture to pay down the outstanding balance on our Senior Secured Credit Facility, we expect to improve our liquidity by reducing our leverage and required interest payments. As such, we believe that the sale of our pressure pumping and wireline businesses will not have a significant adverse impact on our near-term liquidity or cash flows.acquisitions.

PART II—OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

Our former general counsel, Jack D. Loftis, Jr., filed a lawsuit against us in the U.S. District Court, District of New Jersey, on April 21, 2006, in which he alleged a “whistle-blower” claim under the Sarbanes-Oxley Act, breach of contract, breach of duties of good faith and fair dealing, breach of fiduciary duty and wrongful termination. Following the transfer of the caseWe are subject to the District of Pennsylvania, on August 17, 2007, we filed counterclaims against Mr. Loftis alleging attorney malpractice, breach of contract and breach of fiduciary duties. In our counterclaims, we sought repayment of all severance paid to Mr. Loftis (approximately $0.8 million) plus benefits paid during the period July 8, 2004 to September 21, 2004, and damages relating to the allegations of malpractice and breach of fiduciary duties. During the third quarter, on September 2, 2010, we reached a settlement with Mr. Loftis regarding the alleged claims, and recorded an additional charge related to the settlement, having initially recorded a liability for this matter in the fourth quarter of 2008. Additionally, we are involved in various suits and claims that have arisen in the ordinary course of business. We do not believe that the disposition of any of ~~these items~~our ordinary course litigation will result in a material adverse effect on our consolidated financial position, results of operations or cash flows.

For additional information on legal proceedings, see “Note 9.10. Commitments and Contingencies” in “Item 1. Financial Statements” of “Part I” above.

ITEM 1A.RISK FACTORS

There have been no material changes in our risk factors disclosed in our ~~2009 Annual Report dated as of, and filed with the SEC on, February 26, 2010.~~2010 Form 10-K. For a discussion of these risk factors, see “Item 1A. Risk Factors” in our ~~2009 Annual Report. However, we have identified the following additional risk factor:~~

~~We have sold our pressure pumping and wireline businesses, which poses certain risks.~~

~~On October 1,~~ 2010 we completed the sale of our pressure pumping and wireline businesses. Divestitures of businesses involve a number of risks, including the diversion of management and employee attention, significant costs and expenses, the loss of customer relationships, a decrease in revenues and earnings associated with the divested businesses, and the possible disruption of operations in both the affected and retained businesses. In addition, divestitures may involve significant post-closing separation activities, including the expenditure of significant financial and employee resources.Form 10-K.

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

During the three months ended ~~September 30, 2010,~~March 31, 2011, we repurchased the shares shown in the table below to satisfy tax withholding obligations upon the vesting of restricted stock awarded to certain of our employees:

ISSUER PURCHASES OF EQUITY SECURITIES

Approximate
Total Number of Dollar Amount of
Shares Purchased Shares that may
Weighted as Part of Publicly yet be Purchased
Number of Average Price Announced Plans Under the Plans
Period Shares Purchased (1) Paid per Share (2) or Programs or Programs
July 1, 2010 to July 31, 2010 — $ — — —
August 1, 2010 to August 31, 2010 25,327 8.45 — —
September 1, 2010 to September 30, 2010 — — — —

Total 25,327 $ 8.45 — —


							Approximate
					Total Number of		Dollar Amount of
					Shares Purchased		Shares that may
			Weighted		as Part of Publicly		yet be Purchased
	Number of		Average Price		Announced Plans		Under the Plans
Period	Shares Purchased (1)		Paid per Share (2)		or Programs		or Programs
January 1, 2011 to January 31, 2011		132,023	$	13.16		—	$	—
February 1, 2011 to February 28, 2011		—		—		—		—
March 1, 2011 to March 31, 2011		196,894		15.47		—		—

Total		328,917	$	14.54		—	$	—

EXHIBIT INDEX


3.1		Articles of Restatement of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2006, File No. 001-08038.)


3.2		Unanimous consent of the Board of Directors of Key Energy Services, Inc. dated January 11, 2000, limiting the designation of the additional authorized shares to common stock. (Incorporated by reference to Exhibit 3.2 of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 001-08038.)


3.3		Second Amended and Restated By-laws of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on September 22, 2006, File No. 001-08038.)


3.4		Amendment to Second Amended and Restated By-laws of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on November 2, 2007, File No. 001-08038.)


3.5		Amendments to Second Amended and Restated By-laws of Key Energy Services, Inc. adopted April 4, 2008. (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on April 9, 2008, File No. 001-08038.)


3.6		Amendment to Second Amended and Restated By-laws of Key Energy Services, Inc. adopted June 4, 2009. (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on June 10, 2009, File No. 001-08038.)


4.1		Fourth Supplemental Indenture dated as of ~~November 29, 2007,~~March 1, 2011 by and among Key Energy Services, Inc., the subsidiary guarantors ~~party thereto~~named therein and The Bank of New York Mellon Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on ~~November 30, 2007,~~March 1, 2011, File No. 001-08038.)


4.2		~~Registration Rights Agreement,~~Indenture, dated as of ~~November 29, 2007,~~March 4, 2011, among Key Energy Services, Inc., the ~~subsidiary~~ guarantors named therein and The Bank of ~~the~~New York Mellon Trust Company, ~~party thereto, and Lehman Brothers~~N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on March 4, 2011, File No. 001-08038.)

4.3		First Supplemental Indenture, dated as of March 4, 2011, among Key Energy Services, Inc., ~~Banc~~the guarantors named therein and The Bank of ~~America Securities LLC and Morgan Stanley & Co. Incorporated,~~New York Mellon Trust Company, N.A., as ~~representatives of the several initial purchasers named therein.~~trustee. (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed on ~~November 30, 2007,~~March 4, 2011, File No. 001-08038.)

	~~4.3~~
4.4		~~First Supplemental Indenture, dated as~~Form of ~~January 22, 2008, among Key Marine Services, LLC, the existing guarantors party thereto and The Bank of New York Trust Company, N.A., as trustee. (Incorporated~~global note for 6.750% Senior Notes due 2021 (incorporated by reference from Exhibit A to Exhibit ~~4.5 of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 001-08038.)~~
4.3).
	~~4.4~~
10.1		~~Second Supplemental Indenture,~~Credit Agreement, dated as of January 13, 2009, among Key Energy Mexico, LLC, the existing Guarantors and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.6 of our Annual Report on Form 10-K for the fiscal year ended DecemberMarch 31, ~~2009, File No. 001-08038.)~~

	~~4.5~~		~~Third Supplemental Indenture, dated as of July 31, 2009,~~2011, among Key Energy Services, ~~California,~~ Inc., each of the ~~existing Guarantors and The~~lenders from time to time party thereto, JPMorgan Chase Bank, N.A., as administrative agent, Bank of ~~New York Trust Company,~~America, N.A., as ~~trustee. (Incorporated by reference to Exhibit 4.5 of our Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 001-08038.)~~

	~~10.1~~		~~Asset Purchase Agreement, dated~~syndication agent, and Capital One, N.A. and Wells Fargo Bank, N.A., as of July 2, 2010, by and among Key Energy Pressure Pumping Services, LLC, Key Electric Wireline Services, LLC, Key Energy Services, Inc., Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.) and Patterson UTI Energy, Inc.co-documentation agents. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on ~~July 6, 2010, File No. 001-08038.)~~

	10.2*		Amending Letter Agreement, dated September 1, 2010, by and among Key Energy Pressure Pumping Services, LLC, Key Electric Wireline Services, LLC, Key Energy Services, Inc., Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.) and Patterson UTI Energy, Inc.

	10.3*		Amending Letter Agreement, dated October 1, 2010, by and among Key Energy Pressure Pumping Services, LLC, Key Electric Wireline Services, LLC, Key Energy Services, Inc., Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.) and Patterson UTI Energy, Inc.

	~~10.4~~		Purchase and Sale Agreement, dated as of July 23, 2010, by and among OFS Holdings, LLC, a Delaware limited liability company, OFS Energy Services, LLC, a Delaware limited liability company, Key Energy Services, Inc., a Maryland corporation, and Key Energy Services, LLC, a Texas limited liability company. (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K/A filed on October 8, 2010,April 5, 2011, File No. 001-08038.)

	~~10.5~~		Amendment No. 1 to Purchase and Sale Agreements, dated as of August 27, 2010, by and among OFS Holdings, LLC, a Delaware limited liability company, OFS Energy Services, LLC, a Delaware limited liability company, Key Energy Services, Inc., a Maryland corporation, and Key Energy Services, LLC, a Texas limited liability company. (Incorporated by reference to Exhibit 2.2 of our Current Report on Form 8-K/A filed on October 8, 2010, File No. 001-08038.)

	~~10.6~~		Amendment No. 2 to Purchase and Sale Agreements, dated as of September 30, 2010, by and among OFS Holdings, LLC, a Delaware limited liability company, OFS Energy Services, LLC, a Delaware limited liability company, Key Energy Services, Inc., a Maryland corporation, and Key Energy Services, LLC, a Texas limited liability company. (Incorporated by reference to Exhibit 2.3 of our Current Report on Form 8-K/A filed on October 8, 2010, File No. 001-08038.)

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


101*		Interactive Data File.


*		~~Filed herewith~~

~~EXHIBITS INDEX~~

	~~3.1~~		~~Articles of Restatement of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2006, File No. 001-08038.)~~

	~~3.2~~		Unanimous consent of the Board of Directors of Key Energy Services, Inc. dated January 11, 2000, limiting the designation of the additional authorized shares to common stock. (Incorporated by reference to Exhibit 3.2 of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 001-08038.)

	~~3.3~~		~~Second Amended and Restated By-laws of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on September 22, 2006, File No. 001-08038.)~~

	~~3.4~~		Amendment to Second Amended and Restated By-laws of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on November 2, 2007, File No. 001-08038.)

	~~3.5~~		Amendments to Second Amended and Restated By-laws of Key Energy Services, Inc. adopted April 4, 2008. (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on April 9, 2008, File No. 001-08038.)

	~~3.6~~		Amendment to Second Amended and Restated By-laws of Key Energy Services, Inc. adopted June 4, 2009. (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on June 10, 2009, File No. 001-08038.)

	~~4.1~~		Indenture, dated as of November 29, 2007, among Key Energy Services, Inc., the guarantors party thereto and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of our Form 8-K filed on November 30, 2007, File No. 001-08038.)

	~~4.2~~		Registration Rights Agreement, dated as of November 29, 2007, among Key Energy Services, Inc., the subsidiary guarantors of the Company party thereto, and Lehman Brothers Inc., Banc of America Securities LLC and Morgan Stanley & Co. Incorporated, as representatives of the several initial purchasers named therein. (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed on November 30, 2007, File No. 001-08038.)

	~~4.3~~		First Supplemental Indenture, dated as of January 22, 2008, among Key Marine Services, LLC, the existing guarantors party thereto and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.5 of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 001-08038.)

	~~4.4~~		Second Supplemental Indenture, dated as of January 13, 2009, among Key Energy Mexico, LLC, the existing Guarantors and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.6 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2009, File No. 001-08038.)

	~~4.5~~		Third Supplemental Indenture, dated as of July 31, 2009, among Key Energy Services California, Inc., the existing Guarantors and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.5 of our Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 001-08038.)

	~~10.1~~		Asset Purchase Agreement, dated as of July 2, 2010, by and among Key Energy Pressure Pumping Services, LLC, Key Electric Wireline Services, LLC, Key Energy Services, Inc., Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.) and Patterson UTI Energy, Inc. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on July 6, 2010, File No. 001-08038.)

	10.2*		Amending Letter Agreement, dated September 1, 2010, by and among Key Energy Pressure Pumping Services, LLC, Key Electric Wireline Services, LLC, Key Energy Services, Inc., Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.) and Patterson UTI Energy, Inc.

	10.3*		Amending Letter Agreement, dated October 1, 2010, by and among Key Energy Pressure Pumping Services, LLC, Key Electric Wireline Services, LLC, Key Energy Services, Inc., Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.) and Patterson UTI Energy, Inc.

	~~10.4~~		Purchase and Sale Agreement, dated as of July 23, 2010, by and among OFS Holdings, LLC, a Delaware limited liability company, OFS Energy Services, LLC, a Delaware limited liability company, Key Energy Services, Inc., a Maryland corporation, and Key Energy Services, LLC, a Texas limited liability company. (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K/A filed on October 8, 2010, File No. 001-08038.)

	~~10.5~~		Amendment No. 1 to Purchase and Sale Agreements, dated as of August 27, 2010, by and among OFS Holdings, LLC, a Delaware limited liability company, OFS Energy Services, LLC, a Delaware limited liability company, Key Energy Services, Inc., a Maryland corporation, and Key Energy Services, LLC, a Texas limited liability company. (Incorporated by reference to Exhibit 2.2 of our Current Report on Form 8-K/A filed on October 8, 2010, File No. 001-08038.)


Part I—Financial Information		4
Item 1. Financial Statements		4
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	33	31
Item 3. Quantitative and Qualitative Disclosures About Market Risk	46	41
Item 4. Controls and Procedures	46	41
Part II—Other Information	48
Item 1. Legal Proceedings	48	42
Item 1A. Risk Factors	48	42
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	48	42
Item 3. Defaults Upon Senior Securities	49	42
Item 4. (Removed and Reserved)		42
Item 5. Other Information	49	42
Item 6. Exhibits	49
~~EX-10.2~~
~~EX-10.3~~43
EX-31.1
EX-31.2
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT


				Production
	Well Servicing			Services		Total
	(in thousands)
December 31, 2009	$	342,023		$	4,079	$	346,102
Purchase price and other adjustments, net		3,750			—		3,750
Impact of foreign currency translation		(151	)		78		(73	)

September 30, 2010	$	345,622		$	4,157	$	349,779


	Weighted														Weighted
	average														average remaining
	remaing amortization		Expected Amortization Expense												amortization		Expected Amortization Expense
	period (years)		Q4 2010		2011		2012		2013		2014		2015		period (years)		2011		2012		2013		2014		2015
							(In thousands)												(in thousands)
Noncompete agreements		2.7	$	660	$	2,620	$	2,423	$	406	$	338	$	—
Non-compete agreements																2.0	$	2,484	$	2,597	$	406	$	339	$	—
Patents, trademarks and tradename		4.8		84		289		183		127		120		105		17.9		644		537		481		416		405
Customer relationships and contracts		7.7		1,481		4,224		3,056		2,208		1,670		1,299		7.0		11,156		6,818		4,907		3,491		2,490
Developed technology																0.4		478		—		—		—		—
Customer backlog		0.9		76		122		—		—		—		—		0.4		85		—		—		—		—
Developed technology		0.9		312		499		—		—		—		—

Total intangible asset amortization expense			$	2,613	$	7,754	$	5,662	$	2,741	$	2,128	$	1,404			$	14,847	$	9,952	$	5,794	$	4,246	$	2,895


																Three Months Ended March 31, 2010
	Three Months Ended September 30, 2009																		Guarantor			Non-Guarantor
				Guarantor			Non-Guarantor									Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated									(in thousands)
	(in thousands) (unaudited)																					(unaudited)
Revenues	$	—		$	180,910		$	47,960		$	(13,521	)	$	215,349		$	—		$	211,194		$	56,011		$	(15,246	)	$	251,959

Costs and expenses:
Direct operating expense		—			123,751			43,492			(10,799	)		156,444			—			145,347			55,136			(11,281	)		189,202
Depreciation and amortization expense		—			37,087			1,593			—			38,680			—			30,961			2,363			—			33,324
General and administrative expense		(891	)		35,975			4,266			—			39,350			1,228			33,922			5,239			(1,361	)		39,028
Asset retirements and impairments		—			97,035			—			—			97,035
Interest expense, net of amounts capitalized		10,367			(1,326	)		96			—			9,137			11,187			(889	)		(39	)		—			10,259
Other, net		195			1,836			2,183			(2,680	)		1,534			(697	)		686			2,482			(3,714	)		(1,243	)

Total costs and expenses, net		9,671			294,358			51,630			(13,479	)		342,180			11,718			210,027			65,181			(16,356	)		270,570

(Loss) income from continuing operations before taxes		(9,671	)		(113,448	)		(3,670	)		(42	)		(126,831	)		(11,718	)		1,167			(9,170	)		1,110			(18,611	)
Income tax benefit (expense)		70,143			(25,438	)		3,045			1			47,751
Income tax benefit																	7,307			—			402			—			7,709

Income (loss) from continuing operations		60,472			(138,886	)		(625	)		(41	)		(79,080	)
(Loss) income from continuing operations																	(4,411	)		1,167			(8,768	)		1,110			(10,902	)
Discontinued operations		—			(45,937	)		—			—			(45,937	)		—			1,895			—			—			1,895

Net income (loss)		60,472			(184,823	)		(625	)		(41	)		(125,017	)
Net (loss) income																	(4,411	)		3,062			(8,768	)		1,110			(9,007	)
Loss attributable to noncontrolling interest		—			—			75			—			75			—			—			(1,427	)		—			(1,427	)

INCOME (LOSS) ATTRIBUTABLE TO KEY	$	60,472		$	(184,823	)	$	(550	)	$	(41	)	$	(124,942	)
(LOSS) INCOME ATTRIBUTABLE TO KEY																$	(4,411	)	$	3,062		$	(7,341	)	$	1,110		$	(7,580	)


(1)		Represents the average of the monthly average prices for each of the periods presented. Source: EIA / Bloomberg

(2)		Source:www.bakerhughes.com


					Rig Hours		Trucking Hours
2011:
First Quarter						525,460		711,701
	Rig Hours		Trucking Hours
2010:
First Quarter		485,183		459,292		485,183		459,292
Second Quarter		489,168		518,483		489,168		518,483
Third Quarter		503,890		559,181		503,890		559,181
2009:
First Quarter		489,819		499,247
Second Quarter		415,520		416,269
Third Quarter		416,810		398,027
Fourth Quarter		439,552		422,253		493,945		707,616

Total 2009		1,761,701		1,735,796
Total 2010						1,972,186		2,244,572


							Functional
*For the three months ended March 31, 2011:*	U.S.			International			Support
Revenues from external customers	$	329,904		$	61,080		$	—
Operating expenses		271,257			59,512			33,733
Loss on early extinguishment of debt		—			—			46,451
Operating income (loss)		58,647			1,568			(80,184	)
Operating income (loss), excluding loss on early extinguishment of debt		58,647			1,568			(33,733	)
Operating income, as a percentage of revenue		17.8	%		2.6	%		n/a


	Well			Production			Functional
	Servicing			Services			Support
Revenues from external customers	$	244,288		$	39,451		$	—
Operating expenses		216,648			32,071			28,837
Net intersegment expense (income)		2,292			(2,280	)		(12	)
Operating income (loss)		25,348			9,660			(28,825	)

*For the three months ended September 30, 2009:*

	Well			Production			Functional
	Servicing			Services			Support
Revenues from external customers	$	194,071		$	21,278		$	—
Operating expenses		183,466			23,794			27,214
Asset retirements and impairments		65,869			31,166			—
Net intersegment expense (income)		2,689			(1,950	)		(739	)
Operating loss		(57,953	)		(31,732	)		(26,475	)


(1)		Represents shares repurchased to satisfy tax withholding obligations upon the vesting of restricted stock awards.

(2)		The price paid per share on the vesting date with respect to the tax withholding repurchases was determined using the closing price as quoted on the ~~New York Stock Exchange~~NYSE on the vesting date for awards granted under the Key Energy Services, Inc. ~~2007~~2009 Equity and Cash ~~Incentive Plan and the previous business day for awards granted under the Key Energy Group, Inc. 1997~~ Incentive Plan.


	KEY ENERGY SERVICES, INC. (Registrant)
Date: May 5, 2011	By:	/s/ T.M. Whichard III
		T.M. Whichard III
		Senior Vice President and Chief Financial Officer (As duly authorized officer and Principal Financial Officer)


	~~KEY ENERGY SERVICES, INC.~~ ~~(Registrant)~~
	~~By:~~	~~/s/ Richard J. Alario~~
		~~Richard J. Alario~~
		~~President and Chief Executive Officer~~ ~~(Principal Executive Officer)~~