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 ~~March 31,~~June 30, 2010


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

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).

Yesoþ Noo

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



Large accelerated filerþ	Accelerated filero	Non-accelerated filero	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 ~~April~~July 30, 2010, the number of outstanding shares of common stock of the registrant was ~~125,429,664.~~125,665,035.

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 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. In evaluating those statements, you should carefully consider the information above as well as the risks outlined in “~~Item 1A. Risk Factors~~~~” in~~ this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K for the year ended December 31, ~~2009.~~2009, in our Quarterly Report on Form 10-Q for the period ended March 31, 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.

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.~~		*ITEM 1.FINANCIAL STATEMENTS***

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


	March 31,			December 31,
	2010			2009			June 30, 2010			December 31, 2009
	(unaudited)						(unaudited)
*ASSETS*
Current assets:
Cash and cash equivalents	$	66,814		$	37,394		$	47,040		$	37,394
Accounts receivable, net of allowance for doubtful accounts of $7,810 and $5,441, respectively		255,275			214,662
Inventories		28,236			27,452

Accounts receivable, net of allowance for doubtful accounts of $6,560 and $5,441, respectively								284,916			214,662
Inventory								21,191			23,478
Other current assets		56,046			104,624			58,168			104,624
Current assets held for sale								7,631			3,974

Total current assets		406,371			384,132			418,946			384,132

Property and equipment		1,736,559			1,728,174			1,619,590			1,647,718
Accumulated depreciation		(873,909	)		(863,566	)		(837,613	)		(853,449	)

Property and equipment, net		862,650			864,608			781,977			794,269


Goodwill		346,831			346,102			349,107			346,102
Other intangible assets, net		39,045			41,048			35,986			41,048
Deferred financing costs, net		9,768			10,421			9,114			10,421
Equity method investments		5,848			5,203			6,214			5,203
Other non-current assets		12,579			12,896

Other noncurrent assets								13,228			12,896
Noncurrent assets held for sale								67,264			70,339

TOTAL ASSETS	$	1,683,092		$	1,664,410		$	1,681,836		$	1,664,410


*LIABILITIES AND EQUITY*
Current liabilities:
Accounts payable	$	57,738		$	46,086		$	50,488		$	46,086
Current portion of capital leases, notes payable and long-term debt								5,714			10,152
Other current liabilities		148,687			133,531			169,443			133,531
Current portion of capital leases, notes payable and long-term debt		8,863			10,152

Total current liabilities		215,288			189,769			225,645			189,769

Capital leases, notes payable, and long-term debt		522,665			523,949
Other non-current liabilities		207,730			207,552
Capital leases, notes payable and long-term debt								517,464			523,949
Other noncurrent liabilities								200,502			207,552

Commitments and contingencies

Equity:
Common stock, $0.10 par value; 200,000,000 shares authorized, 125,393,247 and 123,993,480 shares issued and outstanding, respectively		12,539			12,399
Common stock, $0.10 par value; 200,000,000 shares authorized, 125,637,523 and 123,993,480 shares issued and outstanding, respectively								12,564			12,399
Additional paid-in capital		610,185			608,223			616,397			608,223
Accumulated other comprehensive loss		(50,569	)		(50,763	)		(50,999	)		(50,763	)
Retained earnings		129,578			137,158			127,342			137,158

Total equity attributable to Key		701,733			707,017			705,304			707,017
Noncontrolling interest		35,676			36,123			32,921			36,123

Total equity		737,409			743,140			738,225			743,140

TOTAL LIABILITIES AND EQUITY	$	1,683,092		$	1,664,410		$	1,681,836		$	1,664,410

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


	Three Months Ended March 31,
	2010			2009			Three Months Ended						Six Months Ended June
							June 30,						30,
							2010			2009			2010			2009
*REVENUES*	$	302,071		$	331,989		$	267,785		$	219,061		$	519,744		$	502,710

*COSTS AND EXPENSES:*
Direct operating expenses		230,920			227,227			196,171			155,118			385,373			340,647
Depreciation and amortization expense		36,703			44,756			32,478			37,181			65,802			76,005
General and administrative expenses		40,952			48,706			44,866			44,039			83,893			90,465
Interest expense, net of amounts capitalized		10,247			9,648			10,729			10,173			20,988			20,103
Other, net		(1,253	)		523			467			(2,061	)		(776	)		(2,222	)

Total costs and expenses, net		317,569			330,860			284,711			244,450			555,280			524,998

(Loss) income before tax		(15,498	)		1,129
Income tax benefit (expense)		6,491			(225	)
Loss from continuing operations before tax								(16,926	)		(25,389	)		(35,536	)		(22,288	)
Income tax benefit								5,888			9,365			13,596			8,477

Net (loss) income		(9,007	)		904
Loss from continuing operations								(11,038	)		(16,024	)		(21,940	)		(13,811	)
Discontinued operations, net of tax (expense) benefit of $(4,312), $1,293, $(5,529) and $1,956, respectively								8,182			(2,449	)		10,077			(3,758	)

Net loss								(2,856	)		(18,473	)		(11,863	)		(17,569	)

Loss attributable to noncontrolling interest								620			—			2,047			—

*LOSS ATTRIBUTABLE TO KEY*							$	(2,236	)	$	(18,473	)	$	(9,816	)	$	(17,569	)


Net loss attributable to noncontrolling interest		1,427			—

*(LOSS) INCOME ATTRIBUTABLE TO KEY*	$	(7,580	)	$	904


*(Loss) earnings per share attributable to Key:*
*Loss per share from continuing operations attributable to Key:*
Basic	$	(0.06	)	$	0.01		$	(0.08	)	$	(0.13	)	$	(0.16	)	$	(0.12	)
Diluted	$	(0.06	)	$	0.01		$	(0.08	)	$	(0.13	)	$	(0.16	)	$	(0.12	)

*Earnings (loss) per share from discontinued operations:*
Basic							$	0.06		$	(0.02	)	$	0.08		$	(0.03	)
Diluted							$	0.06		$	(0.02	)	$	0.08		$	(0.03	)

*Loss per share attributable to Key:*
Basic							$	(0.02	)	$	(0.15	)	$	(0.08	)	$	(0.15	)
Diluted							$	(0.02	)	$	(0.15	)	$	(0.08	)	$	(0.15	)

*Loss from continuing operations attributable to Key:*
Loss from continuing operations							$	(11,038	)	$	(16,024	)	$	(21,940	)	$	(13,811	)
Loss attributable to noncontrolling interest								620			—			2,047			—

Loss from continuing operations attributable to Key							$	(10,418	)	$	(16,024	)	$	(19,893	)	$	(13,811	)


*Weighted average shares outstanding:*
Basic		124,952			120,665			125,412			120,963			125,183			120,815
Diluted		124,952			121,436			125,412			120,963			125,183			120,815

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


	Three Months Ended March 31,
	2010			2009			Six Months Ended June 30,
							2010			2009
*CASH FLOWS FROM OPERATING ACTIVITIES:*

Net (loss) income	$	(9,007	)	$	904
Net loss							$	(11,863	)	$	(17,569	)

Adjustments to reconcile net (loss) income to net cash provided by operating activities:

Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization expense		36,703			44,756			72,560			87,947
Bad debt expense		(32	)		843			(57	)		2,674
Accretion of asset retirement obligations		128			139			259			280
(Income) loss from equity-method investments		(577	)		262
(Income) loss from equity method investments								(900	)		436
Amortization of deferred financing costs and discount		662			522			1,319			1,044
Deferred income tax (benefit) expense		(4,579	)		524			(5,246	)		643
Capitalized interest		(952	)		(1,945	)		(1,977	)		(2,444	)
Loss on disposal of assets, net		335			689
Loss (gain) on disposal of assets, net								645			(661	)
Loss on sale of available for sale investments, net								—			30
Share-based compensation		2,679			489			6,438			3,295
Excess tax benefits from share-based compensation								(2,172	)		—
Changes in working capital:
Accounts receivable		(38,040	)		115,026			(70,261	)		177,321
Other current assets		55,132			649			55,220			8,086
Accounts payable, accrued interest and accrued expenses		21,972			(31,471	)		23,322			(105,098	)
Share-based compensation liability awards		438			(730	)		585			(21	)
Other assets and liabilities		892			(1,274	)		(3,177	)		1,336

Net cash provided by operating activities		65,754			129,383			64,695			157,299


*CASH FLOWS FROM INVESTING ACTIVITIES:*

Capital expenditures		(32,415	)		(44,797	)		(67,923	)		(67,409	)
Proceeds from sale of fixed assets		1,006			797			20,073			3,818
Dividend from equity-method investment		165			—
Dividend from equity method investments								165			199

Net cash used in investing activities		(31,244	)		(44,000	)		(47,685	)		(63,392	)


*CASH FLOWS FROM FINANCING ACTIVITIES:*

Repayments of long-term debt		(513	)		(513	)		(6,970	)		(1,026	)
Repayments of capital lease obligations		(2,077	)		(2,635	)		(3,992	)		(6,107	)
Borrowings on revolving credit facility		30,000			—			30,000			—
Repayments on revolving credit facility		(30,000	)		—			(30,000	)		(100,000	)
Repurchases of common stock		(2,180	)		(38	)		(2,357	)		(113	)
Proceeds from exercise of stock options		1,600			—			2,083			1,177
Excess tax benefits from share-based compensation								2,172			—

Net cash used in investing activities		(3,170	)		(3,186	)
Net cash used in financing activities								(9,064	)		(106,069	)


Effect of changes in exchange rates on cash		(1,920	)		(714	)		1,700			(890	)

Net increase in cash and cash equivalents		29,420			81,483

Net increase (decrease) in cash and cash equivalents								9,646			(13,052	)

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

Cash and cash equivalents, end of period	$	66,814		$	174,174		$	47,040		$	79,639

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 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 services include rig-based services, fluid management services, pressure pumping services, coiled tubing services, fishing and rental services, and wireline services. We operate in most major oil and natural gas producing regions of the United States as well as internationally in Argentina, Mexico, and the Russian Federation. We also own a technology development company based in Canada and have ownership interests in two oilfield service companies based in Canada.

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 balance sheet was prepared from audited financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2009. 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 Form 10-K for the year ended December 31, 2009.

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 six month ~~period~~periods ended ~~March 31,~~June 30, 2010 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 were available to be issued, we ~~identified~~entered into an ~~unfavorable jury verdict in a legal matter~~agreement to sell our pressure pumping and wireline operations to Patterson – UTI Energy (“Patterson”) that required disclosure as a subsequent event. In addition, we entered into a purchase and sale agreement with OFS Energy Services, LLC (“OFS ES”) to purchase 100% of the membership interests in three of OFS ES’s subsidiaries (and indirectly their related subsidiaries) and related incidental assets. See“Note ~~16.~~17. Subsequent ~~Event”~~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 discussed in“Note 16. Discontinued Operations”and“Note 17. Subsequent Events,”on July 2, 2010 we entered into an agreement to sell our pressure pumping and wireline businesses to Patterson. As a result, we now show the assets being sold as held for sale and the results of operations of the businesses being sold as a discontinued operation for all periods presented. The reclassifications had no effect on total assets or the loss attributable to Key for any period.

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) provide allowances for our uncollectible accounts receivable, (viii) value our asset retirement obligations, and (ix) value our equity-based compensation. We review all significant estimates on a recurring basis and record the effect of any necessary adjustments prior to publication of our financial statements. Adjustments made with respect to the use of estimates relate to improved information not previously available. Because of the limitations inherent in this process, our actual results may differ materially from these estimates. We believe that the estimates used in the preparation of these interim financial statements are reasonable.

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. An approach that is expected to be primarily qualitative will be more effective for identifying which reporting entity has a controlling financial interest in a variable interest 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 did not have a material impact on our financial position, results of operations, or cash flows.

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 guidance. ASU 2009-13 establishes a hierarchy for determining the selling price of a deliverable. The selling price will be based on Vendor-Specific Objective Evidence (“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. Entities may elect, but are not required, to adopt the amendments retrospectively for all periods presented. We expect to adopt the provisions of ASU 2009-13 on January 1, 2011 and do not believe that the adoption of this standard will have a material impact on our financial position, results of operations, or cash flows.

NOTE 3. OTHER BALANCE SHEET INFORMATION

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


	March 31,		December 31,
	2010		2009		June 30, 2010		December 31, 2009
	(in thousands)				(in thousands)
Other Current Assets:
Deferred tax assets	$	23,020	$	25,323	$	27,001	$	25,323
Prepaid current assets		14,005		14,212		10,000		14,212
Income tax refund receivable		5,083		50,025		5,609		50,025
Other		13,938		15,064		15,558		15,064

Total	$	56,046	$	104,624	$	58,168	$	104,624

2010 and December 31, 2009, respectively. ~~As of March 31, 2010, the~~The carrying value of our investment in IROC is ~~$4.9 million~~ less than our proportionate share of the book value of ~~our proportionate share~~the net assets of ~~IROC’s net assets.~~IROC as of June 30, 2010. This difference is ~~due~~attributable to certain long-lived assets of IROC, and ~~this difference~~our proportionate share of IROC’s net income or loss for each period is being ~~amortized~~adjusted over the estimated remaining useful life of ~~these assets as an adjustment to~~those long-lived assets. As of June 30, 2010, the difference between the carrying value of our ~~portion~~investment in IROC and our proportionate share of the book value of IROC’s ~~undistributed earnings each period.~~net assets was $4.7 million.

We recorded ~~no equity income~~$0.2 million and ~~$0.2~~$0.1 million of equity income related to our investment in IROC for the three months ended ~~March 31,~~June 30, 2010 and 2009, ~~respectively. During~~respectively, and $0.2 million and $0.3 million for the ~~quarter ending March 31, 2010, IROC declared and paid a dividend to us of $0.2 million. During the three~~six months ended ~~March 31,~~June 30, 2010 and 2009, ~~the value of our investment in IROC increased by $0.1 million and decreased by $0.1 million, respectively, due to fluctuations in exchange rates.~~respectively.

~~Advanced Flow Technologies, Inc.~~NOTE 6. LONG-TERM DEBT

As of March 31, 2010, we owned 48.63% of Advanced Flow Technologies, Inc. (“AFTI”), a Calgary-based oilfield services company. We recorded less than $0.1 million and $0.1 million of equity losses associated with our investment in AFTI for the three months ended March 31,June 30, 2010 and ~~2009, respectively. In addition, during the three months ended March~~December 31, ~~2010 and~~ 2009, the value of our investment in AFTI increased by less than $0.1 million and decreased by less than $0.1 million, respectively, due to fluctuations in exchange rates between the U.S. dollar and Canadian dollar.


~~NOTE 6.~~		~~LONG-TERM DEBT~~

~~The~~ components of our long-term debt ~~are~~were as follows:


	March 31, 2010			December 31, 2009
	(in thousands)						June 30, 2010			December 31, 2009
							(in thousands)
8.375% Senior Notes due 2014	$	425,000		$	425,000		$	425,000		$	425,000
Senior Secured Credit Facility revolving loans due 2012		87,813			87,813			87,813			87,813
Other long-term indebtedness		511			1,044			—			1,044
Notes payable — related parties, net of discount of $59 and $69, respectively		5,941			5,931
Notes payable — related parties, net of discount of $69								—			5,931
Capital lease obligations		12,263			14,313			10,365			14,313

		531,528			534,101			523,178			534,101

Less current portion		(8,863	)		(10,152	)		(5,714	)		(10,152	)

Total capital leases, notes payable and long-term debt	$	522,665		$	523,949		$	517,464		$	523,949

The Senior Secured Credit Facility contains certain financial covenants, which, among other things, require us to maintain ~~specified~~certain financial ratios, limit our annual capital expenditures, restrict our ability to repurchase shares, and limit the assets owned by domestic subsidiaries that may be located outside the United ~~States, and maintain certain financial ratios.~~States.

The ~~amended~~ Senior Secured Credit Facility also contains certain other covenants, including ~~with certain exceptions,~~ restrictions related to (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; (vi) dividends and other distributions to, and redemptions and repurchases from, equity holders; (vii) prepaying, redeeming or repurchasing the Senior Notes or other unsecured debt incurred; (viii) granting negative pledges other than to the lenders; (ix) changes in the nature of our business; (x) 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; and (xi) changes in accounting policies or reporting ~~practices.~~practices; in each of the foregoing cases, with certain exceptions.

We were in compliance with these covenants on ~~March 31,~~June 30, 2010. We may prepay the Senior Secured Credit Facility in whole or in part at any time without premium or penalty, subject to our obligation to reimburse the lenders for breakage and redeployment costs. As of ~~March 31,~~June 30, 2010, we had borrowings of $87.8 million and committed letters of credit of $55.1 million outstanding, leaving $157.1 million of available borrowing capacity under the Senior Secured Credit Facility. The weighted average interest rate on the outstanding borrowings under the Senior Secured Credit Facility at ~~March 31,~~June 30, 2010 was ~~3.73%~~4.85%.

NOTE 7. 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, net” for the periods indicated:

Three Months Ended March 31,
2010 2009
(in thousands)

Loss on disposal of assets, net $ 335 $ 689
Interest income (15 ) (248 )
Foreign exchange (gain) loss (1,363 ) 917
Other income, net (210 ) (835 )

Total $ (1,253 ) $ 523


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in thousands)
Loss (gain) on disposal of assets, net	$	320		$	(1,381	)	$	655		$	(1,376	)
Interest income		(21	)		(169	)		(36	)		(417	)
Foreign exchange loss (gain)		855			(865	)		(509	)		(53	)
Other (income) expense, net		(687	)		354			(886	)		(376	)

Total	$	467		$	(2,061	)	$	(776	)	$	(2,222	)

NOTE 8. INCOME TAXES

~~We are subject to U.S. federal income tax as well as income taxes in multiple state and foreign jurisdictions.~~ Our effective tax rates for the three months ended ~~March 31,~~June 30, 2010 and 2009 were ~~41.9%~~34.8% and ~~19.9%~~36.9%, respectively. Our effective tax ~~rate varies~~rates for the six months ended June 30, 2010 and 2009 were 38.3% and 38.0%, respectively. The variance quarter over quarter is 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, mainly due to tax expense or benefits recognized for uncertain tax positions. The variance between ~~our~~the second quarter 2010 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, including the revised Texas Franchise Tax.

As of ~~March 31,~~June 30, 2010 and December 31, 2009, we had ~~$3.3~~$3.4 million and $3.2 million, respectively, of unrecognized tax benefits, net of federal tax benefit, which, if recognized, would impact our effective tax rate. We recognized tax expense of $0.1 million in ~~each of~~ the ~~quarters~~quarter ended ~~March 31,~~June 30, 2010 and ~~March 31, 2009, and we recognized~~ a tax benefit of ~~$0.7~~$0.1 million ~~due to statute of limitations expirations~~ for the quarter ended ~~March 31, 2009.~~June 30, 2009 related to these items. We are subject to U.S. Federal Income Tax as well as income taxes in multiple state and foreign jurisdictions. We have substantially concluded all U.S. federal and state tax matters through the year ended December 31, 2006.

We record expense and penalties related to unrecognized tax benefits as income tax expense. We have accrued a liability of $1.2 million and $1.1 million for the payment of interest and penalties as of ~~March 31,~~June 30, 2010 and December 31, 2009, respectively. We believe that it is reasonably possible that $1.7 million of our currently remaining unrecognized tax positions, each of which are individually insignificant, may be recognized in the next twelve months as a result of a lapse of statute of limitations and settlement of ongoing audits. ~~No release of~~We recorded a $2.1 million increase to our deferred tax asset valuation allowance ~~was made~~related to net operating loss carryforwards in Argentina during the ~~quarter~~six months ended ~~March 31,~~June 30, 2010.

During the quarter ended March 31, 2010, we filed our 2009 tax return reflecting a net operating loss ~~(“NOL”)~~ of $153.5 million. We ~~subsequently~~also filed ~~Form 1139 to carry the NOL back to prior years to offset the taxable income reported and claimed~~ a claim for refund of federal income taxes paid in ~~those~~ prior ~~years. On~~years and on March 31, 2010, we received remittances from the Internal Revenue Service totaling $53.2 million.

NOTE 9. COMMITMENTS AND CONTINGENCIES

Litigation

Various suits and claims arising in the ordinary course of business are pending against us. Due in part to the locations where we conduct business in the continental United States, we are often subject to jury verdicts and arbitration hearings that result in outcomes in favor of the plaintiffs. We continually assess our contingent liabilities, including potential litigation liabilities, as well as the adequacy of our accruals and our need for the disclosure of these items. We establish a provision for a contingent liability when it is probable that a liability has been incurred and the amount is reasonably estimable. As of ~~March 31,~~June 30, 2010, the aggregate amount of our liabilities related to litigation that are deemed probable and reasonably estimable is ~~$1.7~~$2.0 million. We do not believe that the disposition of any of these matters will result in an additional loss materially in excess of amounts that have been recorded. During the ~~first~~second quarter of 2010, ~~we recorded a net decrease~~there were no changes in our ~~liability of $1.0 million~~reserves related to the settlement ~~and revision~~ of ~~our exposures related to~~ ongoing legal matters. ~~See also~~~~“Note 16. Subsequent Event”.~~

Litigation with Former Officers and Employees

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 alleges 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. 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 are seeking 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. The case is currently pending in the U.S. District Court for the Eastern District of Pennsylvania and ~~will begin to appear on~~trial is scheduled for the ~~trial docket during the second~~fourth quarter of 2010. We recorded a liability for this matter in the fourth quarter of 2008.

UMMA Verdict

On May 3, 2010, a jury returned a verdict in the case ofUMMA 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 counter sued 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 counter claims. 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 June 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 expect to receive the court’s judgment during the third 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 ~~March 31,~~June 30, 2010 and December 31, 2009, we have recorded ~~$65.5~~$66.7 and $65.2 million, respectively, of self-insurance reserves related to workers’ compensation, vehicular liabilities and general liability claims. Partially offsetting these liabilities, we had ~~$17.2~~$17.8 million of insurance receivables as of ~~both March 31,~~June 30, 2010 and $17.2 million as of December 31, 2009. We feel 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.

NOTE 10. EARNINGS PER SHARE

Basic earnings per common share is determined by dividing net earnings applicable to common stock 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 March 31,
2010 2009
(in thousands, except per share data)
Basic EPS Computation:

Numerator

Net (loss) income attributable to Key $ (7,580 ) $ 904
Denominator

Weighted average shares outstanding 124,952 120,665

Basic (loss) earnings per share $ (0.06 ) $ 0.01

Diluted EPS Computation:

Numerator

Net (loss) income attributable to Key $ (7,580 ) $ 904
Denominator

Basic weighted average shares outstanding 124,952 120,665
Stock options — 24
Unvested restricted stock — 747

Diluted weighted average shares outstanding 124,952 121,436

Diluted (loss) earnings per share $ (0.06 ) $ 0.01


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in thousands, except per share amounts)
Basic EPS Calculation:
Loss from continuing operations attributable to Key	$	(10,418	)	$	(16,024	)	$	(19,893	)	$	(13,811	)
Loss from discontinued operations, net of tax		8,182			(2,449	)		10,077			(3,758	)

Loss attributable to Key	$	(2,236	)	$	(18,473	)	$	(9,816	)	$	(17,569	)


Denominator
Weighted average shares outstanding		125,412			120,963			125,183			120,815

Basic loss per share from continuing operations attributable to Key	$	(0.08	)	$	(0.13	)	$	(0.16	)	$	(0.12	)
Basic earnings (loss) per share from discontinued operations		0.06			(0.02	)		0.08			(0.03	)

Basic loss per share attributable to Key	$	(0.02	)	$	(0.15	)	$	(0.08	)	$	(0.15	)


Diluted EPS Calculation:
Loss from continuing operations attributable to Key	$	(10,418	)	$	(16,024	)	$	(19,893	)	$	(13,811	)
Loss from discontinued operations, net of tax		8,182			(2,449	)		10,077			(3,758	)

Loss attributable to Key	$	(2,236	)	$	(18,473	)	$	(9,816	)	$	(17,569	)


Denominator
Weighted average shares outstanding		125,412			120,963			125,183			120,815

Diluted loss per share from continuing operations attributable to Key	$	(0.08	)	$	(0.13	)	$	(0.16	)	$	(0.12	)
Diluted earnings (loss) per share from discontinued operations		0.06			(0.02	)		0.08			(0.03	)

Diluted loss per share attributable to Key	$	(0.02	)	$	(0.15	)	$	(0.08	)	$	(0.15	)

Because of our net loss for the three and six months ended ~~March 31,~~June 30, 2010 and 2009, all potentially dilutive securities were excluded from the calculation of our diluted earnings per share, as the potential exercise of those securities would be anti-dilutive. ~~The diluted earnings per share calculation for~~On July 23, 2010 we entered into an agreement to purchase subsidiaries and related assets of OFS ES. Upon the ~~three months ended March 31, 2009 excludes the potential exercise~~closing of ~~4.5~~this transaction, we will issue approximately 15.8 million ~~stock options and 0.6 million stock appreciation rights (“SARs”) because the effects~~shares of ~~such exercises on the earnings per share calculation would be anti-dilutive. These awards would be anti-dilutive because their exercise prices exceeded the average price for~~ our common stock ~~during~~(the “Consideration Shares”) as part of the ~~period. There were no events occurring after March 31, 2010~~total purchase price. We anticipate that ~~would materially affect~~ the ~~number of~~Consideration Shares will impact our basic and diluted weighted average shares ~~outstanding.~~outstanding beginning in the third quarter of 2010. See“Note 17. Subsequent Events”for further discussion.

NOTE 11. SHARE-BASED COMPENSATION

We recognized employee share-based compensation expense of ~~$3.1~~$3.4 million and ~~$0.3~~$2.6 million during the three months ended ~~March 31,~~June 30, 2010 and 2009, respectively. The related income tax benefit recognized for employee share-based compensation was ~~$1.3~~$1.2 million and ~~$0.1~~$0.9 million for the three months ended ~~March 31,~~June 30, 2010 and 2009, respectively. We recognized employee share-based compensation expense of $6.5 million and $2.9 million for the six months ended June 30, 2010 and 2009, respectively. The related income tax benefit recognized for employee share-based compensation was $2.6 million and $1.0 million for the six months ended June 30, 2010 and 2009, respectively. We did not capitalize any share-based compensation during the three or six month periods ended ~~March 31,~~June 30, 2010 and 2009.

During January 2010, we issued a total of 1.5 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~~The closing price of our common stock was $9.93 per ~~share.~~share on the date of grant. The unrecognized compensation cost related to our unvested stock options, restricted shares and phantom shares as of ~~March 31,~~June 30, 2010 is estimated to be $0.1 million, ~~$18.0~~$19.4 million and $0.9 million, respectively, and is expected to be recognized over a weighted-average period of ~~1.7~~1.5 years, ~~1.6~~1.4 years and ~~1.0~~0.7 years, respectively.

During March 2010, we issued a total of 0.6 million performance units 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~~with 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 ~~subject to that performance period~~ will vest; if we are in the middle third, 50% ~~subject to that performance period~~ will vest; and if we are in the bottom third, the performance units ~~subject to that performance period~~ 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 equal 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. As of ~~March 31,~~June 30, 2010, the fair value of the performance units was ~~$3.5~~$2.8 million, and is being accreted to compensation expense over the vesting terms of the awards. During the three and six months ended ~~March 31,~~June 30, 2010, we recognized ~~$0.2~~$0.5 million and $0.7 million, respectively, of pre-tax compensation expense associated with these awards.

During May 2010, we issued 109,410 shares of common stock to our outside directors. These shares vested immediately and we recognized $1.0 million of expense related to these awards.

NOTE 12. TRANSACTIONS WITH RELATED PARTIES

~~Employee Loans and Advances~~

From time to time, we have made certain retention loans and relocation loans to employees other than executive officers. The retention loans are written off over various time periods, so long as the employees continue employment with us. The relocation loans are repaid upon the employees selling their prior residence. As of March 31, 2010, these loans, in the aggregate, totaled less than $0.1 million.

Related Party Notes Payable

On October 25, 2007, we entered into two promissory notes with related parties in connection with an acquisition. The first was an unsecured note in the amount of $12.5 million and has been repaid, together with accrued interest. The second unsecured note in the amount of $10.0 million iswas payable in annual installments of $2.0 million, plus accrued interest, on each anniversary date of its issue through October 2012. ~~The~~On May 13, 2010, we repaid the outstanding principal balance of $6.0 million of the remaining note, ~~bears interest at~~plus accrued and unpaid interest. This note was repaid concurrently with the ~~Federal Funds Rate, adjusted annually~~sale of six operational barge rigs and related assets 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 ~~anniversary date~~sale of the note. As of March 31, 2010, the carrying amount of the second note was $5.9 million and the interest rate was 0.11%. Interest expense for the quarter ended March 31, 2010 was less than $0.1 million.these assets.

Transactions with Employees

In connection with an acquisition in 2008, the former owner of the acquiree became one of our employees. At the time of the acquisition, the employee owned, and continues to own, an exploration and production company. Subsequent to the acquisition, we continued to provide services to this company. The prices charged for these services are at rates that are an average of the prices charged to our other customers in the California ~~market.~~market where the services are provided. As of ~~March 31,~~June 30, 2010, our receivables with this company totaled ~~$0.2~~$0.4 million.

Board of Director Relationship with Customer

One 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 ~~2.2%~~3% of our total revenues for the ~~quarter~~six months ended ~~March 31,~~June 30, 2010. Transactions with Anadarko for our services are made on terms consistent with other customers.

NOTE 13. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS ~~AND FAIR VALUE MEASUREMENTS~~

The following is a summary of the carrying amounts and estimated fair values of our financial instruments as of ~~March 31,~~June 30, 2010 and December 31, ~~2009.~~2009:

Cash, cash equivalents, accounts payable and accrued liabilities.These carrying amounts approximate fair value because of the short maturity of the instruments or because the carrying value is equal to the fair value of those instruments on the balance sheet date.


	March 31, 2010				December 31, 2009
	Carrying Value		Fair Value		Carrying Value		Fair Value		June 30, 2010				December 31, 2009
	(in thousands)								Carrying Value		Fair Value		Carrying Value		Fair Value
									(in thousands)
Financial assets:
Notes and accounts receivable — related parties	$	350	$	350	$	281	$	281	$	187	$	187	$	281	$	281

Financial liabilities:
8.375% Senior Notes	$	425,000	$	435,625	$	425,000	$	422,875	$	425,000	$	422,344	$	425,000	$	422,875
Senior Secured Credit Facility revolving loans		87,813		87,813		87,813		87,813		87,813		87,813		87,813		87,813
Note payable — related parties		5,941		5,941		5,931		5,931		—		—		5,931		5,931

Notes and accounts receivable — related parties.The amounts reported relate to notes receivable from certain of our employees related to relocation and retention agreements, and certain trade accounts receivable with affiliates. The carrying values of these items approximate their fair values as of the applicable balance sheet dates.

8.375% Senior Notes due 2014.The fair value of our Senior Notes is based upon the quoted market prices for those securities as of the dates indicated. The carrying value of these notes as of ~~March 31,~~June 30, 2010 was $425.0 million and the fair value was ~~$435.6~~$422.3 million ~~(102.5%~~(99.375% of carrying value).

Senior Secured Credit Facility Revolving Loans.Because of their variable interest rates and the amendment of the Senior Secured Credit Facility during the fourth quarter of 2009, the fair values of the revolving loans borrowed under our Senior Secured Credit Facility approximate their carrying values. The carrying and fair values of these loans as of ~~March 31,~~June 30, 2010 were $87.8 million.

Note payable — related parties.The amounts reported relate to a seller financing arrangement entered into in connection with an acquisition made in 2007. ~~Because~~The outstanding balance of ~~their variable interest rates and the discount applied to the~~this note ~~the carrying value of the note approximates its fair value as of March 31,~~was repaid on May 13, 2010.

As of March 31, 2010, the carrying value of our Asset Retirement Obligations (“AROs”) were measured at fair value using primarily Level 3 inputs. In the fair value hierarchy, a Level 3 fair value measurement is defined as one that has significant unobservable inputs. The significant unobservable inputs used in the fair value measurement of our AROs include management’s estimates of the future cash flows required to settle the ARO, expected behavior of inflation rates over the life of the associated ARO asset, and the credit-adjusted risk free rate used to discount the liability at inception of the ARO. As of March 31, 2010 and December 31, 2009, the carrying and fair values of our AROs were $10.2 million and $10.0 million, respectively, and are recorded as a component of Other Non-Current Liabilities in our consolidated balance sheets. Other than accretion expense associated with these liabilities, no adjustments were made to the fair value measurements of our AROs during the three months ended March 31, 2010.

NOTE 14. SEGMENT INFORMATION

We operate in two business segments, Well Servicing and Production Services. Our rig services and fluid management services are aggregated within our Well Servicing segment. Our pressure pumping services, fishing and rental services, and wireline services, as well as our technology development group in Canada, are aggregated within our Production Services segment. The accounting policies for our segments are the same as those described in“Note 1. Organization and Summary of Significant Accounting Policies”included in our Annual Report on Form 10-K for the year ended December 31, 2009. All inter-segment sales pricing is based on current market conditions. The following is a description of our segments:

Well Servicing Segment

Rig-Based Services

Our rig-based services include the maintenance, workover, and recompletion of existing oil and gas wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives. We also provide drilling services to oil and natural gas producers with certain of our larger ~~well servicing~~Well Servicing rigs that are capable of providing conventional and/or horizontal drilling services. Based on current industry data, we have the largest land-based ~~well servicing~~Well Servicing rig fleet in the world. Our rigs consist of various sizes and capabilities, allowing us to work on all types of wells with depths up to 20,000 feet. Many of our rigs are outfitted with our proprietary KeyView^® technology, which captures and

reports well site operating data. We believe that this technology allows our customers and our crews to better monitor well site operations, to improve efficiency and safety, and to add value to the services that we offer.

The maintenance services provided by our rig fleet are generally required throughout the life cycle of an oil or gas well to ensure efficient and continuous production. Examples of the maintenance services provided by our rigs include routine mechanical repairs to the pumps, tubing and other equipment onin a well, removing debris from the ~~well bore,~~wellbore, and pulling the rods and other downhole equipment out of the ~~well bore~~wellbore to identify and resolve a production problem. Maintenance services generally take less than 48 hours to ~~complete.~~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.

The workover services provided by our rig fleet are performed 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 ~~well bores~~wellbores into new formations by drilling horizontal or lateral ~~well bores,~~wellbore sections, 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 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 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 gas well that is at the end of its productive life. These plugging and abandonment services also generally require auxiliary equipment in addition to a 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 fleet of 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 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 ~~well bore.~~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 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 aan SWD well that is either owned by us or a third party.

Production Services Segment

Pressure Pumping Services

Our pressure pumping services include fracturing, nitrogen, acidizing, cementing and coiled tubing services. These services (which may be utilized during the completion or workover of a well) are provided to oil and natural gas producers and are used to enhance the production of oil and natural gas ~~wells~~ from formations which exhibit restricted ~~flow of oil and natural gas.~~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 ~~well bore.~~wellbore. 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 ~~well bore~~wellbore clean-outs, nitrogen jet lifts, and 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, including “stiff wireline” services, in which a wireline is placed in the coiled tube and then fed into a well to carry the wireline to a desired depth. On July 2, 2010, we entered into an agreement to sell our pressure pumping business to Patterson. We now show these assets as held for sale and the results of operations for pressure pumping as a discontinued operation for all periods presented. See“Note 16. Discontinued Operations”and“Note 17. Subsequent Events.”Our coiled tubing operations and pressure pumping operations in California were not sold as part of this transaction, and are still reported in the Production Services segment.

Fishing and Rental Services

We offer a full line of services and rental equipment designed for use both onshore and offshore for drilling and workover services. Fishing services involve recovering lost or stuck equipment in the ~~well bore~~wellbore utilizing a broad array of “fishing ~~tool.~~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

We have a fleet of wireline units that perform services at various times throughout the life of the well including perforating, completion logging, production logging and casing integrity services. After the ~~well bore~~wellbore is cased and cemented, we can provide a number of services. Perforating creates the flow path between the reservoir and the ~~well bore.~~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.

In addition, wireline services may involve ~~well bore~~wellbore remediation, which could include the positioning and installation of various plugs and packers to maintain production or repair well problems, and casing inspection for internal or external abnormalities in the casing string. Wireline services are provided from surface logging units, which lower tools and sensors into the ~~well bore.~~wellbore. We use advanced wireline instruments to evaluate well integrity and perform cement evaluations and production logging. On July 2, 2010, we entered into an agreement to sell our wireline business to Patterson. We now show these assets as held for sale and the results of operations for our wireline business as a discontinued operation for all periods presented. See“Note 16. Discontinued Operations”and“Note 17. Subsequent Events.”

Functional Support Segment

We have aggregated all of 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 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 six month periods ended ~~March 31,~~June 30, 2010 and 2009:

Production Functional Reconciling
Well Servicing Services Support Eliminations Total
(in thousands)
As of and for the three months ended March 31, 2010:

Revenues from external customers $ 223,991 $ 78,080 $ — $ — $ 302,071
Intersegment revenues 21 906 — (927 ) —
Depreciation and amortization 25,782 8,641 2,280 — 36,703
Operating income (loss) 15,011 2,586 (24,101 ) — (6,504 )
Interest expense, net of amounts capitalized (629 ) (6 ) 10,882 — 10,247
Income (loss) before taxes 16,643 2,687 (34,828 ) — (15,498 )

Total assets 1,234,944 265,119 633,187 (450,158 ) 1,683,092
Capital expenditures, excluding acquisitions 19,500 7,321 5,594 — 32,415

Production Functional Reconciling
Well Servicing Services Support Eliminations Total
(in thousands)
As of and for the three months ended March 31, 2009:

Revenues from external customers
$ 256,261 $ 75,728 $ — $ — $ 331,989
Intersegment revenues 7 1,481 — (1,488 ) —
Depreciation and amortization 30,779 11,651 2,326 — 44,756
Operating income (loss) 41,015 (3,560 ) (26,155 ) — 11,300
Interest expense, net of amounts capitalized (556 ) (618 ) 10,822 — 9,648
Income (loss) before taxes 41,414 (3,851 ) (36,434 ) — 1,129

Total assets 1,579,905 368,854 2,125,948 (2,096,060 ) 1,978,647
Capital expenditures, excluding acquisitions 24,200 17,789 2,808 — 44,797

2018

As of and for the three months ended June 30, 2010:


				Production			Functional			Reconciling
	Well Servicing			Services			Support			Eliminations			Total
	(in thousands)
Revenues from external customers	$	232,746		$	35,039		$	—		$	—		$	267,785
Intersegment revenues		130			2,127			—			(2,257	)		—
Depreciation and amortization		24,605			5,552			2,321			—			32,478
Operating income (loss)		16,523			6,338			(28,591	)		—			(5,730	)
Interest expense, net of amounts capitalized		(195	)		(71	)		10,995			—			10,729
Income (loss) from continuing operations before tax		15,925			5,929			(38,780	)		—			(16,926	)

Total assets		1,316,698			307,601			248,973			(191,436	)		1,681,836
Capital expenditures, excluding acquisitions		11,722			15,688			8,098			—			35,508

As of and for the three months ended June 30, 2009:


				Production			Functional			Reconciling
	Well Servicing			Services			Support			Eliminations			Total
	(in thousands)
Revenues from external customers	$	197,945		$	21,116		$	—		$	—		$	219,061
Intersegment revenues		6			928			—			(934	)		—
Depreciation and amortization		28,474			6,658			2,049			—			37,181
Operating income (loss)		15,522			(5,166	)		(27,633	)		—			(17,277	)
Interest expense, net of amounts capitalized		(331	)		8			10,496			—			10,173
Income (loss) from continuing operations before tax		16,858			(4,193	)		(38,054	)		—			(25,389	)

Total assets		1,255,987			347,567			600,086			(397,728	)		1,805,912
Capital expenditures, excluding acquisitions		8,384			11,038			3,190			—			22,612

As of and for the six months ended June 30, 2010:


				Production			Functional			Reconciling
	Well Servicing			Services			Support			Eliminations			Total
	(in thousands)
Revenues from external customers	$	456,737		$	63,007		$	—		$	—		$	519,744
Intersegment revenues		151			2,991			—			(3,142	)		—
Depreciation and amortization		50,386			10,814			4,602			—			65,802
Operating income (loss)		31,534			5,834			(52,692	)		—			(15,324	)
Interest expense, net of amounts capitalized		(824	)		(66	)		21,878			—			20,988
Income (loss) from continuing operations before tax		32,567			5,453			(73,556	)		—			(35,536	)

Total assets		1,316,698			307,601			248,973			(191,436	)		1,681,836
Capital expenditures, excluding acquisitions		31,222			23,009			13,692			—			67,923

As of and for the six months ended June 30, 2009:


				Production			Functional			Reconciling
	Well Servicing			Services			Support			Eliminations			Total
	(in thousands)
Revenues from external customers	$	454,206		$	48,504		$	—		$	—		$	502,710
Intersegment revenues		6			1,750			—			(1,756	)		—
Depreciation and amortization		59,253			12,377			4,375			—			76,005
Operating income (loss)		56,537			(7,156	)		(53,788	)		—			(4,407	)
Interest expense, net of amounts capitalized		(887	)		(328	)		21,318			—			20,103
Income (loss) from continuing operations before tax		58,272			(6,072	)		(74,488	)		—			(22,288	)

Total assets		1,255,987			347,567			600,086			(397,728	)		1,805,912
Capital expenditures, excluding acquisitions		32,584			28,827			5,998			—			67,409

The following ~~tables present~~table presents information related to our operations on a geographical basis as of and for the three and six month periods ended ~~March 31,~~June 30, 2010 and 2009:

CONDENSED CONSOLIDATING BALANCE SHEETS


													June 30, 2010
	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)
Assets:
Current assets	$	24,837	$	252,038	$	129,339		$	157		$	406,371	$	29,648	$	274,256	$	115,042		$	—		$	418,946
Property and equipment, net		—		817,685		44,965			—			862,650		—		736,460		45,517			—			781,977
Goodwill		—		316,514		30,317			—			346,831		—		320,264		28,843			—			349,107
Deferred financing costs, net		9,768		—		—			—			9,768		9,114		—		—			—			9,114
Intercompany notes and accounts receivable and investment in subsidiaries		1,840,365		584,570		7,300			(2,432,235	)		—		1,846,987		611,894		7,476			(2,466,357	)		—
Other assets		4,763		38,224		14,485			—			57,472		4,896		37,444		13,088			—			55,428
Noncurrent assets held for sale														—		67,264		—			—			67,264


TOTAL ASSETS	$	1,879,733	$	2,009,031	$	226,406		$	(2,432,078	)	$	1,683,092	$	1,890,645	$	2,047,582	$	209,966		$	(2,466,357	)	$	1,681,836


Liabilities and equity:
Current liabilities	$	15,560	$	147,990	$	51,738		$	—		$	215,288	$	7,465	$	161,027	$	57,153		$	—		$	225,645
Long-term debt and capital leases, less current portion		512,812		9,826		27			—			522,665		512,813		4,635		16			—			517,464
Intercompany notes and accounts payable		459,188		1,543,173		92,851			(2,095,212	)		—		479,039		1,547,452		97,220			(2,123,711	)		—
Deferred tax liabilities		151,624		—		(5,127	)		—			146,497		150,552		—		(6,954	)		—			143,598
Other long-term liabilities		3,140		58,093		—			—			61,233		2,551		54,353		—			—			56,904
Stockholders’ and members’ equity		737,409		249,949		86,917			(336,866	)		737,409
Equity														738,225		280,115		62,531			(342,646	)		738,225


TOTAL LIABILITIES AND EQUITY	$	1,879,733	$	2,009,031	$	226,406		$	(2,432,078	)	$	1,683,092	$	1,890,645	$	2,047,582	$	209,966		$	(2,466,357	)	$	1,681,836

CONDENSED CONSOLIDATING UNAUDITED STATEMENTS OF OPERATIONS


																Three Months Ended June 30, 2010
	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)
Revenues	$	—		$	261,306		$	56,011		$	(15,246	)	$	302,071		$	—		$	236,978		$	44,515		$	(13,708	)	$	267,785

Costs and expenses:
Direct operating expenses		—			187,065			55,136			(11,281	)		230,920
Direct operating expense																	—			150,956			55,651			(10,436	)		196,171
Depreciation and amortization expense		—			34,340			2,363			—			36,703			—			30,134			2,344			—			32,478
General and administrative expenses		1,228			35,667			5,239			(1,182	)		40,952
General and administrative expense																	65			39,428			6,065			(692	)		44,866
Interest expense, net of amounts capitalized		11,187			(901	)		(39	)		—			10,247			11,486			(821	)		64			—			10,729
Other, net		(697	)		676			2,482			(3,714	)		(1,253	)		(266	)		(130	)		3,442			(2,579	)		467

Total costs and expenses, net		11,718			256,847			65,181			(16,177	)		317,569			11,285			219,567			67,566			(13,707	)		284,711

(Loss) income from continuing operations before tax																	(11,285	)		17,411			(23,051	)		(1	)		(16,926	)
Income tax benefit																	5,186			—			702			—			5,888

(Loss) income before taxes		(11,718	)		4,459			(9,170	)		931			(15,498	)
Income tax benefit (expense)		6,089			—			402						6,491

(Loss) income from continuing operations																	(6,099	)		17,411			(22,349	)		(1	)		(11,038	)
Discontinued operations																	—			8,182			—			—			8,182
Net (loss) income		(5,629	)		4,459			(8,768	)		931			(9,007	)		(6,099	)		17,411			(21,729	)		(1	)		(10,418	)

Net loss attributable to noncontrolling interest		—			—			1,427						1,427

Loss attributable to noncontrolling interest																	—			—			620			—			620

(LOSS) INCOME ATTRIBUTABLE TO KEY	$	(5,629	)	$	4,459		$	(7,341	)	$	931		$	(7,580	)	$	(6,099	)	$	25,593		$	(21,729	)	$	(1	)	$	(2,236	)


	Six Months Ended June 30, 2010
				Guarantor			Non-Guarantor
	Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
	(unaudited)
Revenues	$	—		$	448,172		$	100,526		$	(28,954	)	$	519,744

Costs and expenses:
Direct operating expense		—			296,303			110,787			(21,717	)		385,373
Depreciation and amortization expense		—			61,095			4,707			—			65,802
General and administrative expense		1,293			73,170			11,304			(1,874	)		83,893
Interest expense, net of amounts capitalized		22,673			(1,710	)		25			—			20,988
Other, net		(963	)		556			5,924			(6,293	)		(776	)

Total costs and expenses, net		23,003			429,414			132,747			(29,884	)		555,280

(Loss) income from continuing operations before tax		(23,003	)		18,758			(32,221	)		930			(35,536	)
Income tax benefit		12,492			—			1,104			—			13,596

(Loss) income from continuing operations		(10,511	)		18,758			(31,117	)		930			(21,940	)
Discontinued operations, net of tax		—			10,077			—			—			10,077

Net (loss) income		(10,511	)		18,758			(29,070	)		930			(19,893	)

Loss attributable to noncontrolling interest		—			—			2,047			—			2,047

(LOSS) INCOME ATTRIBUTABLE TO KEY	$	(10,511	)	$	28,835		$	(29,070	)	$	930		$	(9,816	)


	Six Months Ended June 30, 2009
				Guarantor			Non-Guarantor
	Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
	(unaudited)
Revenues	$	—		$	431,643		$	93,560		$	(22,493	)	$	502,710

Costs and expenses:
Direct operating expense		—			287,375			68,950			(15,678	)		340,647
Depreciation and amortization expense		—			73,004			3,001			—			76,005
General and administrative expense		949			80,618			8,869			29			90,465
Interest expense, net of amounts capitalized		21,460			(1,411	)		54			—			20,103
Other, net		386			(2,640	)		5,369			(5,337	)		(2,222	)

Total costs and expenses, net		22,795			436,946			86,243			(20,986	)		524,998

(Loss) income from continuing operations before tax		(22,795	)		(5,303	)		7,317			(1,507	)		(22,288	)
Income tax benefit (expense)		11,715			—			(3,238	)		—			8,477

(Loss) income from continuing operations		(9,124	)		(7,259	)		4,079			(1,507	)		(13,811	)
Discontinued operations, net of tax		—			(3,758	)		—			—			(3,758	)

(LOSS) INCOME ATTRIBUTABLE TO KEY	$	(9,124	)	$	(11,017	)	$	4,079		$	(1,507	)	$	(17,569	)

CONDENSED CONSOLIDATING UNAUDITED STATEMENTS OF CASH FLOWS


	Three Months Ended March 31, 2010															Six Months Ended June 30, 2010
	Parent			Guarantor			Non-Guarantor												Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated			Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)															(in thousands)
																(unaudited)
Net cash provided by operating activities	$	—		$	57,629		$	8,125		$	—		$	65,754
Net cash provided by (used in) operating activities																$	—		$	66,432		$	(1,737	)	$	—		$	64,695

Cash flows from investing activities:
Capital expenditures		—			(27,493	)		(4,922	)		—			(32,415	)		—			(61,448	)		(6,475	)		—			(67,923	)
Intercompany notes and accounts		(165	)		(580	)		—			745			—			(165	)		(2,094	)		—			2,259			—
Other investing activities, net		165			1,006			—			—			1,171			165			20,073			—			—			20,238


Net cash (used in) provided by investing activities		—			(27,067	)		(4,922	)		745			(31,244	)		—			(43,469	)		(6,475	)		2,259			(47,685	)


Cash flows from financing activities:
Repayments on long-term debt		—			(2,590	)		—			—			(2,590	)
Repayments of long-term debt																	—			(6,970	)		—			—			(6,970	)
Repurchases of common stock		(2,180	)		—			—			—			(2,180	)		(2,357	)		—			—			—			(2,357	)
Intercompany notes and accounts		580			165			—			(745	)		—			2,094			165			—			(2,259	)		—
Other financing activities, net		1,600			—			—			—			1,600			263			—			—			—			263


Net cash used in financing activities		—			(2,425	)		—			(745	)		(3,170	)		—			(6,805	)		—			(2,259	)		(9,064	)


Effect of changes in exchange rates on cash		—			—			(1,920	)		—			(1,920	)		—			—			1,700			—			1,700


Net increase in cash and cash equivalents		—			28,137			1,283			—			29,420
Net increase (decrease) in cash																	—			16,158			(6,512	)		—			9,646


Cash and cash equivalents at beginning of period		—			19,391			18,003			—			37,394			—			19,391			18,003			—			37,394


Cash and cash equivalents at end of period	$	—		$	47,528		$	19,286		$	—		$	66,814		$	—		$	35,549		$	11,491		$	—		$	47,040


	Six Months Ended June 30, 2009
				Guarantor			Non-Guarantor
	Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
	(unaudited)
Net cash (used in) provided by operating activities	$	—		$	152,221		$	5,078		$	—		$	157,299

Cash flows from investing activities:
Capital expenditures		—			(65,717	)		(1,692	)		—			(67,409	)
Intercompany notes and accounts		98,624			15,187			9,981			(123,792	)		—
Other investing activities, net		199			3,818			—			—			4,017


Net cash (used in) provided by investing activities		98,823			(46,712	)		8,289			(123,792	)		(63,392	)


Cash flows from financing activities:
Repayment of long-term debt		(100,000	)		—			—			—			(100,000	)
Repurchases of common stock		(113	)		—			—			—			(113	)
Intercompany notes and accounts		113			(108,605	)		(15,300	)		123,792			—
Other financing activities, net		1,177			(7,133	)		—			—			(5,956	)


Net cash provided by (used in) financing activities		(98,823	)		(115,738	)		(15,300	)		123,792			(106,069	)


Effect of changes in exchange rates on cash		—			—			(890	)		—			(890	)


Net (decrease) increase in cash		—			(10,229	)		(2,823	)		—			(13,052	)


Cash and cash equivalents at beginning of period		—			75,848			16,843			—			92,691


Cash and cash equivalents at end of period	$	—		$	65,619		$	14,020		$	—		$	79,639

NOTE 16. DISCONTINUED OPERATIONS

As discussed in“Note 17. Subsequent Events,”on July 2, 2010 we reached an agreement with Patterson to sell our pressure pumping and wireline businesses. Management determined to sell these businesses because they were not aligned with our core business strategy of well intervention and international expansion. As a result of this plan to sell these businesses, we now present the assets being sold as assets held for sale in our consolidated balance sheets and the results of operations related to these businesses as discontinued operations for all periods presented. Prior to the sale, the businesses sold to Patterson were reported as part of our Production Services segment and are based entirely in the U.S. Because the agreed-upon purchase price for the businesses exceeds the carrying value of the assets being sold, we did not record a write-down on these assets on the date that they became classified as held for sale. The following tables present more detailed information about the assets held for sale as well as the results of operations for the businesses being sold in connection with this transaction:


				December
	June 30, 2010			31, 2009
	(in thousands)
Inventory	$	7,631		$	3,974

Current assets held for sale		7,631			3,974

Property and equipment, gross		83,416			80,456
Accumulated depreciation		(16,152	)		(10,117	)

Noncurrent assets held for sale, net		67,264			70,339


Net assets held for sale	$	74,895		$	74,313


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
				(in thousands)
Revenues	$	71,244		$	22,397		$	121,356		$	70,737
Costs and expenses:
Direct operating expenses		53,540			18,735			95,258			60,433
Depreciation and amortization		3,379			6,010			6,758			11,942
General and administrative expenses		1,996			1,356			3,921			3,636
Other (income) expense, net		(165	)		38			(187	)		440

Total costs and expenses, net		58,750			26,139			105,750			76,451
Income (loss) before tax		12,494			(3,742	)		15,606			(5,714	)
Income tax (expense) benefit		(4,312	)		1,293			(5,529	)		1,956

Income (loss) from discontinued operations	$	8,182		$	(2,449	)	$	10,077		$	(3,758	)

NOTE ~~16.~~17. SUBSEQUENT ~~EVENT~~EVENTS

Sale of Pressure Pumping and Wireline Businesses

On ~~May 3,~~July 2, 2010, we reached an agreement with Patterson whereby we will sell our pressure pumping and wireline businesses to Patterson for total consideration of approximately $256.7 million, comprised of a ~~jury returned a verdict~~cash payment at closing of $237.7 million and our retention of working capital associated with the businesses (subject to certain adjustments based on closing inventory and the value of certain owned properties that we may retain).

The closing of the transaction is subject to customary closing conditions. We received notification that the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 terminated effective July 27, 2010. We anticipate that closing of this transaction will occur in the ~~case~~third quarter of ~~UMMA Resources, LLC v. Key Energy Services, Inc. The lawsuit involved pipe recovery~~2010. These assets are classified as held for sale in our consolidated balance sheets and ~~workover~~the results of operations performed between September 2003 through December 2004. The plaintiff alleged that we breached the oral contract and negligently performed the work. We counter sued 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 counter claims. We believe that,have been classified as a matter of law, the jury erred in its decision. The judge in this case has delayed rendering his judgment and has requested both parties to file motions on the jury’s verdict. 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 determined at this time. As of March 31,discontinued operation for all periods presented.

Acquisition

On July 23, 2010, we ~~do not~~entered into a purchase and sale agreement with OFS ES to purchase 100% of the ownership interests in three of OFS ES’s subsidiaries (and indirectly their related subsidiaries). In addition, we agreed to acquire certain incidental assets from OFS ES and its parent company, OFS Holdings, LLC, that are used in the purchased business and to assume certain specified liabilities.

The total consideration for the acquisition is approximately 15.8 million shares of our common stock and a cash payment of $75.6 million, subject to certain working capital and other adjustments at closing. We have ~~a loss contingency accrued~~agreed to register the shares of common stock to be issued in the transaction under the Securities Act of 1933, as amended, subject to certain conditions. The acquisition is subject to customary closing conditions, including termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. We expect the closing of the transaction to take place in the third quarter of 2010. We expect to account for this ~~matter. We believe the range of possible damage awards could be between zero and $13.0 million, plus attorney’s fees. The court’s judgment is expected within 90 days.~~acquisition as a business combination.

2526


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

OVERVIEW

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, 2010 and 2009,~~ included elsewhere herein, and the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, ~~2009.~~2009 (“2009 Annual Report”).

We operate in two business segments, Well Servicing and Production Services. We also have a “Functional Support” segment associated with managing all of our reportable operating segments. See“Note 14. Segment Information”in“Item 1. Financial Statements”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 ~~be high.~~increase. Similarly, as oil and natural gas prices fall, the Baker Hughes U.S. land drilling rig count tends to decline.


					Average Baker
			NYMEX Henry		Hughes U.S.
	WTI Cushing Oil		Hub Natural Gas		Land Drilling						Average Baker
	(1)		(1)		Rigs (2)		WTI Cushing Oil		NYMEX Henry Hub		Hughes U.S. Land
							(1)		Natural Gas (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

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

Market Outlook

We continue to believe that customer spending in the ~~remainder~~onshore U.S. market will increase and that we will see steady improvements in our U.S. markets through the end of 2010, ~~will continue to see steady improvement for~~with the normal seasonal reduction in the fourth quarter. While our U.S. markets. Although spot crude oil prices continue to fluctuate on a daily basis, the U.S. Energy Information Administration projects more stability for West Texas Intermediate crude oil spot prices. Because commodity prices are expected to remain stable and the overall credit markets have improved, we believe that it is probable that activity levels and pricing could continue to improve during the remainder of 2010. We expect that our lines of business will continue to see an increaseinternational operations were affected by decreases in activity in Mexico, labor disruptions in Argentina and pricing relative to 2009. If commodity prices remain near or above current levels, then we anticipate that our core Well Servicing businesses will continue to show improvement, as our customers will spend to maintain or increase their existing production. We also expect that less uncertainty over near- and mid-term oil and natural gas pricing, coupled with modest price increases for our services, should encourage our customers to pursue maintenance activity on existing production.

~~Because of our size and geographical diversity,~~delays in operations in Russia, we believe that we are well equipped to meet the demands of our customers, who should spend more capital for production enhancement or maintenance needs, which would increase the demand for our services. We also believe thatwill see improvement in our international ~~operations will play an increasing role in~~businesses during the growth of our business. We expect that the disruptions in Russia and Mexico were temporary, and that these businesses, combined with Argentina, are positioned to positively contribute to our revenues and earnings for the remaindersecond half of 2010. In March 2010, we entered into a joint venture to expand our operations in the Middle East and Northern Africa. However, operations have not commenced in these regions, and we do not expect to see significant activity from this venture during 2010.

We will continue to aggressively monitor and manage our cost structure, rescinding temporary cost reductions implemented in 2009 as they become affordable. We will continue to focus on maintaining a strong balance sheet with acceptable leverage ratios and good liquidity. We will also continue to explore expansion opportunities in other international markets. We intend to continue deploying capital toward growth of our live well intervention capabilities, including large well servicing and workover rigs, coiled tubing units, and other complementary products and services, both organically and through acquisition.

On July 2, 2010, we reached an agreement with Patterson-UTI Energy (“Patterson”) whereby we will sell our pressure pumping and wireline businesses to Patterson for ~~expanding~~total consideration of approximately $256.7 million, comprised of a cash payment at closing of $237.7 million and our ~~service footprint into new markets or new lines~~retention of ~~business~~working capital associated with the businesses (subject to certain adjustments based on closing inventory and the value of certain owned properties that we may retain). The closing of the transaction is subject to regulatory approval and customary closing conditions. We received notification that the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as ~~those opportunities present themselves~~amended (the “HSR Act”) terminated effective July 27, 2010. We anticipate that closing of this transaction will occur in the ~~current market.~~third quarter of 2010.

On July 23, 2010, we entered into a purchase and sale agreement with OFS Energy Services, LLC (“OFS ES”) to purchase 100% of the ownership interests in three of OFS ES’s subsidiaries (and indirectly their related subsidiaries). In addition, we agreed to acquire certain incidental assets from OFS ES and its parent company, OFS Holdings, LLC, that are used in the purchased business and to assume certain specified liabilities.

RESULTS OF OPERATIONS

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


	Three Months Ended March 31,
	2010			2009			Three Months Ended June 30,						Six Months Ended June 30,
							2010			2009			2010			2009
*REVENUES*	$	302,071		$	331,989		$	267,785		$	219,061		$	519,744		$	502,710

*COSTS AND EXPENSES:*
Direct operating expenses		230,920			227,227			196,171			155,118			385,373			340,647
Depreciation and amortization expense		36,703			44,756			32,478			37,181			65,802			76,005
General and administrative expenses		40,952			48,706			44,866			44,039			83,893			90,465
Interest expense, net of amounts capitalized		10,247			9,648			10,729			10,173			20,988			20,103
Other, net		(1,253	)		523			467			(2,061	)		(776	)		(2,222	)

Total costs and expenses, net		317,569			330,860			284,711			244,450			555,280			524,998

(Loss) income before tax		(15,498	)		1,129
Income tax benefit (expense)		6,491			(225	)
Loss from continuing operations before tax								(16,926	)		(25,389	)		(35,536	)		(22,288	)
Income tax benefit								5,888			9,365			13,596			8,477

Net (loss) income		(9,007	)		904
Loss from continuing operations								(11,038	)		(16,024	)		(21,940	)		(13,811	)
Discontinued operations, net of tax (expense) benefit of $(4,312), $1,293, $(5,529) and $1,956, respectively								8,182			(2,449	)		10,077			(3,758	)

Net loss								(2,856	)		(18,473	)		(11,863	)		(17,569	)

Loss attributable to noncontrolling interest								620			—			2,047			—

*LOSS ATTRIBUTABLE TO KEY*							$	(2,236	)	$	(18,473	)	$	(9,816	)	$	(17,569	)


Net loss attributable to noncontrolling interest		1,427			—

*(LOSS) INCOME ATTRIBUTABLE TO KEY*	$	(7,580	)	$	904


*(Loss) earnings per share attributable to Key:*
*Loss per share from continuing operations attributable to Key:*
Basic	$	(0.06	)	$	0.01		$	(0.08	)	$	(0.13	)	$	(0.16	)	$	(0.12	)
Diluted	$	(0.06	)	$	0.01		$	(0.08	)	$	(0.13	)	$	(0.16	)	$	(0.12	)

*Loss per share from discontinued operations:*
Basic							$	0.06		$	(0.02	)	$	0.08		$	(0.03	)
Diluted							$	0.06		$	(0.02	)	$	0.08		$	(0.03	)

*Loss per share attributable to Key:*
Basic							$	(0.02	)	$	(0.15	)	$	(0.08	)	$	(0.15	)
Diluted							$	(0.02	)	$	(0.15	)	$	(0.08	)	$	(0.15	)

*Income from continuing operations attributable to Key:*
Loss from continuing operations							$	(11,038	)	$	(16,024	)	$	(21,940	)	$	(13,811	)
Loss attributable to noncontrolling interest								620			—			2,047			—

Loss from continuing operations attributable to Key							$	(10,418	)	$	(16,024	)	$	(19,893	)	$	(13,811	)


*Weighted average shares outstanding:*
Basic		124,952			120,665			125,412			120,963			125,183			120,815
Diluted		124,952			121,436			125,412			120,963			125,183			120,815

Depreciation and Amortization Expense

Depreciation and amortization expense decreased ~~$8.1~~$4.7 million ~~or 18.0%,~~ to ~~$36.7~~$32.5 million (12.1% of revenues) during the ~~first~~second quarter of 2010, compared to ~~$44.8~~$37.2 million (17.0% of revenues) for the ~~first~~second quarter of 2009. The decrease in our depreciation and amortization expense is primarily attributable to the ~~reduction in the carrying value of our fixed assets, which was associated with the impairments and~~ asset retirements and impairments we recognized during the third quarter of ~~2009.~~2009, which decreased the cost basis of our depreciable fixed assets.

General and Administrative Expenses

General and administrative expenses ~~decreased $7.8~~increased $0.8 million to ~~$41.0~~$44.9 million ~~(13.6%~~(16.8% of revenues) for the three months ended ~~March 31,~~June 30, 2010, compared to ~~$48.7~~$44.0 million ~~(14.7%~~(20.1% of revenues) for the three months ended ~~March 31,~~June 30, 2009. ~~General~~The increase in general and administrative expenses ~~were less in~~for the ~~first~~second quarter of 2010 as a result of lower headcount and wage rate and benefit reductions, which we implemented during the first quarter of 2009 and that continue in effect. Additionally, we incurred less professional fees as we continued to control spendingwas primarily due to ~~market conditions.~~higher stock-based compensation related to new equity awards and implementation costs for a new Enterprise Resource Planning (“ERP”) system conversion.

Interest Expense, net of Amounts Capitalized

Interest expense ~~increased $0.6~~was $10.7 million for the three months ended ~~March 31,~~June 30, 2010, an increase of $0.6 million, or 5.5%, compared to $10.2 million for the same period in 2009, due to higher interest rates on our borrowings under our amended revolving credit ~~facility in the first quarter of 2010, combined with lower capitalized interest due to lower capital expenditures.~~facility.

Other, net

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


	Three Months Ended June 30,
	2010			2009
	(in thousands)
Loss (gain) on disposal of assets, net	$	320		$	(1,381	)
Interest income		(21	)		(169	)
Foreign exchange loss (gain)		855			(865	)
Other (income) expense, net		(687	)		354

Total	$	467		$	(2,061	)

Income Tax Benefit ~~(Expense)~~

We recorded an income tax benefit of ~~$6.5~~$5.9 million on a pretax loss of ~~$15.5~~$16.9 million in the ~~first~~second quarter of 2010, compared to an income tax ~~expense~~benefit of ~~$0.2~~$9.4 million on a pretax ~~income~~loss of ~~$1.1~~$25.4 million in the ~~first~~second quarter of 2009. Our effective tax rate was ~~41.9%~~34.8% for the three months ended ~~March 31,~~June 30, 2010, compared to ~~19.9%~~36.9% for the three months ended ~~March 31,~~June 30, 2009. Our effective tax rates for the periods differ from the statutory rate of 35% due to numerous factors, including the mix of profit and loss between various taxing jurisdictions, such as foreign, state and local taxes, and the impact of permanent items that affect book income but do not affect taxable income.

Discontinued Operations

We ~~also~~ recorded asnet income from discontinued operations of $8.2 million for the three months ended June 30, 2010, compared to a ~~component~~net loss of $2.5 million for the three months ended June 30, 2009. The increase in net income ~~tax expense $0.1 million related~~from discontinued operations is due to ~~uncertain tax positions during the quarter.~~significant improvement in our fracturing and cementing services within our pressure pumping operations, including higher activity, expansion into new markets and improved pricing.

Noncontrolling Interest

For the three months ended ~~March 31,~~June 30, 2010, we recorded a benefit of ~~$1.4~~$0.6 million associated with the net loss incurred by our joint venture in the Russian Federation with OOO Geostream Services Group (“Geostream”). We own a 50% interest in Geostream and fully consolidate its results, with the noncontrolling interest representing the portion of Geostream’s net income or loss for the period that is attributable to Geostream’s other shareholder.

Operating expenses for Functional Support, which represent expenses associated with managing our other reportable operating segments, increased $1.0 million, or 3.5%, to $28.6 million (10.7% of consolidated revenues) for the three months ended June 30, 2010 compared to $27.6 million (12.6% of consolidated revenues) for the same period in 2009. The primary reason for the increase in costs is higher stock based compensation expense related to new equity awards and implementation costs related to our new ERP system during the second quarter of 2010. This increase was partially offset by cost reduction efforts that remain in effect.

Consolidated Results of Operations — Six Months Ended June 30, 2010 and 2009

Revenues

Our revenues for the six months ended June 30, 2010 increased $17.0 million, or 3.4%, to $519.7 million from $502.7 million for the six months ended June 30, 2009. See“Segment Operating Results — Six Months Ended June 30, 2010 and 2009”below for a more detailed discussion of the change in our revenues.

Direct Operating Expenses

Our direct operating expenses increased $44.7 million to $385.4 million (74.1% of revenues) for the six months ended June 30, 2010, compared to $340.6 million (67.8% of revenues) for the six months ended June 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 $10.2 million to $65.8 million (12.7% of revenues) during the first six months of 2010, compared to $76.0 million (15.1% of revenues) for the first six 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 cost basis of our depreciable fixed assets.

General and Administrative Expenses

General and administrative expenses decreased $6.6 million to $83.9 million (16.1% of revenues) for the six months ended June 30, 2010, compared to $90.5 million (18.0% of revenues) for the six months ended June 30, 2009. General and administrative expenses were less in the first half of 2010 as a result of lower headcount and wage rate and benefit reductions, which we implemented during the first quarter of 2009. Additionally, we incurred less professional fees during the first half of 2010 as we continued our cost reduction efforts.

Interest Expense, net of Amounts Capitalized

Interest expense increased $0.9 million for the six months ended June 30, 2010, compared to 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:


	Six Months Ended June 30,
	2010			2009
	(in thousands)
Loss (gain) on disposal of assets, net	$	655		$	(1,376	)
Interest income		(36	)		(417	)
Foreign exchange gain		(509	)		(53	)
Other income, net		(886	)		(376	)

Total	$	(776	)	$	(2,222	)

Income Tax Benefit

We recorded an income tax benefit of $13.6 million on a pretax loss of $35.5 million for the six months ended June 30, 2010, compared to an income tax benefit of $8.5 million on a pretax loss of $22.3 million for the six months ended June 30, 2009. Our effective tax rate was 38.3% for the six months ended June 30, 2010, compared to 38.0% for the six months ended June 30, 2009. Our effective tax rates for the periods differ from the statutory rate of 35% due to numerous factors, including the mix of profit and loss between various taxing jurisdictions, such as foreign, state and local taxes, and the impact of permanent items that affect book income but do not affect taxable income.

Discontinued Operations

We recorded net income from discontinued operations of $10.1 million for the six months ended June 30, 2010, compared to a net loss from discontinued operations of $3.8 million for the six months ended June 30, 2009. The increase in net income from discontinued operations is due to significant improvement in our fracturing and cementing services within our pressure pumping operations, including higher activity, expansion into new markets and better pricing.

Noncontrolling Interest

For the six months ended June 30, 2010, we recorded a benefit of $2.0 million associated with the net loss incurred by our joint venture in the Russian Federation with Geostream. We own a 50% interest in Geostream and fully consolidate its results, with the noncontrolling interest representing the portion of Geostream’s net income or loss for the period that is attributable to Geostream’s other shareholder.

Segment Operating Results — Six Months Ended June 30, 2010 and 2009

The following table shows operating results for each of our segments for the six month periods ended June 30, 2010 and 2009, respectively (in thousands, except for percentages):

For the six months ended June 30, 2010:


	Well			Production			Functional
	Servicing			Services			Support
Revenues from external customers	$	456,737		$	63,007		$	—
Operating expenses		425,203			57,173			52,692
Operating income (loss)		31,534			5,834			(52,692	)
Operating income (loss) as a percentage of revenue from external customers		6.9	%		9.3	%		n/a

For the six months ended June 30, 2009:


	Well			Production			Functional
	Servicing			Services			Support
Revenues from external customers	$	454,206		$	48,504		$	—
Operating expenses		397,669			55,660			53,788
Operating income (loss)		56,537			(7,156	)		(53,788	)
Operating income (loss) as a percentage of revenue from external customers		12.4	%		(14.8	)%		n/a

Well Servicing

Revenues from external customers for our Well Servicing segment increased $2.5 million, or 0.6%, to $456.7 million for the six months ended June 30, 2010, compared to $454.2 million for the six months ended June 30, 2009. The slight increase in revenues resulted from a net change in revenue for this segment due to 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 $425.2 million during the six months ended June 30, 2010, which represented an increase of $27.5 million, or 6.9%, compared to $397.7 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 $14.5 million, or 29.9%, to $63.0 million for the six months ended June 30, 2010, compared to $48.5 million for the six months ended June 30, 2009. The increase in revenue for this segment is attributable to an increase in revenues from our fishing and rental operations and improved pricing on coiled tubing services during 2010.

Operating expenses for our Production Services segment increased $1.5 million, or 2.7%, to $57.2 million for the first six months of 2010, compared to $55.7 million for the first six 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 as a percentage of revenues from external customers compared to the same period in 2009.

Functional Support

Operating expenses for Functional Support, which represent expenses associated with managing our other reportable operating segments, decreased ~~$2.1~~$1.1 million, or ~~7.9%~~2.0%, to ~~$24.1~~$52.7 million (10.1% of consolidated revenues) for the ~~three~~six months ended ~~March 31,~~June 30, 2010 compared to ~~$26.2~~$53.8 million (10.7% of consolidated revenues) for the same period in 2009. The primary reason for the decline in costs is lower employee compensation associated with reduced headcount and wage rate and benefit reductions that we implemented during the first quarter of 2009 ~~and that continue in effect,~~ partially offset by higher equity compensation expense due to new equity awards ~~granted~~and implementation costs for a new ERP system conversion during the ~~first~~second quarter of ~~2010. Also contributing to the decrease~~2010 and overall increases in ~~Functional Support costs is lower professional fees as we continue to control our costs.~~activity. We also received favorable settlement of a claim from 2007 against one of our former insurance underwriters.

LIQUIDITY AND CAPITAL RESOURCES

Current Financial Condition and Liquidity

As of ~~March 31,~~June 30, 2010, we had cash and cash equivalents of ~~$66.8~~$47.0 million. Our working capital (excluding the current portion of capital leases, notes payable and long-term debt) was ~~$199.9~~$199.0 million, compared to $204.5 million as of December 31, 2009. Our working capital decreased from prior year end primarily as a result of increased accrued operating expenses during the period, partially offset by increased accounts receivable due to activity increases associated with improving market conditions during the first ~~quarter~~half of 2010. Our total outstanding debt ~~(including capital leases and notes payable)~~ was ~~$531.5~~$523.2 million, and we have no significant debt maturities until 2012. As of ~~March 31,~~June 30, 2010, we ~~have~~had $87.8 million in borrowings and $55.1 million in committed letters of credit outstanding under our ~~senior~~ revolving credit facility, leaving $157.1 million of available borrowing capacity (discussed further below under ~~“Senior~~“Senior Secured Credit Facility”).

Cash used in financing activities was ~~$3.2~~$9.1 million during the ~~quarter~~six months ended ~~March 31,~~June 30, 2010 and ~~$3.2~~$106.1 million for the ~~quarter~~six months ended ~~March 31,~~June 30, 2009. Financing cash outflows in the 2010 period primarily consisted of repayments on capital lease obligations and ~~other indebtedness,~~the repayment of the $6.0 million outstanding principal balance of a related party note concurrently with the sale of six barge rigs and related equipment, as well as 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 Credit Facility (defined below), and internally generated cash flows from operations.

Debt Service

We do not have any significant maturities of debt ~~in 2010.~~until 2012. Interest on our Senior Notes (defined below) is due on June 1 and December 1 of each year. Interest on the Senior Notes of $17.8 million was paid on June 1, 2010 and is estimated to be ~~$35.6~~$17.8 million for December 1, 2010. We expect to fund interest payments from cash generated by operations. At ~~March 31,~~June 30, 2010, our annual debt maturities for our Senior Notes and borrowings under our Senior Secured Credit Facility ~~notes payable to related parties and other indebtedness were~~are as follows:


	Principal Payments		Principal Payments
	(in thousands)		(in thousands)
2010	$	3,044
Remainder of 2010			$	—
2011		2,000		—

2012		89,813		87,813

2013		—		—
2014		425,000		425,000

Total principal payments	$	519,857	$	512,813

Notwithstanding the foregoing, at any time and from time to time before December 1, 2010, we may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of the outstanding Senior Notes at a redemption price of 108.375% of the principal amount thereof, plus accrued and unpaid interest thereon to the redemption date, with the net cash proceeds of any one or more equity offerings; provided that at least 65% of the aggregate principal amount of the Senior 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 1, 2011, we may, at our option, redeem all or a portion of the Senior 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) with respect to the Senior 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 Notes the opportunity to sell to us their Senior 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 covenants under the indenture governing the Senior Notes. The indenture limits our ability to, among other things:

	•		sell assets;

	•		pay dividends or make other distributions on capital stock or subordinated indebtedness;

	•		make investments;

	•		incur additional indebtedness or issue preferred stock;

	•		create certain liens;

	•		enter into agreements that restrict dividends or other payments from our subsidiaries to us;

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

	•		engage in transactions with affiliates; and

	•		create unrestricted subsidiaries.

These covenants are subject to certain exceptions and qualifications, and contain cross-default provisions ~~in connection with~~tied to the covenants of our Senior Secured Credit Facility. In addition, substantially all of the covenants will terminate before the Senior Notes mature if one of two specified ratings agencies assigns the Senior Notes an investment grade rating in the future and no events of default exist under the indenture governing the Senior Notes. 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 Notes later falls below an investment grade rating. As of ~~March 31,~~June 30, 2010, the Senior Notes were below investment grade and have never been assigned an investment ~~grade.~~grade rating, and we were in compliance with all the covenants under the Senior Notes.

Senior Secured Credit Facility

We maintain 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 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 of a revolving credit facility, letter of credit sub-facility and swing line facility, up to an aggregate principal amount of $300.0 million, all of which will mature no later than November 29, 2012.

The Amendment reduced the total credit commitments under the facility from $400.0 million to $300.0 million, effected by a pro rata reduction of the commitment of each lender under the facility. We have 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 the applicable interest rates and some of the financial covenants, among other changes.

The interest rate per annum applicable to the Senior Secured Credit Facility (as amended) is, at our option, (i) LIBOR plus a 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 prime rate and (y) the Federal Funds rate plus 0.5%), plus a margin of 250 to 350 basis points, depending on our consolidated leverage ratio. Unused commitment fees on the facility range from 0.50% to 0.75%, depending upon our consolidated leverage ratio.

The Senior Secured Credit Facility contains certain financial covenants, which, among other things, require us to maintain certain 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:

	•		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 Credit Facility, “EBITDA”) be no greater than (i) 2.50 to 1.00 for the fiscal quarter ended ~~December~~March 31, ~~2009~~2010 through and including the fiscal quarter ending December 31, 2010 and, (ii) thereafter, 2.00 to 1.00;

	•		that 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:


from the fiscal quarter ended ~~December~~March 31, ~~2009~~2010 through and including the fiscal quarter ending June 30, 2010			1.75 to 1.00

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) $135.0 million during fiscal year 2009 and $120.0 million during each subsequent 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 limit our capital expenditures (not including any made by foreign subsidiaries that are not wholly-owned) to (i) $135.0 million during fiscal year 2009 and $120.0 million during each subsequent 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 ~~subclauses~~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 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 million during any fiscal year or an aggregate amount after October 27, 2009 equal 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.

In addition, the amended Senior Secured Credit Facility contains certain covenants, including, without limitation, restrictions related to (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; (vi) dividends and other distributions to, and redemptions and repurchases from, equity holders; (vii) prepaying, redeeming or repurchasing the Senior Notes or other unsecured debt incurred pursuant to the sixth bullet point listed above; (viii) granting negative pledges other than to the lenders; (ix) changes in the nature of our business; (x) 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; and (xi) changes in accounting policies or reporting practices; in each of the foregoing cases, with certain exceptions.

We may prepay the Senior Secured Credit Facility in whole or in part at any time without premium or penalty, subject to our obligation to reimburse the lenders for breakage and redeployment costs. We were in compliance with the covenants of the Senior Secured Credit Facility at June 30, 2010.

Related Party Notes Payable

On October 25, 2007, we entered into two notes payable with related parties (each, a “Related Party Note” and, collectively, the “Related Party Notes”). The first Related Party Note was an unsecured note in the amount of $12.5 million, which was due and paid in a lump-sum, together with accrued interest, on October 25, 2009. The second Related Party Note iswas an unsecured note in the amount of $10.0 million and iswas payable in annual installments of $2.0 million, plus accrued interest, beginning October 25, ~~2008 through 2012. Each~~2008. Concurrently with the sale of ~~the Related Party Notes bore or bears interest at the Federal Funds Rate adjusted annually on the anniversary date of October 25. The interest rate on~~six barge rigs and related equipment, we repaid the remaining $6.0 million outstanding under the second Related Party Note ~~at March 31, 2010 was 0.11%, and the carrying value was $5.9 million.~~in May 2010.

Capital Lease Agreements

We lease equipment, such as vehicles, tractors, trailers, frac tanks and forklifts, from financial institutions under master lease agreements. As of ~~March 31,~~June 30, 2010, there was ~~$12.2~~$10.4 million outstanding under such equipment leases.

Off-Balance Sheet Arrangements

At ~~March 31,~~June 30, 2010 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, 2010, we had cash and cash equivalents of $66.8 million, available borrowing capacity of $157.1 million under our Senior Secured Credit Facility, and no significant debt maturities until 2012. We believe that our internally generated cash flows from operations, net cash inflows from our pending transactions, 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 Credit Facility and, in the case of acquisitions, equity.

Capital Expenditures

During the ~~three~~six months ended ~~March 31,~~June 30, 2010, our capital expenditures totaled ~~$32.4~~$67.9 million, primarily related to ~~our international expansion and~~the purchase of coiled tubing units, the addition of larger well service rigs, major maintenance of our existing fleet and ~~equipment.~~equipment, and capitalized costs associated with our new ERP system. Our capital expenditures program is expected to total $170.0 million during 2010, focusing mainly on the maintenance of our fleet and selected growth opportunities in the U.S. market. This projected capital expenditure amount does not include our planned acquisition of certain subsidiaries of OFS ES, capital expenditures related to assets to be acquired subsequent to the transaction’s closing, or other potential growth opportunities related to strategic investments and acquisitions that are in preliminary stages or unplanned at this point. Our capital expenditure program for 2010 is subject to market conditions, including activity levels, commodity prices, and industry capacity. Our focus for 2010 will be the maximization of our current equipment fleet, but we may choose to increase our capital expenditures in 2010 to increase market share or expand our presence into a new market. We currently anticipate funding our 2010 capital expenditures through a combination of cash on hand, operating cash flow, net cash inflows from our pending transactions, and borrowings under our Senior Secured Credit Facility. Should our operating cash flows or activity levels prove to be insufficient to warrant our currently planned capital spending levels, management expects it will adjust our capital spending plans accordingly.

Divestitures and Acquisitions

On July 2, 2010, we reached an agreement to sell our pressure pumping and wireline businesses to Patterson for total consideration of approximately $256.7 million, comprised of a cash payment at closing of $237.7 million and our retention of the working capital of the businesses being sold (subject to certain adjustments based on closing inventory and the value of certain owned properties that we may retain).

On July 23, 2010, we entered into a purchase and sale agreement with OFS ES to purchase 100% of the ownership interests in three of OFS ES’s subsidiaries (and indirectly their related subsidiaries). In addition, we agreed to acquire certain incidental assets from OFS ES and its parent company, OFS Holdings, LLC, that are used in the purchased business and to assume certain designated liabilities. The total consideration for the acquisition will be approximately 15.8 million shares of our common stock and a cash payment of $75.6 million, subject to certain working capital and other adjustments at closing, and will be funded by cash on hand, or borrowings on our Senior Secured Credit Facility, as necessary.

We ~~may also incur~~anticipate using a portion of the net after-tax proceeds from the Patterson transaction to pay down the outstanding balance on the revolving portion of our Senior Secured Credit Facility, with the remainder being used for general corporate purposes.

The cash flows from the businesses being sold have not been separately identified in our consolidated statements of cash flows for the six month periods ended June 30, 2010 and 2009. We believe that the reduction in cash flows expected after the closing of the Patterson transaction will not have a material adverse impact on our liquidity and our ability to fund future operations and capital ~~expenditures for strategic investments~~expenditures. We expect that the proceeds and ~~acquisitions.~~investment of proceeds from the Patterson transaction, as well as anticipated cash flows from our planned acquisition of the OFS businesses, will have an offsetting effect on such reduction. Additionally, as we intend to use 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.


~~ITEM 4.~~		*ITEM 4.CONTROLS AND PROCEDURES***

Disclosure Controls and Procedures

As of the end of the period covered by this Quarterly Report on Form 10-Q, management performed, with the participation of our Chief Executive Officer and our Chief Financial Officer, an evaluation of the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designated to ensure that information is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on this evaluation, management concluded that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

~~There~~ We implemented a new ERP system on May 1, 2010. This implementation has resulted in certain changes to business processes and internal controls impacting financial reporting, but we also continue to perform a significant portion of controls following our previously tested control structure. We believe that the new ERP system and related changes to internal controls will enhance our internal controls over financial reporting. We have taken the necessary steps to monitor and maintain appropriate internal control over financial reporting during this period of system change and will continue to evaluate the operating effectiveness of related controls during subsequent periods.

Other than the implementation of our new ERP system discussed above, there were no changes in our internal control over financial reporting during the ~~first~~second quarter of 2010 that materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION


~~ITEM 1.~~		*ITEM 1.LEGAL PROCEEDINGS***

In addition to various suits and claims that have arisen in the ordinary course of business, we continue to be involved in litigation with a former executive officer. We do not believe that the disposition of any of these items, including litigation with former management, 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. Commitments and Contingencies” in “Item 1. Financial Statements” of “Part I” above.


~~ITEM 1A.~~		*ITEM 1A.RISK FACTORS***

There have been no material changes in our risk factors disclosed in our 2009 Annual Report ~~on Form 10-K~~ dated as of, and filed with the SEC on, February ~~27,~~26, 2010. For a discussion of these risk factors, see “Item 1A. Risk Factors” in our 2009 Annual ~~Report on Form 10-K.~~Report. However, we have identified the following additional risk factor:

We have decided to sell our pressure pumping and wireline businesses, which poses certain risks.

On July 2, 2010, we entered into an agreement to sell our pressure pumping and wireline businesses, which we anticipate will close in the third quarter of 2010. 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. There is a risk that our planned divesture may be delayed or may not close at all. Delays or failure to close could result in additional required capital and personnel resources, and could diminish or preclude our ability to receive the anticipated benefit from the contemplated transaction, which could also negatively impact our ability to successfully implement our overall business strategies. If we are unable to consummate the sale of our pressure pumping and wireline businesses or manage the post-separation transition arrangements, it could adversely affect our business, financial condition, results of operations and cash flows.


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

During the three months ended ~~March 31,~~June 30, 2010, 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
January 1, 2010 to January 31, 2010 — $ — — $ —
February 1, 2010 to February 28, 2010 — — — —
March 1, 2010 to March 31, 2010 206,981 10.52 — —

Total 206,981 $ 10.52 — $ —


							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
April 1, 2010 to April 30, 2010		16,519	$	10.71		—		—
May 1, 2010 to May 31, 2010		662		10.32		—		—
June 1, 2010 to June 30, 2010		11,070		9.48		—		—

Total		28,251	$	10.22		—		—


(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 NYSE on the vesting date for awards granted under the Key Energy Services, Inc. 2007 Equity and Cash Incentive Plan.

3741


~~ITEM 3.~~		*ITEM 3.DEFAULTS UPON SENIOR SECURITIES***

None.


~~ITEM 5.~~		*ITEM 5.OTHER INFORMATION***

None.


~~ITEM 6.~~		*ITEM 6.EXHIBITS***


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†~~10.1		~~Form of Performance Unit Award~~Asset Purchase Agreement, ~~under the~~dated May 13, 2010, by and among Key Energy Services, ~~Inc. 2009 Equity~~LLC, a Texas limited liability company, Key Marine Services, LLC, a Delaware limited liability company, Moncla Companies, L.L.C., a Texas limited liability company, and ~~Cash Incentive Plan~~Moncla Marine, L.L.C., a Louisiana limited liability company, L. Charles Moncla, Jr., Moncla Family Partnership, Ltd., L. Charles Moncla, Jr. Charitable Remainder Trust, Michael Moncla, Matthew Moncla, Marc Moncla, Christopher Moncla, Bipin A. Pandya, Thomas Sandahl, Rhonda Moncla, Cain Moncla, Andrew Moncla, Kenneth Rothstein, Second 4 M Ltd., a Texas limited partnership, and Leon Charles Moncla, Jr., as payment agent. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K ~~dated March 5,~~filed on May 19, 2010, File No. 001-08038.)

~~10.2†~~		Form of Amendment to Employment Agreement, in the form executed on March 29, 2010, by and between Key Energy Services, Inc., Key Energy Shared Services, LLC, and each of Richard J. Alario, T.M. Whichard III, Newton W. Wilson III, Kim B. Clarke and Kimberly R. Frye (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K dated April 1, 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.


†		~~Indicates a management contract or compensatory plan, contract or arrangement in which any director or any executive officer participates.~~

*		Filed herewith

3842

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†~~10.1		~~Form of Performance Unit Award~~Asset Purchase Agreement, ~~under the~~dated May 13, 2010, by and among Key Energy Services, ~~Inc. 2009 Equity~~LLC, a Texas limited liability company, Key Marine Services, LLC, a Delaware limited liability company, Moncla Companies, L.L.C., a Texas limited liability company, and ~~Cash Incentive Plan~~Moncla Marine, L.L.C., a Louisiana limited liability company, L. Charles Moncla, Jr., Moncla Family Partnership, Ltd., L. Charles Moncla, Jr. Charitable Remainder Trust, Michael Moncla, Matthew Moncla, Marc Moncla, Christopher Moncla, Bipin A. Pandya, Thomas Sandahl, Rhonda Moncla, Cain Moncla, Andrew Moncla, Kenneth Rothstein, Second 4 M Ltd., a Texas limited partnership, and Leon Charles Moncla, Jr., as payment agent. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K ~~dated March 5,~~filed on May 19, 2010, File No. 001-08038.)

~~10.2†~~		Form of Amendment to Employment Agreement, in the form executed on March 29, 2010, by and between Key Energy Services, Inc., Key Energy Shared Services, LLC, and each of Richard J. Alario, T.M. Whichard III, Newton W. Wilson III, Kim B. Clarke and Kimberly R. Frye (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K dated April 1, 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.


†		~~Indicates a management contract or compensatory plan, contract or arrangement in which any director or any executive officer participates.~~

*		Filed herewith


	Three Months Ended March 31,
	2010			2009

*NET (LOSS) INCOME*	$	(9,007	)	$	904

Other comprehensive income (loss), net of tax:
Foreign currency translation gain (loss)		194			(5,254	)
Deferred gain from available for sale investments		—			30

Total other comprehensive income (loss), net of tax		194			(5,224	)


*COMPREHENSIVE LOSS, NET OF TAX*		(8,813	)		(4,320	)
Comprehensive loss attributable to noncontrolling interest		1,444			—

*COMPREHENSIVE LOSS ATTRIBUTABLE TO KEY*	$	(7,369	)	$	(4,320	)


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
*LOSS FROM CONTINUING OPERATIONS*	$	(11,038	)	$	(16,024	)	$	(21,940	)	$	(13,811	)

Other comprehensive (loss) income, net of tax:
Foreign currency translation (loss) gain		(429	)		764			(236	)		(4,490	)
Deferred gain from available for sale investments		—			—			—			30

Total other comprehensive (loss) income, net of tax		(429	)		764			(236	)		(4,460	)

*COMPREHENSIVE LOSS FROM CONTINUING OPERATIONS, NET OF TAX*		(11,467	)		(15,260	)		(22,176	)		(18,271	)

Comprehensive loss attributable to noncontrolling interest		715			—			2,125			—
Comprehensive income (loss) from discontinued operations		8,182			(2,449	)		10,077			(3,758	)


*COMPREHENSIVE LOSS ATTRIBUTABLE TO KEY*	$	(2,570	)	$	(17,709	)	$	(9,974	)	$	(22,029	)


	March 31,		December 31,
	2010		2009		June 30, 2010		December 31, 2009
	(in thousands)				(in thousands)
Other Current Liabilities:
Accrued payroll, taxes and employee benefits	$	37,428	$	33,953	$	51,054	$	33,953
Accrued operating expenditures		35,456		24,194		40,783		24,194
Income, sales, use and other taxes		24,805		30,447		27,972		30,447
Self-insurance reserve		23,947		24,366		32,575		24,366
Accrued interest		11,914		3,014		3,369		3,014
Insurance premium financing		4,843		7,282		2,869		7,282
Unsettled legal claims		1,700		2,665		2,000		2,665
Share-based compensation liabilities		1,045		1,518		1,424		1,518
Other		7,549		6,092		7,397		6,092

Total	$	148,687	$	133,531	$	169,443	$	133,531


	March 31,		December 31,				December 31,
	2010		2009		June 30, 2010		2009
	(in thousands)				(in thousands)
Other Non-Current Liabilities:
Deferred tax liabilities	$	146,497	$	146,980	$	143,598	$	146,980
Accrued insurance costs		41,533		40,855		34,149		40,855
Asset retirement obligations		10,237		10,045		10,277		10,045
Environmental liabilities		3,210		3,353		3,159		3,353
Accrued rent		2,309		2,399		2,213		2,399
Accrued income taxes		2,813		2,813
Share-based compensation liabilities		613		508		536		508
Other		518		599		6,570		3,412

Total	$	207,730	$	207,552	$	200,502	$	207,552


	U.S.		International		Eliminations			Total		U.S.		International		Eliminations			Total
	(in thousands)									(in thousands)
As of and for the three months ended March 31, 2010:
As of and for the three months ended June 30, 2010

Revenue from external customers	$	246,420	$	55,651	$	—		$	302,071	$	224,221	$	43,564	$	—		$	267,785
Long-lived assets		1,256,721		148,681		(128,682	)		1,276,720		1,172,432	$	90,458	$	—		$	1,262,890

As of and for the three months ended March 31, 2009:
As of and for the three months ended June 30, 2009

Revenue from external customers	$	284,743	$	47,246	$	—		$	331,989	$	174,877	$	44,184	$	—		$	219,061
Long-lived assets		2,243,792		88,186		(875,445	)		1,456,533	$	1,436,549	$	87,611	$	(90,489	)		1,433,671

As of and for the six months ended June 30, 2010

Revenue from external customers										$	420,529	$	99,215	$	—		$	519,744
Long-lived assets										$	1,172,432	$	90,458	$	—		$	1,262,890

As of and for the six months ended June 30, 2009

Revenue from external customers										$	411,280	$	91,430	$	—		$	502,710
Long-lived assets											1,436,549	$	87,611	$	(90,489	)		1,433,671


Part I—Financial Information			4

Item 1. Financial Statements			4

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			26
			27
Item 3. Quantitative and Qualitative Disclosures About Market Risk			37
			39
Item 4. Controls and Procedures			37
			40
Part II—Other Information			37
			41
Item 1. Legal Proceedings			37
			41
Item 1A. Risk Factors			37
			41
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			37
			41
Item 3. Defaults Upon Senior Securities			38
			42
Item 5. Other Information			38
			42
Item 6. Exhibits			3842
~~Exhibit 31.1~~EX-31.1
~~Exhibit 31.2~~EX-31.2
~~Exhibit 32~~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


																Three Months Ended June 30, 2009
	Three Months Ended March 31, 2009																		Guarantor			Non-Guarantor
	Parent			Guarantor			Non-Guarantor									Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated			(in thousands)
	(in thousands)															(unaudited)
Revenues	$	—		$	294,273		$	48,203		$	(10,487	)	$	331,989		$	—		$	185,710		$	45,357		$	(12,006	)	$	219,061

Costs and expenses:
Direct operating expenses		—			201,641			32,983			(7,397	)		227,227
Direct operating expense																	—			127,432			35,967			(8,281	)		155,118
Depreciation and amortization expense		—			43,256			1,500			—			44,756			—			35,680			1,501			—			37,181
General and administrative expenses		185			44,226			4,267			28			48,706
General and administrative expense																	764			38,672			4,602			1			44,039
Interest expense, net of amounts capitalized		11,132			(1,556	)		72			—			9,648			10,328			(137	)		(18	)		—			10,173
Other, net		367			(395	)		3,011			(2,460	)		523			19			(1,561	)		2,358			(2,877	)		(2,061	)

Total costs and expenses, net		11,684			287,172			41,833			(9,829	)		330,860			11,111			200,086			44,410			(11,157	)		244,450

(Loss) income before income taxes		(11,684	)		7,101			6,370			(658	)		1,129
(Loss) income from continuning operations before tax																	(11,111	)		(14,376	)		947			(849	)		(25,389	)
Income tax benefit (expense)		1,475			—			(1,700	)		—			(225	)		10,903			—			(1,538	)		—			9,365

Income (loss) from continuing operations																	1,085			(15,669	)		(591	)		(849	)		(16,024	)
Discontinued operations																	—			(2,449	)		—			—			(2,449	)

(LOSS) INCOME ATTRIBUTABLE TO KEY	$	(10,209	)	$	7,101		$	4,670		$	(658	)	$	904
INCOME (LOSS) ATTRIBUTABLE TO KEY																$	1,085		$	(18,118	)	$	(591	)	$	(849	)	$	(18,473	)


(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
					Rig Hours		Trucking Hours
2010:
First Quarter		485,183		459,292		485,183		459,292
Second Quarter						489,168		518,483

2009:
First Quarter		489,819		499,247		489,819		499,247
Second Quarter		415,520		416,269		415,520		416,269
Third Quarter		416,810		398,027		416,810		398,027
Fourth Quarter		439,552		422,253		439,552		422,253

Total 2009		1,761,701		1,735,796		1,761,701		1,735,796


*		~~Intersegment expenses have not been eliminated from the amounts shown above.~~


	Three Months Ended March 31,						Six Months Ended
	2010			2009			June 30,
	(in thousands)						2010			2009
							(in thousands)
Net cash provided by operating activities	$	65,754		$	129,383		$	64,695		$	157,299
Cash paid for capital expenditures		(32,415	)		(44,797	)		(67,923	)		(67,409	)
Proceeds received from sale of fixed assets								20,073			3,818
Other investing activities, net		1,171			797			165			199
Repayments of capital lease obligations		(2,077	)		(2,635	)		(3,992	)		(6,107	)
Repayments on long-term debt		(513	)		(513	)		(6,970	)		(101,026	)
Repurchases of common stock		(2,180	)		(38	)		(2,357	)		(113	)
Other financing activities, net		1,600			—			4,255			1,177
Effect of exchange rates on cash		(1,920	)		(714	)		1,700			(890	)

Net increase in cash and cash equivalents	$	29,420		$	81,483
Net increase (decrease) in cash and cash equivalents							$	9,646		$	(13,052	)


~~ITEM 3.~~		*ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK***


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