10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the Quarterly Period Ended September 30, 2010

or

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

Commission file number: 001-08038

KEY ENERGY SERVICES, INC.

(Exact name of registrant as specified in its charter)

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

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

Yes þ No o

     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes þ No o

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

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

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

Yes o No þ

     As of October 27, 2010, the number of outstanding shares of common stock of the registrant was 141,427,042.

KEY ENERGY SERVICES, INC.

QUARTERLY REPORT ON FORM 10-Q
For the Quarter Ended September 30, 2010

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

2

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 this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K for the year ended December 31, 2009, in our Quarterly Report on Form 10-Q for the periods ended March 31, 2010 and June 30, 2010, in our recent Current Reports on Form 8-K and in our other filings with the Securities and Exchange Commission. Actual performance or results may differ materially and adversely.

     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.

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PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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

	September 30,			December 31,
	2010			2009
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	34,053		$	37,394
Accounts receivable, net of allowance for doubtful accounts of $6,996 and $5,441, respectively		301,592			214,662
Inventory		22,064			23,478
Other current assets		48,342			104,624
Current assets held for sale		9,251			3,974
Total current assets		415,302			384,132
Property and equipment		1,650,025			1,647,718
Accumulated depreciation		(863,173	)		(853,449	)
Property and equipment, net		786,852			794,269
Goodwill		349,779			346,102
Other intangible assets, net		33,365			41,048
Deferred financing costs, net		8,460			10,421
Equity method investments		6,146			5,203
Other noncurrent assets		13,807			12,896
Noncurrent assets held for sale		67,264			70,339
TOTAL ASSETS	$	1,680,975		$	1,664,410
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	54,227		$	46,086
Current portion of capital leases, notes payable and long-term debt		4,397			10,152
Other current liabilities		158,395			133,531
Total current liabilities		217,019			189,769
Capital leases, notes payable and long-term debt		515,876			523,949
Other noncurrent liabilities		200,654			207,552
Commitments and contingencies
Equity:
Common stock, $0.10 par value; 200,000,000 shares authorized, 125,618,228 and 123,993,480 shares issued and outstanding, respectively		12,562			12,399
Additional paid-in capital		619,151			608,223
Accumulated other comprehensive loss		(51,511	)		(50,763	)
Retained earnings		134,114			137,158
Total equity attributable to Key		714,316			707,017
Noncontrolling interest		33,110			36,123
Total equity		747,426			743,140
TOTAL LIABILITIES AND EQUITY	$	1,680,975		$	1,664,410

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

4

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
REVENUES	$	283,739		$	215,349		$	803,483		$	718,059
COSTS AND EXPENSES:
Direct operating expenses		198,158			156,444			583,531			497,091
Depreciation and amortization expense		32,565			38,680			98,367			114,685
General and administrative expenses		46,833			39,350			130,726			129,815
Asset retirements and impairments		—			97,035			—			97,035
Interest expense, net of amounts capitalized		10,626			9,137			31,614			29,240
Other, net		(780	)		1,534			(1,556	)		(688	)
Total costs and expenses, net		287,402			342,180			842,682			867,178
Loss from continuing operations before tax		(3,663	)		(126,831	)		(39,199	)		(149,119	)
Income tax benefit		1,383			47,751			14,979			56,228
Loss from continuing operations		(2,280	)		(79,080	)		(24,220	)		(92,891	)
Income (loss) from discontinued operations, net of tax (expense) benefit of $(5,515), $25,438, $(11,044) and $27,394, respectively		8,283			(45,937	)		18,360			(49,695	)
Net income (loss)		6,003			(125,017	)		(5,860	)		(142,586	)
Loss attributable to noncontrolling interest		769			75			2,816			75
INCOME (LOSS) ATTRIBUTABLE TO KEY	$	6,772		$	(124,942	)	$	(3,044	)	$	(142,511	)
Basic and diluted (loss) income per share:
Loss per share from continuing operations attributable to Key	$	(0.01	)	$	(0.65	)	$	(0.17	)	$	(0.77	)
Income (loss) per share from discontinued operations		0.06			(0.38	)		0.15			(0.41	)
Income (loss) per share attributable to Key	$	0.05		$	(1.03	)	$	(0.02	)	$	(1.18	)
Loss from continuing operations attributable to Key:
Loss from continuing operations	$	(2,280	)	$	(79,080	)	$	(24,220	)	$	(92,891	)
Loss attributable to noncontrolling interest		769			75			2,816			75
Loss from continuing operations attributable to Key	$	(1,511	)	$	(79,005	)	$	(21,404	)	$	(92,816	)
Weighted average shares outstanding:
Basic and diluted		125,637			121,277			125,336			120,983

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

5

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
LOSS FROM CONTINUING OPERATIONS	$	(2,280	)	$	(79,080	)	$	(24,220	)	$	(92,891	)
Other comprehensive income (loss), net of tax:
Foreign currency translation gain (loss)		446			(1,026	)		(945	)		(5,516	)
Deferred gain from available for sale investments		—			—			—			30
Total other comprehensive income (loss), net of tax		446			(1,026	)		(945	)		(5,486	)
COMPREHENSIVE LOSS FROM CONTINUING OPERATIONS, NET OF TAX		(1,834	)		(80,106	)		(25,165	)		(98,377	)
Comprehensive income (loss) from discontinued operations		8,283			(45,937	)		18,360			(49,695	)
COMPREHENSIVE INCOME (LOSS)		6,449			(126,043	)		(6,805	)		(148,072	)
Comprehensive (income) loss attributable to noncontrolling interest		(189	)		206			3,013			206
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO KEY	$	6,260		$	(125,837	)	$	(3,792	)	$	(147,866	)

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

6

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

	Nine Months Ended September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(5,860	)	$	(142,586	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization expense		105,125			132,424
Asset retirements and impairments		—			159,802
Bad debt expense		452			3,293
Accretion of asset retirement obligations		388			405
(Income) loss from equity method investments		(723	)		796
Amortization of deferred financing costs and discount		1,967			1,568
Deferred income tax benefit		(5,953	)		(55,359	)
Capitalized interest		(3,055	)		(3,556	)
Loss on disposal of assets, net		492			1,284
Loss on sale of available for sale investments, net		—			30
Share-based compensation		9,001			4,881
Excess tax benefits from share-based compensation		(1,966	)		—
Changes in working capital:
Accounts receivable		(86,530	)		195,976
Other current assets		51,532			11,798
Accounts payable, accrued interest and accrued expenses		26,809			(113,069	)
Share-based compensation liability awards		733			517
Other assets and liabilities		(1,985	)		(623	)
Net cash provided by operating activities		90,427			197,581
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(101,065	)		(102,971	)
Proceeds from sale of fixed assets		20,502			5,184
Acquisitions, net of cash acquired of $0 and $28,362		—			12,007
Dividend from equity method investments		165			199
Net cash used in investing activities		(80,398	)		(85,581	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt		(6,970	)		(1,539	)
Repayments of capital lease obligations		(6,891	)		(8,505	)
Proceeds from borrowings on revolving credit facility		30,000			—
Repayments on revolving credit facility		(30,000	)		(100,000	)
Repurchases of common stock		(2,357	)		(248	)
Proceeds from exercise of stock options		2,248			1,192
Excess tax benefits from share-based compensation		1,966			—
Net cash used in financing activities		(12,004	)		(109,100	)
Effect of changes in exchange rates on cash		(1,366	)		(2,508	)
Net (decrease) increase in cash and cash equivalents		(3,341	)		392
Cash and cash equivalents, beginning of period		37,394			92,691
Cash and cash equivalents, end of period	$	34,053		$	93,083

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

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Key Energy Services, Inc., and Subsidiaries
NOTES TO UNAUDITED CONDENSED CONSOLIDATED 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. On October 1, 2010, we completed the sale of our pressure pumping and wireline businesses to Patterson-UTI Energy (“Patterson-UTI”), which significantly reduced our involvement in these lines of business in the United States. We operate in most major oil and natural gas producing regions of the United States as well as internationally in Latin America, 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 nine month periods ended September 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 issued. After the balance sheet date included in this Quarterly Report on Form 10-Q but before the financial statements were issued, we closed the sale of our pressure pumping and wireline business to Patterson-UTI that required disclosure as a subsequent event. In addition, we closed the acquisition of certain subsidiaries of OFS Energy Services, LLC (“OFS ES”) and related assets. See “Note 17. Subsequent Events” for further discussion.

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

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)

8

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.

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

New Accounting Standards Adopted in this Report

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

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

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

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

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

9

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 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 prospectively 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 September 30, 2010 and December 31, 2009:

	September 30,		December 31,
	2010		2009
	(in thousands)
Other Current Assets:
Deferred tax assets	$	20,410	$	25,323
Prepaid current assets		10,313		14,212
Income tax refund receivable		1,055		50,025
Reinsurance receivable		8,904		8,136
Other		7,660		6,928
Total	$	48,342	$	104,624

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

	September 30,		December 31,
	2010		2009
	(in thousands)
Other Current Liabilities:
Accrued payroll, taxes and employee benefits	$	42,490	$	33,953
Accrued operating expenditures		38,511		24,194
Income, sales, use and other taxes		21,470		30,447
Self-insurance reserve		32,238		24,366
Accrued interest		12,247		3,014
Insurance premium financing		1,602		7,282
Unsettled legal claims		2,240		2,665
Share-based compensation liabilities		1,581		1,518
Other		6,016		6,092
Total	$	158,395	$	133,531

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

	September 30,		December 31,
	2010		2009
	(in thousands)
Other Noncurrent Assets:
Deposits	$	1,117	$	1,008
Reinsurance receivable		8,896		9,050
Other		3,794		2,838
Total	$	13,807	$	12,896

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

	September 30,		December 31,
	2010		2009
	(in thousands)
Other Noncurrent Liabilities:
Deferred tax liabilities	$	138,171	$	146,980
Accrued insurance costs		33,868		40,855
Asset retirement obligations		10,118		10,045
Environmental liabilities		3,035		3,353
Income, sales, use and other taxes		9,090		2,813
Accrued rent		2,107		2,399
Share-based compensation liabilities		713		508
Other		3,552		599
Total	$	200,654	$	207,552

NOTE 4. GOODWILL AND OTHER INTANGIBLE ASSETS

     The changes in the carrying amount of goodwill for the nine months ended September 30, 2010 are as follows:

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				Production
	Well Servicing			Services		Total
	(in thousands)
December 31, 2009	$	342,023		$	4,079	$	346,102
Purchase price and other adjustments, net		3,750			—		3,750
Impact of foreign currency translation		(151	)		78		(73	)
September 30, 2010	$	345,622		$	4,157	$	349,779

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

	September 30,			December 31,
	2010			2009
	(In thousands)
Noncompete agreements:
Gross carrying value	$	14,009		$	14,010
Accumulated amortization		(7,559	)		(5,618	)
Net carrying value	$	6,450		$	8,392
Patents, trademarks and tradename:
Gross carrying value	$	10,606		$	10,481
Accumulated amortization		(891	)		(917	)
Net carrying value	$	9,715		$	9,564
Customer relationships and contracts:
Gross carrying value	$	41,371		$	41,389
Accumulated amortization		(25,180	)		(19,947	)
Net carrying value	$	16,191		$	21,442
Developed technology:
Gross carrying value	$	2,976		$	3,073
Accumulated amortization		(2,160	)		(1,724	)
Net carrying value	$	816		$	1,349
Customer backlog:
Gross carrying value	$	722		$	724
Accumulated amortization		(529	)		(423	)
Net carrying value	$	193		$	301

     The changes in the carrying amount of other intangible assets are as follows (in thousands):

December 31, 2009	$	41,048
Additions		246
Amortization expense		(8,043	)
Impact of foreign currency translation		114
September 30, 2010	$	33,365

     The weighted average remaining amortization periods and expected amortization expense for the next five years for our intangible assets are as follows:

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	Weighted
	average
	remaing amortization		Expected Amortization Expense
	period (years)		Q4 2010		2011		2012		2013		2014		2015
							(In thousands)
Noncompete agreements		2.7	$	660	$	2,620	$	2,423	$	406	$	338	$	—
Patents, trademarks and tradename		4.8		84		289		183		127		120		105
Customer relationships and contracts		7.7		1,481		4,224		3,056		2,208		1,670		1,299
Customer backlog		0.9		76		122		—		—		—		—
Developed technology		0.9		312		499		—		—		—		—
Total intangible asset amortization expense			$	2,613	$	7,754	$	5,662	$	2,741	$	2,128	$	1,404

     Certain of our goodwill and other intangible assets are denominated in currencies other than U.S. dollars and, as such, the values of these assets are subject to fluctuations associated with changes in exchange rates. Amortization expense for our intangible assets was $2.9 million and $3.1 million for the three months ended September 30, 2010 and 2009, respectively, and $8.0 million and $9.9 million for the nine months ended September 30, 2010 and 2009, respectively. The purchase price allocation for our 2009 acquisition of Geostream Services Group (“Geostream”) was finalized in 2010.

Goodwill Impairment Test

     On September 1, 2009, we acquired an additional 24% interest in Geostream for $16.4 million. This was our second investment in Geostream, bringing our total investment in Geostream to 50% of the outstanding equity interests. Upon increasing our ownership interest to 50%, we also obtained majority representation on Geostream’s board of directors and a controlling interest, and we now fully consolidate the assets, liabilities and results of operations of Geostream, with the 50% that remains outside our control representing a noncontrolling interest. We accounted for this transaction as an acquisition performed in stages. Prior to the date we increased our ownership interest in Geostream to 50%, we accounted for our 26% interest in Geostream as an equity-method investment. On the date we increased our ownership interest in Geostream to 50%, we recorded $23.9 million of goodwill, which represented the difference between the fair value of the total consideration transferred to acquire the 50% interest and the fair value of the assets acquired and liabilities assumed on the acquisition date. We perform an annual goodwill impairment test for our Russian reporting unit on September 30 of each year, or more frequently if circumstances warrant.

     Under the first step of the goodwill impairment test, we compared the fair value of the reporting unit to its carrying amount, including goodwill. The first step of the goodwill impairment test showed that the fair value of the reporting unit exceeded the carrying value by 10.8%. In determining the fair value of the reporting unit, we used a weighted-average approach of three commonly used valuation techniques — a discounted cash flow method, a guideline companies method, and a similar transactions method. We assigned a weight to the results of each of these methods based on the facts and circumstances in existence at the testing period. Because of our expansion into Russia and the overall economic downturn that affected most companies’ stock prices and market valuation in 2010, we assigned more weight to the discounted cash flow method. Our cash flow projections were based on financial forecasts developed by management and were discounted using a rate of 16%. A key assumption in our model is that revenue related to this reporting unit will increase in future years. Potential events that could affect this assumption are the level of development, exploration and production activity of, and corresponding capital spending by, oil and natural gas companies in the Russian Federation, oil and natural gas production costs, government regulations and conditions in the worldwide oil and natural gas industry.

     This test concluded that the fair value of the Russian reporting unit exceeded its carrying value. Therefore, the second step of the goodwill impairment test was not required. Our remaining reporting units will be tested for potential impairment on December 31, 2010, the annual testing date.

     We also performed an impairment analysis for the $8.4 million of intangible assets related to Geostream that are not amortized. We performed an assessment of the fair value of these assets using an expected present value technique. We used a discounted cash flow model involving assumptions based on forecasted revenues, projected royalty expenses and applicable income taxes. Our cash flow projections were based on financial forecasts developed by management. Based on this assessment, these intangible assets were not impaired.

NOTE 5. EQUITY METHOD INVESTMENT

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IROC Energy Services Corp.

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

     We recorded $0.1 million and $0.2 million of equity losses related to our investment in IROC for the three months ended September 30, 2010 and 2009, respectively, and $0.8 million and $0.1 million of equity income for the nine months ended September 30, 2010 and 2009, respectively.

NOTE 6. LONG-TERM DEBT

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

	September 30,		December 31,
	2010		2009
	(in thousands)
8.375% Senior Notes due 2014	$	425,000	$	425,000
Senior Secured Credit Facility revolving loans due 2012		87,813		87,813
Other long-term indebtedness		—		1,044
Notes payable -related parties, net of discount of $69		—		5,931
Capital lease obligations		7,460		14,313
		520,273		534,101
Less current portion		4,397		10,152
Total capital leases, notes payable and long-term debt	$	515,876	$	523,949

Related Party Note

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

8.375% Senior Notes due 2014

     We have $425.0 million aggregate principal amount of 8.375% Senior Notes due 2014 (the “Senior Notes”). The Senior Notes are general unsecured senior obligations and are subordinate to all of our existing and future secured indebtedness. The Senior Notes are or will be jointly and severally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. Interest on the Senior Notes is payable on June 1 and December 1 of each year. The Senior Notes mature on December 1, 2014.

     The indenture governing the Senior Notes contains various covenants. These covenants are subject to certain exceptions and qualifications, and contain cross-default provisions tied to the covenants of our Senior Secured Credit

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Facility (defined below). We were in compliance with these covenants at September 30, 2010.

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”). The Senior Secured Credit Facility (which was amended October 27, 2009) 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 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, 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.

     The Senior Secured Credit Facility also contains certain other covenants, including 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; in each of the foregoing cases, with certain exceptions.

     We were in compliance with these covenants on September 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 September 30, 2010, we had borrowings of $87.8 million and committed letters of credit of $58.8 million outstanding, leaving $153.4 million of available borrowing capacity under the Senior Secured Credit Facility. On October 1, 2010 we borrowed $80.0 million under the credit facility to acquire certain subsidiaries of OFS ES (see “Note 17. Subsequent Events”). We subsequently repaid the entire $167.8 million outstanding balance of the revolving credit facility as of October 4, 2010 with a portion of the proceeds from the Patterson-UTI transaction (see “Note 17. Subsequent Events”). The weighted average interest rate on the outstanding borrowings under the Senior Secured Credit Facility at September 30, 2010 was 4.12%.

Capital Leases

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

NOTE 7. 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:

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
(Gain) loss on disposal of assets, net	$	(146	)	$	1,942		$	509		$	566
Interest income		(5	)		(42	)		(41	)		(459	)
Foreign exchange loss (gain), net		30			(1,305	)		(479	)		(1,358	)
Other (income) expense, net		(659	)		939			(1,545	)		563
Total	$	(780	)	$	1,534		$	(1,556	)	$	(688	)

NOTE 8. INCOME TAXES

     We recorded $1.4 million and $47.8 million of tax benefit on pretax losses of $3.7 million and $126.8 million for continuing operations for the three months ended September 30, 2010 and 2009, respectively. Our effective tax rates for our continuing operations for the three months ended September 30, 2010 and 2009 were 37.8% and 37.6%, respectively. We recorded $15.0 million and $56.2 million of tax benefit on pretax losses of $39.2 million and $149.1 million from our continuing operations for the nine months ended September 30, 2010 and 2009, respectively. Our effective tax rates for our continuing operations for the nine months ended September 30, 2010 and 2009 were 38.2% and 37.7%, respectively. The variance quarter over quarter 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, including accrual to return adjustments, increases or decreases to valuation allowances, and tax expense or benefits recognized for uncertain tax positions.

     As of September 30, 2010 and December 31, 2009, we had $2.4 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 benefit of $0.9 million in the quarter ended September 30, 2010 and a tax benefit of $1.1 million for the quarter ended September 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 $1.0 million and $1.1 million for the payment of interest and penalties as of September 30, 2010 and December 31, 2009, respectively. We believe that it is reasonably possible that $0.8 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.

     During the quarter ended March 31, 2010, we filed our 2009 tax return reflecting a net operating loss of $153.5 million. We also filed a claim for refund of federal income taxes paid in prior 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 September 30, 2010, the aggregate amount of our liabilities related to litigation that are deemed probable and reasonably estimable is $2.2 million. We do not believe that the disposition of any of these matters will result in an

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

Litigation with a Former Officer

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

UMMA Verdict

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

Self-Insurance Reserves

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

Environmental Remediation Liabilities

     For environmental reserve matters, including remediation efforts for current locations and those relating to previously-disposed properties, we record liabilities when our remediation efforts are probable and the costs to conduct such remediation efforts can be reasonably estimated. While our litigation reserves reflect the application of our insurance coverage, our environmental reserves do not reflect management’s assessment of the insurance coverage that may apply to the matters at issue. As of September 30, 2010 and December 31, 2009, we have recorded $3.0 million and $3.4 million, respectively, for our environmental remediation liabilities. 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.

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NOTE 10. EARNINGS PER SHARE

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

     The components of our earnings per share are as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(in thousands, except per share amounts)
Basic EPS Calculation:
Numerator
Loss from continuing operations attributable to Key	$	(1,511	)	$	(79,005	)	$	(21,404	)	$	(92,816	)
Income (loss) from discontinued operations, net of tax		8,283			(45,937	)		18,360			(49,695	)
Income (loss) attributable to Key	$	6,772		$	(124,942	)	$	(3,044	)	$	(142,511	)
Denominator
Weighted average shares outstanding		125,637			121,277			125,336			120,983
Basic loss per share from continuing operations attributable to Key	$	(0.01	)	$	(0.65	)	$	(0.17	)	$	(0.77	)
Basic income (loss) per share from discontinued operations		0.06			(0.38	)		0.15			(0.41	)
Basic income (loss) per share attributable to Key	$	0.05		$	(1.03	)	$	(0.02	)	$	(1.18	)
Diluted EPS Calculation:
Numerator
Loss from continuing operations attributable to Key	$	(1,511	)	$	(79,005	)	$	(21,404	)	$	(92,816	)
Income (loss) from discontinued operations, net of tax		8,283			(45,937	)		18,360			(49,695	)
Income (loss) attributable to Key	$	6,772		$	(124,942	)	$	(3,044	)	$	(142,511	)
Denominator
Weighted average shares outstanding		125,637			121,277			125,336			120,983
Diluted loss per share from continuing operations attributable to Key	$	(0.01	)	$	(0.65	)	$	(0.17	)	$	(0.77	)
Diluted income (loss) per share from discontinued operations		0.06			(0.38	)		0.15			(0.41	)
Diluted income (loss) per share attributable to Key	$	0.05		$	(1.03	)	$	(0.02	)	$	(1.18	)

     Because of our loss from continuing operations for the three and nine months ended September 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. On October 1, 2010 we completed the acquisition of certain subsidiaries and related assets of OFS ES. Upon the closing of this transaction, we issued approximately 15.8 million shares of our common stock (the “Consideration Shares”) as part of the total purchase price. The Consideration Shares will impact our basic and diluted weighted average shares outstanding beginning in the fourth quarter of 2010. See “Note 17. Subsequent Events” for further discussion.

NOTE 11. SHARE-BASED COMPENSATION

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

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     The unrecognized compensation cost related to our unvested stock options, restricted shares and phantom shares as of September 30, 2010 is estimated to be $0.1 million, $13.3 million and $0.5 million, respectively, and is expected to be recognized over a weighted-average period of 1.2 years, 1.2 years and 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 a peer group consisting of Key and five other companies. If we are in the top third of the peer group, 100% of the performance units will vest; if we are in the middle third, 50% will vest; and if we are in the bottom third, the performance units will expire unvested and no payment will be made. If any performance units vest for a given performance period, the award holder will be paid a cash amount 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 September 30, 2010, the fair value of outstanding performance units issued in March 2010 was $2.2 million, and is being accreted to compensation expense over the vesting terms of the awards. During the three and nine months ended September 30, 2010, we recognized $0.2 million and $0.9 million, respectively, of pre-tax compensation expense associated with these awards. As of September 30, 2010, the unrecognized compensation cost related to our unvested performance units is estimated to be $1.3 million and is expected to be recognized over a weighted-average period of 1.1 years.

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

NOTE 12. TRANSACTIONS WITH RELATED PARTIES

Related Party Notes Payable

     On May 13, 2010, we repaid the outstanding principal balance of $6.0 million of the Related Party Note, plus accrued and unpaid interest. This note was repaid concurrently with the sale of six operational barge rigs and related equipment to the holders of the note for total consideration of $17.9 million. We received net proceeds, after repayment of the note, of $11.9 million and recorded a $0.6 million loss on the sale of these assets.

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 where the services are provided. As of September 30, 2010, our receivables with this company totaled $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 4% and 2% of our total revenues for the nine months ended September 30, 2010 and 2009, respectively. Sales to Anadarko were approximately 6% and 2% of our total revenues for the three months ended September 30, 2010 and 2009, respectively. Receivables outstanding from Anadarko were approximately 6% and 1% of our total accounts receivable as of September 30, 2010 and December 31, 2009, respectively. Transactions with Anadarko for our services are made on terms consistent with other customers.

NOTE 13. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

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          The following is a summary of the carrying amounts and estimated fair values of our financial instruments as of September 30, 2010 and December 31, 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.

	September 30, 2010				December 31, 2009
	Carrying Value		Fair Value		Carrying Value		Fair Value
			(in thousands)
Financial assets:
Notes and accounts receivable - - related parties	$	588	$	588	$	281	$	281
Financial liabilities:
8.375% Senior Notes	$	425,000	$	449,438	$	425,000	$	422,875
Senior Secured Credit Facility revolving loans		87,813		87,813		87,813		87,813
Note payable — related parties		—		—		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 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 September 30, 2010 was $425.0 million and the fair value was $449.4 million (105.75% 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 September 30, 2010 were $87.8 million.

          Note payable – related parties. The amounts reported relate to the Related Party Note in connection with a seller financing arrangement entered into in connection with an acquisition made in 2007. The outstanding balance of this note was repaid on May 13, 2010.

NOTE 14. SEGMENT INFORMATION

     As of September 30, 2010, 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. As mentioned in “Note 1. General,” on October 1, 2010, we completed the sale of our pressure pumping and wireline businesses to Patterson-UTI, which significantly reduced our involvement in these lines of business. We anticipate revising our reportable segments in the fourth quarter of 2010 to realign our current business and management structure. The following is a description of our segments as of September 30, 2010:

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 specialty drilling services to oil and natural gas producers with certain of our larger Well Servicing rigs that are capable of

20

providing conventional and horizontal drilling services. Based on current industry data, we have the largest land-based 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 in a well, removing debris from the wellbore, and pulling the rods and other downhole equipment out of the wellbore to identify and resolve a production problem. Maintenance services generally take less than 48 hours to complete and, in general, the demand for these services is closely related to the total number of producing oil and gas wells in a given market.

          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 wellbores into new formations by drilling horizontal or lateral 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 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 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 a saltwater disposal 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 from formations which exhibit restricted flow. In the fracturing process, we typically pump fluid and sized sand, or proppants, into a well at high pressure in order to fracture the formation and thereby increase the flow of oil and natural gas. With our cementing services, we pump cement into a well

21

between the casing and the 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 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.

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

     Fishing and Rental Services

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

     Wireline Services

          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 wellbore is cased and cemented, we can provide a number of services. Perforating creates the flow path between the reservoir and the wellbore. Production logging can be performed throughout the life of the well to measure temperature, fluid type, flow rate, pressure and other reservoir characteristics. This service helps the operator analyze and monitor well performance and determine when a well may need a workover or further stimulation.

          In addition, wireline services may involve 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 wellbore. We use advanced wireline instruments to evaluate well integrity and perform cement evaluations and production logging. As discussed above and in “Note 16. Discontinued Operations” and “Note 17. Subsequent Events,” we closed the sale of our U.S. based pressure pumping and wireline businesses to Patterson-UTI. For the periods presented in this report, we show these assets as held for sale and the results of operations for our wireline operations as discontinued operations for all periods presented.

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 nine month periods ended September 30, 2010 and 2009:

22

For the three months ended September 30, 2010:

				Production			Functional			Reconciling
	Well Servicing			Services			Support			Eliminations			Total
Revenues from external customers	$	244,288		$	39,451		$	—		$	—		$	283,739
Intersegment revenues		82			2,834			—			(2,916	)		—
Depreciation and amortization		24,213			5,719			2,633			—			32,565
Operating income (loss)		25,348			9,660			(28,825	)		—			6,183
Interest expense, net of amounts capitalized		(21	)		(88	)		10,735			—			10,626
Income (loss) from continuing operations before tax		25,380			9,593			(38,636	)		—			(3,663	)
Total assets		1,350,262			325,242			223,055			(217,584	)		1,680,975
Capital expenditures, excluding acquisitions		17,520			6,889			8,733			—			33,142

For the three months ended September 30, 2009:

				Production			Functional			Reconciling
	Well Servicing			Services			Support			Eliminations			Total
Revenues from external customers	$	194,071		$	21,278		$	—		$	—		$	215,349
Intersegment revenues		—			2,014			—			(2,014	)		—
Depreciation and amortization		28,757			7,578			2,345			—			38,680
Asset retirements and impairments		65,869			31,166			—			—			97,035
Operating (loss) income		(57,953	)		(31,732	)		(26,475	)		—			(116,160	)
Interest expense, net of amounts capitalized		(607	)		(62	)		9,806			—			9,137
Loss from continuing operations before tax		(58,889	)		(31,487	)		(36,455	)		—			(126,831	)
Total assets		1,155,860			252,483			648,956			(388,472	)		1,668,827
Capital expenditures, excluding acquisitions		24,125			7,705			3,732			—			35,562

23

For the nine months ended September 30, 2010:

				Production			Functional			Reconciling
	Well Servicing			Services			Support			Eliminations			Total
Revenues from external customers	$	701,025		$	102,458		$	—		$	—		$	803,483
Intersegment revenues		233			5,825			—			(6,058	)		—
Depreciation and amortization		74,599			16,534			7,234			—			98,367
Operating income (loss)		56,882			15,494			(81,517	)		—			(9,141	)
Interest expense, net of amounts capitalized		(845	)		(154	)		32,613			—			31,614
Income (loss) from continuing operations before tax		57,947			15,046			(112,192	)		—			(39,199	)
Total assets		1,350,262			325,242			223,055			(217,584	)		1,680,975
Capital expenditures, excluding acquisitions		48,742			29,898			22,425			—			101,065

For the nine months ended September 30, 2009:

				Production			Functional			Reconciling
	Well Servicing			Services			Support			Eliminations			Total
Revenues from external customers	$	648,277		$	69,782		$	—		$	—		$	718,059
Intersegment revenues		6			3,910			—			(3,916	)		—
Depreciation and amortization		88,009			19,956			6,720			—			114,685
Asset retirements and impairments		65,869			31,166			—			—			97,035
Operating loss		(1,416	)		(38,888	)		(80,263	)		—			(120,567	)
Interest expense, net of amounts capitalized		(1,494	)		(390	)		31,124			—			29,240
Loss from continuing operations before tax		(617	)		(37,559	)		(110,943	)		—			(149,119	)
Total assets		1,155,860			252,483			648,956			(388,472	)		1,668,827
Capital expenditures, excluding acquisitions		56,709			36,532			9,730			—			102,971

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

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	U.S.		International		Eliminations			Total
	(in thousands)
As of and for the three months ended September 30, 2010
Revenue from external customers	$	242,142	$	41,597	$	—		$	283,739
Long-lived assets		1,158,994		106,679		—			1,265,673
As of and for the three months ended September 30, 2009
Revenue from external customers	$	168,601	$	46,748	$	—		$	215,349
Long-lived assets		1,240,845		131,940		(88,881	)		1,283,904
As of and for the nine months ended September 30, 2010
Revenue from external customers	$	662,671	$	140,812	$	—		$	803,483
Long-lived assets		1,158,994		106,679		—			1,265,673
As of and for the nine months ended September 30, 2009
Revenue from external customers	$	579,881	$	138,178	$	—		$	718,059
Long-lived assets		1,240,845		131,940		(88,881	)		1,283,904

NOTE 15. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

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

          As a result of these guaranteed arrangements, we are required to present the following condensed consolidating financial information pursuant to SEC Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered.”

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CONDENSED CONSOLIDATING BALANCE SHEETS

	September 30, 2010
			Guarantor		Non-Guarantor
	Parent Company		Subsidiaries		Subsidiaries			Eliminations			Consolidated
	(in thousands) (unaudited)
Assets:
Current assets	$	19,232	$	294,348	$	101,722		$	—		$	415,302
Property and equipment, net		—		738,598		48,254			—			786,852
Goodwill		—		320,264		29,515			—			349,779
Deferred financing costs, net		8,460		—		—			—			8,460
Intercompany notes and accounts receivable and investment in subsidiaries		1,879,726		625,135		5,033			(2,509,894	)		—
Other assets		4,818		36,218		12,282			—			53,318
Noncurrent assets held for sale		—		67,264		—			—			67,264
TOTAL ASSETS	$	1,912,236	$	2,081,827	$	196,806		$	(2,509,894	)	$	1,680,975
Liabilities and equity:
Current liabilities		16,356		151,385		49,278			—			217,019
Long-term debt and capital leases, less current portion		512,813		3,053		10			—			515,876
Intercompany notes and accounts payable		481,207		1,583,966		103,323			(2,168,496	)		—
Deferred tax liabilities		153,037		—		(14,866	)		—			138,171
Other long-term liabilities		1,398		61,085		—			—			62,483
Equity		747,425		282,338		59,061			(341,398	)		747,426
TOTAL LIABILITIES AND EQUITY	$	1,912,236	$	2,081,827	$	196,806		$	(2,509,894	)	$	1,680,975

	December 31, 2009
			Guarantor		Non-Guarantor
	Parent Company		Subsidiaries		Subsidiaries			Eliminations			Consolidated
	(in thousands)
Assets:
Current assets	$	72,021	$	189,935	$	122,018		$	158		$	384,132
Property and equipment, net		—		752,543		41,726			—			794,269
Goodwill		—		316,513		29,589			—			346,102
Deferred financing costs, net		10,421		—		—			—			10,421
Intercompany notes and accounts receivable and investment in subsidiaries		1,782,002		577,546		7,462			(2,367,010	)		—
Other assets		4,033		40,198		14,916			—			59,147
Noncurrent assets held for sale		—		70,339		—			—			70,339
TOTAL ASSETS	$	1,868,477	$	1,947,074	$	215,711		$	(2,366,852	)	$	1,664,410
Liabilities and equity:
Current liabilities	$	6,468	$	145,040	$	38,261		$	—		$	189,769
Long-term debt and capital leases, less current portion		512,812		11,105		32			—			523,949
Intercompany notes and accounts payable		451,361		1,487,950		87,568			(2,026,879	)		—
Deferred tax liabilities		151,624		—		(4,644	)		—			146,980
Other long-term liabilities		3,072		57,500		—			—			60,572
Equity		743,140		245,479		94,494			(339,973	)		743,140
TOTAL LIABILITIES AND EQUITY	$	1,868,477	$	1,947,074	$	215,711		$	(2,366,852	)	$	1,664,410

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CONDENSED CONSOLIDATING UNAUDITED STATEMENTS OF OPERATIONS

	Three Months Ended September 30, 2010
				Guarantor			Non-Guarantor
	Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands) (unaudited)
Revenues	$	—		$	253,076		$	43,635		$	(12,972	)	$	283,739
Costs and expenses:
Direct operating expense		—			162,640			45,546			(10,028	)		198,158
Depreciation and amortization expense		—			30,315			2,250			—			32,565
General and administrative expense		337			41,178			6,677			(1,359	)		46,833
Interest expense, net of amounts capitalized		11,361			(949	)		214			—			10,626
Other, net		18			(1,348	)		2,135			(1,585	)		(780	)
Total costs and expenses, net		11,716			231,836			56,822			(12,972	)		287,402
(Loss) income from continuing operations before taxes		(11,716	)		21,240			(13,187	)		—			(3,663	)
Income tax (expense) benefit		(12,031	)		5,759			7,655			—			1,383
(Loss) income from continuing operations		(23,747	)		26,999			(5,532	)		—			(2,280	)
Discontinued operations		—			8,283			—			—			8,283
Net (loss) income		(23,747	)		35,282			(5,532	)		—			6,003
Loss attributable to noncontrolling interest		—			—			769			—			769
(LOSS) INCOME ATTRIBUTABLE TO KEY	$	(23,747	)	$	35,282		$	(4,763	)	$	—		$	6,772

	Three Months Ended September 30, 2009
				Guarantor			Non-Guarantor
	Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands) (unaudited)
Revenues	$	—		$	180,910		$	47,960		$	(13,521	)	$	215,349
Costs and expenses:
Direct operating expense		—			123,751			43,492			(10,799	)		156,444
Depreciation and amortization expense		—			37,087			1,593			—			38,680
General and administrative expense		(891	)		35,975			4,266			—			39,350
Asset retirements and impairments		—			97,035			—			—			97,035
Interest expense, net of amounts capitalized		10,367			(1,326	)		96			—			9,137
Other, net		195			1,836			2,183			(2,680	)		1,534
Total costs and expenses, net		9,671			294,358			51,630			(13,479	)		342,180
(Loss) income from continuing operations before taxes		(9,671	)		(113,448	)		(3,670	)		(42	)		(126,831	)
Income tax benefit (expense)		70,143			(25,438	)		3,045			1			47,751
Income (loss) from continuing operations		60,472			(138,886	)		(625	)		(41	)		(79,080	)
Discontinued operations		—			(45,937	)		—			—			(45,937	)
Net income (loss)		60,472			(184,823	)		(625	)		(41	)		(125,017	)
Loss attributable to noncontrolling interest		—			—			75			—			75
INCOME (LOSS) ATTRIBUTABLE TO KEY	$	60,472		$	(184,823	)	$	(550	)	$	(41	)	$	(124,942	)

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	Nine Months Ended September 30, 2010
				Guarantor			Non-Guarantor
	Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands) (unaudited)
Revenues	$	—		$	702,221		$	144,187		$	(42,925	)	$	803,483
Costs and expenses:
Direct operating expense		—			459,021			156,333			(31,823	)		583,531
Depreciation and amortization expense		—			91,410			6,957			—			98,367
General and administrative expense		1,630			114,383			17,981			(3,268	)		130,726
Interest expense, net of amounts capitalized		34,034			(2,659	)		239			—			31,614
Other, net		(997	)		(730	)		8,005			(7,834	)		(1,556	)
Total costs and expenses, net		34,667			661,425			189,515			(42,925	)		842,682
(Loss) income from continuing operations before taxes		(34,667	)		40,796			(45,328	)		—			(39,199	)
Income tax (expense) benefit		(5,068	)		11,287			8,760			—			14,979
(Loss) income from continuing operations		(39,735	)		52,083			(36,568	)		—			(24,220	)
Discontinued operations		—			18,360			—			—			18,360
Net (loss) income		(39,735	)		70,443			(36,568	)		—			(5,860	)
Net loss attributable to noncontrolling interest		—			—			2,816			—			2,816
(LOSS) INCOME ATTRIBUTABLE TO KEY	$	(39,735	)	$	70,443		$	(33,752	)	$	—		$	(3,044	)

	Nine Months Ended September 30, 2009
				Guarantor			Non-Guarantor
	Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands) (unaudited)
Revenues	$	—		$	609,167		$	141,520		$	(32,628	)	$	718,059
Costs and expenses:
Direct operating expense		—			409,243			112,532			(24,684	)		497,091
Depreciation and amortization expense		—			110,091			4,594			—			114,685
General and administrative expense		58			116,593			13,136			28			129,815
Asset retirements and impairments		—			97,035			—			—			97,035
Interest expense, net of amounts capitalized		31,828			(2,738	)		150			—			29,240
Other, net		551			224			7,504			(8,967	)		(688	)
Total costs and expenses, net		32,437			730,448			137,916			(33,623	)		867,178
(Loss) income from continuing operations before taxes		(32,437	)		(121,281	)		3,604			995			(149,119	)
Income tax benefit (expense)		83,815			(27,394	)		(193	)		—			56,228
Income (loss) from continuing operations		51,378			(148,675	)		3,411			995			(92,891	)
Discontinued operations		—			(49,695	)		—			—			(49,695	)
Net income (loss)		51,378			(198,370	)		3,411			995			(142,586	)
Net loss attributable to noncontrolling interest		—			—			75			—			75
INCOME (LOSS)  ATTRIBUTABLE TO KEY	$	51,378		$	(198,370	)	$	3,486		$	995		$	(142,511	)

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CONDENSED CONSOLIDATING UNAUDITED STATEMENTS OF CASH FLOWS

	Nine Months Ended September 30, 2010
				Guarantor			Non-Guarantor
	Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
	(unaudited)
Net cash provided by (used in) operating activities	$	—		$	98,362		$	(7,935	)	$	—		$	90,427
Cash flows from investing activities:
Capital expenditures		—			(100,620	)		(445	)		—			(101,065	)
Intercompany notes and accounts		(165	)		(5,034	)		—			5,199			—
Other investing activities, net		165			20,502			—						20,667
Net cash (used in) provided by investing activities		—			(85,152	)		(445	)		5,199			(80,398	)
Cash flows from financing activities:
Repayments of long-term debt		—			(6,970	)		—			—			(6,970	)
Repurchases of common stock		(2,357	)		—			—			—			(2,357	)
Intercompany notes and accounts		5,034			165			—			(5,199	)		—
Other financing activities, net		(2,677	)		—			—			—			(2,677	)
Net cash used in financing activities		—			(6,805	)		—			(5,199	)		(12,004	)
Effect of changes in exchange rates on cash		—			—			(1,366	)		—			(1,366	)
Net increase (decrease) in cash		—			6,405			(9,746	)		—			(3,341	)
Cash and cash equivalents at beginning of period		—			19,391			18,003			—			37,394
Cash and cash equivalents at end of period	$	—		$	25,796		$	8,257		$	—		$	34,053

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	Nine Months Ended September 30, 2009
				Guarantor			Non-Guarantor
	Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
	(unaudited)
Net cash provided by (used in) operating activities	$	—		$	189,119		$	8,462		$	—		$	197,581
Cash flows from investing activities:
Capital expenditures		—			(100,255	)		(2,716	)		—			(102,971	)
Intercompany notes and accounts		82,389			(1,168	)		(6,067	)		(75,154	)		—
Other investing activities, net		199			5,184			12,007			—			17,390
Net cash provided by (used in) investing activities		82,588			(96,239	)		3,224			(75,154	)		(85,581	)
Cash flows from financing activities:
Repayment of long-term debt		(100,000	)		—			—			—			(100,000	)
Intercompany notes and accounts		16,468			(92,677	)		1,055			75,154			—
Other financing activities, net		944			(10,044	)		—			—			(9,100	)
Net cash (used in) provided by financing activities		(82,588	)		(102,721	)		1,055			75,154			(109,100	)
Effect of changes in exchange rates on cash		—			—			(2,508	)		—			(2,508	)
Net (decrease) increase in cash		—			(9,841	)		10,233			—			392
Cash and cash equivalents at beginning of period		—			75,847			16,844			—			92,691
Cash and cash equivalents at end of period	$	—		$	66,006		$	27,077		$	—		$	93,083

NOTE 16. DISCONTINUED OPERATIONS

     On October 1, 2010, we completed the sale of our pressure pumping and wireline businesses to Patterson-UTI. Management determined to sell these businesses because they were not aligned with our core business strategy of well intervention and international expansion. For the periods presented in this report, we show the assets being sold as assets held for sale on 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-UTI were reported as part of our Production Services segment and were based entirely in the U.S. Because the agreed-upon purchase price for the businesses exceeded 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:

	September 30,			December 31,
	2010			2009
	(in thousands)
Inventory	$	9,251		$	3,974
Current assets held for sale		9,251			3,974
Property and equipment, gross		83,416			80,456
Accumulated depreciation		(16,152	)		(10,117	)
Noncurrent assets held for sale		67,264			70,339
Net assets held for sale	$	76,515		$	74,313

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(in thousands)
Revenues	$	76,348		$	22,322		$	197,704		$	93,059
Costs and expenses:
Direct operating expenses		59,111			23,457			154,369			83,890
Depreciation and amortization		—			5,797			6,758			17,739
General and administrative expenses		3,589			1,721			7,510			5,357
Asset retirements and impairments		—			62,767			—			62,767
Other, net		(150	)		(45	)		(337	)		395
Total costs and expenses, net		62,550			93,697			168,300			170,148
Income (loss) before tax		13,798			(71,375	)		29,404			(77,089	)
Income tax (expense) benefit		(5,515	)		25,438			(11,044	)		27,394
Income (loss) from discontinued operations	$	8,283		$	(45,937	)	$	18,360		$	(49,695	)

     In connection with our closing of the Patterson-UTI transaction, we recorded pre-tax charges of $0.5 million in the third quarter of 2010 related to transaction costs. We also anticipate recording a pre-tax gain on the sale of these assets in the fourth quarter of 2010.

NOTE 17. SUBSEQUENT EVENTS

Sale of Pressure Pumping and Wireline Businesses

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

Acquisition

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

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

     The total consideration for the acquisition was approximately 15.8 million shares of our common stock and a cash payment of $75.8 million, subject to certain working capital and other adjustments. We are required to register the shares of common stock issued in the transaction under the Securities Act of 1933, as amended, subject to certain conditions.

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

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Cash	$	75,775
Key common stock		153,962
Total	$	229,737

The fair value of the 15.8 million common shares issued was $9.74 per share based on the closing market price on the acquisition date (October 1, 2010).

     Transaction costs related to this acquisition were $0.6 million through September 30, 2010 and are included in general and administrative expense in the condensed consolidated statements of operations.

     We are in the process of obtaining third-party valuations of certain tangible and intangible assets. The closing of the transaction occurred on October 1, 2010, and as such no revenue or earnings have been included in the consolidated statements of operations through September 30, 2010. We have not disclosed pro forma earnings as these amounts would be calculated after applying our accounting policies and adjusting the results of the OFS ES entities for any fair value adjustments that may result from our third party valuation, which is not complete at this time.

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

OVERVIEW

     Key Energy Services, Inc., its wholly-owned subsidiaries and its controlled subsidiaries (collectively, “Key,” the “Company,” “we,” “us,” “its,” and “our”) provide a complete 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. On October 1, 2010, we completed the sale of our pressure pumping and wireline businesses to Patterson-UTI Energy (“Patterson-UTI”) which significantly reduced our involvement in these lines of business, specifically in the U.S. We operate in most major oil and natural gas producing regions of the United States as well as internationally in Latin America 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 following discussion and analysis should be read in conjunction with the accompanying unaudited condensed consolidated financial statements and related notes 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 Annual Report”).

     Through September 30, 2010, we operated 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 increase. Similarly, as oil and natural gas prices fall, the Baker Hughes U.S. land drilling rig count tends to decline.

			NYMEX Henry		Average Baker
	WTI Cushing Oil		Hub Natural Gas		Hughes U.S. Land
	(1)		(1)		Drilling Rigs (2)
2010:
First Quarter	$	74.78	$	5.14		1,354
Second Quarter	$	74.79	$	4.30		1,513
Third Quarter	$	72.46	$	4.30		1,626
2009:
First Quarter	$	40.16	$	4.60		1,344
Second Quarter	$	55.84	$	3.71		934
Third Quarter	$	66.02	$	3.17		970
Fourth Quarter	$	71.67	$	4.38		1,108

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

     Internally, we measure activity levels in our Well Servicing segment primarily through our rig and trucking hours. Generally, as capital spending by oil and natural gas producers increases, demand for our services also rises, resulting in increased rig and trucking services and more hours worked. Conversely, when activity levels decline due to lower spending by oil and natural gas producers, we generally provide fewer rig and trucking services, which results in lower hours worked.

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We publicly release our monthly rig and trucking hours, and the following table presents our quarterly rig and trucking hours from 2009 through the third quarter of 2010:

	Rig Hours		Trucking Hours
2010:
First Quarter		485,183		459,292
Second Quarter		489,168		518,483
Third Quarter		503,890		559,181
2009:
First Quarter		489,819		499,247
Second Quarter		415,520		416,269
Third Quarter		416,810		398,027
Fourth Quarter		439,552		422,253
Total 2009		1,761,701		1,735,796

MARKET CONDITIONS AND OUTLOOK

Market Conditions — Quarter Ended September 30, 2010

     Overall, market conditions during the third quarter of 2010 continued their recovery from the lows experienced in the second and third quarters of 2009. Within our U.S. well servicing business, our rig hours increased for the fifth consecutive quarter and our trucking hours increased for the fourth consecutive quarter. Although oil and natural gas prices have remained relatively flat over the last several quarters, we continued to see moderate pricing improvements for our rig-based services during the quarter, primarily for our larger equipment in selected oil and shale markets. Our fluid management business continued to expand during the quarter, with much of the increase located in the Bakken Shale.

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

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

Market Outlook

     We expect trends of increased customer spending in the U.S. to continue through the end of 2010, offset by typical seasonality, such as reduced daylight, more holidays and weather. The fourth quarter of 2010 will also be a transition period as we integrate new businesses recently acquired and continue our expansion into new international markets. We believe that the recent strategic moves we have made domestically better position us to capture increased activity related to more complex horizontal drilling and completion techniques.

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

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

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

RESULTS OF OPERATIONS

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
REVENUES	$	283,739		$	215,349		$	803,483		$	718,059
COSTS AND EXPENSES:
Direct operating expenses		198,158			156,444			583,531			497,091
Depreciation and amortization expense		32,565			38,680			98,367			114,685
General and administrative expenses		46,833			39,350			130,726			129,815
Asset retirements and impairments		—			97,035			—			97,035
Interest expense, net of amounts capitalized		10,626			9,137			31,614			29,240
Other, net		(780	)		1,534			(1,556	)		(688	)
Total costs and expenses, net		287,402			342,180			842,682			867,178
Loss from continuing operations before tax		(3,663	)		(126,831	)		(39,199	)		(149,119	)
Income tax benefit		1,383			47,751			14,979			56,228
Loss from continuing operations		(2,280	)		(79,080	)		(24,220	)		(92,891	)
Income (loss) from discontinued operations, net of tax (expense) benefit of $(5,515), $25,438, $(11,044) and $27,394, respectively		8,283			(45,937	)		18,360			(49,695	)
Net income (loss)		6,003			(125,017	)		(5,860	)		(142,586	)
Loss attributable to noncontrolling interest		769			75			2,816			75
INCOME (LOSS) ATTRIBUTABLE TO KEY	$	6,772		$	(124,942	)	$	(3,044	)	$	(142,511	)

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

Revenues

     Our revenues for the three months ended September 30, 2010 increased $68.4 million, or 31.8%, to $283.7 million from $215.3 million for the three months ended September 30, 2009. See “Segment Operating Results — Three Months Ended September 30, 2010 and 2009” below for a more detailed discussion of the change in our revenues.

Direct Operating Expenses

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     Our direct operating expenses increased $41.7 million to $198.2 million (69.8% of revenues) for the three months ended September 30, 2010, compared to $156.4 million (72.6% of revenues) for the three months ended September 30, 2009. The increase in direct operating expenses is directly attributable to increased activity.

Depreciation and Amortization Expense

     Depreciation and amortization expense decreased $6.1 million to $32.6 million (11.5% of revenues) during the third quarter of 2010, compared to $38.7 million (18.0% of revenues) for the third quarter of 2009. The decrease in our depreciation and amortization expense is primarily attributable to the asset retirements and impairments we recognized during the third quarter of 2009, which decreased the basis of our depreciable fixed assets.

General and Administrative Expenses

     General and administrative expenses increased $7.5 million to $46.8 million (16.5% of revenues) for the three months ended September 30, 2010, compared to $39.4 million (18.3% of revenues) for the three months ended September 30, 2009. The increase in general and administrative expenses for the third quarter of 2010 was primarily due to higher stock-based compensation related to new equity awards and implementation costs for a new Enterprise Resource Planning (“ERP”) system conversion. Transaction costs incurred in the third quarter of 2010 related to our acquisition of OFS ES also contributed to the increase.

Interest Expense, Net of Amounts Capitalized

     Interest expense was $10.6 million (3.7% of revenues) for the three months ended September 30, 2010, an increase of $1.5 million, or 16.3%, compared to $9.1 million (4.2% of revenues) for the same period in 2009, due to higher interest rates on our borrowings under our amended revolving credit facility.

Other, net

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

	Three Months Ended September 30,
	2010			2009
	(in thousands)
(Gain) loss on disposal of assets, net	$	(146	)	$	1,942
Interest income		(5	)		(42	)
Foreign exchange loss (gain), net		30			(1,305	)
Other (income) expense, net		(659	)		939
Total	$	(780	)	$	1,534

Income Tax Benefit

     We recorded an income tax benefit of $1.4 million on a pretax loss of $3.7 million in the third quarter of 2010, compared to an income tax benefit of $47.8 million on a pretax loss of $126.8 million in the third quarter of 2009. Our effective tax rate was 37.8% for the three months ended September 30, 2010, compared to 37.6% for the three months ended September 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, the impact of permanent items that affect book income but do not affect taxable income, and discrete adjustments such as accrual to return adjustments, changes in valuation allowances, and expenses or benefits recognized for uncertain tax positions.

Discontinued Operations

     We recorded net income from discontinued operations of $8.3 million for the three months ended September 30, 2010, compared to a net loss of $45.9 million for the three months ended September 30, 2009. The loss in 2009 mostly related to the asset impairment on our pressure pumping equipment recorded in the third quarter of 2009. Excluding the impairment, results of discontinued

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operations improved in the third quarter of 2010 compared to the same period in 2009, for 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 September 30, 2010, we recorded a benefit of $0.8 million, compared to a benefit of $0.1 million for the three months ended September 30, 2009, 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.

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

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

For the three months ended September 30, 2010:

	Well			Production			Functional
	Servicing			Services			Support
Revenues from external customers	$	244,288		$	39,451		$	—
Operating expenses		216,648			32,071			28,837
Net intersegment expense (income)		2,292			(2,280	)		(12	)
Operating income (loss)		25,348			9,660			(28,825	)
For the three months ended September 30, 2009:
	Well			Production			Functional
	Servicing			Services			Support
Revenues from external customers	$	194,071		$	21,278		$	—
Operating expenses		183,466			23,794			27,214
Asset retirements and impairments		65,869			31,166			—
Net intersegment expense (income)		2,689			(1,950	)		(739	)
Operating loss		(57,953	)		(31,732	)		(26,475	)

Well Servicing

     Revenues from external customers for our Well Servicing segment increased $50.2 million, or 25.9%, to $244.3 million for the three months ended September 30, 2010, compared to $194.1 million for the three months ended September 30, 2009. The increase in revenues for this segment is due to an increase in U.S. market activity, which has improved quarter over quarter since June 2009. However, we have experienced declines in revenue in Mexico due to the expiration of one of our contracts with Pemex in March 2010 and also due to 2010 budget cuts by Pemex affecting our activity under our second contract.

     Operating expenses for our Well Servicing segment were $216.6 million during the three months ended September 30, 2010, an increase of $33.2 million, or 18.1%, compared to $183.5 million for the same period in 2009. The increase in operating expenses is attributable to increased activity during the period.

     During the three months ended September 30, 2009, we took out of service and retired a portion of our U.S. rig fleet and associated support equipment, resulting in the recording of a pre-tax asset retirement charge of approximately $65.9 million.

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Production Services

     Revenues from external customers for our Production Services segment increased $18.2 million, or 85.4%, to $39.5 million for the three months ended September 30, 2010, compared to $21.3 million for the three months ended September 30, 2009. The increase in revenue for this segment is attributable to an increase in revenues from our fishing and rental operations, as well as expansion of our coiled tubing services along with improved pricing during the period.

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

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

Functional Support

     Operating expenses for Functional Support, which represent expenses associated with managing our other reportable operating segments, increased $1.6 million, or 6.0%, to $28.8 million (10.2% of consolidated revenues) for the three months ended September 30, 2010 compared to $27.2 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 support costs related to our new ERP system during the third quarter of 2010. Transaction costs incurred in the third quarter of 2010 related to our acquisition of OFS ES also contributed to the increase.

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

Revenues

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

Direct Operating Expenses

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

Depreciation and Amortization Expense

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

General and Administrative Expenses

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

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

Interest Expense, Net of Amounts Capitalized

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

Other, net

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

	Nine Months Ended September 30,
	2010			2009
	(in thousands)
Loss on disposal of assets, net	$	509		$	566
Interest income		(41	)		(459	)
Foreign exchange gain, net		(479	)		(1,358	)
Other (income) expense, net		(1,545	)		563
Total	$	(1,556	)	$	(688	)

Income Tax Benefit

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

Discontinued Operations

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

Noncontrolling Interest

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

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

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

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

For the nine months ended September 30, 2010:

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

For the nine months ended September 30, 2009:

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

Well Servicing

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

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

Production Services

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

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

Functional Support

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

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new equity awards and implementation costs for a new ERP system conversion during the second quarter of 2010 and overall increases in activity. Transaction costs incurred in 2010 related to our acquisition of OFS ES also contributed to the increase.

LIQUIDITY AND CAPITAL RESOURCES

Current Financial Condition and Liquidity

     As of September 30, 2010, we had cash and cash equivalents of $34.1 million. Our working capital (excluding the current portion of capital leases, notes payable and long-term debt) was $202.7 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 current liabilities due to activity increases associated with improving market conditions during the first nine months of 2010. Our total outstanding debt was $520.3 million, and we have no significant debt maturities until 2012. As of September 30, 2010, we had $87.8 million in borrowings and $58.8 million in committed letters of credit outstanding under our revolving credit facility, leaving $153.4 million of available borrowing capacity. On October 1, 2010 we borrowed $80.0 million under the credit facility to fund a portion of the purchase price of the OFS ES entities. Using a portion of the proceeds from the Patterson-UTI transaction, we subsequently repaid the entire balance of $167.8 million on October 4, 2010, bringing our total revolving facility borrowings outstanding to zero (see “Note 17. Subsequent Events” in “Item 1. Financial Statements").

Cash Flows

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

	Nine Months Ended September
	30,
	2010			2009
	(in thousands)
Net cash provided by operating activities	$	90,427		$	197,581
Cash paid for capital expenditures		(101,065	)		(102,971	)
Proceeds received from sale of fixed assets		20,502			5,184
Other investing activities, net		165			12,206
Repayments of capital lease obligations		(6,891	)		(8,505	)
Repayments on long-term debt		(6,970	)		(1,539	)
Net repayment on revolving credit facility		—			(100,000	)
Repurchases of common stock		(2,357	)		(248	)
Other financing activities, net		4,214			1,192
Effect of exchange rates on cash		(1,366	)		(2,508	)
Net (decrease) increase in cash and cash equivalents	$	(3,341	)	$	392

     During the nine months ended September 30, 2010, we generated cash flows from operating activities of $90.4 million, compared to $197.6 million for the nine months ended September 30, 2009. Operating cash inflows for 2010 primarily relate to the collection of accounts receivable and receipt of a $53.2 million federal income tax refund, partially offset by our net loss for the period, as well as by cash paid against accounts payable and other liabilities due to the increase in activity. Our operating cash flows declined from 2009 primarily as a result of the increase in our net working capital compared to the end of the third quarter of 2009. This was primarily driven by an increase in and timing of the collection of our accounts receivable, as a result of higher revenues during the nine months ended September 30, 2010, compared to the same period in 2009.

     Cash used in investing activities was $80.4 million and $85.6 million for the nine months ended September 30, 2010 and 2009, respectively, consisting primarily of capital expenditures. Partially offsetting the cash used for capital expenditures was the receipt of $17.9 million related to the sale of six barge rigs and related equipment during the second quarter of 2010.

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

Sources of Liquidity and Capital Resources

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

Debt Service

     We do not have any significant maturities of debt until 2012. 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 $17.8 million for December 1, 2010. We expect to fund interest payments from cash generated by operations. At September 30, 2010, our annual debt maturities for our Senior Notes and borrowings under our Senior Secured Credit Facility are as follows:

	Principal Payments
	(in thousands)
Remainder of 2010	$	—
2011		—
2012		87,813
2013		—
2014		425,000
Total principal payments	$	512,813

     As discussed above, we repaid the outstanding principal balance on our revolving credit facility in early October 2010 with a portion of the proceeds from the sale of our pressure pumping and wireline businesses.

8.375% Senior Notes

     We have $425.0 million aggregate principal amount of 8.375% Senior Notes due 2014 (the “Senior Notes”). The Senior Notes are general unsecured senior obligations and are subordinate to all of our existing and future secured indebtedness. The Senior Notes are or will be jointly and severally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. Interest on the Senior Notes is payable on June 1 and December 1 of each year. The Senior Notes mature on December 1, 2014.

     On or after December 1, 2011, the Senior Notes will be subject to redemption at any time and from time to time at our option, in whole or in part, upon not less than 30 nor more than 60 days’ notice, at the redemption prices (expressed as percentages of the principal amount redeemed) set forth below, plus accrued and unpaid interest thereon to the applicable redemption date, if redeemed during the twelve-month period beginning on December 1 of the years indicated below:

Year	Percentage
2011		104.19	%
2012		102.09	%
2013		100.00	%

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     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 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 September 30, 2010, the Senior Notes were below investment grade and have never been assigned an investment 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

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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 March 31, 2010 through and including the fiscal quarter ending December 31, 2010 and, (ii) thereafter, 2.00 to 1.00;

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

through the fiscal quarter ending September 30, 2010	2.00 to 1.00
for the fiscal quarter ending December 31, 2010	2.50 to 1.00
thereafter	3.00 to 1.00;

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

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

• that we limit our investment 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;

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(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. The highest amount outstanding under the credit facility during the quarter was $87.8 million. On October 1, 2010 we borrowed $80.0 million against the credit facility to facilitate the purchase of the OFS ES entities (see “Note 17. Subsequent Events” in “Item 1. Financial Statements”) which brought our total borrowings outstanding under the revolver to $167.8 million. Using a portion of the proceeds from the Patterson-UTI transaction, we subsequently repaid the entire balance on October 4, 2010, bringing our total revolving facility borrowings outstanding to zero (see “Note 17. Subsequent Events” in “Item 1. Financial Statements”). We were in compliance with the covenants of the Senior Secured Credit Facility at September 30, 2010.

Related Party Notes Payable

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

Capital Lease Agreements

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

Off-Balance Sheet Arrangements

     At September 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

     We believe that our internally generated cash flows from operations, net cash inflows from the purchase and sale transactions occurring on October 1, 2010, 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 nine months ended September 30, 2010, our capital expenditures totaled $101.1 million, primarily related to the purchase of coiled tubing units, the addition of larger well service rigs, major maintenance of our existing fleet and equipment, and capitalized costs associated with our new ERP system. Our capital expenditures program is

45

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

Divestitures and Acquisitions

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

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

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     There have been no material changes in our quantitative and qualitative disclosures about market risk from those disclosed in our 2009 Annual Report. More detailed information concerning market risk can be found in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2009 Annual Report.

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 designed to ensure that information is accumulated and communicated to our

46

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 were no changes in our internal control over financial reporting during the third quarter of 2010 that materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

     We implemented a new Enterprise Resource Planning (“ERP”) system on May 1, 2010. This implementation resulted in certain changes to business processes and internal controls beginning in the second quarter that impacted financial reporting. However, we continue to perform a significant portion of controls that follow 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 subsequent to the system implementation and will continue to evaluate the operating effectiveness of related controls during subsequent periods.

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PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

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

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

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

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

     During the three months ended September 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
July 1, 2010 to July 31, 2010		—	$	—		—		—
August 1, 2010 to August 31, 2010		25,327		8.45		—		—
September 1, 2010 to September 30, 2010		—		—		—		—
Total		25,327	$	8.45		—		—

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(1)	Represents shares repurchased to satisfy tax withholding obligations upon the vesting of restricted stock awards.
(2)	The price paid per share on the vesting date with respect to the tax withholding repurchases was determined using the closing price as quoted on the New York Stock Exchange on the vesting date for awards granted under the Key Energy Services, Inc. 2007 Equity and Cash Incentive Plan and the previous business day for awards granted under the Key Energy Group, Inc. 1997 Incentive Plan.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

     None.

ITEM 5. OTHER INFORMATION

     None.

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

49

10.2*	Amending Letter Agreement, dated September 1, 2010, by and among Key Energy Pressure Pumping Services, LLC, Key Electric Wireline Services, LLC, Key Energy Services, Inc., Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.) and Patterson UTI Energy, Inc.
10.3*	Amending Letter Agreement, dated October 1, 2010, by and among Key Energy Pressure Pumping Services, LLC, Key Electric Wireline Services, LLC, Key Energy Services, Inc., Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.) and Patterson UTI Energy, Inc.
10.4	Purchase and Sale Agreement, dated as of July 23, 2010, by and among OFS Holdings, LLC, a Delaware limited liability company, OFS Energy Services, LLC, a Delaware limited liability company, Key Energy Services, Inc., a Maryland corporation, and Key Energy Services, LLC, a Texas limited liability company. (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K/A filed on October 8, 2010, File No. 001-08038.)
10.5	Amendment No. 1 to Purchase and Sale Agreements, dated as of August 27, 2010, by and among OFS Holdings, LLC, a Delaware limited liability company, OFS Energy Services, LLC, a Delaware limited liability company, Key Energy Services, Inc., a Maryland corporation, and Key Energy Services, LLC, a Texas limited liability company. (Incorporated by reference to Exhibit 2.2 of our Current Report on Form 8-K/A filed on October 8, 2010, File No. 001-08038.)
10.6	Amendment No. 2 to Purchase and Sale Agreements, dated as of September 30, 2010, by and among OFS Holdings, LLC, a Delaware limited liability company, OFS Energy Services, LLC, a Delaware limited liability company, Key Energy Services, Inc., a Maryland corporation, and Key Energy Services, LLC, a Texas limited liability company. (Incorporated by reference to Exhibit 2.3 of our Current Report on Form 8-K/A filed on October 8, 2010, File No. 001-08038.)
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*	Interactive Data File.

* Filed herewith

50

SIGNATURE

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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

Date: November 1, 2010

51

EXHIBITS INDEX

3.1	Articles of Restatement of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2006, File No. 001-08038.)
3.2	Unanimous consent of the Board of Directors of Key Energy Services, Inc. dated January 11, 2000, limiting the designation of the additional authorized shares to common stock. (Incorporated by reference to Exhibit 3.2 of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 001-08038.)
3.3	Second Amended and Restated By-laws of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on September 22, 2006, File No. 001-08038.)
3.4	Amendment to Second Amended and Restated By-laws of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on November 2, 2007, File No. 001-08038.)
3.5	Amendments to Second Amended and Restated By-laws of Key Energy Services, Inc. adopted April 4, 2008. (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on April 9, 2008, File No. 001-08038.)
3.6	Amendment to Second Amended and Restated By-laws of Key Energy Services, Inc. adopted June 4, 2009. (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on June 10, 2009, File No. 001-08038.)
4.1	Indenture, dated as of November 29, 2007, among Key Energy Services, Inc., the guarantors party thereto and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of our Form 8-K filed on November 30, 2007, File No. 001-08038.)
4.2	Registration Rights Agreement, dated as of November 29, 2007, among Key Energy Services, Inc., the subsidiary guarantors of the Company party thereto, and Lehman Brothers Inc., Banc of America Securities LLC and Morgan Stanley & Co. Incorporated, as representatives of the several initial purchasers named therein. (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed on November 30, 2007, File No. 001-08038.)
4.3	First Supplemental Indenture, dated as of January 22, 2008, among Key Marine Services, LLC, the existing guarantors party thereto and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.5 of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 001-08038.)
4.4	Second Supplemental Indenture, dated as of January 13, 2009, among Key Energy Mexico, LLC, the existing Guarantors and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.6 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2009, File No. 001-08038.)
4.5	Third Supplemental Indenture, dated as of July 31, 2009, among Key Energy Services California, Inc., the existing Guarantors and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.5 of our Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 001-08038.)
10.1	Asset Purchase Agreement, dated as of July 2, 2010, by and among Key Energy Pressure Pumping Services, LLC, Key Electric Wireline Services, LLC, Key Energy Services, Inc., Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.) and Patterson UTI Energy, Inc. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on July 6, 2010, File No. 001-08038.)
10.2*	Amending Letter Agreement, dated September 1, 2010, by and among Key Energy Pressure Pumping Services, LLC, Key Electric Wireline Services, LLC, Key Energy Services, Inc., Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.) and Patterson UTI Energy, Inc.
10.3*	Amending Letter Agreement, dated October 1, 2010, by and among Key Energy Pressure Pumping Services, LLC, Key Electric Wireline Services, LLC, Key Energy Services, Inc., Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.) and Patterson UTI Energy, Inc.
10.4	Purchase and Sale Agreement, dated as of July 23, 2010, by and among OFS Holdings, LLC, a Delaware limited liability company, OFS Energy Services, LLC, a Delaware limited liability company, Key Energy Services, Inc., a Maryland corporation, and Key Energy Services, LLC, a Texas limited liability company. (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K/A filed on October 8, 2010, File No. 001-08038.)
10.5	Amendment No. 1 to Purchase and Sale Agreements, dated as of August 27, 2010, by and among OFS Holdings, LLC, a Delaware limited liability company, OFS Energy Services, LLC, a Delaware limited liability company, Key Energy Services, Inc., a Maryland corporation, and Key Energy Services, LLC, a Texas limited liability company. (Incorporated by reference to Exhibit 2.2 of our Current Report on Form 8-K/A filed on October 8, 2010, File No. 001-08038.)

10.6	Amendment No. 2 to Purchase and Sale Agreements, dated as of September 30, 2010, by and among OFS Holdings, LLC, a Delaware limited liability company, OFS Energy Services, LLC, a Delaware limited liability company, Key Energy Services, Inc., a Maryland corporation, and Key Energy Services, LLC, a Texas limited liability company. (Incorporated by reference to Exhibit 2.3 of our Current Report on Form 8-K/A filed on October 8, 2010, File No. 001-08038.)
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*	Interactive Data File.

* Filed herewith

2

EX-10.2

Exhibit 10.2

September 1, 2010

Key Energy Services, Inc.
Key Electric Wireline Services, LLC
Key Energy Pressure Pumping Services, LLC
c/o Key Energy Services, Inc.
1301 McKinney, Suite 1800
Houston, Texas 77010
Attention: General Counsel

Dear Ladies and Gentlemen:

     Reference is hereby made to the Asset Purchase Agreement by and among Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.), as Buyer, Patterson-UTI Energy, Inc., as Buyer Parent, and Key Energy Pressure Pumping Services, LLC and Key Electric Wireline Services, LLC, as Sellers, and Key Energy Services, Inc., as Seller Parent, dated as of July 2, 2010 (the “Agreement”), relating to the acquisition of the assets of Sellers’ pressure pumping and wireline businesses. This letter sets forth each of our agreements to certain modifications to the Agreement, and unless expressly modified pursuant to this letter agreement, all other provisions of the Agreement remain in full force and effect. Capitalized terms used in this letter which are defined in the Agreement shall have the meaning set forth in the Agreement.

     Attached hereto as Exhibit A is a proposal dated August 30, 2010 from Environmental Resources Management (“ERM”) to Buyer that sets forth proposed Phase II ESA invasive testing and analysis to be performed at the Transferred Leased Real Properties (the “Subject Properties”) listed on Table 1 thereto. By this letter, (i) Sellers and Seller Parent consent to such testing and analysis at the Subject Properties, and (ii) Buyer and Buyer Parent acknowledge and agree that no Environmental Defect Notice shall be issued regarding any other Transferred Real Property and, prior to Closing, that no Phase II ESA shall be performed with respect to any other Transferred Real Property; provided, that this clause (ii) shall not apply to any Transferred Real Property affected by an Environmental Condition coming into existence after the time that the Phase I ESA for such property was conducted pursuant to Section 6.1(b) and prior to Closing and not resulting from the Phase II ESA work.

     Any Environmental Condition identified as a result of the Phase II ESA work approved hereby shall be treated as and shall constitute a Potentially Material Environmental Condition for all purposes of the Agreement, notwithstanding the definition of that term contained in the Agreement.

     Within ten days after delivery to Sellers of the last of the reports with respect to such Phase II ESA work, the parties shall work in good faith to agree on the scope of work necessary to Remediate any Environmental Conditions pursuant to Section 6.2, including an estimate of the reasonable costs required to conduct such Remediation. The following standards will be used in determining the scope of such Remediation: (i) for the Subject Properties located in Texas, the Tier 1 protective concentration levels (Remedy Standard A) for commercial/industrial uses provided pursuant to the Texas Risk Reduction Program, 30 T.A.C. Chapter 350, and (ii) for the Subject Property located in Arkansas, the risk-based remediation standards for industrial use approved by the Arkansas Department of Environmental Quality pursuant to Title 8 of the Arkansas Code and/or Arkansas Pollution Control and Ecology Commission Regulation 23. Notwithstanding any continuing efforts to complete any agreed upon Remediation work at the Subject Properties, the parties shall promptly proceed to the Closing of the transactions contemplated by the Agreement provided that the other conditions to Closing set forth in the Agreement have been satisfied.

     The parties hereto also agree that any Environmental Defect Notice delivered within five days after the delivery to Buyer of the last of the reports with respect to such Phase II ESA work shall be deemed to have been delivered on or before the Environmental Defect Notice Date.

     Separately, Disclosure Schedule 4.22 shall be modified to incorporate by reference the Phase I ESAs and Phase II ESAs prepared by ERM and, such reports shall not be treated as supplements pursuant to Section 6.6.

     Buyer and Buyer Parent agree that Buyer shall pay the first $2,000,000 of the aggregate reasonable and actual costs incurred by Buyer or Seller to perform any Remedial Action on the Subject Properties (including any properties that are removed from among the Purchased Assets pursuant to Section 6.2(c)) as agreed to pursuant hereto, notwithstanding the provisions of Section 13.3(a) of the Agreement; provided, that such Remedial Action with respect to a Subject Property that either Buyer or Seller elects to remove from the Purchased Assets pursuant to Section 6.2(c) shall have been initiated within 90 days after the Closing Date. Payments shall be made by Buyer as such costs are incurred and invoiced to Buyer.

     The parties hereto agree that Sellers’ Environmental Liabilities arising from or related to any Environmental Condition identified pursuant to the Phase II ESA work contemplated herein or any Remedial Actions in response thereto shall cease upon the earlier of (i) confirmation that the commercial/industrial standards identified above have been achieved, or (ii) five years from the Closing Date. Further, the Phase II ESA work shall not give rise to any indemnity obligations for Sellers or Seller Parent with respect to the Subject Properties other than pursuant to Section 13.3(a) of the Agreement as modified by the immediately preceding paragraph hereof.

     The parties agree that the leased properties in Goliad, Texas shall be retained by Sellers, shall not be a Transferred Leased Real Property, and any lease associated therewith shall not be a Transferred Lease.

-2-

          Please indicate your agreement to the foregoing by signing and dating below.

Very truly yours, Patterson-UTI Energy, Inc.
By:	/s/ JOHN E. VOLLMER III
	John E. Vollmer III
	Senior Vice President-Corporate Development, Chief Financial Officer and Treasurer
Universal Pressure Pumping, Inc.
By:	/s/ JOHN E. VOLLMER III
	John E. Vollmer III
	Senior Vice President-Corporate Development, Chief Financial Officer and Treasurer

Agreed to this 1st day of September, 2010

Key Energy Services, Inc.
By:	/s/ NEWTON W. WILSON III Newton W. Wilson III
	Senior Vice President and Chief Operating Officer
Key Energy Pressure Pumping Services, LLC
By:	/s/ NEWTON W. WILSON III Newton W. Wilson III
	President
Key Electric Wireline Services, LLC
By:	/s/ NEWTON W. WILSON III Newton W. Wilson III
	President

-3-

EX-10.3

Exhibit 10.3

October 1, 2010

Key Energy Pressure Pumping Services, LLC
Key Electric Wireline Services, LLC
Key Energy Services, Inc.
c/o Key Energy Services, Inc.
1301 McKinney, Suite 1800
Houston, Texas 77010
Attention: General Counsel

Dear Ladies and Gentlemen:

     Reference is hereby made to the Asset Purchase Agreement by and among Universal Pressure Pumping, Inc. (formerly known as Portofino Acquisition Company), as Buyer, Patterson-UTI Energy, Inc, as Buyer Parent, Key Energy Pressure Pumping Services, LLC and Key Electric Wireline Services, LLC, as Sellers, and Key Energy Services, Inc., as Seller Parent, dated as of July 2, 2010 (as modified by that certain Assignment and Assumption Agreement dated October 1, 2010, by and between Universal Pressure Pumping, Inc., and Universal Wireline, Inc., and as otherwise amended, modified or supplemented through the date hereof the “Purchase Agreement”). This letter sets forth each of our agreements to certain modifications to the terms of the Purchase Agreement, and unless expressly modified pursuant to this letter agreement, all other provisions of the Purchase Agreement remain in full force and effect. Capitalized terms used and not otherwise defined herein shall have the meanings assigned to them in the Purchase Agreement.

     The parties agree that the defined term “Buyer Lease Agreement” in Section 1.1 of the Purchase Agreement is hereby deleted in its entirety and replaced with the following definition:

     “Buyer Lease Agreement” means (i) a written lease agreement containing the material terms identified in Exhibit C to this Agreement between Buyer, as tenant, and an Affiliate of Sellers, as landlord, relating to the Tioga, North Dakota service facility used in the Wireline Business and (ii) the written sublease agreement between Buyer, as sublessee, and an Affiliate of Sellers, as sublessor, relating to the Midland, Texas office facility used in the Purchased Business.

     The parties agree that the defined term “Effective Time” in Section 1.1 of the Purchase Agreement is hereby deleted in its entirety and replaced with the following definition:

     “Effective Time” means 12:01 a.m. on the Closing Date.

     The parties agree that Exhibit A to this letter agreement and incorporated herein by reference sets forth the amount of funds that will be paid by Buyer to Sellers on the Closing Date, including the determination thereof.

     The parties agree that the following schedules contained in the Seller Disclosure Schedules to the Purchase Agreement are hereby amended and restated in their entirety, except

for Schedule 4.19 for which only the severance obligations portion of such schedule is hereby amended and restated, which amended and restated schedules are attached to this letter agreement as Exhibit B:

2.1(a)-1	Pressure Pumping Equipment and Machinery
2.1(a)-2	Wireline Equipment and Machinery
2.1(b)-1	Pressure Pumping Assumed Contracts
2.1(b)-2	Wireline Assumed Contracts
2.1(c)-1	Pressure Pumping Vehicles
2.1(c)-2	Wireline Vehicles
2.1(e)	Transferred Leased Real Property and Transferred Leases
2.1(f)	Transferred Intellectual Property
2.1(g)	Transferred Permits
4.19	Business Employees — Severance Obligations

     The parties agree that all amounts listed on the amended and restated severance obligations portion of Schedule 4.19, included as part of Exhibit B hereto, shall, for the purposes of Section 8.4(j) of the Purchase Agreement, be subject to, and apply towards, Sellers’ and Buyer’s respective obligation to pay such retention benefits, including the limitation on total payments by Buyer not to exceed $900,000.

     This letter agreement (i) shall be governed by the law of the state of Texas, without regard to the conflicts of law principles of such state, (ii) may only be amended by a writing signed by all parties hereto, and (iii) may be executed in one or more counterparts, all of which shall be considered one and the same document.

[Signature Page Follows]

- 2 -

     Please indicate your agreement to the foregoing by signing and dating below.

Very truly yours, Universal Pressure Pumping, Inc.
By:	/s/ JOHN E. VOLLMER
	John E. Vollmer
	Senior Vice President — Corporate Development, Chief Financial Officer and Treasurer

Universal Wireline, Inc.
By:	/s/ JOHN E. VOLLMER
	John E. Vollmer
	Senior Vice President — Corporate Development, Chief Financial Officer and Treasurer

Patterson-UTI Energy, Inc.
By:	/s/ JOHN E. VOLLMER
	John E. Vollmer
	Senior Vice President — Corporate Development, Chief Financial Officer and Treasurer

Agreed to this 1st day of October, 2010. KEY ENERGY PRESSURE PUMPING SERVICES, LLC
By:	/s/ J. MARSHALL DODSON
	J. Marshall Dodson
	Vice President and Treasurer
KEY ELECTRIC WIRELINE SERVICES, LLC
By:	/s/ J. MARSHALL DODSON
	J. Marshall Dodson
	Vice President and Treasurer
KEY ENERGY SERVICES, INC.
By:	/s/ J. MARSHALL DODSON
	J. Marshall Dodson
	Vice President and Treasurer

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT

     I, Richard J. Alario, certify that:

     1. I have reviewed this Quarterly Report on Form 10-Q of Key Energy Services, Inc.

     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

     4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

     a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

     b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

     c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

     d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

     5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

     a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

     b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Richard J. Alario                               
Richard J. Alario
President and Chief Executive Officer

Date: November 1, 2010

3

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO SECTION 302 OF SARBANES-OXLEY ACT

     I, T. M. Whichard III, certify that:

     1. I have reviewed this Quarterly Report on Form 10-Q of Key Energy Services;

     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

     4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

     a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

     b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

     c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

     d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

     5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

     a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

     b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ T. M. Whichard III                                            
T. M. Whichard III
Senior Vice President and Chief Financial Officer

Date: November 1, 2010

4

EX-32

Exhibit 32

CERTIFICATION
PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     Each of the undersigned officers of Key Energy Services, Inc. (the “Company”) hereby certifies, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002, to such officer’s knowledge that:

     (1) the accompanying Quarterly Report on Form 10-Q for the period ending September 30, 2010 as filed with the U.S. Securities and Exchange Commission (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended; and

     (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of and for the periods expressed in the Report.

Dated: November 1, 2010

/s/ Richard J. Alario                     
Richard J. Alario
Chief Executive Officer

Dated: November 1, 2010

/s/ T. M. Whichard III                   
T. M. Whichard III
Chief Financial Officer

5