10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)
þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2010
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 001-08038

KEY ENERGY SERVICES, INC.

(Exact name of registrant as specified in its charter)

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

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

(713) 651-4300
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Exchange on Which Registered
Common Stock, $0.10 par value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

Title of Each Class

None

Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act).  Yes þ     No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes o     No þ

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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.) Yes þ     No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

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

Large accelerated 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

The aggregate market value of the common stock of the registrant held by non-affiliates as of June 30, 2010, based on the $9.18 per share closing price for the registrant’s common stock as quoted on the New York Stock Exchange on such date, was $850 million (for purposes of calculating these amounts, only directors, officers and beneficial owners of 10% or more of the outstanding common stock of the registrant have been deemed affiliates).

As of February 16, 2011, the number of outstanding shares of common stock of the registrant was 142,585,543.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934 with respect to the 2011 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.

KEY ENERGY SERVICES, INC.

ANNUAL REPORT ON FORM 10-K
For the Year Ended December 31, 2010

INDEX

			Page
			Number
PART I
	ITEM 1.	Business		4
	ITEM 1A.	Risk Factors		10
	ITEM 1B.	Unresolved Staff Comments		17
	ITEM 2.	Properties		17
	ITEM 3.	Legal Proceedings		18
	ITEM 4.	(Removed and Reserved)		18
PART II
	ITEM 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		18
	ITEM 6.	Selected Financial Data		22
	ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		23
	ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk		50
	ITEM 8.	Financial Statements and Supplementary Data		51
	ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		117
	ITEM 9A.	Controls and Procedures		117
	ITEM 9B.	Other Information		118
PART III
	ITEM 10.	Directors, Executive Officers and Corporate Governance		118
	ITEM 11.	Executive Compensation		118
	ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		118
	ITEM 13.	Certain Relationships and Related Transactions, and Director Independence		118
	ITEM 14.	Principal Accounting Fees and Services		118
PART IV
	ITEM 15.	Exhibits, Financial Statement Schedules		119
EX-18.1
EX-21
EX-23
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
EX-101 DEFINITION LINKBASE DOCUMENT

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

In addition to statements of historical fact, this report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Statements that are not historical in nature or that relate to future events and conditions are, or may be deemed to be, forward-looking statements. These “forward-looking statements” are based on our current expectations, estimates and projections about Key Energy Services, Inc. and its wholly-owned and controlled subsidiaries, our industry and management’s beliefs and assumptions concerning future events and financial trends affecting our financial condition and results of operations. In some cases, you can identify these statements by terminology such as “may,” “will,” “predicts,” “expects,” “projects,” “potential” or “continue” or the negative of such terms and other comparable terminology. These statements are only predictions and are subject to substantial risks and uncertainties and not guarantees of performance. Future actions, events and conditions and future results of operations may differ materially from those expressed in these statements. In evaluating those statements, you should carefully consider the risks outlined in “Item 1A. Risk Factors.”

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.

Important factors that may affect our expectations, estimates or projections include, but are not limited to, the following:

•  conditions in the oil and natural gas industry, especially oil and natural gas prices and capital expenditures by oil and natural gas companies;

•  volatility in oil and natural gas prices;

•  tight credit markets and disruptions in the U.S. and global financial systems;

•  our ability to implement price increases or maintain pricing on our core services;

•  industry capacity;

•  increased labor costs or unavailability of skilled workers;

•  asset impairments or other charges;

•  operating risks, which are primarily self-insured, and the possibility that our insurance may not be adequate to cover all of our losses or liabilities;

•  the economic, political and social instability risks of doing business in certain foreign countries;

•  our historically high employee turnover rate and our ability to replace or add workers;

•  our ability to implement technological developments and enhancements;

•  significant costs and liabilities resulting from environmental, health and safety laws and regulations;

• severe weather impacts on our business;

•  our ability to successfully identify, make and integrate acquisitions;

•  the loss of one or more of our largest customers;

•  the impact of compliance with climate change legislation or initiatives;

•  our ability to generate sufficient cash flow to meet debt service obligations;

•  the amount of our debt and the limitations imposed by the covenants in the agreements governing our debt;

•  an increase in our debt service obligations due to variable rate indebtedness; and

•  other factors affecting our business described in “Item 1A. Risk Factors.”

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PART I

ITEM 1.   BUSINESS

General Description of Business

Key Energy Services, Inc. (NYSE: KEG) is a Maryland corporation and is the largest onshore, rig-based well servicing contractor based on the number of rigs owned. References to “Key,” the “Company,” “we,” “us” or “our” refer to Key Energy Services, Inc., its wholly-owned subsidiaries and its controlled subsidiaries. We were organized in April 1977 and commenced operations in July 1978 under the name National Environmental Group, Inc. In December 1992, we became Key Energy Group, Inc. and we changed our name to Key Energy Services, Inc. in December 1998.

We provide a full range of well services to major oil companies, foreign national oil companies and independent oil and natural gas production companies. Our services include rig-based and coiled tubing-based well maintenance and workover services, well completion and recompletion services, fluid management services, and fishing and rental services and other ancillary oilfield services. Additionally, certain of our rigs are capable of specialty drilling applications. We operate in most major oil and natural gas producing regions of the continental United States, and have operations based in Mexico, Colombia, the Middle East, Russia and Argentina. In addition, we have a technology development group based in Canada and have ownership interests in two oilfield service companies based in Canada.

The following is a description of the various products and services that we provide and our major competitors for those products and services.

Service Offerings

We operate in two business segments, Well Servicing and Production Services. Our Well Servicing segment includes rig-based services and fluid management services. Historically, our Production Services segment included 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, Inc. (“Patterson-UTI”). Also on October 1, 2010, we completed the acquisition of certain subsidiaries owned by OFS Energy Services, LLC (“OFS”), which increased our coiled tubing, fluid management services and rig services capacity. As of December 31, 2010, our Production Services segment consisted mainly of our coiled tubing, and fishing and rental services. The following discussion provides a description of the major service lines offered by our business segments. Our rig-based services are provided in the continental United States as well as in Mexico, Colombia, the Middle East, Russia and Argentina. Our other major service lines are provided primarily in the continental United States. See “Note 23. Segment Information” in “Item 8. Financial Statements and Supplementary Data” for additional financial information about our reportable business segments and the various geographical areas where we operate.

Effective for the first quarter of 2011, we will begin reporting under two new business segments: U.S. and International. Financial results for all periods presented in future filings will be restated to reflect the change in operating segments. We revised our segments to reflect the change in our operating focus and our assessment of operations and resource allocation in making decisions regarding Key.

Well Servicing Segment

Rig-Based Services

Our rig-based services include the maintenance, workover, and recompletion of existing oil and natural gas wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives. We also provide specialty drilling services to oil and natural gas producers with certain of our larger well servicing rigs that are capable of providing conventional and horizontal drilling services. Our rigs consist of various sizes and capabilities, allowing us to service 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

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

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

The workover services that we provide are designed to enhance the production of existing wells, and generally are more complex and time consuming than normal maintenance services. Workover services can include deepening or extending wellbores into new formations by drilling horizontal or lateral wellbores, sealing off depleted production zones and accessing previously bypassed production zones, converting former production wells into injection wells for enhanced recovery operations and conducting major subsurface repairs due to equipment failures. Workover services may last from a few days to several weeks, depending on the complexity of the workover. Demand for these services is closely related to capital spending by oil and natural gas producers, which in turn is a function of oil and natural gas prices. As commodity prices increase, producers tend to increase their capital spending for workover projects in order to increase their production. Conversely, as commodity prices decline, demand for workover projects tends to decrease.

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 tubulars and downhole equipment. We typically provide a well service rig and may also provide other equipment to assist in the completion process. The completion process usually takes a few days to several weeks, depending on the nature of the completion. The demand for completion and recompletion services is directly related to drilling activity levels, which are highly sensitive to expectations for, and reactions to changes in, commodity prices. As the number of newly drilled wells decreases, the number of completion jobs correspondingly decreases. In addition, during periods of weak drilling activity, some drilling contractors may be more inclined to use drilling rigs for completion work.

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.

We believe that the largest competitors for our U.S. rig-based services include Nabors Industries Ltd., Basic Energy Services, Inc., Complete Production Services, Inc., Forbes Energy Services Ltd. and Pioneer Drilling Company. In addition, there are numerous small companies that compete in our rig-based markets in the United States. In Argentina, we believe our major competitors are San Antonio International (formerly Pride International), Nabors Industries, Drillsearch Energy Ltd. and Emepa S.A. In Mexico, San Antonio International, Weatherford International Ltd. and Forbes Energy Services are our largest competitors. In the Russian Federation, our major competitors are Weatherford International and Integra Technologies Inc. In Colombia, our major competitors are San Antonio International and Serinco Drilling S.A. Our largest competitors in the Middle East are Weatherford International, Nabors Industries and MB Petroleum Services.

Fluid Management Services

We provide fluid management services, including oilfield transportation and produced water disposal services, with our 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 non-hydrocarbon fluids. We also supply frac tanks which are used for temporary storage of fluids associated with fluid hauling operations. In addition, we provide equipment trucks that are used to move large

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pieces of equipment from one well site to the next, and we operate a fleet of hot oilers which are capable of pumping heated fluids that are used to clear soluble restrictions in a wellbore.

Fluid hauling trucks are utilized in connection with drilling and workover projects, which tend to use large amounts of various fluids. In connection with drilling, maintenance or workover activity at a well site, we transport fresh and brine water to the well site and provide temporary storage and disposal of produced saltwater and drilling or workover fluids. These fluids are removed from the well site and transported for disposal in a saltwater disposal (“SWD”) well that is either owned by us or a third party. Key owned or leased 65 active SWD wells at December 31, 2010. Demand and pricing for these services generally correspond to demand for our well service rigs.

We believe that the largest competitors for our domestic fluid management services include Basic Energy Services, Complete Production Services, Nabors Industries and Stallion Oilfield Services Ltd. In addition, numerous small companies compete in the fluid management services market in the United States.

Production Services Segment

Historically, our Production Services segment included pressure pumping services (fracturing, nitrogen, acidizing, and cementing), wireline services (perforating, completion logging, production logging and casing integrity services), coiled tubing services and fishing and rental services. On October 1, 2010, we completed the sale of our pressure pumping and wireline businesses to Patterson-UTI. As discussed in Item 8 of this report, we show the results of operations for our pressure pumping and wireline businesses as discontinued operations for all periods presented. As of December 31, 2010, our Production Services segment primarily consists of our coiled tubing and fishing and rental services. Our Production Services segment also includes some specialty pumping services, nitrogen services, and cementing services.

Coiled Tubing Services

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 stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications such as milling temporary plugs between frac stages.

Our coiled tubing business consists of 43 coiled tubing units, two-thirds of which are large diameter, extended reach capable units, which have become important tools in horizontal well completions. Historically, coiled tubing was limited to remedial work such as wellbore washout and acid placement. Extended-reach, long-lateral coiled tubing units now provide the following services: logging and perforating conveyance; packer and plug milling; specialized drilling; frac placement; and pre-and post-frac well preparation. Our units are also employed in later-life well remediation and provide early and late cycle high pressure live well intervention services. Our coiled tubing units are currently only deployed in the United States; however, we believe that this technology will be requested by our international customers, which would provide additional growth opportunities.

Our primary competitors in the coiled tubing services market include: Schlumberger Ltd., Baker Hughes Incorporated, Halliburton Company, Complete Production Services and Superior Energy Services. In addition, numerous small companies compete in our coiled tubing services markets in the United States.

Fishing and Rental Services

We offer a full line of services and rental equipment designed for use in providing both onshore and offshore drilling and workover services. Fishing services involve recovering lost or stuck equipment in the wellbore utilizing a broad array of “fishing tools.” Our rental tool inventory consists of drill pipe, production tubulars, handling tools (including our patented Hydra-Walk^® pipe-handling units and services), pressure-control equipment, power swivels and foam air units. Demand for our fishing and rental services is also closely related to capital spending by oil and natural gas producers, which is generally a function of oil and natural gas prices.

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Our primary competitors for our fishing and rental services include Baker Oil Tools, Weatherford International, Basic Energy Services, Superior Energy Services, Quail Tools (owned by Parker Drilling Company) and Knight Oil Tools.

Other Business Data

Raw Materials

We purchase a wide variety of raw materials, parts and components that are made by other manufacturers and suppliers for our use. We are not dependent on any single source of supply for those parts, supplies or materials.

Customers

Our customers include major oil companies, foreign national oil companies, and independent oil and natural gas production companies. During the year ended December 31, 2010, no single customer accounted for more than 10% of our consolidated revenues. During the year ended December 31, 2009, the Mexican national oil company Petróleos Mexicanos (“Pemex”) accounted for approximately 11% of our consolidated revenues. No other customer accounted for more than 10% of our consolidated revenues for the year ended December 31, 2009. No single customer accounted for more than 10% of our consolidated revenues for the year ended December 31, 2008. Receivables outstanding from Pemex were approximately 25% of our total accounts receivable as of December 31, 2009. No single customer accounted for more than 10% of our total accounts receivable as of December 31, 2010 and 2008.

Competition and Other External Factors

The markets in which we operate are highly competitive. Competition is influenced by such factors as price, capacity, availability of work crews, and reputation and experience of the service provider. We believe that an important competitive factor in establishing and maintaining long-term customer relationships is having an experienced, skilled and well-trained work force. We devote substantial resources toward employee safety and training programs. In addition, we believe that the KeyView^® system provides important safety enhancements. We believe many of our larger customers place increased emphasis on the safety, performance and quality of the crews, equipment and services provided by their contractors. Although we believe customers consider all of these factors, price is often the primary factor in determining which service provider is awarded the work. However, in numerous instances, we secure and maintain work for large customers for which efficiency, safety, technology, size of fleet and availability of other services are of equal importance to price.

The demand for our services fluctuates, primarily in relation to the price (or anticipated price) of oil and natural gas, which, in turn, is driven by the supply of, and demand for, oil and natural gas. Generally, as supply of those commodities decreases and demand increases, service and maintenance requirements increase as oil and natural gas producers attempt to maximize the productivity of their wells in a higher priced environment. However, in a lower oil and natural gas price environment, demand for service and maintenance generally decreases as oil and natural gas producers decrease their activity. In particular, the demand for new or existing field drilling and completion work is driven by available investment capital for such work. Because these types of services can be easily “started” and “stopped,” and oil and natural gas producers generally tend to be less risk tolerant when commodity prices are low or volatile, we may experience a more rapid decline in demand for well maintenance services compared with demand for other types of oilfield services. Further, in a lower-priced environment, fewer well service rigs are needed for completions, as these activities are generally associated with drilling activity.

The level of our revenues, earnings and cash flows are substantially dependent upon, and affected by, the level of U.S. and international oil and natural gas exploration, development and production activity, as well as the equipment capacity in any particular region.

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Seasonality

Our operations are impacted by seasonal factors. Historically, our business has been negatively impacted during the winter months due to inclement weather, fewer daylight hours and holidays. During the summer months, our operations may be impacted by tropical weather systems. During periods of heavy snow, ice or rain, we may not be able to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. In addition, the majority of our equipment works only during daylight hours. In the winter months when days become shorter, this reduces the amount of time that our assets can work and therefore has a negative impact on total hours worked. Lastly, during the fourth quarter, we historically have experienced significant slowdown during the Thanksgiving and Christmas holiday seasons.

Patents, Trade Secrets, Trademarks and Copyrights

We own numerous patents, trademarks and proprietary technology that we believe provide us with a competitive advantage in the various markets in which we operate or intend to operate. We have devoted significant resources to developing technological improvements in our well service business and have sought patent protection both inside and outside the United States for products and methods that appear to have commercial significance. All the issued patents have varying remaining durations and begin expiring between 2013 and 2028. The most notable of our technologies include numerous patents surrounding the KeyView^® system.

We own several trademarks that are important to our business both in the United States and in foreign countries. In general, depending upon the jurisdiction, trademarks are valid as long as they are in use, or their registrations are properly maintained and they have not been found to become generic. Registrations of trademarks can generally be renewed indefinitely as long as the trademarks are in use. While our patents and trademarks, in the aggregate, are of considerable importance to maintaining our competitive position, no single patent or trademark is considered to be of a critical or essential nature to our business.

We also rely on a combination of trade secret laws, copyright and contractual provisions to establish and protect proprietary rights in our products and services. We typically enter into confidentiality agreements with our employees, strategic partners and suppliers and limit access to the distribution of our proprietary information.

Employees

As of December 31, 2010, we employed approximately 7,400 persons in our United States operations and approximately 1,800 additional persons in Argentina, Mexico, Colombia, and Canada. Additionally, our joint ventures in Russia and the Middle East in which we own a controlling interest employed approximately 430 persons as of December 31, 2010. Our domestic employees are not represented by a labor union and are not covered by collective bargaining agreements. Many of our employees in Argentina are represented by formal unions. In Mexico, we have entered into a collective bargaining agreement that applies to our workers in Mexico performing work under the Pemex contract.

As noted below in “Item 1A. Risk Factors,” we have historically experienced a high employee turnover rate, and during the past several years have experienced labor-related issues in Argentina. Other than with respect to the labor situation in Argentina, we have not experienced any significant work stoppages associated with labor disputes or grievances and consider our relations with our employees to be generally satisfactory.

Governmental Regulations

Our operations are subject to various federal, state and local laws and regulations pertaining to health, safety and the environment. We cannot predict the level of enforcement of existing laws or regulations or how such laws and regulations may be interpreted by enforcement agencies or court rulings in the future. We also cannot predict whether additional laws and regulations affecting our business will be adopted, or the effect such changes might have on us, our financial condition or our business. The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our operations are subject and for which compliance may have a material adverse impact on our results of operations, financial position or cash flows.

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Environmental Regulations

Our operations routinely involve the storage, handling, transport and disposal of bulk waste materials, some of which contain oil, contaminants and other regulated substances. Various environmental laws and regulations require prevention, and where necessary, cleanup of spills and leaks of such materials, and some of our operations must obtain permits that limit the discharge of materials. Failure to comply with such environmental requirements or permits may result in fines and penalties, remediation orders and revocation of permits.

Hazardous Substances and Waste

The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, referred to as “CERCLA” or the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain defined persons, including current and prior owners or operators of a site where a release of hazardous substances occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be jointly and severally liable for the costs of cleaning up the hazardous substances, for damages to natural resources and for the costs of certain health studies.

In the course of our operations, we occasionally generate materials that are considered “hazardous substances” and, as a result, may incur CERCLA liability for cleanup costs. Also, claims may be filed for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants. We also generate solid wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended, or “RCRA,” and comparable state statutes.

Although we use operating and disposal practices that are standard in the industry, hydrocarbons or other wastes may have been released at properties owned or leased by us now or in the past, or at other locations where these hydrocarbons and wastes were taken for treatment or disposal. Under CERCLA, RCRA and analogous state laws, we could be required to clean up contaminated property (including contaminated groundwater), or to perform remedial activities to prevent future contamination.

Air Emissions

The Clean Air Act, as amended, or “CAA,” and similar state laws and regulations restrict the emission of air pollutants and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain approvals or permits for construction, modification or operation of certain projects or facilities and may require use of emission controls.

Global Warming and Climate Change

Some scientific studies suggest that emissions of greenhouse gases (including carbon dioxide and methane) may contribute to warming of the Earth’s atmosphere. While we do not believe our operations raise climate change issues different from those generally raised by commercial use of fossil fuels, legislation or regulatory programs that restrict greenhouse gas emissions in areas where we conduct business could increase our costs in order to comply with any new laws.

Water Discharges

We operate facilities that are subject to requirements of the Clean Water Act, as amended, or “CWA,” and analogous state laws that impose restrictions and controls on the discharge of pollutants into navigable waters. Spill prevention, control and counter-measure requirements under the CWA require implementation of measures to help prevent the contamination of navigable waters in the event of a hydrocarbon spill. Other requirements for the prevention of spills are established under the Oil Pollution Act of 1990, as amended, or “OPA,” which amends the CWA and applies to owners and operators of vessels, including barges, offshore platforms and certain onshore facilities. Under OPA, regulated parties are strictly jointly and severally liable

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for oil spills and must establish and maintain evidence of financial responsibility sufficient to cover liabilities related to an oil spill for which such parties could be statutorily responsible.

Occupational Safety and Health Act

We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or “OSHA,” and comparable state laws that regulate the protection of employee health and safety. OSHA’s hazard communication standard requires that information about hazardous materials used or produced in our operations be maintained and provided to employees and state and local government authorities. We believe that our operations are in substantial compliance with OSHA requirements.

Saltwater Disposal Wells

We operate SWD wells that are subject to the CWA, Safe Drinking Water Act, and state and local laws and regulations, including those established by the Underground Injection Control Program of the Environmental Protection Agency (“EPA”), which establishes the minimum program requirements. Most of our SWD wells are located in Texas. We also operate SWD wells in Arkansas, Louisiana, New Mexico and North Dakota. Regulations in these states require us to obtain an Underground Injection Control permit to operate each of our SWD wells. The applicable regulatory agency may suspend or modify one of our permits if our well operation is likely to result in pollution of freshwater, substantial violation of permit conditions or applicable rules, or if the well leaks into the environment.

Access to Company Reports

Our Web site address is www.keyenergy.com, and we make available free of charge through our Web site our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports, as soon as reasonably practicable after such materials are electronically filed with the Securities and Exchange Commission (the “SEC”). Our Web site also includes general information about us, including our Corporate Governance Guidelines and charters for the committees of our board of directors. Information on our Web site or any other Web site is not a part of this report.

ITEM 1A.   RISK FACTORS

In addition to the other information in this report, the following factors should be considered in evaluating us and our business.

BUSINESS-RELATED RISK FACTORS

Our business is cyclical and depends on conditions in the oil and natural gas industry, especially oil and natural gas prices and capital expenditures by oil and natural gas companies. Volatility in oil and natural gas prices, tight credit markets and disruptions in the U.S. and global financial systems may adversely impact our business.

Prices for oil and natural gas historically have been extremely volatile and have reacted to changes in the supply of, and demand for, oil and natural gas. These include changes resulting from, among other things, the ability of the Organization of Petroleum Exporting Countries to support oil prices, domestic and worldwide economic conditions and political instability in oil-producing countries. We depend on our customers’ willingness to make expenditures to explore for, develop and produce oil and natural gas. Therefore, weakness in oil and natural gas prices (or the perception by our customers that oil and natural gas prices will decrease in the future) could result in a reduction in the utilization of our equipment and result in lower rates for our services. Our customers’ willingness to undertake these activities depends largely upon prevailing industry conditions that are influenced by numerous factors over which we have no control, including:

•  prices, and expectations about future prices, of oil and natural gas;

•  domestic and worldwide economic conditions;

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•  domestic and foreign supply of and demand for oil and natural gas;

•  the price and quantity of imports of foreign oil and natural gas;

•  the cost of exploring for, developing, producing and delivering oil and natural gas;

•  available pipeline, storage and other transportation capacity;

•  lead times associated with acquiring equipment and products and availability of qualified personnel;

•  the expected rates of decline in production from existing and prospective wells;

•  the discovery rates of new oil and gas reserves;

•  federal, state and local regulation of exploration and drilling activities and equipment, material or supplies that we furnish;

•  public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;

•  weather conditions, including hurricanes that can affect oil and natural gas operations over a wide area and severe winter weather that can interfere with our sand mining operations;

•  political instability in oil and natural gas producing companies;

•  advances in exploration, development and production technologies or in technologies affecting energy consumption;

•  the price and availability of alternative fuel and energy sources; and

•  uncertainty in capital and commodities markets and the ability of oil and natural gas producers to raise equity capital and debt financing.

The level of oil and natural gas exploration and production activity in the United States is volatile. A reduction in the activity levels of our customers could cause a decline in the demand for our services and may adversely affect the prices that we can charge or collect for our services. In addition, any prolonged substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and, therefore, would affect demand for the services we provide. A material decline in oil and natural gas prices or drilling activity levels or sustained lower prices or activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flow. Moreover, reduced discovery rates of new oil and natural gas reserves, or a decrease in the development rate of reserves, in our market areas, whether due to increased governmental regulation, limitations on exploration and drilling activity or other factors, could also have a material adverse impact on our business, even in a stronger oil and natural gas price environment.

We operate in a highly cyclical industry. Changes in current or anticipated future prices for crude oil and natural gas are a primary factor affecting spending and drilling activity by exploration and production companies, and decreases in spending and drilling activity can cause rapid and material declines in demand for our services. For example, in 2009 adverse changes in capital and credit markets and declines in prices for oil and natural gas caused many exploration and production companies to reduce capital budgets and drilling activity. This trend resulted in a significant decline in demand for our services, had a material negative impact on the prices we were able to charge our customers, and adversely affected our equipment utilization and results of operations. Future cuts in spending levels or drilling activity could have similar adverse effects on our operating results and financial condition, and such effects could be material.

We may be unable to implement price increases or maintain existing prices on our core services.

We periodically seek to increase the prices on our services to offset rising costs and to generate higher returns for our stockholders. However, we operate in a very competitive industry and as a result, we are not always successful in raising, or maintaining, our existing prices. For example, beginning in the third quarter of 2008 and continuing through the first half of 2009, we were required to make price concessions in order to maintain market share. Additionally, during periods of increased market demand, a significant amount of new

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service capacity, including new well service rigs, coiled tubing units and new fishing and rental equipment, may enter the market, which also puts pressure on the pricing of our services and limits our ability to increase prices.

Even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset such rising costs. In periods of high demand for oilfield services, a tighter labor market may result in higher labor costs. For example in 2010, our labor costs increased at a greater rate than our ability to raise prices for our services. During such periods, we may not be able to successfully increase prices without adversely affecting demand for our services.

The inability to maintain our pricing and to increase our pricing as costs increase could have a material adverse effect on our business, financial position and results of operations.

Increased labor costs or the unavailability of skilled workers could hurt our operations.

Companies in our industry, including us, are dependent upon the available labor pool of skilled employees. We compete with other oilfield services businesses and other employers to attract and retain qualified personnel with the technical skills and experience required to provide our customers with the highest quality service. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require us to enhance our wage and benefits packages. We cannot assure you that labor costs will not increase. Increases in our labor costs could have a material adverse effect on our business, financial condition and results of operations.

Our future financial results could be adversely impacted by asset impairments or other charges.

We have recorded goodwill impairment charges and asset impairment charges in the past. We evaluate our long-lived assets, including our property and equipment, indefinite-lived intangible assets, and goodwill for impairment. In performing these assessments, we project future cash flows on a discounted basis for goodwill, and on an undiscounted basis for other long-lived assets, and compare these cash flows to the carrying amount of the related assets. These cash flow projections are based on our current operating plans, estimates and judgmental assumptions. We perform the assessment of potential impairment on our goodwill and indefinite-lived intangible assets at least annually, or more often if events and circumstances warrant. We perform the assessment of potential impairment for our property and equipment whenever facts and circumstances indicate that the carrying value of those assets may not be recoverable due to various external or internal factors. If we determine that our estimates of future cash flows were inaccurate or our actual results are materially different from what we have predicted, we could record additional impairment charges in future periods, which could have a material adverse effect on our financial position and results of operations.

We have operated at a loss in the past and there is no assurance of our profitability in the future.

We had net operating losses from continuing operations during each of the six fiscal quarters ended December 31, 2010. In the future, we may incur further operating losses and experience negative operating cash flow. We may not be able to reduce our costs, increase revenues, or reduce our debt service obligations sufficient to achieve profitability and generate positive operating income in the future.

Our business involves certain operating risks, which are primarily self-insured, and our insurance may not be adequate to cover all losses or liabilities we might incur in our operations.

Our operations are subject to many hazards and risks, including the following:

•  accidents resulting in serious bodily injury and the loss of life or property;

•  liabilities from accidents or damage by our fleet of trucks, rigs and other equipment;

•  pollution and other damage to the environment;

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•  reservoir damage;

•  blow-outs, the uncontrolled flow of natural gas, oil or other well fluids into the atmosphere or an underground formation; and

•  fires and explosions.

If any of these hazards occur, they could result in suspension of operations, damage to or destruction of our equipment and the property of others, or injury or death to our or a third party’s personnel.

We self-insure against a significant portion of these liabilities. For losses in excess of our self-insurance limits, we maintain insurance from unaffiliated commercial carriers. However, our insurance may not be adequate to cover all losses or liabilities that we might incur in our operations. Furthermore, our insurance may not adequately protect us against liability from all of the hazards of our business. We also are subject to the risk that we may not be able to maintain or obtain insurance of the type and amount we desire at a reasonable cost. If we were to incur a significant liability for which we were uninsured or for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows.

We are subject to the economic, political and social instability risks of doing business in certain foreign countries.

We currently have operations based in Mexico, Colombia, the Middle East, Russia, Argentina and a technology development group based in Canada, and have ownership interests in two oilfield service companies based in Canada. In the future, we may expand our operations into other foreign countries. As a result, we are exposed to risks of international operations, including:

•  increased governmental ownership and regulation of the economy in the markets where we operate;

•  inflation and adverse economic conditions stemming from governmental attempts to reduce inflation, such as imposition of higher interest rates and wage and price controls;

•  economic and financial instability of national oil companies;

•  increased trade barriers, such as higher tariffs and taxes on imports of commodity products;

•  exposure to foreign currency exchange rates;

•  exchange controls or other currency restrictions;

•  war, civil unrest or significant political instability;

•  restrictions on repatriation of income or capital;

•  expropriation, confiscatory taxation, nationalization or other government actions with respect to our assets located in the markets where we operate;

•  governmental policies limiting investments by and returns to foreign investors;

•  labor unrest and strikes, including the significant labor-related issues we have experienced in Argentina;

•  deprivation of contract rights; and

•  restrictive governmental regulation and bureaucratic delays.

The occurrence of one or more of these risks may:

•  negatively impact our results of operations;

•  restrict the movement of funds and equipment to and from affected countries; and

•  inhibit our ability to collect receivables.

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Historically, we have experienced a high employee turnover rate. Any difficulty we experience replacing or adding workers could adversely affect our business.

Historically, we have experienced a high annual employee turnover rate. We believe that the high turnover rate is attributable to the nature of the work, which is physically demanding and performed outdoors. As a result, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive with ours. The potential inability or lack of desire by workers to commute to our facilities and job sites, as well as the competition for workers from competitors or other industries, are factors that could negatively affect our ability to attract and retain workers. We cannot assure that we will be able to recruit, train and retain an adequate number of workers to replace departing workers. The inability to maintain an adequate workforce could have a material adverse effect on our business, financial condition and results of operations.

We may not be successful in implementing and maintaining technology development and enhancements.

An important component of our business strategy is to incorporate the KeyView^® system, our proprietary technology, into our well service rigs. The inability to successfully develop, integrate and protect this technology could:

•  limit our ability to improve our market position;

•  increase our operating costs; and

•  limit our ability to recoup the investments made in this technological initiative.

We may incur significant costs and liabilities as a result of environmental, health and safety laws and regulations that govern our operations.

Our operations are subject to U.S. federal, state and local and foreign laws and regulations that impose limitations on the discharge of pollutants into the environment and establish standards for the handling, storage and disposal of waste materials, including toxic and hazardous wastes. To comply with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various governmental authorities. While the cost of such compliance has not been significant in the past, new laws, regulations or enforcement policies could become more stringent and significantly increase our compliance costs or limit our future business opportunities, which could have a material adverse effect on our results of operations.

Failure to comply with environmental, health and safety laws and regulations could result in the assessment of administrative, civil or criminal penalties, imposition of cleanup and site restoration costs and liens, revocation of permits, and, to a lesser extent, orders to limit or cease certain operations. Certain environmental laws impose strict and/or joint and several liability, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time of those actions.

Severe weather could have a material adverse effect on our business.

Our business could be materially and adversely affected by severe weather. Oil and natural gas operations of our customers located in Louisiana and parts of Texas may be adversely affected by hurricanes and tropical storms, resulting in reduced demand for our services. Furthermore, our customers’ operations in the Rocky Mountain and Atlantic Coast regions of the United States may be adversely affected by seasonal weather conditions in the winter months. Adverse weather can also directly impede our own operations. Repercussions of severe weather conditions may include:

•  curtailment of services;

•  weather-related damage to facilities and equipment, resulting in suspension of operations;

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•  inability to deliver equipment, personnel and products to job sites in accordance with contract schedules; and

•  loss of productivity.

These constraints could delay our operations and materially increase our operating and capital costs. Unusually warm winters may also adversely affect the demand for our services by decreasing the demand for natural gas.

We may not be successful in identifying, making and integrating acquisitions.

An important component of our growth strategy is to make acquisitions that will strengthen our core services or presence in selected markets. The success of this strategy will depend, among other things, on our ability to identify suitable acquisition candidates, to negotiate acceptable financial and other terms, to timely and successfully integrate acquired business or assets into our existing businesses and to retain the key personnel and the customer base of acquired businesses. Any future acquisitions could present a number of risks, including but not limited to:

•  incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets;

•  failure to integrate successfully the operations or management of any acquired operations or assets in a timely manner;

•  diversion of management’s attention from existing operations or other priorities; and

•  inability to secure sufficient financing, on terms we find acceptable, that may be required for any such acquisition or investment.

Our business plan anticipates, and is based upon our ability to successfully complete and integrate, acquisitions of other businesses or assets in a timely and cost effective manner. Our failure to do so could have an adverse effect on our business, financial condition or results of operations.

The loss of one or more of our largest customers could materially and adversely affect our business, financial condition and results of operations.

Although no single customer accounted for more than 10% of our total consolidated revenues for the year ended December 31, 2010, our ten largest customers made up approximately 55% of our revenues. The loss of one or more of these customers could have an adverse effect on our business, financial condition and results of operations.

Compliance with climate change legislation or initiatives could negatively impact our business.

There have been new federal and state legislative and regulatory initiatives proposed in an attempt to control or limit the effects of greenhouse gas emissions, such as carbon dioxide. In June 2009, the U.S. House of Representatives approved The American Clean Energy and Security Act of 2009. However, neither this bill nor a related bill in the U.S. Senate, The Clean Energy and Emissions Power Act was passed by Congress. Several states have passed legislation which impose certain requirements on motor vehicle emissions and some states require greenhouse gas reporting. In addition, in response to its endangerment finding in 2009, EPA adopted regulations that restrict motor vehicle emissions. These regulations took effect on January 2, 2011. At this time, it is not possible to predict how legislation or new federal or state government mandates regarding the emission of greenhouse gases could impact our business; however, any such future laws or regulations could require us or our customers to devote potentially material amounts of capital or other resources in order to comply with such regulations. These expenditures could have a material adverse impact on our financial position, results of operations, or cash flows.

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DEBT-RELATED RISK FACTORS

We may not be able to generate sufficient cash flow to meet our debt service obligations.

Our ability to make payments on our indebtedness, and to fund planned capital expenditures, will depend on our ability to generate cash in the future. This, to a certain extent, is subject to conditions in the oil and natural gas industry, general economic and financial conditions, competition in the markets where we operate, the impact of legislative and regulatory actions on how we conduct our business and other factors, all of which are beyond our control. This risk could be exacerbated by any economic downturn or instability in the U.S. and global credit markets.

We cannot assure you that our business will generate sufficient cash flow from operations to service our outstanding indebtedness, or that future borrowings will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other capital needs. If our business does not generate sufficient cash flow from operations to service our outstanding indebtedness, we may have to undertake alternative financing plans, such as:

•  refinancing or restructuring our debt;

•  selling assets;

•  reducing or delaying acquisitions or capital investments, such as remanufacturing our rigs and related equipment; or

•  seeking to raise additional capital.

We may not be able to implement alternative financing plans, if necessary, on commercially reasonable terms or at all, and implementing any such alternative financing plans may not allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, or to obtain alternative financings, could materially and adversely affect our business, financial condition, results of operations and future prospects for growth.

In addition, a downgrade in our credit rating would make it more difficult for us to raise additional debt financing in the future. However, such a credit downgrade would not have an effect on our currently outstanding senior debt under our indenture or senior secured credit facility.

The amount of our debt and the covenants in the agreements governing our debt could negatively impact our financial condition, results of operations and business prospects.

Our level of indebtedness, and the covenants contained in the agreements governing our debt, could have important consequences for our operations, including:

•  making it more difficult for us to satisfy our obligations under our indebtedness and increasing the risk that we may default on our debt obligations;

•  requiring us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;

•  limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities;

•  limiting management’s flexibility in operating our business;

•  limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

•  diminishing our ability to withstand successfully a downturn in our business or the economy generally;

•  placing us at a competitive disadvantage against less leveraged competitors; and

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•  making us vulnerable to increases in interest rates, because certain debt will vary with prevailing interest rates.

We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the consequent acceleration of our obligation to repay outstanding debt. Our ability to comply with debt covenants and other restrictions may be affected by events beyond our control, including general economic and financial conditions.

In particular, under the terms of our indebtedness, we must comply with certain financial ratios and satisfy certain financial condition tests, several of which become more restrictive over time and could require us to take action to reduce our debt or take some other action in order to comply with them. Our ability to satisfy required financial ratios and tests can be affected by events beyond our control, including prevailing economic, financial and industry conditions, and we cannot assure you that we will continue to meet those ratios and tests in the future. A breach of any of these covenants, ratios or tests could result in a default under our indebtedness. If we default, our credit facility lenders will no longer be obligated to extend credit to us and they, as well as the trustee for our outstanding notes, could elect to declare all amounts outstanding under the indenture or senior secured credit facility, as applicable, together with accrued interest, to be immediately due and payable. The results of such actions would have a significant negative impact on our results of operations, financial position and cash flows.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our senior secured credit facility bear interest at variable rates, exposing us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.

TAKEOVER PROTECTION-RELATED RISKS

Our bylaws contain provisions that may prevent or delay a change in control.

Our bylaws contain certain provisions designed to enhance the ability of the board of directors to respond to unsolicited attempts to acquire control of the Company. These provisions:

•  establish a classified board of directors, providing for three-year staggered terms of office for all members of our board of directors;

•  set limitations on the removal of directors;

•  provide our board of directors the ability to set the number of directors and to fill vacancies on the board of directors occurring between stockholder meetings; and

•  set limitations on who may call a special meeting of stockholders.

These provisions may have the effect of entrenching management and may deprive investors of the opportunity to sell their shares to potential acquirers at a premium over prevailing prices. This potential inability to obtain a control premium could reduce the price of our common stock.

ITEM 1B.   UNRESOLVED STAFF COMMENTS

None.

ITEM 2.   PROPERTIES

We lease office space for our principal executive offices in Houston, Texas. We also lease local office space in the various countries in which we operate. Additionally, we own or lease numerous rig facilities,

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storage facilities, truck facilities and sales and administrative offices throughout the geographic regions in which we operate. Also, in connection with our fluid management services, we operate a number of owned and leased SWD facilities, and brine and freshwater stations. Our leased properties are subject to various lease terms and expirations.

We believe all properties that we currently occupy are suitable for their intended uses. We believe that we have sufficient facilities to conduct our operations. However, we continue to evaluate the purchase or lease of additional properties or the consolidation of our properties, as our business requires.

The following table shows our active owned and leased properties, as well as active SWD facilities, categorized by geographic region:

	Office, Repair &		SWDs, and Brine and		Operational Field
	Service and Other		Freshwater Stations		Services Facilities
Region	(1)		(2)		(3)
United States
Owned		16		49		102
Leased		27		38		60
International
Owned		3		0		3
Leased		31		0		9
TOTAL		77		87		174

(1)	Includes four apartments leased in the United States and twelve apartments leased in Argentina for Key employees to use for operational support and business purposes only. Also includes one staff house leased in Colombia for Key employees and three properties in Russia leased by Geostream Services Group and its subsidiaries (“Geostream”).
(2)	Includes SWD facilities as “leased” if we own the wellbore for the SWD but lease the land. In other cases, we lease both the wellbore and the land. Lease terms vary among different sites, but with respect to some of the SWD facilities for which we lease the land and own the wellbore, the land owner has an option under the land lease to retain the wellbore at the termination of the lease.
(3)	Includes one property in Russia owned by Geostream and one leased property in the Middle East.

ITEM 3.   LEGAL PROCEEDINGS

We are subject to various suits and claims that have arisen in the ordinary course of business. We do not believe that the disposition of any of our ordinary course litigation will result in a material adverse effect on our consolidated financial position, results of operations or cash flows. For additional information on legal proceedings, see “Note 16. Commitments and Contingencies” in “Item 8. Financial Statements and Supplementary Data.”

ITEM 4.   (REMOVED AND RESERVED)

PART II

ITEM 5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market and Share Prices

Our common stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “KEG.” As of February 16, 2011, there were 751 registered holders of 142,585,543 issued and outstanding shares of common stock. This number of registered holders does not include holders that have shares of common stock held for them in “street name”, meaning that the shares are held for their accounts by a broker or other nominee. In these instances, the brokers or other nominees are included in the number of registered holders,

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but the underlying holders of the common stock that have shares held in “street name” are not. The following table sets forth the reported high and low closing price of our common stock for the periods indicated:

	High		Low
Year Ended December 31, 2010
1st Quarter	$	11.26	$	8.64
2nd Quarter		11.15		8.91
3rd Quarter		9.92		8.01
4th Quarter		13.29		9.70

	High		Low
Year Ended December 31, 2009
1st Quarter	$	5.47	$	2.12
2nd Quarter		7.01		2.79
3rd Quarter		9.58		4.82
4th Quarter		9.50		7.00

The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate it by reference into such filing.

The following performance graph compares the performance of our common stock to the PHLX Oil Service Sector, the Russell 1000 Index, the Russell 2000 Index and to a peer group established by management. During 2008, we moved from the Russell 2000 Index to the Russell 1000 Index and, during 2009, we moved back from the Russell 1000 Index to the Russell 2000 Index. For comparative purposes, both the Russell 2000 and the Russell 1000 Indices are reflected in the following performance graph. The peer group consists of five other companies with a similar mix of operations and includes Nabors Industries Ltd., Weatherford International Ltd., Basic Energy Services, Inc., Complete Production Services, Inc. and RPC, Inc. The graph below compares the cumulative five-year total return to holders of our common stock with the cumulative total returns of the PHLX Oil Service Sector, the listed Russell Indices and our peer group. The graph assumes that the value of the investment in our common stock and each index (including reinvestment of dividends) was $100 at December 31, 2005 and tracks the return on the investment through December 31, 2010.

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COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Key Energy Services, Inc., The PHLX Oil Service Sector, The Russell 1000 Index,
The Russell 2000 Index, and the Peer Group

* $100 invested on December 31, 2005 in stock or index, including reinvestment of dividends. Fiscal years ended December 31.

Dividend Policy

There were no dividends declared or paid on our common stock for the years ended December 31, 2010, 2009 and 2008. Under the terms of our current credit facility, we must meet certain financial covenants before we may pay dividends. We do not currently intend to pay dividends.

Issuer Purchases of Equity Securities

During the fourth quarter of 2010, we repurchased an aggregate of 41,278 shares of our common stock. The repurchases were to satisfy tax withholding obligations that arose upon vesting of restricted stock. Set forth below is a summary of the share repurchases:

						Total Number of Shares
						Purchased as Part of
	Total Number		Weighted			Publicly Announced
	of Shares		Average Price			Plans or
Period	Purchased		Paid Per Share			Programs
October 1, 2010 to October 31, 2010		34,912	$	9.74	(1)		—
November 1, 2010 to November 30, 2010		1,103	$	10.29	(2)		—
December 1, 2010 to December 31, 2010		5,263	$	11.06	(3)		—

(1) The price paid per share on the vesting date with respect to the tax withholding repurchases was determined using the closing price on October 1, 2010, as quoted on the NYSE.

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(2)	The price paid per share on the vesting date with respect to the tax withholding repurchases was determined using the closing prices on November 1, 2010 and November 12, 2010, as quoted on the NYSE.
(3)	The price paid per share on the vesting date with respect to the tax withholding repurchases was determined using the closing price on December 4, 2010 and December 10, 2010, as quoted on the NYSE.

Equity Compensation Plan Information

The following table sets forth information as of December 31, 2010 with respect to equity compensation plans (including individual compensation arrangements) under which our common stock is authorized for issuance:

	Number of Securities		Weighted Average		Number of Securities Remaining
	to be Issued Upon		Exercise Price of		Available for Future Issuance
	Exercise of		Outstanding		Under Equity Compensation
	Outstanding Options,		Options, Warrants		Plans (Excluding Securities
	Warrants And Rights		And Rights		Reflected in Column (a))
Plan Category	(a)		(b)		(c)
	(In thousands)				(In thousands)
Equity compensation plans approved by stockholders(1)		3,160	$	13.73		2,379
Equity compensation plans not approved by stockholders(2)		180	$	5.71		—
Total		3,340				2,379

(1)	Represents options and other stock-based awards granted under the Key Energy Services, Inc. 2009 Equity and Cash Incentive Plan (the “2009 Incentive Plan”), the Key Energy Services, Inc. 2007 Equity and Cash Incentive Plan (the “2007 Incentive Plan”), and the Key Energy Group, Inc. 1997 Incentive Plan (the “1997 Incentive Plan”). The 1997 Incentive Plan expired in November 2007.
(2)	Represents non-statutory stock options and warrants granted outside the 1997 Incentive Plan, the 2007 Incentive Plan, and the 2009 Incentive Plan. The options have a ten-year term and other terms and conditions as those options granted under the 1997 Incentive Plan. These options were granted during 2000 and 2001. The warrants have a five-year term and were granted during 2009.

Sale of Unregistered Securities

On December 20, 2010, we issued 54,400 shares of common stock in connection with the exercise of warrants to purchase shares of the Company’s common stock. On May 12, 2009, in connection with the settlement of a lawsuit, the Company had issued to two individuals warrants to purchase shares of the Company’s common stock. The issuance of shares upon exercise of the warrants was made in reliance upon the exemption from the registration requirements of the Securities Act of 1933 provided by Section 4(2) thereof for transactions by an issuer not involving any public offering.

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ITEM 6.   SELECTED FINANCIAL DATA

The following historical selected financial data as of and for the years ended December 31, 2006 through December 31, 2010 has been derived from our audited financial statements included in “Item 8. Financial Statements and Supplementary Data.” For the years ended December 31, 2006 through December 31, 2010, we have reclassified the historical results of operations of our pressure pumping and wireline businesses to discontinued operations. The historical selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and related notes thereto included in “Item 8. Financial Statements and Supplementary Data.”

RESULTS OF OPERATIONS DATA

	Year Ended December 31,
	2010			2009			2008			2007			2006
	(In thousands, except per share amounts)
REVENUES	$	1,153,684		$	955,699		$	1,624,446		$	1,358,327		$	1,305,925
COSTS AND EXPENSES:
Direct operating expenses		835,012			675,942			1,005,850			791,595			785,083
Depreciation and amortization expense		137,047			149,233			149,607			111,211			113,336
General and administrative expenses		198,271			172,140			246,345			218,637			185,791
Asset retirements and impairments		—			97,035			26,101			—			—
Interest expense, net of amounts capitalized		41,959			39,405			42,622			37,206			39,511
Other, net		(2,697	)		(834	)		2,552			4,045			(9,356	)
Total costs and expenses, net		1,209,592			1,132,921			1,473,077			1,162,694			1,114,365
(Loss) income from continuing operations before income taxes and noncontrolling interest		(55,908	)		(177,222	)		151,369			195,633			191,560
Income tax benefit (expense)		20,512			65,974			(81,900	)		(75,695	)		(72,196	)
(Loss) income from continuing operations before noncontrolling interest		(35,396	)		(111,248	)		69,469			119,938			119,364
Income (loss) from discontinued operations, net of tax		105,745			(45,428	)		14,344			49,234			51,669
Net income (loss)		70,349			(156,676	)		83,813			169,172			171,033
Loss attributable to noncontrolling interest		(3,146	)		(555	)		(245	)		(117	)		—
INCOME (LOSS) ATTRIBUTABLE TO KEY	$	73,495		$	(156,121	)	$	84,058		$	169,289		$	171,033
(Loss) income per share from continuing operations attributable to Key:
Basic	$	(0.25	)	$	(0.91	)	$	0.56		$	0.91		$	0.91
Diluted	$	(0.25	)	$	(0.91	)	$	0.56		$	0.90		$	0.89
Income (loss) per share from discontinued operations attributable to Key:
Basic	$	0.82		$	(0.38	)	$	0.12		$	0.38		$	0.39
Diluted	$	0.82		$	(0.38	)	$	0.11		$	0.37		$	0.39
Income (loss) per share attributable to Key:
Basic	$	0.57		$	(1.29	)	$	0.68		$	1.29		$	1.30
Diluted	$	0.57		$	(1.29	)	$	0.67		$	1.27		$	1.28

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CASH FLOW DATA

	Year Ended December 31,
	2010			2009			2008			2007			2006
	(In thousands)
Net cash provided by operating activities	$	129,805		$	184,837		$	367,164		$	249,919		$	258,724
Net cash used in investing activities		(8,631	)		(110,636	)		(329,074	)		(302,847	)		(245,647	)
Net cash (used in) provided by financing activities		(100,205	)		(127,475	)		(7,970	)		23,240			(18,634	)
Effect of changes in exchange rates on cash		(1,735	)		(2,023	)		4,068			(184	)		(238	)

BALANCE SHEET DATA

	Year Ended December 31,
	2010		2009		2008		2007		2006
	(In thousands)
Working capital	$	132,385	$	194,363	$	285,749	$	253,068	$	265,498
Property and equipment, gross		1,832,443		1,647,718		1,635,424		1,403,726		1,139,819
Property and equipment, net		936,744		794,269		898,696		771,002		587,641
Total assets		1,892,936		1,664,410		2,016,923		1,859,077		1,541,398
Long-term debt and capital leases, net of current maturities		427,121		523,949		633,591		511,614		406,080
Total liabilities		911,133		921,270		1,156,191		969,828		810,887
Equity		981,803		743,140		860,732		889,249		730,511
Cash dividends per common share		—		—		—		—		—

ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes thereto in “Item 8. Financial Statements and Supplementary Data.” The discussion below contains forward-looking statements that are based upon our current expectations and are subject to uncertainty and changes in circumstances including those identified in “Cautionary Note Regarding Forward-Looking Statements” above. Actual results may differ materially from these expectations due to inaccurate assumptions and known or unknown risks and uncertainties. Such forward-looking statements should be read in conjunction with our disclosures under “Item 1A. Risk Factors.”

Overview

We provide a full range of well 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 and coiled tubing-based well maintenance and workover services, well completion and recompletion services, fluid management services, and fishing and rental services and other ancillary oilfield services. Additionally, certain of our rigs are capable of specialty drilling applications. We operate in most major oil and natural gas producing regions of the continental United States, and have operations based in Mexico, Colombia, the Middle East, Russia and Argentina. In addition, we have a technology development group based in Canada and have ownership interests in two oilfield service companies based in Canada.

During 2010, we operated in two business segments, Well Servicing and Production Services. On October 1, 2010, we sold the majority of the lines of business within our Production Services segment. We

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also have a Functional Support segment associated with managing all of our reportable operating segments. For a full description of our operating segments, see “Service Offerings” in “Item 1. Business.”

Effective for the first quarter of 2011, we will begin reporting under two new business segments: U.S. and International. Financial results for all periods presented in future filings will be restated to reflect the change in operating segments. We revised our segments to reflect the change in our operating focus and our assessment of operations and resource allocation in making decisions regarding Key.

Business and Growth Strategies

Focus on Horizontal Well Services

In recent years the number of horizontal wells drilled has increased significantly. To capitalize on this growing market segment we have acquired new equipment, and upgraded existing equipment, capable of providing services integral to the completion and maintenance of horizontal wellbores. We recently added larger and higher horsepower well service rigs to our fleet that are capable of servicing the horizontal wellbores, and in 2010, we expanded the number of our coiled tubing units by 72%, 60% of which currently consist of extended-reach, long-lateral coiled tubing units. In addition, we established our fluids management business in the Bakken Shale in 2010. We intend to continue our focus on the expansion of horizontal well service offerings into new markets in the United States.

Continue Expansion in International Markets

We presently operate internationally in Mexico, Colombia, the Middle East, Russia and Argentina, areas with large oilfields with declining production. We believe that our domestic experience with mature oilfields and our proprietary technology, such as the KeyView^® system, provides us with the opportunity to compete for new business in foreign markets that have mature oilfields similar to those in the United States. We continue to evaluate international expansion opportunities and seek to redeploy underutilized assets to international markets.

Pursue Prudent Acquisitions in Complementary Businesses

We intend to continue our disciplined approach to acquisitions, seeking opportunities that strengthen our presence in selected regional markets and provide opportunities to expand our core services. For example, our recent acquisition of coiled tubing businesses expands the range of services that we can offer to customers engaged in the rapidly growing horizontal well drilling trend.

PERFORMANCE MEASURES

In determining the overall health of the oilfield service industry, we believe that the Baker Hughes U.S. land drilling rig count is the best barometer of capital spending and activity levels, 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.

	WTI Cushing Crude		NYMEX Henry Hub		Average Baker Hughes
Year	Oil(1)		Natural Gas(1)		U.S. Land Drilling Rigs(2)
2006	$	66.05	$	6.98		1,559
2007	$	72.34	$	7.12		1,695
2008	$	99.57	$	8.90		1,814
2009	$	61.95	$	4.28		1,046
2010	$	79.48	$	4.38		1,514

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

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Internally, we measure activity levels for our well servicing operations 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. We publicly release our monthly rig and trucking hours and the following table presents our quarterly rig and trucking hours from 2008 through 2010.

	Rig Hours		Trucking Hours
2010
First Quarter		485,183		459,292
Second Quarter		489,168		518,483
Third Quarter		503,890		559,181
Fourth Quarter		493,945		707,616
Total 2010:		1,972,186		2,244,572
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
2008
First Quarter		659,462		585,040
Second Quarter		701,286		603,632
Third Quarter		721,285		620,885
Fourth Quarter		634,772		607,004
Total 2008:		2,716,805		2,416,561

MARKET CONDITIONS AND OUTLOOK

Market Conditions — Year Ended December 31, 2010

During 2010, overall demand for the services that we provide improved considerably compared to 2009. The Baker Hughes U.S. land rig count average for 2010 was 1,514 rigs, up 44.8% compared to the 2009 average of 1,046 rigs. The increase in oilfield activity in 2010 was driven primarily by increases in oil prices, and the associated increase in capital spending on oilfield services during the year. During 2010, the West Texas Intermediate crude oil price averaged $79.48 per barrel, up 28.3% compared to the 2009 average price of $61.95 per barrel. Natural gas at the Henry Hub averaged $4.38 per Mcf in 2010, an increase of 2.3% from the 2009 average price of $4.28 per Mcf.

As a result of the increase in oil prices and our customers’ associated increase in capital spending, Key’s overall activity levels, asset utilization, and prices increased in 2010. In 2010, our rigs worked almost 2.0 million hours, an increase of 11.9% from the 1.8 million hours worked in 2009. Our fluid transportation trucks worked a total of 2.2 million hours in 2010, which was an increase of 29.3% compared to the 1.7 million trucking hours worked in 2009. Additionally, our customers’ capital spending and therefore our overall activity levels benefitted from the improved credit markets in 2010 compared to 2009.

As overall market conditions recovered from the lows experienced during 2009, we responded by making several strategic changes to better position Key in certain geographic areas and businesses that we perceived would yield higher long-term growth and better overall investment returns. In particular, we sold our pressure pumping and wireline businesses, sold our marine rig assets and significantly increased our investment in our coiled tubing business. Also in 2010, we upgraded or re-activated several well servicing and workover rigs, we

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made a significant investment in our fluid transportation business into the Bakken shale of the Williston Basin in North Dakota, and we deployed several rigs, fluid transportation trucks, coiled tubing units, and other assets into high growth regions including the Bakken shale and the Eagle Ford shale. Internationally, we initiated new operations in Colombia and Bahrain in the second half of 2010. In Colombia, our first project for $25 million involves two rigs over two years, and operations under this award started early in the fourth quarter 2010. In Bahrain, we were awarded our first project through our joint venture in the Middle East for two rigs over two years. One rig began operations in early December and the second rig began operating in early January. In Mexico, one of our two contracts with Pemex expired at the end of March 2010. The second of the two contracts remained in place in 2010, but it received limited funding during the year, leading to our activity levels in the country being significantly reduced through much of 2010.

Many of the temporary cost reduction measures we put into place in 2009, including reductions in wages and benefits, remained in place for most of 2010 and some were not re-instated until early 2011. While we continue to aggressively monitor and control costs, inflation of wages, fuel costs, and equipment costs remained a significant challenge throughout 2010.

Market Outlook

We believe the macro fundamental backdrop which drove the oilfield expansion in 2010 will remain present through 2011. Specifically, the ongoing global economic expansion continues to drive increased global demand for crude oil and natural gas. Despite the weak domestic natural gas fundamental outlook, we believe the strong fundamental oil outlook sets the stage for continued growth in production companies’ capital spending in 2011, both domestically and internationally. If there were a material change in the domestic or global economies in 2011, then the outlook for Key’s business in 2011 and 2012 could change.

We believe our U.S. lines of business will experience continued higher demand and resulting higher overall activity levels in 2011 compared to 2010. In our rig-based services business, we intend to address higher customer demand by continuing to upgrade and enhance several of our higher capability rigs, to improve operational efficiency of the existing fleet, and to grow our fleet through organic additions, particularly of larger rig classes.

In fluids management, our business tends to be driven by the overall number of producing oil and gas wells, as it relates to both the hauling of produced water from wells and the U.S. onshore rig count, but especially the horizontal onshore U.S. rig count, as it relates to the transportation of drilling fluid, completion fluid, and water to make frac fluids, to and from well sites. We continue to expand our fluid transportation fleet and invest in additional, strategically located SWD wells.

In our coiled tubing business, activity is driven by the number of producing oil and gas wells in the U.S. and new horizontal well drilling. We anticipate demand for all these services to remain strong in 2011, if not longer, particularly horizontal well completion and fracture stimulation related activities. In 2010, due to strong customer demand and limited availability of extended-reach, long-lateral coiled tubing fleets industry-wide, we realized higher levels of pricing. We anticipate a continued strong pricing environment for horizontal well driven coiled tubing services in 2011.

Our fishing and rental services business tends to be correlated to the onshore rig count. We anticipate moderate to strong customer demand growth in 2011, and we continue to invest in this business to meet that growth in demand with a greater inventory of fishing and rental tools; and we are seeking investments in new or existing technologies which can enhance our fishing and rental services.

Since our initial project award in Colombia in 2010, five additional rigs have been awarded projects for work in the country, bringing our total active rig fleet in Colombia to seven. All seven of these rigs were previously deployed in Mexico but were inactive in 2010. We anticipate strong demand for these rigs in Colombia through 2011 and beyond.

Since our initial project award in Bahrain, a third rig has been added to the scope of work, and it should begin operating in the first quarter of 2011. We anticipate the three rigs will remain active through 2012. The operation in the Middle East will be performed by our joint venture in the Middle East.

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In Mexico, Pemex has begun operating under its 2011 capital budget, and our activity levels have begun to increase from the depressed levels during 2010. We anticipate strong demand through most of 2011 for our rigs currently deployed in Mexico, primarily in the Chicontepec region. We continue to seek additional opportunities for work in other regions of Mexico, particularly in the south. If we were awarded additional work, we may deploy additional rig assets to the country.

In Argentina, overall activity levels continue to increase, driven by higher oil prices. We continue to seek better pricing for our services from our customers to generate appropriate returns for our investment in the country and to aggressively manage our costs.

In Russia, we anticipate better activity and financial performance in 2011 compared to 2010, as we expect the two new purpose-built, 1,000-HP drilling rigs and the two new purpose-built, 500-HP heavy workover rigs, for our joint venture in Russia, to contribute nearly a full year of operations in 2011.

Impact of Inflation on Operations

In 2011, we anticipate cost inflation to remain one of our biggest challenges. We expect that competition for experienced crews throughout the oilfield services industry will continue to put upward pressure on wages. Access to experienced, capable crews remains one of our biggest challenges to growth. We also anticipate the need to mitigate equipment and fuel costs in 2011. In addition to effective, active cost management, we endeavor to secure prices for our services which anticipate cost inflation, such that we can still generate an appropriate return for our services.

RESULTS OF OPERATIONS

Consolidated Results of Operations

The following table shows our consolidated results of operations for the years ended December 31, 2010, 2009 and 2008:

	Year Ended December 31,
	2010			2009			2008
	(In thousands)
REVENUES	$	1,153,684		$	955,699		$	1,624,446
COSTS AND EXPENSES:
Direct operating expenses		835,012			675,942			1,005,850
Depreciation and amortization expense		137,047			149,233			149,607
General and administrative expenses		198,271			172,140			246,345
Asset retirements and impairments		—			97,035			26,101
Interest expense, net of amounts capitalized		41,959			39,405			42,622
Other, net		(2,697	)		(834	)		2,552
Total costs and expenses, net		1,209,592			1,132,921			1,473,077
(Loss) income from continuing operations before taxes and noncontrolling interest		(55,908	)		(177,222	)		151,369
Income tax benefit (expense)		20,512			65,974			(81,900	)
(Loss) income from continuing operations before noncontrolling interest		(35,396	)		(111,248	)		69,469
Income (loss) from discontinued operations, net of tax		105,745			(45,428	)		14,344
Net Income (Loss)		70,349			(156,676	)		83,813
Loss attributable to noncontrolling interest		(3,146	)		(555	)		(245	)
INCOME (LOSS) ATTRIBUTABLE TO KEY	$	73,495		$	(156,121	)	$	84,058

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Year Ended December 31, 2010 and 2009

For the year ended December 31, 2010, income was $73.5 million, compared to a loss of $156.1 million for the year ended December 31, 2009. Income for 2010 was $0.57 per share compared to a loss of $1.29 per share for 2009. Included in income and income per share during 2010 is the gain on the sale of our pressure pumping and wireline businesses on October 1, 2010. Also, the 2009 results included asset retirement and impairment charges of $97.0 million that did not reoccur in 2010.

Revenues

Our revenues for the year ended December 31, 2010 increased $198.0 million, or 20.7% to $1.2 billion from $1.0 billion for the year ended December 31, 2009 as a result of increased activity and improved pricing compared to 2009 as well as the revenue contribution of acquisitions completed during 2010. See “Segment Operating Results — Year Ended December 31, 2010 and 2009” below for a more detailed discussion of the change in our revenues.

Direct operating expenses

Our direct operating expenses increased $159.1 million, or 23.5%, to $835.0 million (72.4% of revenues) for the year ended December 31, 2010, compared to $675.9 million (70.7% of revenues) for the year ended December 31, 2009 as a direct result of activity increases in our business as well as inflation in our operating costs. See “Segment Operating Results — Year Ended December 31, 2010 and 2009” below for a more detailed discussion of the change in our direct operating expenses.

Depreciation and amortization expense

Depreciation and amortization expense decreased $12.2 million, or 8.2%, to $137.0 million (11.9% of revenue) for the year ended December 31, 2010, compared to $149.2 million (15.6% of revenue) for the year ended December 31, 2009. The decrease in our depreciation and amortization expense is primarily attributable to decreases in the carrying value of our fixed assets due to the rig retirement and asset impairment charges recorded in the third quarter of 2009. Partially offsetting this decline are increases to our fixed asset base in 2010 due to our capital spending and acquisitions during the year.

General and administrative expenses

General and administrative expenses increased $26.1 million, or 15.2%, to $198.3 million (17.2% of revenues) for the year ended December 31, 2010, compared to $172.1 million (18.0% of revenues) for the year ended December 31, 2009. Our general and administrative expenses increased due to additional stock based compensation expense related to new equity awards in 2010 and bonuses paid in 2010 that were not present in 2009, offset by less professional fees during 2010 related to our cost reduction efforts. Transaction costs incurred during 2010 related to our acquisition of OFS also contributed to the increase.

Asset retirements and impairments

During the year ended December 31, 2010 we did not have any asset retirements or impairments compared to the year ended December 31, 2009, where we recognized a $97.0 million pre-tax charge associated with asset retirements and impairments. For 2009, our pre-tax charges included $65.9 million related to the retirement of certain of our rigs and associated equipment and a $31.1 million pre-tax impairment charge in our Production Services segment.

Interest expense, net of amounts capitalized

Interest expense increased $2.6 million to $42.0 million (3.6% of revenues) for the year ended December 31, 2010, compared to $39.4 million (4.1% of revenues) for the same period in 2009, due to higher interest rates on our borrowings under the Senior Secured Credit Facility, combined with lower capitalized interest due to lower capital expenditures related to the construction of equipment.

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Other, net

During the year ended December 31, 2010, we recognized other income, net, of $2.7 million, compared to other income, net, of $0.8 million for the year ended December 31, 2009. Other, net consists of:

	Year Ended December 31,
	2010			2009
	(In thousands)
Loss on early extinguishment of debt	$	—		$	472
Loss (gain) on disposal of assets, net		549			(309	)
Interest income		(112	)		(499	)
Foreign exchange gain		(1,541	)		(1,482	)
Other (income) expense, net		(1,593	)		984
Total	$	(2,697	)	$	(834	)

Income tax benefit (expense)

Our income tax benefit on continuing operations was $20.5 million (36.7% effective rate) on a pre-tax loss of $55.9 million for the year ended December 31, 2010, compared to an income tax benefit of $66.0 million (37.2% effective rate) on a pre-tax loss of $177.2 million in 2009. Our effective tax rates differ from the statutory rate of 35% primarily because of state, local and foreign income taxes, and the tax effects of permanent items attributable to book-tax differences.

Discontinued Operations

We recorded net income from discontinued operations of $105.7 million for the year ended December 31, 2010, compared to a net loss from discontinued operations of $45.4 million for the year ended December 31, 2009. The loss in 2009 mostly related to the asset impairment recorded on our pressure pumping equipment in the third quarter of 2009. Discontinued operations improved in 2010 for our fracturing and cementing services within our pressure pumping operations, due to higher activity, expansion into new markets and better pricing. We also recorded a gain on the sale of the discontinued operations in October 2010. See “Note 3. Discontinued Operations” under Item 8. for further discussion.

Noncontrolling Interest

For the year ended December 31, 2010, we allocated out $3.1 million, compared to $0.6 million for the year ended December 31, 2009, associated with the net loss incurred by our joint ventures.

Year Ended December 31, 2009 and 2008

For the year ended December 31, 2009, our loss was $156.1 million, a decrease from income of $84.1 million for the year ended December 31, 2008. The loss for 2009 was $1.29 per share compared to income of $0.67 per share for 2008. Items contributing to the net loss and diluted loss per share during 2009 included the retirement of a portion of our U.S. rig fleet and associated equipment ($65.9 million pre-tax) and an impairment to our Production Services segment ($31.1 million pre-tax). Also contributing to the loss was the dramatic and rapid decline in our activity levels and our inability to remove costs at the same pace as the decline in our revenue in 2009.

Revenues

Our revenues for the year ended December 31, 2009 were $1.0 billion, a decrease of $668.7 million, or 41.2%, from $1.6 billion for the year ended December 31, 2008. See “Segment Operating Results — Year Ended December 31, 2009 and 2008” below for a more detailed discussion of the change in our revenues.

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Direct operating expenses

Our direct operating expenses decreased $329.9 million, or 32.8%, to $675.9 million (70.7% of revenues) for the year ended December 31, 2009 compared to $1.0 billion (61.9% of revenues) for the year ended December 31, 2008. See “Segment Operating Results — Year Ended December 31, 2009 and 2008” below for a more detailed discussion of the change in our direct operating expenses.

Depreciation and amortization expense

Depreciation and amortization expense decreased $0.4 million, or less than 1.0%, to $149.2 million (15.6% of revenues) for the year ended December 31, 2009 compared to $149.6 million (9.2% of revenues) for the same period in 2008. Depreciation and amortization expense was flat year over year primarily due to a decrease in the depreciable asset base as a result of the rig retirement and asset impairment charges recorded in the third quarter of 2009, offset by increases due to the accelerated depreciation of assets that we removed from service during the first half of 2009 in response to a downturn in market conditions.

Asset retirements and impairments

For 2009, pre-tax charges included $65.9 million related to the retirement of certain of our rigs and associated equipment. We also recorded a $30.6 million pre-tax fixed asset impairment charge in our Production Services segment. Additionally, we determined that the goodwill recorded in 2009 for contingent consideration paid related to a prior year acquisition in the fishing and rental services line of business within our Production Services segment was impaired, and as such we recorded a pre-tax impairment charge of $0.5 million during 2009.

In 2008, we recorded a goodwill impairment charge of $20.7 million related to our pressure pumping services and fishing and rental services lines of business within our Production Services segment as the implied fair value of the goodwill was less than the carrying value.

During 2008, the fair value of our investment in IROC Energy Services Corp. (“IROC”), based on publicly available stock prices, remained below its book value. In the fourth quarter of 2008, management determined that, based on IROC’s continued depressed stock price and the overall negative outlook for the general economy and oilfield services sector, the impairment was other than temporary and as a result we recorded a pre-tax charge of $5.4 million in order to write the carrying value of our investment in IROC down to fair value.

General and administrative expenses

General and administrative expenses were $172.1 million (18.0% of revenues) for the year ended December 31, 2009, which represented a decrease of $74.2 million, or 30.1%, from $246.3 million (15.2% of revenues) for the same period in 2008. Our general and administrative expenses declined as a result of cost cutting measures that we put in place beginning in late 2008 and that continued into 2009 related to reductions in headcount, employee wage rate and benefits reductions, and controlled spending in overhead costs. Equity-based compensation was also lower during the year ended December 31, 2009 as a result of our having accelerated the vesting period on the majority of our stock option and stock appreciation right (“SAR”) awards during the fourth quarter of 2008. As a result of the acceleration, no expense was recognized on these awards during the year ended December 31, 2009.

Interest expense, net of amounts capitalized

Interest expense decreased $3.2 million, to $39.4 million (4.1% of revenues) for the year ended December 31, 2009, compared to $42.6 million (2.6% of revenues) for the same period in 2008. The decline was primarily attributable to lower average interest rates on our variable-rate debt instruments, and the repayment of $100.0 million of our revolving credit facility during the second quarter of 2009.

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Other, net

During the year ended December 31, 2009, we recognized other income, net, of $0.8 million, compared to other expense, net, of $2.6 million for the year ended December 31, 2008. Other, net consists of:

	Year Ended December 31,
	2009			2008
	(In thousands)
Loss on early extinguishment of debt	$	472		$	—
(Gain) loss on disposal of assets, net		(309	)		(929	)
Interest income		(499	)		(1,236	)
Foreign exchange (gain) loss		(1,482	)		3,547
Other expense, net		984			1,170
Total	$	(834	)	$	2,552

Income tax expense

Our income tax benefit was $66.0 million (37.2% effective rate) for the year ended December 31, 2009, compared to income tax expense of $81.9 million (54.1% effective rate) for the year ended December 31, 2008. Our effective tax rates differed from the statutory rate of 35% primarily because of state, local and foreign income taxes, and the tax effects of permanent items attributable to book-tax differences and for 2008, the impairment of goodwill.

Discontinued Operations

We recorded a net loss from discontinued operations of $45.4 million for the year ended December 31, 2009, compared to net income from discontinued operations of $14.3 million for the year ended December 31, 2008. The loss in 2009 mostly related to the asset impairment recorded on our pressure pumping equipment in the third quarter of 2009. See “Note 3. Discontinued Operations” under Item 8. for further discussion.

Noncontrolling Interest

For the year ended December 31, 2009, we allocated out $0.6 million, compared to $0.2 million for the year ended December 31, 2008, associated with the net loss incurred by our joint venture in the Russian Federation.

Segment Operating Results

Year Ended December 31, 2010 and 2009

The following table shows operating results for each of our reportable segments for the twelve month periods ended December 31, 2010 and 2009 (in thousands, except for percentages):

				Production			Functional
For The Year Ended December 31, 2010	Well Servicing			Services			Support
Revenues	$	980,271		$	173,413		$	—
Operating expenses		903,282			141,324			125,724
Operating income (loss)		76,989			32,089			(125,724	)
Operating income (loss), as a percentage of revenue		7.9	%		18.5	%		n/a

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				Production			Functional
For The Year Ended December 31, 2009	Well Servicing			Services			Support
Revenues	$	859,747		$	95,952		$	—
Operating expenses		781,504			110,225			105,586
Asset retirements and impairments		65,869			31,166			—
Operating income (loss)		12,374			(45,439	)		(105,586	)
Operating income (loss), as a percentage of revenue		1.4	%		(47.4	)%		n/a

Well Servicing

Revenues for our Well Servicing segment increased $120.5 million, or 14.0% to $980.3 million for the year ended December 31, 2010, compared to $859.7 million for the year ended December 31, 2009. The increase in revenues resulted from sequential improvements in U.S. activity since 2009, international expansion, improved pricing and additional revenues from 2010 acquisitions, offset by lower revenues attributable to our operations in Mexico due to a decrease in work for Pemex. During the fourth quarter of 2010, we commenced operations in Colombia and the Middle East and revenue for our fluid management business improved significantly in 2010 due to increased activity in the Bakken Shale market. However, our contract with Pemex expired in March 2010 resulting in unutilized assets in Mexico. Budget cuts in Mexico suppressed our work under the remaining Pemex contract through the second and third quarter. In the fourth quarter, Pemex extended our contract for an additional year as they began to operate under their 2011 budget.

Excluding charges for asset retirements in 2009, operating expenses for our Well Servicing segment were $903.3 million (92.1% of revenues) during the year ended December 31, 2010, which represented an increase of $121.8 million, or 15.6%, compared to $781.5 million (90.9% of revenues) in 2009. The increase in operating expenses is attributable to higher activity levels and related expansion costs in the U.S., as well as start up costs associated with our foreign expansion, severance costs incurred in Mexico due to a decrease in work for Pemex and overall inflation. We incurred additional costs in 2010 to integrate our newly acquired businesses and to expand our presence in the Bakken Shale. Also, we commenced operations in Colombia and the Middle East during the second half of 2010.

Production Services

Revenues for our Production Services segment increased $77.5 million, or 80.7%, to $173.4 million for the year ended December 31, 2010, compared to $96.0 million for the same period in 2009. The increase in revenue is attributable to the expansion of our coiled tubing services through organic growth and through acquisition as well as an increased activity in our fishing and rental operations due to improved economic conditions.

Excluding charges for asset retirements and impairments in 2009, operating expenses for our Production Services segment increased $31.1 million, or 28.2%, to $141.3 million (81.5% of revenues) for the year ended December 31, 2010, compared to $110.2 million (114.9% of revenues) in 2009. Operating expenses increased due to costs associated with the expansion of our coiled tubing operations; however, expenses as a percentage of revenue were lower due to improved pricing for services and additional activity.

Functional Support

Operating expenses for Functional Support increased $20.1 million to $125.7 million (10.9% of consolidated revenues) for the year ended December 31, 2010, compared to $105.6 million (11.0% of consolidated revenues) for 2009. The increase in costs relates primarily to bonuses paid in December 2010 that were not present in 2009, higher equity compensation expense due to new equity awards and implementation costs for a new ERP system conversion during the second quarter of 2010. Transaction costs incurred in 2010 related to our acquisition of OFS also contributed to the increase.

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Year Ended December 31, 2009 and 2008

The following table shows operating results for each of our reportable segments for the twelve month periods ended December 31, 2009 and 2008 (in thousands, except for percentages):

				Production			Functional
For The Year Ended December 31, 2009	Well Servicing			Services			Support
Revenues	$	859,747		$	95,952		$	—
Operating expenses		781,504			110,225			105,586
Asset retirements and impairments		65,869			31,166			—
Operating income (loss)		12,374			(45,439	)		(105,586	)
Operating income (loss), as a percentage of revenue		1.4	%		(47.4	)%		n/a

				Production			Functional
For The Year Ended December 31, 2008	Well Servicing			Services			Support
Revenues	$	1,470,332		$	154,114		$	—
Operating expenses		1,114,432			130,554			156,816
Asset retirements and impairments		—			20,716			5,385
Operating income (loss)		355,900			2,844			(162,201	)
Operating income (loss), as a percentage of revenue		24.2	%		1.8	%		n/a

Well Servicing

Revenues for our Well Servicing segment decreased $610.6 million, or 41.5% to $859.7 million for the year ended December 31, 2009, compared to $1.5 billion for the year ended December 31, 2008. The decline in revenues was attributable to lower activity levels and negative pricing pressure as a result of the general downturn in the markets for our services. The demand for our services declined in 2009 as a result of falling prices for oil and natural gas, the downturn in the U.S. and global economies, and tight credit markets, which combined to curtail capital spending by our customers. Partially offsetting this decline in activity was the expansion of our operations in Mexico and incremental rig hours from our Russian joint venture in 2009. For much of the year ended December 31, 2009, the primary focus of activity for our U.S. rig services business shifted more towards lower margin repair and maintenance work, and much of this work was performed for small and mid-sized independent operators. Our traditional customer base of major and large independent producers decreased their activity levels during the period, which led to lower activity and pricing for our U.S. rig services business.

Excluding charges for asset retirements, operating expenses for our Well Servicing segment were $781.5 million (90.9% of revenues) during the year ended December 31, 2009, which represented a decrease of $332.9 million, or 29.9%, compared to $1.1 billion (75.8% of revenues) for 2008. The decline in operating expenses during the year ended December 31, 2009 was attributable to lower employee compensation, lower repairs and maintenance expenses, and lower fuel costs. These costs declined due to our lower activity levels associated with the lower demand for our services during 2009 compared to 2008. We also implemented cost control measures beginning in the fourth quarter of 2008 in response to the downturn in demand for our services, but the dramatic and rapid decline in our revenues during 2009 outpaced our ability to cut costs.

Production Services

Revenues for our Production Services segment decreased $58.2 million, or 37.7%, to $96.0 million for the year ended December 31, 2009, compared to $154.1 million for the same period in 2008. The overall decline in revenue for this segment was primarily attributable to lower asset utilization resulting from the decline in gas-directed land drilling activity in the continental United States because of the continued depression of natural gas prices, overall uncertainty about the economy, and tight credit markets. The resulting pressure on pricing as other service providers attempted to maintain market share also impacted our revenues in 2009.

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Excluding charges for asset impairments, operating expenses for our Production Services segment decreased $20.3 million, or 15.6%, to $110.2 million (114.9% of revenues) for the year ended December 31, 2009, compared to $130.6 million (84.7% of revenues) for 2008. Operating expenses declined due to reductions in activity, lower fuel prices, decreased expenses for frac sand, and cost control measures we put in place beginning in the fourth quarter of 2008 in response to the downturn in demand for our services. Despite the decline in operating expenses, the dramatic and rapid decline in our revenues outpaced our ability to cut operating expenses for this segment during 2009, resulting in operating costs in excess of revenues.

Functional Support

Excluding the impairment charge on our investment in IROC during the fourth quarter of 2008, operating expenses for Functional Support decreased $51.2 million to $105.6 million (11.0% of consolidated revenues) for the year ended December 31, 2009, compared to $156.8 million (9.7% of consolidated revenues) for 2008. Operating expenses declined as a result of cost cutting measures that we put in place beginning in late 2008 and that continued into 2009 related to reductions in headcount, employee wage rates and benefits reductions, and controlled spending in overhead costs. Equity-based compensation was also lower during the year ended December 31, 2009 as a result of our having accelerated the vesting period on the majority of our stock option and SAR awards during the fourth quarter of 2008. As a result, no expense was recognized on these awards during 2009.

Liquidity and Capital Resources

We require capital to fund ongoing operations, including maintenance expenditures on our existing fleet and equipment, organic growth initiatives, investments and acquisitions. Our primary sources of liquidity are cash flows generated from our operations, available cash and availability under our Senior Secured Credit Facility. We intend to use these sources of liquidity to fund our working capital requirements, capital expenditures, strategic investments and acquisitions. Additionally, in March 2011, we will be required to make a tax payment of approximately $67 million related to U.S. federal and state income taxes.

As of December 31, 2010, we had no outstanding amounts borrowed under our Senior Secured Credit Facility. In 2011, we expect to access available funds under our Senior Secured Credit Facility to meet our cash requirements for day-to-day operations and in 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. We believe that our internally generated cash flows from operations, current reserves of cash and availability under our Senior Secured Credit Facility are sufficient to finance our cash requirements for current and future operations, budgeted capital expenditures and debt service for the next twelve months. Under the terms of the Senior Secured Credit Facility, committed letters of credit count against our borrowing capacity. All obligations under the Senior Secured Credit Facility are guaranteed by most of our subsidiaries and are secured by most of our assets, including our accounts receivable, inventory and equipment. See further discussion under “Debt Service” below.

As of December 31, 2010, we had working capital of $136.4 million, excluding the current portion of capital lease obligations of $4.0 million. Working capital at December 31, 2009 was $204.5 million, excluding the current portion of long-term debt, notes payable to related parties, and capital lease obligations totaling $10.2 million. Our working capital at December 31, 2010 decreased from 2009 as a result of increased current liabilities due to activity increases associated with improving market conditions during 2010 and use of cash under our capital spending plans, including acquisitions.

As of December 31, 2010, we had $56.6 million of cash, of which approximately $13.7 million was held in the bank accounts of our foreign subsidiaries. Of this amount, approximately $2.6 million was held by our joint ventures, which are subject to a noncontrolling interest and cannot be repatriated. Approximately $0.6 million of the cash held by our foreign subsidiaries was held in U.S. bank accounts and denominated in U.S. dollars. We believe that the cash held by our wholly-owned foreign subsidiaries could be repatriated for general corporate use without material withholdings.

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As of December 31, 2010, $59.4 million of letters of credit were outstanding under our revolving credit facility and we had $240.6 million of availability. On October 1, 2010, we borrowed $80.0 million under the credit facility to fund a portion of the purchase price of the OFS 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.

Cash Flows

During the year ended December 31, 2010, we generated cash flows from operating activities of $129.8 million, compared to $184.8 million for the year ended December 31, 2009. These operating cash inflows primarily relate to net income of $70.3 million, the collection of accounts receivable and receipt of a $53.2 million federal income tax refund, partially offset by cash paid against accounts payable and other liabilities due to the increase in activity.

Cash used in investing activities was $8.6 million and $110.6 million for years ended December 31, 2010 and 2009, respectively. Investing cash outflows decreased from 2009 due to the proceeds from the sale of our pressure pumping and wireline businesses and the sale of six barge rigs. Offsetting these proceeds were increased capital expenditures and cash paid for acquisitions.

Cash used in financing activities was $100.2 million during the year ended December 31, 2010, and $127.5 million for 2009. Financing cash outflows during 2010 consisted primarily of the net repayment of our revolving credit facility of $197.8 million, the repayment of capital lease obligations, and the repayment of the $6.0 million outstanding principal balance of a related party note.

The cash flows from discontinued operations have not been separately identified in our consolidated statements of cash flows for the years ended December 31, 2010, 2009 and 2008. We believe that the reduction in cash flows expected from discontinued operations will not have a material adverse impact on our liquidity or our ability to fund current or future operations and capital expenditures. We expect that the anticipated cash flows from the OFS businesses, will offset the reduction in cash flows from discontinued operations. Additionally, as we used a portion of the net proceeds from the sale of the discontinued operations to pay down the outstanding balance on our Senior Secured Credit Facility, we improved 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.

The following table summarizes our cash flows for the year ended December 31, 2010 and 2009:

	Year Ended December 31,
	2010			2009
	(In thousands)
Net cash provided by operating activities	$	129,805		$	184,837
Cash paid for capital expenditures		(180,310	)		(128,422	)
Acquisitions, net of cash acquired		(86,688	)		12,007
Proceeds from sale of fixed assets		258,202			5,580
Other investing activities, net		165			199
Repayments of capital lease obligations		(8,493	)		(9,847	)
Repayments of long term debt		(6,970	)		(16,552	)
Borrowings on revolving credit facility		110,000			—
Payments on revolving credit facility		(197,813	)		(100,000	)
Repurchases of common stock		(3,098	)		(488	)
Other financing activities, net		6,169			(588	)
Effect of changes in exchange rates on cash		(1,735	)		(2,023	)
Net increase (decrease) in cash and cash equivalents	$	19,234		$	(55,297	)

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Debt Service

At December 31, 2010, our annual maturities on our indebtedness, consisting only of our Senior Notes (defined below) at year-end, are as follows:

	Principal Payments
	(In thousands)
2011	$	—
2012		—
2013		—
2014		425,000
2015 and thereafter		—
Total	$	425,000

We have no maturities of debt in 2011. Interest on our Senior Notes is due on June 1 and December 1 of each year. Our Senior Notes mature in December 2014. Interest paid on the Senior Notes during 2010 was $35.6 million. Interest on the Senior Notes for 2011 will be $35.6 million. We expect to fund interest payments from cash on hand and cash generated by operations. In October 2010, we repaid the outstanding principal balance of $167.8 million under our revolving credit facility 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 of senior notes outstanding (the “Senior Notes”) that were issued in November 2007 under an indenture (the “Indenture”) with an 8.375% coupon rate. The Senior Notes were registered as public debt effective August 22, 2008.

The Senior Notes are general unsecured senior obligations of the Company. They rank effectively subordinate to all of our existing and future secured indebtedness. The Senior Notes are jointly and severally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. 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, at the redemption prices (expressed as percentages of the principal amount redeemed) below, plus accrued and unpaid interest 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	%

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, plus the Applicable Premium (as defined in the Indenture) with respect to the Senior Notes and plus accrued and unpaid interest to the redemption date. If we experience a change of control, subject to certain exceptions, we must give holders of the 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, plus accrued and unpaid interest to the date of purchase.

We are subject to certain negative 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;

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•  make investments;

•  incur additional indebtedness or issue preferred stock;

•  create certain liens;

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

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

•  engage in transactions with affiliates; and

•  create unrestricted subsidiaries.

These covenants are subject to certain exceptions and qualifications, and contain cross-default provisions in connection with the covenants of our Senior Secured Credit Facility. 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. As of December 31, 2010, the Senior Notes were below investment grade and have never been assigned investment grade. Any covenants that cease to apply to us as a result of achieving an investment grade rating will not be restored, even if the credit rating assigned to the Senior Notes later falls below an investment grade rating.

On February 14, 2011, we commenced an any and all cash tender offer and consent solicitation with respect to the Senior Notes. The tender offer is scheduled to expire at 12:00 midnight, New York City time on March 14, 2011, unless extended or earlier terminated. Our obligation to accept for purchase and to pay for Senior Notes in the tender offer is conditioned on, among other things, the tender of Senior Notes representing at least a majority of the aggregate principal amount of Senior Notes outstanding on or prior to March 14, 2011 and our having received replacement financing on terms acceptable to us. We intend to fund the repurchase of the Senior Notes, plus all related fees and expenses, from the proceeds of one or more capital markets debt offerings and borrowings under our Senior Secured Credit Facility.

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 Securities LLC and Wells Fargo Bank, N.A. are the administrative agents. 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.

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.

The interest rate per annum applicable to the Senior Secured Credit Facility 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;

•  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

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Secured Credit Facility, “EBITDA”) be no greater than (i) 2.50 to 1.00 for the fiscal quarter ending December 31, 2010 and, (ii) thereafter, 2.00 to 1.00;

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

for the fiscal quarter ending December 31, 2010	2.50 to 1.00
thereafter	3.00 to 1.00;

•  we limit our capital expenditures (not including any made by foreign subsidiaries that are not wholly-owned) to (i) $120.0 million during each 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;

•  we only make acquisitions that either (i) are completed for equity consideration, without regard to leverage, or (ii) are completed for cash consideration, but only (A) if the consolidated leverage ratio of total funded debt to trailing four quarters EBITDA is 2.75 to 1.00 or less, (x) there is an aggregate amount of $25.0 million in unused credit commitments under the facility and (y) we are in pro forma compliance with the financial covenants contained in the credit agreement; and (B) if the consolidated leverage ratio of total funded debt to trailing four quarters EBITDA is greater than 2.75 to 1.00, in addition to the requirements in subclauses (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

•  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 Senior Secured Credit Facility contains certain affirmative covenants, including, without limitation, restrictions related to (i) liens; (ii) debt, guarantees and other contingent obligations; (iii) mergers and consolidations; (iv) sales, transfers and other dispositions of property or assets; (v) loans, acquisitions, joint ventures and other investments; (vi) dividends and other distributions to, and redemptions and repurchases from, equity holders; (vii) prepaying, redeeming or repurchasing the Senior Notes or other unsecured debt incurred pursuant to the sixth bullet point listed above; (viii) granting negative pledges other than to the lenders; (ix) changes in the nature of our business; (x) amending organizational documents, or amending or otherwise modifying any debt if such amendment or modification would have a material adverse effect, or amending the Senior Notes or any other unsecured debt incurred pursuant to the sixth bullet point listed above if the effect of such amendment is to shorten the maturity of the Senior Notes or such other unsecured debt; and (xi) changes in accounting policies or reporting practices; in each of the foregoing cases, with certain exceptions.

We may prepay the Senior Secured Credit Facility in whole or in part at any time without premium or penalty, subject to our obligation to reimburse the lenders for breakage and redeployment costs.

On February 11, 2011, we received a commitment, subject to customary conditions, including syndication on a best efforts basis, for a new $400.0 million senior secured revolving credit facility, up to $250 million of which may be used for letters of credit. Pursuant to the commitment, the new credit facility would contain an accordion feature to expand the new facility in an aggregate amount up to $100.0 million. We expect to enter into the new credit facility on or before March 31, 2011. We expect the interest rate provisions applicable to loans under the new facility to be more favorable than those contained in our existing Senior Secured Credit Facility, and that the covenants in the new credit facility will be substantially similar to such existing facility, except that we expect to be permitted greater flexibility in both domestic and foreign investments.

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The closing of the new credit facility, and any borrowings thereunder, will be subject to the satisfaction of a number of customary conditions. We cannot assure you that we will be able to enter into the new credit facility on terms acceptable to us in a timely manner or at all.

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. 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. As of December 31, 2010, there was approximately $6.1 million outstanding under such equipment leases.

Off-Balance Sheet Arrangements

At December 31, 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.

Contractual Obligations

Set forth below is a summary of our contractual obligations as of December 31, 2010. The obligations we pay in future periods reflect certain assumptions, including variability in interest rates on our variable-rate obligations and the duration of our obligations, and actual payments in future periods may vary.

	Payments Due by Period
			Less than 1 Year		1-3 Years		4-5 Years		After 5 Years
	Total		(2011)		(2012-2014)		(2015-2016)		(2017+)
	(In thousands)
8.375% Senior Notes due 2014	$	425,000	$	—	$	425,000	$	—	$	—
Interest associated with 8.375% Senior Notes due 2014		142,478		35,595		106,883		—		—
Commitment and availability fees associated with Senior Secured Credit Facility		3,465		1,808		1,657		—		—
Capital lease obligations, excluding interest and executory costs		6,100		3,979		2,121		—		—
Interest and executory costs associated with capital lease obligations(1)		635		365		270		—		—
Non-cancelable operating leases		41,541		15,827		21,429		3,661		624
Liabilities for uncertain tax positions		2,245		942		1,303		—		—
Equity based compensation liability awards(2)		1,283		666		617		—		—
Total	$	622,747	$	59,182	$	559,280	$	3,661	$	624

(1)	Based on interest rates in effect at December 31, 2010.
(2)	Based on our closing stock price at December 31, 2010.

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Debt Compliance

Our Senior Secured Credit Facility and Senior Notes contain numerous covenants that govern our ability to make domestic and international investments and to repurchase our stock. Even if we experience a more severe downturn in our business, we believe that the covenants related to our capital spending and our investments in our foreign subsidiaries are within our control. Therefore, we believe we can avoid a default of these covenants.

At December 31, 2010, we were in compliance with all the financial covenants under the Senior Secured Credit Facility, and our Senior Notes. Based on management’s current projections, we expect to be in compliance with all the covenants under our Senior Secured Credit Facility and Senior Notes for the next twelve months. A breach of any of these covenants, ratios or tests could result in a default under our indebtedness. See “Item 1A. Risk Factors.”

Capital Expenditures

During the year ended December 31, 2010, our capital expenditures totaled $180.3 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 expected to total approximately $240.0 million during 2011, focusing on growth markets in the United States and abroad. Our capital expenditure program for 2011 is subject to market conditions, including activity levels, commodity prices and industry capacity. Our focus for 2011 will be the maximization of our current equipment fleet, but we may choose to increase our capital expenditures in 2011 to increase market share or expand our presence into a new market. We currently anticipate funding our 2011 capital expenditures through a combination of cash on hand, operating cash flow, and borrowings under our Senior Secured Credit Facility. Should our operating cash flows or activity levels prove to be insufficient to warrant our currently planned capital spending levels, management expects it will adjust our capital spending plans accordingly. We may also incur capital expenditures for strategic investments and acquisitions.

Acquisitions

OFS

During 2010, we acquired certain subsidiaries, together with associated assets, from OFS, a privately-held oilfield services company owned by ArcLight Capital Partners, LLC. These subsidiaries are oilfield services companies which provide well workover and stimulation services as well as nitrogen pumping, coiled tubing, fluid handling and wellsite construction and preparation services.

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

Other

In January 2011, we acquired 10 SWD wells from Equity Energy Company for approximately $14.3 million. Most of these SWD wells are located in North Dakota.

We anticipate that acquisitions of complementary companies, assets and lines of businesses will continue to play an important role in our business strategy. While there are currently no unannounced agreements or ongoing negotiations for the acquisition of any material businesses or assets, such transactions can be effected quickly and may occur at any time.

Critical Accounting Policies

Our Accounting Department is responsible for the development and application of our accounting policies and internal control procedures and reports to the Chief Financial Officer.

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The process and preparation of our financial statements in conformity with generally accepted accounting principles in the United States (“GAAP”) requires us to make certain estimates, judgments and assumptions, which may affect the reported amounts of our assets and liabilities, disclosures of contingencies at the balance sheet date, the amounts of revenues and expenses recognized during the reporting period and the presentation of our statement of cash flows. We may record materially different amounts if these estimates, judgments and assumptions change or if actual results differ. However, we analyze our estimates, assumptions and judgments based on our historical experience and various other factors that we believe to be reasonable under the circumstances.

We have identified the following critical accounting policies that require a significant amount of estimation and judgment to accurately present our financial position, results of operations and cash flows:

•  Revenue recognition;

•  Estimate of reserves for workers’ compensation, vehicular liability and other self-insurance;

•  Contingencies;

•  Income taxes;

•  Estimates of depreciable lives;

•  Valuation of indefinite-lived intangible assets;

•  Valuation of tangible and finite-lived intangible assets; and

•  Valuation of equity-based compensation.

Revenue Recognition

We recognize revenue when all of the following criteria have been met: (i) evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price to the customer is fixed and determinable and (iv) collectibility is reasonably assured.

•  Evidence of an arrangement exists when a final understanding between us and our customer has occurred, and can be evidenced by a completed customer purchase order, field ticket, supplier contract, or master service agreement.

•  Delivery has occurred or services have been rendered when we have completed requirements pursuant to the terms of the arrangement as evidenced by a field ticket or service log.

•  The price to the customer is fixed and determinable when the amount that is required to be paid is agreed upon. Evidence of the price being fixed and determinable is evidenced by contractual terms, our price book, a completed customer purchase order, or a completed customer field ticket.

•  Collectibility is reasonably assured when we screen our customers and provide goods and services to customers according to determined credit terms that have been granted in accordance with our credit policy.

We present our revenues net of any sales taxes collected by us from our customers that are required to be remitted to local or state governmental taxing authorities.

We review our contracts for multiple element revenue arrangements. Deliverables will be separated into units of accounting and assigned fair value if they have standalone value to our customer, have objective and reliable evidence of fair value, and delivery of undelivered items is substantially controlled by us. We believe that the negotiated prices for deliverables in our services contracts are representative of fair value since the acceptance or non-acceptance of each element in the contract does not affect the other elements.

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Workers’ Compensation, Vehicular Liability and Other Self-Insurance

Our operations expose our employees to hazards generally associated with the oilfield. Heavy lifting, moving equipment and slippery surfaces can cause or contribute to accidents involving our employees and third parties who may be present at a site. Environmental conditions in remote domestic oil and natural gas basins range from extreme cold to extreme heat, from heavy rain to blowing dust. Those conditions can also lead to or contribute to accidents. Our business activities involve the use of a significant number of fluid transport trucks, other oilfield vehicles and supporting rolling stock that move on public and private roads. Vehicle accidents are a significant risk for us. We also conduct limited contract drilling operations, which present additional hazards inherent in the drilling of wells, such as blowouts, explosions and fires, which could result in loss of hole, damaged equipment and personal injury. All of these hazards and accidents could result in damage to our property or a third party’s property or injury or death to our employees or third parties. Although we purchase insurance to protect against large losses, much of the risk is retained in the form of large deductibles or self-insured retentions.

As a contractor, we also enter into master service agreements with our customers. These agreements subject us to potential contractual liabilities common in the oilfield.

The occurrence of an event not fully insured or indemnified against, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, there can be no assurance that insurance will be available to cover any or all of these risks, or that, if available, it could be obtained without a substantial increase in premiums. It is possible that, in addition to higher premiums, future insurance coverage may be subject to higher deductibles and coverage restrictions.

Based on the risks discussed above, we estimate our liability arising out of potentially insured events, including workers’ compensation, employer’s liability, vehicular liability, and general liability, and record accruals in our consolidated financial statements. Reserves related to claims covered by insurance are based on the specific facts and circumstances of the insured event and our past experience with similar claims. Loss estimates for individual claims are adjusted based upon actual claim judgments, settlements and reported claims. The actual outcome of these claims could differ significantly from estimated amounts.

We are largely self-insured against physical damage to our equipment and automobiles as well as workers’ compensation claims. Our accruals that we maintain on our consolidated balance sheet relate to these deductibles and self-insured retentions, which we estimate through the use of historical claims data and trend analysis. The actual outcome of any claim could differ significantly from estimated amounts. We adjust loss estimates in the calculation of these accruals, based upon actual claim settlements and reported claims. Changes in our assumptions and estimates could potentially have a negative impact on our earnings.

Contingencies

We are periodically required to record other loss contingencies, which relate to lawsuits, claims, proceedings and tax-related audits in the normal course of our operations, on our consolidated balance sheet. We record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We periodically review our loss contingencies to ensure that we have recorded appropriate liabilities on the balance sheet. We adjust these liabilities based on estimates and judgments made by management with respect to the likely outcome of these matters, including the effect of any applicable insurance coverage for litigation matters. Our estimates and judgments could change based on new information, changes in laws or regulations, changes in management’s plans or intentions, the outcome of legal proceedings, settlements or other factors. Actual results could vary materially from these reserves.

We record liabilities when environmental assessment indicates that site remediation efforts are probable and the costs can be reasonably estimated. We measure environmental liabilities based, in part, on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability or the low amount in a range of estimates. These assumptions involve the

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judgments and estimates of management, and any changes in assumptions or new information could lead to increases or decreases in our ultimate liability, with any such changes recognized immediately in earnings.

We record legal obligations to retire tangible, long-lived assets on our balance sheet as liabilities, which are recorded at a discount when we incur the liability. Significant judgment is involved in estimating our future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. If our estimates on the amount or timing of the cash flows change, the change may have a material impact on our results of operations.

Income Taxes

We account for deferred income taxes using the asset and liability method and provide income taxes for all significant temporary differences. Management determines our current tax liability as well as taxes incurred as a result of current operations, yet deferred until future periods. Current taxes payable represent our liability related to our income tax return for the current year, while net deferred tax expense or benefit represents the change in the balance of deferred tax assets and liabilities reported on our consolidated balance sheets. Management estimates the changes in both deferred tax assets and liabilities using the basis of assets and liabilities for financial reporting purposes and for enacted rates that management estimates will be in effect when the differences reverse. Further, management makes certain assumptions about the timing of temporary tax differences for the differing treatment of certain items for tax and accounting purposes or whether such differences are permanent. The final determination of our tax liability involves the interpretation of local tax laws, tax treaties, and related authorities in each jurisdiction as well as the significant use of estimates and assumptions regarding the scope of future operations and results achieved and the timing and nature of income earned and expenditures incurred.

We establish valuation allowances to reduce deferred tax assets if we determine that it is more likely than not (e.g., a likelihood of more than 50%) that some or all of the deferred tax assets will not be realized in future periods. To assess the likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which this taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted results, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. Additionally, we record uncertain tax positions at their net recognizable amount, based on the amount that management deems is more likely than not to be sustained upon ultimate settlement with the tax authorities in the domestic and international tax jurisdictions in which we operate.

If our estimates or assumptions regarding our current and deferred tax items are inaccurate or are modified, these changes could have potentially material negative impacts on our earnings. See “Note 14. Income Taxes” in “Item 8. Financial Statements and Supplementary Data,” for further discussion of accounting for our income taxes, changes in our valuation allowance, components of our tax rate reconciliation and realization of loss carryforwards.

Estimates of Depreciable Lives

We use the estimated depreciable lives of our long-lived assets, such as rigs, heavy-duty trucks and trailers, to compute depreciation expense, to estimate future asset retirement obligations and to conduct impairment tests. We base the estimates of our depreciable lives on a number of factors, such as the environment in which the assets operate, industry factors including forecasted prices and competition, and the assumption that we provide the appropriate amount of capital expenditures while the asset is in operation to maintain economical operation of the asset and prevent untimely demise to scrap. The useful lives of our intangible assets are determined by the years over which we expect the assets to generate a benefit based on legal, contractual or other expectations.

We depreciate our operational assets over their depreciable lives to their salvage value, which is 10% of the acquisition cost. We recognize a gain or loss upon ultimate disposal of the asset based on the difference

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between the carrying value of the asset on the disposal date and any proceeds we receive in connection with the disposal.

We periodically analyze our estimates of the depreciable lives of our fixed assets to determine if the depreciable periods and salvage value continue to be appropriate. We also analyze useful lives and salvage value when events or conditions occur that could shorten the remaining depreciable life of the asset. We review the depreciable periods and salvage values for reasonableness, given current conditions. As a result, our depreciation expense is based upon estimates of depreciable lives of the fixed assets, the salvage value and economic factors, all of which require management to make significant judgments and estimates. If we determine that the depreciable lives should be different than originally estimated, depreciation expense may increase or decrease and impairments in the carrying values of our fixed assets may result, which could negatively impact our earnings.

Valuation of Indefinite-Lived Intangible Assets

We periodically review our intangible assets not subject to amortization, including our goodwill, to determine whether an impairment of those assets may exist. These tests must be made on at least an annual basis, or more often if circumstances indicate that the assets may be impaired. These circumstances include, but are not limited to, significant adverse changes in the business climate.

The test for impairment of indefinite-lived intangible assets is a two step test. In the first step, a fair value is calculated for each of our reporting units, and that fair value is compared to the current carrying value of the reporting unit, including the reporting unit’s goodwill. If the fair value of the reporting unit exceeds its carrying value, there is no potential impairment, and the second step is not performed. If the carrying value exceeds the fair value of the reporting unit, then the second step is required.

The second step of the test for impairment compares the implied fair value of the reporting unit’s goodwill to its current carrying value. The implied fair value of the reporting unit’s goodwill is determined in the same manner as the amount of goodwill that would be recognized in a business combination, with the purchase price being equal to the fair value of the reporting unit. If the implied fair value of the reporting unit’s goodwill is in excess of its carrying value, no impairment charge is recorded. If the carrying value of the reporting unit’s goodwill is in excess of its implied fair value, an impairment charge equal to the excess is recorded.

We conduct our annual impairment test for goodwill and other intangible assets not subject to amortization as of December 31 of each year. In determining the fair value of our reporting units, we use 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 assign a weight to the results of each of these methods based on the facts and circumstances that are in existence for that testing period. We assigned more weight to the discounted cash flow method.

In addition to the estimates made by management regarding the weighting of the various valuation techniques, the creation of the techniques themselves requires that we make significant estimates and assumptions. The discounted cash flow method, which was assigned the highest weight by management during the current year, requires us to make assumptions about future cash flows, future growth rates, tax rates in future periods, book-tax differences in the carrying value of our assets in future periods, and discount rates. The assumptions about future cash flows and growth rates are based on our current budgets for future periods, as well as our strategic plans, the beliefs of management about future activity levels, and analysts’ expectations about our revenues, profitability and cash flows in future periods. The assumptions about our future tax rates and book-tax differences in the carrying value of our assets in future periods are based on the assumptions about our future cash flows and growth rates, and management’s knowledge of and beliefs about tax law and practice in current and future periods. The assumptions about discount rates include an assessment of the specific risk associated with each reporting unit being tested, and were developed with the assistance of a third-party valuation consultant, who reviewed our estimates, assumptions and calculations. The ultimate conclusions of the valuation techniques remain our responsibility.

While this test is required on an annual basis, it can also be required more frequently based on changes in external factors or other triggering events, such as an impairment test of our long-lived assets. We

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conducted our most recent annual test for impairment of our goodwill and other indefinite-lived intangible assets as of December 31, 2010. On that date, our reporting units for the purposes of impairment testing were rig services, fluid management services, coiled tubing services, fishing and rental services and our Russian and Canadian reporting units. We have $301.7 million of goodwill in our rig services reporting unit, $21.1 million of goodwill in our fluid management services reporting unit, $91.3 million in our coiled tubing services reporting unit, $24.6 million of goodwill in our Russian reporting unit, $4.2 million of goodwill related to our Canadian reporting unit and $4.7 million of goodwill in our fishing and rental services reporting unit. We also have intangible assets that are not amortized of $8.7 million related to our Russian reporting unit.

Based on the results of our annual test, the fair value of all our reporting units substantially exceeded their carrying values. Because the fair value of the reporting units substantially exceeded their carrying values, we determined that no potential for impairment of our goodwill associated with those reporting units existed as of December 31, 2010, and that step two of the impairment test was not required.

In the fourth quarter of 2010, we changed the date of our annual goodwill impairment assessment for our Russian reporting unit from September 30 to December 31. This constitutes a change in the method of applying an accounting principle that we believe is preferable. The change was made to align the testing of our Russian reporting unit with the testing date of the remaining reporting units. This change is preferable as it also aligns the timing of our annual Russian goodwill impairment test with our planning and budgeting process, which will allow us to utilize updated forecasts in our discounted cash flow models which are used in the determination of the fair value of the reporting units. We performed our annual goodwill impairment test for our Russian reporting unit on September 30, 2010 and no indicators of impairment were noted. We retested the Russian reporting unit on December 31, 2010 and concluded that the fair value of the Russian reporting unit substantially exceeded its carrying value. A key assumption in our model is that revenue related to this reporting unit will increase in future years based on growth and pricing increases. 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. Other possible events that could affect this assumption are the ability to acquire additional assets and deployment of these assets into the region. As this test concluded that the fair value of the Russian reporting unit exceeded its carrying value, the second step of the goodwill impairment test was not required.

As noted above, the determination of the fair value of our reporting units is heavily dependent upon certain estimates and assumptions that we make about our reporting units. While the estimates and assumptions that we made regarding our reporting units for our 2010 annual test indicated that the fair values of the reporting units exceeded their carrying values and we believe that our estimates and assumptions are reasonable, it is possible that changes in those estimates and assumptions could impact the determination of the fair value of our reporting units. Discount rates we use in future periods could change substantially if the cost of debt or equity were to significantly increase or decrease, or if we chose different comparable companies in determining the appropriate discount rate for our reporting units. Additionally, our future projected cash flows for our reporting units could significantly impact the fair value of our reporting units, and if our current projections about our future activity levels, pricing, and cost structure are inaccurate, the fair value of our reporting units could change materially. If the current recovery in the overall economy is temporary in nature or if there is a significant and rapid adverse change in our business in the near- or mid-term for any of our reporting units, our current estimates of the fair value of our reporting units could decrease significantly, leading to possible impairment charges in future periods. Based on our current knowledge and beliefs, we do not feel that material adverse changes to our current estimates and assumptions such that our reporting units would fail step one of the impairment test are reasonably possible.

Valuation of Tangible and Finite-Lived Intangible Assets

Our fixed assets and finite-lived intangibles are tested for potential impairment when circumstances or events indicate a possible impairment may exist. These circumstances or events are referred to as “trigger events” and examples of such trigger events include, but are not limited to, an adverse change in market

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conditions, a significant decrease in benefits being derived from an acquired business, or a significant disposal of a particular asset or asset class.

If a trigger event occurs, an impairment test is performed based on an undiscounted cash flow analysis. To perform an impairment test, we make judgments, estimates and assumptions regarding long-term forecasts or revenues and expenses relating to the assets subject to review. Market conditions, energy prices, estimated depreciable lives of the assets, discount rate assumptions and legal factors impact our operations and have a significant effect on the estimates we use to determine whether our assets are impaired. If the results of the analysis indicate that the carrying value of the assets being tested for impairment are not recoverable, then we record an impairment charge to write the carrying value of the assets down to their fair value. Using different judgments, assumptions or estimates, we could potentially arrive at a materially different fair value for the assets being tested for impairment, which may result in an impairment charge. We did not identify any trigger events causing us to test our tangible and finite-lived intangible assets for impairment during 2010.

Valuation of Equity-Based Compensation

We have granted stock options, stock-settled stock appreciation rights (“SARs”), restricted stock (“RSAs”), phantom shares and performance units to our employees and non-employee directors. The option and SAR awards we grant are fair valued using a Black-Scholes option model on the grant date and are amortized to compensation expense over the vesting period of the option award, net of estimated and actual forfeitures. Compensation related to RSAs is based on the fair value of the award on the grant date and is recognized based on the vesting requirements that have been satisfied during the period. Phantom shares are accounted for at fair value, and changes in the fair value of these awards are recorded as compensation expense during the period. 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. 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. See “Note 20. Share-Based Compensation” in “Item 8. Financial Statements and Supplementary Data” for further discussion of the various award types and our accounting for our equity-based compensation.

In utilizing the Black-Scholes option pricing model to determine fair values of awards, certain assumptions are made which are based on subjective expectations, and are subject to change. A change in one or more of these assumptions would impact the expense associated with future grants. These key assumptions include the volatility in the price of our common stock, the risk-free interest rate and the expected life of awards.

We did not grant any stock options during the year ended December 31, 2010. We used the following weighted average assumptions in the Black-Scholes option pricing model for determining the fair value of our stock option grants during the years ended December 31, 2009 and 2008:

	Year Ended December 31,
	2010		2009			2008
Risk-free interest rate		n/a		2.21	%		2.86	%
Expected life of options, years		n/a		6			6
Expected volatility of the Company’s stock price		n/a		53.70	%		36.86	%
Expected dividends		n/a		none			none

We calculate the expected volatility for our stock option grants by measuring the volatility of our historical stock price for a period equal to the expected life of the option and ending at the time the option was granted. We determine the risk-free interest rate based upon the interest rate on a U.S. Treasury Bill with a term equal to the expected life of the option at the time the option was granted. In estimating the expected lives of our stock options and SARs, we have elected to use the simplified method. During the time that we did not have current financial statements filed with the SEC, our options were legally restricted from being exercised; therefore we believe that we do not have access to sufficient historical exercise data to appropriately

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provide a reasonable basis upon which to estimate the expected term of stock option awards. The expected life is less than the term of the option as option holders, in our experience, exercise or forfeit the options during the term of the option.

We are not required to recalculate the fair value of our stock option grants estimated using the Black-Scholes option pricing model after the initial calculation unless the original option grant terms are modified.

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 (i) the obligation to absorb losses of the entity or (ii) the right to receive benefits from the entity. An approach that is expected to be primarily qualitative will be more effective for identifying which reporting entity has a controlling financial interest in a variable interest entity. ASU 2009-17 also requires additional disclosures about a reporting entity’s involvement in variable interest entities. The provisions of ASU 2009-17 are to be applied beginning in the first fiscal period beginning after November 15, 2009. 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. The provisions of ASU 2010-02 are effective for the first reporting period beginning after December 13, 2009. 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) and separate presentation of information about purchases, sales, issuances and settlements of fair value measurements with significant unobservable inputs.

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ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009. We adopted the provisions of ASU 2010-06 on January 1, 2010 and the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

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

Accounting Standards Not Yet Adopted in this Report

ASU 2009-13.  In October 2009, the FASB issued ASU 2009-13, Revenue Recognition (Topic 605) — Multiple-Deliverable Revenue Arrangements, a consensus of the FASB Emerging Issues Task Force (“ASU 2009-13”). ASU 2009-13 addresses the accounting for multiple-deliverable arrangements where products or services are accounted for separately rather than as a combined unit, and addresses how to separate deliverables and how to measure and allocate arrangement consideration to one or more units of accounting. Existing GAAP requires an entity to use Vendor-Specific Objective Evidence (“VSOE”) or third-party evidence of a selling price 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 selling price hierarchy for determining the selling price of a deliverable. The selling price will be based on 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 adopted 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.

ASU 2009-14.  In October 2009, the FASB issued ASU 2009-14, Software (Topic 985) — Certain Revenue Arrangements That Include Software Elements — a consensus of the FASB Emerging Issues Task Force (“ASU 2009-14”). ASU 2009-14 was issued to address concerns relating to the accounting for revenue arrangements that contain tangible products and software that is “more than incidental” to the product as a whole. Existing guidance in such circumstances requires entities to use VSOE of a selling price to separate deliverables in a multiple-deliverable arrangement. Reporting entities raised concerns that the current accounting model does not appropriately reflect the economics of the underlying transactions and that more software-enabled products now fall or will fall within the scope of the current guidance than originally intended. ASU 2009-14 changes the current accounting model for revenue arrangements that include both tangible products and software elements to exclude those where the software components are essential to the tangible products’

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core functionality. In addition, ASU 2009-14 also requires that hardware components of a tangible product containing software components always be excluded from the software revenue recognition guidance, and provides guidance on how to determine which software, if any, relating to tangible products is considered essential to the tangible products’ functionality and should be excluded from the scope of software revenue recognition guidance. ASU 2009-14 also provides guidance on how to allocate arrangement consideration to deliverables in an arrangement that contains tangible products and software that is not essential to the product’s functionality. ASU 2009-14 was issued concurrently with ASU 2009-13 and also requires entities to provide the disclosures required by ASU 2009-13 that are included within the scope of ASU 2009-14. ASU 2009-14 will be effective prospectively for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010, and early adoption is permitted. Entities may also elect, but are not required, to adopt ASU 2009-14 retrospectively to prior periods, and must adopt ASU 2009-14 in the same period and using the same transition methods that it uses to adopt ASU 2009-13. We adopted the provisions of ASU 2009-14 on January 1, 2011 and do not believe that the adoption of this standard will have a material impact on our financial position, results of operations, or cash flows.

ASU 2010-13.  In April 2010, the FASB issued ASU No. 2010-13, Compensation — Stock Compensation (Topic 718): Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades. This ASU codifies the consensus reached in EITF Issue No. 09-J, “Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades.” The amendments to the Codification clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity shares trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. ASU 2010-13 will be effective for fiscal years beginning on or after December 15, 2010, and early adoption is permitted. The amendments in this update should be applied by recording a cumulative-effect adjustment to the opening balance of retained earnings. The cumulative-effect adjustment should be calculated for all awards outstanding as of the beginning of the fiscal year in which the amendments are initially applied, as if the amendments had been applied consistently since the inception of the award. The cumulative-effect adjustment should be presented separately. We adopted the provisions of ASU 2010-13 on January 1, 2011 and do not believe that the adoption of this standard will have a material impact on our financial position, results of operations, or cash flows.

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

ASU 2010-29.  In December 2010, the FASB issued ASU 2010-29, Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations. This ASU reflects the decision reached in EITF Issue No. 10-G. The amendments in this ASU affect any public entity as defined by Topic 805, Business Combinations, that enters into business combinations that are material on an individual or aggregate basis. The amendments in this ASU specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior

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annual reporting period only. The amendments also expand the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. ASU 2010-29 is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. Early adoption is permitted. We adopted the provisions of ASU 2010-29 on January 1, 2011 and the adoption of this standard may result in additional disclosures, but it will not have a material impact on our financial position, results of operations, or cash flows.

ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to certain market risks as part of our ongoing business operations, including risks from changes in interest rates, foreign currency exchange rates and equity prices that could impact our financial position, results of operations and cash flows. We manage our exposure to these risks through regular operating and financing activities, and may, on a limited basis, use derivative financial instruments to manage this risk. To the extent that we use such derivative financial instruments, we will use them only as risk management tools and not for speculative investment purposes.

Interest Rate Risk

As of December 31, 2010, we had outstanding $425.0 million of 8.375% Senior Notes due 2014. These notes are fixed-rate obligations, and as such do not subject us to risks associated with changes in interest rates. Borrowings under our Senior Secured Credit Facility and our capital lease obligations bear interest at variable interest rates, and therefore expose us to interest rate risk. As of December 31, 2010, the weighted average interest rate on our outstanding variable-rate debt obligations was 1.78%. A hypothetical 10% increase in that rate would increase the annual interest expense on those instruments by less than $0.1 million.

Foreign Currency Risk

As of December 31, 2010, we conduct operations in Mexico, Colombia, the Middle East, Russia and Argentina. We also have a Canadian subsidiary and have equity-method investments in Canadian companies. The functional currency is the local currency for all of these entities, except Colombia and the Middle East, and as such we are exposed to the risk of changes in the exchange rates between the U.S. Dollar and the local currencies. For balances denominated in our foreign subsidiaries’ local currency, changes in the value of the subsidiaries’ assets and liabilities due to changes in exchange rates are deferred and accumulated in other comprehensive income until we liquidate our investment. For balances denominated in currencies other than the local currency, our foreign subsidiaries must remeasure the balance at the end of each period to an equivalent amount of local currency, with changes reflected in earnings during the period. A hypothetical 10% decrease in the average value of the U.S. Dollar relative to the value of the local currencies for our Argentinean, Mexican, Russian and Canadian subsidiaries and our Canadian investments would decrease our net income by approximately $3.8 million.

Equity Risk

Certain of our equity-based compensation awards’ fair values are determined based upon the price of our common stock on the measurement date. Any increase in the price of our common stock would lead to a corresponding increase in the fair value of those awards. A 10% increase in the price of our common stock from its value at December 31, 2010 would increase annual compensation expense recognized on these awards by approximately $0.1 million.

50

ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Key Energy Services, Inc. and Subsidiaries

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm		52
Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting		53
Consolidated Balance Sheets		54
Consolidated Statements of Operations		55
Consolidated Statements of Comprehensive Income		56
Consolidated Statements of Cash Flows		57
Consolidated Statements of Stockholders’ Equity		58
Notes to Consolidated Financial Statements		59

51

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders of

Key Energy Services, Inc.

We have audited the accompanying consolidated balance sheets of Key Energy Services, Inc. (a Maryland corporation) and Subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Key Energy Services, Inc. and Subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Key Energy Services, Inc. and Subsidiaries’ internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 25, 2011 expressed an unqualified opinion on the effectiveness of internal control over financial reporting.

/s/  GRANT THORNTON LLP

Houston, Texas

February 25, 2011

52

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders of

Key Energy Services, Inc.

We have audited Key Energy Services, Inc. (a Maryland corporation) and Subsidiaries’ internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Key Energy Services, Inc. and Subsidiaries’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express an opinion on Key Energy Services, Inc. and Subsidiaries’ internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Key Energy Services, Inc. and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets, statements of operations, comprehensive income, stockholders’ equity, and cash flows of Key Energy Services, Inc. and Subsidiaries and our report dated February 25, 2011 expressed an unqualified opinion on those consolidated financial statements.

/s/  GRANT THORNTON LLP

Houston, Texas

February 25, 2011

53

Key Energy Services, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

	December 31,
	2010			2009
	(In thousands, except
	share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	56,628		$	37,394
Accounts receivable, net of allowance for doubtful accounts of $7,791 and $5,441		261,818			214,662
Inventories		23,516			23,478
Prepaid expenses		20,478			14,212
Deferred tax assets		32,046			25,323
Income taxes receivable		847			50,025
Other current assets		18,687			15,064
Assets held for sale		—			3,974
Total current assets		414,020			384,132
Property and equipment, gross		1,832,443			1,647,718
Accumulated depreciation		(895,699	)		(853,449	)
Property and equipment, net		936,744			794,269
Goodwill		447,609			346,102
Other intangible assets, net		58,151			41,048
Deferred financing costs, net		7,806			10,421
Equity-method investments		5,940			5,203
Other assets		22,666			12,896
Noncurrent assets held for sale		—			70,339
TOTAL ASSETS	$	1,892,936		$	1,664,410
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	56,310		$	46,086
Accrued liabilities		217,249			130,517
Accrued interest		4,097			3,014
Current portion of capital lease obligations		3,979			7,203
Current portion of notes payable — related parties, net of discount		—			1,931
Current portion of long-term debt		—			1,018
Total current liabilities		281,635			189,769
Capital lease obligations, less current portion		2,121			7,110
Notes payable — related parties, less current portion		—			4,000
Long-term debt, less current portion		425,000			512,839
Workers’ compensation, vehicular and health insurance liabilities		30,110			40,855
Deferred tax liabilities		144,309			146,980
Other non-current accrued liabilities		27,958			19,717
Commitments and contingencies
Equity:
Common stock, $0.10 par value; 200,000,000 shares authorized, 141,656,426 and 123,993,480 shares issued and outstanding		14,166			12,399
Additional paid-in capital		775,601			608,223
Accumulated other comprehensive loss		(51,334	)		(50,763	)
Retained earnings		210,653			137,158
Total equity attributable to common stockholders		949,086			707,017
Noncontrolling interest		32,717			36,123
Total equity		981,803			743,140
TOTAL LIABILITIES AND EQUITY	$	1,892,936		$	1,664,410

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

54

Key Energy Services, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2010			2009			2008
	(In thousands, except per share amounts)
REVENUES	$	1,153,684		$	955,699		$	1,624,446
COSTS AND EXPENSES:
Direct operating expenses		835,012			675,942			1,005,850
Depreciation and amortization expense		137,047			149,233			149,607
General and administrative expenses		198,271			172,140			246,345
Asset retirements and impairments		—			97,035			26,101
Interest expense, net of amounts capitalized		41,959			39,405			42,622
Other, net		(2,697	)		(834	)		2,552
Total costs and expenses, net		1,209,592			1,132,921			1,473,077
(Loss) income from continuing operations before income taxes and noncontrolling interest		(55,908	)		(177,222	)		151,369
Income tax benefit (expense)		20,512			65,974			(81,900	)
(Loss) income from continuing operations before noncontrolling interest		(35,396	)		(111,248	)		69,469
Income (loss) from discontinued operations, net of tax (expense) benefit of ($73,790), $25,151 and ($8,343), respectively		105,745			(45,428	)		14,344
Net income (loss)		70,349			(156,676	)		83,813
Loss attributable to noncontrolling interest		(3,146	)		(555	)		(245	)
INCOME (LOSS) ATTRIBUTABLE TO KEY	$	73,495		$	(156,121	)	$	84,058
(Loss) earnings per share from continuing operations attributable to Key:
Basic	$	(0.25	)	$	(0.91	)	$	0.56
Diluted	$	(0.25	)	$	(0.91	)	$	0.56
Earnings (loss) per share from discontinued operations attributable to Key:
Basic	$	0.82		$	(0.38	)	$	0.12
Diluted	$	0.82		$	(0.38	)	$	0.11
Earnings (loss) per share attributable to Key:
Basic	$	0.57		$	(1.29	)	$	0.68
Diluted	$	0.57		$	(1.29	)	$	0.67
(Loss) income from continuing operations		(35,396	)		(111,248	)		69,469
Loss attributable to noncontrolling interest		(3,146	)		(555	)		(245	)
(Loss) income from continuing operations attributable to Key	$	(32,250	)	$	(110,693	)	$	69,714
Weighted average shares outstanding:
Basic		129,368			121,072			124,246
Diluted		129,368			121,072			125,565

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

55

Key Energy Services, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
	2010			2009			2008
	(In thousands)
(Loss) income from continuing operations	$	(35,396	)	$	(111,248	)	$	69,469
Other comprehensive income (loss), net of tax:
Foreign currency translation loss, net of tax of $(129), $(347), and $(952)		(831	)		(4,243	)		(8,561	)
Deferred gain (loss) from available for sale investments, net of tax of $0, $0 and $0		—			30			(8	)
Total other comprehensive income (loss), net of tax		(831	)		(4,213	)		(8,569	)
Comprehensive income (loss) from continuing operations, net of tax		(36,227	)		(115,461	)		60,900
Comprehensive income (loss) from discontinued operations		105,745			(45,428	)		14,344
Comprehensive income (loss)		69,518			(160,889	)		75,244
Comprehensive loss attributable to noncontrolling interest		(3,406	)		(416	)		(316	)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO KEY	$	72,924		$	(160,473	)	$	75,560

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

56

Key Energy Services, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2010			2009			2008
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	70,349		$	(156,676	)	$	83,813
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense		143,805			169,562			170,774
Asset retirements and impairments		—			159,802			75,137
Bad debt expense		3,849			3,295			37
Accretion of asset retirement obligations		526			533			594
(Income) loss from equity-method investments		(396	)		1,057			(160	)
Amortization of deferred financing costs and discount		2,615			2,182			2,115
Deferred income tax (benefit) expense		(12,370	)		(41,257	)		29,747
Capitalized interest		(3,789	)		(4,335	)		(6,514	)
(Gain) loss on disposal of assets, net		(153,822	)		401			(641	)
Loss on early extinguishment of debt		—			472			—
Loss on sale of available for sale investments, net		—			30			—
Share-based compensation		12,111			6,381			24,233
Excess tax benefits from share-based compensation		(2,069	)		(580	)		(1,733	)
Changes in working capital:
Accounts receivable		(26,448	)		168,824			(34,943	)
Other current assets		36,731			461			(15,622	)
Accounts payable and accrued expenses		61,671			(126,949	)		46,375
Share-based compensation liability awards		1,297			646			(516	)
Other assets and liabilities		(4,255	)		988			(5,532	)
Net cash provided by operating activities		129,805			184,837			367,164
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(180,310	)		(128,422	)		(218,994	)
Proceeds from sale of fixed assets		258,202			5,580			7,961
Investment in Geostream Services Group		—			—			(19,306	)
Acquisitions, net of cash acquired of $539, $28,362, and $2,017, respectively		(86,688	)		12,007			(99,011	)
Dividend from equity-method investments		165			199			—
Proceeds from sale of short-term investments		—			—			276
Net cash used in investing activities		(8,631	)		(110,636	)		(329,074	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt		(6,970	)		(16,552	)		(3,026	)
Repayments of capital lease obligations		(8,493	)		(9,847	)		(11,506	)
Borrowings on revolving credit facility		110,000			—			172,813
Repayments on revolving credit facility		(197,813	)		(100,000	)		(35,000	)
Repurchases of common stock		(3,098	)		(488	)		(139,358	)
Proceeds from exercise of stock options and warrants		4,100			1,306			6,688
Payment of deferred financing costs		—			(2,474	)		(314	)
Excess tax benefits from share-based compensation		2,069			580			1,733
Net cash used in financing activities		(100,205	)		(127,475	)		(7,970	)
Effect of changes in exchange rates on cash		(1,735	)		(2,023	)		4,068
Net increase (decrease) in cash and cash equivalents		19,234			(55,297	)		34,188
Cash and cash equivalents, beginning of period		37,394			92,691			58,503
Cash and cash equivalents, end of period	$	56,628		$	37,394		$	92,691

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

57

Key Energy Services, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

	COMMON STOCKHOLDERS
										Accumulated
	Common Stock						Additional			Other
	Number of			Amount			Paid-in			Comprehensive			Retained			Noncontrolling
	Shares			at par			Capital			Loss			Earnings			Interest			Total
	(In thousands)
BALANCE AT DECEMBER 31, 2007		131,143		$	13,114		$	704,644		$	(37,981	)	$	209,221		$	251		$	889,249
Other comprehensive loss, net of tax		—			—			—			(8,569	)		—			—			(8,569	)
Common stock purchases		(11,183	)		(1,118	)		(135,291	)		—			—			—			(136,409	)
Deconsolidation of AFTI		—			—			—			—			—			(6	)		(6	)
Exercise of stock options		757			76			6,612			—			—			—			6,688
Exercise of warrants		160			16			(16	)		—			—			—			—
Share-based compensation		428			43			24,190			—			—			—			24,233
Tax benefits from share-based compensation		—			—			1,733			—			—			—			1,733
Net income		—			—			—			—			84,058			(245	)		83,813
BALANCE AT DECEMBER 31, 2008		121,305			12,131			601,872			(46,550	)		293,279			—			860,732
Other comprehensive loss, net of tax		—			—			—			(4,213	)		—			(7	)		(4,220	)
Common stock purchases		(72	)		(7	)		(481	)		—			—			—			(488	)
Exercise of stock options		418			42			1,264			—			—			—			1,306
Issuance of warrants		—			—			367			—			—			—			367
Share-based compensation		2,342			233			5,781			—			—			—			6,014
Tax benefits from share-based compensation		—			—			(580	)		—			—			—			(580	)
Net loss		—			—			—			—			(156,121	)		(555	)		(156,676	)
Purchase of Geostream		—			—			—			—			—			36,685			36,685
BALANCE AT DECEMBER 31, 2009		123,993			12,399			608,223			(50,763	)		137,158			36,123			743,140
Other comprehensive loss, net of tax		—			—			—			(571	)		—			(260	)		(831	)
Common stock purchases		(302	)		(30	)		(3,068	)		—			—			—			(3,098	)
Exercise of stock options and warrants		507			50			4,050			—			—			—			4,100
Issuance of shares in acquisition		15,807			1,581			152,382			—			—			—			153,963
Share-based compensation		1,651			166			11,945			—			—			—			12,111
Tax benefits from share-based compensation		—			—			2,069			—			—			—			2,069
Net income		—			—			—			—			73,495			(3,146	)		70,349
BALANCE AT DECEMBER 31, 2010		141,656		$	14,166		$	775,601		$	(51,334	)	$	210,653		$	32,717		$	981,803

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

58

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1.   ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Key Energy Services, Inc., its wholly-owned subsidiaries and its controlled subsidiaries (collectively, “Key,” the “Company,” “we,” “us” and “our”) provide a full range of well services to major oil companies, foreign national oil companies and independent oil and natural gas production companies. Our services include rig-based and coiled tubing-based well maintenance and workover services, well completion and recompletion services, fluid management services, and fishing and rental services and other ancillary oilfield services. Additionally, certain of our rigs are capable of specialty drilling applications. We operate in most major oil and natural gas producing regions of the continental United States, and have operations based in Mexico, Colombia, the Middle East, Russia and Argentina. In addition, we have a technology development group based in Canada and have ownership interests in two oilfield service companies based in Canada.

Basis of Presentation

The consolidated financial statements included in this Annual Report on Form 10-K present our financial position, results of operations and cash flows for the periods presented in accordance with generally accepted accounting principles in the United States (“GAAP”).

The preparation of these 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 also impact the nature and extent of our disclosure, if any, of our contingent liabilities. Among other things, we use estimates to (i) analyze assets for possible impairment, (ii) determine depreciable lives for our assets, (iii) assess future tax exposure and realization of deferred tax assets, (iv) determine amounts to accrue for contingencies, (v) value tangible and intangible assets, (vi) assess workers’ compensation, vehicular liability, self-insured risk accruals and other insurance reserves, (vii) provide allowances for our uncollectible accounts receivable, (viii) value our asset retirement obligations, and (ix) value our equity-based compensation. We review all significant estimates on a recurring basis and record the effect of any necessary adjustments prior to publication of our financial statements. Adjustments made with respect to the use of estimates relate to improved information not previously available. Because of the limitations inherent in this process, our actual results may differ materially from these estimates. We believe that our estimates are reasonable.

Certain reclassifications have been made to prior period amounts to conform to current period financial statement presentation. As a result of the sale of our pressure pumping and wireline businesses in 2010, we now show the results of operations of these businesses as discontinued operations for all periods presented. Prior to the sale, the businesses sold to Patterson-UTI Energy, Inc. (“Patterson-UTI”) were reported as part of our Production Services segment and were based entirely in the U.S. These presentation changes did not impact our consolidated net income, earnings per share, total current assets, total assets or total stockholders’ equity.

We have evaluated events occurring after the balance sheet date included in this Annual Report on Form 10-K for possible disclosure as a subsequent event. Management monitored for subsequent events through the date that these financial statements were issued. Subsequent events that were identified by management that required disclosure are described in “Note 26. Subsequent Events” of these financial statements.

Principles of Consolidation

Within our consolidated financial statements, we include our accounts and the accounts of our majority-owned or controlled subsidiaries. We eliminate intercompany accounts and transactions. When we have an interest in an entity for which we do not have significant control or influence, we account for that interest using the cost method. When we have an interest in an entity and can exert significant influence but not control, we account for that interest using the equity method.

59

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

We apply Accounting Standards Codification (“ASC”) No. 810-10, Consolidation of Variable Interest Entities (revised December 2003) — an Interpretation of ARB No. 51 (“ASC 810-10”) when determining whether or not to consolidate a Variable Interest Entity (“VIE”). ASC 810-10 requires that an equity investor in a VIE have significant equity at risk (generally a minimum of 10%) and hold a controlling interest, evidenced by voting rights, and absorb a majority of the entity’s expected losses, receive a majority of the entity’s expected returns, or both. If the equity investor is unable to evidence these characteristics, the entity that retains these ownership characteristics will be required to consolidate the VIE.

Acquisitions

From time to time, we acquire businesses or assets that are consistent with our long-term growth strategy. Results of operations for acquisitions are included in our financial statements beginning on the date of acquisition and are accounted for using the acquisition method. For all business combinations (whether partial, full or in stages), the acquirer records 100% of all assets and liabilities of the acquired business, including goodwill, at their fair values; including contingent consideration. Final valuations of assets and liabilities are obtained and recorded as soon as practicable and within one year after the date of the acquisition.

Revenue Recognition

We recognize revenue when all of the following criteria have been met: (i) evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price to the customer is fixed and determinable and (iv) collectibility is reasonably assured.

•  Evidence of an arrangement exists when a final understanding between us and our customer has occurred, and can be evidenced by a completed customer purchase order, field ticket, supplier contract, or master service agreement.

•  Delivery has occurred or services have been rendered when we have completed requirements pursuant to the terms of the arrangement as evidenced by a field ticket or service log.

•  The price to the customer is fixed and determinable when the amount that is required to be paid is agreed upon. Evidence of the price being fixed and determinable is evidenced by contractual terms, our price book, a completed customer purchase order, or a completed customer field ticket.

•  Collectibility is reasonably assured when we screen our customers and provide goods and services to customers according to determined credit terms that have been granted in accordance with our credit policy.

We present our revenues net of any sales taxes collected by us from our customers that are required to be remitted to local or state governmental taxing authorities.

We review our contracts for multiple element revenue arrangements. Deliverables will be separated into units of accounting and assigned fair value if they have standalone value to our customer, have objective and reliable evidence of fair value, and delivery of undelivered items is substantially controlled by us. We believe that the negotiated prices for deliverables in our services contracts are representative of fair value since the acceptance or non-acceptance of each element in the contract does not affect the other elements.

Cash and Cash Equivalents

We consider short-term investments with an original maturity of less than three months to be cash equivalents. At December 31, 2010, we have not entered into any compensating balance arrangements, but all of our obligations under our senior credit agreement with a syndicate of banks of which Bank of America Securities LLC and Wells Fargo Bank, N.A. are the administrative agents (the “Senior Secured Credit Facility”) were secured by most of our assets, including assets held by our subsidiaries, which includes our

60

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

cash and cash equivalents. We restrict investment of cash to financial institutions with high credit standing and limit the amount of credit exposure to any one financial institution.

We maintain our cash in bank deposit and brokerage accounts which exceed federally insured limits. As of December 31, 2010, accounts were guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 and substantially all of our accounts held deposits in excess of the FDIC limits.

Cash and cash equivalents held by our Russian and Middle East subsidiaries are subject to a noncontrolling interest and cannot be repatriated; absent these amounts, we believe that the cash held by our foreign subsidiaries could be repatriated for general corporate use without material withholdings. From time to time and in the normal course of business in connection with our operations or ongoing legal matters, we are required to place certain amounts of our cash in deposit accounts with restrictions that limit our ability to withdraw those funds.

Certain of our cash accounts are zero-balance controlled disbursement accounts that do not have right of offset against our other cash balances. We present the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets.

Accounts Receivable and Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable if we determine that there is a possibility that we will not collect all or part of the outstanding balances. We regularly review accounts over 150 days past due from the invoice date for collectibility and establish or adjust our allowance as necessary using the specific identification method. If we exhaust all collection efforts and determine that the balance will never be collected, we write off the accounts receivable and the associated provision for uncollectible accounts.

From time to time we are entitled to proceeds under our insurance policies for amounts that we have reserved in our self insurance liability. We present these insurance receivables gross on our balance sheet as a component of accounts receivable, separate from the corresponding liability.

Concentration of Credit Risk and Significant Customers

Our customers include major oil and natural gas production companies, independent oil and natural gas production companies, and foreign national oil and natural gas production companies. We perform ongoing credit evaluations of our customers and usually do not require material collateral. We maintain reserves for potential credit losses when necessary. Our results of operations and financial position should be considered in light of the fluctuations in demand experienced by oilfield service companies as changes in oil and gas producers’ expenditures and budgets occur. These fluctuations can impact our results of operations and financial position as supply and demand factors directly affect utilization and hours which are the primary determinants of our net cash provided by operating activities.

During the year ended December 31, 2010, no single customer accounted for 10% or more of our consolidated revenues. During the year ended December 31, 2009, revenues from one of the customers of our Well Servicing segment were approximately 11% of our consolidated revenues. No other single customer accounted for more than 10% of our consolidated revenues for the year ended December 31, 2009. No single customer accounted for more than 10% of our consolidated revenues during the year ended December 31, 2008. Receivables outstanding from one of the customers of our Well Servicing segment were approximately 25% of our total accounts receivable as of December 31, 2009. No single customer accounted for more than 10% of our total accounts receivable as of December 31, 2010 and 2008.

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Inventories

Inventories, which consist primarily of equipment parts for use in our well servicing operations and supplies held for consumption, are valued at the lower of average cost or market.

Property and Equipment

Property and equipment are carried at cost less accumulated depreciation. Depreciation is provided for our assets over the estimated depreciable lives of the assets using the straight-line method. Depreciation expense for the years ended December 31, 2010, 2009 and 2008 was $125.8 million, $135.3 million and $132.0 million, respectively. We depreciate our operational assets over their depreciable lives to their salvage value, which is a fair value higher than the assets’ value as scrap. Salvage value approximates 10% of an operational asset’s acquisition cost. When an operational asset is stacked or taken out of service, we review its physical condition, depreciable life and ultimate salvage value to determine if the asset is no longer operable and whether the remaining depreciable life and salvage value should be adjusted. When we scrap an asset, we accelerate the depreciation of the asset down to its salvage value. When we dispose of an asset, gain or loss is recognized.

As of December 31, 2010, the estimated useful lives of our asset classes are as follows:

Description	Years
Well service rigs and components		3-15
Oilfield trucks and related equipment		7-10
Well intervention units and equipment		10-12
Fishing and rental tools		4-10
Disposal wells		15-30
Furniture and equipment		3-7
Buildings and improvements		15-30

We lease certain of our operating assets under capital lease obligations whose terms run from 55 to 60 months. These assets are depreciated over their estimated useful lives or the term of the capital lease obligation, whichever is shorter.

A long-lived asset or asset group should be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. For purposes of testing for impairment, we group our long-lived assets along our lines of business based on the services provided, which is the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. We would record an impairment charge, reducing the net carrying value to an estimated fair value, if the asset group’s estimated future cash flows were less than its net carrying value. Events or changes in circumstance that cause us to evaluate our fixed assets for recoverability and possible impairment may include changes in market conditions, such as adverse movements in the prices of oil and natural gas, or changes of an asset group, such as its expected future life, intended use or physical condition, which could reduce the fair value of certain of our property and equipment. The development of future cash flows and the determination of fair value for an asset group involves significant judgment and estimates. As discussed in “Note 7. Property and Equipment,” during the third quarter of 2009 we identified a triggering event that required us to test our long-lived assets for potential impairment. As a result of those tests, we determined that the equipment for our pressure pumping operations was impaired. We did not identify any triggering events or record any asset impairments during 2010.

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Asset Retirement Obligations

We recognize a liability for the fair value of all legal obligations associated with the retirement of tangible long-lived assets and capitalize an equal amount as a cost of the asset. We depreciate the additional cost over the estimated useful life of the assets. Our obligations to perform our asset retirement activities are unconditional, despite the uncertainties that may exist surrounding an individual retirement activity. Accordingly, we recognize a liability for the fair value of a conditional asset retirement obligation if the fair value can be reasonably estimated. In determining the fair value, we examine the inputs that we believe a market participant would use if we were to transfer the liability. We probability-weight the potential costs a third-party would charge, adjust the cost for inflation for the estimated life of the asset, and discount this cost using our credit adjusted risk free rate. Significant judgment is involved in estimating future cash flows associated with such obligations, as well as the ultimate timing of those cash flows. If our estimates of the amount or timing of the cash flows change, such changes may have a material impact on our results of operations. See “Note 10. Asset Retirement Obligations.”

Capitalized Interest

Interest is capitalized on the average amount of accumulated expenditures for major capital projects under construction using an effective interest rate based on related debt until the underlying assets are placed into service. The capitalized interest is added to the cost of the assets and amortized to depreciation expense over the useful life of the assets, and is included in the depreciation and amortization line in the accompanying consolidated statements of operations.

Deferred Financing Costs

Deferred financing costs associated with long-term debt are carried at cost and are amortized to interest expense using the effective interest method over the life of the related debt instrument. When the related debt instrument is retired, any remaining unamortized costs are included in the determination of the gain or loss on the extinguishment of the debt. We record gains and losses from the extinguishment of debt as a part of continuing operations.

Goodwill and Other Intangible Assets

Goodwill results from business combinations and represents the excess of the acquisition consideration over the fair value of the net assets acquired. Goodwill and other intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired.

The test for impairment of indefinite-lived intangibles is a two step test. In the first step of the test, a fair value is calculated for each of our reporting units, and that fair value is compared to the carrying value of the reporting unit, including the reporting unit’s goodwill. If the fair value of the reporting unit exceeds its carrying value, there is no impairment, and the second step of the test is not performed. If the carrying value exceeds the fair value for the reporting unit, then the second step of the test is required.

The second step of the test compares the implied fair value of the reporting unit’s goodwill to its carrying value. The implied fair value of the reporting unit’s goodwill is determined in the same manner as the amount of goodwill recognized in a business combination, with the purchase price being equal to the fair value of the reporting unit. If the implied fair value of the reporting unit’s goodwill is in excess of its carrying value, no impairment is recorded. If the carrying value is in excess of the implied fair value, an impairment equal to the excess is recorded.

To assist management in the preparation and analysis of the valuation of our reporting units, we utilize the services of a third-party valuation consultant, who reviews our estimates, assumptions and calculations.

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The ultimate conclusions of the valuation techniques remain our sole responsibility. The determination of the fair value used in the test is heavily impacted by the market prices of our equity and debt securities, as well as the assumptions and estimates about our future activity levels, profitability and cash flows. We conduct our annual impairment test on December 31 of each year. For the annual test completed as of December 31, 2010, no impairment of our goodwill was indicated. See “Note 8. Goodwill and Other Intangible Assets,” for further discussion.

In the fourth quarter of 2010, we changed the date of our annual goodwill impairment assessment for our Russian reporting unit from September 30 to December 31. This constitutes a change in the method of applying an accounting principle that we believe is preferable. The change was made to align the testing of our Russian reporting unit with the testing date of our other reporting units. This change is preferable as it also aligns the timing of our annual Russian goodwill impairment test with our planning and budgeting process, which will allow us to utilize updated forecasts in our discounted cash flow models which are used in the determination of the fair value of the reporting units. Also, the November and December months are the contract tendering periods in Russia providing current information on anticipated activity. This change in accounting principle has no effect on our current or prior period financial statements. We performed our annual goodwill impairment test for our Russian reporting unit on September 30, 2010 and no indicators of impairment were noted. We retested the Russian reporting unit on December 31, 2010 and no impairment of our goodwill was indicated.

Internal-Use Software

We capitalize costs incurred during the application development stage of internal-use software and amortize these costs over the software’s estimated useful life, generally five years. Costs incurred related to selection or maintenance of internal-use software are expensed as incurred.

Litigation

When estimating our liabilities related to litigation, we take into account all available facts and circumstances in order to determine whether a loss is probable and reasonably estimable.

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 subject to jury verdicts or other outcomes that may be favorable to plaintiffs. We are also exposed to litigation in foreign locations where we operate. 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 able to be estimated. See “Note 16. Commitments and Contingencies.”

Environmental

Our operations routinely involve the storage, handling, transport and disposal of bulk waste materials, some of which contain oil, contaminants, and regulated substances. These operations are subject to various federal, state and local laws and regulations intended to protect the environment. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. We record liabilities on an undiscounted basis 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. See “Note 16. Commitments and Contingencies.”

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Self Insurance

We are largely self-insured against physical damage to our equipment and automobiles as well as workers’ compensation claims. The accruals that we maintain on our consolidated balance sheet relate to these deductibles and self-insured retentions, which we estimate through the use of historical claims data and trend analysis. To assist management with the liability amount for our self insurance reserves, we utilize the services of a third party actuary. The actual outcome of any claim could differ significantly from estimated amounts. We adjust loss estimates in the calculation of these accruals, based upon actual claim settlements and reported claims. See “Note 16. Commitments and Contingencies.”

Income Taxes

We account for deferred income taxes using the asset and liability method and provide income taxes for all significant temporary differences. Management determines our current tax liability as well as taxes incurred as a result of current operations, but which are deferred until future periods. Current taxes payable represent our liability related to our income tax returns for the current year, while net deferred tax expense or benefit represents the change in the balance of deferred tax assets and liabilities reported on our consolidated balance sheets. Management estimates the changes in both deferred tax assets and liabilities using the basis of assets and liabilities for financial reporting purposes and for enacted rates that management estimates will be in effect when the differences reverse. Further, management makes certain assumptions about the timing of temporary tax differences for the differing treatments of certain items for tax and accounting purposes or whether such differences are permanent. The final determination of our tax liability involves the interpretation of local tax laws, tax treaties, and related authorities in each jurisdiction as well as the significant use of estimates and assumptions regarding the scope of future operations and results achieved and the timing and nature of income earned and expenditures incurred.

We establish valuation allowances to reduce deferred tax assets if we determine that it is more likely than not (e.g., a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized in future periods. To assess the likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which this taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted results, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. Additionally, we record uncertain tax positions at their net recognizable amount, based on the amount that management deems is more likely than not to be sustained upon ultimate settlement with the tax authorities in the domestic and international tax jurisdictions in which we operate.

See “Note 14. Income Taxes” for further discussion of accounting for income taxes, changes in our valuation allowance, components of our tax rate reconciliation and realization of loss carryforwards.

Earnings Per Share

Basic earnings per common share is determined by dividing net earnings applicable to common stock by the weighted average number of common shares actually outstanding during the period. Diluted earnings per common share is based on the increased number of shares that would be outstanding assuming conversion of dilutive outstanding convertible securities using the treasury stock and “as if converted” methods. See “Note 9. Earnings Per Share.”

Share-Based Compensation

In the past, we have issued stock options, shares of restricted common stock, stock appreciation rights (“SARs”), phantom shares and performance units to our employees as part of those employees’ compensation

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and as a retention tool. For our options, restricted shares and SARs, we calculate the fair value of the awards on the grant date and amortize that fair value to compensation expense ratably over the vesting period of the award, net of estimated and actual forfeitures. The fair value of our stock option and SAR awards are estimated using a Black-Scholes fair value model. The valuation of our stock options and SARs requires us to estimate the expected term of award, which we estimate using the simplified method, as we do not currently have sufficient historical exercise information because of past legal restrictions on the exercise of our stock options. Additionally, the valuation of our stock option and SAR awards is also dependent on our historical stock price volatility, which we calculate using a lookback period equivalent to the expected term of the award, a risk-free interest rate, and an estimate of future forfeitures. The grant-date fair value of our restricted stock awards is determined using our stock price on the grant date. Our phantom shares and performance units are treated as “liability” awards and carried at fair value on each balance sheet date, with changes in fair value recorded as a component of compensation expense and an offsetting liability on our consolidated balance sheet. We record share-based compensation as a component of general and administrative expense. See “Note 20. Share-Based Compensation.”

Foreign Currency Gains and Losses

For our international locations in Argentina, Mexico, the Russian Federation and Canada, where the local currency is the functional currency, assets and liabilities are translated at the rates of exchange on the balance sheet date, while income and expense items are translated at average rates of exchange during the period. The resulting gains or losses arising from the translation of accounts from the functional currency to the U.S. Dollar are included as a separate component of stockholders’ equity in other comprehensive income until a partial or complete sale or liquidation of our net investment in the foreign entity.

From time to time our foreign subsidiaries may enter into transactions that are denominated in currencies other than their functional currency. These transactions are initially recorded in the functional currency of that subsidiary based on the applicable exchange rate in effect on the date of the transaction. At the end of each month, these transactions are remeasured to an equivalent amount of the functional currency based on the applicable exchange rates in effect at that time. Any adjustment required to remeasure a transaction to the equivalent amount of the functional currency at the end of the month is recorded in the income or loss of the foreign subsidiary as a component of other income and expense. See “Note 17. Accumulated Other Comprehensive Loss.”

Comprehensive Income

We display comprehensive income and its components in our financial statements, and we classify items of comprehensive income by their nature in our financial statements and display the accumulated balance of other comprehensive income separately in our stockholders’ equity.

Leases

We lease real property and equipment through various leasing arrangements. When we enter into a leasing arrangement, we analyze the terms of the arrangement to determine whether the lease should be accounted for as an operating lease or a capital lease.

We periodically incur costs to improve the assets that we lease under these arrangements. If the value of the leasehold improvements exceeds our threshold for capitalization, we record the improvement as a component of our property and equipment and amortize the improvement over the useful life of the improvement or the lease term, whichever is shorter.

Certain of our operating lease agreements are structured to include scheduled and specified rent increases over the term of the lease agreement. These increases may be the result of an inducement or “rent holiday”

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conveyed to us early in the lease, or are included to reflect the anticipated effects of inflation. We recognize scheduled and specified rent increases on a straight-line basis over the term of the lease agreement. In addition, certain of our operating lease agreements contain incentives to induce us to enter into the lease agreement, such as up-front cash payments to us, payment by the lessor of our costs, such as moving expenses, or the assumption by the lessor of our pre-existing lease agreements with third parties. Any payments made to us or on our behalf represent incentives that we consider to be a reduction of our rent expense, and are recognized on a straight-line basis over the term of the lease agreement.

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 (i) the obligation to absorb losses of the entity or (ii) the right to receive benefits from the entity. An approach that is expected to be primarily qualitative will be more effective for identifying which reporting entity has a controlling financial interest in a variable interest entity. ASU 2009-17 also requires additional disclosures about a reporting entity’s involvement in variable interest entities. The provisions of ASU 2009-17 are to be applied beginning in the first fiscal period beginning after November 15, 2009. 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. The provisions of ASU 2010-02 are effective for the first reporting period beginning after December 13, 2009. 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

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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) and separate presentation of information about purchases, sales, issuances and settlements of fair value measurements with significant unobservable inputs. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009. We adopted the provisions of ASU 2010-06 on January 1, 2010 and the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

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

Accounting Standards Not Yet Adopted in this Report

ASU 2009-13.  In October 2009, the FASB issued ASU 2009-13, Revenue Recognition (Topic 605) — Multiple-Deliverable Revenue Arrangements, a consensus of the FASB Emerging Issues Task Force (“ASU 2009-13”). ASU 2009-13 addresses the accounting for multiple-deliverable arrangements where products or services are accounted for separately rather than as a combined unit, and addresses how to separate deliverables and how to measure and allocate arrangement consideration to one or more units of accounting. Existing GAAP requires an entity to use Vendor-Specific Objective Evidence (“VSOE”) or third-party evidence of a selling price 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 selling price hierarchy for determining the selling price of a deliverable. The selling price will be based on 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 adopted 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.

ASU 2009-14.  In October 2009, the FASB issued ASU 2009-14, Software (Topic 985) — Certain Revenue Arrangements That Include Software Elements — a consensus of the FASB Emerging Issues Task

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Force (“ASU 2009-14”). ASU 2009-14 was issued to address concerns relating to the accounting for revenue arrangements that contain tangible products and software that is “more than incidental” to the product as a whole. Existing guidance in such circumstances requires entities to use VSOE of a selling price to separate deliverables in a multiple-deliverable arrangement. Reporting entities raised concerns that the current accounting model does not appropriately reflect the economics of the underlying transactions and that more software-enabled products now fall or will fall within the scope of the current guidance than originally intended. ASU 2009-14 changes the current accounting model for revenue arrangements that include both tangible products and software elements to exclude those where the software components are essential to the tangible products’ core functionality. In addition, ASU 2009-14 also requires that hardware components of a tangible product containing software components always be excluded from the software revenue recognition guidance, and provides guidance on how to determine which software, if any, relating to tangible products is considered essential to the tangible products’ functionality and should be excluded from the scope of software revenue recognition guidance. ASU 2009-14 also provides guidance on how to allocate arrangement consideration to deliverables in an arrangement that contains tangible products and software that is not essential to the product’s functionality. ASU 2009-14 was issued concurrently with ASU 2009-13 and also requires entities to provide the disclosures required by ASU 2009-13 that are included within the scope of ASU 2009-14. ASU 2009-14 will be effective prospectively for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010, and early adoption is permitted. Entities may also elect, but are not required, to adopt ASU 2009-14 retrospectively to prior periods, and must adopt ASU 2009-14 in the same period and using the same transition methods that it uses to adopt ASU 2009-13. We adopted the provisions of ASU 2009-14 on January 1, 2011 and do not believe that the adoption of this standard will have a material impact on our financial position, results of operations, or cash flows.

ASU 2010-13.  In April 2010, the FASB issued ASU No. 2010-13, Compensation — Stock Compensation (Topic 718): Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades. This ASU codifies the consensus reached in EITF Issue No. 09-J, “Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades.” The amendments to the Codification clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity shares trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. ASU 2010-13 will be effective for fiscal years beginning on or after December 15, 2010, and early adoption is permitted. The amendments in this update should be applied by recording a cumulative-effect adjustment to the opening balance of retained earnings. The cumulative-effect adjustment should be calculated for all awards outstanding as of the beginning of the fiscal year in which the amendments are initially applied, as if the amendments had been applied consistently since the inception of the award. The cumulative-effect adjustment should be presented separately. We adopted the provisions of ASU 2010-13 on January 1, 2011 and do not believe that the adoption of this standard will have a material impact on our financial position, results of operations, or cash flows.

ASU 2010-28.  In December 2010, the FASB issued ASU No. 2010-28, Intangibles — Goodwill and Other (Topic 350): When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts. This ASU reflects the decision reached in EITF Issue No. 10-A. The amendments in this ASU modify Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist. The qualitative factors are consistent with the existing guidance and examples, which require that goodwill of a reporting unit be tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit

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below its carrying amount. For public entities, the amendments in this ASU are effective for fiscal years, and interim periods within those years, beginning after December 15, 2010. Early adoption is not permitted. We adopted the provisions of ASU 2010-28 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.

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

NOTE 2.   ACQUISITIONS

2010 Acquisitions

OFS Energy Services, LLC (“OFS”).  In October 2010, we acquired certain subsidiaries, together with associated assets, owned by OFS, a privately-held oilfield services company of ArcLight Capital Partners, LLC. We accounted for this acquisition as a business combination. The results of operations for the acquired businesses have been included in our consolidated financial statements since the date of acquisition.

The total consideration for the acquisition was 15.8 million shares of our common stock and a cash payment of $75.8 million, subject to certain working capital and other adjustments at closing. We registered the shares of common stock issued in the transaction under the Securities Act of 1933, as amended, subject to certain conditions. OFS’ subsidiaries are oilfield services companies which provide well workover and stimulation services as well as nitrogen pumping, coiled tubing, fluid handling and wellsite construction and preparation services. This transaction complemented our existing rig and fluids management businesses, as well as significantly increased the number of coiled tubing units in our fleet. The OFS subsidiaries were incorporated into both our Well Servicing segment and Production Services segment. The acquisition-date fair value of the consideration transferred totaled $229.7 million which consisted of the following (in thousands):

Cash	$	75,775
Key common stock		153,963
Total	$	229,738

The 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).

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The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the acquisition date. We are in the process of finalizing third-party valuations of the tangible and certain intangible assets; thus, the provisional measurements of tangible assets, intangible assets, goodwill and deferred income tax assets are preliminary and subject to change. Valuations are not complete as we continue to assess the fair values of the assets acquired and liabilities assumed.

	(In thousands)
At October 1, 2010:
Cash and cash equivalents	$	539
Acounts receivable		23,384
Other current assets		1,372
Property and equipment		108,152
Intangible assets		20,988
Deferred tax asset		1,851
Total identifiable assets acquired		156,286
Current liabilities		18,498
Other liabilities		1,134
Total liabilities assumed		19,632
Net identifiable assets acquired		136,654
Goodwill		93,084
Net assets acquired	$	229,738

Of the $21.0 million of acquired intangible assets, $20.0 million was preliminarily assigned to customer relationships that will be amortized as the value of the relationships are realized using rates of 31%, 18.7%, 14.1%, 10.6%, 7.9%, 5.9%, 4.5%, and 3.3% through 2018. The remaining $1.0 million of acquired intangible assets was assigned to non-compete agreements that will be amortized straight-line over 18 months. As noted above, the fair value of the acquired identifiable intangible assets is preliminary pending receipt of the final valuation for these assets.

The fair value of accounts receivable acquired on October 1, 2010 was $23.4 million, with the gross contractual amount being $25.4 million. The Company expects $2.0 million to be uncollectible.

For the goodwill acquired, $91.3 million was assigned to coiled tubing services, and $1.8 million was assigned to fluid management services. We believe the goodwill recognized is attributable primarily to the acquired workforce and expansion of a growing service line. All of the goodwill is expected to be deductible for income tax purposes. The fair value of the acquired goodwill is preliminary pending receipt of the final valuation.

We recognized $2.0 million of acquisition related costs that were expensed during the year ended December 31, 2010. These costs are included in the statements of operations in the line item “General and administrative expenses” for the year ended December 31, 2010. The Company also recognized $0.1 million in costs associated with issuing and registering the shares.

Included in our consolidated statements of operations for the year ended December 31, 2010, related to this acquisition are revenues of approximately $46.4 million and operating income of $14.6 million from the acquisition date to the period ended December 31, 2010.

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The following represents the pro forma consolidated income statement as if the OFS acquisition had been included in the consolidated results of the Company as of January 1 for the years ended December 31, 2010 and 2009:

	Year Ended December 31,
	2010			2009
	(Unaudited)			(Unaudited)
	(In thousands, except per share amounts)
REVENUES	$	1,277,260		$	1,072,929
COSTS AND EXPENSES:
Direct operating expenses		923,644			768,945
Depreciation and amortization expense		147,584			159,770
General and administrative expenses		205,708			181,884
Asset retirements and impairments		—			108,543
Interest expense, net of amounts capitalized		42,579			43,084
Other, net		(2,862	)		(602	)
Total costs and expenses, net		1,316,653			1,261,624
Loss from continuing operations before income taxes and noncontrolling interest		(39,393	)		(188,695	)
Income tax benefit		14,266			69,617
Loss from continuing operations		(25,127	)		(119,078	)
Income (loss) from discontinued operations, net of tax (expense) benefit of ($73,790) and $25,151		105,745			(45,428	)
Net income (loss)		80,618			(164,506	)
Loss attributable to noncontrolling interest		(3,146	)		(555	)
INCOME (LOSS) ATTRIBUTABLE TO KEY	$	83,764		$	(163,951	)
Earnings (loss) per share attributable to Key:
Basic	$	0.59		$	(1.20	)
Diluted	$	0.59		$	(1.20	)
Weighted average shares outstanding:
Basic		141,234			136,879
Diluted		141,234			136,879

These unaudited pro forma results, based on assumptions deemed appropriate by management, have been prepared for informational purposes only and are not necessarily indicative of the company’s results if the acquisition had occurred on January 1, 2010 and 2009, respectively, for the twelve months ended December 31, 2010 and 2009. These amounts have been calculated after applying the Company’s accounting policies and adjusting the results of OFS as if these changes had been applied on January 1, together with the consequential tax effects.

Enhanced Oilfield Technologies, LLC (“EOT”).  In December 2010, we acquired 100% of the equity interests in EOT, a privately-held oilfield technology company. We accounted for this acquisition as a business combination. The acquired business was still in the developmental stage at the time of acquisition; accordingly, there are no results of operations for EOT included in our consolidated financial statements for the year ended December 31, 2010.

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The total consideration for the acquisition was a cash payment of $11.7 million at closing. EOT is an oilfield technology company which develops expandable liner hanger systems. This technology will complement our existing service offerings. The EOT assets were incorporated into our Production Services segment.

The following table summarizes the estimated fair values of the assets acquired at the acquisition date. We are in the process of performing third-party valuations of the intangible assets acquired; thus, the provisional measurements of intangible assets and goodwill are preliminary and subject to change.

	(In thousands)
At December 15, 2010:
Intangible assets	$	7,000
Total identifiable assets acquired		7,000
Total liabilities assumed		—
Net identifiable assets acquired		7,000
Goodwill		4,700
Net assets acquired	$	11,700

The $7.0 million of acquired intangible assets has been preliminarily assigned to patents that we expect to be amortized straight-line over 20 years. As noted above, the fair value of the acquired identifiable intangible asset is preliminary pending receipt of the final valuation for these assets. The valuation of these assets has not been completed as of December 31, 2010 due to the timing of the closing of the transaction.

The goodwill acquired of $4.7 million was assigned to our fishing and rental business. We believe the goodwill recognized is attributable primarily to the entrance in a new technology and service offering. All of the goodwill is expected to be deductible for income tax purposes.

We recognized less than $0.1 million of acquisition related costs that were expensed during the year ended December 31, 2010. These costs are included in the statement of operations in the line item “general and administrative expenses.”

Other Acquisitions.  We have made other asset acquisitions during 2010 as part of our business strategy. In June 2010, we acquired five large diameter capable coiled tubing units and associated equipment for approximately $12.7 million in cash from Express Energy Services, privately-held oilfield service companies. Also, in November 2010, we acquired 13 rigs and associated equipment from Five J.A.B., privately-held oilfield companies, for cash consideration of approximately $14.6 million.

2009 Acquisitions

Geostream Services Group (“Geostream”).  On September 1, 2009, we acquired an additional 24% interest in Geostream for $16.4 million. This was our second investment in Geostream pursuant to an agreement dated August 26, 2008, as amended. This second investment brought our total investment in Geostream to 50%. Prior to the acquisition of the additional interest, we accounted for our ownership in Geostream as an equity-method investment. Upon acquiring the 50% interest, we also obtained majority representation on Geostream’s board of directors and a controlling interest. We accounted for this acquisition as a business combination achieved in stages. The results of Geostream have been included in our consolidated financial statements since the acquisition date, with the portion outside of our control forming a noncontrolling interest.

The acquisition date fair value of the consideration transferred totaled approximately $35.0 million, which consisted of cash consideration in the second investment and the fair value of our previous equity interest. The acquisition date fair value of our previous equity interest was approximately $18.3 million. We recognized a

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

loss of $0.2 million as a result of remeasuring our prior equity interest in Geostream held before the business combination, which is included in the line item “other, net” in the 2009 consolidated statements of operations.

All of the purchase price allocations for 2009 acquisitions were finalized in 2010 without significant changes.

2008 Acquisitions

Leader Energy Services Ltd. (“Leader”).  On July 22, 2008, we purchased all of the United States-based assets of Leader, a Canadian company, for total consideration of $35.4 million, including direct transaction costs. The Leader assets were incorporated into our Production Services segment.

Hydra-Walk, Inc. (“Hydra-Walk”).  On May 30, 2008, we acquired Hydra-Walk, a privately owned company providing automated pipe handling services. The purchase price totaled $10.7 million, including direct transaction costs. The purchase price also provided for a performance earn-out of which we paid $1.1 million total. Hydra-Walk was incorporated into our Production Services segment.

Western Drilling, LLC. (“Western”).  On April 3, 2008, we acquired Western, a privately-owned company based in California that provides workover and drilling services. The purchase price totaled $52.0 million, including direct transaction costs. Western was incorporated into our Well Servicing segment.

All of the purchase price allocations for 2008 acquisitions were finalized in 2009.

NOTE 3.   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 results of operations related to these businesses as discontinued operations for all periods. 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. The sale of these businesses represented the sale of a significant portion of a reporting unit which requires the reassessment of goodwill. However, due to previous impairment charges, there was no goodwill related to this segment remaining in 2010. 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 carrying value of the assets sold was $76.5 million as of September 30, 2010 and $74.3 million as of December 31, 2009. We discontinued depreciation and amortization of our pressure pumping and wireline property and equipment at June 30, 2010 when they were classified as held for sale.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the results of discontinued operations for the businesses sold in connection with this transaction:

	Year Ended December 31,
	2010			2009			2008
	(In thousands)
REVENUES	$	197,704		$	122,966		$	347,642
COSTS AND EXPENSES:
Direct operating expenses		154,369			103,515			244,477
Depreciation and amortization expense		6,758			20,329			21,167
General and administrative expenses		11,734			6,556			11,362
Asset retirements and impairments		—			62,767			49,036
Interest expense, net of amounts capitalized		(262	)		(336	)		(1,375	)
Other, net		(75	)		714			288
Gain on sale of discontinued operations		(154,355	)		—			—
Total costs and expenses, net		18,169			193,545			324,955
Income (loss) before taxes and noncontrolling interest		179,535			(70,579	)		22,687
Income tax (expense) benefit		(73,790	)		25,151			(8,343	)
Net income (loss)		105,745			(45,428	)		14,344

NOTE 4.   OTHER CURRENT AND NON-CURRENT LIABILITIES

The table below presents comparative detailed information about our current accrued liabilities at December 31, 2010 and 2009:

	December 31,		December 31,
	2010		2009
	(In thousands)
Current Accrued Liabilities:
Accrued payroll, taxes and employee benefits	$	35,453	$	33,953
Accrued operating expenditures		39,399		24,194
Income, sales, use and other taxes		93,820		30,447
Self-insurance reserves		30,195		24,366
Insurance premium financing		7,443		7,282
Unsettled legal claims		3,768		2,665
Phantom share liability		1,146		1,518
Other		6,025		6,092
Total	$	217,249	$	130,517

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The table below presents comparative detailed information about our other non-current accrued liabilities at December 31, 2010 and 2009:

	December 31,		December 31,
	2010		2009
	(In thousands)
Non-Current Accrued Liabilities:
Asset retirement obligations	$	11,003	$	10,045
Environmental liabilities		4,011		3,353
Accrued rent		1,998		2,399
Accrued sales, use and other taxes		8,397		2,813
Phantom share liability		1,106		508
Other		1,443		599
Total	$	27,958	$	19,717

NOTE 5.   OTHER INCOME AND EXPENSE

The table below presents comparative detailed information about our other income and expense from continuing operations for the years ended December 31, 2010, 2009 and 2008:

	Year Ended December 31,
	2010			2009			2008
	(In thousands)
Loss on early extinguishment of debt	$	—		$	472		$	—
Loss (gain) on disposal of assets, net		549			(309	)		(929	)
Interest income		(112	)		(499	)		(1,236	)
Foreign exchange (gain) loss, net		(1,541	)		(1,482	)		3,547
Other (income) expense, net		(1,593	)		984			1,170
Total	$	(2,697	)	$	(834	)	$	2,552

NOTE 6.   ALLOWANCE FOR DOUBTFUL ACCOUNTS

The table below presents a rollforward of our allowance for doubtful accounts for the years ended December 31, 2010, 2009 and 2008:

			Additions
	Balance at				Charged to								Balance at
	Beginning		Charged to		Other								End of
	of Period		Expense		Accounts			Acquisitions		Deductions			Period
	(In thousands)
As of December 31, 2010	$	5,441	$	3,849	$	896		$	—	$	(2,395	)	$	7,791
As of December 31, 2009		11,468		3,295		—			—		(9,322	)		5,441
As of December 31, 2008		13,501		37		(38	)		15		(2,047	)		11,468

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NOTE 7.   PROPERTY AND EQUIPMENT

Property and equipment consists of the following:

	December 31,
	2010			2009
	(In thousands)
Major classes of property and equipment:
Well servicing equipment	$	1,418,996		$	1,344,343
Disposal wells		68,834			52,797
Motor vehicles		90,437			51,825
Furniture and equipment		103,923			81,695
Buildings and land		60,157			49,550
Work in progress		90,096			67,508
Gross property and equipment		1,832,443			1,647,718
Accumulated depreciation		(895,699	)		(853,449	)
Net property and equipment	$	936,744		$	794,269

We capitalize costs incurred during the application development stage of internal-use software. These costs are capitalized to work in progress until such time the application is put in service. For the years ended December 31, 2010, 2009 and 2008 we capitalized costs in the amount of $14.7 million, $13.1 million, and $4.5 million, respectively. Capitalized internal-use software during 2010 consisted primarily of our expenditures for new ERP and Human Resources information systems.

Interest is capitalized on the average amount of accumulated expenditures for major capital projects under construction using an effective interest rate based on related debt until the underlying assets are placed into service. Capitalized interest for the years ended December 31, 2010, 2009 and 2008 was $3.5 million, $4.0 million, and $5.1 million, respectively.

We are obligated under various capital leases for certain vehicles and equipment that expire at various dates during the next five years. The carrying value of assets acquired under capital leases consists of the following:

	2010			2009
	(In thousands)
Values of assets leased under capital lease obligations:
Well servicing equipment	$	281		$	342
Motor vehicles		18,620			22,178
Furniture and fixtures		3,153			3,153
Gross values		22,054			25,673
Accumulated depreciation		(15,738	)		(15,314	)
Carrying value of leased assets	$	6,316		$	10,359

Depreciation of assets held under capital leases was $3.2 million, $3.5 million, and $4.3 million for the years ended December 31, 2010, 2009 and 2008, respectively, and is included in depreciation and amortization expense in the accompanying consolidated statements of operations.

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Retirement and Impairment Charge

During the third quarter of 2009, we removed from 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 $65.9 million. We retired these rigs in order to better align supply with demand for well servicing as market activity remained low. The asset retirement charge is included in the line item “asset retirements and impairments” in the consolidated statements of operations for the year ended December 31, 2009. These assets were reported under our Well Servicing segment.

Also, during the third quarter of 2009, we performed an assessment of the fair value of the assets in our Production Services segment. This assessment resulted in the recording of a pre-tax impairment charge of $31.1 million during the third quarter of 2009. The asset impairment charge is included in the line item “asset retirements and impairments” in the consolidated statements of operations for the year ended December 31, 2009.

NOTE 8.   GOODWILL AND OTHER INTANGIBLE ASSETS

The changes in the carrying amount of our goodwill for the years ended December 31, 2010 and 2009 are as follows:

	Well Servicing			Production Services			Total
				(In thousands)
December 31, 2008	$	317,490		$	3,502		$	320,992
Purchase price allocation and other adjustments, net		(356	)		500			144
Goodwill acquired during the period		23,918			—			23,918
Impairment of goodwill		—			(500	)		(500	)
Impact of foreign currency translation		971			577			1,548
December 31, 2009		342,023			4,079			346,102
Purchase price allocation and other adjustments, net		3,750			—			3,750
Goodwill acquired during the period		1,813			95,971			97,784
Impairment of goodwill		—			—			—
Impact of foreign currency translation		(228	)		201			(27	)
December 31, 2010	$	347,358		$	100,251		$	447,609

The 2010 purchase price adjustment relates to a previous acquisition from 2007. During 2010, we made full payment of contingent consideration related to earnout provisions in the purchase agreement.

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

	December 31,			December 31,
	2010			2009
	(In thousands)
Noncompete agreements:
Gross carrying value	$	15,058		$	14,010
Accumulated amortization		(8,224	)		(5,618	)
Net carrying value	$	6,834		$	8,392
Patents, trademarks and tradename:
Gross carrying value	$	17,461		$	10,481
Accumulated amortization		(927	)		(917	)
Net carrying value	$	16,534		$	9,564
Customer relationships and contracts:
Gross carrying value	$	60,057		$	41,389
Accumulated amortization		(26,059	)		(19,947	)
Net carrying value	$	33,998		$	21,442
Developed technology:
Gross carrying value	$	3,106		$	3,073
Accumulated amortization		(2,476	)		(1,724	)
Net carrying value	$	630		$	1,349
Customer backlog:
Gross carrying value	$	762		$	724
Accumulated amortization		(607	)		(423	)
Net carrying value	$	155		$	301

Amortization expense for our intangible assets with determinable lives was as follows:

	Year Ended December 31,
	2010		2009		2008
	(In thousands)
Noncompete agreements	$	2,707	$	3,222	$	4,108
Patents, trademarks and tradename		262		489		748
Customer relationships and contracts		7,349		8,679		10,710
Developed technology		752		659		1,803
Customer backlog		184		167		252
Total intangible asset amortization expense	$	11,254	$	13,216	$	17,621

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Of our intangible assets at December 31, 2010, $8.7 million are indefinite lived intangibles and not subject to amortization. The weighted average remaining amortization periods and expected amortization expense for the next five years for our intangible assets are as follows:

	Weighted
	Average Remaining
	Amortization		Expected Amortization Expense
	Period (years)		2011		2012		2013		2014		2015
	(In thousands)
Noncompete agreements		2.3	$	3,446	$	2,597	$	406	$	385	$	—
Patents, trademarks and tradename		18.2		637		531		475		475		404
Customer relationships and contracts		7.8		11,293		7,067		5,208		3,731		2,619
Developed technology		0.7		630		—		—		—		—
Customer backlog		0.7		155		—		—		—		—
Total intangible asset amortization expense			$	16,161	$	10,195	$	6,089	$	4,591	$	3,023

Certain of our 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. Additionally, certain of these assets are also subject to purchase accounting adjustments. The estimated fair values of intangible assets obtained through acquisitions consummated in the preceding twelve months are based on preliminary information which is subject to change until final valuations are obtained.

We perform annual impairment tests associated with our goodwill on December 31 of each year, or more frequently if circumstances warrant. Under the first step of the goodwill impairment test, we compared the fair value of each reporting unit to its carrying amount, including goodwill. Based on the results of our annual test, the fair value of our rig services, coiled tubing services, fluid management services reporting units and our Russia and Canadian reporting units substantially exceeded their carrying values. Because the fair value of the reporting units substantially exceeded their carrying values, we determined that no potential for impairment of our goodwill associated with those reporting units existed as of December 31, 2010, and that step two of the impairment test was not required.

As discussed in “Note 1. Organization and Summary of Significant Accounting Policies,” during the fourth quarter of 2010, we changed the date of our annual goodwill impairment assessment for our Russian reporting unit from September 30 to December 31. We tested $24.6 million of goodwill associated with the Russian reporting unit on December 31, 2010 and the first step of the goodwill impairment test showed that the fair value of the reporting unit substantially exceeded the carrying value. 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.

In 2009, we identified triggering events which required us to test our goodwill for impairment during the third quarter of 2009. Upon completion of the 2009 assessment, we recorded a pre-tax impairment charge of $0.5 million to our Production Services segment. The impairment charge is included in the line item “asset retirements and impairments” in the consolidated statements of operations for the year ended December 31, 2009. We tested our goodwill for potential impairment again on the 2009 annual testing date. The results of that test indicated that none of our reporting units that had goodwill had a fair value that was not substantially in excess of its carrying value, and no goodwill existed at any of our reporting units that were at risk of failing step one of the goodwill impairment test.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Upon completion of the 2008 assessment, we determined that the goodwill of the pressure pumping and fishing and rental reporting units comprising our Production Services segment was impaired, as such, we recorded a pre-tax impairment charge of $20.7 million for our Production Services segment during the fourth quarter of 2008.

NOTE 9.   EARNINGS PER SHARE

The following table presents our basic and diluted earnings per share for the years ended December 31, 2010, 2009 and 2008:

	Year Ended December 31,
	2010			2009			2008
	(In thousands, except per share data)
Basic EPS Computation:
Numerator
(Loss) income from continuing operations attributable to Key	$	(32,250	)	$	(110,693	)	$	69,714
Income (loss) from discontinued operations, net of tax		105,745			(45,428	)		14,344
Income (loss) attributable to Key	$	73,495		$	(156,121	)	$	84,058
Denominator
Weighted average shares outstanding		129,368			121,072			124,246
Basic (loss) earnings per share from continuing operations attributable to Key	$	(0.25	)	$	(0.91	)	$	0.56
Basic earnings (loss) per share from discontinued operations		0.82			(0.38	)		0.12
Basic earnings (loss) per share attributable to Key	$	0.57		$	(1.29	)	$	0.68
Diluted EPS Computation:
Numerator
(Loss) income from continuing operations attributable to Key	$	(32,250	)	$	(110,693	)	$	69,714
Income (loss) from discontinued operations, net of tax		105,745			(45,428	)		14,344
Income (loss) attributable to Key	$	73,495		$	(156,121	)	$	84,058
Denominator
Weighted average shares outstanding		129,368			121,072			124,246
Stock options		—			—			555
Restricted stock		—			—			254
Warrants		—			—			506
Stock appreciation rights		—			—			4
Total		129,368			121,072			125,565
Diluted income (loss) per share from continuing operations attributable to Key	$	(0.25	)	$	(0.91	)	$	0.56
Diluted income (loss) per share from discontinued operations		0.82			(0.38	)		0.11
Diluted income (loss) per share attributable to Key	$	0.57		$	(1.29	)	$	0.67

Stock options, warrants and SARs are included in the computation of diluted earnings per share using the treasury stock method. Restricted stock grants are legally considered issued and outstanding and are included. The diluted earnings per share calculation for the years ended December 31, 2010, 2009 and 2008 exclude the

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potential exercise of 2.8 million, 3.5 million, and 2.6 million stock options, respectively, because the effect would be anti-dilutive. The diluted earnings per share calculation for the years ended December 31, 2009 and 2008 each exclude the potential exercise of 0.4 million SARs because the effects of such exercises on earnings per share in those periods would be anti-dilutive. For 2010 and 2009, these options and SARs would be anti-dilutive because of our net loss from continuing operations in those years. For 2008, these options and SARs were considered anti-dilutive because their exercise prices exceeded the average price of our stock during those years.

There have been no material changes in share amounts subsequent to the balance sheet date that would have a material impact on the earnings per share calculation for the year ended December 31, 2010. However, we issued 1.1 million shares of restricted stock on February 4, 2011.

NOTE 10.   ASSET RETIREMENT OBLIGATIONS

In connection with our well servicing activities, we operate a number of saltwater disposal (“SWD”) facilities. Our operations involve the transportation, handling and disposal of fluids in our SWD facilities that are by-products of the drilling process. SWD facilities used in connection with our fluid hauling operations are subject to future costs associated with the retirement of these properties. As a result, we have incurred costs associated with the proper storage and disposal of these materials.

Annual amortization of the assets associated with the asset retirement obligations was $0.5 million, $0.5 million, and $0.6 million for the years ended December 31, 2010, 2009 and 2008, respectively. A summary of changes in our asset retirement obligations is as follows (in thousands):

Balance at December 31, 2008	$	9,348
Additions		517
Costs incurred		(306	)
Accretion expense		533
Disposals		(47	)
Balance at December 31, 2009		10,045
Additions		1,023
Costs incurred		(342	)
Accretion expense		525
Disposals		(248	)
Balance at December 31, 2010	$	11,003

NOTE 11.   EQUITY-METHOD INVESTMENTS

IROC Energy Services Corp.

As of December 31, 2010 and 2009 we owned approximately 8.7 million shares of IROC Energy Services Corp. (“IROC”), an Alberta-based oilfield services company. This represented 20.1% of IROC’s outstanding common stock on December 31, 2010 and 2009.

Through December 31, 2010, we have significant influence over the operations of IROC through our ownership interest, but we do not control it. We account for our investment in IROC using the equity method. The pro-rata share of IROC’s earnings and losses to which we are entitled is recorded in our consolidated statements of operations as a component of other income and expense, with an offsetting increase or decrease to the carrying value of our investment, as appropriate. Any earnings distributed back to us from IROC in the form of dividends would result in a decrease in the carrying value of our equity investment. The value of our

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investment may also increase or decrease each period due to changes in the exchange rate between the U.S. Dollar and Canadian Dollar. Changes in the value of our investment due to fluctuations in exchange rates are offset by accumulated other comprehensive income.

During 2010, the value of our investment in IROC increased by $0.2 million due to changes in exchange rates between the U.S. and Canadian dollar. During the years ended December 31, 2010, 2009 and 2008, we recorded equity losses of less than $0.1 million, $0.1 million and $0.2 million related to our investment in IROC, respectively. During the first quarter of 2010, IROC declared a dividend which was paid to us in February of 2010, reducing the value of our investment by $0.2 million.

The carrying value of our investment in IROC totaled $5.1 million and $4.0 million as of December 31, 2010 and 2009, respectively. The carrying value of our investment in IROC was $5.3 million below our proportionate share of the book value of the net assets of IROC as of December 31, 2010. This difference is attributable to certain long-lived assets of IROC, and our proportionate share of IROC’s net income or loss will be adjusted in future periods over the estimated remaining useful lives of those long-lived assets. Accordingly, our investment increased $1.1 million during 2010 due to the accretion of this difference. The market value of our IROC shares was approximately $10.4 million as of December 31, 2010, based on quoted market prices for IROC’s shares.

NOTE 12.   VARIABLE INTEREST ENTITIES

On March 7, 2010, we entered into an agreement with AlMansoori Petroleum Services LLC (“AlMansoori”) to form the joint venture AlMansoori Key Energy Services LLC under the laws of Abu Dhabi, UAE. The purpose of the joint venture is to engage in conventional workover and drilling services, pressure pumping services, coiled tubing services, fishing and rental tools and services, rig monitoring services, pipe handling services, fluids, waste treatment, and handling services, and wireline services. AlMansoori holds a 51% interest in the joint venture while we hold a 49% interest. Future capital contributions to the joint venture will be made on equal terms and in equal amounts and any future share capital increases will be issued in proportion to the initial share capital percentages but paid for by AlMansoori and Key in equal amounts. Also, we share the profits and losses of the joint venture on equal terms and in equal amounts with AlMansoori. However, we hold three of the five board of directors seats and a controlling financial interest. We consolidate the entity in our financial statements.

For the year ended December 31, 2010, we recognized $1.0 million of revenue and $1.5 million of net loss in the statement of operations associated with this joint venture. Also, during 2010 we guaranteed the timely performance of the joint venture under its sole contract valued at $2 million. At December 31, 2010, there was approximately $2.5 million of assets in the joint venture.

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NOTE 13.   ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

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

	December 31, 2010				December 31, 2009
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Financial assets:
Notes and accounts receivable — related parties	$	1,198	$	1,198	$	281	$	281
Financial liabilities:
8.375% Senior Notes	$	425,000	$	450,500	$	425,000	$	422,875
Senior Secured Credit Facility revolving loans		—		—		87,813		87,813
Notes payable — related parties		—		—		5,931		5,931

Notes receivable-related parties.  The amounts reported relate to notes receivable from certain of our employees related to relocation and retention agreements as well as services performed with affiliated parties. The carrying values of these notes approximate their fair values as of the applicable balance sheet dates.

8.375% Senior Notes due 2014.  The fair value of our long-term debt is based upon the quoted market prices and face value for the various debt securities at December 31, 2010. The carrying value of these notes as of December 31, 2010 was $425.0 million and the fair value was $450.5 million (106.0% of carrying value).

Senior Secured Credit Facility revolving loans.  Because of their variable interest rates and our recent amendment of the credit facility, the fair values of the revolving loans borrowed under our Senior Secured Credit Facility approximated their carrying values as of December 31, 2009. On October 4, 2010, we repaid the outstanding balance of these loans.

Notes payable — related parties.  The amounts reported relate to the seller financing arrangement entered into in connection with our acquisition of Moncla in 2007. Because of their variable interest rates and the discount applied to the notes the carrying value of these notes approximated their fair values as of December 31, 2009. On May 13, 2010, we repaid the outstanding principal balance of this note, plus accrued and unpaid interest.

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NOTE 14.   INCOME TAXES

The components of our income tax expense are as follows:

	Year Ended December 31,
	2010			2009			2008
	(In thousands)
Current income tax (expense) benefit:
Federal and state	$	11,134		$	38,878		$	(49,808	)
Foreign		(2,992	)		(3,930	)		(5,306	)
		8,142			34,948			(55,114	)
Deferred income tax (expense) benefit:
Federal and state		(2,959	)		26,664			(27,402	)
Foreign		15,329			4,362			616
		12,370			31,026			(26,786	)
Total income tax benefit (expense)	$	20,512		$	65,974		$	(81,900	)

The sources of our income or loss from continuing operations before income taxes and noncontrolling interest were as follows:

	Year Ended December 31,
	2010			2009			2008
	(In thousands)
Domestic income (loss)	$	4,089		$	(208,699	)	$	128,183
Foreign income (loss)		(59,997	)		31,477			23,186
Total income (loss)	$	(55,908	)	$	(177,222	)	$	151,369

We made no federal income tax payments for the year ended December 31, 2010. We made payments of $0.1 million and $33.5 million for the years ended December 31, 2009 and 2008, respectively. We made net state income tax payments of $0.5 million, $5.5 million and $6.6 million for the years ended December 31, 2010, 2009 and 2008, respectively. We made net foreign tax payments of $4.2 million, $7.3 million and $3.4 million for the years ended December 31, 2010, 2009 and 2008, respectively. For the years ended December 31, 2010 and 2008, tax benefits allocated to stockholders’ equity for compensation expense for income tax purposes in excess of amounts recognized for financial reporting purposes were $2.1 million and $1.7 million, respectively. For the year ended December 31, 2009, $0.6 million of tax expense was allocated to stockholders’ equity for compensation expense for financial reporting purposes in excess of amounts recognized for income tax purposes. In addition, we received a federal income tax refund of approximately $53.2 million in 2010.

Income tax expense differs from amounts computed by applying the statutory federal rate as follows:

	Year Ended December 31,
	2010			2009			2008
Income tax computed at Federal statutory rate		35.00	%		35.00	%		35.00	%
State taxes		1.7			2.5			3.0
Non-deductible goodwill		—			—			14.7
Change in valuation allowance		(3.7	)		—			(0.4	)
Other		3.7			(0.3	)		1.8
Effective income tax rate		36.70	%		37.20	%		54.10	%

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As of December 31, 2010 and 2009, our deferred tax assets and liabilities consisted of the following:

	December 31,
	2010			2009
	(In thousands)
Deferred tax assets:
Net operating loss and tax credit carryforwards	$	32,475		$	11,990
Self-insurance reserves		16,623			17,735
Allowance for doubtful accounts		2,544			1,835
Accrued liabilities		13,886			11,550
Share-based compensation		11,275			10,746
Other		137			2,554
Total deferred tax assets		76,940			56,410
Valuation allowance for deferred tax assets		(2,918	)		(835	)
Net deferred tax assets		74,022			55,575
Deferred tax liabilities:
Property and equipment		(143,211	)		(147,956	)
Intangible assets		(32,515	)		(29,238	)
Other		—			(38	)
Total deferred tax liabilities		(175,726	)		(177,232	)
Net deferred tax liability, net of valuation allowance	$	(101,704	)	$	(121,657	)

In 2010 and 2009, deferred tax liabilities decreased by $0.1 million and $0.4 million, respectively, for adjustments to accumulated other comprehensive loss.

In recording deferred income tax assets, we consider whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. We consider the scheduled reversal of deferred income tax liabilities and projected future taxable income for this determination. To fully realize the deferred income tax assets related to our federal net operating loss carryforwards that do not have a valuation allowance due to Section 382 limitations, we would need to generate future federal taxable income of approximately $2.6 million over the next eight years. With certain exceptions noted below, we believe that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to the historical evidence, it is more likely than not that these assets will be realized.

We estimate that as of December 31, 2010, 2009 and 2008 we have available $4.9 million, $7.1 million and $8.2 million, respectively, of federal net operating loss carryforwards. Approximately $2.5 million of our net operating losses as of December 31, 2010 are subject to a $1.1 million annual Section 382 limitation and expire in 2018. Approximately $2.4 million of our net operating losses as of December 31, 2010 are subject to a $5,000 annual Section 382 limitation and expire in 2016 through 2018. Due to annual limitations under Sections 382 and 383, management believes that we will not be able to utilize all available carryforwards prior to their ultimate expiration. At December 31, 2010 and 2009, we had a valuation allowance of $0.8 million related to the deferred tax asset associated with our remaining federal net operating loss carryforwards that will expire before utilization due to Section 382 limitations.

We estimate that as of December 31, 2010, 2009 and 2008 we have available approximately $37.7 million, $64.2 million and $15.9 million, respectively, of state net operating loss carryforwards that will expire between

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2020 to 2029. The deferred tax asset associated with our remaining state net operating loss carryforwards at December 31, 2010 is $3.3 million. Management believes that it is more likely than not that we will be able to utilize all available carryforwards prior to their ultimate expiration.

We estimate that as of December 31, 2010, 2009 and 2008 we have available approximately $74.5 million, $16.4 million, and $3.2 million, respectively, of foreign net operating loss carryforwards that will expire between 2014 and 2030. The gross deferred tax asset associated with our foreign net operating loss carryforwards at December 31, 2010 is $22.2 million. Management believes that it is more likely than not that we will be able to utilize the net operating loss carryforwards prior to their ultimate expiration in all foreign jurisdictions, with the exception of Argentina. Management believes that it is more likely than not that a portion of the net operating loss carryforwards in Argentina will not be utilized prior to their ultimate expiration, so a valuation allowance of $2.1 million was recorded during the year ended December 31, 2010.

We did not provide for U.S. income taxes or withholding taxes on the 2010 unremitted earnings of our Mexico subsidiaries as these earnings are considered permanently reinvested. Furthermore, we did not provide for U.S. income taxes on unremitted earnings of our other foreign subsidiaries in 2010 or prior years as our tax basis in these foreign subsidiaries exceeded the book basis for each period.

We file income tax returns in the United States federal jurisdiction and various states and foreign jurisdictions. We are currently under audit by the Internal Revenue Service for the tax year ended December 31, 2009. Our other significant filings are in Argentina and Mexico, which have been examined through 2006 and 2008, respectively.

As of December 31, 2010, 2009 and 2008 we had $2.2 million, $3.2 million and $5.6 million, respectively, of unrecognized tax benefits which, if recognized, would impact our effective tax rate. We have accrued $0.8 million, $1.1 million and $2.1 million for the payment of interest and penalties as of December 31, 2010, 2009 and 2008, respectively. We believe that it is reasonably possible that $0.9 million of our currently remaining unrecognized tax positions, each of which are individually insignificant, may be recognized by the end of 2011 as a result of a lapse of the statute of limitations and settlement of an open audit.

We recognized a net tax benefit of $1.0 million in 2010 for expirations of statutes of limitations. We recorded a net income tax benefit of $1.2 million and an increase to deferred tax liabilities of $0.2 million related to these statute expirations.

The following table presents the activity during 2010 and 2009 related to our liabilities for uncertain tax positions (in thousands):

Balance at January 1, 2009	$	5,058
Additions based on tax positions related to the current year		336
Reductions as a result of lapse of applicable statute of limitations		(2,153	)
Settlements		—
Balance at December 31, 2009		3,241
Additions based on tax positions related to the current year		192
Decreases in unrecognized tax benefits acquired or assumed in business combinations		(163	)
Reductions for tax positions from prior years		(1,016	)
Settlements		—
Balance at December 31, 2010	$	2,254

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Tax Legislative Changes

The Small Business Jobs Act of 2010.  The Small Business Jobs Act of 2010 extends the bonus first-year depreciation deduction of 50% of the adjusted basis of qualified property acquired and placed in service during 2010 and increases the deduction to 100% of the adjusted basis of qualified property acquired and placed in service after September 8, 2010 and before January 1, 2012. We have estimated $62 million of qualifying additions in 2010 resulting in bonus tax depreciation of $38.5 million.

The American Recovery and Reinvestment Act of 2009.  The American Recovery and Reinvestment Act of 2009 extends the bonus first-year depreciation deduction of 50% of the adjusted basis of qualified property acquired and placed in service to after December 31, 2008 and before January 1, 2010. We had $66 million of qualifying additions in 2009 resulting in additional 2009 tax depreciation of $33 million.

NOTE 15.   LONG-TERM DEBT

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

	December 31,			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
Other long-term indebtedness		—			1,044
Notes payable — related parties, net of discount of $69		—			5,931
Capital lease obligations		6,100			14,313
		431,100			534,101
Less current portion		(3,979	)		(10,152	)
Total long-term debt and capital lease obligations, net of discount	$	427,121		$	523,949

8.375% Senior Notes due 2014

On November 29, 2007, we issued $425.0 million of Senior Notes under an indenture (the “Indenture”). The Senior Notes were priced at 100% of their face value to yield 8.375%. Net proceeds, after deducting initial purchasers’ fees and offering expenses, were approximately $416.1 million. The Senior Notes were registered as public debt effective August 22, 2008.

The Senior Notes are general unsecured senior obligations of the Company. They rank effectively subordinate to all of our existing and future secured indebtedness. The Senior Notes are jointly and severally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. 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, at the redemption prices (expressed as percentages of the principal amount redeemed) below, plus accrued and unpaid interest 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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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, plus the Applicable Premium (as defined in the Indenture) with respect to the Senior Notes and plus accrued and unpaid interest to the redemption date. If we experience a change of control, subject to certain exceptions, we must give holders of the 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, plus accrued and unpaid interest to the date of purchase.

We are subject to certain negative covenants under the Indenture governing the Senior Notes. The Indenture limits our ability to, among other things:

•  sell assets;

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

•  make investments;

•  incur additional indebtedness or issue preferred stock;

•  create certain liens;

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

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

•  engage in transactions with affiliates; and

•  create unrestricted subsidiaries.

These covenants are subject to certain exceptions and qualifications, and contain cross-default provisions in connection with the covenants of our Senior Secured Credit Facility. 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. As of December 31, 2010, the Senior Notes were below investment grade. Any covenants that cease to apply to us as a result of achieving an investment grade rating will not be restored, even if the credit rating assigned to the Senior Notes later falls below an investment grade rating.

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 Securities LLC and Wells Fargo Bank, N.A. are the administrative agents. 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.

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.

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

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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 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:

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 subclauses (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 affirmative covenants, including, without limitation, restrictions related to (i) liens; (ii) debt, guarantees and other contingent obligations; (iii) mergers and consolidations; (iv) sales, transfers and other dispositions of property or assets; (v) loans, acquisitions, joint ventures and other investments; (vi) dividends and other distributions to, and redemptions and repurchases from, equity holders; (vii) prepaying, redeeming or repurchasing the Senior Notes or other unsecured debt incurred pursuant to the sixth bullet point listed above; (viii) granting negative pledges other than to the lenders; (ix) changes in the nature of our business; (x) amending organizational documents, or amending or otherwise modifying any debt if such amendment or modification would have a material adverse effect, or amending the Senior Notes or any other unsecured debt incurred pursuant to the sixth bullet point listed above if the effect of such amendment is to shorten the maturity of the Senior Notes or such other

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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.

As of December 31, 2010, $59.4 million of letters of credit were outstanding under our revolving credit facility, leaving $240.6 million of availability under our revolving credit facility. Under the terms of the Senior Secured Credit Facility, committed letters of credit count against our borrowing capacity. All obligations under the Senior Secured Credit Facility are guaranteed by most of our subsidiaries and are secured by most of our assets, including our accounts receivable, inventory and equipment.

Notes Payable to Related Parties

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.

Long-Term Debt Principal Repayment and Interest Expense

Presented below is a schedule of the repayment requirements of long-term debt for each of the next five years and thereafter as of December 31, 2010:

	Principal Amount of Long-Term Debt
	(In thousands)
2011	$	—
2012		—
2013		—
2014		425,000
2015		—
Thereafter		—
Total principal payments		425,000
Less: fair value discount		—
Total long-term debt	$	425,000

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Presented below is a schedule of our estimated minimum lease payments on our capital lease obligations for the next five years and thereafter as of December 31, 2010:

	Capital Lease Obligation Minimum
	Lease Payments
	(In thousands)
2011	$	4,344
2012		1,888
2013		503
2014		—
2015		—
Thereafter		—
Total minimum lease payments		6,735
Less: executory costs		(569	)
Net minimum lease payments		6,166
Less: amounts representing interest		(66	)
Present value of minimum lease payments	$	6,100

Interest expense for the years ended December 31, 2010, 2009 and 2008 consisted of the following:

	Year Ended December 31,
	2010			2009			2008
	(In thousands)
Cash payments	$	40,612		$	41,750		$	45,211
Commitment and agency fees paid		1,151			825			102
Amortization of discount		15			113			140
Amortization of deferred financing costs		2,615			2,070			1,975
Net change in accrued interest		1,083			(1,354	)		333
Capitalized interest		(3,517	)		(3,999	)		(5,139	)
Net interest expense	$	41,959		$	39,405		$	42,622

As of December 31, 2010 and 2009, the weighted average interest rate of our variable rate debt was 1.78% and 3.24%, respectively.

Deferred Financing Costs

Cost capitalized, amortized, and written off in the determination of the loss on extinguishment of debt for the years ended December 31, 2010, 2009 and 2008 are presented in the table below:

	December 31,
	2010		2009		2008
	(In thousands)
Capitalized costs	$	—	$	2,474	$	314
Amortization		2,615		2,070		1,975
Loss on extinguishment		—		472		—

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Net carrying values for the years presented appear in the table below:

	December 31,
	2010			2009
	(In thousands)
Deferred financing costs:
Gross carrying value	$	14,611		$	14,611
Accumulated amortization		(6,805	)		(4,190	)
Net carrying value	$	7,806		$	10,421

NOTE 16.   COMMITMENTS AND CONTINGENCIES

Operating Lease Arrangements

We lease certain property and equipment under non-cancelable operating leases that expire at various dates through 2019, with varying payment dates throughout each month.

As of December 31, 2010, the future minimum lease payments under non-cancelable operating leases are as follows (in thousands):

	Lease
	Payments
2011	$	15,827
2012		10,821
2013		6,530
2014		4,078
2015		2,359
Thereafter		1,926
	$	41,541

We are also party to a significant number of month-to-month leases that are cancelable at any time. Operating lease expense was $21.1 million, $22.7 million, and $22.4 million for the years ended December 31, 2010, 2009 and 2008, respectively.

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 subject to jury verdicts or other outcomes that may be favorable to 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 December 31, 2010, the aggregate amount of our liabilities related to litigation that are deemed probable and reasonably estimable is approximately $3.8 million. We do not believe that the disposition of any of these matters will have a material impact on our financial position, results of operations, or cash flows. In the year ended December 31, 2010, we recorded a net increase in our reserves of $1.1 million related to the settlement of ongoing legal matters and the continued refinement of liabilities recognized for litigation deemed probable and estimable. Our liabilities related to litigation matters that were deemed probable and estimable as of December 31, 2009 and 2008 were $2.7 million and $4.5 million, respectively.

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Litigation with Former Officers and Employees

Our former general counsel, Jack D. Loftis, Jr., filed a lawsuit against us in the U.S. District Court, District of New Jersey, on April 21, 2006, in which he 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. 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 year ended December 31, 2010.

UMMA Verdict

On May 3, 2010, a District Court jury in McMullen County, Texas 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. On December 15, 2010, our motion for judgment notwithstanding the verdict was partially granted; however, the Court entered judgment in favor of UMMA on one of its claims. During the subsequent briefing on motions for new trial and for reconsideration, the parties reached a settlement in this case, and we recorded a loss for this matter. The resolution of this matter did not have a material effect on our results of operations for the year ended December 31, 2010.

Tax Audits

We are routinely the subject of audits by tax authorities, and in the past have received material assessments from tax auditors. As of December 31, 2010 and 2009, we have recorded reserves that management feels are appropriate for future potential liabilities as a result of prior audits. While we believe we have fully reserved for these assessments, the ultimate amount of settlements can vary from our estimates.

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, vehicular 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 December 31, 2010 and 2009, we have recorded $60.3 million and $65.2 million, respectively, of self-insurance reserves related to workers’ compensation, vehicular liabilities and general liability claims. Partially offsetting these liabilities, we had approximately $15.4 million and $17.2 million of insurance receivables as of December 31, 2010 and 2009, respectively. 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

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to conduct such remediation efforts can be reasonably estimated. As of December 31, 2010 and 2009, we have recorded $4.0 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.

We provide performance bonds to provide financial surety assurances for the remediation and maintenance of our SWD properties to comply with environmental protection standards. Costs for SWD properties may be mandatory (to comply with applicable laws and regulations), in the future (required to divest or cease operations), or for optimization (to improve operations, but not for safety or regulatory compliance).

NOTE 17.   ACCUMULATED OTHER COMPREHENSIVE LOSS

The components of our accumulated other comprehensive loss are as follows (in thousands):

	December 31,
	2010			2009
Foreign currency translation loss	$	(51,334	)	$	(50,763	)
Accumulated other comprehensive loss	$	(51,334	)	$	(50,763	)

The local currency is the functional currency for our operations in Argentina, Mexico, Canada, the Russian Federation and for our equity investments in Canada. The cumulative translation gains and losses resulting from translating each foreign subsidiary’s financial statements from the functional currency to U.S. dollars are included in other comprehensive income and accumulated in stockholders’ equity until a partial or complete sale or liquidation of our net investment in the foreign entity. The table below summarizes the conversion ratios used to translate the financial statements and the cumulative currency translation gains and losses, net of tax, for each currency:

	Argentine Peso			Mexican Peso			Canadian Dollar			Euro		Russian Rouble			Total
	(In thousands, except for conversion ratios)
As of December 31, 2010:
Conversion ratio		3.98 : 1			12.39 : 1			1.00 : 1			0.75 : 1		30.54 : 1			n/a
Cumulative translation adjustment	$	(50,518	)	$	56		$	(944	)		n/a	$	72		$	(51,334	)
As of December 31, 2009:
Conversion ratio		3.82 : 1			13.04 : 1			1.05 : 1			0.70 : 1		30.27 : 1			n/a
Cumulative translation adjustment	$	(48,953	)	$	(716	)	$	(1,087	)		n/a	$	(7	)	$	(50,763	)

NOTE 18.   EMPLOYEE BENEFIT PLANS

We maintain a 401(k) plan as part of our employee benefits package. Late in the first quarter of 2009, management suspended the 401(k) matching program as part of our cost cutting efforts. No matching contributions were made during 2010. Prior to this suspension, we matched 100% of employee contributions up to 4% of the employee’s salary into our 401(k) plan, subject to maximums of $9,800 and $9,200 for the years ended December 31, 2009 and 2008 respectively. Our matching contributions were $1.7 million and $11.9 million for the years ended December 31, 2009 and 2008, respectively. We do not offer participants the option to purchase units of our common stock through a 401(k) plan fund. We reinstated the 401(k) matching program effective January 1, 2011.

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NOTE 19.   STOCKHOLDERS’ EQUITY

Common Stock

As of December 31, 2010 and 2009, we had 200,000,000 shares of common stock authorized with a $0.10 par value, of which 141,656,426 shares were issued and outstanding at December 31, 2010 and 123,993,480 shares were issued and outstanding at December 31, 2009. During 2010 and 2009, no dividends were declared or paid. Under the terms of the Senior Notes and Senior Secured Credit Facility, we must meet certain financial covenants before we may pay dividends. We currently do not intend to pay dividends.

Tax Withholding

We repurchase shares of restricted common stock that have been previously granted to certain of our employees, pursuant to an agreement under which those individuals are permitted to sell shares back to us in order to satisfy the minimum income tax withholding requirements related to vesting of these grants. We repurchased a total of 301,837, 71,954 and 97,443 shares for an aggregate cost of $3.1 million, $0.5 million and $1.2 million during 2010, 2009 and 2008, respectively, which represented the fair market value of the shares based on the price of our stock on the dates of purchase.

Common Stock Warrants

On May 12, 2009, in connection with the settlement of a lawsuit, we issued to two individuals warrants to purchase shares of Key’s common stock. The warrants, which expire on May 12, 2014, are exercisable for 174,000 shares of our common stock at an exercise price of $4.56 per share. We received no proceeds upon the issuance of the warrants, but we will receive the exercise price of any warrants that are exercised prior to their expiration. The warrants, which are unregistered securities, were issued in a private placement and, therefore, their issuance was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933. As of December 31, 2010, 54,400 of these warrants had been exercised, leaving 119,600 outstanding.

NOTE 20.   SHARE-BASED COMPENSATION

2009 Incentive Plan

On June 4, 2009, our stockholders approved the 2009 Equity and Cash Incentive Plan (the “2009 Incentive Plan”). The 2009 Incentive Plan is administered by our board of directors or a committee designated by our board of directors (the “Committee”). Our board of directors or the Committee (the “Administrator”) will have the power and authority to select Participants (as defined below) in the 2009 Incentive Plan and to grant Awards (as defined below) to such Participants pursuant to the terms of the 2009 Incentive Plan. The 2009 Incentive Plan expires June 4, 2019.

Subject to adjustment, the total number of shares of our common stock available for the grant of Awards under the 2009 Incentive Plan may not exceed 4,000,000 shares; however, for purposes of this limitation, any stock subject to an award that is canceled, forfeited or expires prior to exercise or realization will again become available for issuance under the 2009 Incentive Plan. Subject to adjustment, no Participant will be granted, during any one year period, options to purchase common stock and/or stock appreciation rights with respect to more than 500,000 shares of common stock. Stock available for distribution under the 2009 Incentive Plan will come from authorized and unissued shares or shares we reacquire in any manner. All awards under the 2009 Incentive Plan are granted at fair market value on the date of issuance.

Awards may be in the form of stock options (incentive stock options and nonqualified stock options), restricted stock, restricted stock units, performance compensation awards and stock appreciation rights (collectively, “Awards”). Awards may be granted to employees, directors and, in some cases, consultants and those individuals whom the Administrator determines are reasonably expected to become employees, directors

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or consultants following the grant date of the Award (“Participants”). However, incentive stock options may be granted only to employees. Vesting periods may be set at the Board’s discretion but are generally set at two to four years. Awards to our directors are generally not subject to vesting.

Our Board of Directors at any time, and from time to time, may amend or terminate the 2009 Incentive Plan. However, no repricing of stock options is permitted unless approved by our stockholders, and, except as provided otherwise in the 2009 Incentive Plan, no other amendment will be effective unless approved by our stockholders to the extent stockholder approval is necessary to satisfy any applicable law or securities exchange listing requirements. As of December 31, 2010, there were 2.2 million remaining shares available under the 2009 Incentive Plan.

2007 Incentive Plan

On December 6, 2007, our stockholders approved the 2007 Equity and Cash Incentive Plan (the “2007 Incentive Plan”). The 2007 Incentive Plan is substantially similar to the 2009 Incentive Plan except for certain differences related to treatment of Awards at retirement and transferability of Awards at death.

Subject to adjustment, the total number of shares of our common stock that are available for the grant of Awards under the 2007 Incentive Plan may not exceed 4,000,000 shares; however, for purposes of this limitation, any stock subject to an award that is canceled, forfeited or expires prior to exercise or realization will again become available for issuance under the 2007 Incentive Plan.

Our board of directors at any time, and from time to time, may amend or terminate the 2007 Incentive Plan. However, except as provided otherwise in the 2007 Incentive Plan, no amendment will be effective unless approved by our stockholders to the extent stockholder approval is necessary to satisfy any applicable law or securities exchange listing requirements. As of December 31, 2010, there were 0.2 million remaining shares available under the 2007 Incentive Plan.

1997 Incentive Plan

On January 13, 1998, our stockholders approved the Key Energy Group, Inc. 1997 Incentive Plan, as amended (the “1997 Incentive Plan”). The 1997 Incentive Plan is an amendment and restatement of the plans formerly known as the Key Energy Group, Inc. 1995 Stock Option Plan and the Key Energy Group, Inc. 1995 Outside Directors Stock Option Plan. On November 17, 2007, the 1997 Incentive Plan terminated pursuant to its terms.

The exercise price of options granted under the 1997 Incentive Plan is at or above the fair market value per share on the date the options are granted. Under the 1997 Incentive Plan, while the shares of common stock are listed on a securities exchange, fair market value was determined using the closing sales price on the immediate preceding business day as reported on such securities exchange.

When the shares were not listed on an exchange, which includes the period from April 2005 through October 2007, the fair market value was determined by using the published closing price of the common stock on the Pink Sheets on the business day immediately preceding the date of grant.

During the period 2000-2001, the Board of Directors granted 3.7 million stock options that were outside the 1997 Incentive Plan, of which 60,000 remained outstanding as of December 31, 2010. The 3.7 million non-plan options were in addition to and do not include other options which were granted under the 1997 Incentive Plan, but not in conformity with certain of the terms of the 1997 Incentive Plan.

Accelerated Vesting of Option and SAR Awards

Our Board of Directors resolved during the fourth quarter of 2008 to accelerate the vesting period on certain of our outstanding unvested stock option awards and stock appreciation rights, which affected

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approximately 280 employees. As a result of the acceleration, we recorded a pre-tax charge in general and administrative expense during the fourth quarter of 2008. Because of the acceleration of the vesting term, no expense is recognized on these awards in periods subsequent to December 31, 2008.

Stock Option Awards

Stock option awards granted under our incentive plans have a maximum contractual term of ten years from the date of grant. Shares issuable upon exercise of a stock option are issued from authorized but unissued shares of our common stock. The following table summarizes the stock option activity and certain options granted in prior years that were outside the 1997 Incentive Plan (shares in thousands):

	Year Ended December 31, 2010
				Weighted Average		Weighted Average
	Options			Exercise Price		Fair Value
Outstanding at beginning of period		3,895		$	12.90	$	5.62
Granted		—		$	—	$	—
Exercised		(454	)	$	8.51	$	4.83
Cancelled or expired		(625	)	$	13.28	$	5.77
Outstanding at end of period		2,816		$	13.52	$	5.72
Exercisable at end of period		2,790		$	13.60	$	5.76

	Year Ended December 31, 2009
				Weighted Average		Weighted Average
	Options			Exercise Price		Fair Value
Outstanding at beginning of period		4,961		$	12.21	$	5.42
Granted		15		$	4.14	$	2.23
Exercised		(418	)	$	3.12	$	2.30
Cancelled or expired		(663	)	$	13.70	$	5.84
Outstanding at end of period		3,895		$	12.90	$	5.62
Exercisable at end of period		3,853		$	12.99	$	5.66

	Year Ended December 31, 2008
				Weighted Average		Weighted Average
	Options			Exercise Price		Fair Value
Outstanding at beginning of period		4,594		$	11.01	$	5.32
Granted		1,379		$	14.76	$	5.43
Exercised		(757	)	$	8.81	$	4.81
Cancelled or expired		(255	)	$	14.53	$	6.15
Outstanding at end of period		4,961		$	12.21	$	5.38
Exercisable at end of period		4,911		$	12.30	$	5.42

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The following table summarizes information about the stock options outstanding at December 31, 2010 and certain options granted in prior years that were outside the 1997 Incentive Plan (shares in thousands):

	Options Outstanding
	Weighted Average
	Remaining		Number of
	Contractual Life		Options		Weighted Average		Weighted Average
	(Years)		Outstanding		Exercise Price		Fair Value
Range of exercise prices:
$3.87 - $8.00		2.76		134	$	7.06	$	3.65
$8.01 - $9.37		1.24		139	$	8.38	$	4.48
$9.38 - $13.10		3.87		590	$	11.58	$	5.26
$13.11 - $15.05		6.07		1,077	$	14.57	$	6.43
$15.06 - $19.42		7.27		876	$	15.33	$	5.68
				2,816	$	13.52	$	5.72
Aggregate intrinsic value (in thousands)			$	2,265

	Options Exercisable
	Number of
	Options		Weighted Average		Weighted Average
	Exercisable		Exercise Price		Fair Value
Range of exercise prices:
$3.87 - $8.00		108	$	7.68	$	4.03
$8.01 - $9.37		139	$	8.38	$	4.48
$9.38 - $13.10		590	$	11.58	$	5.26
$13.11 - $15.05		1,077	$	14.57	$	6.43
$15.06 - $19.42		876	$	15.33	$	5.68
		2,790	$	13.60	$	5.76
Aggregate intrinsic value (in thousands)	$	2,040

We did not grant any stock options during the year ended December 31, 2010. The total fair value of stock options granted during the years ended December 31, 2009 and 2008 was less than $0.1 million, and $7.5 million, respectively. The total fair value of stock options vested during the year ended December 31, 2010 was less than $0.1 million. For the years ended December 31, 2010, 2009 and 2008, we recognized less than $0.1 million, less than $0.1 million and $15.1 million in pre-tax expense related to stock options, respectively. We recognized tax benefits of less than $0.1 million, less than $0.1 million, and $5.2 million related to our stock options for the years ended December 31, 2010, 2009 and 2008, respectively. Compensation expense recognized during 2008 related to stock option awards included the charge we took for the accelerated vesting, as discussed above. For unvested stock option awards outstanding as of December 31, 2010, we expect to recognize less than $0.1 million of compensation expense over a weighted average remaining vesting period of approximately 1.5 years. The weighted average remaining contractual term for stock option awards exercisable as of December 31, 2010 is 5.6 years. The intrinsic value of the options exercised for the years ended December 31, 2010, 2009 and 2008 was $4.0 million, $1.9 million and $5.8 million, respectively. Cash received from the exercise of options for the year ended December 31, 2010, was $3.6 million with recognition of associated tax benefits in the amount of $0.3 million.

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Common Stock Awards

The total fair market value of all common stock awards granted during the years ended December 31, 2010, 2009 and 2008 was $17.9 million, $8.8 million and $6.5 million, respectively.

The following table summarizes information for the years ended December 31, 2010, 2009 and 2008 about the common share awards that we have issued (shares in thousands):

	Year Ended December 31, 2010
				Weighted Average					Weighted Average
	Outstanding			Issuance Price		Vested			Issuance Price
Shares at beginning of period		3,679		$	7.14		1,094		$	13.70
Shares issued during period(1)		1,804		$	9.90		153		$	1.28
Previously issued shares vesting during period		—		$	—		968		$	4.13
Shares cancelled during period		(154	)	$	5.94		—		$	—
Shares repurchased during period		(302	)	$	10.24		(302	)	$	10.24
Shares at end of period		5,027		$	7.98		1,913		$	8.41

	Year Ended December 31, 2009
				Weighted Average					Weighted Average
	Outstanding			Issuance Price		Vested			Issuance Price
Shares at beginning of period		1,409		$	14.42		748		$	14.05
Shares issued during period(1)		2,667		$	3.30		146		$	5.96
Previously issued shares vesting during period		—		$	—		272		$	15.04
Shares cancelled during period		(325	)	$	7.24		—		$	—
Shares repurchased during period		(72	)	$	6.73		(72	)	$	6.73
Shares at end of period		3,679		$	7.14		1,094		$	13.70

	Year Ended December 31, 2008
				Weighted Average					Weighted Average
	Outstanding			Issuance Price		Vested			Issuance Price
Shares at beginning of period		1,078		$	14.01		478		$	13.48
Shares issued during period(1)		428		$	15.10		47		$	18.01
Previously issued shares vesting during period		—		$	—		320		$	13.97
Shares repurchased during period		(97	)	$	12.86		(97	)	$	12.86
Shares at end of period		1,409		$	14.42		748		$	14.05

(1) Includes 109,410, 143,100 and 47,190 shares of common stock issued to our non-employee directors vested immediately upon issuance during 2010, 2009 and 2008, respectively.

For common stock grants that vest immediately upon issuance, we record expense equal to the fair market value of the shares on the date of grant. For common stock awards that do not immediately vest, we recognize compensation expense ratably over the vesting period of the grant, net of estimated and actual forfeitures. For the years ended December 31, 2010, 2009 and 2008, we recognized $10.6 million, $6.0 million and $6.1 million, respectively, of pre-tax expense from continuing operations associated with common stock

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awards, including common stock grants to our outside directors. In connection with the expense related to common stock awards recognized during the year ended December 31, 2010, we recognized tax benefits of $4.1 million. Tax benefits for the years ended December 31, 2009 and 2008 were $2.0 million and $1.5 million, respectively. For the unvested common stock awards outstanding as of December 31, 2010, we anticipate that we will recognize $11.3 million of pre-tax expense over the next 1.0 years.

Performance Units

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 December 31, 2010, the fair value of outstanding performance units issued in March 2010 was $2.7 million, and is being accreted to compensation expense over the vesting terms of the awards. The unrecognized compensation cost related to our unvested performance units is estimated to be $1.2 million and is expected to be recognized over a weighted-average period of 1.0 years as of December 31, 2010.

Phantom Share Plan

In December 2006, we announced the implementation of a “Phantom Share Plan,” in which certain of our employees were granted “Phantom Shares.” Phantom Shares vest ratably over a four-year period and convey the right to the grantee to receive a cash payment on the anniversary date of the grant equal to the fair market value of the Phantom Shares vesting on that date. Grantees are not permitted to defer this payment to a later date. The Phantom Shares are a “liability” type award and we account for these awards at fair value. We recognize compensation expense related to the Phantom Shares based on the change in the fair value of the awards during the period and the percentage of the service requirement that has been performed, net of estimated and actual forfeitures, with an offsetting liability recorded on our consolidated balance sheets. We recognized $1.1 million and $1.9 million of pre-tax compensation expense from continuing operations, and less than $0.1 million of pre-tax benefit associated with the Phantom Shares for the years ended December 31, 2010, 2009 and 2008, respectively. As of December 31, 2010, we recorded current and non-current liabilities of $1.1 million and $1.1 million, respectively, which represented the aggregate fair value of the Phantom Shares on that date.

We recognized income tax benefits associated with the Phantom Shares of $0.4 million, $0.7 million and less than $0.1 million in 2010, 2009 and 2008, respectively. For unvested Phantom Share awards outstanding as of December 31, 2010, based on the market price of our common stock on this date, we expect to recognize $0.4 million of compensation expense over a weighted average remaining vesting period of approximately 0.8 years. During 2010, cash payments related to the Phantom Shares totaled $2.2 million.

Stock Appreciation Rights

In August 2007, we issued approximately 587,000 SARs to our executive officers. Each SAR has a ten-year term from the date of grant. The vesting of all outstanding SAR awards was accelerated during the fourth quarter of 2008. Upon the exercise of a SAR, the recipient will receive an amount equal to the difference

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between the exercise price and the fair market value of a share of our common stock on the date of exercise, multiplied by the number of shares of common stock for which the SAR was exercised. All payments will be made in shares of our common stock. Prior to exercise, the SAR does not entitle the recipient to receive any shares of our common stock and does not provide the recipient with any voting or other stockholders’ rights. We account for these SARs as equity awards and recognize compensation expense ratably over the vesting period of the SAR based on their fair value on the date of issuance, net of estimated and actual forfeitures. We did not recognize any expense associated with these awards during 2010 and 2009. Compensation expense recognized in 2008 in connection with the SARs was $3.1 million. We recognized income tax benefits of $1.1 million in 2008, in connection with this expense.

Valuation Assumptions on Stock Options and Stock Appreciation Rights

The fair value of each stock option grant or SAR was estimated on the date of grant using the Black-Scholes option-pricing model, based on the following weighted-average assumptions:

	Year Ended December 31,
	2010		2009			2008
Risk-free interest rate		n/a		2.21	%		2.86	%
Expected life of options and SARs, years		n/a		6			6
Expected volatility of our stock price		n/a		53.70	%		36.86	%
Expected dividends		n/a		none			none

NOTE 21.   TRANSACTIONS WITH RELATED PARTIES

Employee Loans and Advances

From time to time, we have made certain retention loans and relocation loans to employees other than executive officers. The retention loans are forgiven over various time periods so long as the employee continues their employment with us. The relocation loans are repaid upon the employee selling his prior residence. As of December 31, 2010 and 2009, these loans, in the aggregate, totaled $0.1 million and $0.2 million, respectively. Of this amount, less than $0.1 million were made to our former officers, with the remainder being made to our current employees.

Receivables from Affiliates

As discussed in “Note 2. Acquisitions”, in October 2010, we acquired certain subsidiaries, together with associated assets, owned by OFS, a privately-held oilfield services company of ArcLight Capital Partners, LLC. At the time of the acquisition, OFS conducted business with companies owned by one of the former owners and employees of an OFS subsidiary purchased by us. Subsequent to the acquisition, we continued to provide services to these companies. The prices charged for our services are at rates that are equivalent to the prices charged to our other customers in the U.S. market. As of December 31, 2010, our receivables with these related parties totaled $1.0 million and revenues from these customers since the date of acquisition through the year ended December 31, 2010 totaled $1.3 million.

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.

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Transactions with Employees

In connection with an acquisition in 2008, the former owner of the acquiree became an employee of Key. 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. As of December 31, 2010, our receivables with this company totaled $0.2 million, and for the year ended December 31, 2010, revenues from this company totaled $4.3 million.

Board of Director Relationships

One of the members 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% of our total revenues for the year ended December 31, 2010, and less than 2% of our total revenues for the years ended December 31, 2009 and 2008. Our sales to Anadarko were less than 1% of Anadarko’s revenues for 2010, 2009 and 2008. Receivables outstanding from Anadarko were approximately 2% and 1% of our total accounts receivable as of December 31, 2010 and 2009, respectively. Transactions with Anadarko for our services are made on terms consistent with other customers.

Concurrent with our acquisition of OFS in October 2010, we created a new class III directorship on our Board with a term ending at the 2012 annual stockholder meeting. This vacancy was filled with by a nominee designated by OFS pursuant to the terms of the purchase and sale agreement.

NOTE 22.   SUPPLEMENTAL CASH FLOW INFORMATION

	Year Ended December 31,
	2010		2009		2008
	(In thousands)
Noncash investing and financing activities:
Property and equipment acquired under capital	$	—	$	938	$	7,654
lease obligations
Common stock issued in acquisition		153,963		—		—
Asset retirement obligations		1,023		517		397
Unrealized loss on short-term investments		—		—		(8	)
Software acquired under financing arrangement		—		—		3,985
Supplemental cash flow information:
Cash paid for interest	$	41,763	$	42,575	$	45,313
Cash paid for taxes	$	4,610	$	12,872	$	43,494
Tax refunds	$	56,154	$	9,135	$	3,701

Cash paid for interest includes cash payments for interest on our long-term debt and capital lease obligations, and commitment and agency fees paid.

NOTE 23.   SEGMENT INFORMATION

As of December 31, 2010, we operate in two business segments, Well Servicing and Production Services. Our rig services and fluid management services operations are aggregated within our Well Servicing segment. Our pressure pumping services, coiled tubing services, fishing and rental services and wireline services operations, 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.” All inter-segment sales pricing is based on current market conditions. As mentioned in “Note 3. Discontinued Operations,” on October 1, 2010, we completed the sale of our pressure pumping and wireline businesses to Patterson-UTI, which significantly

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reduced our involvement in these lines of business. We are revising our reportable segments in the first quarter of 2011 to realign our current business and management structure. The following is a description of our segments as of December 31, 2010:

Well Servicing

Rig-Based Services

These services include the maintenance, workover and recompletion of existing 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 providing conventional and horizontal drilling services.

Maintenance services provided by our rigs include routine mechanical repairs to the pumps, tubing and other equipment in a well, removing debris and formation material from the wellbore, and pulling rods and other downhole equipment out of the wellbore to identify and resolve a production problem.

The workover services that we provide are designed to enhance the production of existing wells, and generally are more complex and time consuming than normal maintenance services. Workover services can include deepening or extending well bores into new formations by drilling horizontal or lateral well bores, 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.

Our completion and recompletion services prepare a newly drilled oil or natural gas well for production. We typically provide a well service rig and may also provide other equipment such as a workover package to assist in the completion process.

Fluid Management Services

These services include fluid management logistics, including oilfield transportation and produced-water disposal services. These services include vacuum truck services, fluid transportation services and disposal services for operators whose oil or natural gas wells produce saltwater or other non-hydrocarbon fluids. In addition, we are a supplier of frac tanks which are used for temporary storage of fluids associated with fluid hauling operations. Our fluid management services will collect, transport and dispose of the saltwater. These fluids are removed from the well site and transported for disposal in a SWD well.

Production Services Segment

Historically, our Production Services segment included pressure pumping services (fracturing, nitrogen, acidizing, and cementing), wireline services (perforating, completion logging, production logging and casing integrity services), coiled tubing services and fishing and rental services. 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 in the United States. As discussed in “Note 3. Discontinued Operations,” for the financial statements presented in this report, we show the results of operations for our pressure pumping and wireline business as discontinued operations for all periods presented. As of December 31, 2010, our Production Services segment primarily consists of our coiled tubing and fishing and rental services. Our Production Services segment also includes some specialty pumping services, nitrogen services, and cementing services.

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Coiled Tubing Services

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 fracturing. Coiled tubing is also used for a number of horizontal well applications such as milling temporary plugs between frac stages.

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, production tubulars, handling tools (including our patented Hydra-Walk^® pipe-handling units and services), pressure-control equipment, power swivels and foam air units.

Advanced Measurements, Inc. (“AMI”)

Also included in our Production Services segment is AMI, our technology development company based in Canada. AMI is focused on oilfield service equipment controls, data acquisition and digital information flow.

Functional Support

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, our equity-method investment in IROC and deferred income tax assets.

The following present our segment information as of and for the years ended December 31, 2010, 2009 and 2008 (in thousands):

	Well			Production			Functional
	Servicing			Services			Support			Eliminations			Total
As of and for the year ended December 31, 2010:
Revenues from external customers	$	980,271		$	173,413		$	—		$	—		$	1,153,684
Intersegment revenue		251			9,434			—			(9,685	)		—
Depreciation and amortization		102,044			24,114			10,889			—			137,047
Operating expenses		801,238			117,210			114,835			—			1,033,283
Operating income (loss)		76,989			32,089			(125,724	)		—			(16,646	)
Interest expense, net of amounts capitalized		(948	)		(190	)		43,097			—			41,959
Income (loss) from continuing operations before tax		76,756			34,538			(167,202	)		—			(55,908	)
														—
Total assets		1,425,710			369,639			479,913			(382,326	)		1,892,936
Capital expenditures, excluding acquisitions		109,301			37,058			33,951			—			180,310

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	Well			Production			Functional
	Servicing			Services			Support			Eliminations			Total
As of and for the year ended December 31, 2009:
Revenues from external customers	$	859,747		$	95,952		$	—		$	—		$	955,699
Intersegment revenue		10			5,411			—			(5,421	)		—
Depreciation and amortization		114,178			27,163			7,892			—			149,233
Operating expenses		667,326			83,062			97,694			—			848,082
Asset retirements and impairments		65,869			31,166			—			—			97,035
Operating income (loss)		12,374			(45,439	)		(105,586	)		—			(138,651	)
Interest expense, net of amounts capitalized		(2,007	)		(391	)		41,803			—			39,405
Income (loss) from continuing operations before tax		14,414			(43,571	)		(148,065	)		—			(177,222	)
Total assets		1,133,068			251,580			643,854			(364,092	)		1,664,410
Capital expenditures, excluding acquisitions		75,242			39,305			13,875			—			128,422

	Well			Production			Functional
	Servicing			Services			Support			Eliminations			Total
As of and for the year ended December 31, 2008:
Revenues from external customers	$	1,470,332		$	154,114		$	—		$	—		$	1,624,446
Intersegment revenue		93			5,177			—			(5,270	)		—
Depreciation and amortization		120,169			17,718			11,720			—			149,607
Operating expenses		994,263			112,836			145,096			—			1,252,195
Asset retirements and impairments		—			20,716			5,385			—			26,101
Operating income (loss)		355,900			2,844			(162,201	)		—			196,543
Interest expense, net of amounts capitalized		(2,310	)		(453	)		45,385			—			42,622
Income (loss) from continuing operations before tax		354,928			5,117			(208,676	)		—			151,369
Total assets		1,386,753			429,131			587,696			(386,657	)		2,016,923
Capital expenditures, excluding acquisitions		145,494			65,312			8,188			—			218,994

The following table presents selected financial information related to our operations by geography (in thousands of U.S. Dollars):

	U.S.		International		Eliminations			Total
As of and for the year ended December 31, 2010:
Revenue from external customers	$	961,244	$	192,440	$	—		$	1,153,684
Long-lived assets		1,359,993		171,957		(53,034	)		1,478,916
As of and for the year ended December 31, 2009:
Revenue from external customers	$	758,363	$	197,336	$	—		$	955,699
Long-lived assets		1,263,376		145,971		(129,069	)		1,280,278
As of and for the year ended December 31, 2008:
Revenue from external customers	$	1,452,557	$	171,889	$	—		$	1,624,446
Long-lived assets		1,434,578		78,448		(55,225	)		1,457,801

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NOTE 24.   UNAUDITED QUARTERLY RESULTS OF OPERATIONS

Set forth below is unaudited summarized quarterly information for the two most recent years covered by these consolidated financial statements (in thousands, except for per share data):

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year Ended December 31, 2010:
Revenues	$	251,959		$	267,785		$	283,739		$	350,201
Direct operating expenses		189,202			196,171			198,158			251,481
(Loss) income from continuing operations		(10,902	)		(11,038	)		(2,280	)		(11,176	)
Net (loss) income		(9,007	)		(2,856	)		6,003			76,209
(Loss) income attributable to Key		(7,580	)		(2,236	)		6,772			76,539
Earnings per share(1):
Basic	$	(0.06	)	$	(0.02	)	$	0.05		$	0.54
Diluted	$	(0.06	)	$	(0.02	)	$	0.05		$	0.54

	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
Year Ended December 31, 2009:
Revenues	$	283,649	$	219,061		$	215,349		$	237,640
Direct operating expenses		185,529		155,118			156,444			178,851
Asset retirements and impairments		—		—			97,035			—
Income (loss) from continuing operations		2,213		(16,024	)		(79,080	)		(18,357	)
Net income (loss)		904		(18,473	)		(125,017	)		(14,090	)
Income (loss) attributable to Key		904		(18,473	)		(124,942	)		(13,610	)
Earnings per share(1):
Basic	$	0.01	$	(0.15	)	$	(1.03	)	$	(0.11	)
Diluted	$	0.01	$	(0.15	)	$	(1.03	)	$	(0.11	)

(1) Quarterly earnings per common share are based on the weighted average number of shares outstanding during the quarter, and the sum of the quarters may not equal annual earnings per common share.

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NOTE 25.   CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

Our Senior Notes are guaranteed by virtually all of our domestic subsidiaries, all of which are wholly-owned. The guarantees were joint and several, full, complete and unconditional. There were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company.

As a result of these guarantee arrangements, we are required to present the following condensed consolidating financial information.

CONDENSED CONSOLIDATING BALANCE SHEETS

	December 31, 2010
	Parent		Guarantor		Non-Guarantor
	Company		Subsidiaries		Subsidiaries			Eliminations			Consolidated
	(In thousands)
Assets:
Current assets	$	20,287	$	287,244	$	106,489		$	—		$	414,020
Property and equipment, net		—		861,041		75,703			—			936,744
Goodwill		—		418,047		29,562			—			447,609
Deferred financing costs, net		7,806		—		—			—			7,806
Intercompany notes and accounts receivable and investment in subsidiaries		2,110,185		757,657		(6,226	)		(2,861,616	)		—
Other assets		5,234		56,954		24,569			—			86,757
TOTAL ASSETS	$	2,143,512	$	2,380,943	$	230,097		$	(2,861,616	)	$	1,892,936
Liabilities and equity:
Current liabilities		77,144		142,962		61,529			—			281,635
Long-term debt and capital leases, less current portion		425,000		2,116		5			—			427,121
Intercompany notes and accounts payable		587,801		1,738,214		120,410			(2,446,425	)		—
Deferred tax liabilities		70,511		73,790		8			—			144,309
Other long-term liabilities		1,253		56,815		—			—			58,068
Equity		981,803		367,046		48,145			(415,191	)		981,803
TOTAL LIABILITIES AND EQUITY	$	2,143,512	$	2,380,943	$	230,097		$	(2,861,616	)	$	1,892,936

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	December 31, 2009
	Parent		Guarantor		Non-Guarantor
	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		—		537			—			10,958
Intercompany notes, accounts receivable and investment in subsidiaries		1,782,002		577,546		7,462			(2,367,010	)		—
Other assets		4,033		40,198		14,379			—			58,610
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 STATEMENTS OF OPERATIONS

	Year Ended December 31, 2010
				Guarantor			Non-Guarantor
	Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	1,009,261		$	198,005		$	(53,582	)	$	1,153,684
Costs and expenses:
Direct operating expense		—			664,387			212,195			(41,570	)		835,012
Depreciation and amortization expense		—			127,550			9,497			—			137,047
General and administrative expense		3,618			173,274			25,517			(4,138	)		198,271
Interest expense, net of amounts capitalized		44,707			(3,390	)		642			—			41,959
Other, net		(1,243	)		(1,404	)		9,161			(9,211	)		(2,697	)
Total costs and expenses, net		47,082			960,417			257,012			(54,919	)		1,209,592
(Loss) income from continuing operations before taxes		(47,082	)		48,844			(59,007	)		1,337			(55,908	)
Income tax benefit		8,175			—			12,337			—			20,512
(Loss) income from continuing operations		(38,907	)		48,844			(46,670	)		1,337			(35,396	)
Discontinued operations		—			105,745			—			—			105,745
Net (loss) income		(38,907	)		154,589			(46,670	)		1,337			70,349
Loss attributable to noncontrolling interest		—			—			(3,146	)		—			(3,146	)
(LOSS) INCOME ATTRIBUTABLE TO KEY	$	(38,907	)	$	154,589		$	(43,524	)	$	1,337		$	73,495

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	Year Ended December 31, 2009
				Guarantor			Non-Guarantor
	Parent Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	805,673		$	201,507		$	(51,481	)	$	955,699
Costs and expenses:
Direct operating expense		—			549,597			164,243			(37,898	)		675,942
Depreciation and amortization expense		—			142,086			7,147			—			149,233
General and administrative expense		(452	)		153,870			18,693			29			172,140
Asset retirements and impairments		—			96,768			267			—			97,035
Interest expense, net of amounts capitalized		42,671			(3,420	)		154			—			39,405
Other, net		1,237			(1,412	)		10,412			(11,071	)		(834	)
Total costs and expenses, net		43,456			937,489			200,916			(48,940	)		1,132,921
(Loss) income from continuing operations before taxes		(43,456	)		(131,816	)		591			(2,541	)		(177,222	)
Income tax benefit (expense)		90,694			(25,151	)		431			—			65,974
Income (loss) from continuing operations		47,238			(156,967	)		1,022			(2,541	)		(111,248	)
Discontinued operations		—			(45,428	)		—			—			(45,428	)
Net income (loss)		47,238			(202,395	)		1,022			(2,541	)		(156,676	)
Loss attributable to noncontrolling interest		—			—			(555	)		—			(555	)
INCOME (LOSS) ATTRIBUTABLE TO KEY	$	47,238		$	(202,395	)	$	1,577		$	(2,541	)	$	(156,121	)

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	Year Ended December 31, 2008
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	1,471,094		$	175,845		$	(22,493	)	$	1,624,446
Costs and expenses:
Direct operating expense		—			894,529			127,374			(16,053	)		1,005,850
Depreciation and amortization expense		—			142,090			7,517			—			149,607
General and administrative expense		1,616			226,273			19,251			(795	)		246,345
Asset retirements and impairments		—			26,101			—			—			26,101
Interest expense, net of amounts capitalized		44,842			(2,945	)		477			248			42,622
Other, net		5,219			(7,361	)		9,143			(4,449	)		2,552
Total costs and expenses, net		51,677			1,278,687			163,762			(21,049	)		1,473,077
(Loss) income from continuing operations before taxes		(51,677	)		192,407			12,083			(1,444	)		151,369
Income tax (expense) benefit		(81,233	)		4,023			(4,690	)		—			(81,900	)
(Loss) income from continuing operations		(132,910	)		196,430			7,393			(1,444	)		69,469
Discontinued operations		—			14,344			—			—			14,344
Net (loss) income		(132,910	)		210,774			7,393			(1,444	)		83,813
Loss attributable to noncontrolling interest		—			—			(245	)		—			(245	)
(LOSS) INCOME ATTRIBUTABLE TO KEY	$	(132,910	)	$	210,774		$	7,638		$	(1,444	)	$	84,058

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Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	Year Ended December 31, 2010
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by operating activities	$	—		$	121,551		$	8,254		$	—		$	129,805
Cash flows from investing activities:
Capital expenditures		—			(169,443	)		(10,867	)		—			(180,310	)
Proceeds from sale of fixed assets		—			258,202			—			—			258,202
Acquisitions, net of cash acquired		—			(86,688	)		—			—			(86,688	)
Intercompany notes and accounts		(165	)		(84,742	)		—			84,907			—
Other investing activities, net		165			—			—						165
Net cash (used in) provided by investing activities		—			(82,671	)		(10,867	)		84,907			(8,631	)
Cash flows from financing activities:
Repayments of long-term debt		—			(6,970	)		—			—			(6,970	)
Repayments of capital lease obligations		—			(8,493	)		—			—			(8,493	)
Proceeds from borrowings on revolving credit facility		110,000			—			—			—			110,000
Repayments on revolving credit facility		(197,813	)		—			—			—			(197,813	)
Repurchases of common stock		(3,098	)		—			—			—			(3,098	)
Intercompany notes and accounts		84,742			165			—			(84,907	)		—
Other financing activities, net		6,169			—			—			—			6,169
Net cash used in financing activities		—			(15,298	)		—			(84,907	)		(100,205	)
Effect of changes in exchange rates on cash		—			—			(1,735	)		—			(1,735	)
Net increase (decrease) in cash		—			23,582			(4,348	)		—			19,234
Cash and cash equivalents at beginning of period		—			19,391			18,003			—			37,394
Cash and cash equivalents at end of period	$	—		$	42,973		$	13,655		$	—		$	56,628

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Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Year Ended December 31, 2009
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	—		$	185,279		$	(442	)	$	—		$	184,837
Cash flows from investing activities:
Capital expenditures		—			(124,744	)		(3,678	)		—			(128,422	)
Intercompany notes and accounts		65,580			(17,523	)		(22,115	)		(25,942	)		—
Other investing activities, net		199			5,580			12,007			—			17,786
Net cash provided by (used in) investing activities		65,779			(136,687	)		(13,786	)		(25,942	)		(110,636	)
Cash flows from financing activities:
Payments on revolving credit facility		(100,000	)		—			—			—			(100,000	)
Intercompany notes and accounts		32,823			(76,175	)		17,410			25,942			—
Other financing activities, net		1,398			(28,873	)		—			—			(27,475	)
Net cash (used in) provided by financing activities		(65,779	)		(105,048	)		17,410			25,942			(127,475	)
Effect of changes in exchange rates on cash		—			—			(2,023	)		—			(2,023	)
Net (decrease) increase in cash		—			(56,456	)		1,159			—			(55,297	)
Cash and cash equivalents, beginning of period		—			75,847			16,844			—			92,691
Cash and cash equivalents, end of period	$	—		$	19,391		$	18,003		$	—		$	37,394

114

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Year Ended December 31, 2008
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	17,573		$	364,840		$	(15,249	)	$	—		$	367,164
Cash flows from investing activities:
Capital expenditures		—			(214,659	)		(4,335	)		—			(218,994	)
Acquisitions and asset purchases, net of cash acquired		—			(97,925	)		—			—			(97,925	)
Investment in Geostream Services Group		(19,306	)		—			—			—			(19,306	)
Intercompany notes and accounts		(179,501	)		(199,428	)		(1,515	)		380,444			—
Other investing activities, net		—			7,151			—			—			7,151
Net cash (used in) provided by investing activities		(198,807	)		(504,861	)		(5,850	)		380,444			(329,074	)
Cash flows from financing activities:
Borrowings on revolving credit facility		172,813			—			—			—			172,813
Payments on revolving credit facility		(38,026	)		—			—			—			(38,026	)
Repurchases of common stock		(139,358	)		—			—			—			(139,358	)
Intercompany notes and accounts		177,698			181,016			21,730			(380,444	)		—
Other financing activities, net		8,107			(11,506	)		—			—			(3,399	)
Net cash provided by (used in) financing activities		181,234			169,510			21,730			(380,444	)		(7,970	)
Effect of changes in exchange rates on cash		—			—			4,068			—			4,068
Net increase in cash		—			29,489			4,699			—			34,188
Cash and cash equivalents, beginning of period		—			46,358			12,145			—			58,503
Cash and cash equivalents, end of period	$	—		$	75,847		$	16,844		$	—		$	92,691

115

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 26.   SUBSEQUENT EVENTS

In January 2011, we acquired 10 SWD wells from Equity Energy Company for $14.3 million. We accounted for this purchase as an asset acquisition.

On February 14, 2011, we commenced an any and all cash tender offer and consent solicitation with respect to the Senior Notes. The tender offer is scheduled to expire at 12:00 midnight, New York City time on March 14, 2011, unless extended or earlier terminated. Our obligation to accept for purchase and to pay for Senior Notes in the tender offer is conditioned on, among other things, the tender of Senior Notes representing at least a majority of the aggregate principal amount of Senior Notes outstanding on or prior to March 14, 2011 and our having received replacement financing on terms acceptable to us. We intend to fund the repurchase of the Senior Notes, plus all related fees and expenses, from the proceeds of one or more capital markets debt offerings and borrowings under our Senior Secured Credit Facility.

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ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.   CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We maintain a set of disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 (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 required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on such evaluation, our principal executive and financial officers have concluded that our disclosure controls and procedures were effective as of the end of such period.

Management’s Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed 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. Internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting can also be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

A material weakness (as defined in Rule 12b-2 under the Exchange Act) is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

Management conducted an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria described in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway

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Commission. Based on this assessment, management concluded that our internal control over financial reporting was effective as of December 31, 2010.

Our internal control over financial reporting has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report included herein.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during our last fiscal quarter of 2010, that materially affected, or are 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.

ITEM 9B.   OTHER INFORMATION

Not applicable.

PART III

ITEM 10.   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Item 10 is incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2010.

ITEM 11.   EXECUTIVE COMPENSATION

Item 11 is incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2010.

ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Item 12 is incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2010.

ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Item 13 is incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2010.

ITEM 14.   PRINCIPAL ACCOUNTING FEES AND SERVICES

Item 14 is incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2010.

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PART IV

ITEM 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES

The following financial statements and exhibits are filed as part of this report:

1. Financial Statements — See “Index to Consolidated Financial Statements” at Page 48.

2. We have omitted all financial statement schedules because they are not required or are not applicable, or the required information is shown in the financial statements in notes to the financial statements.

3. Exhibits

The Exhibit Index, which follows the signature pages to this report and is incorporated by reference herein, sets forth a list of exhibits to this report.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

By:  /s/  T.M. Whichard III,

T.M. Whichard III,

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

Date: February 25, 2011

POWER OF ATTORNEY

Each person whose signature appears below hereby constitutes and appoints Richard J. Alario and T.M. Whichard III, and each of them, his true and lawful attorney-in-fact and agent, with full powers of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission granting to said attorneys-in-fact, and each of them, full power and authority to perform any other act on behalf of the undersigned required to be done in connection therewith.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in their capacities and on February 25, 2011.

Signature	Title
/s/  Richard J. Alario Richard J. Alario	Chairman of the Board of Directors, President and Chief Executive Officer (Principal Executive Officer)
/s/  T.M. Whichard III T.M. Whichard III	Senior Vice President and Chief Financial Officer (Principal Financial Officer)
/s/  Ike C. Smith Ike C. Smith	Vice President and Controller (Principal Accounting Officer)
/s/  David J. Breazzano David J. Breazzano	Director
/s/  Lynn R. Coleman Lynn R. Coleman	Director
/s/  Kevin P. Collins Kevin P. Collins	Director
/s/  William D. Fertig William D. Fertig	Director

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Signature	Title
/s/  W. Phillip Marcum W. Phillip Marcum	Director
/s/  Ralph S. Michael, III Ralph S. Michael, III	Director
/s/  William F. Owens William F. Owens	Director
/s/  Robert K. Reeves Robert K. Reeves	Director
/s/  Carter A. Ward Carter A. Ward	Director
/s/  J. Robinson West J. Robinson West	Director
/s/  Arlene M. Yocum Arlene M. Yocum	Director

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EXHIBIT INDEX

Exhibit No.	Description
2.1	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 the Company’s Current Report on Form 8-K filed on July 6, 2010, File No. 001-08038.)
2.2	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. (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010, File No. 001-08038)
2.3	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. (Incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010, File No. 001-08038)
2.4	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 the Company’s Current Report on Form 8-K/A filed on October 8, 2010, File No. 001-08038.)
2.5	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 the Company’s Current Report on Form 8-K/A filed on October 8, 2010, File No. 001-08038.)
2.6	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 the Company’s Current Report on Form 8-K/A filed on October 8, 2010, File No. 001-08038.)
3.1	Articles of Restatement of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s 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 the Company’s 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., adopted September 21, 2006. (Incorporated by reference to Exhibit 3.1 of the Company’s 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., adopted November 2, 2007. (Incorporated by reference to Exhibit 3.1 of the Company’s 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 the Company’s 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 the Company’s Current Report on Form 8-K filed on June 10, 2009, File No. 001-08038.)

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Exhibit No.	Description
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 the Company’s Current Report on Form 8-K filed on November 30, 2007, File No. 001-08038.)
4.2	First Supplemental Indenture, dated as of January 22, 2008, among Key Marine Services, LLC, the existing Guarantors and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.5 of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 001-08038.)
4.3	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 the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-08038.)
4.4	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 the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 001-08038.)
10.1†	Key Energy Group, Inc. 1997 Incentive Plan, as an amendment and restatement effective November 17, 1997 of the Key Energy Group, Inc. 1995 Outside Directors Stock Option Plan. (Incorporated by reference to Exhibit B of the Company’s Schedule 14A Proxy Statement filed November 26, 1997, File No. 001-08038.)
10.2†	Form of Restricted Stock Award Agreement under Key Energy Group, Inc. 1997 Incentive Plan. (Incorporated by reference to Exhibit 10.15 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-08038.)
10.3†	The 2006 Phantom Share Plan of Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 001-08038.)
10.4†	Form of Award Agreement under the 2006 Phantom Share Plan of Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 001-08038.)
10.5†	Form of Stock Appreciation Rights Agreement under Key Energy Group, Inc. 1997 Incentive Plan. (Incorporated by reference to Exhibit 99.1 of the Company’s Current Report on Form 8-K dated August 24, 2007, File No. 001-08038.)
10.6†	Form of Non-Plan Option Agreement under Key Energy Group, Inc. 1997 Incentive Plan. (Incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-8 filed on September 25, 2007, File No. 333-146294.)
10.7†	Key Energy Services, Inc. 2007 Equity and Cash Incentive Plan. (Incorporated by Reference to Appendix A of the Company’s Schedule 14A Proxy Statement filed on November 1, 2007, File No. 001-08038.)
10.8†	Form of Nonstatutory Stock Option Agreement under 2007 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.8 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-08038.)
10.9†	Form of Restricted Stock Award Agreement under 2007 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated April 16, 2008, File No. 001-08038.)
10.10†	Key Energy Services, Inc. 2009 Equity and Cash Incentive Plan. (Incorporated by Reference to Appendix A of the Company’s Schedule 14A Proxy Statement filed on April 16, 2009, File No. 001-08038.)
10.11†	Form of Restricted Stock Award Agreement under 2009 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 001-08038.)

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Exhibit No.	Description
10.12†	Form of Nonqualified Stock Option Agreement under 2009 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 001-08038.)
10.13†	Restated Employment Agreement, dated effective as of December 31, 2007, among Richard J. Alario, Key Energy Services, Inc. and Key Energy Shared Services, LLC. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on January 7, 2008, File No. 001-08038.)
10.14†	Employment Agreement, dated as of March 26, 2009, by and between Trey Whichard and Key Energy Shared Services, LLC. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated April 1, 2009, File No. 001-08038.)
10.15†	Restated Employment Agreement, dated effective as of December 31, 2007, among Newton W. Wilson III, Key Energy Services, Inc. and Key Energy Shared Services, LLC. (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed on January 7, 2008, File No. 001-08038.)
10.16†	Amended and Restated Employment Agreement, dated October 22, 2008, between Kimberly R. Frye, Key Energy Services, Inc. and Key Energy Shared Services, LLC. (Incorporated by reference to Exhibit 10.14 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-08038.)
10.17†	Restated Employment Agreement dated effective as of December 31, 2007, among Kim B. Clarke, Key Energy Services, Inc. and Key Energy Shared Services, LLC (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K filed on January 7, 2008, File No. 001-08038.)
10.18†	Amended and Restated Employment Agreement, dated December 31, 2007, between Key Energy Services, Inc. and Don D. Weinheimer. (Incorporated by reference to Exhibit 10.19 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 filed on February 28, 2008, File No. 001-08038.)
10.19†	Employment Agreement, dated August 14, 2007, between Key Energy Shared Services, LLC and J. Marshall Dodson. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007, File No. 001-08038.)
10.20†	Form of Amendment to Employment Agreement, in the form executed on March 29, 2010, by and between Key Energy Services, Inc., Key Energy Shared Services, LLC, and each of Richard J. Alario, T.M. Whichard III, Newton W. Wilson III, Kim B. Clarke and Kim R. Frye. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated April 1, 2010, File No. 001-08038.)
10.21	Credit Agreement, dated as of November 29, 2007, among Key Energy Services, Inc., each lender from time to time party thereto, Bank of America, N.A., as Paying Agent, Co-Administrative Agent, Swing Line Lender and L/C Issuer, and Wells Fargo Bank, National Association, as Co-Administrative Agent, Swing Line Lender and L/C Issuer. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on November 30, 2007, File No. 001-08038.)
10.22	Amendment No. 1 to Credit Agreement, dated as of October 27, 2009, among Key Energy Services, Inc., each lender from time to time party thereto, Bank of America, N.A., as Paying Agent, Co-Administrative Agent, Swing Line Lender and L/C Issuer, and Wells Fargo Bank, National Association, as Co-Administrative Agent, Swing Line Lender and L/C Issuer. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on October 29, 2009, File No. 001-08038.)
10.23	Master Agreement, dated August 26, 2008, by and among Key Energy Services, Inc., Key Energy Services Cyprus Ltd., OOO Geostream Assets Management and L-Group. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on September 2, 2008, File No. 001-08038.)

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Exhibit No.	Description
10.24	Amendment to Master Agreement, dated March 11, 2009, by and among Key Energy Services, Inc., Key Energy Services Cyprus Ltd., OOO Geostream Assets Management and L-Group. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on March 25, 2009, File No. 001-08038.)
10.25	Amendment No. 2 to Master Agreement, dated June 23, 2009 (fully executed on June 26, 2009), by and among Key Energy Services, Inc., Key Energy Services Cyprus Ltd., OOO Geostream Assets Management and L-Group. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on July 1, 2009, File No. 001-08038.)
10.26	Master Equipment Purchase and Sale Agreement, dated September 1, 2009, by and between Key Energy Pressure Pumping Services, LLC and GK Drilling Tools Leasing Company Ltd., and form of Addendum thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on September 8, 2009, File No. 001-08038.)
10.27	Asset Purchase Agreement, dated May 13, 2010, by and among Key Energy Services, LLC, a Texas limited liability company, Key Marine Services, LLC, a Delaware limited liability company, Moncla Companies, L.L.C., a Texas limited liability company, and Moncla Marine, L.L.C., a Louisiana limited liability company, L. Charles Moncla, Jr., Moncla Family Partnership, Ltd., L. Charles Moncla, Jr. Charitable Remainder Trust, Michael Moncla, Matthew Moncla, Marc Moncla, Christopher Moncla, Bipin A. Pandya, Thomas Sandahl, Rhonda Moncla, Cain Moncla, Andrew Moncla, Kenneth Rothstein, Second 4 M Ltd., a Texas limited partnership, and Leon Charles Moncla, Jr., as payment agent. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on May 19, 2010, File No. 001-08038.)
18.1*	Preferability Letter from Grant Thornton, LLP dated February 25, 2011.
21*	Significant Subsidiaries of the Company.
23*	Consent of Independent Registered Public Accounting Firm.
31.1*	Certification of CEO pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. of 2002.
31.2*	Certification of CFO pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification of CEO and CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*	Interactive Data File.

†	Indicates a management contract or compensatory plan, contract or arrangement in which any Director or any Executive Officer participates.
*	Filed herewith.

125

EX-18.1

Exhibit 18.1

February 25, 2011

Board of Directors
Key Energy Services, Inc.
1301 McKinney Street, Suite 1800
Houston, Texas 77010

Dear Directors:

We are providing this letter solely for inclusion as an exhibit to Key Energy Services, Inc.’s (the “Company”) Form 10-K filing pursuant to Item 601 of Regulation S-K.

We have audited the consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010, as set forth in our report dated February 25, 2011. As stated in Note 1 to those financial statements, the Company changed the date of its annual goodwill impairment assessment for its Russian reporting unit from September 30 to December 31. Note 1 also states management’s belief that the newly adopted method of applying an accounting principle is preferable in the circumstances because December 31 coincides with the Company’s planning and budgeting process, which will allow it to utilize updated forecasts in the discounted cash flow models that are used in the determination of the fair value of the reporting unit.

With regard to the aforementioned accounting change, it should be understood that authoritative criteria have not been established for evaluating the preferability of one acceptable method of accounting over another acceptable method and, in expressing our concurrence below, we have relied on management’s business planning and judgment and on management’s determination that this change in accounting principle is preferable.

Based on our reading of management’s stated reasons and justification for this change in accounting principle in the Form 10-K, and our discussions with management as to their judgment about the relevant business planning factors relating to the change, we concur with management that the newly adopted method of accounting is preferable in the Company’s circumstances.

Very truly yours,

/s/ GRANT THORNTON LLP

EX-21

Exhibit 21

KEY ENERGY SERVICES, INC. — SUBSIDIARIES LIST

The following is a list of the significant subsidiaries of Key Energy Services, Inc. showing the place of incorporation or organization and the names under which each subsidiary does business. The names of certain subsidiaries are omitted as such subsidiaries, considered as a single subsidiary, would not constitute a significant subsidiary.

Subsidiary/Doing Business As(1)	State of Incorporation/Organization
Key Energy Services, LLC	Texas
Key Energy Services California, Inc.	Texas
Key Energy Services, S.A.	Argentina
Key Energy Services de Mexico S. De R.L. De C.V.	Mexico

(1) Effective December 31, 2010, the Company performed an internal reorganization via merger of certain of its subsidiary entities.

126

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our reports dated February 25, 2011, with respect to the consolidated financial statements and internal control over financial reporting included in the Annual Report of Key Energy Services, Inc. on Form 10-K for the year ended December 31, 2010. We hereby consent to the incorporation by reference of said reports in the Registration Statements of Key Energy Services, Inc. on Forms S-8 (File No. 333-146293, effective September 25, 2007, File No. 333-146294, effective September 25, 2007, File No. 333-150098, effective April 4, 2008 and File No. 333-159794, effective June 5, 2009), and on Form S-3ASR (File No. 333-171322, effective December 21, 2010).

/s/  GRANT THORNTON LLP

Houston, Texas

February 25, 2011

127

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Richard J. Alario, certify that:

1. I have reviewed this annual report on Form 10-K 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 (the registrant’s fourth fiscal quarter in the case of an annual report) 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 the 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.

By:  /s/  Richard J. Alario

Richard J. Alario,

President and Chief Executive Officer

(Principal Executive Officer)

Date: February 25, 2011

128

EX-31.2

Exhibit 31.2

CERTIFICATION

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

1. I have reviewed this annual report on Form 10-K 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 (the registrant’s fourth fiscal quarter in the case of an annual report) 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 the 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.

By:  /s/  T. M. Whichard III

T. M. Whichard III,

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

Date: February 25, 2011

132

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 the Sarbanes-Oxley Act of 2002, to such officer’s knowledge that:

(1) the accompanying Annual Report on Form 10-K for the period ending December 31, 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 the dates and for the periods expressed in the Report.

/s/  Richard J. Alario

Richard J. Alario,

President and Chief Executive Officer

(Principal Executive Officer)

Dated: February 25, 2011

/s/  T. M. Whichard III

T. M. Whichard III,

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

Dated: February 25, 2011

133