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, 2011

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

Commission file number 001-08038

KEY ENERGY SERVICES, INC.

(Exact name of registrant as specified in its charter)

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

1301 McKinney Street

Suite 1800

Houston, Texas 77010

(Address of principal executive offices, 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  ¨

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  ¨         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  ¨

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  ¨

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 ¨	Non-accelerated filer ¨	Smaller reporting company ¨
	(Do not check if a smaller reporting company)

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

The aggregate market value of the common stock of the registrant held by non-affiliates as of June 30, 2011, based on the $18.00 per share closing price for the registrant’s common stock as quoted on the New York Stock Exchange on such date, was $2.2 billion (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 22, 2012, the number of outstanding shares of common stock of the registrant was 151,345,723.

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 2012 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, 2011

INDEX

		Page Number
	PART I
ITEM 1.	Business		4
ITEM 1A.	Risk Factors		10
ITEM 1B.	Unresolved Staff Comments		19
ITEM 2.	Properties		19
ITEM 3.	Legal Proceedings		20
ITEM 4.	Mine Safety Disclosures		20
	PART II
ITEM 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		21
ITEM 6.	Selected Financial Data		24
ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		25
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk		50
ITEM 8.	Financial Statements and Supplementary Data		52
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

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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,” “should,” “predicts,” “expects,” “believes,” “anticipates,” “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) a Maryland corporation, 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” in this report 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, 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 we have operations in Mexico, Colombia, the Middle East, Russia and Argentina. In addition, we have a technology development and control systems business 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 revised our reportable business segments as of the first quarter of 2011. The revised operating segments are U.S. and International. We also have a “Functional Support” segment associated with managing each of our reportable operating segments. Financial results as of and for the years ended December 31, 2010 and 2009 have been restated to reflect the change in operating segments. We revised our segments to reflect changes in management’s resource allocation and performance assessment in making decisions regarding our business. Our domestic rig services, fluid management services, fishing and rental services, and intervention services are now aggregated within our U.S. reportable segment. Our international rig services business and our Canadian technology development group are now aggregated within our International reportable segment. 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.

U.S. Segment

Rig Services

Our rig-based services include the completion of newly drilled wells, workover and recompletion of existing oil and natural gas wells, well maintenance, and the 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 rigs that are capable of providing conventional and horizontal drilling services. Our rigs encompass 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 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 completion and recompletion services provided with our rigs prepare a newly drilled well, or a well that was recently extended through a workover, for production. The completion process may involve selectively perforating the well casing to access production zones, stimulating and testing these zones, and installing tubular and downhole equipment. We typically provide a well service rig and may also provide other equipment to assist in the completion process. The completion process usually takes a few days to several weeks, depending on the nature of the completion.

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

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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.

The maintenance services that we provide with our rig fleet are generally required throughout the life cycle of an oil or natural gas well. Examples of these maintenance 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.

Our rig fleet is also used in the process of permanently shutting-in oil or natural gas wells that are at the end of their productive lives. 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., Superior Energy Services (Complete Production Services), Forbes Energy Services Ltd. and Pioneer Drilling Company. Numerous smaller companies also compete in our rig-based markets in the United States.

Fluid Management Services

We provide fluid management services, including oilfield fluid 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 used for temporary storage of fluids associated with fluid hauling operations. In addition, we provide equipment trucks that are used to move large pieces of equipment from one well site to the next, and we operate a fleet of hot oilers capable of pumping heated fluids used to clear soluble restrictions in a wellbore.

Fluid hauling trucks are utilized in connection with drilling, completions, workover and maintenance activities, which tend to use large amounts of various fluids. In connection with these activities 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 saltwater disposal (“SWD”) wells owned by us or a third party. 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, Superior Energy Services (Complete Production Services), Nabors Industries and Stallion Oilfield Services Ltd. Numerous smaller companies also compete in the fluid management services market in the United States.

Intervention Services

Our intervention services line of business includes our coiled tubing, pumping and nitrogen service offerings. Coiled tubing services involve the use of a continuous metal pipe spooled onto a large reel which is then deployed into oil and natural gas wells to perform various applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, and formation stimulations utilizing acid and chemical treatments. Coiled tubing is also used for a number of horizontal well applications such as logging and perforating tool conveyance, milling temporary isolation plugs that separate frac zones, and various other pre- and post- hydraulic fracturing well preparation services.

Our coiled tubing operations consist of both small diameter conventional units (less than two inches in diameter) and large diameter units (two inches or greater in diameter). Nearly two-thirds of our fleet are long-

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lateral capable units, including several extended-reach capable units, all of which have become important tools in horizontal well completions. Historically, coiled tubing was limited to remedial work such as wellbore washout and acid placement. Long-lateral coiled tubing units are used in the horizontal well applications. 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 our international customers also may request such technology.

Our primary competitors in the coiled tubing services market include: Schlumberger Ltd., Baker Hughes Incorporated, Halliburton Company and Superior Energy Services. Numerous smaller companies also compete in our intervention 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, tubulars, handling tools (including our patented Hydra-Walk^® pipe-handling units and services), pressure-control equipment, pumps, power swivels, reversing units and foam air units.

As a result of our acquisition of Edge Oilfield Services, LLC and Summit Oilfield Services, LLC (collectively, “Edge”) in August 2011, our rental inventory also includes frac stack equipment used to support hydraulic fracturing operations and the associated flowback of frac fluids, proppants, oil and natural gas. We also provide well testing services.

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.

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

International Segment

Our international segment includes operations in Mexico, Colombia, the Middle East, Russia and Argentina. Services in these locations include rig-based services such as the maintenance, workover, and recompletion of existing oil wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives. We also provide drilling services in some of the regions where we work and we provide engineering and consulting services for the development of reservoirs.

Our operations in Mexico consist mainly of workover, wireline, project management and consulting services. We generate significant revenue from our contracts with the Mexican national oil company, Petróleos Mexicanos (“Pemex”). In Mexico, San Antonio International, Weatherford International Ltd. and Forbes Energy Services are our largest competitors.

In Argentina, our operations consist of drilling and workover services. In Argentina, we believe our major competitors are San Antonio International (formerly Pride International), Nabors Industries and DLS.

In Colombia, we provide workover services. Our major competitors in Colombia are San Antonio International, Independence, Petroworks and Estrella International.

In Russia, we provide drilling, workover, and reservoir engineering services. Our Russian operations are structured as a 50/50 joint venture in which we have a controlling financial interest. In Russia, our major competitors are Weatherford International and Integra Technologies Inc.

In the Middle East, we formed a joint venture in the first quarter of 2010 in which we have a controlling financial interest. Our operations in the Middle East consist mainly of workover services in the Kingdom of Bahrain. Our largest competitors in the Middle East are Weatherford International, Nabors Industries and MB Petroleum Services.

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Also included in our International segment is our technology development and control systems business based in Canada. This business is focused on the development of software related to oilfield service equipment controls, data acquisition and digital information flow.

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 years ended December 31, 2011 and 2010, no single customer accounted for more than 10% of our consolidated revenues. During the year ended December 31, 2009, 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.

Receivables outstanding from Pemex were approximately 10% of our total accounts receivable as of December 31, 2011. No single customer accounted for more than 10% of our total accounts receivable as of December 31, 2010. Pemex accounted for approximately 25% of our total accounts receivable as of December 31, 2009. No other customers accounted for more than 10% of our total accounts receivable as of December 31, 2011 and 2009.

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 our proprietary 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 our 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, 2011, we employed approximately 8,000 persons in our United States operations and approximately 2,400 additional persons in Mexico, Colombia, Argentina and Canada. Additionally, our joint ventures in Russia and the Middle East in which we own a controlling interest employed approximately 350 persons as of December 31, 2011. 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 our Pemex contracts.

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 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.

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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 (“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;

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

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• 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 operations;

• political instability in oil and natural gas producing countries;

• 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.

Spending by exploration and production companies can also be impacted by conditions in the capital markets. Limitations on the availability of capital, or higher costs of capital, for financing expenditures may cause exploration and production companies to make additional reductions to capital budgets in the future even if oil prices remain at current levels or natural gas prices increase from current levels. Any such cuts in spending will curtail drilling programs as well as discretionary spending on well services, which may result in a reduction in the demand for our services, the rates we can charge and the utilization of our assets. 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. 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. Additionally, during periods of increased market

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demand, a significant amount of new service capacity, including new well service rigs, fluid hauling trucks, 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. During such periods, our labor costs could increase at a greater rate than our ability to raise prices for our services. Also, we may not be able to successfully increase prices without adversely affecting our activity levels. 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.

We participate in a capital-intensive industry. We may not be able to finance future growth of our operations or future acquisitions.

Our activities require substantial capital expenditures. If our cash flow from operating activities and borrowings under our revolving bank credit facility are not sufficient to fund our capital expenditure budget, we would be required to fund these expenditures through debt or equity or alternative financing plans, such as:

• refinancing or restructuring our debt;

• selling assets; and/or

• reducing or delaying acquisitions or capital investments, such as acquisitions of additional revenue generating equipment and refurbishments of our rigs and related equipment.

However, if debt and equity capital or alternative financing plans are not available or are not available on economically attractive terms, we would be required to curtail our capital spending, and our ability to grow our business and sustain or improve our profits may be adversely affected. Our ability to refinance or restructure our debt will depend on the condition of the capital markets and our financial condition at such time, among other things. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis or to satisfy our liquidity needs would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. Any of the foregoing consequences could materially and adversely affect our business, financial condition, results of operations and prospects.

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, and which can increase our labor costs or subject us to liabilities to our employees. 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

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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.

Historically, we have experienced periods of low demand for our services and have incurred operating losses. 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;

• 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. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. 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 operate in a highly competitive industry, with intense price competition, which may intensify as our competitors expand their operations.

The market for oilfield services in which we operate is highly competitive. Contracts are traditionally awarded on the basis of competitive bids or direct negotiations with customers. The principal competitive factors in our markets are product and service quality and availability, responsiveness, experience, technology, equipment quality, reputation for safety and price. The competitive environment has intensified as recent mergers among exploration and production companies have reduced the number of available customers. The fact that drilling rigs and other vehicles and pieces of oilfield services equipment are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry. We may be competing for work against competitors that may be better able to withstand industry downturns and may be better suited to compete on the basis of price, retain skilled personnel and acquire new equipment and technologies, all of which could affect our revenues and profitability.

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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 and Argentina, and we own a technology development and control systems business 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.

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

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 may not 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.

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Potential adoption of future state or federal laws or regulations surrounding the hydraulic fracturing process could make it more difficult to complete oil or natural gas wells and could materially and adversely affect our business, financial condition and results of operations.

Many of our customers utilize hydraulic fracturing services during the life of a well. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations underground where water, sand and other additives are pumped under high pressure into the formation. Although we are not a provider of hydraulic fracturing services, many of our services complement the hydraulic fracturing process.

Legislation has been introduced in Congress to provide for broader federal regulation of hydraulic fracturing operations and the reporting and public disclosure of chemicals used in the fracturing process. Additionally, the U.S. Environmental Protection Agency has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the Safe Drinking Water Act and is completing the process of drafting guidance documents related to this newly asserted regulatory authority. If additional levels of regulation or permitting requirements were imposed through the adoption of new laws and regulations, our customers’ business and operations could be subject to delays and increased operating and compliance costs, which could negatively impact the number of active wells in the marketplaces we serve. Therefore, the adoption of future federal, state or municipal laws regulating the hydraulic fracturing process could negatively impact our business.

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.

Our operations pose risks of environmental liability, including leakage from our operations to surface or subsurface soils, surface water or groundwater. Some environmental laws and regulations may impose strict liability, joint and several liability, or both. Therefore, in some situations, we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, third parties without regard to whether we caused or contributed to the conditions. Actions arising under these laws and regulations could result in the shutdown of our operations, fines and penalties, expenditures for remediation or other corrective measures, and claims for liability for property damage, exposure to hazardous materials, exposure to hazardous waste or personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations also may include the assessment of administrative, civil or criminal penalties, revocation of permits, temporary or permanent cessation of operations in a particular location and issuance of corrective action orders. Such claims or sanctions and related costs could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition, results of operations and cash flow. Additionally, an increase in regulatory requirements on oil and natural gas exploration and completion activities could significantly delay or interrupt our operations.

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;

• failure to retain or attract key employees;

• 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, 2011, our ten largest customers made up approximately 47% of our consolidated revenues. In addition, our two largest customers in our International segment made up approximately 65% of our International segment 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.

Various state governments and regional organizations comprising state governments are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as our equipment and operations. At the federal level, the EPA has already made findings and issued regulations that require us to establish and report an inventory of greenhouse gas emissions and that could lead to the imposition of restrictions on greenhouse gas emissions from stationary sources such as ours. Legislative and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the natural gas and oil that we drill for and help produce. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for oil and natural gas.

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New technology may cause us to become less competitive.

The oilfield service industry is subject to the introduction of new drilling and completion techniques and services using new technologies, some of which may be subject to patent protection. As competitors and others use or develop new technologies in the future, we may be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and implement new technologies before we can. We cannot be certain that we will be able to implement new technologies or products on a timely basis or at an acceptable cost. Thus, limits on our ability to effectively use and implement new and emerging technologies may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Conservation measures and technological advances could reduce demand for natural gas and oil.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. Management cannot predict the impact of the changing demand for oil and natural gas services and products, and any major changes may have a material adverse effect on our business, financial condition, results of operations and cash flows.

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.

Our business may not generate sufficient cash flow from operations to service our outstanding indebtedness. In addition, future borrowings may not 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 revolving credit facility.

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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

• 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 may not be able to 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 our senior secured credit facility or indentures, 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 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;

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• set limitations on the removal of directors;

• enable our board of directors 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, storage facilities, truck facilities and sales and administrative offices throughout the geographic regions in which we operate. We also lease temporary facilities to house employees in regions where infrastructure is limited. 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:

Region	Office, Repair  & Service and Other (1)		SWDs, and Brine  and Freshwater Stations (2)		Operational Field Services Facilities (3)
United States
Owned		17		51		82
Leased		60		15		68
International
Owned		—		—		2
Leased		20		—		10
TOTAL		97		66		162

(1) Includes twenty residential properties leased in the United States and fourteen 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 one property 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 leased by Geostream and one leased property in the Middle East.

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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.

Shareholder Derivative Demand

On December 7, 2011, we received a letter on behalf of the Arkansas Public Employees Retirement Systems (“APERS”), stating that APERS is a Key stockholder and alleging that certain of our officers and one director had breached their fiduciary duties, violated internal corporate policies and been unjustly enriched in connection with their oversight and administration of our compliance with health, safety, labor, motor vehicle and other similar laws, rules and regulations to which Key is subject. The letter demands that our board of directors take action against such officers and director to remedy the conduct alleged in the letter and threatens that APERS will commence a shareholder derivative suit on behalf of Key absent action from the board of directors. To our knowledge, no complaint has been filed in connection with the letter. Our board has established a special committee, consisting of independent members of the board, to review and evaluate the allegations made in the letter. The special committee has engaged independent legal counsel to assist it with its review, which is currently underway. Once its review has been completed, the special committee is expected to report its findings to our board of directors and recommend whether or not suit should be filed or what other action, if any, should be taken in response to the allegations in the letter. For additional information on legal proceedings, see “Note 16. Commitments and Contingencies” in “Item 8. Financial Statements and Supplementary Data.”

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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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 22, 2012, there were 766 registered holders of 151,345,723 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, 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, 2011
1st Quarter	$	15.92	$	12.16
2nd Quarter		18.20		14.59
3rd Quarter		20.48		9.09
4th Quarter		15.47		8.70

	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

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.

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The following performance graph compares the performance of our common stock to the PHLX Oil Service Sector Index, 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. In February 2012, Complete Production Services was acquired by Superior Energy Services, 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, 2006 and tracks the return on the investment through December 31, 2011.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*

Among Key Energy Services, Inc., the Russell 2000 Index, the Russell 1000 Index,

the PHLX Oil Service Sector Index, and Peer Group

* $100 invested on 12/31/06 in stock or index, including reinvestment of dividends. Fiscal year ending December 31.

Dividend Policy

There were no dividends declared or paid on our common stock for the years ended December 31, 2011, 2010 and 2009. 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.

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Issuer Purchases of Equity Securities

During the fourth quarter of 2011, we repurchased an aggregate of 11,274 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:

Period	Total Number of Shares Purchased		Weighted Average  Price Paid Per Share(1)		Total Number of  Shares Purchased as Part of Publicly Announced Plans or Programs
October 1, 2011 to October 31, 2011		—	$	—		—
November 1, 2011 to November 30, 2011		6,967	$	14.57		—
December 1, 2011 to December 31, 2011		4,307	$	14.69		—

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

Equity Compensation Plan Information

The following table sets forth information as of December 31, 2011 with respect to equity compensation plans (including individual compensation arrangements) under which our common stock is authorized for issuance:

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants And Rights (a)		Weighted Average Exercise Price of Outstanding Options, Warrants And Rights (b)		Number of Securities  Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (c)
	(in thousands)				(in thousands)
Equity compensation plans approved by stockholders(1)		2,422	$	13.89		1,320
Equity compensation plans not approved by stockholders		—	$	—		—
Total		2,422				1,320

(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.

Sale of Unregistered Securities

During 2011, we issued 81,087 shares of common stock in connection with the exercise of warrants to purchase shares of our common stock. On May 12, 2009, in connection with the settlement of a lawsuit, we issued to two individuals warrants to purchase shares of our 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, 2007 through December 31, 2011 has been derived from our audited financial statements included in “Item 8. Financial Statements and Supplementary Data.” For the years ended December 31, 2007 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,
	2011			2010			2009			2008			2007
	(in thousands, except per share amounts)
REVENUES	$	1,846,883		$	1,153,684		$	955,699		$	1,624,446		$	1,358,327
COSTS AND EXPENSES:
Direct operating expenses		1,197,083			835,012			675,942			1,005,850			791,595
Depreciation and amortization expense		169,604			137,047			149,233			149,607			111,211
General and administrative expenses		238,068			198,271			172,140			246,345			218,637
Asset retirements and impairments		—			—			97,035			26,101			—
Operating income (loss)		242,128			(16,646	)		(138,651	)		196,543			236,884
Loss on early extinguishment of debt		46,451			—			472			—			9,557
Interest expense, net of amounts capitalized		42,543			41,959			39,405			42,622			37,206
Other (income) expense, net		(5,818	)		(2,697	)		(1,306	)		2,552			(5,512	)
Income (loss) from continuing operations before tax		158,952			(55,908	)		(177,222	)		151,369			195,633
Income tax (expense) benefit		(58,297	)		20,512			65,974			(81,900	)		(75,695	)
Income (loss) from continuing operations		100,655			(35,396	)		(111,248	)		69,469			119,938
Income (loss) from discontinued operations, net of tax		—			105,745			(45,428	)		14,344			49,234
Net income (loss)		100,655			70,349			(156,676	)		83,813			169,172
Loss attributable to noncontrolling interest		(806	)		(3,146	)		(555	)		(245	)		(117	)
INCOME (LOSS) ATTRIBUTABLE TO KEY	$	101,461		$	73,495		$	(156,121	)	$	84,058		$	169,289
Earnings (loss) per share from continuing operations attributable to Key:
Basic	$	0.70		$	(0.25	)	$	(0.91	)	$	0.56		$	0.91
Diluted	$	0.69		$	(0.25	)	$	(0.91	)	$	0.56		$	0.90
Earnings (loss) per share from discontinued operations:
Basic	$	—		$	0.82		$	(0.38	)	$	0.12		$	0.38
Diluted	$	—		$	0.82		$	(0.38	)	$	0.11		$	0.37
Earnings (loss) per share attributable to Key:
Basic	$	0.70		$	0.57		$	(1.29	)	$	0.68		$	1.29
Diluted	$	0.69		$	0.57		$	(1.29	)	$	0.67		$	1.27

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	Year Ended December 31,
	2011			2010			2009			2008			2007
	(in thousands, except per share amounts)
Income (loss) from continuing operations attributable to Key:
Income (loss) from continuing operations	$	100,655		$	(35,396	)	$	(111,248	)	$	69,469		$	119,938
Loss attributable to noncontrolling interest		(806	)		(3,146	)		(555	)		(245	)		(117	)
Income (loss) from continuing operations attributable to Key	$	101,461		$	(32,250	)	$	(110,693	)	$	69,714		$	120,055
Weighted Average Shares Outstanding:
Basic		145,909			129,368			121,072			124,246			131,194
Diluted		146,217			129,368			121,072			125,565			133,551

CASH FLOW DATA

	Year Ended December 31,
	2011			2010			2009			2008			2007
	(in thousands)
Net cash provided by operating activities	$	188,305		$	129,805		$	184,837		$	367,164		$	249,919
Net cash used in investing activities		(520,090	)		(8,631	)		(110,636	)		(329,074	)		(302,847	)
Net cash provided by (used in) financing activities		306,084			(100,205	)		(127,475	)		(7,970	)		23,240
Effect of changes in exchange rates on cash		4,516			(1,735	)		(2,023	)		4,068			(184	)

BALANCE SHEET DATA

	Year Ended December 31,
	2011		2010		2009		2008		2007
	(in thousands)
Working capital	$	311,060	$	132,385	$	194,363	$	285,749	$	253,068
Property and equipment, gross		2,224,102		1,832,443		1,647,718		1,635,424		1,403,726
Property and equipment, net		1,210,297		936,744		794,269		898,696		771,002
Total assets		2,599,120		1,892,936		1,664,410		2,016,923		1,859,077
Long-term debt and capital leases, net of current maturities		773,975		427,121		523,949		633,591		511,614
Total liabilities		1,384,489		911,133		921,270		1,156,191		969,828
Equity		1,214,631		981,803		743,140		860,732		889,249
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 potentially 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.”

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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 produce, 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, 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 we have operations in Mexico, Colombia, the Middle East, Russia and Argentina. In addition, we have a technology development and control systems business based in Canada.

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.

We revised our reportable business segments as of the first quarter of 2011. The revised operating segments are U.S. and International. We 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.” Financial results as of and for the years ended December 31, 2010 and 2009 have been restated to reflect the change in operating segments.

Business and Growth Strategies

Focus on Horizontal Well Services

In recent years the number of horizontal wells drilled in the U.S. has increased significantly. Horizontal wells tend to involve a higher degree of service intensity associated with their drilling and completion, and we believe ultimately the maintenance required over their lifetime. To capitalize on this growing market segment we have built and acquired new equipment, including more capable rigs and coiled tubing units, and upgraded existing equipment capable of providing services integral to the completion and maintenance of horizontal wellbores. Additionally, during 2011 we acquired Edge Oilfield Services, LLC and Summit Oilfield Services, LLC (collectively “Edge”), which primarily rents frac stack equipment used to support hydraulic fracturing operations and the associated flowback of frac fluids, proppants, oil and natural gas. Edge increases our higher-end equipment and service offerings associated with horizontal well completion activity. We also expanded all our service offerings into unconventional shale regions where horizontal activity is most prevalent including the Bakken shale, the Eagle Ford shale, and others. We intend to continue our focus on the expansion of horizontal well service offerings in existing markets and 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, particularly in regions of those countries with large legacy oilfields facing production declines. We believe that our experience with domestic mature oilfields and our proprietary technologies, including our KeyView^® system, provides us with the opportunity to compete for new business in foreign markets. We continue to evaluate international expansion opportunities in the regions where we already have a presence as well as other regions.

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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. We also seek to acquire technologies, assets and businesses that represent a good operational, strategic, and/or synergistic fit with our existing service offerings. For example, our recent acquisition of Edge complemented our other horizontal well service offerings. Likewise, our acquisition of OFS Energy Services, LLC (“OFS”) in 2010 and other coiled tubing asset acquisitions enabled us to further expand our unconventional shale market positioning.

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.

Year	WTI Cushing  Crude Oil(1)		NYMEX Henry Hub Natural Gas(1)		Average Baker  Hughes U.S. Land Drilling Rigs(2)
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
2011	$	94.87	$	4.03		1,846

(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. The following table presents our quarterly rig and trucking hours from 2009 through 2011.

	Rig Hours						Trucking Hours		Key’s U.S. Working Days
	U.S.		International		Total
2011
First Quarter		415,691		109,769		525,460		711,701		64
Second Quarter		426,278		118,639		544,917		776,382		63
Third Quarter		428,236		125,907		554,143		757,550		64
Fourth Quarter		413,052		120,404		533,456		721,411		61
Total 2011:		1,683,257		474,719		2,157,976		2,967,044		252
2010
First Quarter		372,842		112,341		485,183		459,292		63
Second Quarter		396,877		92,291		489,168		518,483		63
Third Quarter		413,052		90,838		503,890		559,181		64
Fourth Quarter		402,187		91,758		493,945		707,616		61
Total 2010:		1,584,958		387,228		1,972,186		2,244,572		251
2009
First Quarter		402,794		87,025		489,819		499,247		63
Second Quarter		331,659		83,861		415,520		416,269		63
Third Quarter		325,839		90,971		416,810		398,027		64
Fourth Quarter		332,327		107,225		439,552		422,253		61
Total 2009:		1,392,619		369,082		1,761,701		1,735,796		251

MARKET CONDITIONS AND OUTLOOK

Market Conditions — Year Ended December 31, 2011

During 2011, overall demand for the services that we provide continued to improve, building on the industry expansion that began in earnest in 2010. The Baker Hughes U.S. rig count data, published weekly, is often used as a coincident indicator of broader oilfield activity. The Baker Hughes U.S. land rig count average for 2011 was 1,846 rigs, up 21.9% compared to the 2010 average of 1,514 rigs. Additionally, the Baker Hughes U.S. oil rig count average for 2011 was 984 rigs, up 66.6% compared to the 2010 average of 591, and the horizontal rig count average for 2011 was 1,074 rigs, up 30.7% compared to the 2010 average of 822.

As a result of the increase in oil prices and the related increase in our customers’ capital spending, our overall activity levels, asset utilization, and prices increased in 2011. As overall market conditions continued to improve in 2011 compared to 2010, we continued to build on the strategic initiatives underway in 2010 in our efforts to generate higher long-term growth and better investment returns. In particular, we continued to increase our investments in higher capability heavy workover and completion rigs, large diameter, extended-reach capable coiled tubing units, fluid transportation vehicles, disposal wells, premium rental drill pipe and service tubing, high pressure, certified blowout preventers, and KeyView^® systems. We continued to focus our investments on growing our market positioning in legacy oil markets and newer unconventional shale oil markets including the Bakken of North Dakota and the Eagle Ford of Texas.

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In furtherance of that investment strategy, we acquired Edge in August 2011. The Edge acquisition added to our premium rental equipment offerings, particularly frac stacks, which are used before, during and after high pressure hydraulic fracturing operations. We also expanded Edge’s frac stack business into the Eagle Ford shale. Additionally, Edge represents our initial foray into production testing services, which is a good operational fit with our other well completion service offerings.

We also expanded our position in Mexico, Colombia, and the Middle East during 2011. In Mexico, we were awarded two $90 million contracts for work in the Aceite Terciario del Golfo (“ATG”) field. The contracts led us to increase our rig count in the country during 2011 with additional rigs planned for the country in 2012, doubling our rig count in the country. In Colombia and Bahrain, we increased our rig count during our first full year of operations in these markets with opportunities for further increases during 2012. In Argentina, our focus remains on improving overall asset utilization and profitability. However, we have begun the process of selling our Argentina operations and expect to close this transaction during 2012. In Russia, we continue to grow our customer base and a stable backlog of projects to improve asset utilization.

Market Outlook

Continued growth in global and domestic oil demand combined with limited global production capacity continues to drive oil prices favorable for continued investment in oil-directed activity in 2012, especially more productive horizontal wells. Despite weak domestic natural gas prices, we believe the strong fundamental oil outlook sets the stage for continued growth in production companies’ capital spending in 2012, both domestically and internationally. If there were a material change in the domestic or global economies in 2012, then the outlook for our business in 2012 and 2013 could change.

We believe our U.S. lines of business will experience continued higher demand and resulting higher overall activity levels in 2012 compared to 2011. In our rig 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.

Our fluids management services 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, 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.

Activity in our intervention services coiled tubing business is driven by new horizontal well completions and the number of producing oil and gas wells in the U.S. We anticipate demand for these services to remain strong in 2012 and beyond, particularly as additional drilling rig and hydraulic fracturing capacity de-bottlenecks growth in well completion activity. Conversely, new coiled tubing equipment deliveries and availability of experienced crews remain a challenge to growth.

Our fishing and rental services business tends to be correlated to the onshore rig count. We anticipate continued moderate-to-strong customer demand growth in 2012, 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 that can enhance our fishing and rental services.

Internationally, we expect to build on the growth experienced in 2011 in Mexico, Colombia and the Middle East with additional investments in each of those areas, supported by expected strong customer demand. We further plan to leverage into our other international operations the reservoir and field development engineering expertise in our Russian business.

Impact of Inflation on Operations

In 2012, we anticipate cost inflation to remain one of our biggest challenges as it was in 2011. 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 2012. 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.

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RESULTS OF OPERATIONS

Consolidated Results of Operations

The following table shows our consolidated results of operations for the years ended December 31, 2011, 2010 and 2009:

	Year Ended December 31,
	2011			2010			2009
	(in thousands, except per share amounts)
REVENUES	$	1,846,883		$	1,153,684		$	955,699
COSTS AND EXPENSES:
Direct operating expenses		1,197,083			835,012			675,942
Depreciation and amortization expense		169,604			137,047			149,233
General and administrative expenses		238,068			198,271			172,140
Asset retirements and impairments		—			—			97,035
Operating income (loss)		242,128			(16,646	)		(138,651	)
Loss on early extinguishment of debt		46,451			—			472
Interest expense, net of amounts capitalized		42,543			41,959			39,405
Other income, net		(5,818	)		(2,697	)		(1,306	)
Income (loss) from continuing operations before tax		158,952			(55,908	)		(177,222	)
Income tax (expense) benefit		(58,297	)		20,512			65,974
Income (loss) from continuing operations		100,655			(35,396	)		(111,248	)
Income (loss) from discontinued operations, net of tax		—			105,745			(45,428	)
Net income (loss)		100,655			70,349			(156,676	)
Loss attributable to noncontrolling interest		(806	)		(3,146	)		(555	)
INCOME (LOSS) ATTRIBUTABLE TO KEY	$	101,461		$	73,495		$	(156,121	)

Year Ended December 31, 2011 and 2010

For the year ended December 31, 2011, income was $101.5 million, compared to $73.5 million for the year ended December 31, 2010. Income for 2011 was $0.69 per diluted share compared to $0.57 per diluted share for 2010. Income and income per share during 2011 was impacted by our loss on the extinguishment of debt. Also, our 2010 results included the gain on the sale of our pressure pumping and wireline businesses on October 1, 2010.

Revenues

Our revenues for the year ended December 31, 2011 increased $693.2 million, or 60.1% to $1.85 billion from $1.15 billion for the year ended December 31, 2010 as a result of increased activity and improved pricing compared to 2010, domestic and international growth, as well as the revenue contribution of acquisitions completed during 2011 and in the fourth quarter of 2010. See “Segment Operating Results — Year Ended December 31, 2011 and 2010” below for a more detailed discussion of the change in our revenues.

Direct operating expenses

Our direct operating expenses increased $362.1 million, or 43.4%, to $1.2 billion (64.8% of revenues) for the year ended December 31, 2011, compared to $835.0 million (72.4% of revenues) for the year ended December 31, 2010 as a direct result of increased business activity as well as inflation in our operating costs. See “Segment Operating Results — Year Ended December 31, 2011 and 2010” below for a more detailed discussion of the change in our direct operating expenses.

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Depreciation and amortization expense

Depreciation and amortization expense increased $32.6 million, or 23.8%, to $169.6 million (9.2% of revenue) for the year ended December 31, 2011, compared to $137.0 million (11.9% of revenue) for the year ended December 31, 2010. The increase is primarily attributable to the increase in our fixed asset base through our acquisitions during 2011 and the fourth quarter of 2010, as well as increased capital expenditures in 2011.

General and administrative expenses

General and administrative expenses increased $39.8 million, or 20.1%, to $238.1 million (12.9% of revenues) for the year ended December 31, 2011, compared to $198.3 million (17.2% of revenues) for the year ended December 31, 2010. Our general and administrative expenses increased due to an increase in employee compensation resulting from the rescission of temporary employee compensation and benefit reductions late in 2010 as well as increased headcount due to our growth.

Loss on early extinguishment of debt

Loss on early extinguishment of debt was $46.5 million for the year ended December 31, 2011, compared to zero for the same period in 2010, due to our tender offer for our 8.375% Senior Notes due 2014 (the “2014 Notes”) and the termination of our prior credit facility during the first quarter of 2011. The loss consisted of the tender premium on the 2014 Notes, as well as transaction fees and the write-off of the unamortized portion of deferred financing costs.

Interest expense, net of amounts capitalized

Interest expense increased $0.6 million to $42.5 million (2.3% of revenues), for the year ended December 31, 2011, compared to $42.0 million (3.6% of revenues) for the same period in 2010. Overall, interest rates on our debt declined during 2011 due to the replacement of the 2014 Notes with our 6.75% Senior Notes due 2021 (the “2021 Notes”) during the first quarter of 2011. However, this rate decline was offset by additional interest expense due to a greater aggregate principal amount outstanding of the 2021 Notes and additional borrowings under our amended 2011 Credit Facility (as defined below) to fund the acquisition of Edge.

Other (income) expense, net

During the year ended December 31, 2011, we recognized other income, net, of $5.8 million, compared to other income, net, of $2.7 million for the year ended December 31, 2010. In April 2011, we sold our equity interest in IROC Energy Services Corp. (“IROC”) and recorded a gain on the sale of $4.8 million during the second quarter of 2011. Our foreign exchange gain relates to an increase in U.S. dollar-denominated transactions in our foreign locations and fluctuations in the strength of the U.S. dollar. The table below presents comparative detailed information about other income, net at December 31, 2011 and 2010:

	Year Ended December 31,
	2011			2010
	(in thousands)
Interest income	$	(26	)	$	(112	)
Foreign exchange gain		(1,784	)		(1,541	)
Gain on sale of equity method investment		(4,783	)		—
Other expense (income), net		775			(1,044	)
Total	$	(5,818	)	$	(2,697	)

Income tax (expense) benefit

Our income tax expense on continuing operations was $58.3 million (36.7% effective rate) on pre-tax income of $159.0 million for the year ended December 31, 2011, compared to an income tax benefit of $20.5

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million (36.7% effective rate) on a pre-tax loss of $55.9 million in 2010. 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

Net income from discontinued operations was zero for the year ended December 31, 2011, compared to $105.7 million for the year ended December 31, 2010. Our discontinued operations in 2010 relate to the sale of our pressure pumping and wireline businesses. For further discussion see “Note 3. Discontinued Operations” in “Item 8. Financial Statements and Supplementary Data.”

Noncontrolling Interest

For the year ended December 31, 2011, we allocated $0.8 million associated with the net loss incurred by our joint ventures to the noncontrolling interest holders of these ventures, compared to $3.1 million for the year ended December 31, 2010.

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 recur in 2010.

Revenues

Our revenues for the year ended December 31, 2010 increased $198.0 million, or 20.7%, to $1.2 billion from $955.7 million 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 lower 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.

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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 related to other assets in our U.S. segment.

Loss on early extinguishment of debt

Loss on early extinguishment of debt was zero for the year ended December 31, 2010, compared to $0.5 million for the same period in 2009. The loss consisted of the write-off of the unamortized portion of deferred financing costs associated with the capacity reduction of the credit facility in the fourth quarter of 2009.

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 our credit facility, combined with lower capitalized interest due to lower capital expenditures related to the construction of equipment.

Other income, net

During the year ended December 31, 2010, we recognized other income, net, of $2.7 million, compared to other income, net, of $1.3 million for the year ended December 31, 2009. The table below presents comparative detailed information about other income, net at December 31, 2010 and 2009:

	Year Ended December 31,
	2010			2009
	(in thousands)
Interest income	$	(112	)	$	(499	)
Foreign exchange gain		(1,541	)		(1,482	)
Other (income) expense, net		(1,044	)		675
Total	$	(2,697	)	$	(1,306	)

Income tax (expense) benefit

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 for the year ended December 31, 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. For further discussion, see “Note 3. Discontinued Operations” in “Item 8. Financial Statements and Supplementary Data.”

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.

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Segment Operating Results

Year Ended December 31, 2011 and 2010

The following table shows operating results for each of our reportable segments for the twelve-month periods ended December 31, 2011 and 2010 (in thousands):

For the year ended December 31, 2011

	U.S.		International		Functional Support			Total
Revenues from external customers	$	1,530,087	$	316,796	$	—		$	1,846,883
Operating expenses		1,172,481		289,523		142,751			1,604,755
Operating income (loss)		357,606		27,273		(142,751	)		242,128

For the year ended December 31, 2010

	U.S.		International			Functional Support			Total
Revenues from external customers	$	961,244	$	192,440		$	—		$	1,153,684
Operating expenses		828,957		215,649			125,724			1,170,330
Operating income (loss)		132,287		(23,209	)		(125,724	)		(16,646	)

U.S.

Revenues for our U.S. segment increased $568.8 million, or 59.2%, to $1.53 billion for the year ended December 31, 2011, compared to $961.2 million for the year ended December 31, 2010. The increase in this segment was due to an increase in activity because of customer spending and improved pricing. During the first quarter of 2011, we implemented price increases for all of our lines of business. We also added new equipment capacity in several growing shale plays, including the Bakken and Eagle Ford. Additionally, acquisitions in the fourth quarter of 2010 and during 2011 contributed to the increase in revenue year over year.

Operating expenses for our U.S. segment were $1.17 billion during the year ended December 31, 2011, which represented an increase of $343.5 million, or 41.4%, compared to $829.0 million for the same period in 2010. The increase was directly attributable to activity and growth increases during the period combined with the impact of inflationary pressure on operating costs, including fuel and wages and the impact of the rescission in late 2010 of temporary cost reduction measures.

International

Revenues for our international segment increased $124.4 million, or 64.6%, to $316.8 million for the year ended December 31, 2011, compared to $192.4 million for the year ended December 31, 2010. The increase for this segment is primarily attributable to our international expansion in the second half of 2010 to Colombia and the Middle East, in addition to a significant activity increase in Mexico.

Operating expenses for our international segment increased $73.9 million, or 34.3%, to $289.5 million for the year ended December 31, 2011, compared to $215.6 million for the year ended December 31, 2010, and increased as a direct result of additional activity growth and a full year of operations in Colombia and the Middle East during the period.

Functional Support

Operating expenses for Functional Support increased $17.0 million, or 13.5%, to $142.8 million (7.7% of consolidated revenues) for the year ended December 31, 2011 compared to $125.7 million (10.9% of consolidated revenues) for the year ended December 31, 2010. The increase in costs relates to the reinstatement in late 2010 of certain employee compensation and benefits that had been suspended in 2009 as part of our cost savings effort.

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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):

For the year ended December 31, 2010

	U.S.		International			Functional Support			Total
Revenues from external customers	$	961,244	$	192,440		$	—		$	1,153,684
Operating expenses		828,957		215,649			125,724			1,170,330
Operating income (loss)		132,287		(23,209	)		(125,724	)		(16,646	)

For the year ended December 31, 2009

	U.S.			International		Functional Support			Total
Revenues from external customers	$	758,363		$	197,336	$	—		$	955,699
Operating expenses		725,044			166,685		105,586			997,315
Asset retirements and impairments		97,035			—		—			97,035
Operating (loss) income		(63,716	)		30,651		(105,586	)		(138,651	)

U.S.

Revenues for our U.S. segment increased $202.9 million, or 26.8%, to $961.2 million for the year ended December 31, 2010, compared to $758.4 million for the year ended December 31, 2009. The increase in this segment was due to the expansion of our coiled tubing services through organic growth and acquisitions, as well as an increase in activity in our fishing and rental operations due to improved economic conditions. Revenue for our fluid management business improved significantly in 2010 due to increased activity in the Bakken Shale market.

Excluding asset retirements and impairments, operating expenses for our U.S. segment were $829.0 million during the year ended December 31, 2010, which represented an increase of $103.9 million, or 14.3%, compared to $725.0 million for the same period in 2009. Although we incurred additional costs attributable to higher activity levels and expansion costs in the U.S., these costs were offset by the impact of temporary cost reduction measures implemented in 2009.

We did not incur any asset retirement and impairment charges during 2010. 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 a pre-tax asset retirement charge of $65.9 million. Also, during the third quarter of 2009, we performed an assessment of the fair value of the other assets in our U.S. segment. The assessment resulted in a pre-tax asset impairment charge of $31.1 million.

International

Revenues for our international segment decreased $4.9 million, or 2.5%, to $192.4 million for the year ended December 31, 2010, compared to $197.3 million for the year ended December 31, 2009. The decrease for this segment was primarily attributable to lower revenues in Mexico due to a decrease in work for Pemex. 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 of 2010. Partially offsetting this decrease was an increase in revenue for Colombia and the Middle East due to our international expansion during the second half of 2010.

Operating expenses for our international segment increased $49.0 million, or 29.4%, to $215.6 million for the year ended December 31, 2010, compared to $166.7 million for the year ended December 31, 2009. The increase was a direct result of start up costs associated with our foreign expansion, severance costs incurred in Mexico due to a decrease in work for Pemex and overall inflation.

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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 the year ended December 31, 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 costs associated with our new ERP system in the second quarter of 2010. Transaction costs incurred in 2010 related to our acquisition of OFS also contributed to the increase.

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 revolving credit facility. We intend to use these sources of liquidity to fund our working capital requirements, capital expenditures, strategic investments and acquisitions.

In 2012, we expect to access available funds under our amended 2011 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 amended 2011 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 amended 2011 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 amended 2011 Credit Facility, committed letters of credit count against our borrowing capacity. As of December 31, 2011, we have $295.0 million in borrowings and $64.3 million of letters of credit outstanding under our amended 2011 Credit Facility, leaving $190.7 million of available borrowing capacity. Subsequent to December 31, 2011, we borrowed an additional $85 million under our amended 2011 Credit Facility to fund capital expenditures.

All obligations under the amended 2011 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, 2011, our adjusted working capital (working capital excluding the current portion of capital lease obligations of $1.7 million) was $312.8 million. Adjusted working capital at December 31, 2010 was $136.4 million, excluding the current portion of capital lease obligations of $4.0 million. Our adjusted working capital at December 31, 2011 increased from 2010 as a result of increased receivables due to activity increases and growth associated with improving market conditions during 2011.

As of December 31, 2011, we had $35.4 million of cash, of which approximately $10.6 million was held in the bank accounts of our foreign subsidiaries. Of this amount, approximately $1.0 million was held by our joint ventures, which are subject to a noncontrolling interest and cannot be repatriated. Less than $0.1 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.

Cash Flows

During the year ended December 31, 2011, we generated cash flows from operating activities of $188.3 million, compared to $129.8 million for the year ended December 31, 2010. These operating cash inflows primarily relate to the income generated during the year, partially offset by the net payment of our income tax obligations from 2010 and an increase in accounts receivable and deposits associated with increased activity.

Cash used in investing activities was $520.1 million and $8.6 million for years ended December 31, 2011 and 2010, respectively. Investing cash outflows relate to increased capital expenditure program in 2011 and cash paid for acquisitions.

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Cash provided by financing activities was $306.1 million during the year ended December 31, 2011, compared to cash used in financing activities of $100.2 million during the year ended December 31, 2010. Financing cash inflows during 2011 consisted primarily of the net borrowings of $295.0 million under our revolving credit facility to fund our acquisition of Edge in August 2011 as well as to fund a portion of our capital expenditures.

The following table summarizes our cash flows for the year ended December 31, 2011 and 2010:

	Year Ended December 31,
	2011			2010
	(in thousands)
Net cash provided by operating activities	$	188,305		$	129,805
Cash paid for capital expenditures		(359,097	)		(180,310	)
Acquisitions, net of cash acquired		(187,058	)		(86,688	)
Proceeds from sale of fixed assets		14,100			258,202
Other investing activities, net		11,965			165
Repayments of capital lease obligations		(4,016	)		(8,493	)
Repayments of long-term debt		(421,427	)		(6,970	)
Payment of bond tender premium		(39,082	)		—
Proceeds from long-term debt		475,000			—
Proceeds from borrowings on revolving credit facility		418,000			110,000
Repayments on revolving credit facility		(123,000	)		(197,813	)
Payment of deferred financing costs		(16,485	)		—
Other financing activities, net		17,094			3,071
Effect of changes in exchange rates on cash		4,516			(1,735	)
Net (decrease) increase in cash and cash equivalents	$	(21,185	)	$	19,234

Debt Service

At December 31, 2011, our annual maturities on our indebtedness, consisting only of our 2014 Notes and 2021 Notes and borrowings under our amended 2011 Credit Facility at year-end, are as follows:

	Principal Payments
	(in thousands)
2012	$	—
2013		—
2014		3,573
2015		—
2016 and thereafter		770,000
Total	$	773,573

We have no maturities of debt in 2012. Interest on our $475.0 million of 2021 Notes is due on March 1 and September 1 of each year. Our 2021 Notes mature on September 1, 2021. Interest on the remaining $3.6 million aggregate principal amount of 2014 Notes outstanding is due on June 1 and December 1 of each year. Our 2014 Notes mature on December 1, 2014. Interest paid on our 2014 Notes and 2021 Notes during 2011 was $22.6 million. Interest on the 2014 Notes and 2021 Notes for 2012 is expected to be $32.4 million. We expect to fund interest payments from cash on hand and cash generated by operations.

8.375% Senior Notes due 2014

On November 29, 2007, we issued $425.0 million aggregate principal amount of our 2014 Notes. On March 4, 2011, we repurchased $421.3 million aggregate principal amount of our 2014 Notes at a purchase price

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of $1,090 per $1,000 principal amount. On March 15, 2011, we repurchased an additional $0.1 million aggregate principal amount at a purchase price of $1,060 per $1,000 principal amount. In connection with the repurchase of the 2014 Notes, we incurred a loss of $44.3 million on the early extinguishment of debt related to the premium paid on the tender, the payment of related fees and the write-off of unamortized loan fees.

6.75% Senior Notes due 2021

On March 4, 2011, we issued $475.0 million aggregate principal amount of our 2021 Notes. Net proceeds, after deducting underwriters’ fees and offering expenses, were $466.0 million. We used the net proceeds to repurchase the 2014 Notes as described above, including accrued and unpaid interest, fees and expenses. We capitalized $10.2 million of financing costs associated with the issuance of the 2021 Notes that will be amortized over the term of the notes.

The 2021 Notes are general unsecured senior obligations and are subordinated to all of our existing and future secured indebtedness. The 2021 Notes are or will be jointly and severally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries.

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

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

At any time and from time to time before March 1, 2014, we may on any one or more occasions redeem up to 35% of the aggregate principal amount of the outstanding 2021 Notes at a redemption price of 106.750% of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cash proceeds from any one or more equity offerings provided that (i) at least 65% of the aggregate principal amount of the 2021 Notes remains outstanding immediately after each such redemption and (ii) each such redemption shall occur within 180 days of the date of the closing of such equity offering.

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

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

• incur additional indebtedness and issue preferred equity interests;

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

• make loans and investments;

• enter into sale and leaseback transactions;

• sell, transfer or otherwise convey assets;

• create liens;

• enter into transactions with affiliates;

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

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• designate future subsidiaries as unrestricted subsidiaries; and

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

These covenants are subject to certain exceptions and qualifications, and contain cross-default provisions relating to the covenants of our 2011 Credit Facility discussed below. Substantially all of the covenants will terminate before the 2021 Notes mature if one of two specified ratings agencies assigns the 2021 Notes an investment grade rating in the future and no events of default exist under the Indenture. As of December 31, 2011, the 2021 Notes were below investment grade. Any covenants that cease to apply to us as a result of achieving an investment grade rating will not be restored, even if the credit rating assigned to the 2021 Notes later falls below investment grade. We were in compliance with all covenants at December 31, 2011.

Senior Secured Credit Facility

On March 31, 2011, we simultaneously terminated (without pre-payment penalty) our $300 million credit agreement dated November 29, 2007, as amended, which was to mature no later than November 29, 2012, and entered into a new credit agreement (the “2011 Credit Facility”) with several lenders and JPMorgan Chase Bank, N.A., as Administrative Agent and Swing Line Lender, Bank of America, N.A., as Syndication Agent, and Capital One, N.A. and Wells Fargo Bank, N.A., as Co-Documentation Agents. The 2011 Credit Facility consists of a revolving credit facility, letter of credit sub-facility and swing line facility, all of which will mature no later than March 31, 2016. In connection with the termination of our previous credit agreement, we incurred a loss of $2.2 million on early extinguishment of debt related to the write-off of the unamortized portion of deferred financing costs.

On July 27, 2011, we entered into the First Amendment to the 2011 Credit Facility (the “Amendment”) with several lenders and JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., as Syndication Agent, and Capital One, N.A., Wells Fargo Bank, N.A., Credit Agricole Corporate and Investment Bank and DnB NOR Bank ASA, as Co-Documentation Agents. The Amendment, which is effective as of July 27, 2011, amends certain provisions of our 2011 Credit Facility. Among other changes, the Amendment increased the total commitments by the lenders under the 2011 Credit Facility from $400.0 million to $550.0 million, effected by an increase in the commitments of certain existing lenders under the facility and the addition of certain new lenders. The Amendment also modifies the 2011 Credit Facility by increasing, from $500.0 million to $650.0 million, the maximum aggregate amount of commitments permitted under the 2011 Credit Facility pursuant to our option to increase commitments by the lenders. The amended 2011 Credit Facility and the obligations thereunder are secured by substantially all of our assets and those of our subsidiary guarantors and are guaranteed by certain of our existing and future domestic subsidiaries.

We capitalized $4.9 million of financing costs in connection with the execution of the 2011 Credit Facility and an additional $1.4 million related to the Amendment that will be amortized over the term of the debt.

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

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

• our ratio of consolidated funded indebtedness to total capitalization be no greater than the percentages specified below;

Fiscal Quarter Ending	Ratio
December 31, 2011 through March 31, 2012		50	%
June 30, 2012 through September 30, 2012		47.5	%
December 31, 2012 and thereafter		45	%

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

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

Fiscal Quarter Ending	Ratio
December 31, 2011 through June 30, 2012		1.85 to 1.00
September 30, 2012 and thereafter		2.00 to 1.00

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

• we limit our capital expenditures and investments in foreign subsidiaries to $250.0 million per fiscal year, if the consolidated total leverage ratio exceeds 3.00 to 1.00.

In addition, the amended 2011 Credit Facility contains certain affirmative and negative covenants, including, without limitation, restrictions on (i) liens; (ii) debt, guarantees and other contingent obligations; (iii) mergers and consolidations; (iv) sales, transfers and other dispositions of property or assets; (v) loans, acquisitions, joint ventures and other investments (with acquisitions permitted so long as, after giving pro forma effect thereto, no default or event of default exists under the 2011 Credit Facility, the pro forma consolidated total leverage ratio does not exceed 4.00 to 1.00, we are in compliance with other financial covenants and we have at least $25.0 million of availability under the 2011 Credit Facility); (vi) dividends and other distributions to, and redemptions and repurchases from, equityholders; (vii) making investments, loans or advances; (viii) selling properties; (ix) prepaying, redeeming or repurchasing subordinated (contractually or structurally) debt; (x) engaging in transactions with affiliates; (xi) entering into hedging arrangements; (xii) entering into sale and leaseback transactions; (xiii) granting negative pledges other than to the lenders; (xiv) changes in the nature of business; (xv) amending organizational documents; and (xvi) changes in accounting policies or reporting practices; in each of the foregoing cases, with certain exceptions.

We were in compliance with these covenants at December 31, 2011. We may prepay the amended 2011 Credit Facility in whole or in part at any time without premium or penalty, subject to certain reimbursements to the lenders for breakage and redeployment costs. As of December 31, 2011, we had borrowings of $295.0 million under the revolving credit facility and $64.3 million of letters of credit outstanding, leaving $190.7 million of available borrowing capacity under the amended 2011 Credit Facility. The weighted average interest rate on the outstanding borrowings under the amended 2011 Credit Facility was 2.78% for the year ended December 31, 2011.

Capital Lease Agreements

We lease equipment, such as vehicles, tractors, trailers, frac tanks and forklifts, from financial institutions under master lease agreements. As of December 31, 2011, there was approximately $2.1 million outstanding under such equipment leases.

Off-Balance Sheet Arrangements

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

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Contractual Obligations

Set forth below is a summary of our contractual obligations as of December 31, 2011. 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
	Total		Less than 1 Year (2012)		1-3 Years (2013-2015)		4-5 Years (2016-2017)		After 5 Years (2018+)
	(in thousands)
8.375% Senior Notes due 2014	$	3,573	$	—	$	3,573	$	—	$	—
6.75% Senior Notes due 2021		475,000		—		—		—		475,000
Interest associated with 8.375% Senior Notes due 2014 and 6.75% Senior Notes due 2021		300,334		24,454		96,779		64,209		114,892
Borrowings under Senior Secured Credit Facility		295,000		—		—		295,000		—
Interest associated with Senior Secured Credit Facility(1)		41,679		5,524		33,019		3,136		—
Commitment and availability fees associated with Senior Secured Credit Facility		4,053		954		2,861		238		—
Capital lease obligations, excluding interest and executory costs		2,096		1,694		402		—		—
Interest and executory costs associated with capital lease obligations(1)		187		130		57		—		—
Non-cancelable operating leases		45,014		20,409		18,428		3,498		2,679
Liabilities for uncertain tax positions		1,767		909		858		—		—
Equity based compensation liability awards(2)		2,968		2,968		—		—		—
Total	$	1,171,671	$	57,042	$	155,977	$	366,081	$	592,571

(1) Based on interest rates in effect at December 31, 2011.

(2) Based on our closing stock price at December 31, 2011.

Debt Compliance

Our 2011 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, 2011, we were in compliance with all the financial covenants under the amended 2011 Credit Facility, our 2014 Notes and 2021 Notes. Based on management’s current projections, we expect to be in compliance with all the covenants under our amended 2011 Credit Facility, 2014 Notes and 2021 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, 2011, our capital expenditures totaled $359.1 million, primarily related to the addition of larger well service rigs, coiled tubing units, fluid transportation equipment, rental equipment including drill pipe and major maintenance of our existing fleet and equipment. Our 2012 capital expenditures program is expected to total approximately $450.0 million, focusing on growth markets in the United States and

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select international regions. Our capital expenditure program for 2012 is subject to market conditions, including activity levels, commodity prices, industry capacity and specific customer needs. Our focus for 2012 will be the maximization of our current equipment fleet, but we may choose to increase our capital expenditures in 2012 to increase market share or expand our presence into a new market. We currently anticipate funding our 2012 capital expenditures through a combination of cash on hand, operating cash flow, and borrowings under our amended 2011 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

Edge

We completed our acquisition of Edge in August 2011. Edge primarily rents frac stack equipment used to support hydraulic fracturing operations and the associated flowback of frac fluids, proppants, oil and natural gas. It also provides well testing services, rental equipment such as pumps and power swivels and oilfield fishing services.

The total consideration for the acquisition was approximately $305.9 million consisting of approximately 7.5 million shares of our common stock and approximately $187.9 million in cash, which included $26.3 million to reimburse Edge for growth capital expenditures incurred between March 1, 2011 and the date of closing, net of working capital adjustments of $1.8 million.

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.

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;

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• 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) collectability 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 field ticket.

• Collectability 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.

Workers’ Compensation, Vehicular Liability and Other Self-Insurance

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, insurance may not be available to cover any or all of these risks, and, if available, we might not be able to obtain such insurance 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.

We estimate our liability arising out of uninsured and 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 are based on the specific facts and circumstances of the insured event and our past experience with similar claims and trend analysis. We adjust loss estimates in the calculation of these accruals based upon actual claim settlements and reported 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. Changes in our assumptions and estimates could potentially have a negative impact on our earnings.

We are largely self-insured against physical damage to our property, rigs, equipment and automobiles due to large deductibles or self-insurance.

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

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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 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.

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.

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

During the fourth quarter of 2011, we adopted the provisions of ASU 2011-08, Intangibles — Goodwill and Other (Topic 350): Testing Goodwill for Impairment. The test for impairment of indefinite-lived intangible assets allows us to first assess the qualitative factors to determine whether it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If our qualitative analysis shows that it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount we will perform the two-step goodwill impairment 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

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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. 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. We conducted our most recent annual test for impairment of our goodwill and other indefinite-lived intangible assets as of December 31, 2011. On that date, our reporting units for the purposes of impairment testing were rig services, fluid management services, intervention services, fishing and rental services and our Russian, Canadian and Argentine reporting units. Our goodwill by reporting unit as of December 31, 2011 is as follows (in thousands, except for percentages):

U.S.
Rig Services	302,571	49	%
Intervention Services	102,799	16	%
Fishing and Rental Services	170,378	27	%
Fluid Management Services	19,301	3	%
Subtotal	595,049	95	%
International
Canada	4,182	1	%
Argentina	661	0	%
Russia	23,542	4	%
Subtotal	28,385	5	%
Total	623,434	100	%

We also have intangible assets that are not amortized of $3.7 million and $8.7 million related to our fishing and rental services reporting unit and our Russian reporting unit, respectively.

We performed our qualitative analysis of goodwill impairment as of December 31, 2011. Based on this analysis, our rig services, fluid management services, coiled tubing services, fishing and rental services and our Canadian reporting unit did not have triggering events that would indicate it was not “more likely than not” that the fair value of these reporting units was higher than the carrying amount. However, we determined it was necessary to perform the first step of the goodwill impairment test for our Russia and Argentine reporting units. 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 step 1, the fair value of our Argentine reporting unit significantly exceeded its carrying value. The fair value of our Russia reporting unit exceeded its carrying value by approximately 13%. 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 Russia, 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. Because the fair value of the reporting units exceeded their carrying values, we determined that no potential for impairment of our goodwill associated with those reporting units existed as of December 31, 2011, and that step two of the 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 2011 annual test indicated that the fair values of the reporting units exceeded their carrying values, and although 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

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were to significantly increase or decrease, or if we were to choose 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 conditions, a significant decrease in benefits being derived from an acquired business, a change in the use of an asset, 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.

During the fourth quarter of 2011, our largest customer in Argentina significantly reduced their business with us and this decline is expected to continue through at least the first half of 2012. We identified this as a trigger event that required us to test our fixed assets in Argentina for impairment. Based on our analysis, the expected undiscounted cash flows for these assets exceeded their carrying value, and no indication of impairment existed, and we do not believe that material adverse changes in our estimates or assumptions which would cause the carrying value of our assets in Argentina to exceed their fair value are reasonably possible. We did not identify any trigger events causing us to test our tangible and finite-lived intangible assets for impairment during the first, second or third quarters of 2011.

Valuation of Equity-Based Compensation

We have granted stock options, stock-settled stock appreciation rights (“SARs”), restricted stock (“RSAs” and “RSUs”), 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 and RSUs 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.

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.

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We did not grant any stock options during the years ended December 31, 2011 and 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 year ended December 31, 2009:

	Year Ended December 31,
	2009
Risk-free interest rate		2.21	%
Expected life of options, years		6
Expected volatility of the Company’s stock price		53.70	%
Expected dividends		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, as we did not have sufficient historical exercise information because of past legal restrictions on the exercise of our stock options. 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 2009-13.    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. As a result of ASU 2009-13, multiple-deliverable arrangements will be separated in more circumstances than under prior guidance. ASU 2009-13 establishes a selling price hierarchy for determining the selling price of a deliverable. The selling price will be based on vendor-specific objective evidence (“VSOE”) 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. 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 the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

ASU 2009-14.    In October 2009, the FASB issued ASU 2009-14, Software (Topic 985) — Certain Revenue Arrangements That Include Software Elements — a consensus of the FASB Emerging Issues Task Force (“ASU 2009-14”). ASU 2009-14 was issued to address concerns relating to the accounting for revenue arrangements that contain tangible products and software that is “more than incidental” to the product as a whole. ASU 2009-14 changes the accounting model for revenue arrangements that include both tangible products and software elements to exclude those where the software components are essential to the tangible products’ core functionality. In addition, ASU 2009-14 also requires that hardware components of a tangible product containing software components always be excluded from the software revenue recognition guidance, and provides guidance on how to determine which software, if any, relating to tangible products is considered essential to the tangible products’ functionality and should be excluded from the scope of software revenue recognition guidance. ASU 2009-14 also provides guidance on how to allocate arrangement consideration to deliverables in an arrangement that contains tangible products and software that is not essential to the product’s functionality. ASU 2009-14 was issued concurrently with ASU 2009-13 and also requires entities to provide the disclosures required by ASU 2009-13

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that are included within the scope of ASU 2009-14. ASU 2009-14 is effective prospectively for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010. Entities may also elect, but are not required, to adopt ASU 2009-14 retrospectively to prior periods, and must adopt ASU 2009-14 in the same period and using the same transition methods that it uses to adopt ASU 2009-13. We adopted the provisions of ASU 2009-14 on January 1, 2011, and the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

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

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

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

ASU 2011-05.    In June 2011, the FASB issued ASU 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. The amendments in this ASU allow an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income

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either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. ASU 2011-05 should be applied retrospectively for interim and annual reporting periods beginning after December 15, 2011 with early adoption permitted. We early adopted the provisions of ASU 2011-05 during the fourth quarter of 2011, and the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

ASU 2011-12.    In December 2011, the FASB issued ASU 2011-12, Deferral of the Effective Date for Amendment to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This ASU defers the guidance on whether to require entities to present reclassification adjustments out of accumulated other comprehensive income by component in both the statement where net income is presented and the statement where other comprehensive income is presented for both interim and annual financial statements. ASU 2011-12 reinstated the requirements for the presentation of reclassifications that were in place prior to the issuance of ASU 2011-05 and did not change the effective date of ASU 2011-05. ASU 2011-12 should be applied consistently with ASU 2011-05; accordingly, this ASU is to be applied retrospectively for interim and annual reporting periods beginning after December 15, 2011, with early adoption permitted. We early adopted the provisions of ASU 2011-12 during the fourth quarter of 2011, and the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

ASU 2011-08.    In September 2011, the FASB issued ASU 2011-08, Intangibles — Goodwill and Other (Topic 350): Testing Goodwill for Impairment. This ASU is intended to simplify how entities, both public and nonpublic, test goodwill for impairment. ASU 2011-08 permits an entity to first assess qualitative factors to determine whether it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in Topic 350, Intangibles – Goodwill and Other. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, with early adoption permitted. We adopted the provisions of ASU 2011-08 during the fourth quarter of 2011, 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 2011-04.    In May 2011, the FASB issued ASU 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This ASU represents the converged guidance of the FASB and the IASB on measuring fair value and for disclosing information about fair value measurements. The amendments in this ASU clarify the Board’s intent about the application of existing fair value measurement and disclosure requirements and changes particular principles or requirements for measuring fair value and for disclosing information about fair value measurements. ASU 2011-04 is effective prospectively for interim and annual reporting periods beginning after December 15, 2011. We adopted the provisions of ASU 2011-04 on January 1, 2012, and the adoption of this standard did 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. Derivative financial instruments were not used in the years ended December 31, 2011, 2010 and 2009. 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.

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Interest Rate Risk

As of December 31, 2011, we had outstanding $475.0 million of 6.75% Senior Notes due 2021 and $3.6 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, 2011, the weighted average interest rate on our outstanding variable-rate debt obligations was 2.72%. A hypothetical 10% increase in that rate would increase the annual interest expense on those instruments by $1.4 million.

Foreign Currency Risk

As of December 31, 2011, we conduct operations in Mexico, Colombia, the Middle East, Russia and Argentina. We also have a Canadian subsidiary. 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 would decrease our net income by approximately $0.8 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, 2011 would increase annual compensation expense recognized on these awards by approximately $0.3 million.

51

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		53
Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting		54
Consolidated Balance Sheets		55
Consolidated Statements of Operations		56
Consolidated Statements of Comprehensive Income (Loss)		57
Consolidated Statements of Cash Flows		58
Consolidated Statements of Stockholders’ Equity		59
Notes to Consolidated Financial Statements		60

52

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, 2011 and 2010, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011. 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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 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, 2011, 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 29, 2012 expressed an unqualified opinion on the effectiveness of internal control over financial reporting.

/s/ GRANT THORNTON LLP

Houston, Texas

February 29, 2012

53

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, 2011, 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 (Management’s Report) appearing in 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. Our audit of, and opinion on, Key Energy Services, Inc. and Subsidiaries internal control over financial reporting does not include internal control over financial reporting of Edge Oilfield Services, L.L.C and Summit Oilfield Services, L.L.C, collectively the “Acquired Companies”, wholly owned subsidiaries, whose combined financial statements reflect total assets and revenues constituting fourteen and three percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2011. As indicated in Management’s Report, the Acquired Companies were acquired during 2011 and therefore, management’s assertion on the effectiveness of the Key Energy Services, Inc and Subsidiaries internal control over financial reporting excluded internal control over financial reporting of the Acquired Companies.

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, 2011, 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 (loss), stockholders’ equity, and cash flows of Key Energy Services, Inc. and Subsidiaries and our report dated February 29, 2012, expressed an unqualified opinion on those consolidated financial statements.

/s/ GRANT THORNTON LLP

Houston, Texas

February 29, 2012

54

Key Energy Services, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

	December 31,
	2011			2010
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	35,443		$	56,628
Accounts receivable, net of allowance for doubtful accounts of $8,082 and $7,791		421,215			261,818
Inventories		33,986			23,516
Prepaid expenses		25,528			20,478
Deferred tax assets		57,100			32,046
Other current assets		27,291			19,534
Total current assets		600,563			414,020
Property and equipment, gross		2,224,102			1,832,443
Accumulated depreciation		(1,013,805	)		(895,699	)
Property and equipment, net		1,210,297			936,744
Goodwill		623,434			447,609
Other intangible assets, net		81,867			58,151
Deferred financing costs, net		14,771			7,806
Deposits		43,692			1,478
Equity method investments		918			5,940
Other assets		23,578			21,188
TOTAL ASSETS	$	2,599,120		$	1,892,936
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	78,837		$	56,310
Accrued liabilities		198,102			217,249
Accrued interest		10,870			4,097
Current portion of capital lease obligations		1,694			3,979
Total current liabilities		289,503			281,635
Capital lease obligations, less current portion		402			2,121
Long-term debt		773,573			425,000
Workers’ compensation, vehicular and health insurance liabilities		30,854			30,110
Deferred tax liabilities		261,072			144,309
Other non-current accrued liabilities		29,085			27,958
Commitments and contingencies
Equity:
Common stock, $0.10 par value; 200,000,000 shares authorized, 150,733,022 and 141,656,426 shares issued and outstanding		15,073			14,166
Additional paid-in capital		915,400			775,601
Accumulated other comprehensive loss		(58,231	)		(51,334	)
Retained earnings		312,114			210,653
Total equity attributable to Key		1,184,356			949,086
Noncontrolling interest		30,275			32,717
Total equity		1,214,631			981,803
TOTAL LIABILITIES AND EQUITY	$	2,599,120		$	1,892,936

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

55

Key Energy Services, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2011			2010			2009
	(in thousands, except per share amounts)
REVENUES	$	1,846,883		$	1,153,684		$	955,699
COSTS AND EXPENSES:
Direct operating expenses		1,197,083			835,012			675,942
Depreciation and amortization expense		169,604			137,047			149,233
General and administrative expenses		238,068			198,271			172,140
Asset retirements and impairments		—			—			97,035
Operating income (loss)		242,128			(16,646	)		(138,651	)
Loss on early extinguishment of debt		46,451			—			472
Interest expense, net of amounts capitalized		42,543			41,959			39,405
Other income, net		(5,818	)		(2,697	)		(1,306	)
Income (loss) from continuing operations before tax		158,952			(55,908	)		(177,222	)
Income tax (expense) benefit		(58,297	)		20,512			65,974
Income (loss) from continuing operations		100,655			(35,396	)		(111,248	)
Income (loss) from discontinued operations, net of tax		—			105,745			(45,428	)
Net income (loss)		100,655			70,349			(156,676	)
Loss attributable to noncontrolling interest		(806	)		(3,146	)		(555	)
INCOME (LOSS) ATTRIBUTABLE TO KEY	$	101,461		$	73,495		$	(156,121	)
Earnings (loss) per share from continuing operations attributable to Key:
Basic	$	0.70		$	(0.25	)	$	(0.91	)
Diluted	$	0.69		$	(0.25	)	$	(0.91	)
Earnings (loss) per share from discontinued operations:
Basic	$	—		$	0.82		$	(0.38	)
Diluted	$	—		$	0.82		$	(0.38	)
Earnings (loss) per share attributable to Key:
Basic	$	0.70		$	0.57		$	(1.29	)
Diluted	$	0.69		$	0.57		$	(1.29	)
Income (loss) from continuing operations attributable to Key:
Income (loss) from continuing operations	$	100,655		$	(35,396	)	$	(111,248	)
Loss attributable to noncontrolling interest		(806	)		(3,146	)		(555	)
Income (loss) from continuing operations attributable to Key	$	101,461		$	(32,250	)	$	(110,693	)
Weighted Average Shares Outstanding:
Basic		145,909			129,368			121,072
Diluted		146,217			129,368			121,072

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

56

Key Energy Services, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
INCOME (LOSS) FROM CONTINUING OPERATIONS	$	100,655		$	(35,396	)	$	(111,248	)
Other comprehensive income (loss), net of tax:
Foreign currency translation loss, net of tax of $(734), $(129), and $(347)		(9,594	)		(831	)		(4,243	)
Deferred gain from available for sale investments, net of tax of $—, $—, and $—		—			—			30
Gain on sale of equity method investment, net of tax of $(410), $—, and $—		1,061			—			—
Total other comprehensive loss, net of tax		(8,533	)		(831	)		(4,213	)
COMPREHENSIVE INCOME (LOSS) FROM CONTINUING OPERATIONS, NET OF TAX		92,122			(36,227	)		(115,461	)
Comprehensive income (loss) from discontinued operations, net of tax		—			105,745			(45,428	)
COMPREHENSIVE INCOME (LOSS)		92,122			69,518			(160,889	)
Comprehensive loss attributable to noncontrolling interest		2,442			3,406			416
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO KEY	$	94,564		$	72,924		$	(160,473	)

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

57

Key Energy Services, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	100,655		$	70,349		$	(156,676	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense		169,604			143,805			169,562
Asset retirements and impairments		—			—			159,802
Bad debt expense		2,559			3,849			3,295
Accretion of asset retirement obligations		594			526			533
(Income) loss from equity method investments		(266	)		(396	)		1,057
Gain on sale of equity method investment		(4,783	)		—			—
Amortization of deferred financing costs and discount		2,150			2,615			2,182
Deferred income tax expense (benefit)		85,792			(12,370	)		(41,257	)
Capitalized interest		(1,735	)		(3,789	)		(4,335	)
(Gain) loss on disposal of assets, net		(3,726	)		(153,822	)		401
Loss on early extinguishment of debt		46,451			—			472
Loss on sale of available for sale investments, net		—			—			30
Share-based compensation		15,609			12,111			6,381
Excess tax benefits from share-based compensation		(4,859	)		(2,069	)		(580	)
Changes in working capital:
Accounts receivable		(152,771	)		(26,448	)		168,824
Other current assets		(22,110	)		36,731			461
Accounts payable and accrued liabilities		3,720			61,671			(126,949	)
Share-based compensation liability awards		385			1,297			646
Other assets and liabilities		(48,964	)		(4,255	)		988
Net cash provided by operating activities		188,305			129,805			184,837
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(359,097	)		(180,310	)		(128,422	)
Proceeds from sale of fixed assets		14,100			258,202			5,580
Acquisitions, net of cash acquired of $886, $539, and $28,362, respectively		(187,058	)		(86,688	)		12,007
Dividend from equity method investments		—			165			199
Proceeds from sale of equity method investment		11,965			—			—
Net cash used in investing activities		(520,090	)		(8,631	)		(110,636	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt		(421,427	)		(6,970	)		(16,552	)
Payment of bond tender premium		(39,082	)		—			—
Proceeds from long-term debt		475,000			—			—
Repayments of capital lease obligations		(4,016	)		(8,493	)		(9,847	)
Proceeds from borrowings on revolving credit facility		418,000			110,000			—
Repayments on revolving credit facility		(123,000	)		(197,813	)		(100,000	)
Payment of deferred financing costs		(16,485	)		—			(2,474	)
Repurchases of common stock		(5,681	)		(3,098	)		(488	)
Proceeds from exercise of stock options and warrants		8,000			4,100			1,306
Excess tax benefits from share-based compensation		4,859			2,069			580
Other financing activities		9,916			—			—
Net cash provided by (used in) financing activities		306,084			(100,205	)		(127,475	)
Effect of changes in exchange rates on cash		4,516			(1,735	)		(2,023	)
Net (decrease) increase in cash and cash equivalents		(21,185	)		19,234			(55,297	)
Cash and cash equivalents, beginning of period		56,628			37,394			92,691
Cash and cash equivalents, end of period	$	35,443		$	56,628		$	37,394

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

58

Key Energy Services, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

	COMMON STOCKHOLDERS															Noncontrolling Interest			Total
	Common Stock						Additional Paid-in Capital			Accumulated Other Comprehensive Loss			Retained Earnings
	Number of Shares			Amount at par
	(in thousands)
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
Other comprehensive loss, net of tax		—			—			—			(7,958	)		—			(1,636	)		(9,594	)
Common stock purchases		(384	)		(39	)		(5,642	)		—			—			—			(5,681	)
Exercise of stock options and warrants		728			73			7,927			—			—			—			8,000
Issuance of shares in acquisition		7,549			755			117,164			—			—			—			117,919
Share-based compensation		1,184			118			15,491			—			—			—			15,609
Tax benefits from share-based compensation		—			—			4,859			—			—			—			4,859
Sale of equity method investment, net of tax		—			—			—			1,061			—			—			1,061
Net income		—			—			—			—			101,461			(806	)		100,655
BALANCE AT DECEMBER 31, 2011		150,733		$	15,073		$	915,400		$	(58,231	)	$	312,114		$	30,275		$	1,214,631

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

59

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, 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 we have operations in Mexico, Colombia, the Middle East, Russia and Argentina. In addition, we have a technology development and control systems business 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 classifications. We revised our reportable business segments effective in the first quarter of 2011, and in connection with the revision, have restated the corresponding items of segment information for all periods presented. The new operating segments are U.S. and International. We revised our segments to reflect changes in management’s resource allocation and performance assessment in making decisions regarding the Company. Our fluid management services, fishing and rental services, intervention services and domestic rig services businesses are aggregated within our U.S. segment. Our international rig services business and our Canadian technology development group are aggregated within our International segment. These changes reflect our current operating focus in compliance with Accounting Standards Codification (“ASC”) No. 280, Segment Reporting (“ASC 280”). 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

60

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

We apply ASC No. 810-10, Consolidation of Variable Interest Entities (revised December 2009) — Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities (“ASU 2009-17”), when determining whether or not to consolidate a Variable Interest Entity (“VIE”). ASC 810-10 requires the reporting entity to have the power to direct the activities of a VIE that most significantly impacts 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. A reporting entity that has these 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 no later than one year from 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) collectability 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 field ticket.

• Collectability 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, 2011, we have not entered into any compensating balance arrangements, but all of our obligations under our amended 2011 Credit Facility (as defined below) with a syndicate of banks of which

61

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

JPMorgan Chase Bank, N.A. is the administrative agent were secured by most of our assets, including assets held by our subsidiaries, which includes our 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, 2011, 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 other 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 collectability 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 other assets, 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 years ended December 31, 2011 and 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.

Receivables outstanding from Pemex were approximately 10% of our total accounts receivable as of December 31, 2011. No single customer accounted for more than 10% of our total accounts receivable as of December 31, 2010. Pemex accounted for approximately 25% of our total accounts receivable as of December 31, 2009. No other customers accounted for more than 10% of our total accounts receivable as of December 31, 2011 and 2009.

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Inventories

Inventories, which consist primarily of equipment parts and spares for use in our 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, 2011, 2010 and 2009 was $148.4 million, $125.8 million and $135.3 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, a gain or loss is recognized.

As of December 31, 2011, the estimated useful lives of our asset classes are as follows:

Description	Years
Well service rigs and components		3-15
Oilfield trucks, vehicles and related equipment		5-10
Well intervention units and equipment		10-12
Fishing and rental tools, tubulars and pressure control equipment		3-10
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 fourth quarter of 2011, we identified a triggering event that required us to test our long-lived assets in Argentina for potential impairment. Based on the results of that test, we determined that our assets in Argentina were not impaired.

We did not identify any triggering events or record any asset impairments during 2010. 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. See “Note 7. Property and Equipment,” for further discussion.

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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.”

Deposits

Due to capacity constraints on equipment manufacturers, we have been required to make advanced payments for certain oilfield service equipment and other items used in the normal course of business. As of December 31, 2011, deposits totaled $43.7 million and consisted mostly of payments made related to high demand long-lead time items for our U.S. and Mexico operations, as well as, equipment deposits related to our recent acquisition of Edge Oilfield Services, LLC and Summit Oilfield Services, LLC (collectively, “Edge”). As of December 31, 2010, deposits totaled $1.5 million and consisted of escrow for workers’ compensation insurance and security deposits for leases.

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. See “Note 15. Long-term Debt,” for further discussion.

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.

During the fourth quarter of 2011, we adopted the provisions of ASU 2011-08, Intangibles — Goodwill and Other (Topic 350): Testing Goodwill for Impairment. The test for impairment of indefinite-lived intangible assets allows us to first assess the qualitative factors to determine whether it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If our qualitative analysis shows that it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount we will perform the two-step goodwill impairment

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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. 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 as of December 31 of each year. For the annual test completed as of December 31, 2011, no impairment of our goodwill was indicated. See “Note 8. Goodwill and Other Intangible Assets,” for further discussion.

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 to seven 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. We conduct business throughout the continental United States and may be subject to jury verdicts or arbitrations that result in outcomes in favor of the plaintiffs. We are also exposed to various claims abroad. 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. 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, restricted stock units, stock appreciation rights (“SARs”), phantom shares and performance units to our employees as part of those employees’ compensation 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

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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 estimated using the simplified method, as we did not 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 SARs 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 at 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 and direct operating expense for the applicable individual. See “Note 20. Share-Based Compensation.”

Foreign Currency Gains and Losses

For our international locations in Argentina, Mexico, Russia 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. See “Note 17. Accumulated Other Comprehensive Loss.”

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, net.

Comprehensive Income

We display comprehensive income (loss) 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” 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

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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 2009-13.    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. As a result of ASU 2009-13, multiple-deliverable arrangements will be separated in more circumstances than under prior guidance. ASU 2009-13 establishes a selling price hierarchy for determining the selling price of a deliverable. The selling price will be based on vendor-specific objective evidence (“VSOE”) 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. 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 the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

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

ASU 2010-13.    In April 2010, the FASB issued ASU No. 2010-13, Compensation — Stock Compensation (Topic 718): Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades. This ASU codifies the consensus reached in EITF Issue No. 09-J, “Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades.” The amendments to the Codification clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity shares trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. ASU 2010-13 is effective for fiscal years beginning on or after December 15,

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

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

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

ASU 2011-05.    In June 2011, the FASB issued ASU 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. The amendments in this ASU allow an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. ASU 2011-05 should be applied retrospectively for interim and annual reporting periods beginning after December 15, 2011 with early adoption permitted. We early adopted the provisions of ASU 2011-05 during the fourth quarter of 2011, and the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

ASU 2011-12.    In December 2011, the FASB issued ASU 2011-12, Deferral of the Effective Date for Amendment to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This ASU defers the guidance on whether to require entities to present reclassification adjustments out of accumulated other comprehensive income by component in

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both the statement where net income is presented and the statement where other comprehensive income is presented for both interim and annual financial statements. ASU 2011-12 reinstated the requirements for the presentation of reclassifications that were in place prior to the issuance of ASU 2011-05 and did not change the effective date of ASU 2011-05. ASU 2011-12 should be applied consistently with ASU 2011-05; accordingly, this ASU is to be applied retrospectively for interim and annual reporting periods beginning after December 15, 2011, with early adoption permitted. We early adopted the provisions of ASU 2011-12 during the fourth quarter of 2011, and the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

ASU 2011-08.    In September 2011, the FASB issued ASU 2011-08, Intangibles — Goodwill and Other (Topic 350): Testing Goodwill for Impairment. This ASU is intended to simplify how entities, both public and nonpublic, test goodwill for impairment. ASU 2011-08 permits an entity to first assess qualitative factors to determine whether it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in Topic 350, Intangibles — Goodwill and Other. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, with early adoption permitted. We adopted the provisions of ASU 2011-08 during the fourth quarter of 2011, 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 2011-04.    In May 2011, the FASB issued ASU 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This ASU represents the converged guidance of the FASB and the IASB on measuring fair value and for disclosing information about fair value measurements. The amendments in this ASU clarify the Board’s intent about the application of existing fair value measurement and disclosure requirements and changes particular principles or requirements for measuring fair value and for disclosing information about fair value measurements. ASU 2011-04 is effective prospectively for interim and annual reporting periods beginning after December 15, 2011. We adopted the provisions of ASU 2011-04 on January 1, 2012, and the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

NOTE 2.    ACQUISITIONS

2011 Acquisitions

Edge Oilfield Services, LLC and Summit Oilfield Services, LLC (collectively, “Edge”).    On August 5, 2011, we completed the acquisition of Edge. We accounted for this acquisition as a business combination. The results of operations for Edge have been included in our consolidated financial statements from the acquisition date.

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The total consideration for the acquisition was approximately $305.9 million consisting of approximately 7.5 million shares of our common stock and approximately $187.9 million in cash, which included $26.3 million to reimburse Edge for growth capital expenditures incurred between March 1, 2011 and the date of closing, net of working capital adjustments of $1.8 million. Edge primarily rents frac stack equipment used to support hydraulic fracturing operations and the associated flowback of frac fluids, proppants, oil and natural gas. It also provides well testing services, rental equipment such as pumps and power swivels, and oilfield fishing services. This transaction complements our existing fishing and rental services business and significantly increases our fleet of rental equipment. The acquisition-date fair value of the consideration transferred totaled $305.9 million which consisted of the following (in thousands):

Cash	$	189,696
Key common stock		117,919
Consideration transferred	$	307,615
Working capital adjustment		(1,752	)
Total	$	305,863

The fair value of the 7.5 million common shares issued was $15.62 per share based on the closing price on the acquisition date (August 5, 2011).

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed. We are still in the process of finalizing our third-party valuations of the tangible and intangible assets; thus, the provisional measurements below 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 August 5, 2011:
Cash and cash equivalents	$	886
Acounts receivable		21,590
Other current assets		234
Property and equipment		90,000
Intangible assets		48,670
Other long term assets		3,826
Total identifiable assets acquired		165,206
Current liabilities		19,640
Total liabilities assumed		19,640
Net identifiable assets acquired		145,566
Goodwill		160,297
Net assets acquired	$	305,863

Of the $48.7 million of acquired intangible assets, $40.7 million was preliminarily assigned to customer relationships that will be amortized as the value of the relationships are realized using expected rates of 12.2%, 29.2%, 29.2%, 12.1%, 7.4%, 3.9%, 2.5%, 1.6%, 1.0%, 0.7%, and 0.2% from 2011 through 2021. In addition, $3.7 million of acquired intangible assets was assigned to tradenames. The remaining $4.3 million of acquired intangible assets was assigned to non-compete agreements that will be amortized on a straight-line basis over 38 months. As noted above, the fair value of the acquired identifiable intangible assets is preliminary pending receipt of the final valuation for these assets.

71

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The fair value and gross contractual amount of accounts receivable acquired on August 5, 2011 was $21.6 million. We do not expect any of these receivables to be uncollectible.

All of the goodwill acquired was assigned to our fishing and rental business, which is part of our U.S. reportable segment. 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.

Transaction costs related to this acquisition were $3.6 million for the year ended December 31, 2011, and are included in general and administrative expenses on the consolidated statements of operations.

Included in our consolidated statements of operations for the year ended December 31, 2011, related to this acquisition are revenues of $52.5 million and operating income of $14.7 million from the acquisition date through December 31, 2011.

The following represents the pro forma consolidated income statement as if the Edge acquisition had been included in our consolidated results as of January 1, 2010 for the years ended December 31, 2011 and 2010:

Year Ended December 31,
2011	2010
(unaudited)
(in thousands, except per share amounts)