UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

 

 

Form 10-K

 

 

Commission file number 001-08038

KEY ENERGY SERVICES, INC.

(Exact name of registrant as specified in its charter)

 

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:

 

 

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

Title of Each Class

None

 

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

 

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

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.) Yes þ     No o

 

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

 

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

 

 

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

 

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

 

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

 

DOCUMENTS INCORPORATED BY REFERENCE

 

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

 

 

KEY ENERGY SERVICES, INC.

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

INDEX

 

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

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

 

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

 

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

 

 

 

 

 

General Description of Business

 

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

 

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

 

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

 

Service Offerings

 

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

 

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

 

Well Servicing Segment

 

Rig-Based Services

 

Our rig-based services include the maintenance, workover, and recompletion of existing oil and natural gas wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives. We also provide specialty drilling services to oil and natural gas producers with certain of our larger well servicing rigs that are capable of providing conventional and horizontal drilling services. Our rigs consist of various sizes and capabilities, allowing us to service all types of wells with depths up to 20,000 feet. Many of our rigs are outfitted with our proprietary KeyView^® technology, which captures and reports well site

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

 

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

 

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

 

The completion and recompletion services provided by our rigs prepare a newly drilled well, or a well that was recently extended through a workover, for production. The completion process may involve selectively perforating the well casing to access production zones, stimulating and testing these zones, and installing tubulars and downhole equipment. We typically provide a well service rig and may also provide other equipment to assist in the completion process. The completion process usually takes a few days to several weeks, depending on the nature of the completion. The demand for completion and recompletion services is directly related to drilling activity levels, which are highly sensitive to expectations for, and reactions to changes in, commodity prices. As the number of newly drilled wells decreases, the number of completion jobs correspondingly decreases. In addition, during periods of weak drilling activity, some drilling contractors may be more inclined to use drilling rigs for completion work.

 

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

 

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

 

Fluid Management Services

 

We provide fluid management services, including oilfield transportation and produced water disposal services, with our fleet of heavy- and medium-duty trucks. The specific services offered include vacuum truck services, fluid transportation services and disposal services for operators whose wells produce saltwater or other non-hydrocarbon fluids. We also supply frac tanks which are used for temporary storage of fluids associated with fluid hauling operations. In addition, we provide equipment trucks that are used to move large

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

 

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

 

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

 

Production Services Segment

 

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

 

Coiled Tubing Services

 

Coiled tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts, and through-tubing fishing and formation stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications such as milling temporary plugs between frac stages.

 

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

 

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

 

Fishing and Rental Services

 

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

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

 

Other Business Data

 

Raw Materials

 

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

 

Customers

 

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

 

Competition and Other External Factors

 

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

 

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

 

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

Seasonality

 

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

 

Patents, Trade Secrets, Trademarks and Copyrights

 

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

 

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

 

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

 

Employees

 

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

 

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

 

Governmental Regulations

 

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

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.

 

Occupational Safety and Health Act

 

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

 

Saltwater Disposal Wells

 

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

 

Access to Company Reports

 

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

 

 

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:

 

 

 

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

 

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

 

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

 

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

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

 

 

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

 

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

 

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

 

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

 

 

The occurrence of one or more of these risks may:

 

 

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

 

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

 

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

 

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

 

 

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

 

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

 

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

 

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

 

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

 

 

 

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:

 

 

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

 

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

 

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

 

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

 

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

DEBT-RELATED RISK FACTORS

 

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

 

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

 

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

 

 

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

 

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

 

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

 

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

 

 

 

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

 

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

 

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

 

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

 

TAKEOVER PROTECTION-RELATED RISKS

 

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

 

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

 

 

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.

 

 

None.

 

 

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. 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:

 

 

 

 

 

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

 

 

 

Market and Share Prices

 

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

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:

 

 

 

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

 

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

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

 

 

 

Dividend Policy

 

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

 

Issuer Purchases of Equity Securities

 

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

 

 

 

 

 

Equity Compensation Plan Information

 

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

 

 

 

 

Sale of Unregistered Securities

 

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

 

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

 

RESULTS OF OPERATIONS DATA

 

CASH FLOW DATA

 

 

BALANCE SHEET DATA

 

 

 

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

 

Overview

 

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

 

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

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

 

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

 

Business and Growth Strategies

 

Focus on Horizontal Well Services

 

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

 

Continue Expansion in International Markets

 

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

 

Pursue Prudent Acquisitions in Complementary Businesses

 

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

 

PERFORMANCE MEASURES

 

In determining the overall health of the oilfield service industry, we believe that the Baker Hughes U.S. land drilling rig count is the best barometer of capital spending and activity levels, since this data is made publicly available on a weekly basis. Historically, our activity levels have been highly correlated to capital spending by oil and natural gas producers.

 

 

 

 

Internally, we measure activity levels for our well servicing operations primarily through our rig and trucking hours. Generally, as capital spending by oil and natural gas producers increases, demand for our services also rises, resulting in increased rig and trucking services and more hours worked. Conversely, when activity levels decline due to lower spending by oil and natural gas producers, we generally provide fewer rig and trucking services, which results in lower hours worked. We publicly release our monthly rig and trucking hours and the following table presents our quarterly rig and trucking hours from 2008 through 2010.

 

 

MARKET CONDITIONS AND OUTLOOK

 

Market Conditions — Year Ended December 31, 2010

 

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

 

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

 

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

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

 

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

 

Market Outlook

 

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

 

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

 

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

 

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

 

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

 

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

 

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

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

 

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

 

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

 

Impact of Inflation on Operations

 

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

 

RESULTS OF OPERATIONS

 

Consolidated Results of Operations

 

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

 

Year Ended December 31, 2010 and 2009

 

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

 

Revenues

 

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

 

Direct operating expenses

 

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

 

Depreciation and amortization expense

 

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

 

General and administrative expenses

 

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

 

Asset retirements and impairments

 

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

 

Interest expense, net of amounts capitalized

 

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

Other, net

 

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

 

 

Income tax benefit (expense)

 

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

 

Discontinued Operations

 

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

 

Noncontrolling Interest

 

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

 

Year Ended December 31, 2009 and 2008

 

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

 

Revenues

 

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

Direct operating expenses

 

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

 

Depreciation and amortization expense

 

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

 

Asset retirements and impairments

 

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

 

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

 

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

 

General and administrative expenses

 

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

 

Interest expense, net of amounts capitalized

 

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

Other, net

 

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

 

 

Income tax expense

 

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

 

Discontinued Operations

 

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

 

Noncontrolling Interest

 

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

 

Segment Operating Results

 

Year Ended December 31, 2010 and 2009

 

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

 

 

 

Well Servicing

 

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

 

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

 

Production Services

 

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

 

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

 

Functional Support

 

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

Year Ended December 31, 2009 and 2008

 

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

 

 

 

Well Servicing

 

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

 

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

 

Production Services

 

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

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

 

Functional Support

 

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

 

Liquidity and Capital Resources

 

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

 

As of December 31, 2010, we had no outstanding amounts borrowed under our Senior Secured Credit Facility. In 2011, we expect to access available funds under our Senior Secured Credit Facility to meet our cash requirements for day-to-day operations and in times of peak needs throughout the year. Our planned capital expenditures, as well as any acquisitions we choose to pursue, could be financed through a combination of cash on hand, cash flow from operations, borrowings under our Senior Secured Credit Facility and, in the case of acquisitions, equity. We believe that our internally generated cash flows from operations, current reserves of cash and availability under our Senior Secured Credit Facility are sufficient to finance our cash requirements for current and future operations, budgeted capital expenditures and debt service for the next twelve months. Under the terms of the Senior Secured Credit Facility, committed letters of credit count against our borrowing capacity. All obligations under the Senior Secured Credit Facility are guaranteed by most of our subsidiaries and are secured by most of our assets, including our accounts receivable, inventory and equipment. See further discussion under “Debt Service” below.

 

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

 

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

As of December 31, 2010, $59.4 million of letters of credit were outstanding under our revolving credit facility and we had $240.6 million of availability. On October 1, 2010, we borrowed $80.0 million under the credit facility to fund a portion of the purchase price of the OFS entities. Using a portion of the proceeds from the Patterson-UTI transaction, we subsequently repaid the entire balance of $167.8 million on October 4, 2010, bringing our total revolving facility borrowings outstanding to zero.

 

Cash Flows

 

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

 

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

 

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

 

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

 

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

 

Debt Service

 

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

 

 

We have no maturities of debt in 2011. Interest on our Senior Notes is due on June 1 and December 1 of each year. Our Senior Notes mature in December 2014. Interest paid on the Senior Notes during 2010 was $35.6 million. Interest on the Senior Notes for 2011 will be $35.6 million. We expect to fund interest payments from cash on hand and cash generated by operations. In October 2010, we repaid the outstanding principal balance of $167.8 million under our revolving credit facility with a portion of the proceeds from the sale of our pressure pumping and wireline businesses.

 

8.375% Senior Notes

 

We have $425.0 million of senior notes outstanding (the “Senior Notes”) that were issued in November 2007 under an indenture (the “Indenture”) with an 8.375% coupon rate. The Senior Notes were registered as public debt effective August 22, 2008.

 

The Senior Notes are general unsecured senior obligations of the Company. They rank effectively subordinate to all of our existing and future secured indebtedness. The Senior Notes are jointly and severally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. The Senior Notes mature on December 1, 2014.

 

On or after December 1, 2011, the Senior Notes will be subject to redemption at any time and from time to time at our option, in whole or in part, at the redemption prices (expressed as percentages of the principal amount redeemed) below, plus accrued and unpaid interest to the applicable redemption date, if redeemed during the twelve-month period beginning on December 1 of the years indicated below:

 

 

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

 

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

 

 

 

These covenants are subject to certain exceptions and qualifications, and contain cross-default provisions in connection with the covenants of our Senior Secured Credit Facility. Substantially all of the covenants will terminate before the Senior Notes mature if one of two specified ratings agencies assigns the Senior Notes an investment grade rating in the future and no events of default exist under the Indenture. As of December 31, 2010, the Senior Notes were below investment grade and have never been assigned investment grade. Any covenants that cease to apply to us as a result of achieving an investment grade rating will not be restored, even if the credit rating assigned to the Senior Notes later falls below an investment grade rating.

 

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

 

Senior Secured Credit Facility

 

We maintain a Senior Secured Credit Facility pursuant to a revolving credit agreement with a syndicate of banks of which Bank of America Securities LLC and Wells Fargo Bank, N.A. are the administrative agents. The Senior Secured Credit Facility consists of a revolving credit facility, letter of credit sub-facility and swing line facility, up to an aggregate principal amount of $300.0 million, all of which will mature no later than November 29, 2012.

 

We have the ability to request increases in the total commitments under the facility by up to $100.0 million in the aggregate, with any such increases being subject to certain requirements as well as lenders’ approval.

 

The interest rate per annum applicable to the Senior Secured Credit Facility is, at our option, (i) LIBOR plus a margin of 350 to 450 basis points, depending on our consolidated leverage ratio, or, (ii) the base rate (defined as the higher of (x) Bank of America’s prime rate and (y) the Federal Funds rate plus 0.5%), plus a margin of 250 to 350 basis points, depending on our consolidated leverage ratio. Unused commitment fees on the facility range from 0.50% to 0.75%, depending upon our consolidated leverage ratio.

 

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

 

 

 

 

 

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

 

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

 

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

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

 

Related Party Notes Payable

 

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

 

Capital Lease Agreements

 

We lease equipment, such as vehicles, tractors, trailers, frac tanks and forklifts, from financial institutions under master lease agreements. During the third quarter of 2010, we repaid $1.3 million of capital leases that we had incurred to acquire vehicles pursuant to the terms of the Patterson-UTI sale agreement. As of December 31, 2010, there was approximately $6.1 million outstanding under such equipment leases.

 

Off-Balance Sheet Arrangements

 

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

 

Contractual Obligations

 

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

 

 

 

 

Debt Compliance

 

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

 

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

 

Capital Expenditures

 

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

 

Acquisitions

 

OFS

 

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

 

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

 

Other

 

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

 

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

 

Critical Accounting Policies

 

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

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

 

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

 

 

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

 

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

 

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

 

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

 

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

 

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

 

Contingencies

 

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

 

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

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

 

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

 

Income Taxes

 

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

 

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

 

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

 

Estimates of Depreciable Lives

 

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

 

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

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

 

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

 

Valuation of Indefinite-Lived Intangible Assets

 

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

 

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

 

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

 

We conduct our annual impairment test for goodwill and other intangible assets not subject to amortization as of December 31 of each year. In determining the fair value of our reporting units, we use a weighted-average approach of three commonly used valuation techniques — a discounted cash flow method, a guideline companies method, and a similar transactions method. We assign a weight to the results of each of these methods based on the facts and circumstances that are in existence for that testing period. We assigned more weight to the discounted cash flow method.

 

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

 

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

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

 

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

 

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

 

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

 

Valuation of Tangible and Finite-Lived Intangible Assets

 

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

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

 

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

 

Valuation of Equity-Based Compensation

 

We have granted stock options, stock-settled stock appreciation rights (“SARs”), restricted stock (“RSAs”), phantom shares and performance units to our employees and non-employee directors. The option and SAR awards we grant are fair valued using a Black-Scholes option model on the grant date and are amortized to compensation expense over the vesting period of the option award, net of estimated and actual forfeitures. Compensation related to RSAs is based on the fair value of the award on the grant date and is recognized based on the vesting requirements that have been satisfied during the period. Phantom shares are accounted for at fair value, and changes in the fair value of these awards are recorded as compensation expense during the period. Performance units provide a cash incentive award, the unit value of which is determined with reference to our common stock. The performance units are measured based on two performance periods. At the end of each performance period, 100%, 50%, or 0% of an individual’s performance units for that period will vest, based on the relative placement of our total shareholder return within a peer group consisting of Key and five other companies. See “Note 20. Share-Based Compensation” in “Item 8. Financial Statements and Supplementary Data” for further discussion of the various award types and our accounting for our equity-based compensation.

 

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

 

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

 

 

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

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

 

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

 

New Accounting Standards Adopted in this Report

 

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

 

ASU 2009-17.  In December 2009, the FASB issued ASU 2009-17, Consolidations (Topic 810) — Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities.  ASU 2009-17 replaces the quantitative-based risk and rewards calculation for determining which reporting entity, if any, has a controlling financial interest in a variable interest entity with an approach focused on identifying which reporting entity has the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance and (i) the obligation to absorb losses of the entity or (ii) the right to receive benefits from the entity. An approach that is expected to be primarily qualitative will be more effective for identifying which reporting entity has a controlling financial interest in a variable interest entity. ASU 2009-17 also requires additional disclosures about a reporting entity’s involvement in variable interest entities. The provisions of ASU 2009-17 are to be applied beginning in the first fiscal period beginning after November 15, 2009. We adopted ASU 2009-17 on January 1, 2010 and the adoption of this standard did not have a material effect on our financial position, results of operations, or cash flows.

 

ASU 2010-02.  In January 2010, the FASB issued ASU 2010-02, Consolidation (Topic 810) — Accounting and Reporting for Decreases in Ownership of a Subsidiary — A Scope Clarification.  ASU 2010-02 clarifies that the scope of previous guidance in the accounting and disclosure requirements related to decreases in ownership of a subsidiary apply to (i) a subsidiary or a group of assets that is a business or nonprofit entity; (ii) a subsidiary that is a business or nonprofit entity that is transferred to an equity method investee or joint venture; and (iii) an exchange of a group of assets that constitutes a business or nonprofit activity for a noncontrolling interest in an entity. ASU 2010-02 also expands the disclosure requirements about deconsolidation of a subsidiary or derecognition of a group of assets to include (i) the valuation techniques used to measure the fair value of any retained investment; (ii) the nature of any continuing involvement with the subsidiary or entity acquiring a group of assets; and (iii) whether the transaction that resulted in the deconsolidation or derecognition was with a related party or whether the former subsidiary or entity acquiring the assets will become a related party after the transaction. The provisions of ASU 2010-02 are effective for the first reporting period beginning after December 13, 2009. We adopted the provisions of ASU 2010-02 on January 1, 2010 and the adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

 

ASU 2010-06.  In January 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures About Fair Value Measurements.  ASU 2010-06 clarifies the requirements for certain disclosures around fair value measurements and also requires registrants to provide certain additional disclosures about those measurements. The new disclosure requirements include (i) the significant amounts of transfers into and out of Level 1 and Level 2 fair value measurements during the period, along with the reason for those transfers, and (ii) and separate presentation of information about purchases, sales, issuances and settlements of fair value measurements with significant unobservable inputs.

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

 

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

 

Accounting Standards Not Yet Adopted in this Report

 

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

 

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

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

 

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

 

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

 

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

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

 

 

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

 

Interest Rate Risk

 

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

 

Foreign Currency Risk

 

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

 

Equity Risk

 

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

 

Key Energy Services, Inc. and Subsidiaries

 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

Board of Directors and Stockholders of

Key Energy Services, Inc.

 

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

 

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

 

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

 

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

 

 

Houston, Texas

February 25, 2011

 

Board of Directors and Stockholders of

Key Energy Services, Inc.

 

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

 

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

 

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

 

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

 

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

 

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

 

 

Houston, Texas

February 25, 2011

Key Energy Services, Inc. and Subsidiaries

 

CONSOLIDATED BALANCE SHEETS