KEY ENERGY SERVICES INC - Annual Report: 2009 (Form 10-K)

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 o     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.  o

 

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

 

(Do not check if a smaller reporting company)

 

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

 

The aggregate market value of the common stock of the registrant held by non-affiliates of the registrant as of June 30, 2009, based on the $5.76 per share closing price for the registrant’s common stock as quoted on the New York Stock Exchange on such date, was $583,410,649 (for purposes of calculating these amounts, only directors, officers and beneficial owners of 10% or more of the outstanding capital stock of the registrant have been deemed affiliates).

 

As of February 17, 2010, the number of outstanding shares of common stock of the registrant was 125,430,259.

 

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 2010 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, 2009

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,” “expects,” “believes,” “anticipates,” “will,” “predicts,” “projects,” “potential” or “continue” or the negative of such terms and other comparable terminology. These statements are only predictions and are subject to substantial risks and uncertainties. In evaluating those statements, you should carefully consider the information above as well as the risks outlined in “Item 1A. Risk Factors.” Actual performance or results may differ materially and adversely.

 

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

 

 

General Description of Business

 

Key Energy Services, Inc. (NYSE: KEG) is a Maryland corporation and is one of the world’s leading onshore, rig-based well servicing contractors. 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 changed our name to Key Energy Services, Inc. in December 1998.

 

We provide a complete range of services to major oil companies, foreign national oil companies and independent oil and natural gas production companies, including rig-based well maintenance and workover services, well completion and recompletion services, fluid management services, pressure pumping services, fishing and rental services, wireline services and other ancillary oilfield services. We operate in most major oil and gas producing regions of the continental United States, and have operations based in Mexico, Argentina and the Russian Federation. Additionally, 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. Our Production Services segment includes pressure pumping services, fishing and rental services and wireline services. The following discussion provides a description of the major service lines offered by our business segments. With the exception of our rig-based services, all of our major service lines are provided primarily in the continental United States. Our rig-based services are provided in the continental United States as well as in Mexico, Argentina and the Russian Federation. See “Note 21. 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.

 

Well Servicing Segment

 

Rig-Based Services

 

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

 

The maintenance services provided by our rig fleet are generally required throughout the life cycle of an oil or gas well to ensure efficient and continuous production. Examples of the maintenance services provided by our rigs include routine mechanical repairs to the pumps, tubing and other equipment on a well, removing debris from the well bore, and pulling the rods and other downhole equipment out of the well bore to identify a production problem. Maintenance services generally take less than 48 hours to complete and, in general, the demand for these services is closely related to the total number of producing oil and gas wells in a given market.

The workover services provided by our rig fleet are performed to enhance the production of existing wells, and generally are more complex and time consuming than normal maintenance services. Workover services can include deepening or extending well bores into new formations by drilling horizontal or lateral well bores, sealing off depleted production zones and accessing previously bypassed production zones, converting former production wells into injection wells for enhanced recovery operations and conducting major subsurface repairs due to equipment failures. Workover services may last from a few days to several weeks, depending on the complexity of the workover. 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 downhole equipment. We typically provide a well service rig and may also provide other equipment to assist in the completion process. The completion process typically takes a few days to several weeks, depending on the nature of the completion. The demand for completion and recompletion services is directly related to drilling activity levels, which are highly sensitive to expectations about, and reactions to changes in, commodity prices. As the number of newly drilled wells decreases, the number of completion jobs correspondingly decreases. During periods of weak demand, some drilling contractors may 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 also generally require auxiliary equipment in addition to a well servicing rig. The demand for plugging and abandonment services is not significantly impacted by the demand for oil and natural gas because well operators are required by state regulations to plug wells that are no longer productive.

 

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., Bronco Drilling Company, 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 Ltd. and Allis-Chalmers Energy Inc. In Mexico, San Antonio International and Forbes Energy Services Ltd. are our largest competitors. In the Russian Federation, our major competitors are Weatherford International Ltd. and Integran Technologies Inc.

 

Fluid Management Services

 

We provide fluid management services, including oilfield transportation and produced water disposal services, with a very large fleet of heavy- and medium-duty trucks. The specific services offered include vacuum truck services, fluid transportation services and disposal services for operators whose wells produce saltwater or other fluids. We also supply frac tanks which are used for temporary storage of fluids associated with fluid hauling operations. In addition, we provide equipment trucks that are used to move large pieces of equipment from one well site to the next, and we operate a fleet of hot oilers which are capable of pumping heated fluids that are used to clear soluable restrictions in a well bore.

 

Fluid hauling trucks are utilized in connection with drilling and workover projects, which tend to use large amounts of various fluids. In connection with drilling, maintenance or workover activity at a well site, we transport fresh water to the well site and provide temporary storage and disposal of produced saltwater and drilling or workover fluids. These fluids are removed from the well site and transported for disposal in a saltwater disposal (“SWD”) well. Key owned or leased 57 active SWD wells at December 31, 2009. 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, Inc., Complete Production Services, Inc., Nabors Industries Ltd. and Stallion Oilfield Services Ltd.

In addition, there are numerous small companies that compete in our fluid management services markets in the United States.

 

Production Services Segment

 

Pressure Pumping Services

 

Our pressure pumping services include fracturing, nitrogen, acidizing, cementing and coiled tubing services. We have approximately 212,000 stimulation pressure pumping horsepower and a fleet of coiled tubing units. These services (which may be utilized during the completion or workover of a well) are provided to oil and natural gas producers and are used to enhance the production of oil and natural gas wells from formations which exhibit restricted flow of oil and natural gas. In the fracturing process, we typically pump fluid and sized sand, or proppants, into a well at high pressure in order to fracture the formation and thereby increase the flow of oil and natural gas. With our cementing services, we pump cement into a well between the casing and the well bore. Coiled tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural gas well applications, such as well bore clean-outs, nitrogen jet lifts, and through tubing fishing and formation stimulations utilizing acid, chemical treatments and sand fracturing. Coiled tubing is also used for a number of horizontal well applications, including “stiff wireline” services, in which a wireline is placed in the coiled tube and then fed into a well to carry the wireline to a desired depth.

 

Demand for our pressure pumping services is primarily influenced by current and anticipated oil and natural gas prices and the resulting impact on the willingness of our customers to make operating and capital expenditures. The pressure pumping services market is dominated by three major competitors: Schlumberger Ltd., Halliburton Company and BJ Services Company. Other competitors for our pressure pumping services include Weatherford International Ltd., Superior Well Services, Inc., Basic Energy Services, Inc., Complete Production Services, Inc., Frac-Tech Services, Ltd. and RPC, Inc.

 

Fishing and Rental Services

 

We offer a full line of services and rental equipment designed for use both onshore and offshore for drilling and workover services. Fishing services involve recovering lost or stuck equipment in the well bore utilizing a “fishing tool.” Our rental tool inventory consists of drill pipe, tubulars, handling tools (including our patented Hydra-Walk^® pipe-handling units and services), pressure-control equipment, power swivels and foam air units. 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, Smith International, Inc., Weatherford International Ltd., Basic Energy Services, Inc., Superior Energy Services, Inc., Quail Tools (owned by Parker Drilling Company) and Knight Oil Tools.

 

Wireline Services

 

We have a fleet of wireline units that perform services at various times throughout the life of the well including perforating, completion logging, production logging and casing integrity services. After the well bore is cased and cemented, we can provide a number of services. Perforating creates the flow path between the reservoir and the well bore. Production logging can be performed throughout the life of the well to measure temperature, fluid type, flow rate, pressure and other reservoir characteristics. This service helps the operator analyze and monitor well performance and determine when a well may need a workover or further stimulation.

 

In addition, wireline services may involve well bore remediation, which could include the positioning and installation of various plugs and packers to maintain production or repair well problems, and casing inspection for internal or external abnormalities in the casing string. Wireline services are provided from surface logging units, which lower tools and sensors into the well bore. We use advanced wireline instruments to evaluate well integrity and perform cement evaluations and production logging. Demand for our wireline services is correlated to current and anticipated oil and natural gas prices and the resulting effect on the willingness of our customers to make operating and capital expenditures. The major competitors for our wireline services are

Baker Hughes Incorporated, Schlumberger Ltd., Wood Group Logging Services and Kuykendall Wireline Service Co., Inc.

 

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. However, there are a limited number of vendors for some specialized types of sand our pressure pumping operations use in frac jobs. See “Item 1A. Risk Factors.”

 

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, 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, and no single customer accounted for more than 10% of our consolidated revenues for the years ended December 31, 2008 and 2007.

 

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. In recent years, many of our larger customers have placed 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. Due, in part, to the general economic downturn and declines in the price of oil and natural gas since the first half of 2008, pricing for our services has become increasingly competitive. Further, as demand drops for oilfield services, the market is left with excess supply, placing additional pressure on our pricing.

 

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, such as the one we experienced during the first half of 2009, demand for service and maintenance 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 these types of 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 highly dependent upon, and affected by, the level of U.S. and international oil and natural gas exploration and development activity, as well as the equipment capacity in any particular region. For a more detailed discussion, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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. In the United States, as of December 31, 2009, we had 43 patents issued and 8 patents pending. In foreign countries, as of December 31, 2009, we had 30 patents issued and 145 patents pending. However, after evaluating the individual market opportunities and our international patent portfolio last year, we have determined not to maintain approximately two-thirds of the 145 currently active foreign pending patents applications. 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 January 31, 2010, we employed approximately 6,200 persons in our United States operations and approximately 1,900 additional persons in Argentina, Mexico and Canada. In addition, OOO Geostream Services Group (“Geostream”), a company in the Russian Federation in which we own a 50% controlling interest, employed (together with its wholly-owned subsidiaries) approximately 370 persons as of January 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 labor unions. In Mexico, we have entered into a collective bargaining agreement that applies to our workers in Mexico performing work under the PEMEX contracts.

 

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

Governmental Regulations

 

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

 

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 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 Control

 

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 control 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 stay compliant with any new laws. See “Item 1A. Risk Factors.”

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 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, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements.

 

Marine Employees

 

Certain of our employees who perform services on our barge rigs or work offshore may be covered by the provisions of the Jones Act, the Death on the High Seas Act, the Longshore and Harbor Workers’ Compensation Act and general maritime law. These laws operate to make the liability limits established under state workers’ compensation laws inapplicable to these employees. Instead, these employees or their representatives are permitted to pursue actions against us for damages resulting from job related injuries, generally with no limitations on our potential liability.

 

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 and New Mexico. Regulations in these states require us to obtain a 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.

 

Wireline

 

We conduct wireline logging, which may entail the use of radioactive isotopes along with other nuclear, electrical, acoustic and mechanical devices to evaluate downhole formation. Our activities involving the use of isotopes are regulated by the U.S. Nuclear Regulatory Commission and specified agencies of certain states. Additionally, we may use high explosive charges for perforating casing and formations, and various explosive cutters to assist in well bore cleanout. Such operations are regulated by the U.S. Department of Justice Bureau of Alcohol, Tobacco, Firearms, and Explosives and require us to obtain licenses or other approvals for the use of densitometers as well as explosive charges.

 

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”). We have filed the required certifications under Section 302 of the Sarbanes-Oxley Act of 2002 as Exhibits 31.1 and 31.2 to this Annual Report on Form 10-K.

In 2009, we submitted to the New York Stock Exchange (the “NYSE”) the CEO certification required by Section 303A.12(a) of the NYSE’s Listed Company Manual. 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 dependent 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. 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. In addition, when oil and natural gas prices are weak, or when our customers expect oil and natural gas prices to decrease, fewer wells are drilled, resulting in less completion and maintenance work for us. Additional factors that affect demand for our services include:

 

 

Demand for our services is primarily influenced by current and anticipated oil and natural gas prices, and the significant decline in oil and natural gas prices beginning in the third quarter of 2008 caused our customers to reduce their spending on exploration and development drilling throughout 2009. This reduction in our customers’ spending could continue through 2010 and beyond. Further decline in demand for our oil and natural gas services could have a material adverse effect on our revenue and profitability. Also impacting demand are the global economic conditions. While appearing to have stabilized, the disruptions in the global credit markets during 2009 could continue to negatively impact the exploration and production expenditures by our customers throughout 2010 and beyond. Additionally, even as economic conditions appear to have begun to stabilize, it remains uncertain whether our customers, vendors and suppliers will be able to access financing necessary to return to their previous level of operations or to avoid further deceases in their level of operations, fulfill their commitments and fund future operations and obligations.

 

We may be unable to maintain pricing on our core services.

 

During the period from 2006 to 2008, we periodically increased the prices on our services to offset rising costs and to generate higher returns for our stockholders. However, as a result of pressures stemming from deteriorating market conditions and falling oil and natural gas prices beginning in the third quarter of 2008 and continuing through the first half of 2009, it became increasingly difficult to maintain our prices. We have and will likely continue to face pricing pressure from our competitors. We have made price concessions, and may be compelled to make further price concessions, in order to maintain market share.

In addition, we expect our costs to rise if demand for our services increases with a recovering market, due in part to tighter labor markets and similar economic developments that would likely result from an improving market. In addition to the recent difficulty we have experienced maintaining prices as described above, even if we are able to increase our prices as market conditions improve, we may not be able to do so at a rate that would be sufficient to cover such rising costs.

 

The inability to maintain our pricing, to increase our pricing as costs increase, or a reduction in our pricing, may have a continuing and material negative impact on our operating results in the future.

 

Industry capacity may adversely affect our business.

 

Between 2006 and 2008, a significant amount of new capacity, including new well service rigs, new pressure pumping equipment and new fishing and rental equipment, entered the market. In some cases, the new capacity was attributable to start-up oilfield service companies and, in other cases, the new capacity was deployed by existing service providers to increase their service capacity. The combination of overcapacity and declining demand exacerbated the pricing pressure for our services in 2009. Although oilfield service companies are not likely to add significant new capacity under current market conditions, the overcapacity could cause us to experience continued pressure on the pricing of our services and experience lower utilization. This could continue to have a material negative impact on our operating results.

 

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 for 2010 are materially different than we have predicted, we could record additional impairment charges for interim periods during 2010 or in future years, which could have a material adverse effect on our financial position and results of operations.

 

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 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 in Argentina, Mexico and the Russian Federation, a technology development group based in Canada, as well as investments in oilfield service companies based in Canada. In the future, we may expand our operations into other foreign countries as well. As a result, we are exposed to risks of international operations, including:

 

 

The occurrence of one or more of these risks may:

 

 

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

 

We historically have experienced an annual employee turnover rate of almost 50%. 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. We cannot assure that at times of high demand we will be able to retain, recruit and train an adequate number of workers. Potential inability or lack of desire by workers to commute to our facilities and job sites and competition for workers from competitors or other industries are factors that could affect our ability to attract and retain workers. We believe that our wage rates are competitive with the wage rates of our competitors and other potential employers. A significant increase in the wages other employers pay could result in a reduction in our workforce, increases in our wage rates, or both. Either of these events could diminish our profitability and growth potential.

Additionally, in response to the downturn in market conditions beginning in the second quarter of 2008 and continuing through the third quarter of 2009, we made significant reductions in the size of our workforce. Excluding the reductions in workforce during 2009 in response to market conditions, our turnover rate in 2009 was 33%. As market conditions and our activity levels improve, we will be required to expand our workforce to accommodate these increases. We may encounter difficulties in adding new headcount with the requisite experience levels, which could negatively impact our ability to take advantage of improving market conditions.

 

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

 

A component of our business strategy is to incorporate our technology into our well service rigs, primarily through the KeyView^® system. The inability to successfully develop and integrate the 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 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. For additional information, see the discussion under “Governmental Regulations” in “Item 1. Business.”

 

We rely on a limited number of suppliers for certain materials used in providing our pressure pumping services.

 

We rely on a limited number of suppliers for sized sand, a principal raw material that is critical for our pressure pumping operations. While the materials are generally available, if we were to have a problem sourcing raw materials or transporting these materials from these suppliers, our ability to provide pressure pumping services could be limited.

 

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

 

A component of our growth strategy is to make geographic-focused acquisitions that will strengthen our presence in selected regional markets. Pursuit of this strategy may be restricted by the deterioration of credit markets, which may significantly limit the availability of funds for such acquisitions. In addition to restricted funding availability, the success of this strategy will depend on our ability to identify suitable acquisition candidates and to negotiate acceptable financial and other terms. There is no assurance that we will be able to do so. The success of an acquisition depends on our ability to perform adequate due diligence before the acquisition and on our ability to integrate the acquisition after it is completed. While we commit significant resources to ensure that we conduct comprehensive due diligence, there can be no assurance that all potential risks and liabilities will be identified in connection with an acquisition. Similarly, while we expect to commit

substantial resources, including management time and effort, to integrating acquired businesses into ours, there is no assurance that we will be successful integrating these businesses. In particular, it is important that we be able to retain both key personnel of the acquired business and its customer base. A loss of either key personnel or customers could negatively impact the future operating results of the acquired business.

 

The loss of a significant customer could cause our revenue to decline.

 

For the year ended December 31, 2009, one customer of our Well Servicing segment comprised approximately 11% of our total consolidated revenues. The work that we perform for this customer is done under contracts that expire in the near term and are subject to renewal through a bidding process. We can provide no assurance that we will be able to secure renewals of these contracts, and if we are unable to do so, the loss of this customer could have a material negative impact on our revenues and profitability.

 

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

 

The U.S. Congress is considering legislation to mandate reductions of greenhouse gas emissions and certain states have already implemented, or are in the process of implementing, similar legislation. Additionally, the U.S. Supreme Court has held in its decisions that carbon dioxide can be regulated as an “air pollutant” under the CAA, which could result in future regulations even if the U.S. Congress does not adopt new legislation regarding emissions. 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 condition, 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 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 would 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 cannot assure you that we would be able to implement alternative financing plans, if necessary, on commercially reasonable terms or at all, or that implementing any such alternative financing plans would 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 could become more likely if poor market conditions persist or worsen. Although such a credit downgrade would not have an effect on our currently outstanding senior debt under our indenture or senior secured credit facility, such a downgrade would make it more difficult for us to raise additional debt financing in the future.

 

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 condition 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 Amended and Restated 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 in both Houston, Texas and Midland, Texas (our principal executive office is in Houston, Texas). We own or lease numerous rig yards, storage yards, truck yards 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 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 business segment and geographic region:

 

 

 

 

 

On September 3, 2006, our former controller and former assistant controller filed suit against us in Harris County, Texas, alleging constructive termination and breach of contract. We reached an agreement to resolve the matter through arbitration that included an obligation to pay a minimum amount to the claimants regardless of the outcome. In the fourth quarter of 2009, the matter went to trial and the arbitrator found in favor of Key.

 

In addition to various other suits and claims that have arisen in the ordinary course of business, we continue to be involved in litigation with one of our former executive officers. We do not believe that the disposition of any of these items, including litigation with former management, will result in a material adverse effect on our consolidated financial position, results of operations or cash flows. For additional information on legal proceedings, see “Note 14. Commitments and Contingencies” in “Item 8. Financial Statements and Supplementary Data.”

 

 

None.

 

 

Market and Share Prices

 

Our common stock is traded on the NYSE under the symbol “KEG.” As of February 17, 2010, there were 812 registered holders of 125,430,259 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 is comprised 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, 2004 and tracks the return on the investment through December 31, 2009.

 

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, 2009, 2008 and 2007. 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.

 

Stock Repurchases

 

On October 26, 2007, our board of directors authorized a share repurchase program, in which we could spend up to $300.0 million to repurchase shares of our common stock on the open market. The program expired March 31, 2009. We did not make any purchases under this program during 2009.

During the fourth quarter of 2009, we repurchased an aggregate 26,819 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:

 

Issuer Purchases of Equity Securities

 

 

 

 

Equity Compensation Plan Information

 

The following table sets forth information as of December 31, 2009 with respect to equity compensation plans (including individual compensation arrangements) under which our common stock is authorized for issuance:

 

 

 

 

 

The following historical selected financial data as of and for the years ended December 31, 2005 through December 31, 2009 has been derived from our audited financial statements. 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

 

 

SELECTED 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 complete range of services to major oil companies, foreign national oil companies and independent oil and natural gas production companies, including rig-based services, fluid management services, pressure pumping services, fishing and rental services, and wireline services. We operate in most major oil and natural gas producing regions of the United States as well as internationally in Mexico, Argentina and the Russian Federation. We also own a technology development company based in Canada and have equity interests in oilfield service companies in Canada.

 

During 2009, we operated in two business segments, Well Servicing and Production Services. We also have a Functional Support segment associated with managing all of our reportable operating segments. For a full description of our operating segments, see “Service Offerings” in “Item 1. Business.”

Business and Growth Strategies

 

Our strategy is to improve results through acquisitions, controlling spending, maintenance and growth of our market share in core segments, expansion internationally, investments in technology and new service offerings, enhancement of safety and quality, and maintenance of a strong balance sheet and good liquidity.

 

Acquisition Strategy

 

Our strategy contemplates that from time to time we may acquire businesses or assets that are consistent with our long-term growth strategy. During 2009, we acquired an additional 24% interest in Geostream and gained 50% ownership and a controlling interest. Geostream is an oilfield services company in the Russian Federation providing drilling services, workover services and sub-surface engineering and modeling. As a result of this investment, we expect to expand our international presence, specifically in Russia where the wells are shallow and suited to the services that we perform.

 

Our investment in Geostream was made using cash generated by our operations, and our objective is to use cash for future acquisitions. We may, from time to time, access our availability under our revolving credit facility to fund future acquisitions. Depending on future market conditions, however, we may elect to use equity as a financing tool for acquisitions.

 

Controlling Spending

 

Through most of 2009, market conditions for oilfield services continued the downward trend that began in the latter part of 2008. This downturn in the market for our services resulted from the disruption in the credit markets that caused many of our customers to begin to slow down their capital spending, as well as from declines in the prices of oil and natural gas. In response to the downturn, we began taking steps during the latter part of 2008, which continued through 2009, to decrease our spending levels and control costs. These steps included targeted reductions in our workforce, reductions in pay and benefits, and other reductions in our cost structure. We believe that the actions we took resulted in significant cost savings during the year. We continue to focus on the rationalization of our infrastructure, including facility consolidations and continued cost reductions efforts.

 

Maintain and Grow in Core Segments

 

From 2006 to 2008, we significantly increased our capital expenditures compared to prior years, devoting more capital to organic growth. Excluding acquisitions, we have cumulatively spent approximately $560.0 million on capital expenditures since the beginning of 2007, including capital expenditures of $128.4 million in 2009. These expenditures include purchases to expand our operations in Mexico and Russia, drill strings and nitrogen units for our rental operations, and capitalized costs for new information system projects. With the overall downturn in the economy that began in late 2008 and persisted through 2009, we reduced our capital expenditure program in 2009 in order to maintain liquidity and provide flexibility for the use of our capital. However, we continue to evaluate our capital spending in the current environment and could increase spending for growth opportunities or if we are awarded additional international work or recognize an opportunity to expand our services in a particular market.

 

International Expansion

 

We are evaluating expansion into a number of international markets. One of our objectives is to redeploy underutilized assets into international markets. We continue to grow our presence and service capabilities in Mexico and Russia. During 2009, we increased the number of working rigs we had positioned in Mexico. We also have deployed other oilfield service equipment to this region to expand our service offerings. In Russia, we sold drilling and workover rigs and other equipment to Geostream to enhance our presence. We will consider strategic international acquisitions and joint ventures in order to establish a presence in a particular market.

Investing in Technology

 

We have invested, and will continue to invest, in technologies which will improve our operational and safety performance. We believe these investments will continue to differentiate Key as a premium energy service provider and provide opportunities for higher pricing.

 

KeyView^® Technology

 

The KeyView^® system is our proprietary rig data acquisition, control and information system which began deployment in 2003. The KeyView^® system measures selected rig sensor data and rig activity data which provides visibility into the performance and safety of well site operations. In 2009, we continued to upgrade the KeyView^® system with enhanced data mining, reporting and safety capabilities to enhance the operational and safety benefits of these systems. We believe measuring performance is critical to providing a premium service to our customer base and differentiates us from our competitors. As of December 31, 2009, we had 299 KeyView^® systems deployed.

 

Advanced Measurements, Inc. (“AMI”)

 

Our technology initiative was expanded with the acquisition of AMI in 2007. AMI designs and produces oilfield service data acquisition, control and information systems. AMI’s technology platform and application facilitate the collection of job performance and related information and digitally distributes the information to customers. AMI contributed to the development of the KeyView^® system and assists in the advancement of this technology.

 

SmartTong^sm Services

 

During 2009, we introduced “SmartTong^sm Rod Connection Services” to the market. The development of this technology was driven by high sucker rod connection failure rates and the additional associated repair costs incurred by our clients. SmartTong^sm systems are computer-controlled and fully automated hydraulic sucker rod tong systems that make up a sucker rod connection to the manufacturer’s or American Petroleum Institute (“API”) specifications. We believe that it is the only technology of its kind that provides this level of precision. As of December 31, 2009, we had two SmartTong^sm systems deployed. We anticipate deploying additional SmartTong^sm systems over the course of 2010.

 

Safety and Quality

 

We devote significant resources to the training and professional development of our employees, with a special emphasis on safety. We currently own and operate training centers in Texas, California, Oklahoma, New Mexico and Louisiana. In addition, in conjunction with local community colleges, we have cooperative training centers in Wyoming, New Mexico and Texas. The training centers are used to enhance our employees’ understanding of operating and safety procedures. We recognize the historically high turnover rate in the industry in which we operate. We are committed to offering competitive compensation, benefits and incentive programs for our employees in order to ensure we have qualified, safety-conscious personnel who are able to provide quality service to our customers.

 

Maintain Strong Balance Sheet and Liquidity

 

We believe that our ability to maintain a strong balance sheet and exercise sound capital discipline is critical to position Key to sustain itself through the current market conditions. We also believe that our ability to maintain liquidity and borrowing capacity is important in order to enable us to maintain operational flexibility, as well as to take advantage of business opportunities as they arise. As of December 31, 2009, we had $37.4 million in cash and cash equivalents and $156.9 million of availability under the revolving portion of our senior secured credit agreement (the “Senior Secured Credit Facility”). We do not have any material indebtedness repayment obligations in 2010. We have no maturities under our 8.375% Senior Notes (the “Senior Notes”) until 2014 and no required repayments of borrowings on our Senior Secured Credit Facility until 2012. Also, in the fourth quarter of 2009, we made principal payments totaling $14.5 million related to

our Related Party Notes (as defined below under “Related Party Notes Payable” of “Liquidity and Capital Resources”). We funded our obligations under the Related Party Notes with cash on hand.

 

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. When oil and natural gas prices are strong, capital spending by our customers tends to be high, as indicated by the correlation of the Baker Hughes U.S. land drilling rig count. Similarly, as oil and natural gas prices fall, notably in 2009, the Baker-Hughes U.S. land drilling rig count declines.

 

 

 

 

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 2007 through 2009.

 

 

MARKET CONDITIONS AND OUTLOOK

 

Market Conditions — Year Ended December 31, 2009

 

During 2009, the overall demand and pricing for the services that we provide declined compared to 2008. The average Baker Hughes U.S. land drilling rig count during 2009 was 1,046 rigs, which was a decrease of 42.4% from the 2008 average and 38.3% from the 2007 average. The decrease in the average land drilling rig count was driven primarily by sharp declines in oil and natural gas prices; during 2009 the West Texas Intermediate — Cushing crude oil price averaged $61.95 per barrel and natural gas at the Henry Hub averaged $4.28 per Mcf, decreases of 37.8% and 51.9%, respectively, from 2008 prices and 14.4% and 39.9%, respectively, from 2007 prices.

 

Due to the decline in commodity prices, our prices, overall activity levels and asset utilization during 2009 decreased as our customers reduced capital spending. For 2009, we had 1.8 million rig hours and 1.7 million trucking hours, which was a decrease of 35.2% and 28.2%, respectively, from 2008 activity levels and 28.1% and 24.8%, respectively, from 2007 activity levels. Partially offsetting the decline in rig hours was our expansion into Mexico and Russia during 2009, and the full year effect of acquisitions completed during 2008. Also impacting our activity levels was the disruption in the credit markets and general uncertainty in the U.S. and global economy. Reduced credit availability significantly curtailed the capital spending by our customers.

 

As conditions deteriorated for most of 2009, driven by rapidly declining commodity prices in the first half of 2009, tight credit markets and overall uncertainty about market conditions, we responded by implementing an aggressive cost control program, implementing pricing changes in selected markets in an effort to maintain asset utilization and cutting our own capital spending plans. Our cost control program

included targeted reductions in headcount, employee wage rates and benefits reductions, and controlled spending in overhead costs.

 

Based on our assessment of conditions in the rig-based oilfield services market, we chose to retire a portion of our U.S. rig fleet and associated equipment during the third quarter of 2009, which resulted in a pre-tax charge of $65.9 million. Included in this retirement were approximately 250 of our older, less efficient rigs, leaving a remaining U.S. well service rig fleet of 743 rigs. During the third quarter of 2009, we also determined that market overcapacity, prolonged depression of natural gas prices, lower activity levels from our major customer base related to stimulation work and consecutive quarterly operating losses in our Production Services segment, indicated that the carrying amounts of the asset groups under this segment were potentially not recoverable. We performed an assessment of the fair value of the asset groups in this segment, and the results of this assessment indicated that the carrying value of our pressure pumping equipment exceeded its fair value. As a result, we recorded a pre-tax impairment charge of $93.4 million during the third quarter of 2009. We also recorded a pre-tax impairment charge of $0.5 million related to goodwill during the third quarter of 2009 in our Production Services segment.

 

Market Outlook

 

The outlook for 2010 will remain largely dependent on the U.S. and global economies. However, as oil prices have gradually recovered to over $70 per barrel for most of the second half of 2009, we believe that the outlook for 2010 will be generally favorable relative to the lows that we experienced during 2009. Our activity levels for the latter half of the fourth quarter improved over earlier periods, even when considering the effects of the Thanksgiving and Christmas holidays, which historically have negatively impacted our fourth quarter activity levels. This, coupled with signs that demand for oil and natural gas is increasing, provides encouragement on the near term as well as the long term outlook. We believe that if oil prices are sustained at the levels that were seen at the end of the fourth quarter of 2009, our customers will increase capital spending in 2010 compared to 2009. This will be dependent on continued increases in economic growth during 2010.

 

We believe that we will see higher levels of workover and completion activity for our U.S. well servicing business, in 2010 as industry activity levels increase. We expect that PEMEX will maintain their level of workover activity and that the rigs we have currently operating in Mexico will be utilized for all of 2010. In Argentina, although we experienced significant labor-related issues during 2009, operating conditions and our activity levels and pricing in this country began to stabilize and improve in late 2009 and into 2010. During 2010, we also expect our activity levels in Russia will increase significantly as the equipment that we have sold to the joint venture is deployed and begins working.

 

For our production services business, we are encouraged by the increased number and size of frac jobs that we saw during the latter half of the fourth quarter. Our production services business is highly correlated with drilling activity and as drilling activity has increased from the lows of 2009, we have seen signs that the pressure pumping business is beginning to stabilize relative to the sharp decline it experienced in 2009. We currently believe that the market for our fishing and rental operations and wireline business will also improve during 2010, as activity levels for these businesses have historically been directly correlated with drilling, completion and workover activity.

 

As we enter 2010, we will also continue to monitor our cost structure and focus on the rationalization of our infrastructure base. During the latter half of 2009, we closed several facilities and consolidated others in order to more efficiently serve our customers and reduce costs. Throughout 2010 we will continue to assess the size and compensation levels of our workforce to ensure that we can take advantage of any recovery that may occur during the near term, and we believe that this rationalization process will serve to better position us to take advantage of those opportunities. However, some portion of the temporary cost cutting measures that we put into place during 2009 may be discontinued as activity levels in the market increase, and the need to bring these costs back into our operations is required. Additionally, we are exploring several opportunities to expand our services internationally and feel that our liquidity will be sufficient to take advantage of any attractive acquisition opportunities, should those develop.

Impact of Inflation on Operations

 

We are of the opinion that inflation has not had a significant impact on our business.

RESULTS OF OPERATIONS

 

Consolidated Results of Operations

 

The following table shows our consolidated results of operations for the years ended December 31, 2009, 2008 and 2007:

 

 

Year Ended December 31, 2009 and 2008

 

For the year ended December 31, 2009, our net loss was $156.1 million, compared to net income of $84.1 million for the year ended December 31, 2008. Our loss per diluted share for 2009 was $1.29 per share compared to earnings per diluted share 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, or $0.34 per diluted share) and an impairment of the carrying value of our pressure pumping equipment ($93.4 million pre-tax or $0.49 per diluted share). Also contributing to the net loss was the dramatic and rapid decline in our activity levels and our inability to reduce costs at the same pace as the decline in our revenues.

 

Revenues

 

Our revenues for the year ended December 31, 2009 decreased $893.4 million, or 45.3% to $1.1 billion from $2.0 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 $470.9 million, or 37.7%, to $779.5 million (72.3% of revenues) for the year ended December 31, 2009, compared to $1.3 billion (63.4% 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 $1.2 million, or 0.7%, to $169.6 million (15.7% of revenue) during the year ended December 31, 2009, compared to $170.8 million (8.7% of revenue) for the year ended December 31, 2008. 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 in depreciation are increases due to accelerated depreciation for assets that we removed from service during the first half of 2009 in response to the downturn in market conditions, as well as a larger fixed asset base in 2009 due to our capital spending in 2008.

 

General and administrative expenses

 

General and administrative expenses decreased $79.0 million, or 30.7%, to $178.7 million (16.6% of revenues) for the year ended December 31, 2009, compared to $257.7 million (13.1% of revenues) for the year ended December 31, 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.

 

Asset retirements and impairments

 

During the year ended December 31, 2009, we recognized $159.8 million in pre-tax charges associated with asset retirements and impairments, compared to $75.1 million for the year ended December 31, 2008. For 2009, our pre-tax charges included $65.9 million related to the retirement of certain of our rigs and associated equipment. Additionally, we identified events and changes in circumstance indicating that the carrying amounts of certain of our asset groups may not be recoverable. Accordingly, we performed a recoverability assessment by comparing the estimated future cash flows for these asset groups to the asset groups’ estimated carrying value. The completion of this test indicated that the carrying value of our pressure pumping equipment was not recoverable and resulted in the recording of a $93.4 million pre-tax impairment charge in our Production Services segment. We also 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.

 

Upon completion of our annual goodwill impairment test in 2008, there were indicators that the goodwill of our pressure pumping services and fishing and rental services lines of business within our Production Services segment might be impaired. We calculated the implied fair value of these lines of business and determined that the implied fair value was less than the carrying value of the goodwill, meaning that the goodwill was impaired. As a result, during the fourth quarter of 2008, we recorded a pre-tax charge of $69.8 million to write off the goodwill balances of our pressure pumping services and fishing and rental services lines of business within our Production Services segment.

 

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.

 

Interest expense, net of amounts capitalized

 

Interest expense decreased $2.2 million for the year ended December 31, 2009, compared to the same period in 2008. The decline is 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

 

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

 

 

In connection with the amendment of our Senior Secured Credit Facility in the fourth quarter of 2009, we recorded a loss on the early extinguishment of debt of $0.5 million.

 

Income tax benefit (expense)

 

Our income tax benefit was $91.1 million (36.8% effective rate) on a pre-tax loss of $247.8 million for the year ended December 31, 2009, compared to income tax expense of $90.2 million (51.8% effective rate) on pre-tax income of $174.1 million in 2008. 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.

 

Year Ended December 31, 2008 and 2007

 

For the year ended December 31, 2008, our net income was $84.1 million, a 50.3% decrease from net income of $169.3 million for the year ended December 31, 2007. Our earnings per diluted share for the year were $0.67 per share compared to $1.27 per share for the same period in 2007. Items contributing to the decline in net income and diluted earnings per share during 2008 included an impairment of our goodwill ($69.8 million pre- tax, or $0.54 per diluted share); a charge associated with the acceleration of the vesting of certain of our equity awards ($10.9 million pre-tax, or $0.05 per diluted share); an impairment of our investment in IROC ($5.4 million pre-tax, or $0.03 per diluted share); severance charges associated with a reduction in our domestic and international workforce ($2.6 million pre-tax, or $0.01 per diluted share); and the impact of hurricanes and their after-effects along the U.S. Gulf Coast during the third quarter of 2008 (estimated to have decreased our pre-tax earnings by $8.4 million, or $0.04 per diluted share). Partially offsetting these items were price increases implemented during the second and third quarters of 2008, incremental net income from acquisitions we completed during 2008, the full-year effect of acquisitions completed during 2007, and expansion of our wireline operations and operations in Mexico.

 

Revenues

 

Our revenues for the year ended December 31, 2008 were $2.0 billion, an increase of $310.1 million, or 18.7%, from $1.7 billion for the year ended December 31, 2007. See “Segment Operating Results — Year Ended December 31, 2008 and 2007” below for a more detailed discussion of the change in our revenues.

Direct operating expenses

 

Our direct operating expenses increased $264.7 million, or 26.9%, to $1.3 billion (63.4% of revenues) for the year ended December 31, 2008 compared to $985.6 million (59.3% of revenues) for the year ended December 31, 2007. See “Segment Operating Results — Year Ended December 31, 2008 and 2007” below for a more detailed discussion of the change in our direct operating expenses.

 

Depreciation and amortization expense

 

Depreciation and amortization expense increased $41.2 million, or 31.7%, to $170.8 million (8.7% of revenues) for the twelve months ended December 31, 2008 compared to $129.6 million (7.8% of revenues) for the same period in 2007. Acquisitions we completed during 2008 contributed $6.6 million to the increase and the full-year effect of acquisitions completed during 2007 during 2008 contributed $24.1 million. The remaining $10.5 million increase can be attributed to a larger fixed asset base.

 

General and administrative expenses

 

General and administrative expenses were $257.7 million (13.1% of revenues) for the year ended December 31, 2008, which represented an increase of $27.3 million, or 11.9%, over $230.4 million (13.9% of revenues) for the same period in 2007. Our general and administrative expenses increased as a result of increases in non-equity employee compensations costs due to pay rate increases throughout 2008, incremental costs from acquisitions completed during 2008, and the full-year effect of acquisitions completed in 2007. In addition, during the fourth quarter of 2008, we accelerated the vesting period on certain of our outstanding unvested stock option and SAR awards, resulting in a charge to general and administrative expenses. Partially offsetting this increase were declines in professional fees as a result of our emerging from our delayed financial reporting process and becoming current with our SEC filings and being re-listed on a national stock exchange during 2007.

 

Asset retirements and impairments

 

Upon completion of our annual goodwill impairment test in 2008, there were indicators that the goodwill of our Production Services segment might be impaired. We calculated the implied fair value of the goodwill for the Production Services segment and determined that the implied fair value was less than the carrying value of the goodwill, meaning that the goodwill was impaired. As a result, during the fourth quarter of 2008 we recorded a pre-tax charge of $69.8 million to goodwill for the Production Services segment. Management believed that the goodwill of these segments was impaired because of the economic downturn in the second half of 2008 and deterioration in the global credit markets and specifically the downturn in the oilfield services sector, which resulted in a decline in our stock price and market valuation during this period.

 

During 2008, the fair value of our investment in 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. 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.

 

Interest expense, net of amounts capitalized

 

Our interest expense increased $5.0 million, or 13.9%, to $41.2 million for the twelve months ended December 31, 2008 compared to $36.2 million for the same period in 2007. Higher overall debt levels led to the increase in interest expense.

Other, net

 

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

 

 

In the fourth quarter of 2007 we issued the Senior Notes (defined below). We used the proceeds of the Senior Notes to repay all outstanding amounts under our previous credit facility, and replaced that facility with our current Senior Secured Credit Facility. In connection with these transactions, we wrote off the unamortized debt issuance costs associated with the previous credit facility, resulting in a loss on the early extinguishment of debt of $9.6 million.

 

Income tax expense

 

Our income tax expense was $90.2 million (51.8% effective rate) for the year ended December 31, 2008, compared to $106.8 million (38.7% effective rate) for the year ended December 31, 2007. The decrease in income tax expense is primarily attributable to lower pre-tax income in 2008. The increase in our effective tax rate was primarily attributable to the portion of the impairment of our goodwill that was non-deductible for income tax purposes in 2008. The 2008 effective tax rate excluding the goodwill impairment would have been 38.0%. Other differences in the effective tax rate and the statutory rate of 35.0% result primarily from the effect of state and certain foreign income taxes and permanent items attributable to book-tax differences.

 

Segment Operating Results

 

We revised our reportable business segments effective in the first quarter of 2009. The new operating segments are Well Servicing and Production Services. Financial results for the years ended December 31, 2008 and 2007 have been recast to reflect the change in reportable segments. We revised our segments to reflect changes in management’s resource allocation and performance assessment in making decisions regarding our operations. Our rig services and fluid management services operations are now aggregated within our Well Servicing segment. Our pressure pumping services, fishing and rental services and wireline services operations, as well as our technology development group in Canada, are now aggregated within our Production Services segment. We also have a reportable segment titled Functional Support that includes expenses associated with managing our operating segments. For a full description of our segments, see “Service Offerings” in “Item 1. Business.”

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 is 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 were 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 towards lower margin repair and maintenance work, and much of this work was being 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) in 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 $282.8 million, or 56.4%, to $218.9 million for the year ended December 31, 2009, compared to $501.8 million for 2008. The overall decline in revenue for this segment is 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. 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 $166.9 million, or 41.0%, to $240.6 million (109.9% of revenues) for the year ended December 31, 2009, compared to $407.6 million (81.2% of revenues) in 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 declined $51.2 million to $105.6 million (9.8% of revenues) for the year ended December 31, 2009, compared to $156.8 million (8.0% of 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.

 

Year Ended December 31, 2008 and 2007

 

The following table shows operating results for each of our reportable segments for the twelve month periods ended December 31, 2008 and 2007 (in thousands, except for percentages):

 

 

 

Well Servicing

 

Revenues for our Well Servicing segment increased $230.2 million, or 18.6%, to $1.5 billion for the year ended December 31, 2008, compared to $1.2 billion for the year ended December 31, 2007. The increase in revenues was primarily attributable to the Well Serving segment acquisitions that we completed during 2008, the full year impact of the acquisitions we completed during 2007, the expansion of our operations for PEMEX in Mexico, and price increases we implemented during the second and third quarters of 2008 across most of the markets in which we operate. Partially offsetting these increases in revenues for the Well Servicing segment during 2008 were the effects of hurricanes Ike and Gustav during the third quarter, which restricted our well servicing operations in Texas, Louisiana, and Oklahoma.

 

Operating expenses for our Well Servicing segment were $1.1 billion (75.8% of revenues) during the year ended December 31, 2008, which represented an increase of $235.2 million, or 26.7%, compared to $0.9 million (70.9% of revenues) for 2007. Operating expenses for our Well Servicing segment increased in 2008 compared to 2007 due to acquisitions we made in 2008 and the full year effect of the acquisitions we

completed during 2007, higher per-gallon prices for fuel, higher costs for self-insurance due to increased headcount, higher repair and maintenance expenses due to higher activity levels in 2008, and the expansion of our operations in Mexico.

 

Production Services

 

Revenues for our Production Services segment increased $79.9 million, or 18.9%, to $501.8 million for the year ended December 31, 2008, compared to $421.9 million for 2007. The increase in revenues was driven primarily by incremental revenue from acquisitions we made during 2008, organic growth of our pressure pumping equipment fleet, the expansion of our wireline operations, and price increases that we implemented during the second and third quarters of 2008. Partially offsetting the increase in revenues were the effects of hurricanes along the U.S. Gulf Coast during the third quarter of 2008.

 

Excluding charges for asset impairments, operating expenses for our Production Services segment increased $91.6 million, or 29.0%, to $407.6 million (81.2% of revenues) for the year ended December 31, 2008, compared to $315.9 million (74.9% of revenues) for 2007. The increase in operating expenses for our Production Services segment was driven primarily by incremental operating expenses associated with the acquisitions we made during 2008, increased costs for frac sand and chemicals used in our pressure pumping operations, additional employee compensation associated with the increase in the number of frac crews, and the expansion of our wireline operations.

 

Functional Support

 

Excluding charges for asset impairments, operating expenses for Functional Support increased $6.4 million to $156.8 million, or (8.0% of revenues) for the year ended December 31, 2008, compared to $150.4 million (9.1% of revenues) for 2007. Functional Support operating expenses increased in 2008 due to headcount and pay rate increases we made during the first three quarters of 2008, the effects of acquisitions we made during 2008, and increased equity-based compensation associated with the charge we took during the fourth quarter of 2008 in connection with the acceleration of the vesting period on the majority of our stock option and SAR awards.

 

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 cash equivalents, and availability under our Senior Secured Credit Facility. In addition, we expect to receive an income tax refund of approximately $50.0 million in 2010. We intend to use these sources of liquidity to fund our working capital requirements, capital expenditures, strategic investments and acquisitions. As part of our business strategy, we regularly evaluate acquisition opportunities, including equipment and businesses.

 

We believe that our internally generated cash flows from operations and current reserves of cash and cash equivalents are sufficient to finance the majority of our cash requirements for operations, budgeted capital expenditures and debt service for the next twelve months. As we have historically done, we may, from time to time, 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.

 

As of December 31, 2009, we had working capital of $204.5 million, excluding the current portion of long-term debt, notes payable to related parties, and capital lease obligations totaling $10.2 million. Working capital at December 31, 2008 was $311.5 million, excluding the current portion of long-term debt, notes payable to related parties, and capital lease obligations totaling $25.7 million. Our working capital at December 31, 2009 decreased from 2008 as a result of decreased cash and cash equivalents, due primarily to the repayment of $100.0 million on our revolving credit facility, and decreased accounts receivable due to

lower revenues during the period. Partially offsetting these declines were higher income tax receivables due to our current taxable losses, lower accounts payable and lower accrued expenses due to the decline in our activity levels.

 

As of December 31, 2009, we had $37.4 million of cash and cash equivalents. Of this amount, up to $0.9 million of our accounts were guaranteed by the Federal Deposit Insurance Corporation (“FDIC”), including under the FDIC’s Temporary Liquidity Guarantee Program. On January 1, 2010, the lending institution where this amount was held discontinued its participation in the FDIC Temporary Liquidity Guarantee Program. As of December 31, 2009, approximately $18.6 million of our cash and cash equivalents was held in the bank accounts of our foreign subsidiaries. Of this amount, approximately $10.9 million was held by our Russian subsidiary, which is subject to a noncontrolling interest. Approximately $1.0 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, 2009, $87.8 million of borrowings and $55.2 million of letters of credit were outstanding under our Senior Secured Credit Facility. As of December 31, 2009, we had $156.9 million of availability under the facility. Under the terms of the Senior Secured Credit Facility, committed letters of credit count against our borrowing capacity. All obligations under the Senior Secured Credit Facility are guaranteed by most of our subsidiaries and are secured by most of our assets, including our accounts receivable, inventory and equipment. The weighted average interest rate on the outstanding borrowings of the Senior Secured Credit Facility was 3.73% at December 31, 2009. See further discussion under “Debt Service — Senior Secured Credit Facility.” As of February 17, 2010, we had $55.2 million of letters of credit issued under the letter of credit sub-facility and approximately $533.4 million of total debt, notes payable and capital leases. As of February 17, 2010 we had cash and cash equivalents of $27.2 million and available borrowing capacity of $156.9 million under our Senior Secured Credit facility. As of February 17, 2010, approximately $13.0 million of our cash and cash equivalents was held in the bank accounts of our foreign subsidiaries, with $0.6 million of that amount being held in U.S. bank accounts and denominated in U.S. Dollars. Except for the amounts held by our Russian subsidiary, we believe that these balances could be repatriated for general corporate use without material withholdings.

 

Cash Flows

 

During the year ended December 31, 2009, we generated cash flows from operating activities of $184.8 million, compared to $367.2 million for the year ended December 31, 2008. Operating cash inflows for 2009 primarily relate to the collection of accounts receivable, partially offset by our overall net loss for the period, as well as by cash paid against accounts payable and other liabilities. Our operating cash flow declined primarily as a result of lower net income for the period, which is attributable to the decrease in our activity levels and pricing during 2009.

 

Cash used in investing activities was $110.6 million and $329.1 million for year ended December 31, 2009 and 2008, respectively. Investing cash flows during the year ended December 31, 2009 consisted primarily of capital expenditures and our second investment in Geostream, which were financed through cash on hand and cash generated by our operations. Investing cash flows declined from 2008 due to lower capital expenditures and lower net cash paid for acquisitions during the current period.

 

Cash used in financing activities was $127.5 million during the year ended December 31, 2009 and $8.0 million for 2008. Financing cash flows during 2009 consisted primarily of the repayment of $100.0 million on the outstanding principal balance of our Senior Secured Credit Facility during the second quarter, which was paid through the use of existing cash on hand and cash generated by our operations, and the lump sum repayment of a Related Party Note totaling $12.5 million in the fourth quarter. Financing cash outflows increased during the year ended December 31, 2009 as we did not borrow on our Senior Secured Credit Facility, partially offset by lower cash paid to repurchase our common stock as our share repurchase program expired on March 31, 2009.

The following table summarizes our cash flows for the year ended December 31, 2009 and 2008:

 

 

Debt Service

 

During the third quarter of 2009, we amended our Senior Secured Credit Facility to reduce total credit commitments under the facility from $400.0 million to $300.0 million. See “Senior Secured Credit Facility” below for further detail. At December 31, 2009, our annual debt maturities for our Senior Notes (defined below), borrowings under our Senior Secured Credit Facility, notes payable to related parties and other indebtedness are as follows:

 

 

Our revolving Senior Secured Credit Facility matures in November 2012. In May 2009, we repaid $100.0 million on the outstanding balance of the revolving credit facility. In October 2009, we made principal payments totaling $14.5 million, plus accrued interest, related to the Related Party Notes. These payments represent a lump sum repayment of one Related Party Note totaling $12.5 million and a $2.0 million annual installment payment on the second Related Party Note. 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 2009 was $35.6 million. Interest on the Senior Notes due in 2010 will be $35.6 million. We expect to fund interest payments from cash on hand and cash generated by operations.

 

8.375% Senior Notes

 

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

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

 

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

 

 

In addition, at any time and from time to time before December 1, 2010, we have the option to redeem up to 35% of the aggregate principal amount of the outstanding Senior Notes at a redemption price of 108.375%, plus accrued and unpaid interest to the redemption date, with the net cash proceeds of one or more equity offerings, provided that at least 65% of the aggregate principal amount of the Senior Notes issued under the Indenture remains outstanding immediately after each such redemption. These redemptions must occur within 180 days of the date of the closing of the equity offering.

 

In addition, at any time and from time to time prior to December 1, 2011, we may, at our option, redeem all or a portion of the Senior Notes at a redemption price equal to 100% of the principal amount, plus the Applicable Premium (as defined in the Indenture) with respect to the Senior Notes plus accrued and unpaid interest to the redemption date. If we experience a change of control, subject to certain exceptions, we must give holders of the 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, 2009, 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.

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. We entered into the Senior Secured Credit Facility on November 29, 2007, simultaneously with the offering of the Senior Notes, and entered into an amendment (the “Amendment”) to the Senior Secured Credit Facility on October 27, 2009. As amended, the Senior Secured Credit Facility consists of a revolving credit facility, letter of credit sub-facility and swing line facility, up to an aggregate principal amount of $300.0 million, all of which will mature no later than November 29, 2012.

 

The Amendment we entered into in the fourth quarter of 2009 reduced the total credit commitments under the facility from $400.0 million to $300.0 million, effected by a pro rata reduction of the commitment of each lender under the facility. We have the ability to request increases in the total commitments under the facility by up to $100.0 million in the aggregate, with any such increases being subject to certain requirements as well as lenders’ approval. Pursuant to the Amendment, we also modified the applicable interest rates and some of the financial covenants, among other changes.

 

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

 

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

 

 

 

 

 

In addition, the amended Senior Secured Credit Facility contains certain affirmative covenants, including, without limitation, restrictions related to (i) liens; (ii) debt, guarantees and other contingent obligations; (iii) mergers and consolidations; (iv) sales, transfers and other dispositions of property or assets; (v) loans, acquisitions, joint ventures and other investments; (vi) dividends and other distributions to, and redemptions and repurchases from, equity holders; (vii) prepaying, redeeming or repurchasing the Senior Notes or other unsecured debt incurred pursuant to the sixth bullet point listed above; (viii) granting negative pledges other than to the lenders; (ix) changes in the nature of our business; (x) amending organizational documents, or amending or otherwise modifying any debt if such amendment or modification would have a material adverse effect, or amending the Senior Notes or any other unsecured debt incurred pursuant to the sixth bullet point listed above if the effect of such amendment is to shorten the maturity of the Senior Notes or such other 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. In connection with the Amendment, we wrote off a proportionate amount of the unamortized deferred financing costs associated with the capacity reduction of the credit facility. During the year ended December 31, 2009, we recognized $0.5 million in pre-tax charges in losses on extinguishment of debt associated with the write-off of unamortized deferred financing costs and capitalized $2.5 million in costs associated with the amendment of our Senior Secured Credit Facility.

 

Related Party Notes Payable

 

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

 

Capital Lease Agreements

 

We lease equipment, such as vehicles, tractors, trailers, frac tanks and forklifts, from financial institutions under master lease agreements. As of December 31, 2009, there was approximately $14.3 million outstanding under such equipment leases.

Off-Balance Sheet Arrangements

 

At December 31, 2009, 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, 2009. 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.

 

 

 

 

We believe that our internally generated cash flows from operations and current reserves of cash and cash equivalents are sufficient to finance the majority of our cash requirements for current and future operations, budgeted capital expenditures and debt service for 2010. As we have historically done, we may, from time to time, access available funds under our Senior Secured Credit Facility to supplement our liquidity to meet cash requirements for day to day operations and times of peak needs throughout the year. Our planned capital expenditures as well as any acquisitions we choose to pursue, are expected to be financed through a

combination of cash on hand, cash flow from operations and borrowings under our Senior Secured Credit Facility.

 

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, 2009, we were in compliance with all the financial covenants under the Senior Secured Credit Facility, as amended, 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 the covenants, ratios or tests under our debt could result in a default under our indebtedness. See “Item 1A. Risk Factors.”

 

Capital Expenditures

 

During the year ended December 31, 2009, our capital expenditures totaled $128.4 million, mostly related to the expansion of our operations in Mexico and Russia, drill strings and nitrogen units for our rental operations, capitalized costs for new information systems, asset acquisitions for our fluids management operations, and maintenance of our existing fleet. Our capital expenditures program is expected to total approximately $140.0 million during 2010, focusing mainly on the maintenance of our fleet. Our capital expenditure program for 2010 is subject to market conditions, including activity levels, commodity prices and industry capacity. Our focus for 2010 will be the maximization of our current equipment fleet, but we may choose to increase our capital expenditures in 2010 to increase market share or expand our presence into a new market. We currently anticipate funding our 2010 capital expenditures through a combination of cash on hand, operating cash flow, 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.

 

Geostream Investment

 

On September 1, 2009, we acquired an additional 24% interest in Geostream for approximately $16.4 million. Geostream is an oilfield services company in the Russian Federation providing drilling and workover services and sub-surface engineering and modeling in Russia. This was our second investment in Geostream pursuant to an agreement dated August 26, 2008, as amended. This second investment brings our total investment in Geostream to 50%. Upon acquiring the 50% interest, we also obtained majority representation on Geostream’s board of directors and therefore a controlling interest. The results of Geostream have been included in our consolidated financial statements since the acquisition date. As a result of this acquisition, we expect to expand our international presence in Russia where the wells are shallow and are suited to the services that we perform.

 

The fair value of the consideration transferred for the 50% interest in Geostream totaled approximately $35.0 million, which consisted of cash consideration in the second investment on September 1, 2009 and the fair value of our previous equity interest. In conjunction with the second investment, Geostream agreed to purchase from us a customized suite of equipment, including two workover rigs, two drilling rigs, associated complementary support equipment, cementing equipment, and fishing tools for approximately $23.0 million, a portion of which will be financed by us. Concurrent with the second investment, Geostream paid us approximately $16.0 million in cash, representing a down payment on the equipment we will deliver to them. We began delivery of the equipment under the purchase agreement during the fourth quarter of 2009.

 

Under the Geostream agreement, as amended, for a period not to exceed six years subsequent to October 31, 2008, we have the option to increase our ownership percentage of Geostream to 100%. However,

if we have not acquired 100% of Geostream on or before the end of the six-year period, we will be required to arrange an initial public offering for those shares.

 

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:

 

 

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 for physical damage to our equipment and automobiles. Our accruals that we maintain on our consolidated balance sheet relate to 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 appropriate liabilities recorded 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 12. 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. During 2009, because of our international expansion in Russia, acquisitions we made in prior years, and the overall economic downturn that affected all companies’ stock prices and market valuation, we assigned more weight to the discounted cash flow method. We also weighted the discounted cash flow method more heavily in 2008 for similar reasons. In prior years, we had assigned more weight to the guideline companies 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, 2009. On that date, our rig services reporting unit had $298.6 million of goodwill, our fluid management services reporting unit had $18.6 million of goodwill, and AMI had $4.1 million of goodwill. Our pressure pumping services, fishing and rental services, and wireline services reporting units did not have any goodwill, because either all of the goodwill for those reporting units had been impaired in prior periods or the reporting unit had been created entirely through organic growth. The $24.8 million of goodwill associated with our acquisition of Geostream was not included in this annual assessment due to the specific nature of the transaction giving rise to the goodwill and the recent nature of the fair value assessment in connection with the acquisition. Based on the results of our annual test, the fair value of our reporting units that have goodwill substantially exceeded their carrying values. Because the fair value of those 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, 2009, and that step two of the impairment test was not required.

 

As noted above, the determination of the fair value of our reporting units is heavily dependent upon certain estimates and assumptions that we make about our reporting units. While the estimates and assumptions that we made regarding our reporting units for our 2009 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.

 

As discussed in “Note 7. Goodwill and Other Intangible Assets” in “Item 8. Financial Statements and Supplementary Data,” during the third quarter of 2009, we identified a triggering event that required us to test our goodwill for impairment on an interim basis. As a result of that test, we determined that the goodwill associated with our fishing and rental services reporting unit was impaired, and recorded a pre-tax charge of $0.5 million to write off the goodwill associated with that reporting unit.

 

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.

 

As discussed in “Note 6. Property, Plant and Equipment” in “Item 8. Financial Statements and Supplementary Data,” during the third quarter of 2009 we retired a portion of our U.S. rig fleet and associated support equipment. We identified this as a trigger event that required us to test our well servicing fixed assets for impairment. Based on our analysis, the expected undiscounted cash flows for these assets exceeded their carrying value, and no indication of impairment existed, and we do not feel that material adverse changes in our estimates or assumptions such that our well servicing assets’ carrying value exceeded their fair value is reasonably possible.

 

However, during the third quarter of 2009, due to continuing market overcapacity, continued and prolonged depression of natural gas prices, decreased activity levels from our major customer base related to stimulation work and consecutive quarterly operating losses, we determined that events and changes in circumstances occurred indicating that the carrying value of the assets in our Production Services segment may not have been recoverable. We performed an assessment of the fair value of these asset groups using an expected present value technique based on undiscounted cash flows. We used discounted cash flow models involving assumptions based on the utilization of the equipment, revenues, expenses, capital expenditures and working capital requirements. Our discounted cash flow projections were based on financial forecasts and were discounted using a discount rate of 14%. Based on this assessment, the fair value of our pressure pumping assets was less than their carrying value, and this resulted in the recording of a pre-tax impairment charge of $93.4 million during the third quarter of 2009.

The impairment tests for our well servicing and pressure pumping assets also triggered an interim test of our goodwill and indefinite-lived intangible assets for potential impairment during the third quarter of 2009. We did not identify any trigger events causing us to test our tangible and finite-lived intangible assets for impairment during the first, second, or fourth quarters of 2009.

 

Valuation of Equity-Based Compensation

 

We have granted stock options, stock-settled stock appreciation rights (“SARs”), restricted stock (“RSAs”), and phantom shares (“Phantom Shares”) 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. See “Note 18. 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 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, 2008 and 2007:

 

 

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. However, a 10 percent increase in our expected volatility and risk-free rate at the grant date would have increased our compensation expense for the year ended December 31, 2009 by less than $0.1 million.

 

New Accounting Standards Adopted in this Report

 

SFAS 141(R).  In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141 (Revised 2007), Business Combinations (“SFAS 141(R)”). SFAS 141(R) establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial

statements the identifiable assets acquired, liabilities assumed, and any noncontrolling interests in the acquiree, as well as the goodwill acquired. Significant changes from previous practice resulting from SFAS 141(R) include the expansion of the definitions of a “business” and a “business combination.” For all business combinations (whether partial, full or step acquisitions), the acquirer will record 100% of all assets and liabilities of the acquired business, including goodwill, generally at their fair values; contingent consideration will be recognized at its fair value on the acquisition date and, for certain arrangements, changes in fair value will be recognized in earnings until settlement; and acquisition-related transaction and restructuring costs will be expensed rather than treated as part of the cost of the acquisition. SFAS 141(R) also establishes disclosure requirements to enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) applies prospectively to 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, 2008. The Company adopted the provisions of SFAS 141(R) on January 1, 2009, but did not consummate any business combinations during the three months ended March 31, 2009. SFAS 141(R) may have an impact on our consolidated financial statements in the future. The nature and magnitude of the specific impact will depend upon the nature, terms, and size of any acquisitions consummated after the effective date.

 

SFAS 160.  In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — An amendment of ARB No. 51 (“SFAS 160”). SFAS 160 amends Accounting Research Bulletin No. 51, Consolidated Financial Statements , to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is a third-party ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 requires the consolidated statement of income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. SFAS 160 also requires disclosure on the face of the consolidated statement of income of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. We adopted the provisions of SFAS 160 on January 1, 2009. The adoption of this standard did not have a material impact on our financial position, results of operations, or cash flows.

 

SFAS 165.  In May 2009, the FASB issued SFAS No. 165, Subsequent Events (“SFAS 165”). SFAS 165 establishes general standards of accounting for and disclosing of events that occur after the balance sheet date but before the financial statements are issued or are available to be issued. SFAS 165 does not significantly change the types of subsequent events that an entity reports, but it requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. SFAS 165 is effective for interim or annual reporting requirements ending after June 15, 2009. The adoption of this standard did not have a material impact on our financial position, results of operations or cash flows.

 

ASU 2009-01.  In June 2009, the FASB issued Accounting Standards Update (“ASU”) 2009-01, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles — a replacement of FASB Statement No. 162 (“ASU 2009-01”). ASU 2009-01 established the Accounting Standards Codification (the “Codification”) as the source of authoritative GAAP recognized by the FASB to be applied to nongovernmental entities. The Codification supersedes all prior non-SEC accounting and reporting standards. Following ASU 2009-01, the FASB will not issue new accounting standards in the form of FASB Statements, FASB Staff Positions, or Emerging Issues Task Force abstracts. ASU 2009-01 also modifies the existing hierarchy of GAAP to include only two levels — authoritative and non-authoritative. ASU 2009-01 is effective for financial statements issued for interim and annual periods ending after September 15, 2009, and early adoption was not permitted. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows.

 

ASU 2009-05.  In August 2009, the FASB issued ASU 2009-05, Fair Value Measurements and Disclosures (Topic 820) — Measuring Liabilities at Fair Value (“ASU 2009-05”). ASU 2009-05 addresses concerns in situations where there may be a lack of observable market information to measure the fair value of a liability, and provides clarification in circumstances where a quoted market price in an active market for an identical liability is not available. In these cases, reporting entities should measure fair value using a valuation technique that uses the quoted price of the identical liability when that liability is traded as an asset,

quoted prices for similar liabilities, or another valuation technique, such as an income or market approach. ASU 2009-05 also clarifies that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents the transfer of the liability. ASU 2009-05 is effective for the first reporting period subsequent to August 2009 and the adoption of this update did not have a material impact on our financial position, results of operations, or cash flows.

 

Accounting Standards Not Yet Adopted in this Report

 

SFAS 166.  In June 2009, the FASB issued SFAS No. 166, Accounting for Transfers of Financial Assets, an amendment of FASB Statement No. 140 (“SFAS 166”). SFAS 166 amends the application and disclosure requirements of SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities — a Replacement of FASB Statement 125 (“SFAS 140”), removes the concept of a “qualifying special purpose entity” from SFAS 140 and removes the exception from applying FASB Interpretation (“FIN”) No. 46(R), Consolidation of Variable Interest Entities — an Interpretation of ARB No. 51 (“FIN 46(R)”) to qualifying special purpose entities. SFAS 166 is effective for the first annual reporting period that begins after November 15, 2009, and early adoption is not permitted. The adoption of this standard is not anticipated to have a material impact on our financial position, results of operations or cash flows.

 

SFAS 167.  In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No. 46(R) (“SFAS 167”). SFAS 167 amends the scope of FIN 46(R) to include entities previously considered qualifying special-purpose entities by FIN 46(R), as the concept of a qualifying special-purpose entity was eliminated in SFAS 166. This standard shifts the guidance for determining which enterprise in a Variable Interest Entity consolidates that entity from a quantitative consideration of who is the primary beneficiary to a qualitative focus of which entity has the power to direct activities and the obligation to absorb losses. This standard is to be effective for the first annual reporting period that begins after November 15, 2009, and early adoption is not permitted. The adoption of this standard is not anticipated to have a material impact on our financial position, results of operations or cash flows.

 

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 expect to adopt the provisions of ASU 2009-13 on January 1, 2011 and do not believe that the adoption of this standard will have a material impact on our financial position, results of operations, or cash flows.

 

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 expect to adopt 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 2009-17.  In December 2009, the FASB issued ASU 2009-17, Consolidations (Topic 810) — Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities. ASU 2009-17 replaces the quantitative-based risk and rewards calculation for determining which reporting entity, if any, has a controlling financial interest in a variable interest entity with an approach focused on identifying which reporting entity has the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance and (1) the obligation to absorb losses of the entity or (2) the right to receive benefits from the entity. An approach that is expected to be primarily qualitative will be more effective for identifying which reporting entity has a controlling financial interest in a variable interest entity. ASU 2009-17 also requires additional disclosures about a reporting entity’s involvement in variable interest entities. The provisions of ASU 2009-17 are to be applied beginning in the first fiscal period beginning after November 15, 2009. We will adopt ASU 2009-17 on January 1, 2010 and do not anticipate that the adoption of this standard will 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 will be effective for us for the first reporting period beginning after December 13, 2009. We will adopt the provisions of ASU 2010-02 on January 1, 2010 and do not anticipate that the adoption of this standard will have a material impact on our financial position, results of operations, or cash flows.

 

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

purchases, sales, issuances and settlements of fair value measurements with significant unobservable inputs. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009. We will adopt the provisions of ASU 2010-06 on January 1, 2010 and do not expect that the adoption of this standard will 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, 2009, 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, our capital lease obligations, and our Related Party Notes all bear interest at variable interest rates, and therefore expose us to interest rate risk. As of December 31, 2009, the weighted average interest rate on our outstanding variable-rate debt obligations was 3.24%. A hypothetical 10% increase in that rate would increase the annual interest expense on those instruments by approximately $0.4 million.

 

Foreign Currency Risk

 

As of December 31, 2009, we conduct operations in Argentina, Mexico, the Russian Federation, and also own Canadian subsidiaries and have equity-method investments in two Canadian companies. The functional currency is the local currency for all of these entities, 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 $0.2 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, 2009 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, 2009 and 2008, 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, 2009. 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 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), the effectiveness of Key Energy Services, Inc. and Subsidiaries’ internal control over financial reporting as of December 31, 2009, 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 26, 2010, expressed an unqualified opinion on the effectiveness of internal control over financial reporting.

 

 

Houston, Texas

February 26, 2010

 

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, 2009, 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 the accompanying Management’s Report on Internal Control Over Financial Reporting. 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, 2009, 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 26, 2010, expressed an unqualified opinion on those consolidated financial statements.

 

 

Houston, Texas

February 26, 2010

 

Key Energy Services, Inc. and Subsidiaries

 

CONSOLIDATED BALANCE SHEETS