Key Energy Services Inc.
Annual Report 2008

Plain-text annual report

Planned Performance. 2008 Annual Report Revenue Revenue (in millions) (in millions) $2,000 $2,000 $1,500 $1 500 $1,000 $500 Revenue growth rate (%) Revenue growth rate (%) 30 30 20 10 2006 2007 2008 2006 2007 2008 Net income (in millions) Shareholders’ equity (in millions) $200 $150 $100 $50 $1,000 $800 $600 $400 $200 2006 2007 2008 2006 2007 2008 Employee turnover (%) Safety record (TRIR = Total Recordable Incident Rate. A lower number is desirable) 50 40 30 20 3.0 2.5 2.0 2006 2007 2008 2006 2007 2008 Financial Highlights (in thousands, except per share data) Revenues Direct expenses Year Ended December 31, 2006 Year Ended December 31, 2007 Year Ended December 31, 2008 $ 1,546,177 $ 1,662,012 $ 1,972,088 920,602 985,614 1,250,327 Depreciation and amortization 126,011 129,623 170,774 Impairment of goodwill and equity method investment — — 75,137 General and administrative expenses 195,527 230,396 257,707 Interest expense Other, net Income from continuing operations before income taxes and minority interest Income tax expense Minority interest 38,927 36,207 41,247 (9,370) 4,232 2,840 274,480 275,940 174,056 (103,447) (106,768) (90,243) 0 117 245 Net income $ 171,033 $ 169,289 $ 84,058 Net income per common share Basic Diluted Total assets Total debt $ $ 1.30 $ 1.29 $ 0.68 1.28 $ 1.27 $ 0.67 $ 1,541,398 $ 1,859,077 $ 2,016,923 $ 421,794 $ 523,993 $ 659,295 Shareholders’ equity $ 730,511 $ 888,998 $ 860,732 2008 Annual Report | 1 Dear Shareholder, Dear Shareholder, In normal times, annual shareholder letters In normal times, annual shareholder letters are typically lists of highlights accompanied are typically lists of highlights accompanied by craftily worded depictions of the initiatives and by craftily worded depictions of the initiatives and strategies that underlie corporate performance. strategies that underlie corporate performance. These times are anything but normal and, while These times are anything but normal and, while we do include some accomplishments on the facing page, I thought you might appreciate some straight talk about the current conditions in Key’s markets, what we are doing to address them and the opportunities they will create. In the second half of 2008, we witnessed extremes in the fundamental drivers of our business. At record-setting speed, oil prices went from all-time highs to levels at which our customer base began to severely curtail capital expenditures. Natural gas futures followed generally the same path. Th e dramatic decline in capital expenditures has caused a cliff -drop in U.S. drilling activity. Th is energy shutdown, over-arched by the global fi nancial crisis, brought a new twist in our customers’ reaction to the fall in commodity prices. In addition to focusing their spending cuts on capital-intensive new drilling activity as they had in the past, many of our customers also cut fi eld programs across their entire return-on-capital spectra, including well maintenance expenditures in low-cost-to-produce oilfi elds. Th is resulted in a signifi cant contraction of activity across all of Key’s service lines in most of our marketplaces. During the fourth quarter, our management team acted quickly and decisively to address the activity downturn and the impending pressure on pricing. We made the tough decisions and took the hard steps. We fi rst cut costs through reductions in force, eliminated discretionary spending and leveraged our buying power on large-spend items such as fuel, tires and maintenance. We believe that our decisive actions to align our cost structure with current market conditions kept Key’s operating margins in the fourth quarter of 2008 in line with the third quarter, an enviable and unique outcome compared to our peers. Under the weight of the economic climate, we understand we must manage our cost structure so that we can aff ord to assist our customers in generating cost-eff ective projects that create new activity for our services. From our patented 2 | 2008 Annual Report KeyView® system technology, to our unique service-bundling KeyView® system technology, to our unique service-bundling capabilities — all our eff orts are designed with just that in capabilities — all our eff orts are designed with just that in mind. We believe that these value creators diff erentiate Key mind. We believe that these value creators diff erentiate Key in the market. in the market. th ff er We can’t discern how deep this down-cycle will go or how will go or how We can’t discern how deep this down-cycle will go or how long it will last. However, we have and will continue to long it will last However we have and will coontinue to adjust our short-term strategy to fi t these unprecedented times. We are focused on cash generation and liquidity, and remain resolute to keep Key’s balance sheet strong. In the past, companies in the oilfi eld service arena that have come out of down-cycles well fi nanced and highly liquid are the ones that were able to grow rapidly, and at low cost with respect to adding assets. Th e challenge is choosing the proper timing for such steps and selecting the best opportunity from the many that will be presented. At Key, we know what opportunity looks like and we are ready to act when the time is right. Finally, we have not altered our core values in the face of the market upheaval. Our long-term strategy to grow internationally and improve Key’s “fi ngerprint,” that is the combination of what we do and where we do it, remains intact. We are still committed to improving the safety of our operations, bettering the communities in which we live, training for success and treating our employees fairly. Th ese values do not change, no matter the market conditions. In fact, we also believe that these market conditions are temporary and off er us an opportunity that did not exist in the fi ve-year run that preceded them — the ability to show that we are better structured, better managed and better fi nanced to take advantage of the many opportunities to become more valuable to our customers, which will in turn make Key more valuable to its shareholders. In closing, I thank you for your continued support of Key Energy Services, and I thank our thousands of employees for the hard work they perform every day to support our customers and their projects. Best Regards, Dick Alario Chairman, President and CEO Key Energy Services de México Technology, Effi ciency, Engineering: A planned performance success story in Mexico. During 2004, Key met with the Mexican national oil company, PEMEX, to address the problem of declining production. We designed a method of arresting these declines, employing our well-servicing competencies as a platform to deliver comprehensive value, creating value to a distinguished customer. By 2008, with the help of our patented KeyView® system, we had increased effi ciency versus comparable well-servicing operations by 30% and now look forward to a long-lasting partnership. In addition to our climbing rig count, we continue to deploy our KeyView system on an increasing number of PEMEX-owned rigs. Our engineering team in Poza Rica, Mexico analyzes fi eld data collected by the KeyView system and then proposes tangible solutions and specifi c operational recommendations to the fi eld to further improve performance. Highly trained crews, working hand-in-hand with dedicated Key employees, then implement these recommendations at the fi eld level. Th is results in improved operating procedures, creates a culture of safety and positions Key as a service provider of choice with exposure to a high-quality customer: Planned Performance. Th e Key success story in Mexico is just one of many places where we deliver superior solutions and results — on a daily basis. 2008 Accomplishments • Achieved record quarterly revenue of $535 million for the third quarter of 2008 and $1,972 million for the full year 2008 despite signifi cant business interruptions from Hurricanes Ike and Gustav and a sharp deterioration in the economic climate • Emerged as the California well service rig market leader with the purchase of Western Drilling, LLC, and leveraged our leading well service rig position by extending our product offerings in the promising Marcellus Shale region • Entered the Russian oilfi eld service market by taking an initial 26-percent interest in GeoStream Services Group; Geostream is a high quality provider of sub-surface, reservoir engineering as well as drilling and workover services • Completed the acquisition of all U.S.-based assets of Canadian oil service provider Leader Energy Services Ltd. and all of the outstanding stock of specialized pipe-handling company Hydra-Walk, Inc. • Contracted with PEMEX to place our 21st rig in Mexico by the second quarter of 2009, at which time Key will have built a 500-employee business with an annualized revenue run rate of $120 million, from essentially nothing in early 2007 • Recognizing Key’s commitment to quality, safety and effi ciency, a major U.S. producer promoted Key to an Advanced Supplier Relationship; this is the highest supplier relationship with this producer, a status which only three other suppliers enjoy • Joined the Russell 3,000 index in June 2008, as Russell Investments reconstituted its U.S. and global indices A Letter from COO Trey Wilson In early 2009, Key Energy Services streamlined its operations into a business marketplace matrix organization. Th is was spurred in part by the early recognition of rapidly changing market conditions, but more so because the leadership team identifi ed a need to better understand and respond to our customers’ needs, streamline decision- making and to accelerate operational enhancements. Th e fi rst step in implementing this plan was to consolidate all domestic operations into six distinct lines of business – Rig Services, Fluid Management Services, Pressure Pumping Services (which includes Coiled Tubing), Rental Services, Wireline Services and Fishing Services – each led by experienced managers. Second, we divided the lower 48 states into six marketplaces: West Coast, Rockies, Permian, Gulf Coast, Central and Northeast. Teams were created for each of these marketplaces and are led by senior members of our marketplace organization. Every team includes a senior LOB (Line of Business) leader and staff leaders within its specifi c marketplace. Th e resulting structure better aligns Key assets and personnel with its customers in each marketplace, facilitating quick, solid decision-making by our teams. Th is allows us to rapidly respond to customer needs or opportunities and deliver bundled service packages that provide solutions to benefi t our customers. By delivering packaged services, Key reduces its customers’ total costs through improved onsite project management and better scheduling, thereby reducing or eliminating non-productive time. Th e new structure also provides Key with a larger, broader “fi ngerprint” on its service matrix, resulting in an increase in revenue per job, as well as a more agile line of customer- centric thinking. Early wins for Key are already apparent. In a number of areas, the Company has kept or expanded rig services’ market share because of an ability to bundle it with other services, such as fl uid management or rental services. Wireline services have been combined with pressure pumping services to maintain or obtain new pressure pumping business. Additionally, Key’s signifi cant footprint, meaning its ability to service its customers’ needs just about anywhere in the lower 48, is a competitive advantage, appealing to many customers – both major and large independents. Customers continue to rely on Key’s wellsite and fi eld solutions while Key makes every eff ort to maintain and improve, wherever possible, safety and operational performance. Key has also leveraged its well-developed presence in the lower 48 to grow its footprint internationally, an expansionary strategy that we believe will serve us well into the future. Th e bottom line is that Key eff ectively manages our business in a rapidly changing environment. Th is new marketplace organization provides the leadership team with real-time information needed to quickly make course corrections, and the new LOB organization allows Key to swift ly execute these course corrections without compromising quality of service. 4 | 2008 Annual Report UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K (Mark One) ¥ n ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2008 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number 001-08038 KEY ENERGY SERVICES, INC. (Exact name of registrant as specified in its charter) Maryland (State or other jurisdiction of incorporation or organization) 04-2648081 (I.R.S. Employer Identification No.) 1301 McKinney Street Suite 1800 Houston, Texas 77010 (Address of principal executive offices, including Zip Code) (713) 651-4300 (Registrant’s telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Name of Exchange on Which Registered Common Stock, $0.10 par value New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: Title of Each Class None Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act). Yes n No ¥ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes n No ¥ 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 ¥ No n Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. n Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer ¥ Smaller reporting company n Accelerated filer n Non-accelerated filer n (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 n No ¥ The aggregate market value of the common stock of the registrant held by non-affiliates of the registrant as of June 30, 2008, based on the $19.42 per share closing price for the registrant’s common stock as quoted on the New York Stock Exchange on such date, was $1,727,937,807 (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 23, 2009, the number of outstanding shares of common stock of the registrant was 121,210,781. 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 2009 Annual Meeting of Shareholders 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, 2008 INDEX PART I Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 1. ITEM 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 1B. Unresolved Staff Comments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 2. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 3. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 4. PART II ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 6. ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . . Consolidated Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . ITEM 8. Changes in and Disagreements with Accountants on Accounting and Financial ITEM 9. Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PART III ITEM 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . ITEM 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 13. Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 14. Page Number 4 17 23 23 25 25 25 28 29 63 64 127 127 129 130 130 130 130 130 ITEM 15. Exhibits, Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130 PART IV 2 CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS In addition to statements of historical fact, this report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Statements that are not historical in nature or that relate to future events and conditions are, or may be deemed to be, forward-looking statements. These “forward-looking statements” are based on our current expectations, estimates and projections about Key Energy Services, Inc. and its subsidiaries, our industry and management’s beliefs and assumptions concerning future events and financial trends affecting our financial condition and results of operations. In some cases, you can identify these statements by terminology such as “may,” “will,” “predicts,” “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. 3 ITEM 1. BUSINESS PART I THE COMPANY Key Energy Services, Inc. is a Maryland corporation. References to “Key,” the “Company,” “we,” “us” or “our” are intended to refer to Key Energy Services, Inc., its wholly-owned subsidiaries and its controlled subsidiaries. We provide a complete range of well services to major oil companies, foreign national oil companies and independent oil and natural gas production companies, including rig-based well maintenance, workover, well completion and recompletion services, fluid management services, pressure pumping services, fishing and rental services and ancillary oilfield services. We believe that we are the leading onshore, rig-based well servicing contractor in the world. We operate in most major oil and natural gas producing regions of the United States as well as internationally in Argentina and Mexico. Additionally, we have a technology development group based in Canada. We also have an ownership interest in a drilling and production services company based in Canada, and, during October 2008, acquired a 26% ownership interest in a drilling and workover services and sub-surface engineering and modeling company based in the Russian Federation. Key’s principal executive office is located at 1301 McKinney Street, Suite 1800, Houston, Texas 77010. Our phone number is (713) 651-4300 and website address is www.keyenergy.com. We make available free of charge through our website 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 material is 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 2008, 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. Information on our website or any other website is not a part of this report. DESCRIPTION OF BUSINESS SEGMENTS During fiscal year 2008, our business was comprised of three primary business segments: well servicing, pressure pumping services and fishing and rental services. Key operates in various regions in the continental United States and internationally in Argentina and Mexico. The following is a description of these three business segments. For financial information regarding these business segments, see “Note 19. Segment Information,” in “Item 8. Consolidated Financial Statements and Supplementary Data.” In early 2009, we implemented a reorganization of our U.S. operating segments to realign both our management structure and resources along six lines of business. We have undertaken this structural realignment in an effort to better position the Company to utilize our assets efficiently in meeting customer needs and to ensure that all lines of business share the same geographic footprint. The six lines of business will be rig services, fluid management services, pressure pumping services, wireline services, rental services and fishing services. Well Servicing Segment Through our well servicing segment (which accounted for approximately 76.6% of revenues for the year ended December 31, 2008), we provide a broad range of well services, including rig-based services, fluid management services (which includes oilfield transportation and produced-water disposal services), cased-hole electric wireline services and ancillary oilfield services. These services are necessary to complete, stimulate, maintain and workover oil and natural gas producing wells. Our well service rig fleet provides well maintenance, workover, completion, and plugging and abandonment services to our customers. Certain of our larger well service rigs are suitable for and used in certain drilling applications, including horizontal drilling. 4 Our fluid management fleet provides vacuum truck services, fluid transportation services and disposal services for operators whose wells produce saltwater or other fluids and is also a supplier of frac tanks, which are used for temporary storage of fluids used in conjunction with fluid hauling operations. During 2008, we conducted well servicing operations in virtually every major onshore oil and natural gas producing region of the continental United States, including the Gulf Coast (including South Texas, Central Gulf Coast of Texas and South Louisiana), Permian Basin of West Texas and Eastern New Mexico, Mid- Continent (including the Anadarko, Hugoton and Arkoma Basins and the Ark-La-Tex and North Texas regions), Four Corners (including the San Juan, Piceance, Uinta and Paradox Basins), the Appalachian Basin, Rocky Mountains (including the Denver Julesberg, Powder River, Wind River, Green River and Williston Basins), and California (the San Joaquin Basin), and internationally in Argentina and Mexico. In addition to our onshore operations, we also operate six barge-based rigs that serve customers along the Gulf Coast that can conduct operations in shallow water. Rig-based Services Rig-based services include the maintenance of existing wells, workover of existing wells, completion of newly drilled wells, drilling of horizontal wells, recompletion of existing wells (re-entering a well to complete the well in a new geologic zone or formation) and plugging and abandonment of wells at the end of their useful lives. Our rig fleet consists of 924 active rigs and is diverse, allowing us to work on all types of wells ranging from very shallow wells to wells as deep as 20,000 feet. Over 250 of our well service rigs are outfitted with our proprietary KeyView» technology, which captures and reports well site operating data. This technology allows our customers and our crews to actively monitor well site operations, to improve efficiency and safety and to add value to the services we offer. Included in our domestic well service fleet are six operational inland barge rigs. Inland barge rigs are mobile, self-contained, drilling and/or workover vessels that are used in the drilling and completion of oil and natural gas wells in shallow marshes, inland lakes, rivers and swamps along the Gulf Coast of the United States. When moved from one location to another, the barge floats; when stationed on the drill or workover site, the barge is submerged to rest on the bottom. Typically, inland barge rigs are used to drill or workover wells in marshes, shallow inland bays and offshore where the water covering the drill site is not too deep. Our barge rigs can operate at depths between three and 17 feet. For our rig-based services, we typically charge by the hour in the United States and Argentina, and by the job in Mexico. Maintenance Services We provide well service rigs, equipment and crews for maintenance services. These services are performed on both oil and natural gas wells, but more frequently on oil wells. While some oil wells in the United States flow oil to the surface without mechanical assistance, most require pumping or some other method of artificial lift. Oil wells that require pumping characteristically require more maintenance than flowing wells due to the operation of the mechanical pumping equipment. Because few natural gas wells have mechanical pumping systems in the wellbore, maintenance work on natural gas wells is less frequent. Maintenance services are required throughout the life of most producing wells to ensure efficient and continuous operation. These services consist of routine mechanical repairs necessary to maintain production from the well, such as repairing inoperable pumping equipment in an oil well or replacing defective tubing in an oil or natural gas well, and removing debris such as sand and paraffin from the well. Other services include pulling the rods, tubing, pumps and other downhole equipment out of the wellbore to identify and repair a production problem. Maintenance services are often performed on a series of wells in close proximity to each other and typically require less than 48 hours per well to complete. In general, demand for maintenance services is closely related to the total number of producing oil and natural gas wells in a geographic market, and maintenance services are generally the most stable type of well service activity. 5 Workover Services In addition to periodic maintenance, producing oil and natural gas wells occasionally require major repairs or modifications, called “workovers.” Workover services are performed to enhance the production of existing wells. Such services include extensions of existing wells to drain new formations either by deepening wellbores to new zones or by drilling horizontal or lateral wellbores to improve reservoir drainage. In less extensive workovers, our rigs are used to seal off depleted zones in existing wellbores and access previously bypassed productive zones. Our workover rigs are also used to convert former producing wells to injection wells through which water or carbon dioxide is pumped into the formation for enhanced recovery operations. Other workover services include: conducting major subsurface repairs such as casing repair or replacement, recovering tubing and removing foreign objects in the wellbore, repairing downhole equipment failures, plugging back a section of a well to reduce the amount of water being produced with the oil and natural gas, cleaning out and recompleting a well if production has declined and repairing leaks in the tubing and casing. These extensive workover operations are normally performed by a well service rig with a workover package, which may include rotary drilling equipment, mud pumps, mud tanks and blowout preventers, depending upon the particular type of workover operation. Most of our well service rigs are designed to perform complex workover operations. Workover services are more complex and time consuming than routine maintenance operations and consequently may last from a few days to several weeks. These services are almost exclusively performed by well service rigs. Demand for workover services is closely related to capital spending by oil and natural gas producers, which is generally a function of oil and natural gas prices. As commodity prices increase, oil and natural gas producers tend to increase capital spending for workover services in order to increase oil and natural gas production. Conversely, as commodity prices decrease, as they have during the second half of 2008, oil and natural gas producers tend to decrease capital spending for workover services. Completion Services Our completion services prepare a newly drilled oil or natural gas well for production. The completion process may involve selectively perforating the well casing to access producing zones, stimulating and testing these zones and installing downhole equipment. We typically provide a well service rig and may also provide other equipment such as a workover package to assist in the completion process. However, during periods of weak drilling rig demand, some drilling contractors may compete with service rigs for completion work. Also, for some completion work on natural gas wells, coiled tubing units can be used in place of a well service rig. The completion process typically requires a few days to several weeks, depending on the nature and type of the completion, and generally requires additional auxiliary equipment that we provide for an additional fee. The demand for well completion services is directly related to drilling activity levels, which are highly sensitive to expectations relating to, and changes in, oil and natural gas prices. As the number of newly drilled wells decreases, the number of completion jobs correspondingly decreases. Plugging and Abandonment Services Well service rigs and workover equipment are also used in the process of permanently shutting-in oil and natural gas wells at the end of their productive lives. Plugging and abandonment work can be performed with a well service rig along with electric wireline and cementing equipment. Plugging and abandonment services require compliance with state regulatory requirements. The demand for oil and natural gas does not significantly affect the demand for plugging and abandonment services because well operators are required by state regulations to plug wells that are no longer productive. The need for these services is also driven by lease or operator policy requirements. Fluid Management Services We provide fluid management services, including oilfield transportation and produced-water disposal services. Our oilfield transportation and produced-water disposal services include vacuum truck services, fluid transportation services and disposal services for operators whose oil or natural gas wells produce saltwater and 6 other fluids. In addition, we are a supplier of frac tanks which are used for temporary storage of fluids in conjunction with the fluid hauling operations. Fluid hauling trucks are utilized in connection with drilling and workover projects, which tend to use large amounts of various oilfield fluids. In connection with drilling or maintenance 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. In many oil and natural gas producing regions of the United States, saltwater is produced along with the oil and natural gas. The production of saltwater typically increases as the oil and natural gas production decreases. Our fluid management services will collect, transport and dispose of the saltwater. These fluids are removed from the well site and transported for disposal in a saltwater disposal (“SWD”) well. Key owned or leased 52 active SWD wells at December 31, 2008. 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 wellbore. Demand and pricing for these services generally correspond to demand for our well service rigs. Fluid hauling and equipment hauling services are typically priced on a per barrel or per hour basis while frac tank rentals are typically billed on a per day basis. Cased-Hole Electric Wireline Services Key provides cased-hole electric wireline services in the Appalachian Basin, Texas and Louisiana. These services are performed at various times throughout the life of the well and includes perforating, completion logging, production logging and casing integrity services. After the wellbore is cased and cemented, we can provide a number of services. Perforating creates the flow path between the reservoir and the wellbore. Production logging can be performed throughout the life of the well to measure temperature, fluid type, flow rate, pressure and other reservoir characteristics. This service helps the operator analyze and monitor well performance and determine when a well may need a workover or further stimulation. In addition, cased-hole services may involve wellbore remediation, which could include the positioning and installation of various plugs and packers to maintain production or repair well problems, and casing inspection for internal or external abnormalities in the casing string. Wireline services are provided from surface logging units, which lower tools and sensors into the wellbore. We owned 27 wireline units as of December 31, 2008. Cased-hole electric wireline services are conducted during the completion of an oil or natural gas well and often times throughout the life of a producing well. Services include: production logging, perforating, pipe recovery, pressure control and setting services. We use advanced wireline instruments to evaluate well integrity and perform cement evaluations and production logging. Demand for our cased-hole electric 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. Contract Drilling Services We provide limited drilling services to oil and natural gas producers. In Argentina, we operate seven drilling rigs and in the continental United States we operate 151 heavy-duty well service rigs that are capable of providing conventional and/or horizontal drilling services. Our drilling services are primarily provided under standard day rates, and, to a lesser extent, footage contracts. Our drilling rigs vary in size and capability. The rigs located in Argentina are equipped with mechanical power systems and have depth ratings of approx- imately 10,000 feet, although one rig can drill up to approximately 15,000 feet. Domestically, we recently acquired three new rigs equipped with mechanical power systems and 250 ton hydraulic top drive units. These three new rigs are rated to drill to 12,000 feet. Like workover services, the demand for contract drilling is directly related to expectations about, and changes in, oil and natural gas prices which, in turn, are driven by the supply of and demand for these commodities. Ancillary Oilfield Services We provide ancillary oilfield services, which include, among others: well site construction (preparation of a well site for drilling activities); roustabout services (provision of manpower to assist with activities on a well 7 site); and air drilling services (drilling technique using compressed air). Demand and pricing for these services are generally related to demand for our well service operations. Pressure Pumping Services Segment Through our pressure pumping services segment (which accounted for approximately 17.5% of revenues for the year ended December 31, 2008), we provide well stimulation and cementing services to oil and natural gas producers. Well stimulation services include fracturing, nitrogen, coiled tubing and acidizing services. These services (which may be completion or workover services) 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 wellbore. Demand for our pressure pumping services is primarily influenced by current and anticipated oil and natural gas prices and the resulting effect on the willingness of our customers to make operating and capital expenditures. Coiled tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts and through tubing fishing and formation stimulations utilizing acid, chemical treatments and sand fracturing. Coiled tubing is also used for a number of horizontal well applications, including “stiff wireline” uses in which a wireline is placed in the coiled tube and then fed into a well to carry the wireline to a desired depth (since gravity will not pull the wireline to the desired depth in a horizontal well). Our pressure pumping services in 2008 were conducted in the Permian Basin and Barnett Shale in Texas, the Marcellus Shale in West Virginia, the Bakken Shale in North Dakota, the Michigan Basin, Illinois Basin and New Albany Shale in the four state area of Michigan, Illinois, Indiana and western Ohio, the San Juan Basin in Colorado and New Mexico and the Oswego, Mississippi and Anadarko Basins in Oklahoma. Our well stimulation services were provided in the Permian Basin and Barnett Shale in Texas and Mississippi and Anadarko Basins in Oklahoma. We provided cementing services in the Permian Basin and Barnett Shale in Texas, Mississippi and Anadarko Basins in Oklahoma and the Bakken Shale in North Dakota. We provided coiled tubing services in the Permian Basin and Barnett Shale in Texas, the Marcellus Shale in West Virginia, the Bakken Shale in North Dakota, the Michigan Basin, Illinois Basin, New Albany Shale in the four state area of Michigan, Illinois, Indiana and western Ohio and Minden, Louisiana. We also provided cementing and coiled tubing services in conjunction with our plugging and abandonment operations in the Elk Hills and Kern River Basins of California. Fishing and Rental Services Segment Through our fishing and rental services segment (which accounted for approximately 5.9% of revenues for the year ended December 31, 2008), we provided fishing and rental services to major and independent oil and natural gas production companies in the Gulf Coast, Mid-Continent and Permian Basin regions, as well as in California. We also provided limited services offshore in the Gulf of Mexico. Fishing services involve recovering lost or stuck equipment in the wellbore utilizing a “fishing tool.” We offer a full line of services and rental equipment designed for use both onshore and offshore for drilling and workover services. Our rental tool inventory consists of drill pipe, tubulars, handling tools (including our patented Hydra-Walk» pipe- handling units and services), pressure-controlled 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. Pricing for fishing services is typically on a per job basis, including charges for equipment and tools used during the operation along with charges for equipment operators and consulting services. Prices for rental services typically include a daily charge for equipment and tools in addition to any equipment operators furnished. 8 EQUIPMENT OVERVIEW Well Service Rigs Our rigs typically are billed to customers on a per hour basis, but in certain cases may be billed on a day rate or by project. We categorize our rigs as active, stacked or inactive. We consider an active rig or piece of equipment to be a unit that is working, on standby, or down for repairs but with work orders assigned to it or that is available for work. A stacked rig or piece of equipment is defined as a unit that is in the remanufacturing process and could not be put to work without significant investment in repairs and additional equipment. A rig or piece of equipment is considered inactive if we intend to salvage the unit for parts, sell the unit or scrap the unit. The definitions of active, stacked and inactive are used for the majority of our equipment. As of December 31, 2008, our fleet of active well service rigs totaled 924 rigs. These rigs are located throughout the United States and internationally in Argentina and Mexico. Our geographic diversification provides us with a balanced mix of oil versus natural gas exposure. We estimate that approximately 68% of our rigs are located in predominantly oil regions, while 32% of our rigs are located in predominantly natural gas regions. As mentioned above, our fleet is diverse and allows us to work on all types of wells, ranging from very shallow wells to wells as deep as 20,000 feet. The following table classifies our active rigs based on size and location. Typically, heavy-duty rigs will be utilized on deep wells while light-duty rigs will be used on shallow wells. In most cases, these rigs can be reassigned to other regions should market conditions warrant the transfer of equipment. Region Swab(1) Light-Duty(2) Medium-Duty(3) Heavy-Duty(4) Total Active Well Service Rig Fleet as of December 31, 2008 Appalachia . . . . . . . . . . . . . . . . . . Argentina . . . . . . . . . . . . . . . . . . . Ark-La-Tex. . . . . . . . . . . . . . . . . . California . . . . . . . . . . . . . . . . . . . Gulf Coast . . . . . . . . . . . . . . . . . . Mexico . . . . . . . . . . . . . . . . . . . . . Mid-Continent . . . . . . . . . . . . . . . Permian Basin . . . . . . . . . . . . . . . Rocky Mountains . . . . . . . . . . . . . Southeastern Marine(5) . . . . . . . . . Southeastern . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . 2 1 4 0 2 0 10 12 2 0 4 37 14 3 1 88 0 0 9 8 1 0 1 125 8 31 36 66 47 11 97 216 47 3 41 603 1 7 7 20 11 3 4 59 33 3 11 159 25 42 48 174 60 14 120 295 83 6 57 924 (1) Swab rigs include rigs used in shallow-depth wells. (2) Light-duty rigs include rigs with rated capacity of less than 90 tons. (3) Medium-duty rigs include rigs with rated capacity of 90 tons to 125 tons. (4) Heavy-duty rigs include rigs with rated capacity of greater than 125 tons. The seven heavy-duty rigs in Argentina are drilling rigs. (5) Consists of six inland barge rigs. Fluid Management Services — Oilfield Transportation Equipment We have a broad and diverse fleet of oilfield transportation service vehicles. We broadly define an oilfield transportation service vehicle as any heavy-duty, revenue-generating vehicle weighing over one ton. Our transportation fleet includes vacuum trucks, winch trucks, hot oilers and other vehicles, including kill trucks and various hauling and transport trucks. 9 Region Vacuum Truck Winch Truck Hot Oil Truck Other Total Transportation Fleet as of December 31, 2008 Appalachia . . . . . . . . . . . . . . . . . . . . Argentina . . . . . . . . . . . . . . . . . . . . . Ark-La-Tex . . . . . . . . . . . . . . . . . . . . California . . . . . . . . . . . . . . . . . . . . . Gulf Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mid-Continent Permian Basin. . . . . . . . . . . . . . . . . . Rocky Mountains . . . . . . . . . . . . . . . Southeastern . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . 19 1 174 29 158 23 181 13 0 598 Pressure Pumping Equipment 21 13 25 2 30 14 29 2 33 169 0 2 0 0 0 6 64 0 3 75 11 30 36 30 8 20 110 6 6 257 51 46 235 61 196 63 384 21 42 1,099 Our pressure pumping services segment operates a diverse fleet of equipment, including frac pumps, cementing units, acidizing units, nitrogen units and coiled tubing units. Region Frac Pumps Cement Units Acidizing Units Nitrogen Units Coiled Tubing Units Total Pressure Pumping Fleet as of December 31, 2008 California . . . . . . . . . Barnett Shale . . . . . . Mid-Continent . . . . . Permian Basin. . . . . . Eastern . . . . . . . . . . . Rocky Mountains . . . Total . . . . . . . . . . . . . 0 50 13 23 0 0 86 9 8 3 7 0 0 27 0 7 3 8 8 3 29 0 2 0 6 6 2 16 8 5 0 2 6 3 17 72 19 46 20 8 24 182 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. Our well service rigs are mobile, and we operate a significant number of oilfield transportation service vehicles. 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 generate rig or trucking hours. In addition, the majority of our well service rigs work only during daylight hours. In the winter months when days become shorter, this reduces the amount of time that the rigs 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, 2008, we had 34 patents issued and 16 patents pending. As of December 31, 2008, we had 23 patents issued and 182 patents pending in foreign countries. All the issued patents have varying remaining durations and begin expiring between 2013 and 2025. The most notable of our technologies include numerous patents surrounding the KeyView» system, a field data 10 acquisition system that captures vital well site operating data from service equipment. We believe this information helps us and our customers improve safety, reduce costs and increase productivity. 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. FOREIGN OPERATIONS During 2008, we operated internationally in Argentina and Mexico, and we have a technology develop- ment group based in Canada. We also have ownership interests in a drilling and production services company based in Canada and a drilling and workover services and sub-surface engineering and modeling company based in the Russian Federation. Revenue from our international operations during 2008 totaled $171.9 million, or 8.7% of total revenue. Revenue from international operations for 2007 and 2006 totaled $105.9 million and $78.3 million, respec- tively. International revenues by country are summarized in the following table: For the year ended December 31, 2008: Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Percentage of total Revenue . . . . . . . . . . . . . . . . . . . . For the year ended December 31, 2007: Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Percentage of total Revenue . . . . . . . . . . . . . . . . . . . . For the year ended December 31, 2006: Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Percentage of total Revenue . . . . . . . . . . . . . . . . . . . . Argentina Mexico Canada Total (In thousands, except for percentages) $118,841 $47,200 $5,848 $171,889 6.0% 2.4% 0.3% 8.7% $ 93,925 $ 9,041 $2,938 $105,904 5.7% 0.5% 0.2% 6.4% $ 78,321 $ — $ — $ 78,321 5.1% 0.0% 0.0% 5.1% In Argentina, we operate 42 well service rigs (of which seven are drilling rigs) and 46 oilfield transportation vehicles, all of which we include in our well servicing segment. Beginning in the third quarter of 2008, we experienced a significant downturn in activity levels in Argentina due, in part, to deteriorating oil prices. At December 31, 2008, approximately 75% of our rigs in Argentina were working. The downturn has been further exacerbated by labor-related issues in this country. We are currently exploring other options for our equipment in Argentina if market conditions there do not improve. For additional information regarding Argentina, see the discussion on “International Expansion” under “Business and Growth Strategies” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” In Mexico, we commenced operations during the second quarter of 2007 after Petróleos Mexicanos, the Mexican national oil company (“PEMEX”), awarded our Mexican subsidiary, Key Energy Services de México S. de R.L. de C.V., a 22-month contract (the “First PEMEX Contract”) valued at approximately $45.8 million to provide field production solutions and well workover services. During the fourth quarter of 2008, we were awarded a second 24-month contract with PEMEX (the “Second PEMEX Contract”) to provide the same type of well services valued at approximately $68.0 million. Also, during the fourth quarter of 2008, our First PEMEX Contract was extended until September 2009 and the value increased approximately $60.0 million, for an aggregate value of approximately $105.8 million. Under the terms of the First PEMEX Contract, we 11 initially provided three well service rigs outfitted with our proprietary KeyView» system, and we installed two KeyView» systems on PEMEX-owned well service rigs. PEMEX has the option to call for additional rigs and KeyView» systems in the future, and, as of December 31, 2008, we had supplied PEMEX a total of 14 rigs. As of February 23, 2009, we have increased the number of rigs in Mexico to 17 rigs. The projects under both contracts cover PEMEX’s North Region assets and initially focus on oil wells in Burgos, Poza Rica-Altamira and Cerro Azul. We anticipate that we will install units with KeyView» systems on all PEMEX-owned workover rigs over the next two years, through 2010. On October 31, 2008, we acquired a 26% interest in OOO Geostream Services Group (“Geostream”) for $17.4 million. Geostream is based in the Russian Federation and provides drilling and workover services and sub-surface engineering and modeling in the Russian Federation. We are contractually required to purchase an additional 24% of Geostream no later than March 31, 2009 for approximately A11.3 million (which at February 23, 2009 is equivalent to $14.4 million). For a period not to exceed six years subsequent to October 31, 2008, we will have the option to increase our ownership percentage to 100%. 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. In 2007, we acquired Advanced Measurements, Inc. (“AMI”), a privately-held Canadian technology company focused on oilfield service equipment controls, data acquisition and digital information work flow. AMI builds Key’s proprietary KeyView» systems for deployment on our well service rigs, designs and builds control and data acquisition systems for fracturing services and develops additional technologies for Key as well as other service providers. In addition, in connection with the acquisition of AMI, we acquired an ownership interest in Advanced Flow Technologies, Inc. (“AFTI”), a privately-held Canadian technology company focused on low cost wireless gas well production monitoring. As of December 31, 2008, we held a 48.73% interest in AFTI. CUSTOMERS Our customers include major oil companies, independent oil and natural gas production companies, and foreign national oil and natural gas production companies. During the years ended December 31, 2008, 2007 and 2006, no single customer accounted for 10% or more of our consolidated revenues. COMPETITION AND OTHER EXTERNAL FACTORS In the well servicing markets, we believe that, based on available industry data, we are the largest provider of land-based well service rigs in the United States. At December 31, 2008, we had 924 active rigs. Based on the Weatherford-AESC (“AESC”) well service rig count, which is available on Weatherford International’s internet website, there were approximately 2,910 well service rigs in the United States at December 31, 2008. A prior survey suggested that there are more well service rigs in the United States than are reported by the AESC count. While we agree that there are likely more rigs than reported by the AESC, AESC provides the most readily available information concerning the U.S. well service rig count. We believe that the difference between the AESC data and the prior survey is likely attributable to (i) not all U.S. well service providers being members of the AESC, (ii) some U.S. oil and natural gas producers owning well service rigs and not reporting to the AESC and (iii) poor reporting of equipment by certain members of the AESC. 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. 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. We have devoted, and will continue to devote, substantial resources toward employee safety 12 and training programs. In addition, we believe that the KeyView» system has provided and will continue to provide important safety enhancements. 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 dramatic declines in the price of oil and natural gas, pricing for our services has become increasingly competitive since September of 2008. Further, as demand drops for oilfield services, the market is left with excess supply, placing additional pressure on our pricing. Significant well service providers include Nabors Industries, Basic Energy Services and Complete Production Services. Other public-company competitors include Bronco Drilling, Forbes Energy Services and Pioneer Drilling Company. In addition, though there has been consolidation in the domestic well servicing industry, there are numerous small companies that compete in Key’s well servicing markets. We do not believe that any other competitor has more active well service rigs than Key. In Argentina, our largest competitors are San Antonio International (formerly Pride International), Nabors Industries and Allis-Chalmers Energy. San Antonio International and Forbes Energy Services are our largest competitors in Mexico. The pressure pumping services market is dominated by three major competitors: Schlumberger Ltd., Halliburton Company and BJ Services Company. These three companies have a substantially larger asset base than Key and are believed to operate in all major U.S. oil and natural gas producing basins. Other competitors include Weatherford International Ltd., Superior Well Services, Inc., Basic Energy Services, Inc., Complete Production Services, Inc., Frac-Tech Services, Ltd. and RPC, Inc. The pressure pumping industry is very competitive, and the three major competitors generally lead pricing in any particular region. Our pressure pumping services operate in niche markets and historically have competed effectively with these competitors based on performance and strong customer service. Where feasible, we cross-market our electric wireline services to a number of customers where our pressure pumping crews work in tandem with our wireline crews, thereby offering our customers the ability to minimize vendors, which, we believe, will improve efficiency. We may be able to further pursue other cross-marketing opportunities utilizing capabilities that are unique to Key, because none of the three major pressure pumping contractors own and operate well service rigs in the United States. The U.S. fishing and rental services market is fragmented compared to our other product lines. Companies that provide fishing services generally compete based on the reputation of their fishing tool operators and their relationships with customers. Competition for rental tools is sometimes based on price; however, in most cases, when a customer chooses a specific fishing tool operator for a particular job, then the necessary rental equipment will be part of that job as well. Our primary competitors 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. The need for well servicing, pressure pumping services and fishing and rental 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 are currently experiencing, 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, including electric wireline services, 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 are 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 this lower-priced environment, fewer well service rigs are needed for completions and there is reduced demand for fishing services because these activities are generally associated with drilling activity. 13 The level of our revenues, earnings and cash flows are substantially dependent upon, and affected by, the level of domestic 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.” EMPLOYEES As of December 31, 2008, we employed approximately 8,411 persons in our domestic operations and approximately 1,710 additional persons in Argentina, Mexico and Canada. Not including the reductions in force that were initiated by the Company in response to market conditions, we experienced an annual domestic employee turnover rate of approximately 42% during 2008, compared to a turnover rate of approximately 41% in 2007. The high turnover rate is caused, in part, by the nature of the work, which is physically demanding and sometimes performed in harsh outdoor conditions. 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. Alternatively, some employees may leave Key if they can earn a higher wage with a competitor. Our domestic employees are not represented by a labor union and are not covered by collective bargaining agreements. Many of our employees in Argentina are represented by formal unions. Beginning in 2008, we have been experiencing significant labor-related issues in Argentina as a result of not being able to terminate the employment of field and office personnel because of restrictions imposed by local regulatory agencies in that country. In Mexico, during 2008, we entered into a collective bargaining agreement that applies to our workers in Mexico performing work under the PEMEX contracts. 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 satisfactory. A discussion of the risks associated with our high turnover is presented under “Business Related Risk Factors” in “Item 1A. Risk Factors.” 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 operation or financial position. Environmental Regulations Our operations routinely involve the storage, handling, transport and disposal of bulk waste materials, some of which contain oil, contaminants and 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. Laws and regulations protecting the environment have become more stringent over the years, and in certain circumstances may impose “strict liability,” rendering us liable for environmental damage without regard to negligence or fault on our part. Moreover, cleanup costs, penalties and other damages arising as a result of new or changes to existing environmental laws and regulations could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows. From time to time, claims have been made and litigation has been brought against us under such laws. However, the costs incurred in connection with such claims and other costs of environmental compliance have not had a material adverse effect on our past operations or financial statements. Management believes that Key conducts its 14 operations in substantial compliance with current federal, state and local requirements related to health, safety and the environment. 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 do not typically generate materials that are considered “hazardous substances.” One exception, however, would be spills that occur prior to well treatment materials being circulated downhole. For example, if we spill acid on a roadway as a result of a vehicle accident in the course of providing well stimulation services, or if a tank with acid leaks prior to downhole circulation, the spilled material may be considered a “hazardous substance.” In this respect, we are occasionally considered to “generate” materials that are regulated as 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. Certain materials generated in the exploration, development or production of crude oil and natural gas are excluded from RCRA’s hazardous waste regulation, but these wastes, which include wastes currently generated during our operations, could be designated as “hazardous wastes” in the future and become subject to more rigorous and costly disposal requirements. Any such changes in these laws and regulations could have a material adverse effect on our operating expense. Although we used operating and disposal practices that were standard in the industry at the time, 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. Our failure to comply with CAA requirements and those of similar state laws and regulations could subject us to civil and criminal penalties, injunctions and restrictions on operations. Global Warming and Climate Control Scientific studies suggest that emissions of greenhouse gases (including carbon dioxide and methane) may contribute to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is considering legislation to reduce greenhouse gas emissions. In addition, many states have already taken measures to address greenhouse gases through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. As a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts et al. v. EPA, the Environmental Protection Agency (the “EPA”) may regulate greenhouse gas emissions from mobile sources (e.g. cars and trucks) even if Congress does not adopt new legislation. The Court’s holding in Massachusetts that greenhouse gases are covered pollutants under the CAA may also result in future regulation of greenhouse gas emissions from stationary sources. In addition, some states where we 15 have operations have become more active in the regulation of emissions that are believed to be contributing to global climate change. For example, California enacted the Global Warming Solutions Act of 2006, which established the first statewide program in the United States to limit greenhouse gas emissions and impose penalties for non-compliance. 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. 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. Pursuant to these laws, permits must be obtained to discharge pollutants into state waters or waters of the United States, including to discharge storm water runoff from certain types of facilities. Spill prevention, control and countermeasure 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. The CWA can impose substantial civil and criminal penalties for non- compliance. Employees 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 are covered by the provisions of the Jones Act, the Death on the High Seas 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, with generally no limitations on our potential liability. Other Laws and Regulations 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 EPA’s Underground Injection Control Program which establishes the minimum program requirements. Most of our SWD wells are located in Texas and 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 leaks to the environment. We maintain insurance against some risks associated with our well service activities, but there can be no assurance that this insurance will continue to be commercially available or available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified could have a material adverse effect on our financial condition and operations. 16 Electric Wireline We conduct cased-hole electric 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 wellbore 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. We have obtained these licenses and approvals when necessary and believe that we are in substantial compliance with these federal requirements. ITEM 1A. RISK FACTORS In addition to the other information in this report, the following factors should be considered in evaluating us and our business. BUSINESS-RELATED RISK FACTORS Our business is 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, and the recent volatility in oil and natural gas prices, in addition to the deteriorating 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 continue to decrease) could result in further reduction in the utilization of available well service equipment and result in lower rates. 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: (cid:129) the level of development, exploration and production activity of, and corresponding capital spending by, oil and natural gas companies; (cid:129) oil and natural gas production costs; (cid:129) government regulation; and (cid:129) conditions in the worldwide oil and natural gas industry. Financial markets are in an unprecedented economic crisis worldwide, affecting both debt and equity markets. The shortage of liquidity and credit combined with the recent substantial losses in worldwide equity markets have led to an economic recession that could continue for an extended period of time. The slowdown in economic activity caused by the recession has reduced worldwide demand for energy and resulted in lower oil and natural gas prices. This reduction in demand could continue through 2009 and beyond. Demand for our services is primarily influenced by current and anticipated oil and natural gas prices. As a result of recent volatility and significant decreases in oil and natural gas prices and the substantial uncertainty due to the deteriorating credit markets and disruptions in the U.S. and global financial systems, our customers have reduced, and may continue to reduce, their spending on exploration and development drilling. If economic conditions continue to deteriorate or do not improve, it could result in additional reductions of exploration and production expenditures by our customers, causing further declines in the demand for our services and products. The decline in demand for our oil and natural gas services could have a material adverse effect on our revenue and profitability. Further, it is uncertain whether customers, vendors and suppliers will be able to access financing necessary to sustain their previous level of operations, fulfill their commitments and fund future operations and obligations. 17 Periods of diminished or weakened demand for our services have occurred in the past. We experienced a material decrease in the demand for our services beginning in August 2001 and continuing through September 2002. Although we experienced strong demand for our services following that period through the third quarter of 2008, we believe the overall decrease in demand resulting from the current economic crisis could be more severe than what we experienced during the 2001 — 2002 downturn. The current economic downturn and oil and natural gas price volatility could have a material adverse effect on our financial condition and results of operations. In light of these and other factors relating to the oil and natural gas industry, our historical operating results may not be indicative of future performance. We may be unable to maintain pricing on our core services. During the past three years, we have periodically increased the prices on our services to offset rising costs and to generate higher returns for our shareholders. However, as a result of pressures stemming from deteriorating market conditions and falling commodity prices, it has become 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. The inability to maintain our pricing or reduction in our pricing may have a material negative impact on our operating results. Industry capacity may adversely affect our business. Over much of the past three years, new capacity, including new well service rigs, new pressure pumping equipment and new fishing and rental equipment, has entered the market. In some cases, the new capacity is attributable to start-up oilfield service companies and, in other cases, the new capacity has been deployed by existing service providers to increase their service capacity. The new capacity adversely affected our utilization rates in 2008, which is down from prior years. Lower utilization of our fleet has led to reduced pricing for our services. The combination of overcapacity and declining demand has further exacerbated the pricing pressure for our services. Although oilfield service companies are not likely to add significant new capacity under current market conditions, in light of current market conditions and the deteriorating demand for our services, the overcapacity could cause us to experience continued pressure on the pricing of our services and experience lower utilization. This could have a material negative impact on our operating results. 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: (cid:129) blow-outs, the uncontrolled flow of natural gas, oil or other well fluids into the atmosphere or an underground formation; (cid:129) reservoir damage; (cid:129) fires and explosions; (cid:129) accidents resulting in serious bodily injury and the loss of life or property; (cid:129) pollution and other damage to the environment; and (cid:129) liabilities from accidents or damage by our fleet of trucks, rigs and other equipment. If 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 18 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 Canada, as well as investments in a drilling and production services company based in Canada and a drilling and workover services and sub-surface engineering and modeling company based in the Russian Federation. We may expand our operations into other foreign countries as well. As a result, we are exposed to risks of international operations, including: (cid:129) increased governmental ownership and regulation of the economy in the markets where we operate; (cid:129) inflation and adverse economic conditions stemming from governmental attempts to reduce inflation, such as imposition of higher interest rates and wage and price controls; (cid:129) increased trade barriers, such as higher tariffs and taxes on imports of commodity products; (cid:129) exposure to foreign currency exchange rates; (cid:129) exchange controls or other currency restrictions; (cid:129) war, civil unrest or significant political instability; (cid:129) restrictions on repatriation of income or capital; (cid:129) expropriation, confiscatory taxation, nationalization or other government actions with respect to our assets located in the markets where we operate; (cid:129) governmental policies limiting investments by and returns to foreign investors; (cid:129) labor unrest and strikes, including the significant labor-related issues we are currently experiencing in Argentina; (cid:129) deprivation of contract rights; and (cid:129) restrictive governmental regulation and bureaucratic delays. The occurrence of one or more of these risks may: (cid:129) negatively impact our results of operations; (cid:129) restrict the movement of funds and equipment to and from affected countries; and (cid:129) inhibit our ability to collect receivables. 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%, although we experienced a lower 42% turnover rate domestically during 2008. 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. 19 We may not be successful in implementing technology development and technology 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: (cid:129) limit our ability to improve our market position; (cid:129) increase our operating costs; and (cid:129) limit our ability to recoup the investments made in technology initiatives. 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 heavily on three 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 recent deterioration of the 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 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. 20 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 is significantly exacerbated by the current economic downturn and related instability in the global and U.S. 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: (cid:129) refinancing or restructuring our debt; (cid:129) selling assets; (cid:129) reducing or delaying acquisitions or capital investments, such as remanufacturing our rigs and related equipment; or (cid:129) seeking to raise additional capital. However, 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 current market conditions continue to 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: (cid:129) making it more difficult for us to satisfy our obligations under our indebtedness and increasing the risk that we may default on our debt obligations; (cid:129) requiring us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities; (cid:129) limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities; (cid:129) limiting management’s flexibility in operating our business; (cid:129) limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; (cid:129) diminishing our ability to withstand successfully a downturn in our business or the economy generally; (cid:129) placing us at a competitive disadvantage against less leveraged competitors; and 21 (cid:129) making us vulnerable to increases in interest rates, because certain debt will vary with prevailing interest rates. We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the consequent acceleration of our obligation to repay outstanding debt. Our ability to comply with debt covenants and other restrictions may be affected by events beyond our control, including prevailing 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 obliga- tions 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. DELAYED FINANCIAL REPORTING-RELATED RISK FACTORS Taxing authorities may determine that we owe additional taxes from previous years. We restated our financial statements for periods prior to 2004 and experienced delays in our financial reporting for subsequent periods. As result, we have amended previously filed tax returns and reports through 2004. We also intend to amend our 2005 and 2006 federal and state income tax filings during 2009. Where legal, regulatory or administrative rules require or allow us to amend our previous tax filings, we intend to comply with our obligations under applicable law. To the extent that tax authorities do not accept our conclusions about the tax effects of the restatement, liabilities for taxes could differ from those which have been recorded in our consolidated financial statements. If it is determined that we have additional tax liabilities, there could be an adverse effect on our financial condition, results of operations and cash flows. During the past three years, we have identified material weaknesses in our internal control over financial reporting. These material weaknesses, if not corrected, could affect the reliability of our financial statements and have other adverse consequences. Section 404 of the Sarbanes-Oxley Act of 2002 and the related SEC rules require management of public companies to assess the effectiveness of their internal control over financial reporting annually and to include in Annual Reports on Form 10-K a management report on that assessment, together with an attestation report by an independent registered public accounting firm. Under Section 404 and the SEC rules, a company cannot find that its internal control over financial reporting is effective if there exist any “material weaknesses” in its financial controls. A “material weakness” is a control deficiency, or combination of control deficiencies in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected. 22 We have identified one material weakness in internal control over financial reporting as of December 31, 2008. We have taken actions to remediate the material weakness and improve the effectiveness of our internal control over financial reporting; however, we cannot assure you that material weaknesses will not exist during 2009. Any failure in the effectiveness of internal control over financial reporting, if it results in misstatements in our financial statements, could have a material effect on financial reporting or cause us to fail to meet reporting obligations, and could negatively impact investor perceptions. 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: (cid:129) establish a classified Board of Directors, providing for three-year staggered terms of office for all members of our Board of Directors; (cid:129) set limitations on the removal of directors; (cid:129) provide our Board of Directors the ability to set the number of directors and to fill vacancies on the Board of Directors occurring between shareholder meetings; and (cid:129) set limitations on who may call a special meeting of shareholders. These provisions may have the effect of entrenching management and may deprive investors of the opportunity to sell their shares to potential acquirers at a premium over prevailing prices. This potential inability to obtain a control premium could reduce the price of our common stock. ITEM 1B. UNRESOLVED STAFF COMMENTS None. ITEM 2. PROPERTIES We lease executive 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. 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. 23 The following table shows our active owned and leased properties, as well as active SWD facilities, categorized by business segment and geographic region: Division MID-CONTINENT OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . . LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . . GULF COAST OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . . LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . . ARK-LA-TEX OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . . LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . . APPALACHIA OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . . LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . . PERMIAN BASIN OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . . LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . . ROCKY MOUNTAINS OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . . LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . . CALIFORNIA OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . . LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . . ARGENTINA OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . . LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . . CANADA OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . . LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . . MEXICO OWNED . . . . . . . . . . . . . . . . . . . . . . . . . . . LEASE . . . . . . . . . . . . . . . . . . . . . . . . . . . . TOTAL OWNED . . . . . . . . . . . . . . . . . . . . TOTAL LEASE . . . . . . . . . . . . . . . . . . . . . TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . Well Services (Other Than SWD) SWD Facilities Pressure Pumping Fishing & Rental 13 13 14 16 15 12 0 8 55 25 14 9 1 11 2 14 0 2 0 2 114 112 226 0 1 4 11 13 7 0 0 6 10 0 0 0 0 0 0 0 0 0 0 23 29 52 1 1 0 0 1 1 0 1 0 1 0 5 0 0 0 0 0 0 0 0 2 9 11 3 6 1 11 1 2 0 0 2 3 0 1 0 1 0 0 0 0 0 0 7 24 31 Although we have listed some of our SWD facilities as “leased” in the above table, in some of these cases, we actually own the wellbore for the SWD and lease only the land. In other cases, we lease both the wellbore and the land. Lease terms vary among different sites, but with respect to some of the SWD facilities for which we lease the land and own the wellbore, the land owner has an option under the land lease to retain the wellbore at the termination of the lease. Also included in the figures shown in the table above are nine apartments leased in the United States and eight apartments leased in Argentina. These apartments are for Key employees to use for operational support and business purposes only. 24 ITEM 3. LEGAL PROCEEDINGS In addition to various suits and claims that have arisen in the ordinary course of business, we continue to be involved in litigation with some 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 13. Commitments and Contingencies” in “Item 8. Consolidated Financial Statements and Supplementary Data.” ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. PART II ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES MARKET AND SHARE PRICES During fiscal year 2008, Key’s common stock traded on the NYSE, under the symbol “KEG.” From April 8, 2005 until October 2, 2007, our stock was quoted on the Pink Sheets Electronic Quotation Service (the “Pink Sheets”) under the symbol “KEGS.” As of February 23, 2009, there were 537 registered holders of 121,210,781 issued and outstanding shares of common stock. The following table sets forth the reported high and low sales price of Key’s common stock for the periods indicated: High Low Year Ended December 31, 2008 1st Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $14.47 19.75 2nd Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.94 3rd Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.14 4th Quarter. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $11.23 13.36 11.33 3.58 Year Ended December 31, 2007 1st Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $16.90 20.07 2nd Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.38 3rd Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.95 4th Quarter. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $14.85 16.52 13.08 13.25 High Low The following Corporate 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, the Company moved from the Russell 2000 Index to the Russell 1000 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 matches 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 25 and each index (including reinvestment of dividends) was $100 at December 31, 2003 and tracks the return on the investment through December 31, 2008. COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN* Among Key Energy Services, Inc., The Russell 1000 Index, The Russell 2000 Index, The PHLX Oil Service Sector and the Peer Group Key Energy Services, Inc. Russell 2000 PHLX Oil Service Sector Peer Group Russell 1000 350 300 250 200 150 100 50 0 S R A L L O D 2003 2004 2005 2006 2007 2008 * $100 invested on December 31, 2003 in stock or index, including reinvestment of dividends. Fiscal year ending December 31. DIVIDEND POLICY There were no dividends paid on Key’s common stock for the year ended December 31, 2008. Key must meet certain financial covenants before it may pay dividends under the terms of its current credit facility. Key does not currently intend to pay dividends. STOCK REPURCHASES On October 26, 2007, the Company’s Board of Directors authorized a share repurchase program, in which the Company may spend up to $300.0 million to repurchase shares of its common stock on the open market. The program expires March 31, 2009. At December 31, 2008, the Company had $132.7 million of availability remaining under the share repurchase program to repurchase shares of its common stock on the open market. During 2008, the Company repurchased an aggregate of approximately 11.1 million shares at a total cost of approximately $135.2 million, which represents the fair market value of the shares based on the price of the Company’s stock on the dates of purchase. From the inception of the program in November 2007 through December 31, 2008, the Company has repurchased an aggregate of approximately 13.4 million shares for a total cost of approximately $167.3 million. Under the terms of our Senior Secured Credit Facility (as defined under “Sources of Liquidity and Capital Resources” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation”), we are limited to stock repurchases of $200.0 million if our consolidated debt to capitalization ratio, as defined in the Senior Secured Credit Facility, is in excess of 50%. As of December 31, 2008, our consolidated debt to capitalization ratio was less than 50%. During the fourth quarter of 2008, the Company repurchased an aggregate 2.3 million shares of its common stock. The repurchases were made pursuant to the Company’s $300.0 million share repurchase program and to satisfy tax withholding obligations that arose upon vesting of restricted stock that had been 26 granted to certain senior executives. As noted above, the share repurchase program expires March 31, 2009. Set forth below is a summary of the share repurchases: ISSUER PURCHASES OF EQUITY SECURITIES Period Total Number of Shares Purchased Weighted Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs October 1, 2008 to October 31, 2008 . . . . . . . November 1, 2008 to November 30, 2008 . . . . December 1, 2008 to December 31, 2008 . . . . 1,728,528(1) 522,500 33,463(3) $6.56(2) $5.73 $4.42(4) 1,725,000 522,500 — (1) Includes 3,528 shares repurchased to satisfy tax withholding obligations of certain executive officers upon vesting of restricted stock. (2) The price paid per share on the vesting date with respect to the tax withholding repurchases was deter- mined using the closing prices on October 2, 2008 and October 30, 2008, respectively, as quoted on the NYSE. (3) Relates to shares repurchased to satisfy tax withholding obligations of certain executive officers upon vest- ing of restricted stock. (4) The price paid per share on the vesting date with respect to the tax withholding repurchases was deter- mined using the closing price on December 19, 2008, as quoted on the NYSE. EQUITY COMPENSATION PLAN INFORMATION The following table sets forth information as of December 31, 2008 with respect to compensation plans (including individual compensation arrangements) under which our common stock is authorized for issuance: Plan Category Equity compensation plans approved by shareholders(1) . . . . . . . . . Equity compensation plans not approved by shareholders(2) . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants And Rights (a) (In thousands) Weighted Average Exercise Price of Outstanding Options, Warrants And Rights (b) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (c) (In thousands) 5,429 120 5,549 $12.53 $ 8.07 2,250 — 2,250 (1) Represents options and other stock-based awards granted under the Key Energy Group, Inc. 1997 Incentive Plan (the “1997 Incentive Plan”) and the options and other stock-based awards available under the Key Energy Services, Inc. 2007 Equity and Cash Incentive Plan (the “2007 Incentive Plan”). The 1997 Incen- tive Plan expired in November 2007. (2) Represents non-statutory stock options granted outside the 1997 Incentive Plan and the 2007 Incentive Plan. The options have a ten-year term and other terms and conditions as those options granted under the 1997 Incentive Plan. These options were granted during 2000 and 2001. 27 ITEM 6. SELECTED FINANCIAL DATA The following historical selected financial data for the years ended December 31, 2004 through December 31, 2008 has been derived from the audited financial statements of the Company. 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. Consolidated Financial Statements and Supplementary Data.” CONSOLIDATED RESULTS OF OPERATIONS DATA 2008 Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,972,088 1,250,327 Direct operating expenses . . . . . . . . . . . . . . . Depreciation and amortization expense . . . . . 170,774 Impairment of goodwill and equity method 2007 Year Ended December 31, 2006 (In thousands, except per share amounts) $1,662,012 $1,546,177 $1,190,444 $987,739 685,420 103,339 780,243 111,888 920,602 126,011 985,614 129,623 2004 2005 investment . . . . . . . . . . . . . . . . . . . . . . . . General and administrative expenses . . . . . . . Interest expense, net of amounts capitalized . . Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . Income from continuing operations before income taxes and minority interest . . . . . . . Income tax (expense) benefit . . . . . . . . . . . . . Minority interest . . . . . . . . . . . . . . . . . . . . . . Income from continuing operations . . . . . . . . Discontinued operations, net of tax . . . . . . . . 75,137 257,707 41,247 2,840 174,056 (90,243) 245 84,058 — — 230,396 36,207 4,232 275,940 (106,768) 117 169,289 — — 195,527 38,927 (9,370) 274,480 (103,447) — 171,033 — — 151,303 50,299 12,313 — 162,133 46,206 19,114 84,398 (35,320) — 49,078 (3,361) (28,473) 1,890 — (26,583) (5,643) Net income (loss) . . . . . . . . . . . . . . . . . . . . . $ 84,058 $ 169,289 $ 171,033 $ 45,717 $ (32,226) Income (loss) per common share from continuing operations: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Income (loss) per common share from discontinued operations: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Net income (loss) per common share: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.68 0.67 $ $ 1.29 $ 1.27 $ 1.30 $ 1.28 $ 0.37 $ 0.37 $ (0.20) (0.20) — $ — $ — $ — $ — $ — $ (0.03) $ (0.03) $ (0.04) (0.04) 0.68 0.67 $ $ 1.29 $ 1.27 $ 1.30 $ 1.28 $ 0.34 $ 0.34 $ (0.24) (0.24) SELECTED CONSOLIDATED CASH FLOW DATA Net cash provided by operating activities . . . Net cash used in investing activities . . . . . . . Net cash (used in) provided by financing activities. . . . . . . . . . . . . . . . . . . . . . . . . . Effect of exchange rates on cash . . . . . . . . . . 2008 $ 367,164 (329,074) (7,970) 4,068 28 2007 Year Ended December 31, 2006 (In thousands) $ 258,724 (245,647) $ 249,919 (302,847) 2005 2004 $ 218,838 (33,218) $ 69,801 (64,081) 23,240 (184) (18,634) (238) (111,213) (662) (88,277) (233) SELECTED CONSOLIDATED BALANCE SHEET DATA . . . . . . . . . . . . . . . . . $ 285,749 1,858,307 1,051,683 2,016,923 Working capital Property and equipment, gross. . . . . . . Property and equipment, net . . . . . . . . Total assets . . . . . . . . . . . . . . . . . . . . . Long-term debt and capital leases, net of current maturities . . . . . . . . . . . . Total liabilities . . . . . . . . . . . . . . . . . . Stockholders’ equity . . . . . . . . . . . . . . Cash dividends per common share . . . . 2008 2007 2005 2004 Year Ended December 31, 2006 (In thousands) $ 265,498 1,279,980 694,291 1,541,398 $ 253,068 1,595,225 911,208 1,859,077 $ 169,022 1,089,826 610,341 1,329,244 633,591 1,156,191 860,732 — 511,614 970,079 888,998 — 406,080 810,887 730,511 — 410,781 775,187 554,057 — $ 165,920 999,414 597,778 1,316,622 481,047 810,956 505,666 — ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes thereto in “Item 8. Consolidated 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 well services to major oil companies, foreign national oil companies and independent oil and natural gas production companies, including rig-based well maintenance, workover, well completion and recompletion services, fluid management services, pressure pumping services, fishing and rental services and ancillary oilfield services. We believe that we are the leading onshore, rig-based well servicing contractor in the world. We operate in most major oil and natural gas producing regions of the United States as well as internationally in Argentina and Mexico. Additionally, we have a technology development group based in Canada. We also have ownership interests in a drilling and production services company based in Canada and a drilling and workover services and sub-surface engineering and modeling company based in the Russian Federation. During 2008, we operated in three business segments: the well servicing segment, the pressure pumping services segment and the fishing and rental services segment. For further detail regarding these business segments, please see the discussion under “Description of Business Segments” 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, maintenance of a strong balance sheet and good liquidity, expansion internationally, investments in technology and new service offerings and enhancement of safety and quality. Acquisition Strategy Our strategy contemplates that from time to time we may make acquisitions that strengthen one or more of our service lines, enhance our presence in selected regional markets or expand the service offerings we provide to our customer base. During 2008, we completed the acquisitions of the fishing and rental assets of Tri-Energy Services, LLC (“Tri-Energy”), Western Drilling, LLC (“Western”) and Hydra-Walk, Inc. (“Hydra- 29 Walk”). In addition, we acquired the U.S.-based assets of Leader Energy Services, Ltd. (“Leader”). Through these acquisitions and purchases, we expanded our well servicing rig fleet in the California market by 22 rigs, increased our presence in the Southeastern Gulf Coast and Gulf of Mexico rental tool market, acquired an automated pipe handling business that we feel is complementary to our rig-based service offerings and increased our presence in the Baaken and Marcellus shale formations through the acquisition of nine coiled tubing units. We believe that these transactions will help us to expand our geographic “footprint” and diversify and improve our service offerings to our customers. For more information on the acquisitions we completed during 2008, see the discussion below under “Acquisitions” in this Item. Our acquisitions in 2008 were made with cash on hand and availability under our Senior Secured Credit Facility, and our objective is to use cash for future acquisitions. Depending on future market conditions, however, we may elect to use equity as a financing tool for acquisitions. See “Liquidity and Capital Resources” under this Item for further discussion of the financing tools available to us. Controlling Spending During the late third quarter of 2008, we saw signs that the market for oilfield services was beginning to weaken. This weakening in the market for our services resulted from the overall turmoil in the credit markets that caused many of our customers to begin to slow down their capital spending, and from significant declines in the prices of oil and natural gas. In response to the pending downturn, we took steps during the later part of the third quarter and in the fourth quarter of 2008 to decrease our spending levels and control costs. These steps included targeted reductions in our workforce, reductions in pay and other reductions in our cost structure. We believe that the actions we have already taken will result in significant cost savings in the near term, and we are continuing to implement other cost saving measures during early 2009, including further reductions in our spending levels and capital expenditures, in order to further improve our cost structure. Maintain and Grow in Core Segments During the past three years, we have significantly increased our capital expenditures, devoting more capital to organic growth. Excluding acquisitions, we have cumulatively spent approximately $627.4 million on capital expenditures since the beginning of 2006, including capital expenditures of $219.0 million in 2008. These expenditures include the purchase of new pressure pumping equipment, new cased-hole electric wireline units and new and remanufactured well service rigs, as well as numerous rental equipment and fishing tools. With the overall downturn in the economy during late 2008 and the projected slowdown for activity in our industry during the near term, we intend to reduce our capital expenditure program in 2009 in order to maintain liquidity and provide flexibility for the use of our capital. Presently, we estimate that we will spend approximately $130.0 million in capital expenditures in 2009, of which we estimate approximately $20.0 mil- lion a quarter will be devoted to maintenance of our existing fleet. Our 2009 capital spending could increase if we are awarded additional international work or recognize an opportunity to expand our services in a particular market. Maintain Strong Balance Sheet and Liquidity We believe that our ability to maintain a strong balance sheet and exercise sound capital discipline is critical, and this will position the Company well to sustain itself through the current and projected downturn in the market. We also believe that our ability to maintain ample liquidity and borrowing capacity is important in order to enable us to maintain operational flexibility, as well as to take advantage of other attractive business opportunities, should they develop. As of December 31, 2008, we had $92.7 million in cash and cash equivalents as well as $139.3 million of availability under the revolving portion of our Senior Secured Credit Facility, and we have no maturities under our 8.375% Senior Notes (the “Senior Notes”) until 2014 or required repayments of borrowings on our Senior Secured Credit Facility until 2012. Also, in the fourth quarter of 2009, we are required to make principal payments totaling $14.5 million related to the Moncla Notes (as defined in the discussion below of “Moncla Notes Payable” under “Liquidity and Capital Resources” in this Item). We expect to fund our obligations under the Moncla Notes through cash on hand generated by operating activities or borrowing under our Senior Secured Credit Facility. 30 International Expansion We presently operate in Argentina and Mexico and have a technology development group based in Canada. We also have an ownership interest in a drilling and production services company based in Canada. During October 2008, we purchased a 26% interest in a drilling, workover and sub-surface engineering and reservoir modeling company operating in the Russian Federation, and we have an obligation to expand that interest in 2009. One of our objectives is to redeploy under-utilized assets to international markets. In addition, we will consider strategic international acquisitions in order to establish a presence in a particular market, if appropriate. We have evaluated a number of international markets, and our near-term priority is expansion in Mexico. During 2008, we increased the number of working rigs we had positioned in Mexico to 14. We intend to further increase our working rigs in Mexico to 21 by the end of the second quarter of 2009. See “Foreign Operations” in “Item 1. Business” for further discussion of our current international operations. Investing in Technology and New Service Offerings We have invested, and will continue to invest, in technology projects that improve operating efficiencies for both ourselves and our customers, improve the safety performance of our well service rigs and fluid hauling vehicles and provide opportunities for additional revenue. In 2003, we began deployment of our proprietary well service technology called KeyView». The KeyView» control and data acquisition system measures certain well-site operating parameters and actively uses this information for safety intervention purposes on the rig, allowing our customers and ourselves to monitor and analyze the information about well servicing to promote improved efficiency and quality. At December 31, 2008, we had more than 250 KeyView» systems installed. The KeyView» system increases our and our customers’ visibility into activities at the well site. Through this technology, we have the ability to (i) ensure proper rod and tubing make-up which will result in reduced downhole failures, (ii) improve efficiency, through better logistics and planning, and (iii) improve safety. We believe that this system provides us a competitive advantage as it is a patented technology. For a further discussion of the KeyView» system, see “Patents, Trade Secrets, Trademarks and Copyrights” and “Foreign Operations” in “Item 1. Business.” 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 applications 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 will assist in the advancement of this technology. We also believe that it is important to have a broad, diverse and complementary services offering. For this reason, we have expanded the service offerings of our pressure pumping segment and our fishing and rental segment. We took delivery of five coiled tubing units during the fourth quarter of 2008 that we had previously ordered during 2007, as well as four segments of drill string for our rental tools group. In addition, we took delivery of three drilling rigs and continued to expand our cased-hole wireline business that we entered into during 2006. We believe that some customers prefer to consolidate vendors and we feel that our expanded services offering may provide better opportunities to serve our customers. 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, Wyoming and Louisiana. In addition, in conjunction with local community colleges, we have two cooperative training centers in New Mexico and Oklahoma. 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. 31 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 commodity prices are strong, capital spending by our customers tends to be high, as illustrated by the Baker Hughes U.S. land drilling rig count. As the following table indicates, the land drilling rig count has increased significantly since 2002 and commodity prices for both oil and natural gas have increased. Year 2002 . . . . . . . . . . . . . . . . . . . . 2003 . . . . . . . . . . . . . . . . . . . . 2004 . . . . . . . . . . . . . . . . . . . . 2005 . . . . . . . . . . . . . . . . . . . . 2006 . . . . . . . . . . . . . . . . . . . . 2007 . . . . . . . . . . . . . . . . . . . . 2008 . . . . . . . . . . . . . . . . . . . . WTI Cushing Crude Oil(1) NYMEX Henry Hub Natural Gas(1) Average Baker Hughes Land Drilling Rigs(2) $26.18 $31.08 $41.51 $56.64 $66.05 $72.34 $99.57(3) $3.37 $5.49 $6.18 $9.02 $6.98 $7.12 $8.90(3) 717 924 1,095 1,290 1,559 1,695 1,814(4) (1) Represents average crude oil or natural gas price, respectively, for each of the years presented. Source: Bloomberg (2) Source: www.bakerhughes.com (3) Prices for oil and natural gas declined sharply during the fourth quarter of 2008. The spot prices at Febru- ary 23, 2009 for WTI-Cushing crude oil and NYMEX Henry Hub natural gas were $39.47 per barrel and $4.20 per Mcf, respectively. (4) The land drilling rig count was affected by the drop in commodity prices. The land drilling rig count at January 31, 2009 was 1,412. 32 Internally, we measure activity levels 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 2006 through 2008. Rig Hours Trucking Hours 2008 First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 659,462 701,286 721,285 634,772 Total 2008: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,716,805 2007 First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 625,748 611,890 597,617 614,444 Total 2007: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,449,699 2006 First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 663,819 679,545 677,271 637,994 585,040 603,632 620,885 607,004 2,416,561 571,777 583,074 570,356 583,191 2,308,398 609,317 602,118 587,129 578,471 Total 2006: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,658,629 2,377,035 MARKET CONDITIONS AND OUTLOOK Market Conditions — Year Ended December 31, 2008 During 2008, the overall industry demand for the services that we provide was high. The average Baker Hughes land rig count in the United States during 2008 was 1,814 rigs, which was an increase of approximately 7% over the 2007 average and approximately 16% over the 2006 average. The increase in the average land rig count was driven primarily by record commodity prices; during 2008 the West Texas Intermediate — Cushing crude oil price averaged almost $100 per barrel and natural gas at the Henry Hub averaged almost $9.00 per Mcf, increases of approximately 38% and 25%, respectively, over 2007 levels. Overall, our activity levels and asset utilization during 2008 were high. For 2008, we had approximately 2.7 million rig hours and 2.4 million trucking hours, which was an increase of approximately 10.9% and 4.7%, respectively, over 2007 activity levels. Acquisitions we made during 2008 contributed approximately 65,509 rig hours during 2008, and the full year effect of acquisitions we completed during 2007 was 242,545 rig hours. Also contributing to the increase in rig hours was our expansion into Mexico during 2008, which contributed an additional 44,736 rig hours. Excluding the effects of acquisitions and expansion in Mexico, our domestic rig and trucking hours per working day increased slightly during 2008. During the first three quarters of 2008, we saw our activity levels steadily increase, due to high demand for our services associated with strong commodity prices. However, throughout 2008, there were signs that the financial markets of the United States were becoming unstable. As the turmoil in the credit markets increased during the summer and fall of 2008, commodity prices peaked at all-time highs. Late in the third quarter of 2008, we began to see demand for our services starting to weaken, as the tightening of the credit markets 33 made access to capital for spending more difficult for our customers and uncertainty grew around future pricing for oil and natural gas. Conditions continued to deteriorate during the fourth quarter of 2008, driven by rapidly declining commodity prices, tight credit markets and overall uncertainty about market conditions. We responded to these deteriorating market conditions 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. Additionally, the steps we were taking towards a new organizational structure to more efficiently manage our under-utilized assets allowed us to identify cost savings. Market Outlook We believe that 2009 will be a challenging year for our business, as public estimates point to an anticipated decline in the land rig count of a magnitude not seen since the 2001 — 2002 timeframe. Because of tighter credit markets and declining borrowing bases, our customers will likely have less access to capital, and because of lower commodity prices, our customers will likely not be inclined to spend capital even if they can access it. These assessments are supported by the fact that the land drilling rig count at January 31, 2009 stood at 1,412, a decline of approximately 22.2% from the 2008 average, and oil and natural gas prices were $41.73 per barrel and $4.42 per MMbtu, respectively, down approximately 58.1% and 50.3%, respectively, from their 2008 averages. Near-term, we anticipate that our service lines whose revenues are more closely tied to new drilling activity will be most severely affected. However, we believe that our core service lines, including rig-based well servicing and our fluids management business, will be more resilient to the market downturn because our customers will still need to maintain their existing wells and transport and dispose of saltwater and other fluids. While we expect prices for our core services will decline during 2009, we do not believe they will fall as much as prices in some other service lines that are more closely connected with new drilling. In light of these challenging conditions, we believe that Key is well equipped for the downturn until production decline rates begin to drive commodity prices higher, causing our customers to spend capital dollars and increasing the demand for our services. Management has focused on maintaining a strong balance sheet, with acceptable leverage ratios and good liquidity, and we do not currently believe that the downturn in 2009 will affect the Company’s compliance with the financial covenants in its debt agreements. We also feel that our geographic diversity will help the Company maintain its margins until the market for all of our services in the United States recovers. Impact of Inflation on Operations We are of the opinion that inflation has not had a significant impact on Key’s business. ACQUISITIONS Acquisitions and equity method investments completed during 2008 Tri-Energy Services, LLC. On January 17, 2008, the Company purchased the fishing and rental assets of Tri-Energy for approximately $1.9 million in cash. These assets were integrated into our fishing and rental segment. The equity interests of Tri-Energy were owned by employees of the Company who joined the Company in October 2007 in connection with the earlier acquisition in 2007 of Moncla Well Service, Inc. and related entities (collectively, “Moncla”). Western Drilling, LLC. On April 3, 2008, the Company purchased all of the outstanding equity interests of Western, a privately-owned company based in California that operated 22 working well service rigs, three stacked well service rigs and equipment used in the workover and rig relocation process, for total consideration of $51.6 million. We acquired Western to increase our service footprint in the California market. The acquisition was funded from borrowings under the Company’s Senior Secured Credit Facility and cash on hand. 34 Hydra-Walk, Inc. On May 30, 2008, the Company purchased all of the outstanding stock of Hydra-Walk for approximately $10.5 million in cash. The Company retained approximately $1.1 million of Hydra-Walk’s net working capital and did not assume any debt of Hydra-Walk. Hydra-Walk is a leading provider of pipe handling solutions for the oil and gas industry and operates over 80 automated pipe handling units in Oklahoma, Texas and Wyoming. We acquired Hydra-Walk to expand the level of integrated services we are able to provide customers. The assets and results of operations for Hydra-Walk were integrated into our fishing and rental segment. Leader Energy Services Ltd. On July 22, 2008, the Company acquired all of the United States-based assets of Leader, a Canadian company, for consideration of $34.6 million in cash. The acquired assets include nine coiled tubing units, seven nitrogen trucks, twelve pumping trucks and other ancillary equipment. Additionally, the Company paid approximately $0.7 million for supplies and inventory used in pressure pumping operations. The Leader assets were integrated into our pressure pumping segment. OOO Geostream Services Group. On October 31, 2008, we acquired a 26% interest in Geostream for $17.4 million. We incurred direct transaction costs of approximately $1.9 million associated with the transaction. Geostream is based in the Russian Federation and provides drilling and workover services and sub-surface engineering and modeling in the Russian Federation. In connection with our initial investment in Geostream, three officers of the Company became board members of Geostream, representing 50% of the board membership. We are contractually required to purchase an additional 24% of Geostream no later than March 31, 2009 for approximately A11.3 million (which at December 31, 2008 was equivalent to $15.9 mil- lion). For a period not to exceed six years subsequent to October 31, 2008, we will have the option to increase our ownership percentage of Geostream to 100%. 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. Acquisitions completed during 2007 AMI. On September 5, 2007, the Company acquired AMI, which operates in Canada and is a technology company focused on oilfield service equipment controls, data acquisition and digital information flow. The purchase price was $6.6 million in cash and $2.9 million in assumed debt. Moncla. On October 25, 2007, the Company acquired Moncla, which operated well service rigs, barges and ancillary equipment in the southeastern United States for total consideration of $146.0 million, consisting of cash, notes payable and assumed debt. The acquisition was made to expand our presence in the southeastern United States market, and was incorporated into our well servicing segment. Kings Oil Tools. On December 7, 2007, the Company acquired the well service assets and related equipment of Kings Oil Tools, Inc. (“Kings”), a California-based well service company, for approximately $45.1 million in cash to increase our presence in the California market. The assets of Kings were incorporated into our well servicing segment. Acquisitions completed during 2006 We made no acquisitions during 2006. 35 RESULTS OF OPERATIONS Consolidated Results of Operations The following table shows our consolidated results of operations for the years ended December 31, 2008, 2007 and 2006: REVENUES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,972,088 COSTS AND EXPENSES: 2008 2006 Year Ended December 31, 2007 (In thousands) $1,662,012 $1,546,177 Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . Depreciation and amortization expense . . . . . . . . . . . . . Impairment of goodwill and equity method investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative expenses . . . . . . . . . . . . . . . Interest expense, net of amounts capitalized . . . . . . . . . Loss on early extinguishment of debt . . . . . . . . . . . . . . (Gain) loss on sale of assets, net . . . . . . . . . . . . . . . . . . Interest income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other expense (income), net . . . . . . . . . . . . . . . . . . . . . 1,250,327 170,774 75,137 257,707 41,247 — (641) (1,236) 4,717 985,614 129,623 — 230,396 36,207 9,557 1,752 (6,630) (447) 920,602 126,011 — 195,527 38,927 — (4,323) (5,574) 527 Total costs and expenses, net . . . . . . . . . . . . . . . . . . . . . . 1,798,032 1,386,072 1,271,697 Income before income taxes and minority interest . . . . . . . Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Minority interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 174,056 (90,243) 245 275,940 (106,768) 117 274,480 (103,447) — NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 84,058 $ 169,289 $ 171,033 Year Ended December 31, 2008 and 2007 For the year ended December 31, 2008, our net income was $84.1 million, which represents a 50.3% decrease from net income of $169.3 million for the year ended December 31, 2007. Our earnings per fully 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 the Company’s goodwill pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets (“SFAS 142”) (approximately $69.8 million before tax, or $0.54 per fully diluted share); a charge associated with the acceleration of the vesting of certain of the Company’s equity awards (approximately $10.9 million before tax, or $0.05 per fully diluted share); an impairment of the Company’s investment in IROC Energy Services Corp. (“IROC”) (approximately $5.4 mil- lion before tax, or $0.03 per fully diluted share); severance charges associated with a reduction in the Company’s domestic and international workforce (approximately $2.6 million before tax, or $0.01 per fully diluted share); and the impact of hurricanes and their after-effects in the Gulf Coast during the third quarter of 2008 (estimated to have decreased our pre-tax earnings by $8.4 million, or $0.04 per fully diluted share). Partially offsetting these items were price increases implemented during the second and third quarters of 2008, incremental net income from acquisitions the Company completed during 2008, the integration of acquisitions completed during 2007 for a full year of operations, and expansion of the Company’s cased-hole wireline operations and operations in Mexico. Revenues Our consolidated revenue for the year ended December 31, 2008 was $2.0 billion, an increase of $310.1 million, or 18.7%, from $1.7 billion for the year ended December 31, 2007. The increase in revenue is 36 primarily attributable to price increases implemented during the second and third quarters of 2008, expansion of the Company’s cased-hole wireline operations and international operations in Mexico, acquisitions completed during 2008 and the integration of the acquisitions the Company made during 2007 for a full year of operations. Please refer to “Segment Operating Results” below for further discussion of the changes in revenues from 2007. Changes in revenues for each of our reportable segments were (in millions): Change from 2007 Well Servicing segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure Pumping segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fishing and Rental segment Total change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $245.1 45.6 19.4 $310.1 Weather, including hurricanes Ike and Gustav, impacted our land-based operations during the third quarter of 2008 in parts of Texas, Louisiana and Oklahoma. The inclement weather also significantly impacted our fishing operations in the Gulf of Mexico. The Company estimates that inclement weather during the third quarter of 2008 reduced well servicing segment revenues by approximately $7.0 million and fishing and rental segment revenues by approximately $1.4 million. Direct operating expenses Our consolidated direct operating expenses increased approximately $264.7 million, or 26.9%, to $1.3 billion for the year ended December 31, 2008 compared to $985.6 million for the year ended December 31, 2007. Excluding depreciation and amortization, these costs were 63.4% of consolidated revenues during 2008, compared to 59.3% of consolidated revenues for 2007. The change in consolidated direct operating expenses was the result of (in millions): Change from 2007 Employee compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equipment, supplies and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Frac sand and chemicals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Self-insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $125.5 58.0 33.4 29.4 4.7 13.7 $264.7 Direct employee compensation, which includes salaries, cash bonuses, health insurance, 401(k) costs and payroll taxes, increased approximately $125.5 million, or 23.4%, for 2008 compared to the same period in 2007. Acquisitions completed by the Company during 2008 contributed approximately $18.6 million to the increase over 2007, and the incorporation of acquisitions completed during 2007 for a full year of operations in 2008 contributed approximately $57.4 million to the increase. The Company’s expansion of its operations in Mexico contributed approximately $7.4 million to the increase. Excluding these items, direct employee compensation increased approximately 7.9% for 2008 compared to the same period last year. This increase is primarily attributable to organic direct headcount growth over the course of 2008 to support our ongoing operations, as well as pay rate increases that were implemented over the course of the year in order to retain a high quality workforce. In response to deteriorating market conditions during the fourth quarter of 2008, the Company’s management implemented a cost control program, which included freezing pay rates and reductions in the Company’s workforce in certain areas. Equipment, supplies and maintenance costs increased approximately $58.0 million for 2008 compared to the same period in 2007. Acquisitions completed during 2008 contributed approximately $5.7 million to the year-over-year increase in these costs, and the full year effect of acquisitions the Company completed during 2007 was approximately $24.5 million. The expansion of our operations in Mexico contributed approximately $23.0 million to the increase. Absent these items, these costs increased approximately 0.3% during 2008. The increase in these costs is related to higher prices from the Company’s vendors, and increased requirements for 37 repairs and maintenance related to the preparation of our assets for increased utilization and expansion of our operations. Fuel costs increased approximately $33.4 million, or 44.9%, for the year ended December 31, 2008 compared to the same period in 2007. Acquisitions completed during 2008 contributed approximately $2.1 million to the increase in fuel costs, while the incorporation of acquisitions the Company completed during 2007 for a full year of operations during 2008 contributed approximately $3.6 million to the increase. The Company estimates that on average, the per-gallon cost of diesel fuel increased approximately 27.5% during 2008 compared to 2007. This, combined with the overall higher usage of fuel because of higher activity levels, led to the remaining increase in fuel costs. Frac sand and chemical costs, which also includes the cost of transporting those supplies, increased approximately $29.4 million, or 34.0%, during 2008 compared to the same period in 2007. Acquisitions by the Company during 2008 contributed approximately $1.2 million to the increase in these costs and the full year effect of acquisitions completed during 2007 contributed approximately $0.6 million to the increase in 2008. Overall demand for frac sand and chemicals increased during 2008 because of the overall increase in pressure pumping activity. As a result, prices increased for all users of these products. This also had a direct impact on the cost to transport our frac sand; these costs increased approximately 36.1% during 2008. Additionally, during 2008 the Company began using coated sand as a proppant for certain high pressure frac jobs in the Barnett Shale formation. Coated sand is more expensive than normal types of frac sand, which contributed to the overall increase in these costs. Our pressure pumping operations are able to charge higher rates for frac jobs that require coated sand. The Company’s costs associated with self-insurance increased approximately $4.7 million during 2008 compared to 2007. The Company is largely self-insured against loss and uses actuarial information, as well as actual claims history, in order to calculate the required reserves. The primary cause for the increase in self- insurance costs was the increase in the number of employees covered, as we added headcount through acquisitions during 2007 and 2008. Depreciation and amortization expense Depreciation and amortization expense increased $41.2 million, or 31.7%, to $170.8 million for the twelve months ended December 31, 2008 compared to $129.6 million for the same period in 2007. Acquisitions the Company completed during 2008 contributed approximately $6.6 million to the increase and the integration of acquisitions made during 2007 for a full year of operations during 2008 contributed approximately $24.1 million. The remaining $10.5 million increase can be attributed to the Company’s capital expenditures and its larger fixed asset base, which resulted from the Company’s capital expenditures. Impairment of goodwill and equity method investment As discussed in “Critical Accounting Policies — Valuation of Tangible and Intangible Assets,” we test goodwill for impairment on an annual basis, or more often if circumstances indicate our goodwill might be impaired. Our tests for 2006 and 2007 resulted in no indications of impairment. However, upon completion of our test in 2008, there were indicators that the goodwill of our pressure pumping and fishing and rental segments might be impaired. As required by SFAS 142, we calculated the implied fair value of the goodwill for the pressure pumping and fishing and rental segments 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 approximately $69.8 million to write off the goodwill balances for both the pressure pumping and fishing and rental segments. Management of the Company believes that the goodwill of these segments was impaired because of the overall economic downturn and deterioration in the global credit markets and specifically the downturn in the oilfield services sector, which has resulted in a decline in the Company’s stock price and market valuation. All of the goodwill written off from our pressure pumping segment and approximately $18.9 million of the goodwill written off from our fishing and rental segment arose from our acquisition of Q Services, Inc. during 2002. 38 In 2007, the fair value of the Company’s investment in IROC, based on publicly available stock prices, declined below its book value. At that time, management of the Company believed that steps being taken by IROC’s management as well as economic trends in the Canadian markets indicated that the impairment of the investment was temporary and would be recovered. In the fourth quarter of 2008, management of the Company determined that, based on IROC’s continued depressed stock price and the overall negative outlook for the general economy and oilfield services sector, the impairment was other than temporary and as a result we recorded a pre-tax charge of $5.4 million in order to write the carrying value of our investment in IROC down to fair value. General and administrative expenses General and administrative expenses were approximately $257.7 million for the year ended December 31, 2008, which represents an increase of $27.3 million, or 11.9%, over approximately $230.4 million for the same period in 2007. General and administrative expenses were 13.1% of revenue during 2008, compared to 13.9% of revenue during 2007. The change in general and administrative expense was the result of (in millions): Change from 2007 Employee compensation (non-equity) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Legal fees and reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Professional fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 27.1 11.3 (2.2) (12.3) 3.4 $ 27.3 Non-equity employee compensation costs increased $27.1 million, or 30.6%, for the year ended December 31, 2008 compared to the same period in 2007. Acquisitions made during 2008 contributed approximately $0.9 million to this increase, and the integration of acquisitions made during 2007 for a full year during 2008 contributed approximately $5.2 million to the increase. Other increases in non-equity compensation during 2008 were the result of pay rate increases given over the course of 2008, the expansion of our operations in Mexico, and the expansion of our business development group through the transfer of existing personnel who previously held positions classified as direct labor. During the fourth quarter of 2008, due to declining industry conditions, the Company’s management initiated a cost control program, which included efforts to curtail all nonessential spending and, in some cases, reductions in the Company’s workforce. Severance charges associated with these workforce reductions resulted in a pre-tax charge totaling approximately $1.8 million recorded in general and administrative expenses. Equity-based compensation increased $11.3 million for the year ended December 31, 2008 compared to the same period in 2007. Because of declines in the Company’s stock price, during the fourth quarter of 2008 we accelerated the vesting period on certain of the Company’s outstanding unvested stock option awards and stock appreciation rights. As a result of the acceleration the Company recorded a pre-tax charge of approximately $10.9 million in general and administrative expenses. Absent this item, equity-based compensa- tion was approximately $12.5 million during 2008, which represents an increase of approximately $0.4 million from 2007. The increase was primarily due to new awards granted during 2008, partially offset be declines in the fair value of certain awards classified as liabilities whose value is based on the Company’s stock price. Legal fees and reserves decreased $2.2 million for the year ended December 31, 2008 compared to the same period in 2007. The Company records loss contingencies related to lawsuits, claims, and proceedings in the normal course of our business. These loss contingencies are reviewed routinely to ensure that appropriate liabilities are recorded and are adjusted as appropriate. Professional fees declined approximately $12.3 million, or 27.2%, during 2008 compared to 2007. Professional fees declined primarily as a result of the Company emerging from its delayed financial reporting process and becoming current with its SEC filings and re-listed on a national stock exchange during 2007. 39 Loss on early extinguishment of debt For the year ended December 31, 2007, we incurred a loss of $9.6 million associated with the termination of our prior senior credit agreement, dated July 29, 2005 (the “Prior Credit Facility”). During 2007, we issued the $425.0 million of Senior Notes and used the proceeds to retire the term loans then outstanding under the Prior Credit Facility. Concurrently, we entered into the Senior Secured Credit Facility and terminated the Prior Credit Facility. The loss represents the write-off of debt issue costs we incurred when we entered into the Prior Credit Facility. Interest expense, net of amounts capitalized The Company’s interest expense increased approximately $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. Gain on sale of assets, net The Company recorded a net gain of approximately $0.6 million in connection with the sale of various assets during 2008, compared with a loss of approximately $1.8 million during 2007. From time to time and in the normal course of business, the Company sells assets that are either in scrap condition or no longer being used by the Company. Interest income Interest income recognized by the Company during 2008 was approximately $1.2 million. This represents a decline of approximately $5.4 million from the amounts recognized during 2007. The primary reason for the decline in interest income was the decline in the Company’s short-term investment balances since 2007. During the fourth quarter of 2007, the Company liquidated its short-term interest-bearing investments to complete the acquisition of Moncla. Other expense, net Other expense, net for the twelve months ended December 31, 2008 was approximately $4.7 million, compared to other income, net of approximately $0.4 million for the year ended December 31, 2007. Other expense, net for 2008 primarily relates to foreign currency transaction losses associated with the Company’s foreign operations in Mexico, Argentina, and Canada of approximately $3.5 million. Partially offsetting these losses was equity in earnings from the Company’s investment in IROC. Income tax expense Our income tax expense was $90.2 million for the year ended December 31, 2008, compared to $106.8 million for the year ended December 31, 2007. Our effective tax rate was 51.8% in 2008, compared to 38.7% in 2007. The decrease in income tax expense is primarily attributable to lower pretax income in 2008. The increase in our effective tax rate is primarily attributable to the impairment of $63.4 million of goodwill that was non-deductible for income tax purposes and $6.4 million of goodwill that was deductible for income tax purposes in 2008. The 2008 effective tax rate exclusive of the goodwill impairment would be 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. Year Ended December 31, 2007 and 2006 For the year ended December 31, 2007, the Company’s net income was $169.3 million, which represented a decline of approximately $1.7 million, or 1%, from the Company’s net income of $171.0 million for the year ended December 31, 2006. Fully diluted earnings per share for the year ended December 31, 2007 were $1.27 per share, a decline of $0.01 per share from fully diluted earnings per share for the year ended December 31, 2006 of $1.28 per share. Items contributing to the decline in net income and diluted earnings per share were 40 costs associated with the refinancing of indebtedness during the fourth quarter of 2007. In connection with that refinancing, the Company recorded a pre-tax loss of approximately $9.6 million, or $0.04 per fully diluted share, associated with the write-off of existing unamortized debt issuance costs, and the termination of two interest rate swaps, which led to a pre-tax charge of approximately $2.3 million, or $0.01 per fully diluted share. Offsetting these one-time charges were increased revenues and net income associated with acquisitions the Company made during the third and fourth quarters of 2007 as well as the effect of higher pricing and increased activity during 2007, and expansion of our cased-hole wireline business and international operations in Mexico. Revenues Consolidated revenue for the year ended December 31, 2007 was approximately $1.7 billion, which represented an increase of $115.8 million, or 7.5%, from $1.6 billion for the year ended December 31, 2006. Please refer to “Segment Operating Results” below for further discussion of the changes in revenues from 2006. Changes in revenue for each of our reportable segments were (in millions): Well Servicing segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure Pumping segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fishing and Rental segment Total change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 63.5 51.9 0.4 $115.8 Change from 2006 Contributing to the increase in revenues in 2007 were acquisitions the Company made during the third and fourth quarters, the startup of our operations in Mexico during the second quarter, and the expansion of our cased-hole wireline business, as well as price increases and increased activity levels. Direct operating expenses Consolidated direct operating expenses increased approximately $65.0 million, or 7.1%, to $985.6 million for the year ended December 31, 2007, compared to $920.6 million for the year ended December 31, 2006. The increase in direct operating expenses was the result of (in millions): Employee compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure pumping supplies and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Well service acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Self-insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 25.4 41.6 16.0 (21.8) 3.8 $ 65.0 Change from 2006 Our employee compensation costs, which include salaries, bonuses and related expenses, increased $25.4 million primarily as the result of increased incentive compensation and increased headcount, exclusive of the impact of acquisitions. Wage and bonus increases during the year were necessary, as the market for our labor was extremely competitive. Because new competitors entered the market and existing competitors added equipment capacity, we were forced to increase wage rates in order to maintain our high levels of quality personnel. Supplies and equipment for our pressure pumping segment increased $41.6 million, primarily as a result of increases in the size of our pressure pumping fleet and increases in the costs to purchase and transport materials used in providing services to our customers. Acquisitions in our well services segment added $16.0 million to our direct operating expenses in 2007. Our self-insurance costs, comprised of costs associated with workers compensation, vehicular liability exposure, and insurance premiums declined signifi- cantly in 2007 as compared to 2006. 41 Depreciation and amortization expense Depreciation and amortization expense increased $3.6 million, or 2.9%, to $129.6 million for the year ended December 31, 2007, compared to $126.0 million for the year ended December 31, 2006. Contributing to the increase in depreciation and amortization expense was depreciation expense associated with our acquisi- tions during 2007, which totaled approximately $4.8 million, and increased depreciation of approximately $7.7 million related to management’s reassessment of the useful lives of certain assets. Excluding the depreciation and amortization expense associated with acquisitions and reassessment of useful lives, our depreciation expense would have declined approximately $8.9 million because the assets we added through various acquisitions during the 1994 to 2002 time period were reaching the end of their depreciable lives. Depreciation and amortization expense as a percentage of revenue for the year ended December 31, 2007 totaled 7.8%, compared to 8.1% for the year ended December 31, 2006. General and administrative expenses General and administrative expense increased $34.9 million, or 17.8%, to $230.4 million for the year ended December 31, 2007, compared to $195.5 million for the year ended December 31, 2006. The $34.9 million increase was primarily the result of (in millions): Change from 2006 Employee compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2006 legal settlement to the Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Professional fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bad debt expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7.5 3.0 7.5 9.6 1.8 5.5 $34.9 Employee compensation, exclusive of the impact of acquisitions, which includes salaries, bonuses, equity- based compensation and payroll taxes, increased primarily due to higher equity-based compensation and, to a lesser extent, increased salaries. Equity-based compensation expense during 2007, excluding grants made to our outside directors, totaled $12.0 million, compared to $5.6 million during 2006. The $6.4 million increase is primarily attributable to awards granted under our Phantom Share Plan at the end of 2006, as well as incremental stock options, restricted stock and stock appreciation rights awarded during 2007 under our 1997 Incentive Plan. General and administrative expenses added through acquisitions made during 2007 contributed $3.0 million to the increase in costs when compared to 2006. General and administrative expenses also increased in 2007 because 2006 general and administrative expenses included a $7.5 million benefit from a legal settlement in 2006 that was not repeated during 2007. Professional fees increased approximately $9.6 million during 2007, primarily due to our delayed financial reporting process. Also contributing to the increase was an additional $1.8 million in bad debt expense and $5.5 million in other general and administrative costs. General and administrative expense as a percentage of revenue for the year ended December 31, 2007 totaled 13.9% compared to 12.6% for the year ended December 31, 2006. Interest expense, net of amounts capitalized Interest expense decreased $2.7 million, or 7.0%, to $36.2 million for the year ended December 31, 2007, compared to $38.9 million for the year ended December 31, 2006. The decrease was primarily the result of the impact of higher capitalized interest as a result of higher capital expenditures. This decrease was partially offset by a one-time $2.3 million cost associated with the settlement of two interest rate swaps that were terminated in connection with the termination of our Prior Credit Facility in 2007. Interest expense as a percentage of revenue for the year ended December 31, 2007 totaled 2.2%, compared to 2.5% for the year ended December 31, 2006. 42 Loss on early extinguishment of debt For the year ended December 31, 2007, we incurred a loss of $9.6 million associated with the termination of our Prior Credit Facility. During 2007, we issued the $425.0 million of Senior Notes and used the proceeds to retire the term loans then outstanding under the Prior Credit Facility. Concurrently, we entered into the Senior Secured Credit Facility and terminated the Prior Credit Facility. The loss represents the write-off of debt issue costs we incurred when we entered into the Prior Credit Facility. Loss on sale of assets, net For the year ended December 31, 2007, we incurred a net loss on the disposal of assets of approximately $1.8 million, compared to a net gain of approximately $4.3 million in 2006. From time to time and in the ordinary course of business the Company sells assets that are in scrap condition or are no longer being used by the Company, and recognizes gains or losses as a result of these sales. Interest Income Interest income was approximately $6.6 million during 2007, compared to approximately $5.6 million during 2006. The increase in interest income is primarily associated with the Company’s investments of excess cash and cash equivalents. These investments were liquidated during the fourth quarter of 2007 to partially fund our purchase of Moncla. Other income, net Other income, net was approximately $0.4 million during 2007 compared to other expense, net of approximately $0.5 million in 2006. The increase in other income, net was primarily attributable to our equity in earnings from our investment in IROC and foreign currency transaction gains. Income tax expense Our income tax expense was $106.8 million for the year ended December 31, 2007, as compared to income tax expense of $103.4 million for the year ended December 31, 2006. Our effective tax rate in 2007 was 38.7%, as compared to 37.7% in 2006. The increase in income tax and our effective tax rate was primarily attributable to the revised Texas Franchise Tax. In general, differences between the effective tax rates and the statutory rate of 35% result primarily from the effect of certain foreign and state income taxes and permanent items attributable to book-tax differences. 43 Segment Operating Results 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: Segments Well Servicing Year Ended December 31, 2008 2007 (In thousands, except for percentages) Change Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses, as a percentage of revenue . . . $1,509,823 939,893 $1,264,797 738,694 $245,026 201,199 62.3% 58.4% Pressure Pumping Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses, as a percentage of revenue . . . $ 344,993 239,833 $ 299,348 189,645 $ 45,645 50,188 69.5% 63.4% Fishing and Rental Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses, as a percentage of revenue . . . $ 117,272 70,601 $ 97,867 57,275 $ 19,405 13,326 60.2% 58.5% Well servicing segment Revenues for the well servicing segment increased $245.0 million, or 19.4%, to $1.5 billion for the year ended December 31, 2008 compared to $1.3 billion for the same period in 2007. Acquisitions the Company completed during 2008 that were incorporated into the well servicing segment contributed $34.7 million to the increase, and the full year impact of the acquisitions the Company completed during 2007 was approximately $134.9 million. Also leading to higher revenues during 2008 was the expansion of our cased-hole wireline business (approximately $14.3 million) and the continuing expansion of our operations for PEMEX in Mexico (approximately $38.2 million). Additionally, the Company implemented price increases during the second and third quarters of 2008 across most of the markets in which the Company operates, leading to higher revenues. 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 the Company’s well servicing operations in Texas, Louisiana, and Oklahoma. The Company estimates that this negatively impacted well servicing segment revenue by approximately $7.0 million during 2008. Direct operating expenses, excluding depreciation and amortization expense, for the well servicing segment were $939.9 million during 2008, which was an increase of $201.2 million, or 27.2%, from the same period in 2007. These costs were 62.3% of revenue during 2008, up from 58.4% during 2007. The increase in direct costs for the well servicing segment resulted from (in millions): Change from 2007 Employee compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Supplies, equipment and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Self-insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $110.9 48.9 24.6 3.1 13.7 $201.2 Employee compensation for the well servicing segment, which includes salaries, cash bonuses, health insurance, 401(k) fees and payroll taxes, increased $110.9 million during 2008 compared to the same period in 2007. Acquisitions made by the Company during 2008 that were incorporated into the well servicing segment 44 contributed approximately $13.9 million to the increase, and the incorporation of acquisitions made during 2007 for a full year of operations during 2008 contributed approximately $57.4 million to the increase. Also contributing to the increase in employee compensation for the well servicing segment was the expansion of our cased-hole wireline business (approximately $3.6 million) and the Company’s international operations in Mexico (approximately $7.4 million). Additionally, during the third quarter of 2008 the Company incurred approximately $2 million in retroactive union wage increases in Argentina that it will likely be unable to recover from our customers. Excluding these items, direct employee compensation increased approximately 5.7% during 2008, mainly due to organic growth and wage rate increases made throughout the course of the year in order to maintain a quality workforce. Supplies, equipment and maintenance costs for the well servicing segment were approximately $222.5 million for the year ended December 31, 2008, which was an increase of approximately $48.9 million, or 28.2%, compared to the same period in 2007. Acquisitions the Company made during 2008 contributed approximately $4.0 million to the increase and the incorporation of acquisitions the Company made during 2007 for a full twelve months of operations in 2008 contributed approximately $24.5 million to the increase. Absent these items, these costs increased approximately $20.4 million, or 11.8%, from 2007. This increase was due primarily to higher prices being charged by vendors, especially for certain chemicals used in the well servicing process. Fuel costs for the well servicing segment increased approximately $24.6 million, or 43.7%, to $80.7 million for the year ended December 31, 2008 compared to the year ended December 31, 2007. Acquisitions the Company made during 2008 contributed approximately $1.3 million to the increase in fuel costs and the incorporation of acquisitions made during 2007 for a full twelve months during 2008 contributed approximately $3.6 million to the increase. Absent acquisitions, fuel costs have increased primarily as a result of higher usage due to increased utilization and the per gallon price of fuel. The Company estimates that on average, the per- gallon price of diesel increased approximately 27.5% during 2008 compared to 2007. Self-insurance costs for the well servicing segment increased approximately $3.1 million, or 15.8%, during 2008 compared to the same period in 2007. Acquisitions the Company made during 2008 and the incorporation of acquisitions the Company made during 2007 for a full year of operations during 2008 contributed to the increase, primarily due to the costs of insuring increased headcount. These increases were offset by better safety performance resulting in a lower number of incidents. Pressure pumping segment Revenues for the Company’s pressure pumping segment were approximately $345.0 million for the year ended December 31, 2008, which represents an increase of $45.6 million, or 15.2%, from revenues of $299.3 million for the same period in 2007. The acquisition of the Leader assets during the third quarter of 2008 contributed approximately $9.6 million to the increase in pressure pumping segment revenues. Excluding the effects of acquisitions, revenues for the pressure pumping segment increased approximately $36.1 million, or 12.0%, during 2008. This increase was driven primarily by the incremental equipment added by the Company over the course of the year, as well as price increases implemented during the second quarter of 2008. However, during the fourth quarter of 2008, the Company’s pressure pumping segment began to experience significant pricing pressure and began to increase the discounts offered to customers in order to preserve market share. Revenues during 2008 were also negatively impacted by a decline in the number of cementing and acid jobs performed, but these declines were partially offset by an increase in the number of coiled tubing jobs as a result of several coiled tubing units being placed in service during late 2008 in addition to the coiled tubing units acquired from Leader. Direct operating expenses, excluding depreciation and amortization expense, for the pressure pumping segment were approximately $239.9 million during 2008, which represents an increase of $50.2 million, or 26.5%, from the same period in 2007. Excluding depreciation and amortization, direct operating expenses of the pressure pumping segment were 69.5% of revenue during 2008 and 63.4% of revenue during 2007. The increase in the pressure pumping segment’s direct operating expenses as a percentage of revenue was primarily attributable to pricing pressures during the second half of 2008 combined with increasing supply costs during 45 2008 for fuel and proppants. The increase in direct operating expenses for the pressure pumping segment resulted from (in millions): Change from 2007 Frac sand and chemicals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Employee compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Supplies, equipment and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total Change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $29.5 8.1 7.2 3.6 1.8 $50.2 Frac sand and chemical costs for the pressure pumping segment increased approximately $29.5 million, or 34.0%, to $115.9 million during 2008 compared to $86.4 million during 2007. The acquisition of the Leader assets during the third quarter of 2008 contributed approximately $0.7 million to the increase in these costs during 2008. Absent the effect from the Leader asset purchase, costs for frac sand and chemicals increased during 2008 primarily due to higher commodity prices, as well as higher prices being charged by shippers to transport the sand. In addition, during 2008 the pressure pumping segment began using coated sand as a proppant in certain high-pressure frac jobs in the Barnett Shale formation. Using coated sand is more costly than normal sand, but allows the pressure pumping segment to charge a higher rate to its customers to cover the additional cost. Employee compensation for the pressure pumping segment, which is comprised of salaries, cash bonuses, health insurance, 401(k) fees and payroll taxes, increased approximately $8.1 million during 2008 compared to the same period in 2007. The Leader asset purchase during the third quarter of 2008 contributed approximately $2.4 million to the increase in direct employee compensation for the pressure pumping segment. Absent the effects of the Leader asset purchase, direct employee compensation for the pressure pumping segment increased $5.6 million, or 14.1%, during 2008. This increase was the result of the addition of several frac and coiled tubing crews during the year in order to meet customer demand, and wage rate increases given throughout the course of the year in order to maintain a high quality workforce. Fuel costs for the pressure pumping segment increased approximately $7.2 million or 48.9% during 2008 to $22.0 million compared to $14.8 million for the same period in 2007. The acquisition of the Leader assets during the third quarter of 2008 contributed approximately $0.5 million to the increase. Absent the effects of the Leader asset purchase, the primary driver in the increase in fuel is the per gallon price of diesel; the Company estimates that on average the price of diesel rose approximately 27.5% during 2008. Other factors driving the increase in fuel costs are higher activity levels during 2008. Supplies, equipment and maintenance costs for our pressure pumping segment increased $3.6 million, or 9.5%, during 2008 compared to 2007. The increase in these costs is attributable to the acquisition of the Leader fixed assets during 2008, higher prices from the Company’s vendors, and increased requirements for repairs and maintenance associated with the overall increase in utilization of our pressure pumping assets during 2008. Fishing and rental segment Revenues for the Company’s fishing and rental segment were approximately $117.3 million for the year ended December 31, 2008, which represented an increase of $19.4 million, or 19.8%, from revenues of $97.9 million for the same period in 2007. The acquisition of Hydra-Walk during the second quarter of 2008 contributed approximately $6.9 million to the increase in revenues. Excluding the effects of the acquisition, fishing and rental segment revenues increased $12.5 million, or 12.8%, from the same period in 2007. The increase in revenues is attributable to price increases implemented during the second quarter of 2008 as well as a higher number of reverse unit and fishing jobs during 2008 compared to 2007. Partially offsetting these increased revenues were the effects of hurricanes in the Gulf Coast region during the second and third quarters of 2008, which significantly restricted the segment’s operations in the Gulf of Mexico. Direct operating expenses, excluding depreciation and amortization expense, for the fishing and rental segment were $70.6 million during 2008, which was an increase of $13.3 million, or 23.3%, from 2007. The acquisition of Hydra-Walk during 2008 contributed approximately $3.2 million to the increase in direct 46 operating expenses. Excluding depreciation and amortization expense, direct operating expenses for the fishing and rental segment were 60.2% of revenue during 2008 and 58.5% of revenue during 2007. The increase in direct operating expenses resulted from (in millions): Change from 2007 Employee compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Supplies, equipment and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total Change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6.5 5.5 1.6 (0.3) $13.3 Employee compensation expenses, which include salaries, bonuses, insurance, 401(k) fees and payroll taxes, increased approximately $6.5 million during 2008 compared to the same period in 2007. The acquisition of Hydra-Walk during 2008 contributed approximately $2.2 million to the increase in employee compensation. Absent the effects of the acquisition, employee compensation increased as the segment added personnel to keep pace with increased demand, and also resulted from wage rate increases given throughout the course of the year in order to maintain a quality workforce. Supplies, equipment and maintenance for the fishing and rental segment were approximately $24.0 million during 2008, which represents an increase of approximately $5.5 million, or 29.6% from 2007. The acquisition of Hydra-Walk during 2008 contributed approximately $1.0 million to the increase in these costs. Other increases in these costs were attributable to a larger asset fleet and higher activity levels. Fuel for the fishing and rental segment increased approximately $1.6 million, or 47.9%, during 2008 compared to the same period in 2007. The acquisition of Hydra-Walk contributed approximately $0.3 million to the increase in fuel costs during 2008. The remainder of the increase is attributable to increased activity levels and an increase in the per-gallon price of diesel. The Company estimates that on average, the per-gallon price of diesel increased approximately 27.5% during 2008. Year Ended December 31, 2007 and 2006 The following table shows the results of operations for each of the Company’s reportable segments for the years ended December 31, 2007 and 2006: Segments Well Servicing Year Ended December 31, 2007 2006 Change (In thousands, except for percentages) Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses, as a percentage of revenue . . . . $1,264,797 738,694 $1,201,228 725,008 $63,569 13,686 58.4% 60.4% Pressure Pumping Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses, as a percentage of revenue . . . . $ 299,348 189,645 $ 247,489 138,377 $51,859 51,268 63.4% 55.9% Fishing and Rental Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating expenses, as a percentage of revenue . . . . $ 97,867 57,275 $ 97,460 57,217 $ 407 58 58.5% 58.7% Well servicing segment Well servicing segment revenue increased $63.5 million, or 5.3%, to $1.26 billion for the year ended December 31, 2007, compared to revenue of $1.20 billion for the year ended December 31, 2006. The increase 47 in revenue is largely attributable to the impact of the acquisition of Moncla, which contributed $23.6 million, $9.0 million from our contract with PEMEX in Mexico and $13.7 million in higher revenue from our cased- hole electric wireline operations. The remainder of the increase is a result of the full-year impact of pricing increases implemented during the second half of 2006, though revenues were affected by declines in activity levels and reductions from overall peak pricing in the second half of 2007. During the year ended December 31, 2007, our rig hours decreased 7.9% compared to the year ended December 31, 2006 and our trucking hours decreased 2.9% during the comparable period. The decrease in both rig and trucking hours was due primarily to lost market share to new market entrants. Well servicing direct operating expenses increased $13.7 million, or 2.0%, to $738.7 million for the year ended December 31, 2007, compared to $725.0 million for the year ended December 31, 2006. Acquisitions made during 2007 contributed approximately $16.0 million to the increase in direct operating expenses. Excluding the effect of acquisitions, well servicing direct operating expenses increased as a result of higher employee compensation costs of $17.2 million. Compensation-related expenses increased due to the need to retain our workforce. As a result of new equipment capacity in the marketplace, the demand for labor was strong and we implemented programs to retain our personnel, including higher wage rates. Partially offsetting the increased compensation costs was a $22.8 million decrease in costs associated with our self-insurance programs. These costs, which include workers’ compensation, vehicular liability exposure and insurance premiums declined primarily as a result of improved safety performance and fewer and less severe incidents in 2007 compared to 2006. Other well servicing direct expenses increased approximately $3.3 million. Pressure pumping segment Pressure pumping segment revenue increased $51.9 million, or 21.0%, to $299.3 million for the year ended December 31, 2007, compared to revenue of $247.5 million for the year ended December 31, 2006. The increase in revenue is attributable to the purchase of incremental pressure pumping equipment and higher activity levels, but was offset somewhat by lower pricing in 2007. Over the course of 2006 and 2007 we purchased additional new pressure pumping equipment to service and satisfy our customers’ needs, increasing the size of our fleet. The new equipment resulted in additional services performed, which resulted in higher revenue during 2007. During 2007, we completed 2,152 fracturing jobs and 2,074 cementing jobs as compared to 1,585 and 1,958, respectively, in 2006. Fracturing and cementing jobs accounted for the substantial majority of the segment revenue. Direct operating expenses increased $51.3 million, or 37.0%, to $189.6 million for the year ended December 31, 2007, compared to $138.4 million for the year ended December 31, 2006. The increase in direct operating expenses is largely attributable to costs associated with increased demand for pressure pumping services and the increased size of our pressure pumping fleet. During 2007, costs related to employee compensation for the pressure pumping segment increased $8.8 million due primarily to expansion of our pressure pumping fleet through the introduction of new equipment, which required us to hire additional personnel and increased wage rates for our crews. Our equipment costs increased $13.2 million from 2006 primarily due to the expansion of our pressure pumping fleet. Additionally, sand, chemical and associated freight costs increased approximately $29.3 million during 2007. These costs relate to the purchase of sand and chemicals used in our operations from our various suppliers and the shipment to our pressure pumping facilities and job locations. As activity levels in our pressure pumping segment increased in 2007, we used greater amounts of sand and chemicals. Additionally, as overall activity in the pressure pumping sector increased during 2007, the costs for the materials and their transportation increased. Fishing and rental segment Fishing and rental segment revenue totaled $97.9 million for the year ended December 31, 2007, compared to revenue of $97.5 million for the year ended December 31, 2006. Although the segment benefited from additional rental equipment in 2007, these equipment additions were offset somewhat by lower overall pricing. Fishing and rental segment direct operating expenses were flat at $57.3 million for the year ended December 31, 2007, compared to $57.2 million for the year ended December 31, 2006. 48 LIQUIDITY AND CAPITAL RESOURCES Current Financial Condition and Liquidity The following table summarizes our cash flows for the years ended December 31, 2008 and 2007: Year Ended December 31, 2008 2007 (In thousands) Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . Cash paid for capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash paid for short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from the sale of short-term investments . . . . . . . . . . . . . . . . . . . . Investment in Geostream . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acquisitions, net of cash acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acquisition of fixed assets from asset purchases. . . . . . . . . . . . . . . . . . . . . Other investing activities, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from long-term debt, net of cash paid for debt issance costs. . . . . Repayments of capital lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . Borrowings under revolving credit facility . . . . . . . . . . . . . . . . . . . . . . . . . Payments on revolving credit facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Repurchases of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other financing activities, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of exchange rates on cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 367,164 (218,994) $ 249,919 (212,560) — (121,613) 183,177 — (157,955) — 6,104 461,600 (424,751) — — (30,454) 16,845 (184) 276 (19,306) (63,457) (34,468) 6,875 — (11,506) 172,813 (35,000) (139,358) 5,081 4,068 Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . $ 34,188 $ (29,872) Cash flow from operating activities increased approximately $117.2 million, which was primarily the result of growth in revenues and earnings during 2008. Cash flows related to accounts receivable increased and vendor payments were also managed more effectively. While we have not yet experienced collectibility issues on receivable balances from our customers in excess of historical norms, a reduction in commodity prices may increase the credit risk associated with our customer payments. The deterioration and uncertainty of the global economy and the resulting impact on oil and natural gas prices may also have an impact on our customer’s ability to pay for our services in 2009. We actively monitor our customers’ ability to pay for our services and have and will take appropriate actions with respect to collectibility issues as circumstances dictate. Cash flow used in investing activities increased $26.2 million in 2008 compared to the same period in 2007. For the past three years, we have devoted significant amounts of our cash flow from operations to support organic growth. From the beginning of 2006 through December 31, 2008, we have cumulatively invested approximately $627.4 million in our rig fleet and equipment, which does not include expenditures for acquisitions. Capital expenditures for the year ended December 31, 2008 were $219.0 million, excluding acquisitions. During 2008, we completed four acquisitions for approximately $98.2 million in the aggregate, net of cash acquired. Cash used in investing activities also increased from 2007 to 2008 due to the Company’s investment in Geostream in the fourth quarter of 2008 and the sale of the Company’s marketable securities in the fourth quarter of 2007. The Company expects its capital expenditure program for 2009 to decrease from 2008 and total approximately $130.0 million. Our focus in 2009 will be maintaining and maximizing the utilization of our existing asset base. Cash used in financing activities during 2008 also increased due to the repurchase of approximately $139.4 million of our common stock. In 2007, our Board of Directors authorized a share repurchase program of up to $300 million which is effective through March 31, 2009. From the inception of the program through December 31, 2008, we have repurchased approximately 13.4 million shares of our common stock for approximately $167.3 million. Our share repurchase program, as well as the amount and timing of future repurchases, is subject to market conditions and our financial condition and liquidity. Our Senior Secured 49 Credit Facility permits share repurchases up to $200.0 million and provides that share repurchases in excess of $200.0 million can be made if our debt to capitalization ratio is below 50%. As of December 31, 2008, we would have been permitted to make share repurchases in excess of $200.0 million. Cash outflows from financing activities during 2008 were partially offset by increased proceeds from borrowings on the revolving portion of our Senior Secured Credit Facility. During 2008, we borrowed approximately $172.8 million under the revolving portion of our Senior Secured Credit Facility to finance our acquisitions, fund our initial investment in Geostream and for general corporate purposes. During 2008, we paid down approximately $35.0 million on our outstanding borrowings under the Senior Secured Credit Facility. As of December 31, 2008, we had net working capital (excluding the current portion of long-term debt, notes payable to affiliates, and capital lease obligations of $25.7 million) of $311.5 million. Net working capital at December 31, 2007 (excluding the current portion of long-term debt, notes payable to affiliates, and capital lease obligations of $12.4 million) was $265.4 million. Our working capital increased from December 31, 2007 to December 31, 2008 primarily as a result of increases in our cash and cash equivalents and accounts receivable balances associated with incremental revenues from our acquisitions, higher pricing during 2008 and higher values for our sand inventories due to higher pricing for commodities and freight costs, offset by a decline in our income tax refund receivable and increases in our current accrued liabilities. As of December 31, 2008, approximately $16.9 million of our cash and cash equivalents was held in bank accounts of our foreign subsidiaries, representing approximately 20.3% of total cash and cash equivalents. Of the total amount held by our foreign subsidiaries as of December 31, 2008, approximately $8.9 million was held by our Argentinean subsidiary, with $5.6 million of that amount being held in U.S. bank accounts and denominated in U.S. Dollars; $0.8 million was located in Canada; approximately $7.1 million was held by our Mexican subsidiary, with $1.1 million of that amount being held in U.S. bank accounts; and the remaining $0.1 million located in other countries. We do not believe that the repatriation of any of our cash balances held by our foreign subsidiaries would cause material withholdings. We maintain our cash in bank deposit and brokerage accounts which exceed federally insured limits. As of December 31, 2008, accounts were guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 and substantially all of the Company’s accounts held deposits in excess of the FDIC limits. We believe our current financial condition is strong. As of December 31, 2008, we had $92.7 million in cash and cash equivalents, and working capital, excluding the current portion of long-term debt, notes payable to affiliates and capital lease obligations, of $311.5 million. As of December 31, 2008, $187.8 million of borrowings were outstanding under our revolving credit facility and $53.6 million of letters of credit issued under the letter of credit sub-facility were outstanding, which also reduces the total borrowing capacity under the Senior Secured Credit Facility. We have $139.3 million of availability under our Senior Secured Credit Facility. The availability under our Senior Secured Credit Facility reflects a reduction of approximately $19.3 million of unfunded commitments by Lehman Commercial Paper, Inc. (“LCPI”), a subsidiary of Lehman Brothers Holdings (“Lehman”), one of the members in the syndicate of banks participating in our Senior Secured Credit Facility. We do not believe that the reduction in the available capacity under the Senior Secured Credit Facility has had or will have a material impact on the Company’s liquidity. Our borrowing level at December 31, 2008 represents the highest amount of outstanding borrowings incurred by us during 2008. See “Senior Secured Credit Facility” under “Sources of Liquidity and Capital Resources” below in this “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further discussion of LCPI. 50 At December 31, 2008, our annual debt maturities for our Senior Notes, borrowings under our Senior Secured Credit Facility, notes payable to affiliates and other indebtedness were as follows (in millions): 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Principal Payments (In thousands) $ 16,500 3,015 2,000 189,813 — 425,000 Total principal payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 636,328 At December 31, 2008, the Company is in compliance with all the covenants required under our Senior Notes and the Senior Secured Credit Facility. See “Sources of Liquidity and Capital Resources” and “Liquidity Outlook and Future Capital Requirements” in this “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further discussion of the Senior Notes and the Senior Secured Credit Facility. Sources of Liquidity and Capital Resources The Company’s sources of liquidity include our current cash and cash equivalents, availability under our Senior Secured Credit Facility, and internally generated cash flows from operations. During the fourth quarter of 2007, we refinanced our indebtedness and issued the Senior Notes, using the proceeds from that issuance to retire our then-existing senior credit facility. We also entered into our current Senior Secured Credit Facility during the fourth quarter of 2007. See “Note 12. Long-Term Debt” in “Item 8. Consolidated Financial Statements and Supplementary Data” for further detail. 8.375% Senior Notes On November 29, 2007, we issued the Senior Notes. 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. We used approximately $394.9 million of the net proceeds to retire our term loans, including accrued and unpaid interest, under our then-existing senior credit facility. The Senior Notes are general unsecured senior obligations of Key. Accordingly, 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. Interest on the Senior Notes is payable on June 1 and December 1 of each year. The Senior Notes mature on December 1, 2014. On or after December 1, 2011, the Senior Notes will be subject to redemption at any time and from time to time at our option, in whole or in part, upon not less than 30 nor more than 60 days’ notice, at the redemption prices (expressed as percentages of the principal amount redeemed) set forth below, plus accrued and unpaid interest thereon to the applicable redemption date, if redeemed during the twelve-month period beginning on December 1 of the years indicated below: Year 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Percentage 104.19% 102.09% 100.00% Notwithstanding the foregoing, at any time and from time to time before December 1, 2010, we may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of the outstanding Senior Notes at a redemption price of 108.375% of the principal amount thereof, plus accrued and unpaid interest thereon to the redemption date, with the net cash proceeds of any one or more equity offerings; provided that 51 at least 65% of the aggregate principal amount of the Senior Notes issued under the indenture remains outstanding immediately after each such redemption; and provided, further, that each such redemption shall occur within 180 days of the date of the closing of such equity offering. In addition, at any time and from time to time prior to December 1, 2011, we may, at our option, redeem all or a portion of the Senior Notes at a redemption price equal to 100% of the principal amount thereof plus the applicable premium (as defined in the Indenture) with respect to the Senior Notes and plus accrued and unpaid interest thereon to the redemption date. If we experience a change of control, subject to certain exceptions, we must give holders of the Senior Notes the opportunity to sell to us their Senior Notes, in whole or in part, at a purchase price equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest thereon to the date of purchase. We are subject to certain negative covenants under the Indenture governing the Senior Notes. The indenture limits our ability to, among other things: (cid:129) sell assets; (cid:129) pay dividends or make other distributions on capital stock or subordinated indebtedness; (cid:129) make investments; (cid:129) incur additional indebtedness or issue preferred stock; (cid:129) create certain liens; (cid:129) enter into agreements that restrict dividends or other payments from our subsidiaries to us; (cid:129) consolidate, merge or transfer all or substantially all of our assets; (cid:129) engage in transactions with affiliates; and (cid:129) create unrestricted subsidiaries. These covenants are subject to certain exceptions and qualifications, and contain cross-default provisions in connection with the covenants of our Senior Secured Credit Facility. In addition, substantially all of the covenants will terminate before the Senior Notes mature if one of two specified ratings agencies assigns the Senior Notes an investment grade rating in the future and no events of default exist under the Indenture. 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. In connection with the sale of the Senior Notes, the Company entered into a registration rights agreement with the initial purchasers, pursuant to which it agreed to file an exchange offer registration statement with the SEC with respect to an offer to exchange the Senior Notes for substantially identical notes that would be registered under the Securities Act, and to use reasonable best efforts to cause such registration statement to become effective on or prior to November 29, 2008. In accordance with the agreement, the Company filed an exchange offer registration statement with the SEC, which became effective on August 22, 2008, and offered to exchange an aggregate principal amount of $425.0 million of registered 8.375% Senior Notes due 2014, which the Company refers to as the exchange notes, for any and all of our original unregistered 8.375% Senior Notes due 2014 that were issued in a private offering on November 29, 2007. The terms of the exchange notes were substantially identical to those terms of the original notes, except that transfer restrictions, registration rights and additional interest provisions relating to the originally issued notes did not apply to the exchange notes. References to the “Senior Notes” herein includes exchange notes issued in the exchange offer. Senior Secured Credit Facility Simultaneously with the closing of the offering of the Senior Notes, the Company entered into a new credit agreement with several lenders that provides for a senior secured credit facility (the “Senior Secured Credit Facility”) consisting of a revolving credit facility, letter of credit sub-facility and swing line facility of up to an aggregate principal amount of $400.0 million, all of which will mature no later than November 29, 2012. All obligations under the Senior Secured Credit Facility are guaranteed by most of our subsidiaries and 52 are secured by most of our assets, including our accounts receivable, inventory and equipment. The Senior Secured Credit Facility and the obligations thereunder are secured by substantially all of the assets of the Company and are or will be guaranteed by certain of the Company’s existing and future domestic subsidiaries. The Senior Secured Credit Facility replaced the Company’s Prior Credit Facility, which was terminated in connection with the closing of the offering of the Senior Notes. The interest rate per annum applicable to amounts borrowed under the Senior Secured Credit Facility are, at the Company’s option, (i) LIBOR plus the applicable margin or (ii) the higher of (x) Bank of America’s prime rate and (y) the Federal Funds rate plus 0.5%, plus the applicable margin. The applicable margin for LIBOR loans ranges from 150 to 200 basis points, and the applicable margin for all other loans ranges from 50 to 100 basis points, both of which depend upon the Company’s consolidated leverage ratio. The one-month LIBOR rate at December 31, 2008 was 0.43625%. The Senior Secured Credit Facility contains certain financial covenants, which, among other things, require the maintenance of a consolidated leverage ratio not to exceed 3.50 to 1.00 and a consolidated interest coverage ratio of not less than 3.00 to 1.00, and limit the Company’s capital expenditures to $250.0 million per fiscal year, up to 50% of which amount may be carried over for expenditure in the following fiscal year. Each of the ratios referred to above will be calculated quarterly on a consolidated basis for each trailing four fiscal quarter period. In addition, the Senior Secured Credit Facility contains certain affirmative and negative covenants, including, without limitation, restrictions on (i) liens; (ii) debt, guarantees and other contingent obligations; (iii) mergers and consolidations; (iv) sales, transfers and other dispositions of property or assets; (v) loans, acquisitions, joint ventures and other investments (with acquisitions permitted so long as, after giving pro forma effect thereto, no default or event of default exists under the Senior Secured Credit Facility, the consolidated leverage ratio does not exceed 2.75 to 1.00, the Company is in compliance with the consolidated interest coverage ratio and the Company has at least $25 million of availability under the Senior Secured Credit Facility); (vi) dividends and other distributions to, and redemptions and repurchases from, equity holders; (vii) prepaying, redeeming or repurchasing subordinated (contractually or structurally) debt; (viii) granting negative pledges other than to the lenders; (ix) changes in the nature of the Company’s business; (x) amending organizational documents, or amending or otherwise modifying any debt, any related document or any other material agreement if such amendment or modification would have a material adverse effect; and (xi) changes in accounting policies or reporting practices; in each of the foregoing cases, with certain exceptions. The Senior Secured Credit Facility also contains cross-default provisions in connection with the covenants of the Senior Notes. Further, the Senior Secured Credit Facility permits share repurchases up to $200.0 million and provides that share repurchases in excess of $200.0 million can be made only if our debt to capitalization ratio is below 50%. The Company may prepay the Senior Secured Credit Facility in whole or in part at any time without premium or penalty, subject to certain reimbursements to the lenders for breakage and redeployment costs. On September 15, 2008, Lehman filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. A subsidiary of Lehman, LCPI, was a member of the syndicate of banks participating in our Senior Secured Credit Facility. LCPI’s commitment was approximately 11% of the Company’s total facility. Moncla Notes Payable In connection with the acquisition of Moncla, we entered into two notes payable with its former owners (each, a “Moncla Note” and, collectively, the “Moncla Notes”). The first Moncla Note is an unsecured note in the amount of $12.5 million, which is due and payable in a lump-sum, together with accrued interest, on October 25, 2009. Interest on this note is due on each anniversary of the closing date, which was October 25, 2007. The second Moncla Note is an unsecured note in the amount of $10.0 million is payable in annual installments of $2.0 million, plus accrued interest, beginning October 25, 2008 through 2012. Each of the Moncla Notes bears interest at the Federal Funds rate adjusted annually on the anniversary of the closing date of the Moncla acquisition. 53 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, 2008, there was approximately $23.1 million outstanding under such equipment leases. Off-Balance Sheet Arrangements At December 31, 2008 we did not, and we currently do not, have any off-balance sheet arrangements that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources. Liquidity Outlook and Future Capital Requirements Set forth below is a summary of our contractual obligations as of December 31, 2008. The obligations we pay in future periods reflect certain assumptions, including variability in interest rates on our variable-rate obligations and the duration of our obligations, and actual payments in future periods may vary. Payments Due by Period Total Less than 1 Year (2009) 1-3 Years (2010-2012) (In thousands) 4-5 Years (2013-2014) After 5 Years (2015+) 8.375% Senior Notes due 2014 . . . . . . . . . . $425,000 Interest associated with 8.375% Senior $ — $ — $425,000 $ — Notes due 2014 . . . . . . . . . . . . . . . . . . . . 213,668 35,595 106,883 71,190 Borrowings under Senior Secured Credit Facility . . . . . . . . . . . . . . . . . . . . . . . . . . 187,813 — 187,813 — — — — — Interest associated with Senior Secured Credit Facility(1) . . . . . . . . . . . . . . . . . . . Commitment and availability fees associated with Senior Secured Credit Facility . . . . . Notes payable — related party, excluding 14,238 3,507 10,731 2,480 620 discount . . . . . . . . . . . . . . . . . . . . . . . . . 20,500 14,500 Interest associated with notes payable — related party(1) . . . . . . . . . . . . . . . . . . . . 484 304 1,860 6,000 180 Capital lease obligations, excluding interest and executory costs . . . . . . . . . . . . . . . . . Interest and executory costs associated with capital lease obligations(1) . . . . . . . . . . . . Other long-term indebtedness . . . . . . . . . . . Interest associated with other long-term indebtedness . . . . . . . . . . . . . . . . . . . . . . Investment in Geostream Services Group(2) . . . . . . . . . . . . . . . . . . . . . . . . . Non-cancellable operating leases . . . . . . . . . FIN 48 liabilities . . . . . . . . . . . . . . . . . . . . . Equity based compensation liability awards(3) . . . . . . . . . . . . . . . . . . . . . . . . Earnout payments(4) . . . . . . . . . . . . . . . . . . Sand purchse contract(5) . . . . . . . . . . . . . . . 23,149 9,386 13,440 323 2,577 3,015 70 15,900 28,229 5,600 2,556 26,500 5,176 1,248 2,000 60 15,900 6,312 3,200 898 6,000 2,545 1,274 1,015 10 — 14,242 1,800 1,658 20,500 2,631 55 — — — 5,639 600 — — — — — — — — — — — — — — 2,036 — — — — Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $976,955 $102,075 $370,037 $502,807 $2,036 (1) Interest costs on our floating rate debt were estimated using the rates in effect at December 31, 2008. 54 (2) Based on the December 31, 2008 exchange rate. (3) Based on the Company’s stock price at December 31, 2008. (4) These amounts assume certain performance targets will be achieved. (5) These amounts assume the minimum required purchase and price for the remaining two years of the contract. We believe that our internally generated cash flow 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 2009. As we have historically done, the Company may, from time to time, access available funds under its Senior Secured Credit Facility to supplement its liquidity to meet its 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. As of February 23, 2009, we had $53.6 million of letters of credit issued under the letter of credit sub- facility and approximately $658.3 million of total debt, notes payable and capital leases. As of February 23, 2009 we had cash on hand of $149.7 million and available borrowing capacity of $139.3 million under our Senior Secured Credit facility. This availability reflects the reduction of approximately $19.3 million of unfunded commitments by LCPI. As of February 23, 2009, approximately $13.5 million of our cash and cash equivalents was held in the bank accounts of our foreign subsidiaries, with $5.5 million of that amount being held in U.S. bank accounts and denominated in U.S. Dollars. We believe that these balances could be repatriated for general corporate use without material withholdings. 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. Our Senior Secured Credit Facility also requires us to maintain certain financial performance levels. The financial covenants are as follows: (cid:129) Consolidated Interest Coverage Ratio — As calculated pursuant to the terms of the Senior Secured Credit Facility, we are required to maintain a ratio of trailing four quarters earnings before interest, tax, depreciation and amortization (“EBITDA”) to interest expense of at least 3.0 to 1.0. At December 31, 2008, the calculated consolidated interest coverage ratio was 11.8 to 1.0. Management believes that the Company will remain in compliance with this covenant through at least the end of 2009. (cid:129) Consolidated Leverage Ratio — As calculated pursuant to the terms of the Senior Secured Credit Facility, we are required to maintain a ratio of total debt to trailing four quarters EBITDA of no greater than 3.5 to 1.0. At December 31, 2008, the calculated consolidated leverage ratio was 1.4 to 1.0. With total qualifying debt of $712.9 million at December 31, 2008, this covenant requires that our trailing four quarters EBITDA meet a minimum threshold of $203.7 million. Management believes that the Company will remain in compliance with the covenant through at least the end of 2009. Should the trailing four quarter EBITDA fall below the required threshold in the future, management may also utilize cash on hand to reduce debt outstanding to lower the EBITDA minimum and maintain compliance with this covenant. A breach of any of these covenants, ratios or tests could result in a default under our indebtedness. See “Item 1A. Risk Factors.” Although continued deterioration of market conditions could lead to a downgrade in the credit ratings of companies in our industry, a downgrade of Key’s credit rating would not have an effect on our outstanding debt under either the Senior Secured Credit Facility or the Senior Notes, but would potentially impact our ability to obtain additional external financing, if it was required. 55 During 2009, management plans to continue to invest in our business through capital expenditures, albeit at levels lower than in prior years. Our capital expenditure program for 2009 is expected to total approximately $130.0 million, of which approximately $50.0 million had already been committed, either on order or to fulfill customer requests, as of December 31, 2008; however, that amount is subject to market conditions, including activity levels, commodity prices and industry capacity. Our focus in 2009 will be maximizing the utilization of our current equipment; however, we may seek to increase our 2009 capital expenditure budget in the event international expansion opportunities develop. We currently plan to fund these expenditures through a combination of cash on hand, operating cash flows and borrowings under our Senior Secured Credit Facility. Should our operating cash flows prove to be insufficient to fund these expenditures, management expects it will adjust capital spending plans accordingly. In the fourth quarter of 2009, we are required to make principle payments totaling $14.5 million related to the Moncla Notes. These payments represent a lump sum payment of one Moncla Note totaling $12.5 million and a $2.0 million annual installment payment on the second Moncla Note. We expect to fund our obligations under the Moncla Notes through cash on hand generated by operating activities or borrowings under our Senior Secured Credit Facility. On October 31, 2008, we acquired a 26% interest in Geostream for $17.4 million. Geostream is based in the Russian Federation and provides drilling and workover services and sub-surface engineering and modeling in the Russian Federation. We are contractually required to purchase an additional 24% of Geostream no later than March 31, 2009 for approximately A11.3 million (which at December 31, 2008 was equivalent to $15.9 million). 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%. 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. We expect to fund our obligation to Geostream through cash on hand generated by operating cash flows or from borrowings under our Senior Secured Credit Facility. While management anticipates that 2009 may be a period of lower demand and prices for our services, we believe that our operating cash flow, cash on hand and available borrowings, coupled with our ability to control our capital expenditures, will be sufficient to maintain adequate liquidity throughout 2009. CRITICAL ACCOUNTING POLICIES Our Accounting Department is responsible for the development and application of our accounting policies and internal control procedures. It reports to the principal financial officer. The process and preparation of our financial statements in conformity with generally accepted accounting principles in the United States (“GAAP”) requires our management to make certain estimates, judgments and assumptions, which may affect 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 for the period ended. 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. As such, 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: (cid:129) Estimate of reserves for workers’ compensation, vehicular liability and other self-insured reserves; (cid:129) Accounting for contingencies; (cid:129) Accounting for income taxes; (cid:129) Estimate of fixed asset depreciable lives; (cid:129) Valuation of tangible and intangible assets; and (cid:129) Valuation of equity-based compensation. 56 Workers’ Compensation, Vehicular Liability and Other Self-Insurance Reserves Well servicing and workover 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 incorporate significant numbers 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 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. 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. 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. 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, automobiles and rigs. Our accruals that we maintain on our consolidated balance sheet relate to these deductibles and self-insured retentions, which we estimate through the use of historical claims data and trend analysis. The actual outcome of any claim could differ significantly from estimated amounts. We adjust loss estimates in the calculation of these accruals, based upon actual claim settlements and reported claims. Accounting for Contingencies In addition to our workers’ compensation, vehicular liability and other self-insurance reserves, we record other loss contingencies, which relate to numerous lawsuits, claims, proceedings and tax-related audits in the normal course of our operations on our consolidated balance sheet. In accordance with SFAS No. 5, Accounting for Contingencies (“SFAS 5”), 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 review our loss contingencies routinely 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 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. 57 Under the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”), 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. Accounting for Income Taxes We follow SFAS No. 109, Accounting for Income Taxes (“SFAS 109”), which requires that 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 portion or all of the deferred tax assets will not be realized in future periods. To assess the likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which this taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted results, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. Additionally, we record reserves for uncertain tax positions that are subject to management judgment related to the resolution of the tax positions and completion of audits by tax authorities in the domestic and international tax jurisdictions in which we operate. Please see “Note 11. Income Taxes” in “Item 8. Consolidated 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. 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 58 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. Valuation of Intangible and Tangible Assets The Company periodically reviews its intangible assets not subject to amortization, including goodwill, to determine whether an impairment of those assets may exist. SFAS 142 requires that these tests 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 intangibles is a two step test. In the first step of the test, a fair value is calculated for each of the Company’s reporting units, and that fair value is compared to the carrying value of the reporting unit, including the reporting unit’s goodwill. If the fair value of the reporting unit exceeds its carrying value, there is no impairment, and the second step of the test is not performed. If the carrying value exceeds the fair value for the reporting unit, then the second step of the test is required. The second step of the test compares the implied fair value of the reporting unit’s goodwill to its carrying value. The implied fair value of the reporting unit’s goodwill is determined in the same manner as the amount of goodwill recognized in a business combination, with the purchase price being equal to the fair value of the reporting unit. If the implied fair value of the reporting unit’s goodwill is in excess of its carrying value, no impairment is recorded. If the carrying value is in excess of the implied fair value, an impairment equal to the excess is recorded. The Company conducts its annual impairment test for goodwill on December 31 of each year. In determining the fair value of the Company’s reporting units, management uses a weighted-average approach of three commonly used valuation techniques — a discounted cash flow method, a guideline companies method, and a similar transaction method. The Company’s management assigns 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 2008, because of the acquisitions and international investments made by the Company over the prior two years and the overall economic downturn and the decline in the Company’s stock price and market valuation during 2008, management assigned more weighting to the discounted cash flow method than other methods. In prior years the Company had assigned higher weightings 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 significant estimates and assumptions to be made by management. The discounted cash flow method, which is assigned the highest weight by management, requires assumptions about future cash flows, future growth rates, and discount rates. The assumptions about future cash flows and growth rates are based on the Company’s budgets and strategic plans, as well as the beliefs of management about future activity levels. Discount rate assumptions include an assessment of the specific risk associated with the reporting unit being tested. To assist management in the preparation and analysis of the valuation of the Company’s reporting units, management utilized the services of a third-party valuation consultant, who reviewed management’s estimates, assumptions and calculations. The ultimate conclusions of the valuation techniques remain the sole responsibility of the Company’s management. While this test is required on an annual basis, it also can be required more frequently based on changes in external factors. While we do not currently expect that additional tests would result in an additional charge, the fair value used in the test is heavily impacted by the market prices of our equity and debt securities, and could result in impairment charges in the future. Unlike goodwill and indefinite-lived intangible assets, fixed assets and finite-lived intangibles are not tested for impairment on a recurring basis, but only when circumstances or events indicate that 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. 59 If a trigger event occurs, an impairment test pursuant to the guidelines established by SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”), is performed based on an undiscounted cash flow analysis. To perform an impairment test, we make judgments, estimates and assumptions regarding long-term forecasts of revenues and expenses relating to 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 of management. Using different judgments, these estimates could differ significantly and actual financial results could differ materially from these estimates. These long-term forecasts are used in the impairment tests to determine if an asset’s carrying value is recoverable or if a write-down to fair value is required. If the analysis determines that the assets of a reporting unit or asset grouping are impaired, then an impairment charge is recorded. Valuation of Equity-Based Compensation We account for share based compensation under the provisions of SFAS No. 123 (revised 2004), Share- Based Payment (“SFAS 123(R)”), which we adopted on January 1, 2006. We adopted the provisions of SFAS 123(R) using the modified prospective transition method. The Company has granted stock options, stock-settled stock appreciation rights (“SARs”), restricted stock (“RSAs”), and phantom shares (“Phantom Shares”) to its employees and non-employee directors. Option and SAR awards granted by the Company are fair valued using a Black-Scholes option model 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. Please see “Note 17. Share-Based Compensation” in “Item 8. Consolidated 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 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, 2008, 2007 and 2006: Year Ended December 31, 2008 2006 2007 Risk-free interest rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expected life of options, years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expected volatility of the Company’s stock price . . . . . . . . . . . . . . . . . . . . Expected dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 2.86% 4.41% 4.70% 6 36.86% 39.49% 48.80% none none none 6 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, we have relied primarily on our actual experience with our previous stock option grants. 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 100 basis point increase in our expected volatility and risk-free interest rate at the grant date would have increased our compensation expense for the year ended December 31, 2008 by approximately $1.0 million. 60 New Accounting Standards Adopted in this Report FIN 48 and FSP FIN 48-1. In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation (“FIN”) No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (“FIN 48”), which provides clarification of SFAS 109 with respect to the recognition of income tax benefits of uncertain tax positions in financial statements. FIN 48 requires that uncertain tax positions be reviewed and assessed, with recognition and measurement of the tax benefit based on a “more likely than not” standard. In May 2007 the FASB issued FASB Staff Position (“FSP”) FIN 48-1 (“FSP FIN 48-1”). FSP FIN 48-1 provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. In determining whether a tax position has been effectively settled, entities must evaluate (i) whether taxing authorities have completed their examination procedures; (ii) whether the entity intends to appeal or litigate any aspect of a tax position included in a completed evaluation; and (iii) whether it is remote that a taxing authority would examine or re-examine any aspect of a taxing position. FSP FIN 48-1 is to be applied upon the initial adoption of FIN 48. We adopted the provisions of FIN 48 and FSP FIN 48-1 on January 1, 2007 and recorded a $1.3 million decrease to the balance of our retained earnings as of January 1, 2007 to reflect the cumulative effect of adopting these standards. FSP EITF 00-19-2. In December 2006, the FASB issued FSP EITF 00-19-2, Accounting for Registration Payment Arrangements (“FSP EITF 00-19-2”). FSP EITF 00-19-2 addresses accounting for Registration Payment Arrangements (“RPAs”), which are provisions within financial instruments such as equity shares, warrants or debt instruments in which the issuer agrees to file a registration statement and to have that registration statement declared effective by the SEC within a specified grace period. If the registration statement is not declared effective within the grace period or its effectiveness is not maintained for the period of time specified in the RPA, the issuer must compensate its counterparty. The FASB Staff concluded that the contingent obligation to make future payments or otherwise transfer consideration under a RPA should be recognized as a liability and measured in accordance with SFAS 5 and FIN No. 14, Reasonable Estimation of the Amount of a Loss, and that the RPA should be recognized and measured separately from the instrument to which the RPA is attached. In January 1999, the Company completed the private placement of 150,000 units consisting of $150.0 million of 14% Senior Subordinated Notes due January 25, 2009 (the “14% Senior Subordinated Notes”) and 150,000 warrants to purchase an aggregate of approximately 2.2 million shares of the Company’s common stock at an exercise price of $4.88125 per share (the “Warrants”). Under the terms of the Warrants, we were required to maintain an effective registration statement covering the shares of common stock issuable upon exercise of the Warrants. Due to our past failure to file our SEC reports in a timely manner, we did not have an effective registration statement covering the Warrants, and were required to make liquidated damages payments. The requirement to make liquidated damages payments constituted an RPA under the provisions of FSP EITF 00-19-2, and as prescribed by the transition provisions of that standard, on January 1, 2007 the Company recorded a pre-tax current liability of approximately $1.0 million, which is equivalent to the payments for the Warrant RPA for one year, with an offsetting adjustment to the opening balance of retained earnings. SFAS 157. In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”), effective for periods beginning on or after January 1, 2008. SFAS 157 establishes a framework for measuring fair value and requires expanded disclosure about the information used to measure fair value. The statement applies whenever other statements require or permit assets or liabilities to be measured at fair value, and does not expand the use of fair value accounting in any new circumstances. The adoption of this standard did not have a material impact on our consolidated financial statements. SFAS 159. The Company adopted Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Liabilities, including an amendment of FASB Statement No. 115 (“SFAS 159”), on January 1, 2008. SFAS 159 permits companies to choose, at specified election dates, to measure eligible items at fair value (the “Fair Value Option”). Companies choosing such an election report unrealized gains and 61 losses on items for which the Fair Value Option has been elected in earnings at each subsequent reporting period. We did not elect to measure any of our financial assets or liabilities using the Fair Value Option. We will assess at each measurement date whether to use the Fair Value Option on any future financial assets or liabilities as permitted pursuant to the provisions of SFAS 159. FSP SFAS 157-3. In October 2008, the FASB issued FSP SFAS No. 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active (“FSP 157-3”). FSP SFAS 157-3 clarified the application of SFAS 157. FSP SFAS 157-3 demonstrated how the fair value of a financial asset is determined when the market for that financial asset is inactive. FSP SFAS 157-3 was effective upon issuance, including prior periods for which financial statements had not been issued. The implementation of this standard did not have a material impact on our consolidated financial statements. Accounting Standards Not Yet Adopted in this Report FSP SFAS 142-3. In April 2008, the FASB issued FSP SFAS No. 142-3, Determination of Useful Life of Intangible Assets (“FSP 142-3”). FSP SFAS 142-3 amends the factors that should be considered in developing the renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS 142. FSP SFAS 142-3 also requires expanded disclosure regarding the determination of intangible asset useful lives. FSP SFAS 142-3 is effective for fiscal years beginning after December 15, 2008. We are currently evaluating the potential impact the adoption of FSP SFAS 142-3 will have on our consolidated financial statements. SFAS 161. In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. This statement is effective for financial statements issued for fiscal periods beginning after November 15, 2008. The Company currently has no financial instruments that qualify as derivatives, and we do not expect that the adoption of this standard will have a material impact on the Company’s financial position, results of operations and cash flows. FSP SFAS 157-2. In February 2008, the FASB issued FSP SFAS No. 157-2, Effective Date of FASB Statement No. 157 (“FSP 157-2”), to partially defer SFAS 157. FSP 157-2 defers the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), to fiscal years, and interim periods within those fiscal years, beginning after November 15, 2008. We are currently evaluating the impact of adopting the provisions of SFAS 157 as it relates to nonfinancial assets and liabilities. SFAS 141(R). In December 2007, the FASB issued SFAS No. 141 (Revised 2007), Business Combina- tions (“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 current 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, 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. SFAS 141(R) may have an impact on our consolidated financial statements. The nature and magnitude of the specific impact will depend upon the nature, terms, and size of the acquisitions consummated after the effective date. 62 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. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is not permitted. We are currently evaluating the potential impact of this statement. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We are exposed to certain market risks as part of our ongoing business operations, including risks from changes in interest rates, foreign currency exchange rates and equity prices that could impact our financial position, results of operations and cash flows. We manage our exposure to these risks through regular operating and financing activities, and may, on a limited basis, use derivative financial instruments to manage this risk. To the extent that we use such derivative financial instruments, we will use them only as risk management tools and not for speculative investment purposes. Interest Rate Risk As of December 31, 2008, 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 the Moncla Notes all bear interest at variable interest rates, and therefore expose us to interest rate risk. As of December 31, 2008, the weighted average interest rate on our outstanding variable-rate debt obligations was 4.17%. A hypothetical 10% increase in that rate would increase the annual interest expense on those instruments by approximately $0.5 million. Foreign Currency Risk As of December 31, 2008, we conduct operations in Argentina and Mexico, and also own Canadian subsidiaries and have equity-method investments in a Canadian company and a Russian company. 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 and Canadian subsidiaries and our Canadian and Russian investments would decrease our net income by approximately $1.3 million. Equity Risk We account for our equity-based compensation awards at fair value under the provisions of SFAS 123(R). Certain of these awards’ fair values are determined based upon the price of the Company’s common stock on the measurement date. Any increase in the price of the Company’s common stock would lead to a corresponding increase in the fair value of those awards. A 10% increase in the price of the Company’s common stock from its value at December 31, 2008 would increase annual compensation expense recognized on these awards by approximately $0.1 million. 63 ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Key Energy Services, Inc. and Subsidiaries INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Comprehensive Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Cash Flows. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Stockholders’ Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Page 65 66 67 68 69 70 71 72 64 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors and Shareholders of Key Energy Services, Inc. We have audited the accompanying consolidated balance sheets of Key Energy Services, Inc. and subsidiaries (a Maryland corporation) as of December 31, 2008 and 2007, 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, 2008. 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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 1 to the consolidated financial statements, effective January 1, 2007, the Company adopted the provisions of Financial Accounting Standards Interpretation No. 48, Accounting for Uncertainty in Income Taxes. As discussed in Note 1 to the consolidated financial statements, effective January 1, 2007, the Company adopted the provisions of FSP EITF 00-19-2, Accounting for Registration Payment Arrangements. 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, 2008, 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 24, 2009 expressed an adverse opinion on the effectiveness of internal control over financial reporting. /s/ GRANT THORNTON LLP Houston, Texas February 24, 2009 65 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors and Shareholders of Key Energy Services, Inc. We have audited Key Energy Services, Inc.’s and subsidiaries (a Maryland Corporation) internal control over financial reporting as of December 31, 2008, 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. A material weakness is a deficiency, or combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management’s assessment. Payroll: The Company determined that deficiencies surrounding its payroll process, in particular, lack of proper documentation concerning hours worked, employee master file data and rate changes coupled with deficiencies with reconciliations where payroll or payroll related data was a major component, constituted a material weakness in its system of internal controls. In our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Key Energy Services, Inc. and subsidiaries have not maintained effective internal control over financial reporting as of December 31, 2008, 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. The material weakness identified above was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2008 consolidated financial statements, and this report does not affect our report dated February 24, 2009, which expressed an unqualified opinion on those consolidated financial statements. /s/ GRANT THORNTON LLP Houston, Texas February 24, 2009 66 Key Energy Services, Inc. and Subsidiaries CONSOLIDATED BALANCE SHEETS December 31, 2007 2008 (In thousands, except share amounts) Current assets: ASSETS Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Accounts receivable, net of allowance for doubtful accounts of $11,468 and 92,691 $ 58,503 377,353 $13,501, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34,756 Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,513 Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26,623 Deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,848 Income taxes receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,338 Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 559,122 Total current assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,858,307 Property and equipment, gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (806,624) Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,051,683 Property and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 320,992 Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42,345 Other intangible assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,489 Deferred financing costs, net. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 336 Notes and accounts receivable — related parties . . . . . . . . . . . . . . . . . . . . . . . . . . 24,220 Equity method investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,736 TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,016,923 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current portion of capital lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current notes payable — related parties, net of discount . . . . . . . . . . . . . . . . . . . Current portion of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Capital lease obligations, less current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . Notes payable — related parties, less current portion . . . . . . . . . . . . . . . . . . . . . . . Long-term debt, less current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Workers’ compensation, vehicular, health and other insurance claims . . . . . . . . . . . Deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other non-current accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Minority interest. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Commitments and contingencies Stockholders’ equity: Common stock, $0.10 par value; 200,000,000 shares authorized, 121,305,289 46,185 197,116 4,368 9,386 14,318 2,000 273,373 13,763 6,000 613,828 43,151 188,581 17,495 — 343,408 22,849 12,997 27,676 15,796 6,636 487,865 1,595,225 (684,017) 911,208 378,550 45,894 12,117 173 11,217 12,053 $1,859,077 $ 35,159 183,364 3,895 10,701 1,678 — 234,797 16,114 20,500 475,000 43,818 160,068 19,531 251 and 131,142,905 shares issued and outstanding, respectively . . . . . . . . . . . . . . 12,131 601,872 Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (46,550) Accumulated other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 293,279 Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total stockholders’ equity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 860,732 TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY . . . . . . . . . . . . . . . $2,016,923 13,114 704,644 (37,981) 209,221 888,998 $1,859,077 See the accompanying notes which are an integral part of these consolidated financial statements 67 Key Energy Services, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF OPERATIONS REVENUES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,972,088 COSTS AND EXPENSES: Year Ended December 31, 2006 2007 2008 (In thousands, except per share amounts) $1,662,012 $1,546,177 Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation and amortization expense . . . . . . . . . . . . . . . . . . . . Impairment of goodwill and equity method investment . . . . . . . . . General and administrative expenses . . . . . . . . . . . . . . . . . . . . . . Interest expense, net of amounts capitalized . . . . . . . . . . . . . . . . . Loss on early extinguishment of debt. . . . . . . . . . . . . . . . . . . . . . (Gain) loss on sale of assets, net . . . . . . . . . . . . . . . . . . . . . . . . . Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other expense (income), net . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,250,327 170,774 75,137 257,707 41,247 — (641) (1,236) 4,717 985,614 129,623 — 230,396 36,207 9,557 1,752 (6,630) (447) 920,602 126,011 — 195,527 38,927 — (4,323) (5,574) 527 Total costs and expenses, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,798,032 1,386,072 1,271,697 Income before income taxes and minority interest . . . . . . . . . . . . . . Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Minority interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 174,056 (90,243) 245 275,940 (106,768) 117 274,480 (103,447) — NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 84,058 $ 169,289 $ 171,033 EARNINGS PER SHARE: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.68 0.67 $ $ 1.29 1.27 $ $ 1.30 1.28 WEIGHTED AVERAGE SHARES OUTSTANDING: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124,246 125,565 131,194 133,551 131,332 134,064 See the accompanying notes which are an integral part of these consolidated financial statements 68 Key Energy Services, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $84,058 OTHER COMPREHENSIVE (LOSS) INCOME, NET OF TAX: 2008 Year Ended December 31, 2007 (In thousands) $169,289 2006 $171,033 Foreign currency translation loss, net of tax of $(952), $0, and $0, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net deferred (loss) gain from cash flow hedges, net of tax of $0, $(115), and $115, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred (loss) gain from available for sale investments, net of tax of $0, $(97), and $97, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (8,561) (1,281) (51) — (8) (213) (203) 213 181 COMPREHENSIVE INCOME, NET OF TAX. . . . . . . . . . . . . . . . . . . . . $75,489 $167,592 $171,376 See the accompanying notes which are an integral part of these consolidated financial statements 69 Key Energy Services, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF CASH FLOWS 2008 Year Ended December 31, 2007 (In thousands) 2006 CASH FLOWS FROM OPERATING ACTIVITIES: Net income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 84,058 Adjustments to reconcile net income to net cash provided by operating activities: Minority interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation and amortization expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion on asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income from equity method investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Impairment of goodwill and equity method investment . . . . . . . . . . . . . . . . . . . . Amortization of deferred financing costs and discount . . . . . . . . . . . . . . . . . . . . Deferred income tax expense. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Capitalized interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (Gain) loss on sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss on early extinguishment of debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Share-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Excess tax benefits from share-based compensation . . . . . . . . . . . . . . . . . . . . . . (245) 170,774 594 (160) 75,137 2,115 29,747 (6,514) (641) — 24,233 (1,733) Changes in working capital: (34,906) (516) (15,622) 46,375 — — (5,532) 367,164 Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Share-based compensation liability awards . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable, accrued interest and accrued expenses . . . . . . . . . . . . . . . . . . Income tax refund receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash paid for legal settlement with former chief executive officer . . . . . . . . . . . . Other assets and liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from sale of fixed assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Investment in Geostream Services Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acquisitions, net of cash acquired of $2,017, $2,154, and $0, respectively . . . . . . . . Acquisition of fixed assets from asset purchases . . . . . . . . . . . . . . . . . . . . . . . . . . Cash paid for short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from the sale of short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . Acquisition of intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . CASH FLOWS FROM FINANCING ACTIVITIES: — Repayments of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Proceeds from long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (35,000) Payments on revolving credit facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 172,813 Borrowings under revolving credit facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (11,506) Repayments of capital lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,026) Repayments of other long-term indebtedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Repayments of debt assumed in acquisition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (314) Proceeds paid for deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (139,358) Repurchases of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,688 Proceeds from exercise of stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,733 Excess tax benefits from share-based compensation . . . . . . . . . . . . . . . . . . . . . . . . (7,970) Net cash (used in) provided by financing activities . . . . . . . . . . . . . . . . . . . . . . . 4,068 Effect of exchange rates on cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34,188 Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . 58,503 Cash and cash equivalents, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 92,691 (218,994) 7,961 (19,306) (63,457) (34,468) — 276 (1,086) (329,074) $ 169,289 $ 171,033 (117) 129,623 585 (387) — 1,680 24,613 (5,296) 1,752 9,557 9,355 (3,401) (44,712) 3,701 (424) (1,360) (15,154) (21,200) (8,185) 249,919 (212,560) 8,427 — (157,955) — (121,613) 183,177 (2,323) (302,847) (396,000) 425,000 — 50,000 (11,316) — (17,435) (13,400) (30,454) 13,444 3,401 23,240 (184) (29,872) 88,375 $ 58,503 — 126,011 508 (416) — 1,620 6,757 (3,358) (4,323) — 6,345 — (60,801) — 976 35,138 (642) — (20,124) 258,724 (195,830) 11,658 — — — (83,769) 22,294 — (245,647) (4,000) — — — (12,975) — — (479) (1,180) — — (18,634) (238) (5,795) 94,170 $ 88,375 See the accompanying notes which are an integral part of these consolidated financial statements 70 Key Energy Services, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY Common Stock Number of Shares Amount at par Additional Paid-in Capital Accumulated Other Comprehensive (Loss) Income Retained (Deficit) Earnings Total (In thousands) BALANCE AT DECEMBER 31, 2005 . . . . . . . . . . . . . . . . . . . . . . . . 131,334 $13,133 $ 706,749 $(36,627) $(129,198) $ 554,057 Comprehensive income, net of tax . . Common stock purchases . . . . . . . . . Share-based compensation . . . . . . . . Tax benefits from share-based compensation . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . BALANCE AT DECEMBER 31, — (81) 371 — — — (8) 37 — — — (1,172) 6,181 40 — 343 — — — — — — — 343 (1,180) 6,218 — 171,033 40 171,033 2006 . . . . . . . . . . . . . . . . . . . . . . . . 131,624 13,162 711,798 (36,284) 41,835 730,511 Effect of adoption of FIN 48 . . . . . . Effect of adoption of EITF 00-19-2, net of tax . . . . . . . . . . . . . . . . . . . — — — — — — — — (1,272) (1,272) (631) (631) Adjusted balance, beginning of year . . . . . . . . . . . . . . . . . . . . . . 131,624 13,162 711,798 (36,284) 39,932 728,608 Comprehensive loss, net of tax . . . . . Common stock purchases . . . . . . . . . Exercise of stock options . . . . . . . . . Exercise of warrants . . . . . . . . . . . . Share-based compensation . . . . . . . . Tax benefits from share-based compensation . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . — (2,414) 1,592 23 318 — — — (241) 159 2 32 — — — (33,161) 13,285 (2) 9,323 3,401 — (1,697) — — — — — (1,697) — (33,402) 13,444 — — — 9,355 — — — — 169,289 3,401 169,289 BALANCE AT DECEMBER 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . 131,143 13,114 704,644 (37,981) 209,221 888,998 Comprehensive loss, net of tax . . . . . Common stock purchases . . . . . . . . . Exercise of stock options . . . . . . . . . Exercise of warrants . . . . . . . . . . . . Share-based compensation . . . . . . . . Tax benefits from share-based compensation . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . BALANCE AT DECEMBER 31, — (11,183) 757 160 428 — (1,118) 76 16 43 — (135,291) 6,612 (16) 24,190 (8,569) — — — — — (8,569) — (136,409) 6,688 — — — 24,233 — — — — — 1,733 — — — — 84,058 1,733 84,058 2008 . . . . . . . . . . . . . . . . . . . . . . . . 121,305 $12,131 $ 601,872 $(46,550) $ 293,279 $ 860,732 See the accompanying notes which are an integral part of these consolidated financial statements 71 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Key Energy Services, Inc., its wholly-owned subsidiaries and its controlled subsidiaries (collectively, “Key,” the “Company,” “we,” “us,” “its,” and “our”) provide a complete range of well services to major oil companies, foreign national oil companies and independent oil and natural gas production companies, including rig-based well maintenance, workover, well completion and recompletion services, fluid management services, pressure pumping services, fishing and rental services and ancillary oilfield services. We operate in most major oil and natural gas producing regions of the United States as well as internationally in Argentina and Mexico. We also own a technology development company based in Canada and have equity interests in oilfield service companies in Canada and the Russian Federation. Basis of Presentation The consolidated financial statements and associated schedules included in this Annual Report on Form 10-K present our financial position, results of operations and cash flows for the periods presented in accordance with generally accepted accounting principles in the United States (“GAAP”). The preparation of these consolidated financial statements requires us to develop estimates and to make assumptions that affect our financial position, results of operations and cash flows. These estimates also impact the nature and extent of our disclosure, if any, of our contingent liabilities. Among other things, we use estimates to (i) analyze assets for possible impairment, (ii) determine depreciable lives for our assets, (iii) assess future tax exposure and realization of deferred tax assets, (iv) determine amounts to accrue for contingencies, (v) value tangible and intangible assets, (vi) assess workers’ compensation, vehicular liability, self-insured risk accruals and other insurance reserves, (vii) provide allowances for our uncollectible accounts receivable, and (viii) value our equity-based compensation. We review all significant estimates on a recurring basis and record the effect of any necessary adjustments prior to publication of our financial statements. Adjustments made with respect to the use of estimates relate to improved information not previously available. Because of the limitations inherent in this process, our actual results may differ materially from these estimates. We believe that our estimates are reasonable. Certain reclassifications have been made to prior period amounts to conform to current period financial statement classifications. We now present our short-term investments in marketable securities as a component of other current assets in the accompanying consolidated balance sheets. In prior years, we presented these amounts as a separate component of current assets. We apply the provisions of Emerging Issues Task Force (“EITF”) Issue 04-10, Determining Whether to Aggregate Operating Segments That Do Not Meet Quantitative Thresholds (“EITF 04-10”) for our segment reporting in “Note 19. Segment Information.” Under the provisions of EITF 04-10, operating segments that do not individually meet the aggregation criteria described in Statement of Financial Accounting Standards (“SFAS”) No. 131, Disclosures About Segments of an Enterprise and Related Information (“SFAS 131”), may be combined with other operating segments that do not individually meet the aggregation criteria to form a separate reportable segment. We have combined all of our operating segments that do not individually meet the aggregation criteria established in SFAS 131 to form the “Corporate and Other” segment in our segment reporting. Principles of Consolidation Within our consolidated financial statements, we include our accounts and the accounts of our majority- owned or controlled subsidiaries. We eliminate intercompany accounts and transactions. When we have an interest in an entity for which we do not have significant control or influence, we account for that interest using the cost method. When we have an interest in an entity and can exert significant influence but not control, we account for that interest using the equity method. 72 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) As further discussed in “Note 2. Acquisitions,” in September 2007 we completed the acquisition of Advanced Measurements, Inc. (“AMI”), a privately-held Canadian company focused on oilfield technology. Prior to the acquisition, AMI owned a portion of another Canadian company, Advanced Flow Technologies, Inc. (“AFTI”). As part of the acquisition, AMI increased its ownership percentage of AFTI to 51.46%. At December 31, 2007, we consolidated the assets, liabilities, results of operations and cash flows of AFTI into our consolidated financial statements, with the portion of AFTI remaining outside of our control forming a minority interest in our consolidated financial statements. Our ownership of AFTI declined to 48.73% during the fourth quarter of 2008 due to the issuance of additional shares by AFTI. As a result, we deconsolidated AFTI from our consolidated financial statements at December 31, 2008 and accounted for that interest under the equity method. We apply Financial Accounting Standards Board (“FASB”) Interpretation (“FIN”) No. 46, Consolidation of Variable Interest Entities — an Interpretation of ARB No. 51 (Revised 2003) (“FIN 46(R)”) when determining whether or not to consolidate a Variable Interest Entity (“VIE”). FIN 46(R) requires that an equity investor in a VIE have significant equity at risk (generally a minimum of 10%) and hold a controlling interest, evidenced by voting rights, and absorb a majority of the entity’s expected losses, receive a majority of the entity’s expected returns, or both. If the equity investor is unable to evidence these characteristics, the entity that retains these ownership characteristics will be required to consolidate the VIE. We have determined that we do not have an interest in a VIE, and as such we are not the primary beneficiary of a variable interest in a VIE and are not the holder of a significant variable interest in a VIE. Revenue Recognition We recognize revenue when all of the following criteria established in the Securities and Exchange Commission (the “SEC”) Staff Accounting Bulletin (“SAB”) No. 101, Revenue Recognition in Financial Statements (“SAB 101”), as amended by SAB No. 104, Revenue Recognition (“SAB 104”), have been met: (i) evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price to the customer is fixed and determinable and (iv) collectibility is reasonably assured. (cid:129) Evidence of an arrangement exists when a final understanding between the Company and its customer has occurred, and can be evidenced by a completed customer purchase order, field ticket, supplier contract, or master service agreement. (cid:129) Delivery has occurred or services have been rendered when the Company has completed what is required pursuant to the terms of the arrangement and can be evidenced by a completed field ticket or service log. (cid:129) The price to the customer is fixed and determinable when the amount that is required to be paid is agreed upon. Evidence of the price being fixed and determinable is evidenced by contractual terms, a Company price book, a completed customer purchase order, or a completed customer field ticket. (cid:129) Collectibility is reasonably assured as a result of the Company screening its customers and providing goods and services to customers that have been granted credit terms in accordance with the Company’s credit policy. In accordance with EITF Issue No. 06-03, How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (That is, Gross versus Net Presenta- tion) (“EITF 06-03”), we present our revenues net of any sales taxes collected by us from our customers that are required to be remitted to local or state governmental taxing authorities. 73 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Cash and Cash Equivalents We consider short-term investments with an original maturity of less than three months to be cash equivalents. None of our cash is restricted, and we have not entered into any compensating balance arrangements. However, at December 31, 2008, all of our obligations under our Senior Secured Credit Facility were secured by most of our assets, including assets held by our subsidiaries, which includes our cash and cash equivalents. We restrict investment of cash to financial institutions with high credit standing and limit the amount of credit exposure to any one financial institution. We maintain our cash in bank deposit and brokerage accounts which exceed federally insured limits. As of December 31, 2008, accounts were guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 and substantially all of the Company’s accounts held deposits in excess of the FDIC limits. Certain of our cash accounts are zero-balance controlled disbursement accounts that do not have right of offset against our other cash balances. In accordance with FIN No. 39, Offsetting of Amounts Related to Certain Contracts, an Interpretation of APB No. 10 and FASB Statement No. 105 (“FIN 39”), we present the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets. Investment in Debt and Equity Securities We account for investments in debt and equity securities under the provisions of SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities (“SFAS 115”). Under SFAS 115, investments are classified as either “trading,” “available for sale,” or “held to maturity,” depending on management’s intent regarding the investment. Securities classified as “trading” are carried at fair value, with any unrealized holding gains or losses reported currently in earnings. Securities classified as “available for sale” or “held to maturity” are carried at fair value, with any unrealized holding gains or losses, net of tax, reported as a separate component of shareholders’ equity in other comprehensive income. Accounts Receivable and Allowance for Doubtful Accounts We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of the outstanding balances. We regularly review collectibility and establish or adjust our allowance as necessary using the specific identification method. From time to time we are entitled to proceeds under our insurance policies, and in accordance with FIN No. 39, we present insurance receivables gross on our balance sheet as a component of accounts receivable, separate from the corresponding liability. Concentration of Credit Risk and Significant Customers Key’s customers include major oil and natural gas production companies, independent oil and natural gas production companies, and foreign national oil and natural gas production companies. We perform ongoing credit evaluations of our customers and usually do not require material collateral. We maintain reserves for potential credit losses when necessary. Our results of operations and financial condition should be considered in light of the fluctuations in demand experienced by oilfield service companies as changes in oil and gas producers’ expenditures and budgets occur. These fluctuations can impact our results of operations and financial condition as supply and demand factors directly affect utilization and hours which are the primary determinants of our net cash provided by operating activities. For all periods presented, no single customer accounted for more than ten percent of our consolidated revenue. 74 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Inventories Inventories, which consist primarily of equipment parts for use in our well servicing operations, sand and chemicals for our pressure pumping operations, and supplies held for consumption, are valued at the lower of average cost or market. Property and Equipment Property and equipment are carried at cost less accumulated depreciation. Depreciation is provided for our assets over the estimated depreciable lives of the assets using the straight-line method. We depreciate our operational assets over their depreciable lives to their salvage value, which is a fair value higher than the assets’ value as scrap. Salvage value approximates 10% of an operational asset’s acquisition cost. When an operational asset is stacked or taken out of service, we review its physical condition, depreciable life and ultimate salvage value to determine if the asset is no longer operable and whether the remaining depreciable life and salvage value should be adjusted. . In the first quarter of 2007, management reassessed the estimated useful lives assigned to all of the Company’s equipment in light of the higher activity and utilization levels experienced in 2006 and early 2007. As a result, the maximum estimated useful lives of certain assets were adjusted to reflect higher annual utilization. As a result, the useful life expected for a well service rig was reduced from an average expected life of 17 years to 15 years. With respect to oilfield trucks, trailers and related equipment the expected life was reduced from an average expected life of 15 years to 12 years. Management also determined that the life assigned to a self-remanufactured well service rig should be the same as the 15-year life assigned to a newly constructed well service rig acquired from third parties. As of December 31, 2008, the estimated useful lives of the Company’s asset classes are as follows: Description Years 3-15 Well service rigs and components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-12 Oilfield trucks, pressure pumping equipment, and related equipment . . . . . . . . . . . . . . . . . . . 3-5 Motor vehicles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-10 Fishing and rental tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Disposal wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15-30 Furniture and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-7 Buildings and improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15-30 The Company leases certain of its operating assets under capital lease obligations whose terms run from 55 to 60 months. These assets are depreciated over their estimated useful lives or the term of the capital lease obligation, whichever is shorter. We apply SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”) in reviewing our long-lived assets for possible impairment. This statement requires that long-lived assets held and used by us, including certain identifiable intangibles, be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. For purposes of testing for impairment, we group our long-lived assets into divisions, which are based on geographical regions or the services provided. We then compare the estimated future cash flows of each division to the division’s net carrying value. The division level represents the lowest level for which identifiable cash flows are available. We would record an impairment charge, reducing the division’s net carrying value to an estimated fair value, if its estimated future cash flows were less than the division’s net carrying value. “Trigger events,” as defined in SFAS 144, that cause us to evaluate our fixed assets for recoverability and possible impairment may include changes in market conditions, such as adverse movements in the prices of oil and natural gas, which could reduce the fair value of certain of our property and equipment. The development of 75 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) future cash flows and the determination of fair value for a division involves significant judgment and estimates. During 2007 and 2006, no trigger events were identified by management. During the fourth quarter of 2008, the impairment of the Company’s goodwill was identified as a trigger event by management. As a result, an undiscounted cash flow analysis was performed for our long-lived assets, and no impairment was indicated. Asset Retirement Obligations In accordance with SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”), we recognize a liability for the fair value of all legal obligations associated with the retirement of tangible long- lived assets and capitalize an equal amount as a cost of the asset. We depreciate the additional cost over the estimated useful life of the assets. Our obligations to perform our asset retirement activities are unconditional, despite the uncertainties that may exist surrounding an individual retirement activity. Accordingly, we recognize a liability for the fair value of a conditional asset retirement obligation if the fair value can be reasonably estimated. Significant judgment is involved in estimating future cash flows associated with such obligations, as well as the ultimate timing of those cash flows. If our estimates of the amount or timing of the cash flows change, such changes may have a material impact on our results of operations. See “Note 7. Asset Retirement Obligations.” Capitalized Interest Interest is capitalized on the average amount of accumulated expenditures for major capital projects using an effective interest rate based on related debt until the underlying assets are placed into service. The capitalized interest is added to the cost of the assets and amortized to depreciation and amortization expense over the useful life of the assets. It is included in the depreciation and amortization line in the accompanying consolidated statements of operations. Long-Term Debt Deferred financing costs associated with long-term debt are carried at cost and are expensed over the term of the applicable long-term debt facility or the term of the notes. These costs are amortized to interest expense using the effective interest method over the life of the related debt instrument. When the related debt instrument is retired, any remaining unamortized costs are included in the determination of the gain or loss on the extinguishment of the debt. We record gains and losses from the extinguishment of debt as a part of continuing operations. See “Note 12. Long-Term Debt.” Goodwill and Other Intangible Assets Goodwill results from business combinations and represents the excess of acquisition costs over the fair value of the net assets acquired. We account for goodwill and other intangible assets under the provisions of SFAS No. 142, Accounting for Goodwill and Intangible Assets (“SFAS 142”). Goodwill and other intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. The test for impairment of indefinite-lived intangibles is a two step test. In the first step of the test, a fair value is calculated for each of the Company’s reporting units, and that fair value is compared to the carrying value of the reporting unit, including the reporting unit’s goodwill. If the fair value of the reporting unit exceeds its carrying value, there is no impairment, and the second step of the test is not performed. If the carrying value exceeds the fair value for the reporting unit, then the second step of the test is required. The second step of the test compares the implied fair value of the reporting unit’s goodwill to its carrying value. The implied fair value of the reporting unit’s goodwill is determined in the same manner as the amount 76 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) of goodwill recognized in a business combination, with the purchase price being equal to the fair value of the reporting unit. If the implied fair value of the reporting unit’s goodwill is in excess of its carrying value, no impairment is recorded. If the carrying value is in excess of the implied fair value, an impairment equal to the excess is recorded. To assist management in the preparation and analysis of the valuation of the Company’s reporting units, management utilized the services of a third-party valuation consultant, who reviewed management’s estimates, assumptions and calculations. The ultimate conclusions of the valuation techniques remain the sole responsi- bility of the Company’s management. The Company conducts its annual impairment test on December 31 of each year. For the annual test completed as of December 31, 2008, an impairment of the Company’s goodwill was indicated. While this test is required on an annual basis, it also can be required more frequently based on changes in external factors. We do not currently expect that additional tests would result in additional charges, but the determination of the fair value used in the test is heavily impacted by the market prices of our equity and debt securities. See “Note 5. Goodwill and Other Intangible Assets.” Internal-Use Software As required by Statement of Position (“SOP”) No. 98-1, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use (“SOP 98-1”), we capitalize costs incurred during the application development stage of internal-use software and amortize these costs over its estimated useful life, generally five years. Costs incurred related to selection or maintenance of internal-use software are expensed as incurred. See “Note 4. Property and Equipment.” Derivative Instruments and Hedging Activities The Company applies SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”), as amended, in accounting for derivative instruments. SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. It requires the recognition of all derivative instruments as assets and liabilities on the balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge, and if so, the type of hedge. To account for a financial instrument as a hedge, the contract must meet the following criteria: the underlying asset or liability must expose a company to risk that is not offset in another asset or liability, the hedging contract must reduce that risk, and the instrument must be properly designated as a hedge at the inception of the contract and throughout the contract period. To be an effective hedge, there must be a high correlation between changes in the fair value of the financial instrument and the fair value of the underlying asset or liability, such that changes in the market value of the financial instrument would be offset by the effect of price changes on the exposed items. For derivatives designated as cash flow hedges, the effective portion of the change in the fair value of the hedging instrument is recognized in other comprehensive income until the hedged item is recognized in earnings. Any ineffective portion of changes in the fair value of the hedging instrument is recognized currently in earnings. For all derivative contracts entered into, the Company analyzes the derivative contracts for embedded instruments and accounts for those instruments based on current guidance. During the years ended December 31, 2007 and 2006, the Company had interest rate swaps and foreign currency instruments that qualified as derivative instruments under SFAS 133. During 2008, the Company had no derivative instruments. See “Note 10. Derivative Financial Instruments” for further discussion. 77 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Litigation When estimating our liabilities related to litigation, we take into account all available facts and circumstances in order to determine whether a loss is probable and reasonably estimable in accordance with SFAS No. 5, Accounting for Contingencies (“SFAS 5”). Various suits and claims arising in the ordinary course of business are pending against us. Due in part to the locations where we conduct business in the continental United States, we are often subject to jury verdicts and arbitration hearings that result in outcomes in favor of the plaintiffs. We continually assess our contingent liabilities, including potential litigation liabilities, as well as the adequacy of our accruals and our need for the disclosure of these items. In accordance with SFAS 5 we establish a provision for a contingent liability when it is probable that a liability has been incurred and the amount is able to be estimated. See “Note 13. Commitments and Contingencies.” Environmental Our operations are subject to various federal, state and local laws and regulations intended to protect the environment. Our operations routinely involve the storage, handling, transport and disposal of bulk waste materials, some of which contain oil, contaminants, and 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 limiting 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. Laws and regulations have become more stringent over the years, and in certain circumstances may impose “strict liability,” rendering us liable for environmental damage without regard to negligence or fault on our part. Cleanup costs, penalties, and other damages arising as a result of environmental laws and costs associated with changes in environmental laws and regulations, could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows. From time to time, claims have been made and litigation has been brought against us under such laws. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. For environmen- tal reserve matters, including remediation efforts for current locations and those relating to previously-disposed properties, we record liabilities when our remediation efforts are probable and the costs to conduct such remediation efforts can be reasonably estimated. While our litigation reserves reflect the application of our insurance coverage, our environmental reserves do not reflect management’s assessment of the insurance coverage that may apply to the matters at issue. See “Note 13. Commitments and Contingencies” for further discussion. Self Insurance We are largely self-insured for physical damage to our equipment, automobiles and rigs. Our accruals that we maintain on our consolidated balance sheet relate to these deductibles and self-insured retentions, which we estimate through the use of historical claims data and trend analysis. The actual outcome of any claim could differ significantly from estimated amounts. We adjust loss estimates in the calculation of these accruals, based upon actual claim settlements and reported claims. Income Taxes In accounting for income taxes, we follow SFAS No. 109, Accounting for Income Taxes (“SFAS 109”), which requires that we account for deferred income taxes using the asset and liability method and provide income taxes for all significant temporary differences. Management determines our current tax liability as well as taxes incurred as a result of current operations, but which are deferred until future periods. Current taxes payable represent our liability related to our income tax return for the current year, while net deferred tax 78 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 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 portion or all of the deferred tax assets will not be realized in future periods. To assess the likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which this taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted results, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. Additionally, we record reserves for uncertain tax positions that are subject to management judgment related to the resolution of the tax positions and completion of audits by tax authorities in the domestic and international tax jurisdictions in which we operate. The Company is subject to the revised Texas Franchise tax. The revised Texas Franchise tax is an income tax equal to one percent of Texas-sourced revenue reduced by the greater of (a) cost of goods sold (as defined by Texas law), (b) compensation (as defined by Texas law), or (c) thirty percent of the Texas-sourced revenue. We account for the revised Texas Franchise tax in accordance with SFAS 109, as the tax is derived from a taxable base that consists of income less deductible expenses. See “Note 11. Income Taxes” 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. Earnings Per Share We present earnings per share information in accordance with the provisions of SFAS No. 128, Earnings Per Share (“SFAS 128”). Under SFAS 128, basic earnings per common share is determined by dividing net earnings applicable to common stock by the weighted average number of common shares actually outstanding during the period. Diluted earnings per common share is based on the increased number of shares that would be outstanding assuming conversion of dilutive outstanding convertible securities using the treasury stock and “as if converted” methods. See “Note 6. Earnings Per Share” for further discussion. Share-Based Compensation We account for share-based compensation under the provisions of SFAS No. 123 (revised 2004), Share- Based Payment (“SFAS 123(R)”), which we adopted on January 1, 2006. We adopted SFAS 123(R) using the modified prospective transition method, and no cumulative effect was recorded on the adoption date of SFAS 123(R). We record share-based compensation as a component of general and administrative expense. See “Note 17. Share-Based Compensation” for further discussion. Foreign Currency Gains and Losses We follow a translation policy in accordance with SFAS No. 52, Foreign Currency Translation (“SFAS 52”). In our international locations in Argentina, Mexico and Canada where the local currency is the functional currency, assets and liabilities are translated at the rates of exchange on the balance sheet date, while income and expense items are translated at average rates of exchange during the year. The resulting 79 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) gains or losses arising from the translation of accounts from the functional currency to the U.S. Dollar are included as a separate component of stockholders’ equity in other comprehensive income until a partial or complete sale or liquidation of our net investment in the foreign entity. From time to time our foreign subsidiaries may enter into transactions that are denominated in currencies other than their functional currency. These transactions are initially recorded in the functional currency of that subsidiary based on the applicable exchange rate in effect on the date of the transaction. At the end of each month, these transactions are remeasured to an equivalent amount of the functional currency based on the applicable exchange rates in effect at that time. Any adjustment required to remeasure a transaction to the equivalent amount of the functional currency at the end of the month is recorded in the income or loss of the foreign subsidiary as a component of other income and expense. See “Note 14. Accumulated Other Comprehensive Loss.” Comprehensive Income We report and display comprehensive income in accordance with SFAS No. 130, Reporting Comprehen- sive Income (“SFAS 130”), which establishes standards for reporting and displaying comprehensive income and its components. SFAS 130 requires enterprises to display comprehensive income and its components in the enterprise’s financial statements, to classify items of comprehensive income by their nature in the financial statements and to display the accumulated balance of other comprehensive income separately in shareholders’ equity. Leases We account for leases in accordance with SFAS No. 13, Accounting for Leases (“SFAS 13”). Certain of our operating lease agreements are structured to include scheduled and specified rent increases over the term of the lease agreement. These increases may be the result of an inducement or “rent holiday” conveyed to us early in the lease, or are included to reflect the anticipated effects of inflation. We apply the provisions of FASB Technical Bulletin (“FTB”) No. 85-3, Accounting for Operating Leases with Scheduled Rent Increases (“FTB 85-3”), when accounting for scheduled and specified rent increases. FTB 85-3 provides that the effects of scheduled and specified rent increases should be recognized on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. We recognize scheduled and specified rent increases on a straight-line basis over the term of the lease agreement. In addition, certain of our operating lease agreements contain incentives to induce us to enter into the lease agreement, such as up-front cash payments to us, payment by the lessor of our costs, such as moving expenses, or the assumption by the lessor of our pre-existing lease agreements with third parties. Any payments made to us or on our behalf represent incentives that we consider to be a reduction of our rent expense, and are recognized on a straight-line basis over the term of the lease agreement. We amortize leasehold improvements on our operating leases over the shorter of their economic lives or the lease term. New Accounting Standards Adopted in this Report FIN 48 and FSP FIN 48-1. In June 2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (“FIN 48”), which provides clarification of SFAS 109 with respect to the recognition of income tax benefits of uncertain tax positions in financial statements. FIN 48 requires that uncertain tax positions be reviewed and assessed, with recognition and measurement of the tax benefit based on a “more likely than not” standard. In May 2007 the FASB issued FASB Staff Position (“FSP”) FIN 48-1 (“FSP FIN 48-1”). FSP FIN 48-1 provides guidance on how an enterprise should determine whether a tax position is effectively settled for the 80 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) purpose of recognizing previously unrecognized tax benefits. In determining whether a tax position has been effectively settled, entities must evaluate (i) whether taxing authorities have completed their examination procedures; (ii) whether the entity intends to appeal or litigate any aspect of a tax position included in a completed evaluation; and (iii) whether it is remote that a taxing authority would examine or re-examine any aspect of a taxing position. FSP FIN 48-1 is to be applied upon the initial adoption of FIN 48. We adopted the provisions of FIN 48 and FSP FIN 48-1 on January 1, 2007 and recorded a $1.3 million decrease to the balance of our retained earnings as of January 1, 2007 to reflect the cumulative effect of adopting these standards. FSP EITF 00-19-2. In December 2006, the FASB issued FSP EITF 00-19-2, Accounting for Registration Payment Arrangements (“FSP EITF 00-19-2”). FSP EITF 00-19-2 addresses accounting for Registration Payment Arrangements (“RPAs”), which are provisions within financial instruments such as equity shares, warrants or debt instruments by which the issuer agrees to file a registration statement and to have that registration statement declared effective by the SEC within a specified grace period. If the registration statement is not declared effective within the grace period or its effectiveness is not maintained for the period of time specified in the RPA, the issuer must compensate its counterparty. The FASB Staff concluded that the contingent obligation to make future payments or otherwise transfer consideration under a RPA should be recognized as a liability and measured in accordance with SFAS 5 and FIN No. 14, Reasonable Estimation of the Amount of a Loss, and that the RPA should be recognized and measured separately from the instrument to which the RPA is attached. In January 1999, the Company completed the private placement of 150,000 units consisting of $150.0 million of 14% Senior Subordinated Notes due January 25, 2009 (the “14% Senior Subordinated Notes”) and 150,000 warrants to purchase an aggregate of approximately 2.2 million shares of the Company’s common stock at an exercise price of $4.88125 per share (the “Warrants”). Under the terms of the Warrants, we were required to maintain an effective registration statement covering the shares of common stock issuable upon exercise of the Warrants. Due to our past failure to file our SEC reports in a timely manner, we did not have an effective registration statement covering the Warrants, and were required to make liquidated damages payments. The requirement to make liquidated damages payments constituted an RPA under the provisions of FSP EITF 00-19-2, and as prescribed by the transition provisions of that standard, on January 1, 2007 the Company recorded a pre-tax current liability of approximately $1.0 million, which is equivalent to the payments for the Warrant RPA for one year, with an offsetting adjustment to the opening balance of retained earnings. SFAS 157. In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”). SFAS 157 establishes a framework for measuring fair value and requires expanded disclosure about the information used to measure fair value. The statement applies whenever other statements require or permit assets or liabilities to be measured at fair value, and does not expand the use of fair value accounting in any new circumstances. The adoption of this standard did not have a material impact on our consolidated financial statements. SFAS 159. The Company adopted Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Liabilities, including an amendment of FASB Statement No. 115 (“SFAS 159”), on January 1, 2008. SFAS 159 permits companies to choose, at specified election dates, to measure eligible items at fair value (the “Fair Value Option”). Companies choosing such an election report unrealized gains and losses on items for which the Fair Value Option has been elected in earnings at each subsequent reporting period. We did not elect to measure any of our financial assets or liabilities using the Fair Value Option. We will assess at each measurement date whether to use the Fair Value Option on any future financial assets or liabilities as permitted pursuant to the provisions of SFAS 159. FSP SFAS 157-3. In October 2008, the FASB issued FSP SFAS No. 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active (“FSP 157-3”). FSP 157-3 clarified the 81 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) application of SFAS 157. FSP 157-3 demonstrated how the fair value of a financial asset is determined when the market for that financial asset is inactive. FSP 157-3 was effective upon issuance, including for prior periods for which financial statements had not been issued. The implementation of this standard did not have a material impact on our consolidated financial statements. Accounting Standards Not Yet Adopted in this Report FSP SFAS 142-3. In April 2008, the FASB issued FSP SFAS No. 142-3, Determination of Useful Life of Intangible Assets (“FSP 142-3”). FSP 142-3 amends the factors that should be considered in developing the renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS 142. FSP 142-3 also requires expanded disclosure regarding the determination of intangible asset useful lives. FSP 142-3 is effective for fiscal years beginning after December 15, 2008. Earlier adoption is not permitted. We are currently evaluating the potential impact the adoption of FSP 142-3 will have on our consolidated financial statements. SFAS 161. In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. This statement is effective for financial statements issued for fiscal periods beginning after November 15, 2008. Early application is encouraged. The Company currently has no financial instruments that qualify as derivatives, and we do not expect that the adoption of this standard will have a material impact on the Company’s financial position, results of operations and cash flows. FSP SFAS 157-2. In February 2008, the FASB issued FSP SFAS No. 157-2, Effective Date of FASB Statement No. 157 (“FSP 157-2”), to partially defer SFAS 157. FSP SFAS 157-2 defers the effective date of SFAS 157 for nonfinancial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), to fiscal years, and interim periods within those fiscal years, beginning after November 15, 2008. We are currently evaluating the impact of adopting the provisions of SFAS 157 as it relates to nonfinancial assets and liabilities. SFAS 141(R). In December 2007, the FASB issued SFAS No. 141 (Revised 2007), Business Combina- tions (“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 current 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, 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. SFAS 141(R) may have an impact on our consolidated financial statements. The nature and magnitude of the specific impact will depend upon the nature, terms, and size of the 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 82 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 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. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is not permitted. We are currently evaluating the potential impact of this statement. NOTE 2. ACQUISITIONS From time to time, the Company may acquire businesses or assets that are consistent with its long-term growth strategy. Results of operations for acquisitions are included in the Company’s financial statements beginning from the date of acquisition. Acquisitions through December 31, 2008 are accounted for using the purchase method of accounting and the purchase price is allocated to the assets acquired and liabilities assumed based upon their estimated fair values at the date of acquisition. Final valuations of assets and liabilities are obtained and recorded as soon as practicable and within one year from the date of the acquisition. Purchase price allocations that have not yet been finalized are based on preliminary information and are subject to change when final fair value determinations are made for the assets acquired and liabilities assumed. Acquisitions completed during 2008 Tri-Energy Services, LLC. On January 17, 2008, the Company purchased the fishing and rental assets of Tri-Energy Services, LLC (“Tri-Energy”) for approximately $1.9 million in cash. These assets were integrated into our fishing and rental segment. The equity interests of Tri-Energy are owned by employees of the Company who joined the Company in October 2007 in connection with the earlier acquisition in 2007 of Moncla Well Service, Inc. and related entities (collectively, “Moncla”). The purchase price was allocated to the tangible and intangible assets purchased and the acquisition of the Tri-Energy assets was accounted for as an asset purchase and did not result in the establishment of goodwill. The assets acquired include an identifiable intangible asset of $1.1 million related to customer relationships and is subject to amortization under SFAS No. 142. The asset will be amortized on a straight-line basis over two years from the acquisition date. Western Drilling, LLC. On April 3, 2008, the Company purchased all of the outstanding equity interests of Western Drilling, LLC (“Western”), a privately-owned company based in California that operated 22 working well service rigs, three stacked well service rigs and equipment used in the workover and rig relocation process. We acquired Western to increase our service footprint in the California market. The purchase price was $51.5 million in cash and was paid on April 3, 2008. The purchase price was subject to a working capital adjustment 45 days from the closing date of the acquisition that resulted in additional consideration paid of $0.1 million in May 2008. The Company also incurred direct transaction costs of approximately $0.4 million. The acquisition was funded by borrowings of $50.0 million under the Company’s Senior Secured Credit Facility (see “Note 12. Long-Term Debt”) and cash on hand. The acquisition of Western was accounted for as a business combination. The total purchase price was allocated to the assets acquired and liabilities assumed based on their estimated fair values. The excess of the purchase price over the fair value of net assets acquired was recorded as goodwill. The allocation of the purchase price was based upon preliminary valuations and estimates, and is subject to change as the valuations are finalized. The primary area of the purchase price allocation that is not yet finalized relates to pre-merger 83 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) contingencies. The final valuation is expected to be completed no later than the first quarter of 2009. The following table summarizes the preliminary estimated fair values of the assets acquired and liabilities assumed on the date of the Western acquisition (in thousands): Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total assets acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 687 6,839 30,162 8,166 9,000 132 54,986 2,979 Total liabilities assumed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net assets acquired. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,979 $52,007 The fair values of property and equipment were determined using a market approach. The fair values of identified intangible assets were determined using an income approach to measure the present worth of anticipated future economic benefits. The Company also performed an economic obsolescence analysis to confirm the values identified through the aforementioned methods. The allocation is still preliminary at this time, and may potentially change by a material amount once the purchase price allocation is finalized. Goodwill was recognized as part of the acquisition of Western as the purchase price exceeded the fair value of the acquired assets and assumed liabilities. The Company believes the goodwill associated with the Western acquisition is related to the acquired workforce, potential future expansion of the Western service offerings, and the ability to expand our service offerings. Therefore, it was not allocated to the acquired assets and assumed liabilities. The acquired identifiable intangible asset of $9.0 million is related to customer relationships and is subject to amortization under SFAS No. 142. The customer relationships will be amortized as the value of the relationships are realized using rates of 17%, 19%, 15%, 12%, 9%, 7%, 6%, 5%, 4%, 3%, 2% and 1% for 2008 through 2019, respectively. The $8.2 million of goodwill associated with the purchase of Western was allocated to our well servicing segment, and the assets and results of operations subsequent to April 3, 2008 have also been integrated into the well servicing segment. Of the goodwill recorded, $8.2 million is expected to be deductible for income tax purposes. Hydra-Walk, Inc. On May 30, 2008, the Company purchased all of the outstanding stock of Hydra- Walk, Inc. (“Hydra-Walk”) for approximately $10.3 million in cash and a performance earn-out of up to $2.0 million over two years from the acquisition date if certain financial and operational performance measures are met. Additionally, during the third quarter of 2008 the Company paid approximately $0.2 million in additional consideration related to a holdback amount that was withheld from the seller pending the completion of a seller closing requirement. The purchase price was also subject to a post-closing working capital adjustment of less than $0.1 million that was paid during the third quarter of 2008. The Company incurred direct transaction costs of approximately $0.1 million. The Company retained approximately $1.1 million of Hydra-Walk’s net working capital as a result of the transaction and did not assume any debt of Hydra-Walk. Hydra-Walk is a leading provider of pipe handling solutions for the oil and gas industry and operates over 80 automated pipe handling units in Oklahoma, Texas and Wyoming. We acquired Hydra-Walk to expand the level of integrated well servicing services we are able to provide customers. The assets and results of operations for Hydra-Walk were integrated into our fishing and rental segment beginning on May 31, 2008. 84 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) The acquisition of Hydra-Walk was accounted for as a business combination and the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated fair values. The excess of the purchase price over the fair value of net assets acquired was recorded as goodwill. The allocation of the purchase price was based upon preliminary valuations and estimates, and is subject to change as valuations are finalized. The primary area of the purchase price allocation that is not yet finalized relates to pre-merger contingencies. The final valuation is expected to be completed no later than the second quarter of 2009. This business combination resulted in the acquisition of $3.7 million of tangible assets, $4.5 million of intangible assets and $1.3 million of goodwill. The fair values of tangible assets were determined using a market approach. The fair values of intangible assets were determined using an income approach to measure the present worth of anticipated future economic benefits. The Company also performed an economic obsolescence analysis to confirm the values identified through the aforementioned methods. The allocation is still preliminary at this time and may potentially change by a material amount once the purchase price allocation is finalized. The acquired identifiable intangible assets of $4.5 million relate to customer relationships, a tradename and a non-compete agreement. These intangible assets are subject to amortization under SFAS 142. The customer relationships asset of $4.0 million will be amortized as the value of the relationships are realized using rates of 19%, 24%, 17%, 13%, 9%, 6%, 4%, 3%, 3% and 2% for 2008 through 2017, respectively. The tradename asset of $0.4 million will be amortized straight-line over 10 years and the non-compete agreement asset will be amortized straight-line over 3 years. Goodwill of $1.3 million has been recognized as part of the purchase price allocation as the purchase price exceeded the fair value of the acquired assets and assumed liabilities. The Company believes the goodwill associated with the Hydra-Walk acquisition is related to the acquired workforce and potential expansion of our service offerings. Therefore, it was not allocated to the acquired assets and assumed liabilities. The $1.3 million of goodwill was allocated to our fishing and rental segment and $1.3 million is expected to be deductible for income tax purposes. As of December 31, 2008, the Hydra-Walk operations had met performance earn-out requirements that resulted in additional consideration of $0.5 million which has been recorded as additional goodwill. Leader Energy Services Ltd. On July 22, 2008, the Company acquired all of the United States-based assets of Leader Energy Services Ltd. (“Leader”), a Canadian company, for consideration of $34.6 million in cash. The acquired assets include nine coiled tubing units, seven nitrogen trucks, twelve pumping trucks and other ancillary equipment. Additionally, the Company paid approximately $0.7 million for supplies and inventory used in pressure pumping operations. The Company also incurred direct transaction costs of approximately $0.1 million. The purchase price was allocated to the tangible assets acquired. The acquisition of the Leader assets was accounted for as an asset purchase as the assets acquired did not constitute a business and therefore did not result in the establishment of goodwill. The Company did not identify any acquired intangible assets. The Leader assets were integrated into our pressure pumping segment. Acquisitions completed during 2007 AMI. On September 5, 2007, the Company acquired AMI, which operates in Canada and is a technology company focused on oilfield service equipment controls, data acquisition and digital information flow. The purchase price was $6.6 million in cash and $2.9 million in assumed debt and was paid in September 2007. During the nine months ended September 30, 2008, the Company refined its fair value allocation of the assets acquired and liabilities assumed by increasing its deferred tax asset balance by $0.3 million and decreasing its deferred tax liability balance by $1.0 million. These changes were offset by a corresponding net decrease to goodwill of $1.3 million. During 2008, but prior to the anniversary of the acquisition, the Company made additional payments to settle its working capital adjustment with the former owners of AMI and incurred 85 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) additional transaction costs directly related to the business combination. These payments totaled $1.3 million and resulted in additional goodwill of $1.3 million. The purchase price allocation was completed during the third quarter of 2008. Moncla. On October 25, 2007, the Company acquired Moncla, which operated well service rigs, barges and ancillary equipment in the southeastern United States for total consideration of $146.0 million. During 2008, the Company refined its fair value allocation of the assets acquired and liabilities assumed by increasing the working capital accounts (excluding deferred tax assets) by $2.2 million, decreasing the fair value of the well service assets acquired by $3.6 million, decreasing the deferred tax and other long-term asset balances by $0.4 million, increasing its long-term deferred tax liability balance by $2.1 million and incurring additional fees related to the closing of the transaction of less than $0.2 million. The Company also paid additional purchase consideration of $0.8 million during the third quarter of 2008. These changes were offset with a corresponding net increase to goodwill of $4.9 million. The purchase price allocation was finalized in the fourth quarter of 2008. Kings Oil Tools. On December 7, 2007, the Company acquired the well service assets and related equipment of Kings Oil Tools, Inc. (“Kings”), a California-based well service company for approximately $45.1 million. During the nine months ended September 30, 2008, the Company revised its fair value allocation of the assets acquired and liabilities assumed by increasing the fair value of the well service assets acquired by $1.6 million, increasing the deferred tax assets by $0.4 million, decreasing the fair value of working capital accounts by $0.1 million and incurring additional fees related to the closing of the transaction of $0.1 million. These changes were offset with a corresponding net decrease to goodwill for $1.7 million. The purchase price allocation was finalized in the fourth quarter of 2008 . Acquisitions completed during 2006 We made no acquisitions during 2006. NOTE 3. OTHER CURRENT AND NON-CURRENT LIABILITIES December 31, 2008 2007 (In thousands) Current Accrued Liabilities: Accrued payroll, taxes and employee benefits . . . . . . . . . . . . . . . . . . . . . . . $ 67,408 50,833 Accrued operating expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,003 Income, sales, use and other taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,724 Self-insurance reserve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,550 Unsettled legal claims . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 902 Phantom share liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,696 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 55,486 52,180 35,310 25,208 6,783 2,458 5,939 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $197,116 $183,364 86 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Non-Current Accrued Liabilities: Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Environmental liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued rent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Phantom share liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . December 31, 2008 2007 (In thousands) $ 9,348 3,004 2,497 1,359 478 809 $ 9,298 3,090 2,829 2,705 896 713 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $17,495 $19,531 NOTE 4. PROPERTY AND EQUIPMENT Property and equipment consists of the following: December 31, 2008 2007 (In thousands) Major classes of property and equipment: Well servicing equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,431,624 60,508 Disposal wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125,031 Motor vehicles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81,129 Furniture and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71,014 Buildings and land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89,001 Work in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,200,069 56,576 112,986 73,032 64,258 88,304 Gross property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,858,307 (806,624) 1,595,225 (684,017) Net property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,051,683 $ 911,208 The Company capitalizes costs incurred during the application development stage of internal-use software. These costs are capitalized to work in progress until such time the application is put in service. For the years ended December 31, 2008, 2007 and 2006 the Company capitalized costs in the amount of $4.5 million, $1.9 million, and zero, respectively. Interest is capitalized on the average amount of accumulated expenditures for major capital projects using an effective interest rate based on related debt until the underlying assets are placed into service. Capitalized interest for the years ended December 31, 2008, 2007 and 2006 was $6.5 million, $5.3 million and $3.4 million, respectively. 87 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) The Company is obligated under various capital leases for certain vehicles and equipment that expire at various dates during the next five years. The carrying value of assets acquired under capital leases consists of the following: December 31, 2008 2007 (In thousands) Well servicing equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Motor vehicles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $20,442 9,271 $19,687 5,938 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $29,713 $25,625 Depreciation of assets held under capital leases of approximately $4.3 million, $5.9 million and $6.0 million for the years ended December 31, 2008, 2007 and 2006, respectively, and is included in depreciation and amortization expense in the accompanying consolidated statements of operations. NOTE 5. GOODWILL AND OTHER INTANGIBLE ASSETS The following table summarizes the activity in our goodwill accounts for the years ended December 31, 2008 and 2007: Well Servicing Segment Balance at December 31, 2006 . . . . . . . . . . . . . . . Goodwill acquired during the period . . . . . . . . . Impact of foreign currency translation . . . . . . . . $252,975 57,820 (182) Pressure Pumping Segment (In thousands) $ 49,036 — — Balance at December 31, 2007 . . . . . . . . . . . . . . . 310,613 49,036 Goodwill acquired during the period . . . . . . . . . Purchase price allocation and other adjustments, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Impairment of goodwill . . . . . . . . . . . . . . . . . . . Impact of foreign currency translation . . . . . . . . 8,970 2,376 — (967) — (49,036) — Fishing and Rental Services Segment $ 18,901 — — 18,901 1,815 — (20,716) — Total $320,912 57,820 (182) 378,550 10,785 2,376 (69,752) (967) Balance at December 31, 2008 . . . . . . . . . . . . . . . $320,992 $ — $ — $320,992 88 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) The following tables present the gross carrying values and accumulated amortization of our identified intangible assets with determinable lives that are subject to amortization under SFAS 142 as of December 31, 2008 and 2007: December 31, 2008 2007 (In thousands) Noncompete agreements: Gross carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 16,309 (4,699) $18,402 (2,772) Net carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 11,610 $15,630 Patents and trademarks: Gross carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,391 (3,114) $ 4,150 (2,526) Net carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,277 $ 1,624 Customer relationships: Gross carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 39,225 (12,359) $25,139 (1,649) Net carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 26,866 $23,490 Customer backlog: Gross carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 622 (207) Net carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 415 $ $ 999 (214) 785 Developed technology: Gross carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,598 (1,421) $ 4,762 (397) Net carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,177 $ 4,365 Amortization expense for our intangible assets with determinable lives was as follows: Noncompete agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,108 748 Patents and trademarks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,710 Customer relationships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Customer backlog . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 252 1,803 Developed technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2008 2006 Year Ended December 31, 2007 (In thousands) $1,919 774 1,649 210 389 $2,202 713 — — — Total intangible asset amortization expense . . . . . . . . . . . . . . . . . . . . $17,621 $4,941 $2,915 89 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) The weighted average remaining amortization periods and expected amortization expense for the next five years for our intangible assets are as follows: Weighted Average Remaining Amortization Period (Years) Noncompete agreements. . . . . . . . . . . . . Patents and trademarks . . . . . . . . . . . . . . Customer relationships . . . . . . . . . . . . . . Customer backlog . . . . . . . . . . . . . . . . . Developed technology . . . . . . . . . . . . . . Total intangible asset amortization expense . . . . . . . . . . . . . . . . . . . . . . . 5.9 4.5 9.3 2.3 2.8 Expected Amortization Expense 2009 2010 2011 2012 2013 $ 3,221 489 8,113 797 156 (In thousands) $2,620 203 3,808 423 104 $2,652 273 5,232 668 156 $2,423 96 2,818 — — $ 406 40 2,069 — — $12,776 $8,981 $7,158 $5,337 $2,515 Certain of our intangible assets are denominated in currencies other than U.S. Dollars and as such the values of these assets are subject to fluctuations associated with changes in exchange rates. Additionally, certain of these assets are also subject to purchase accounting adjustments. The estimated fair values of intangible assets obtained through acquisitions consummated in the preceding twelve months are based on preliminary information which is subject to change until final valuations are obtained. We perform annual impairment tests associated with our goodwill on December 31 of each year, or more frequently if circumstances warrant, as dictated by SFAS 142. As of December 31, 2008, 2007 and 2006, we had three reporting units as determined and identified by SFAS 142. We estimate the fair values of our reporting units using three common valuation techniques — the discounted cash flow method, the guideline company method, and the similar transaction method. The Company’s management assigns a weighting to the results of each method based on the facts and circumstances that exist at the assessment date. The discounted cash flows for each reporting unit being tested are based on the Company’s financial budgets and forecasts, as well as management’s beliefs about the long- term growth patterns of the reporting units. For the 2008 future cash flow projections were discounted at rates ranging from 14% to 15% and terminal growth rates of approximately 3%. As part of the assessment, management also considered the current market capitalization of the Company, based on publicly available information and adjusted for an estimate of a control premium, in assessing the reasonableness of the fair values of the reporting units based on the results of the valuation models. To assist management in the preparation and analysis of the valuation of the Company’s reporting units, management utilized the services of a third-party valuation consultant, who reviewed management’s estimates, assumptions and calculations. The ultimate conclusions of the valuation techniques remain the sole responsi- bility of the Company’s management. The Company conducts its annual impairment test on December 31 of each year. Upon completion of the 2007 and 2006 assessments, no impairment was indicated since the estimated fair values of the reporting units were in excess of their carrying values. Upon completion of the 2008 assessment, we determined that the fair value associated with the reporting units comprising our pressure pumping and fishing and rental reportable segments was less than the carrying value of the reporting units of those segments, indicating potential impairment. Because indicators of impairment existed for these reporting units, we performed step two of the SFAS 142 impairment test for those units. While this test is required on an annual basis, it also can be required more frequently based on changes in external factors. We do not currently expect that additional tests would result in any additional charges, but the determination of fair value used in the test is heavily impacted by the market prices of our equity and debt securities. 90 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) In accordance with SFAS 142, the implied fair value of the goodwill of the reporting units being tested was determined in the same manner as a hypothetical business combination, with the fair value of the reporting unit representing the purchase price. As a result of the calculations of step two of the test, we determined that the goodwill of the reporting units comprising our pressure pumping and fishing and rental segments was impaired, and that the amount of the impairment loss was greater than the current carrying value of those reporting units’ goodwill. As such, we recorded a pre-tax impairment charge of approximately $49.0 million and $20.7 million for our pressure pumping and fishing and rental segments, respectively, during the fourth quarter of 2008. NOTE 6. EARNINGS PER SHARE The following table presents our basic and diluted earnings per share for the years ended December 31, 2008, 2007 and 2006: Year Ended December 31, 2007 (In thousands, except per share data) 2006 2008 Basic EPS Computation: Numerator Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 84,058 $169,289 $171,033 Denominator Weighted average shares outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . Basic earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted EPS Computation: Numerator 124,246 0.68 $ 131,194 1.29 $ 131,332 1.30 $ Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 84,058 $169,289 $171,033 Denominator Weighted average shares outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . Stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Restricted stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Stock appreciation rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124,246 555 254 506 4 131,194 1,518 256 565 18 131,332 2,180 — 552 — 125,565 133,551 134,064 Diluted earnings per share. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.67 $ 1.27 $ 1.28 Stock options, warrants and stock appreciation rights are included in the computation of diluted earnings per share using the treasury stock method. Restricted stock grants are legally considered issued and outstanding, but are included in basic and diluted earnings per share only to the extent that they are vested. Unvested restricted stock is included in the computation of diluted earnings per share using the treasury stock method. The diluted earnings per share calculation for the years ended December 31, 2008, 2007 and 2006 exclude the potential exercise of 2.6 million, 0.5 million and 0.4 million stock options, respectively, because the effects of such exercises on earnings per share in those periods would be anti-dilutive. The diluted earnings per share calculation for the year ended December 31, 2008 excludes the potential exercise of 0.4 million stock-settled stock appreciation rights (“SARs”) because the effects of such exercises on earnings per share in those periods would be anti-dilutive. Shares are considered anti-dilutive because their exercise prices exceeded the average price of the Company’s stock during those years. 91 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) There have been no material changes in share amounts subsequent to the balance sheet date that would have a material impact on the earnings per share calculation for the year ended December 31, 2008. NOTE 7. ASSET RETIREMENT OBLIGATIONS In connection with our well servicing activities, we operate a number of saltwater disposal (“SWD”) facilities. Our operations involve the transportation, handling and disposal of fluids in our SWD facilities that are by-products of the drilling process, some of which have been determined to be harmful to the environment. SWD facilities used in connection with our fluid hauling operations are subject to future costs associated with the abandonment of these properties. As a result, we have incurred costs associated with the proper storage and disposal of these materials. Annual amortization of the assets associated with the asset retirement obligations was $0.6 million, $0.6 million and $0.5 million for the years ended December 31, 2008, 2007 and 2006, respectively. A summary of changes in our asset retirement obligations is as follows (in thousands): Balance at December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $9,622 Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Costs incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Disposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 (576) 585 (345) Balance at December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,298 Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Costs incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Disposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 397 (462) 594 (478) Balance at December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $9,349 NOTE 8. EQUITY METHOD INVESTMENTS IROC Energy Services Corp. As of December 31, 2008 and 2007, we owned approximately 8.7 million shares of IROC Energy Services Corp. (“IROC”), an Alberta-based oilfield services company. This represented approximately 19.7% of IROC’s outstanding common stock on December 31, 2008 and 2007. IROC shares trade on the Toronto Venture Stock Exchange and had a closing price of $0.54 CDN and $0.74 CDN per share on December 31, 2008 and 2007, respectively. Mr. William Austin, our former chief financial officer, and Mr. Newton W. Wilson III, our Chief Operating Officer, serve on the board of directors of IROC. Through December 31, 2008, we have significant influence over the operations of IROC through our ownership interest and representation on IROC’s board of directors, but we do not control it. We account for our investment in IROC using the equity method. Our investment in IROC totaled $3.7 million and $11.2 million as of December 31, 2008 and 2007, respectively. The pro-rata share of IROC’s earnings and losses to which we are entitled is recorded in our consolidated statements of operations as a component of other income and expense, with an offsetting increase or decrease to the carrying value of our investment, as appropriate. Any earnings distributed back to us from IROC in the form of dividends would result in a decrease in the carrying value of our equity investment. The value of our investment may also increase or decrease each period due to changes in the exchange rate between the U.S. Dollar and Canadian Dollar. 92 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Changes in the value of our investment due to fluctuations in exchange rates are offset by accumulated other comprehensive income. IROC had net income of approximately $0.8 million, $2.0 million and $1.8 million U.S. Dollars for the years ended December 31, 2008, 2007 and 2006, respectively. In addition to our pro-rata share of IROC’s net income, the value of our investment changes based on the exchange rate between the U.S. and Canadian dollars. During the fourth quarter of 2008 the U.S. Dollar strengthened significantly against the Canadian Dollar, reducing the value of our investment. This decrease was offset in accumulated other comprehensive income. During the years ended December 31, 2008, 2007 and 2006, we recorded $0.2 million, $0.4 million and $0.4 million, respectively, of equity income related to our investment in IROC. During the years ended December 31, 2008, 2007 and 2006, no earnings were distributed to us by IROC. Only distributed earnings or any gains or losses arising from the disposal of our investment are reportable for income tax purposes; as a result, the amounts we record for our pro-rata share of IROC’s earnings or losses to which we are entitled result in a temporary difference between book and taxable income. Under the provisions of SFAS 109, we record a deferred tax asset or liability, as appropriate, to account for these temporary differences. An impairment review of our equity method investment in IROC is performed on a quarterly basis to determine if there has been a decline in fair value that is other than temporary. The fair value of the asset is measured using quoted market prices or, in the absence of quoted market prices, fair value is based on an estimate of discounted cash flows. In determining whether the decline is other than temporary, we consider the cyclicality of the industry in which the investment operates, its historical performance, its performance in relation to its peers and the current economic environment. Future conditions in the industry, operating performance and performance in relation to peers and the future economic environment may vary from our current assessment of recoverability. While the carrying value of the investment approximated the fair value during the second quarter of 2008, IROC’s stock price is currently depressed and has historically been volatile. During the fourth quarter of 2008 the Company’s management determined that the decline in the value of the investment in IROC was other than temporary and as such recorded a pretax charge of $5.4 million in order to reduce the carrying value of the investment to fair value. Fair value was determined by using the quoted market prices for the IROC shares as of December 31, 2008. Geostream Services Group On October 31, 2008, we acquired a 26% interest in OOO Geostream Services Group (“Geostream”) for $17.4 million. We incurred direct transaction costs of approximately $1.9 million associated with the transaction. Geostream is located in the Russian Federation and provides drilling and workover services and sub-surface engineering and modeling in the Russian Federation. In connection with our initial investment, three officers of the Company became board members of Geostream, representing 50% of the board membership. We can exert significant influence over the operations of Geostream, but do not control it; therefore we account for it using the equity method. The fair value of the amounts we have invested in Geostream is in excess of the underlying book value of our investment. We are currently performing a valuation to determine the components of the difference in basis and have preliminarily allocated substantially all of the difference to goodwill. Our pro-rata share of Geostream’s net income for the two months ended December 31, 2008 was not material. We are contractually required to purchase an additional 24% of Geostream no later than March 31, 2009 for approximately A11.3 million (which at December 31, 2008 was equivalent to $15.9 million). 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. 93 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Advanced Flow Technologies, Inc. In September 2007 we completed the acquisition of AMI, a privately-held Canadian company focused on oilfield technology. Prior to the acquisition, AMI owned a portion of another Canadian company, AFTI. As part of the acquisition, AMI increased its ownership percentage of AFTI to 51.46%. At December 31, 2007 we consolidated the assets, liabilities, results of operations and cash flows of AFTI into our consolidated financial statements, with the portion of AFTI remaining outside of our control forming a minority interest in our consolidated financial statements. Our ownership of AFTI declined to 48.73% as of December 31, 2008 due to the issuance of additional shares by AFTI. As a result, we deconsolidated AFTI results from our consolidated financial statements at December 31, 2008 and now account for that interest under the equity method. NOTE 9. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS The following is a summary of the carrying amounts and estimated fair values of our financial instruments as of December 31, 2008 and 2007. SFAS No. 107, Disclosures about Fair Value of Financial Instruments (“SFAS 107”) defines the fair value of a financial instrument as the amount at which the instrument could be exchanged in a current transaction between willing parties. Cash, cash equivalents, short-term investments, accounts payable and accrued liabilities. These carrying amounts approximate fair value because of the short maturity of the instruments or because the carrying value is equal to the fair value of those instruments on the balance sheet date. December 31, 2008 December 31, 2007 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Financial assets: Notes receivable — related parties . . . . . $ 336 $ 336 $ 173 $ 173 Financial liabilities: 8.375% Senior Notes due 2014 . . . . . . . Senior Secured Credit Facility revolving loans . . . . . . . . . . . . . . . . . . . . . . . . . Notes payable — related parties . . . . . . . $425,000 $282,115 $425,000 $434,563 187,813 20,318 187,813 20,318 50,000 22,178 50,000 22,178 Notes receivable-related parties. The amounts reported relate to notes receivable from certain employees of the Company related to relocation and retention agreements. The carrying values of these notes approximate their fair values as of the applicable balance sheet dates. 8.375% Senior Notes due 2014. The fair value of our long-term debt is based upon the quoted market prices and face value for the various debt securities at December 31, 2008. The carrying value of these notes as of December 31, 2008 was $425.0 million and the fair value was $282.1 million. Senior Secured Credit Facility revolving loans. Because of their variable interest rates, the fair values of the revolving loans borrowed under our Senior Secured Credit Facility approximate their carrying values as of December 31, 2008. The carrying and fair values of these loans as of December 31, 2008 were approximately $187.8 million. Notes payable — related parties. The amounts reported relate to the seller financing arrangement entered into in connection with our acquisition of Moncla (see “Note 2. Acquisitions”). The carrying value of these notes approximate their fair values as of December 31, 2008. 94 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) NOTE 10. DERIVATIVE FINANCIAL INSTRUMENTS Interest Rate Swaps. On March 10, 2006 we entered into two $100.0 million notional amount interest rate swaps to fix the interest rate on a portion of the borrowings under our prior senior credit agreement, dated July 29, 2005 (the “Prior Credit Facility”). These swaps met the criteria of derivative instruments. In connection with the termination of our Prior Credit Facility in November 2007, we settled all outstanding interest rate swap arrangements. We recognized a loss of approximately $2.3 million related to the settlement of our interest rate swaps, which is recorded in our consolidated statements of operations as a component of interest expense. Call Options on 8.375% Senior Notes due 2014. The indenture related to our $425.0 million in 8.375% Senior Notes due 2014 (see “Note 12. Long-Term Debt”) contains provisions by which, at our option, we may redeem the notes at varying prices before their stated maturity date. Certain of these provisions are based on contingent events, such as a future equity offering by us or a change in control of the Company. Other provisions are not contingent in nature. In one of the non-contingent scenarios, the price at which we could retire the notes is based, in part, on a variable interest rate. We have analyzed all the provisions of the indenture that allow us to repay this debt early in order to determine if any of these call options constitute an embedded derivative instrument under SFAS 133 and require bifurcation and separate measurement from the host contract. We followed the guidance provided in paragraphs 6, 12, 13 and 61 of SFAS 133 and Derivatives Implementation Group (“DIG”) Issues B-16 and B-39 in determining whether or not the call options required bifurcation and separate measurement. Based on our analysis, we do not believe these options require bifurcation and separate measurement. NOTE 11. INCOME TAXES The components of our income tax expense are as follows: 2008 Year Ended December 31, 2007 (In thousands) 2006 Current income tax expense: Federal and state . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(55,190) (5,306) $ (81,384) (771) $ (92,213) (4,242) Deferred income tax (expense) benefit: Federal and state . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (60,496) (82,155) (96,455) (30,363) 616 (29,747) (24,281) (332) (24,613) (7,906) 914 (6,992) Total income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(90,243) $(106,768) $(103,447) We made net federal income tax payments of approximately $33.5 million, $85.5 million and $87.6 million for the years ended December 31, 2008, 2007 and 2006, respectively. We made net state income tax payments of approximately $6.6 million, $6.6 million and $8.4 million for the years ended December 31, 2008, 2007 and 2006, respectively. We made net foreign tax payments of approximately $3.4 million, $4.2 million and $3.0 million for the years ended December 31, 2008, 2007 and 2006, respectively. For the years ended December 31, 2008, 2007 and 2006, tax benefits allocated to stockholders’ equity for compensation expense for income tax purposes in excess of amounts recognized for financial reporting purposes were $1.7 million, $3.4 million and less than $0.1 million, respectively. The Company had allocated tax benefits to stockholders’ equity in prior years for compensation expense for income tax purposes in excess of amounts recognized for financial reporting purposes. 95 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Income tax expense differs from amounts computed by applying the statutory federal rate as follows: Year Ended December 31, 2007 2006 2008 Income tax computed at Federal statutory rate . . . . . . . . . . . . . . . . . . . . . . . . State taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Non deductible goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Change in valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35.0% 35.0% 35.0% 3.2 3.1 — 12.8 0.2 (0.3) 0.3 1.2 1.7 — (0.5) 1.5 Effective income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51.8% 38.7% 37.7% As of December 31, 2008 and 2007, our deferred tax assets and liabilities were comprised of the following: December 31, 2008 2007 (In thousands) Deferred tax assets: Net operating loss and tax credit carryforwards . . . . . . . . . . . . . . . . . . . Self-insurance reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Allowance for doubtful accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Total deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,664 20,944 4,023 14,681 10,116 3,085 57,513 Valuation allowance for deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . (844) Net deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56,669 $ 6,000 21,484 4,731 15,600 3,876 488 52,179 (1,458) 50,721 Deferred tax liabilities: Property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (190,675) (27,952) — (150,802) (31,993) (318) Total deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (218,627) (183,113) Net deferred tax liability, net of valuation allowance . . . . . . . . . . . . . . . . . $(161,958) $(132,392) In 2008, deferred tax liabilities decreased by $1.0 million for adjustments to accumulated other comprehensive loss. In 2007, deferred tax liabilities decreased by $0.2 million for adjustments to accumulated other comprehensive loss. In recording deferred income tax assets, we consider whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. We consider the scheduled reversal of deferred income tax liabilities and projected future taxable income for this determination. To fully realize the deferred income tax assets related to our federal net operating loss carryforwards that do not have a valuation allowance due to Section 382 limitations, we would need to generate future federal taxable income of approximately $4.8 million over the next ten years. With certain exceptions noted below, we believe that after considering all the available 96 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) objective evidence, both positive and negative, historical and prospective, with greater weight given to the historical evidence, it is more likely than not that these assets will be realized. We estimate that as of December 31, 2008, 2007 and 2006 we have available $7.1 million, $8.2 million and $9.3 million, respectively, of federal net operating loss carryforwards. Approximately $4.7 million of our net operating losses as of December 31, 2008 are subject to a $1.1 million annual Section 382 limitation and expire in 2018. Approximately $2.4 million of our net operating losses as of December 31, 2008 are subject to a $5,000 annual Section 382 limitation and expire in 2016 through 2018. A valuation allowance is provided when it is more likely than not that some portion of the deferred tax assets will not be realized. Due to annual limitations under Sections 382 and 383, management believes that we will not be able to utilize all available carryforwards prior to their ultimate expiration. The deferred tax asset associated with our remaining federal net operating loss carryforwards that will expire before utilization due to Section 382 limitations of $2.3 million includes a valuation allowance of $0.8 million as a result of the Section 382 limitations at December 31, 2008 and 2007, respectively. We estimate that as of December 31, 2008, 2007 and 2006 we have available $16 million, $19 million, and $31 million, respectively, of state net operating loss carryforwards that will expire from 2009 to 2025. To fully realize the deferred income tax assets related to our state net operating loss carryforwards, we would need to generate future West Virginia taxable income of $12.9 million over the next 17 years and future Pennsylvania taxable income of $2.0 million over the next 17 years. Management believes that it is not more likely than not that we will be able to utilize all available carryforwards prior to their ultimate expiration. The deferred tax asset associated with our remaining state net operating loss carryforwards at December 31, 2008 of $1.4 million includes a valuation allowance of less than $0.1 million as a result. In 2007, the Company began operations in Mexico that resulted in a net operating loss of $2 million and a deferred tax asset related to the net operating loss carryforward of $0.6 million. Mexico enacted a new flat tax rate effective January 1, 2008. The flat tax functions in addition to the regular corporate tax rate of 28%. Tax expense is calculated under both methods and if the flat tax is greater than the regular tax, the additional tax expense above the regular tax is assessed in addition to the regular tax calculation. In 2007, we recorded a full valuation allowance related to our Mexico net operating loss carryforwards of $0.6 million, as management believed that, due to the enactment of the Mexico flat tax, all of our net operating loss carryforwards related to the Mexico operations were not more likely than not to be fully realized in the future. It was determined the Company would not be in a flat tax position in 2008 and all of the 2007 regular net operating loss will be utilized against 2008 regular Mexico income. Accordingly, the valuation allowance of $0.6 million set up in 2007 was released in 2008. In 2007, the Company made a stock acquisition of AMI, a Canadian company. At December 31, 2008 and 2007, the Company’s Canadian operations had net operating losses of $3.8 million and $3.2 million, respectively. At December 31, 2008 and 2007 the deferred tax asset related to the net operating loss carryforward was $1.1 million and $1.0 million respectively. We have recorded no valuation allowance related to our Canadian net operating loss carryforwards at December 31, 2008 and 2007, as management believes that all of our net operating loss carryforwards related to the Canadian operations are more likely than not to be fully realized in the future. To fully realize the deferred income tax assets related to our Canadian net operating loss carryforwards, we would need to generate $0.2 million of future Canadian taxable income over the next seven years and $3.6 million of future Canadian taxable income over the next nineteen years. The net operating losses expire from 2015 to 2028. We did not provide for U.S. income taxes or withholding taxes on the 2008 unremitted earnings of our Mexico subsidiaries as these earnings are considered permanently reinvested. Unremitted earnings of our Mexico subsidiaries, representing tax basis accumulated earnings and profits, totaled approximately $6.3 million as of December 31, 2008. We did not provide for U.S. income taxes on 2007 and 2006 unremitted earnings of our 97 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) foreign subsidiaries as our tax basis in each foreign subsidiary was in excess of the book basis as of December 31, 2007 and 2006. In December 2006, the FASB issued FIN 48. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109. FIN 48 prescribes a recognition threshold and measurement attributes for the financial statement recognition and measurement of an income tax position taken or expected to be taken in an income tax return. FIN 48 also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. In May 2007, the FASB issued FSP FIN 48-1. FSP FIN 48-1 provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. In determining whether a tax position has been effectively settled, entities must evaluate (i) whether taxing authorities have completed their examination procedures; (ii) whether the entity intends to appeal or litigate any aspect of a tax position included in a completed evaluation; and (iii) whether it is remote that a taxing authority would examine or re-examine any aspect of a taxing position. FSP FIN 48-1 is to be applied upon the initial adoption of FIN 48. As of December 31, 2008, December 31, 2007 and January 1, 2007 we had approximately $5.6 million, $6.8 million and $3.4 million, respectively, of unrecognized tax benefits net of federal benefits which, if recognized, would impact our effective tax rate. We have accrued approximately $2.1 million, $2.3 million and $1.0 million for the payment of interest and penalties as of December 31, 2008, December 31, 2007 and January 1, 2007, respectively. We believe that is reasonably possible that approximately $2.8 million of our currently remaining unrecognized tax positions, each of which are individually insignificant, may be recognized by the end of 2008 as a result of a lapse of the statute of limitations. We file income tax returns in the United States federal jurisdiction and various states and foreign jurisdictions. We are not under a current federal tax examination. Federal tax years ending December 31, 2005 and forward are open for tax audits as of December 31, 2008. Our other significant filings are Argentina which has been examined through 2006, Mexico which is in the initial stages of a 2007 tax audit of our initial year of operations and in the State of Texas, where tax filings remain open for 2003 to 2006 for certain subsidiaries of the Company. We recognized tax benefits in 2008 of $1.7 million for expirations of statutes of limitations. We recorded an income tax benefit of $0.7 million, increase to deferred tax liabilities of $0.5 million and decrease to goodwill of $0.5 million related to these statute expirations. The following table presents the activity during 2008 related to our FIN 48 reserve (in thousands): Balance at January 1, 2008. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Additions based on tax positions related to the current year . . . . . . . . . . . . . . . . . . . . . . . . . Additions based on tax positions related to prior years . . . . . . . . . . . . . . . . . . . . . . . . . . . . Decreases in unrecognized tax benefits acquired or assumed in business combinations . . . . . Reductions for tax positions from prior years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $5,722 551 104 (707) (612) — Balance at December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $5,058 Tax Legislative Changes The Economic Stimulus Act of 2008. The Economic Stimulus Act of 2008 permits a bonus first-year depreciation deduction of 50% of the adjusted basis of qualified property (most personal property and software) acquired and placed in service after December 31, 2007 and before January 1, 2009. We have 98 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) estimated $123 million of qualifying additions in 2008 resulting in additional 2008 tax depreciation of $49 million. The American Recovery and Reinvestment Act of 2009. The American Recovery and Reinvestment Act of 2009 extends the bonus first-year depreciation deduction of 50% of the adjusted basis of qualified property acquired and placed in service to after December 31, 2008 and before January 1, 2010. Revised Texas Franchise tax. In May 2006, the state of Texas enacted a new law, effective January 1, 2007, that substantially changes the tax system in Texas. The law replaces the taxable capital and earned surplus components of its franchise tax with a new tax that is based on modified gross revenue. This law imposes a tax on a unitary group of affiliated entities’ net receipts rather than on the earned surplus of each separate entity. NOTE 12. LONG-TERM DEBT The components of our long-term debt are as follows: December 31, 2008 2007 (In thousands) 8.375% Senior Notes due 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $425,000 187,813 Senior Secured Credit Facility revolving loans due 2012. . . . . . . . . . . . . . . . 3,015 Other long-term indebtedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,318 Notes payable — related party, net of discount of $182 and $322 . . . . . . . . . 23,149 Capital lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $425,000 50,000 — 22,178 26,815 659,295 523,993 Less current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (25,704) (12,379) Total long-term debt and capital lease obligations, net of fair value discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $633,591 $511,614 8.375% Senior Notes due 2014 On November 29, 2007, the Company issued $425.0 million aggregate principal amount of 8.375% Senior Notes due 2014 (the “Senior Notes”), under an Indenture, dated as of November 29, 2007 (the “Indenture”), among us, the guarantors party thereto (the “Guarantors”) and The Bank of New York Trust Company, N.A., as trustee. The Senior Notes were priced at 100% of their face value to yield 8.375%. Net proceeds, after deducting initial purchasers’ fees and estimated offering expenses, were approximately $416.1 million. We used approximately $394.9 million of the net proceeds to retire then existing term loans, including accrued and unpaid interest, with the balance used for general corporate purposes. The Senior Notes are general unsecured senior obligations of Key. Accordingly, they will rank effectively subordinate to all of our existing and future secured indebtedness. The Senior Notes are or will be jointly and severally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. Interest on the Senior Notes is payable on June 1 and December 1 of each year beginning June 1, 2008. The Senior Notes mature on December 1, 2014. On or after December 1, 2011, the Senior Notes will be subject to redemption at any time and from time to time at our option, in whole or in part, upon not less than 30 nor more than 60 days’ notice, at the redemption prices (expressed as percentages of the principal amount redeemed) set forth below, plus accrued 99 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) and unpaid interest thereon to the applicable redemption date, if redeemed during the twelve-month period beginning on December 1 of the years indicated below: Year 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Percentage 104.19% 102.09% 100.00% Notwithstanding the foregoing, at any time and from time to time before December 1, 2010, we may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of the outstanding Senior Notes at a redemption price of 108.375% of the principal amount thereof, plus accrued and unpaid interest thereon to the redemption date, with the net cash proceeds of any one or more equity offerings; provided that at least 65% of the aggregate principal amount of the Senior Notes issued under the Indenture remains outstanding immediately after each such redemption; and provided, further, that each such redemption shall occur within 180 days of the date of the closing of such equity offering. In addition, at any time and from time to time prior to December 1, 2011, the Company may, at our option, redeem all or a portion of the Senior Notes at a redemption price equal to 100% of the principal amount thereof plus the applicable premium (as defined in the Indenture) with respect to the Senior Notes and plus accrued and unpaid interest thereon to the redemption date. If the Company experiences a change of control, subject to certain exceptions, it must give holders of the Senior Notes the opportunity to sell to the Company their Senior Notes, in whole or in part, at a purchase price equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest thereon to the date of purchase. The Company and its restricted subsidiaries are subject to certain negative covenants under the indenture governing the Senior Notes. The indenture limits the ability of the Company and each of its restricted subsidiaries to, among other things, (i) sell assets, (ii) pay dividends or make other distributions on capital stock or subordinated indebtedness, (iii) make investments, (iv) incur additional indebtedness or issue preferred stock, (v) create certain liens, (vi) enter into agreements that restrict dividends or other payments from its subsidiaries to itself, (vii) consolidate, merge or transfer all or substantially all of its assets, (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. In connection with the sale of the Senior Notes, the Company entered into a registration rights agreement with the initial purchasers, pursuant to which it agreed to file an exchange offer registration statement with the SEC with respect to an offer to exchange the Senior Notes for substantially identical notes that would be registered under the Securities Act, and to use reasonable best efforts to cause such registration statement become effective on or prior to November 29, 2008. In accordance with the agreement, the Company filed an exchange offer registration statement with the SEC on August 19, 2008, which became effective August 22, 2008, and offered to exchange an aggregate principal amount of $425.0 million of registered 8.375% Senior Notes due 2014, which the Company refers to as the exchange notes, for any and all of our original unregistered 8.375% Senior Notes due 2014 that were issued in a private offering on November 29, 2007. The terms of the exchange notes were substantially identical to those terms of the original notes, except that the transfer restrictions, registration rights and additional interest provisions relating to the originally issued notes did not apply to the exchange notes. References to the “Senior Notes” herein includes exchange notes issued in the exchange offer. As of December 31, 2008, the Company is in compliance with all the covenants required under the Senior Notes. 100 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Senior Secured Credit Facility Simultaneously with the closing of the offering of the Senior Notes, the Company entered into a new credit agreement (the “Credit Agreement”) with several lenders. The Credit Agreement provides for a senior secured credit facility (the “Senior Secured Credit Facility”) consisting of a revolving credit facility, letter of credit sub-facility and swing line facility of up to an aggregate principal amount of $400.0 million, all of which will mature no later than November 29, 2012. 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 Senior Secured Credit Facility replaced the Company’s Prior Credit Facility, which was repaid with the proceeds from the Senior Notes. The interest rate per annum applicable to amounts borrowed under the Senior Secured Credit Facility are, at the Company’s option, (i) LIBOR plus the applicable margin or (ii) the higher of (x) Bank of America’s prime rate and (y) the Federal Funds rate plus 0.5%, plus the applicable margin. The applicable margin for LIBOR loans ranges from 150 to 200 basis points, and the applicable margin for all other loans ranges from 50 to 100 basis points, both of which depend upon the Company’s consolidated leverage ratio. The Senior Secured Credit Facility contains certain financial covenants, which, among other things, require the maintenance of a consolidated leverage ratio not to exceed 3.50 to 1.00 and a consolidated interest coverage ratio of not less than 3.00 to 1.00, and limit the Company’s capital expenditures to $250.0 million per fiscal year, up to 50% of which amount may be carried over for expenditure in the following fiscal year. Each of the ratios referred to above will be calculated quarterly on a consolidated basis for each trailing four fiscal quarter period. In addition, the Senior Secured Credit Facility contains certain affirmative and negative covenants, including, without limitation, restrictions on (i) liens; (ii) debt, guarantees and other contingent obligations; (iii) mergers and consolidations; (iv) sales, transfers and other dispositions of property or assets; (v) loans, acquisitions, joint ventures and other investments (with acquisitions permitted so long as, after giving pro forma effect thereto, no default or event of default exists under the Senior Secured Credit Facility, the consolidated leverage ratio does not exceed 2.75 to 1.00, the Company is in compliance with the consolidated interest coverage ratio and the Company has at least $25 million of availability under the Senior Secured Credit Facility); (vi) dividends and other distributions to, and redemptions and repurchases from, equity holders; (vii) prepaying, redeeming or repurchasing subordinated (contractually or structurally) debt; (viii) granting negative pledges other than to the lenders; (ix) changes in the nature of the Company’s business; (x) amending organizational documents, or amending or otherwise modifying any debt, any related document or any other material agreement if such amendment or modification would have a material adverse effect; and (xi) changes in accounting policies or reporting practices; in each of the foregoing cases, with certain exceptions. Further, the Senior Secured Credit Facility permits share repurchases up to $200.0 million and provides that share repurchases in excess of $200.0 million can be made only if our debt to capitalization ratio is below 50%. As of December 31, 2008, the Company is in compliance with all the covenants required under the Senior Secured Credit Facility. The Company may prepay the Senior Secured Credit Facility in whole or in part at any time without premium or penalty, subject to certain reimbursements to the lenders for breakage and redeployment costs. On September 15, 2008, Lehman Brothers Holdings (“Lehman”) filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Lehman Commercial Paper, Inc. (“LCPI”), a subsidiary of Lehman, was a member of the syndicate of banks participating in our Senior Secured Credit Facility. LCPI’s commitment was approximately 11% of the Company’s total facility. As of December 31, 2008, the Company had approximately $139.3 million available under its Senior Secured Credit Facility. This availability reflects the reduction of approximately $19.3 million of unfunded commitments by LCPI. The Company also had 101 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) $53.6 million in committed letters of credit under the facility. Under the terms of the agreement, committed letters of credit count against our borrowing capacity under the revolving credit facility. Seller Financing Arrangement in Moncla Purchase In connection with the acquisition of Moncla (see “Note 2. Acquisitions”), the Company entered into two promissory notes with the sellers. The first is an unsecured note in the amount of $12.5 million, which is due and payable in a lump-sum, together with accrued interest, on October 25, 2009. Interest on this note is due on each anniversary of the closing of the acquisition of Moncla, which was October 25, 2007. The second unsecured note in the amount of $10.0 million is payable in annual installments of $2.0 million, plus accrued interest, beginning October 25, 2008 through 2012. Each of the notes bears interest at the Federal Funds rate, adjusted annually on the anniversary of the closing date. As of December 31, 2008, the interest rate on these notes was 1.5%. Interest expense for the years ended December 31, 2008 and 2007 was $1.2 million and $0.2 million, respectively, on the two notes in aggregate. The Federal Funds rate does not represent a rate that would have resulted if an independent borrower and an independent lender had negotiated a similar transaction under comparable terms and conditions and is not equal to our incremental borrowing rate. In accordance with Accounting Principles Board (“APB”) No. 21, Interest on Receivables and Payables (“APB 21”) and SFAS No. 141, Business Combinations (“SFAS 141”), we recorded the promissory notes at fair value which resulted in a discount being recorded. The discount will be recognized as interest expense over the life of the promissory notes using the effective interest method. The amount of discount remaining to be amortized as of December 31, 2008 and 2007 was $0.2 million and $0.3 million, respectively, for both notes in the aggregate. The total amount of discount amortization included in interest expense related to the notes for the years ended December 31, 2008 and 2007 was approximately $0.1 million and less than $0.1 million, respectively. Long-Term Debt Principal Repayment and Interest Expense Presented below is a schedule of the repayment requirements of long-term debt for each of the next five years and thereafter as of December 31, 2008: 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total principal payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: fair value discount. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Principal Amount of Long-Term Debt (In thousands) $ 16,500 3,015 2,000 189,813 — 425,000 636,328 182 $636,146 102 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Presented below is a schedule of our estimated minimum lease payments on our capital lease obligations for the next five years and thereafter as of December 31, 2008: 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total minimum lease payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: executory costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net minimum lease payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: amounts representing interest . . . . . . . . . . . . . . . . . . . . . . . . . Capital Lease Obligation Minimum Lease Payments (In thousands) $10,635 7,913 4,832 1,969 378 — 25,727 (729) 24,998 (1,849) Present value of minimum lease payments . . . . . . . . . . . . . . . . . . . . $23,149 Interest expense for the years ended December 31, 2008, 2007 and 2006 consisted of the following: Cash payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Commitment and agency fees paid . . . . . . . . . . . . . . . . . . . . . . . . . Amortization of discount, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amortization of deferred financing costs . . . . . . . . . . . . . . . . . . . . Settlement of interest rate swaps . . . . . . . . . . . . . . . . . . . . . . . . . . Net change in accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . Capitalized interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2008 2006 Year Ended December 31, 2007 (In thousands) $33,964 2,232 — 1,680 2,261 1,366 (5,296) $45,211 102 140 1,975 — 333 (6,514) $40,290 4,244 — 1,620 — (3,869) (3,358) Total interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $41,247 $36,207 $38,927 As of December 31, 2008 and 2007, the weighted average interest rate of our variable rate debt was 4.17% and 5.98%, respectively. Deferred Financing Costs In connection with our long-term debt, we capitalized costs and expenses of approximately $0.3 million, $13.4 million and $0.5 million for the years ended December 31, 2008, 2007 and 2006, respectively. Amortization of deferred financing costs totaled $2.0 million, $1.7 million and $1.6 million for the years ended December 31, 2008, 2007 and 2006, respectively. Unamortized debt issuance costs written off and included in the determination of the gain or loss on the extinguishment of debt were zero, $9.6 million and 103 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) zero for the years ended December 31, 2008, 2007 and 2006, respectively. Net carrying values for the years presented appear in the table below: December 31, 2008 2007 (In thousands) Deferred financing costs: Gross carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $12,609 (2,120) $12,262 (145) Net carrying value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $10,489 $12,117 NOTE 13. COMMITMENTS AND CONTINGENCIES Operating Lease Arrangements Key leases certain property and equipment under non-cancelable operating leases that expire at various dates through 2019, with varying payment dates throughout each month. As of December 31, 2008, the future minimum lease payments under non-cancelable operating leases are as follows (in thousands): 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lease Payments $ 6,312 5,664 4,578 4,000 2,996 4,679 $28,229 The Company also is party to a significant number of month-to-month leases that are cancelable at any time. Operating lease expense was $22.4 million, $16.4 million and $17.0 million for the years ended December 31, 2008, 2007 and 2006, respectively. Litigation Various suits and claims arising in the ordinary course of business are pending against us. Due in part to the locations where we conduct business in the continental United States, we are often subject to jury verdicts and arbitration hearings that result in outcomes in favor of the plaintiffs. We continually assess our contingent liabilities, including potential litigation liabilities, as well as the adequacy of our accruals and our need for the disclosure of these items. In accordance with SFAS 5, we establish a provision for a contingent liability when it is probable that a liability has been incurred and the amount is estimable. As of December 31, 2008, the aggregate amount of our provisions for losses related to litigation that are deemed probable and estimable is approximately $4.5 million. We do not believe that the disposition of any of these matters will result in an additional loss materially in excess of amounts that have been recorded. In the year ended December 31, 2008, we recorded a benefit of approximately $2.2 million related to settlement of ongoing legal matters and continued refinement of liabilities recognized for litigation deemed probable and estimable. Provisions related to litigation matters that were deemed probable and estimable were $6.8 million in 2007 and $28.8 million in 2006. 104 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Gonzales Matter In September 2005, a class action lawsuit, Gonzales v. Key Energy Services, Inc., was filed in Ventura County, California Superior Court, alleging that Key did not pay its hourly employees for travel time between the yard and the wellhead and that certain employees were denied meal and rest periods. On September 17, 2008, we reached an agreement in principle, subject to court approval, to settle all claims related to this matter for $1.2 million. In 2005 we recorded a liability for this lawsuit, and the subsequent settlement of this matter in 2008 did not have a material impact on our financial position, results of operations or cash flows. Litigation with Former Officers and Employees We were named in a lawsuit by our former general counsel, Jack D. Loftis, Jr., filed in the U.S. District Court, District of New Jersey on April 21, 2006, in which he alleges a “whistle-blower” claim under the Sarbanes-Oxley Act, breach of contract, breach of duties of good faith and fair dealing, breach of fiduciary duty and wrongful termination. On August 17, 2007, the Company filed counterclaims against Mr. Loftis alleging attorney malpractice, breach of contract and breach of fiduciary duties. In its counterclaims, the Company seeks repayment of all severance paid to Mr. Loftis to date (approximately $0.8 million) plus benefits paid during the period July 8, 2004 to September 21, 2004, and damages relating to the allegations of malpractice and breach of fiduciary duties. The case was transferred to and is now pending in the U.S. District Court for the Eastern District of Pennsylvania and is currently set for trial in the fourth quarter of 2009. We recorded for the fourth quarter of 2008 a liability for this matter and do not believe that the conclusion of this matter will have a material impact on our financial position, results of operations or cash flows. On October 17, 2006, Jane John, the ex-wife of our former chief executive officer, Francis John, filed a complaint in Bucks County, Pennsylvania against her ex-husband and the Company. Ms. John alleges breach of marital agreement, breach of options agreements, civil conspiracy and fraud. She alleges that Mr. John and the Company defrauded her with regard to Mr. John’s compensation, as well as in the disclosures of marital property. By virtue of assignments, Ms. John holds 375,000 stock options which expired unexercised during the period before the Company became current in its financial statements, when such options could not be exercised. In resolving a separate lawsuit between the Company and Mr. John, Mr. John agreed to indemnify the Company with respect to damages attributable to any and all of Ms. John’s claims, other than damages attributable to any alleged breach of Ms. John’s stock option agreements, for which the Company agreed to indemnify Mr. John. Discovery in the case remains ongoing, and there is currently not a trial setting. We recorded a liability for this matter for the third quarter of 2008 and do not believe that the conclusion of this matter will have a material impact on our financial position, results of operations or cash flows. On September 3, 2006, our former controller and former assistant controller filed a joint complaint against the Company in the 133rd District Court, Harris County, Texas, alleging constructive termination and breach of contract. Additionally, on January 11, 2008, our former chief operating officer, James Byerlotzer, filed a lawsuit in the 55th District Court, Harris County, Texas, alleging breach of contract based on his inability to exercise his stock options during the period that we were not current in our SEC filings, and based on our failure to provide him shares of restricted stock. We are currently set for trial in both of these matters in the second quarter of 2009. We have not recorded a liability for these matters and do not believe that the conclusion of these matters will have a material impact on our financial position, results of operations or cash flows. On August 21, 2006, our former chief financial officer, Royce W. Mitchell, filed a suit against the Company in 385th District Court, Midland County, Texas alleging breach of contract with regard to alleged bonuses, benefits, expense reimbursements, conditional stock grants and stock options, as well as relief under theories of quantum meruit, promissory estoppel and specific performance. On February 15, 2008, the parties 105 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) settled the matter for $0.5 million, which included reimbursement of expenses and attorneys fees of approximately $0.4 million. Stockholder Class Action Suits and Derivative Actions Since June 2004, we and certain of our officers and directors were named as defendants in six class action complaints brought on behalf of a putative class of purchasers of our securities for alleged violations of federal securities laws, which were filed in federal district court in Texas. These six actions were consolidated into one action. Four stockholder derivative actions were also filed, purportedly on our behalf, generally alleging the same facts as those in the consolidated stockholder class action. On September 7, 2007, we reached agreements in principle to settle all of these stockholder class action and derivative lawsuits in consideration of payments totaling $16.6 million in exchange for full and complete releases for all defendants, of which the Company paid approximately $1.1 million. We received final approval of the settlement of the stockholder class action claims by the court on March 6, 2008, and final court approval on the derivative settlement was received on August 8, 2008. All litigation in the stockholder class action and derivative matters has been concluded. Expired Option Holders In September 2007, Belinda Taylor filed a lawsuit in the 11th Judicial District of Harris County, Texas, on behalf of herself and all similarly situated current and former employees who held vested options that expired between April 28, 2004 and the date that the Company became current in its financial statements (the “Expired Option Holders”). The suit, as amended, alleged that the Company breached its contracts with the Expired Option Holders, and breached its fiduciary duties and duties of good faith and fair dealing in the pricing of stock options it granted to those Expired Option Holders. On March 6, 2008, the parties agreed to settle all pending claims with all Expired Option Holders, excluding those terminated for cause and those who have previously filed suits against us, for approximately $1.0 million, which includes all taxes and legal fees. The court entered a final order approving the settlement on August 25, 2008 and dismissed the case. In December 2008, the payments to the class, pursuant to the terms of the settlement, were completed. The lawsuits in which we are involved with Jane John and our former controller and former assistant controller, described above under “Litigation with Former Officers and Employees,” also involve claims relating to expired stock options. Automobile Accident Litigation On August 22, 2007, one of our employees was involved in an automobile accident that resulted in a third party fatality and during the first quarter of 2008 we recorded an appropriate liability for this matter. The lawsuit arising from this accident was settled during the third quarter of 2008 and the Company recognized incremental expense of less than $0.5 million related to the settlement during the third quarter of 2008. Tax Audits We are routinely the subject of audits by tax authorities, and in the past have received material assessments from tax auditors. As of December 31, 2008 and 2007, we have recorded reserves that management feels are appropriate for future potential liabilities as a result of these audits. While we believe we have fully reserved for these assessments, the ultimate amount of settlements can vary from our estimates. In connection with an ongoing sales tax audit, the Company recorded a liability of approximately $3.2 million during the third quarter of 2008 relating to state sales taxes not collected from the Company’s customers from 2003 through September 30, 2008 and therefore not remitted to the appropriate state agency. 106 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) The provision was recorded as general and administrative expense. We do not expect that the ultimate resolution of the matter will result in a loss materially in excess of the amount already accrued. In connection with our former Egyptian operations, which terminated in 2005, we are undergoing income tax audits for all periods in which we had operations. As of December 31, 2008, the Company has recorded a liability of approximately $0.4 million relating to open Egyptian income tax audits. In the fourth quarter of 2007, the Company reached a preliminary settlement with the Egyptian tax authorities on the 2003 and 2004 tax years, recording a tax benefit of $0.7 million and reducing the tax liability accrued at December 31, 2007 to approximately $0.4 million. We do not expect that the ultimate resolution of the matter will result in a loss materially in excess of the amount already accrued. Self-Insurance Reserves We maintain reserves for workers’ compensation and vehicle liability on our balance sheet based on our judgment and estimates using an actuarial method based on claims incurred. We estimate general liability claims on a case-by-case basis. We maintain insurance policies for workers’ compensation, vehicle liability and general liability claims. These insurance policies carry self-insured retention limits or deductibles on a per occurrence basis. The retention limits or deductibles are accounted for in our accrual process for all workers’ compensation, vehicular liability and general liability claims. As of December 31, 2008 and 2007, we have recorded $68.9 million and $69.0 million, respectively, of self-insurance reserves related to workers’ compen- sation, vehicular liabilities and general liability claims. Partially offsetting these liabilities, we had approxi- mately $10.8 million and $8.1 million of insurance receivables as of December 31, 2008 and 2007, respectively. We feel that the liabilities we have recorded are appropriate based on the known facts and circumstances and do not expect further losses materially in excess of the amounts already accrued for existing claims. Environmental Remediation Liabilities For environmental reserve matters, including remediation efforts for current locations and those relating to previously-disposed properties, we record liabilities when our remediation efforts are probable and the costs to conduct such remediation efforts can be reasonably estimated. While our litigation reserves reflect the application of our insurance coverage, our environmental reserves do not reflect management’s assessment of the insurance coverage that may apply to the matters at issue. As of December 31, 2008 and 2007, we have recorded $3.0 million and $3.1 million, respectively, for our environmental remediation liabilities. We feel that the liabilities we have recorded are appropriate based on the known facts and circumstances and do not expect further losses materially in excess of the amounts already accrued. We provide performance bonds to provide financial surety assurances for the remediation and mainte- nance of our SWD properties to comply with environmental protection standards. Costs for SWD properties may be mandatory (to comply with applicable laws and regulations), in the future (required to divest or cease operations), or for optimization (to improve operations, but not for safety or regulatory compliance). Registration Payment Arrangement In January 1999, we issued 150,000 warrants (the “Warrants”) in connection with a debt offering that were exercisable for an aggregate of approximately 2.2 million shares of the Company’s stock at an exercise price of $4.88125 per share. As of December 31, 2008, 83,800 Warrants had been exercised, leaving 66,200 outstanding, which were exercisable for approximately 1.0 million shares of our common stock. Termination notice was provided to the holders of the outstanding Warrants that the Warrants expired on February 2, 2009. Under the terms of the Warrants, the Company was required to maintain an effective registration statement covering the shares potentially issuable upon exercise of the Warrants. If the Company did not have 107 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) an effective registration statement covering the shares, the Company was required to make liquidated damages payments to the holders of the Warrants. During the twelve months ended December 31, 2008, 2007 and 2006, the Company made liquidated damages payments totaling $0.8 million, $0.9 million and $0.9 million, respectively. On August 21, 2008, the requisite registration statement required by the terms of the Warrants became effective. From and after August 22, 2008, no additional liquidated damage payments were required to be made by the Company. NOTE 14. ACCUMULATED OTHER COMPREHENSIVE LOSS The components of our accumulated other comprehensive loss are as follows: December 31, 2008 2007 (In thousands) Foreign currency translation loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(46,520) (30) Deferred loss from available for sale investments. . . . . . . . . . . . . . . . . . . . . . $(37,959) (22) Accumulated other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . $(46,550) $(37,981) The local currency is the functional currency for our operations in Argentina, Mexico and Canada, and for our equity investments in Canada and the Russian Federation. The cumulative translation gains and losses resulting from translating each foreign subsidiary’s financial statements from the functional currency to U.S. dollars are included in other comprehensive income and accumulated in stockholders’ equity until a partial or complete sale or liquidation of our net investment in the foreign entity. The table below summarizes the conversion ratios used to translate the financial statements and the cumulative currency translation gains and losses, net of tax, for each currency: As of December 31, 2008: Conversion ratio . . . . . . . . . Cumulative translation Argentine Peso Mexican Peso Canadian Dollar Euro Russian Rouble Total (In thousands, except for conversion ratios) 3.46:1 13.78:1 1.22:1 0.71:1 29.48:1 n/a adjustment . . . . . . . . . . . . $(43,654) $ (1,663) $ (917) $ (286) $ — $(46,520) As of December 31, 2007: Conversion ratio . . . . . . . . . Cumulative translation 3.15:1 10.92:1 0.98:1 0.68:1 24.51:1 n/a adjustment . . . . . . . . . . . . $(38,181) $ (143) $ 365 $ — $ — $(37,959) NOTE 15. EMPLOYEE BENEFIT PLANS We maintain a 401(k) plan as part of our employee benefits package. We match 100% of employee contributions up to 4% of the employee’s salary into our 401(k) plan, subject to maximums of $9,200, $9,000 and $8,800 for the years ended December 31, 2008, 2007 and 2006, respectively. Our matching contributions were $11.9 million, $10.2 million and $7.4 million for the years ended December 31, 2008, 2007 and 2006, respectively. Employees are fully vested in the matching contributions when they are made by the Company. Effective January 1, 2006, we no longer offered participants the option to purchase units of company stock through a 401(k) plan fund. We discontinued this option for participants and transferred all units of Key stock into another 401(k) plan fund, which did not affect the ability of plan participants to manage these contributions. 108 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) NOTE 16. STOCKHOLDERS’ EQUITY Common Stock On December 31, 2008, we had 200,000,000 shares of common stock authorized with a $0.10 par value, of which 121,305,289 shares were issued and outstanding, and during 2008 no dividends were paid. On December 31, 2007, we had 200,000,000 shares of common stock authorized with a $0.10 par value, of which 131,142,905 shares were issued and outstanding, and during 2007 no dividends were paid. Under the terms of the Senior Notes and Senior Secured Credit Facility, we must meet certain financial covenants before we may pay dividends. We currently do not intend to pay dividends. Share Repurchase Program In October 2007, our Board of Directors authorized a share repurchase program of up to $300.0 million which is effective through March 31, 2009. From the inception of the program in November 2007 through December 31, 2008, we have repurchased approximately 13.4 million shares of our common stock through open market transactions for an aggregate price of approximately $167.3 million. Share repurchases during 2008 were approximately 11.1 million shares for an aggregate price of approximately $135.2 million. Our repurchase program, as well as the amount and timing of future repurchases, is subject to market conditions, our financial condition, and our liquidity. Our Senior Secured Credit Facility permits us to make stock repurchases in excess of $200.0 million only if our consolidated debt to capitalization ratio (as defined) is below 50%; as of December 31, 2008, that ratio was below 50%. Tax Withholding In June 2006, the Company began purchasing shares of restricted common stock that had been previously granted to certain of the Company’s officers, pursuant to an agreement under which those individuals were permitted to sell shares back to the Company in order to satisfy the minimum income tax withholding requirements related to vesting of these grants. We repurchased a total of 97,443 and 72,847 shares for an aggregate cost of $1.2 million and $1.3 million during 2008 and 2007, respectively, which represented the fair market value of the shares based on the price of the Company’s stock on the dates of purchase. Through December 31, 2008, under the share repurchase program, tax withholdings and share acquisitions in prior years, we have repurchased approximately 13.7 million shares of our common stock, at an aggregate cost of $171.0 million. Common Stock Warrants In January 1999, we issued 150,000 warrants (the “Warrants”) in connection with a debt offering that were exercisable for an aggregate of approximately 2.2 million shares of the Company’s stock at an exercise price of $4.88125 per share. As of December 31, 2008, 83,800 Warrants had been exercised, leaving 66,200 outstanding, which were exercisable for approximately 1.0 million shares of our common stock. Termination notice was provided to the holders of the outstanding Warrants and the Warrants expired on February 2, 2009. Under the terms of the Warrants, the Company was required to maintain an effective registration statement covering the shares potentially issuable upon exercise of the Warrants. If the Company did not have an effective registration statement covering the shares, the Company was required to make liquidated damages payments to the holders of the Warrants. Because of the Company’s past failure to timely file its Annual and Quarterly Reports with the SEC, it did not have an effective registration statement, and during the twelve months ended December 31, 2008, 2007 and 2006, the Company made liquidated damages payments totaling $0.8, $0.9 and $0.9 million, respectively. On August 21, 2008, the requisite registration statement required by the terms of the Warrants became effective. From and after August 22, 2008, no additional liquidated damage payments were required to be made by the Company related to the Warrants. 109 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) NOTE 17. SHARE-BASED COMPENSATION 2007 Incentive Plan On December 6, 2007, the Company’s shareholders approved the 2007 Equity and Cash Incentive Plan (the “2007 Incentive Plan”). The 2007 Incentive Plan is administered by the Board or a committee designated by the Board (the “Committee”). The Board or the Committee (the “Administrator”) will have the power and authority to select Participants (as defined below) in the 2007 Incentive Plan and to grant Awards (as defined below) to such Participants pursuant to the terms of the 2007 Incentive Plan. Subject to adjustment, the total number of shares of the Company’s common stock, par value $0.10 per share, that will be available for the grant of Awards under the 2007 Incentive Plan may not exceed 4,000,000 shares; however, for purposes of this limitation, any stock subject to an award that is canceled, forfeited or expires prior to exercise or realization will again become available for issuance under the 2007 Incentive Plan. Subject to adjustment, no Participant will be granted, during any one year period, options to purchase common stock and/or stock appreciation rights with respect to more than 500,000 shares of common stock. Stock available for distribution under the 2007 Incentive Plan will come from authorized and unissued shares or shares reacquired by the Company in any manner. All awards under the 2007 Incentive Plan are granted at fair market value on the date of issuance. Awards may be in the form of options (incentive stock options and nonstatutory stock options), restricted stock, restricted stock units, performance compensation awards and stock appreciation rights (collectively, “Awards”). Awards may be granted to employees, directors and, in some cases, consultants and those individuals whom the Administrator determines are reasonably expected to become employees, directors or consultants following the grant date of the Award (“Participants”). However, incentive stock options may be granted only to employees. Vesting periods may be set at the Board’s discretion, and Awards have ten-year contractual lives. The Board at any time, and from time to time, may amend or terminate the 2007 Incentive Plan. However, except as provided otherwise in the 2007 Incentive Plan, no amendment will be effective unless approved by the shareholders of the Company to the extent shareholder approval is necessary to satisfy any applicable law or securities exchange listing requirements. As of December 31, 2008, there have been 1,806,556 awards granted with 2,250,144 remaining grants available under the 2007 Incentive Plan. 1997 Incentive Plan On January 13, 1998, Key’s shareholders approved the Key Energy Group, Inc. 1997 Incentive Plan, as amended (the “1997 Incentive Plan”, and together with the 2007 Incentive Plan, the “Plans”). The 1997 Incentive Plan is an amendment and restatement of the plans formerly known as the Key Energy Group, Inc. 1995 Stock Option Plan and the Key Energy Group, Inc. 1995 Outside Directors Stock Option Plan. On November 17, 2007, the 1997 Incentive Plan terminated pursuant to its terms. The exercise price of options granted under the 1997 Incentive Plan is at or above the fair market value per share on the date the options are granted. Under the 1997 Incentive Plan, while the shares of common stock are listed on a securities exchange, fair market value was determined using the closing sales price on the immediate preceding business day as reported on such securities exchange. When the shares were not listed on an exchange, which includes the period from April 2005 through October 2007, the fair market value was determined by using the published closing price of the common stock on the Pink Sheets on the business day immediately preceding the date of grant. The exercise of NSOs results in a U.S. tax deduction to us equal to the difference between the exercise price and the market price at the exercise date. 110 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) During the period 2000-2001, the Board of Directors granted 3.7 million stock options that were outside the 1997 Incentive Plan, of which 120,000 remained outstanding as of December 31, 2008 The 3.7 million non-plan options were in addition to and do not include other options which were granted under the 1997 Incentive Plan, but not in conformity with certain of the terms of the 1997 Incentive Plan. Accelerated Vesting of Option and SAR Awards Because of declines in the Company’s stock price, the Company’s Board of Directors resolved during the fourth quarter of 2008 to accelerate the vesting period on certain of the Company’s outstanding unvested stock option awards and stock appreciation rights, which affected approximately 280 employees. As a result of the acceleration, the Company recorded a pre-tax charge of approximately $10.9 million in general and adminis- trative expense in the accompanying consolidated statement of operations. Stock Option Awards Stock option awards granted under the Plans have a maximum contractual term of ten years from the date of grant. Shares issuable upon exercise of a stock option are issued from authorized but unissued shares of the Company’s common stock. The following table summarizes the stock option activity related to the Plans and certain options granted in prior years that were outside the 1997 Incentive Plan. 5.0 million options were outstanding as of December 31, 2008, and 2.3 million shares remained available for issuance under the 2007 Incentive Plan as of December 31, 2008 (shares in thousands): Outstanding at beginning of period. . . . . . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cancelled or expired . . . . . . . . . . . . . . . . . . . . . . . . . Options 4,594 1,379 (757) (255) Outstanding at end of period . . . . . . . . . . . . . . . . . . . 4,961 Exercisable at end of period . . . . . . . . . . . . . . . . . . . . 4,911 Outstanding at beginning of period. . . . . . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cancelled or expired . . . . . . . . . . . . . . . . . . . . . . . . . Options 5,829 1,195 (1,592) (838) Outstanding at end of period . . . . . . . . . . . . . . . . . . . 4,594 Exercisable at end of period . . . . . . . . . . . . . . . . . . . . 2,615 Year Ended December 31, 2008 Weighted Average Exercise Price Weighted Average Fair Value $11.01 $14.76 $ 8.81 $14.53 $12.21 $12.30 $5.32 $5.43 $4.81 $6.15 $5.38 $5.42 Year Ended December 31, 2007 Weighted Average Exercise Price Weighted Average Fair Value $ 9.46 $14.41 $ 8.45 $10.36 $11.01 $ 8.34 $4.94 $5.98 $4.58 $5.03 $5.32 $4.47 111 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Outstanding at beginning of period. . . . . . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cancelled or expired(1) . . . . . . . . . . . . . . . . . . . . . . . Options 9,275 833 — (4,279) Outstanding at end of period . . . . . . . . . . . . . . . . . . . 5,829 Exercisable at end of period . . . . . . . . . . . . . . . . . . . . 4,791 Year Ended December 31, 2006 Weighted Average Exercise Price Weighted Average Fair Value $ 8.68 $15.03 $ — $ 8.86 $ 9.46 $ 8.42 $4.79 $7.21 $ — $5.06 $4.94 $4.51 (1) Cancelled/expired options in 2006 include approximately 3.9 million options previously held by our former chief executive officer, which were cancelled in connection with his termination. The following table summarizes information about the stock options outstanding at December 31, 2008 (shares in thousands): Options Outstanding Weighted Average Remaining Contractual Life (Years) Number of Options Outstanding Weighted Average Exercise Price Weighted Average Fair Value Range of exercise prices: $ 3.00 - $ 7.44 . . . . . . . . . . . . $ 7.45 - $ 9.37 . . . . . . . . . . . . $ 9.38 - $13.10 . . . . . . . . . . . . $13.11 -$14.70 . . . . . . . . . . . . $14.71 -$19.42 . . . . . . . . . . . . 1.42 2.28 5.63 8.55 8.63 Aggregate intrinsic value (in thousands) . . . . . . . . . . . . . . 549 660 813 1,066 1,873 4,961 $ 578 $ 3.85 $ 8.31 $11.32 $14.31 $15.22 $12.21 $2.62 $4.89 $5.28 $5.99 $6.14 $5.38 Range of exercise prices: $ 3.00 - $ 7.44 . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7.45 - $ 9.37 . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9.38 - $13.10 . . . . . . . . . . . . . . . . . . . . . . . . . . . $13.11 -$14.70 . . . . . . . . . . . . . . . . . . . . . . . . . . . $14.71 -$19.42 . . . . . . . . . . . . . . . . . . . . . . . . . . . Options Exercisable Number of Options Exercisable Weighted Average Exercise Price Weighted Average Fair Value 499 653 821 1,066 1,872 4,911 $ 3.83 $ 8.33 $11.30 $14.31 $15.22 $12.30 $2.71 $4.89 $5.11 $5.99 $6.14 $5.42 Aggregate intrinsic value (in thousands) . . . . . . . . . $ 556 The total fair value of stock options granted during the years ended December 31, 2008, 2007 and 2006 was $7.5 million, $7.1 million and $6.0 million, respectively. The total fair value of stock options vested during the year ended December 31, 2008 was $19.4 million, including $14.8 million resulting from the 112 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) acceleration of the vesting of certain of the Company’s equity awards. For the years ended December 31, 2008, 2007 and 2006, the Company recognized approximately $15.1 million, $3.5 million and $2.6 million in pre-tax expense related to stock options, respectively. For unvested stock option awards outstanding as of December 31, 2008, the Company expects to recognize approximately less than $0.1 million of compensation expense over a weighted average remaining vesting period of approximately 2.4 years. The weighted average remaining contractual term for stock option awards exercisable as of December 31, 2008 is 6.5 years. The intrinsic value of the options exercised for the years ended December 31, 2008 and 2007 was $5.8 million and $10.2 million, respectively. No options were exercised in 2006. Cash received from the exercise of options for the year ended December 31, 2008 was $6.7 million with recognition of associated tax benefits in the amount of $5.2 million. Common Stock Awards In June 2005 we began granting shares of common stock to our outside directors and certain employees. Common stock awards granted to our outside directors vest immediately, while those granted to our employees vest ratably over a three-year period and are subject to forfeiture. The total fair market value of all common stock awards granted during the years ended December 31, 2008, 2007 and 2006 was $6.5 million, $4.7 million and $5.9 million, respectively. Pursuant to the agreement under which they are issued common stock awards, recipients of those awards may have shares withheld in order to satisfy those individuals’ income tax obligations associated with the vesting of the awards granted to them. Shares withheld for tax withholding purposes totaled 97,443 and 72,847 for the years ended December 31, 2008 and 2007, respectively, with aggregate repurchase values of $1.2 million and $1.3 million, respectively. In connection with a vesting in June of 2006, one of the recipients was permitted to have an amount withheld that was in excess of the required minimum withholding under current tax law. Under SFAS 123(R), the Company is required to account for this grant as a liability award. Compensation expense for this award during the years ended December 31, 2008, 2007 and 2006 was less than $0.1 million, $0.1 million and $0.2 million, respectively. The last tranche of shares associated with this award vested during 2008. The following table summarizes information for the years ended December 31, 2008, 2007 and 2006 about the common share awards that have been issued by the Company (shares in thousands): Year Ended December 31, 2008 Outstanding Weighted Average Issuance Price Shares at beginning of year. . . . . . . . . . . Shares issued during year(1) . . . . . . . . . . Previously issued shares vesting during year . . . . . . . . . . . . . . . . . . . . . . . . . . Shares repurchased during year . . . . . . . . 1,078 428 — (97) Shares at end of year . . . . . . . . . . . . . . . 1,409 $14.01 $15.10 $ — $12.86 $14.42 Vested 478 47 320 (97) 748 Weighted Average Issuance Price $13.48 $18.01 $13.97 $12.86 $14.05 113 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Year Ended December 31, 2007 Outstanding Weighted Average Issuance Price Shares at beginning of year. . . . . . . . . . . Shares issued during year(1) . . . . . . . . . . Previously issued shares vesting during year . . . . . . . . . . . . . . . . . . . . . . . . . . Shares repurchased during year . . . . . . . . 833 318 — (73) Shares at end of year . . . . . . . . . . . . . . . 1,078 $13.69 $14.87 $ — $14.05 $14.01 Vested 258 54 239 (73) 478 Weighted Average Issuance Price $12.44 $17.48 $13.87 $14.05 $13.48 Year Ended December 31, 2006 Outstanding Weighted Average Issuance Price Vested Weighted Average Issuance Price Shares at beginning of year. . . . . . . . . . . Shares issued during year(1) . . . . . . . . . . Previously issued shares vesting during year . . . . . . . . . . . . . . . . . . . . . . . . . . Shares repurchased during year . . . . . . . . Shares at end of year . . . . . . . . . . . . . . . 543 371 — (81) 833 $11.90 $15.92 $ — $11.90 $13.69 43 46 250 (81) 258 $11.90 $14.95 $11.90 $11.90 $12.44 (1) Shares of common stock issued to our non-employee directors vest immediately upon issuance. For common stock grants that vest immediately upon issuance, the Company records expense equal to the fair market value of the shares on the date of grant. For common stock awards that do not immediately vest, the Company recognizes compensation expense ratably over the vesting period of the grant, net of estimated and actual forfeitures. For the years ended December 31, 2008, 2007 and 2006, the Company recognized $6.1 million, $5.6 million and $3.6 million, respectively, of pre-tax expense associated with common stock awards, including common stock grants to our outside directors, net of estimated and actual forfeitures. In connection with the expense related to common stock awards recognized during the year ended December 31, 2008, the Company recognized tax benefits of approximately $1.5 million. For the unvested common stock awards outstanding as of December 31, 2008, the Company anticipates that it will recognize approximately $5.5 million of pre-tax expense over the next 1.5 years. Phantom Share Plan In December 2006, the Company announced the implementation of a “Phantom Share Plan,” in which certain of our employees were granted “Phantom Shares.” The Phantom Shares vest ratably over a four-year period and convey the right to the grantee to receive a cash payment on the anniversary date of the grant equal to the fair market value of the Phantom Shares vesting on that date. Grantees are not permitted to defer this payment to a later date. The Phantom Shares are a “liability” type award under SFAS 123(R), and we account for these awards at fair value. We recognize compensation expense related to the Phantom Shares based on the change in the fair value of the awards during the period and the percentage of the service requirement that has been performed, net of estimated and actual forfeitures, with an offsetting liability recorded on our consolidated balance sheets. We recognized less than $0.1 million of pre-tax benefit and approximately $3.3 million of pre-tax compensation expense associated with the Phantom Shares for the years ended December 31, 2008 and 2007, respectively. As of December 31, 2008, we recorded current and non-current liabilities of $0.9 million and $0.5 million, respectively, which represented the aggregate fair value of the 114 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Phantom Shares on that date. As of December 31, 2006, the amount of compensation expense and liabilities recorded related to the Phantom Share Plan in our consolidated financial statements were not material. We recognized income tax benefits associated with the Phantom Shares of less than $0.1 million and $1.3 million in 2008 and 2007, respectively. For unvested Phantom Share awards outstanding as of December 31, 2008, we expect to recognize approximately $1.3 million of compensation expense over a weighted average remaining vesting period of approximately 1.7 years. The first payout under the Phantom Share Plan was made in January 2008, at which time we paid approximately $1.6 million in cash to the holders of Phantom Shares that vested in December 2007. Stock Appreciation Rights In August 2007, the Company issued approximately 587,000 SARs to its executive officers. Each SAR has a ten-year term from the date of grant and vests in equal annual installments on the first, second and third anniversaries of the date of grant. Upon the exercise of a SAR, the recipient will receive an amount equal to the difference between the exercise price and the fair market value of a share of the Company’s common stock on the date of exercise, multiplied by the number of shares of common stock for which the SAR was exercised. All payments will be made in shares of the Company’s common stock. Prior to exercise, the SAR does not entitle the recipient to receive any shares of the Company’s common stock and does not provide the recipient with any voting or other stockholders’ rights. The Company accounts for these SARs as equity awards under SFAS 123(R) and recognizes compensation expense ratably over the vesting period of the SAR based on their fair value on the date of issuance, net of estimated and actual forfeitures. Compensation expense recognized in 2008 and 2007 in connection with the SARs was approximately $3.1 million and $0.6 million, respectively. Income tax benefits of approximately $1.1 million and $0.2 million in 2008 and 2007, respectively, were recognized by the Company in connection with this expense. The vesting of all of the Company’s outstanding SAR awards was accelerated during the fourth quarter of 2008 and therefore there were no outstanding unvested SAR awards as of December 31, 2008. As such, the Company will not recognize expense in future periods associated with these awards. Valuation Assumptions on Stock Options and Stock Appreciation Rights The fair value of each stock option grant or SAR was estimated on the date of grant using the Black- Scholes option-pricing model, based on the following weighted-average assumptions: Year Ended December 31, 2008 2006 2007 Risk-free interest rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expected life of options, years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expected volatility of the Company’s stock price . . . . . . . . . . . . . . . . . . . . Expected dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . NOTE 18. TRANSACTIONS WITH RELATED PARTIES Employee Loans and Advances 6 2.86% 4.41% 4.70% 6 36.86% 39.49% 48.80% none none none 6 From time to time and continuing in the comparative periods contained in this report, we have made certain retention loans and relocation loans to employees other than executive officers. The retention loans are forgiven over various time periods so long as the employee continues employment at the Company. The relocation loans are repaid upon the employee selling his prior residence. As of December 31, 2008 and 2007, these loans, in the aggregate, totaled approximately $0.2 million and $0.2 million, respectively. Of this 115 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) amount, less than $0.1 million were made to former officers of the Company, with the remainder being made to current employees of the Company. Seller Financing Arrangement Associated with Moncla Acquisition In connection with the acquisition of Moncla (see “Note 2. Acquisitions”), the Company entered into two promissory notes payable agreement with the seller, who, subsequent to the acquisition, became an officer of the Company. The first is an unsecured note in the amount of $12.5 million, which is due and payable in a lump-sum, together with accrued interest, on October 25, 2009. Interest on this note is payable on each anniversary of the closing of the acquisition of Moncla, which was October 25, 2007. The second unsecured note in the amount of $10.0 million is payable in annual installments of $2.0 million, plus accrued interest, beginning October 25, 2008 through 2012. Each of the notes bears interest at the Federal Funds rate adjusted annually on the anniversary of the closing date. The Federal Funds rate does not represent a rate that would have resulted if an independent borrower and an independent lender had negotiated a similar transaction under comparable terms and conditions and is not equal to our incremental borrowing rate. In accordance with APB 21 and SFAS 141, we recorded the promissory notes at fair value which resulted in a discount being recorded. The discount will be recognized as interest expense over the life of the promissory notes using the effective interest method. Transactions with Employees In connection with our acquisition of Western, the former owner of Western, Fred Holmes, became an employee of the Company. Mr. Holmes owned at the time of the acquisition, and continues to own, an exploration and production company, Holmes Western Oil Corporation (“HWOC”), which was a customer of Western. Subsequent to the acquisition, the Company continued to provide services to HWOC. The prices charged for these services are at rates that are an average of the prices charged to our other customers in the California market. As of December 31, 2008, our receivables with HWOC totaled approximately $0.2 million, and for the year ended December 31, 2008, revenues from HWOC totaled approximately $4.3 million. Board of Director Relationship with Customer In October 2007, we added a member to the Company’s Board of Directors who is the Senior Vice President, General Counsel and Chief Administrative Officer of Anadarko Petroleum Corporation (“Ana- darko”), which is one of our customers. Sales to Anadarko comprised less than 2% of our total revenues for the years ended December 31, 2008 and 2007, respectively. Transactions with Anadarko for our services are made at market prices. NOTE 19. SEGMENT INFORMATION For 2008, our reportable operating business segments are well servicing, pressure pumping and fishing and rental. We aggregate services which create our reportable segments in accordance with SFAS 131. The accounting policies of the reportable segments are the same as those described in “Note 1. Organization and Summary of Significant Accounting Policies.” We evaluate the performance of our operating segments based on revenue and EBITDA, which is a non-GAAP measure and not disclosed below. All inter-segment sales pricing is based on current market conditions. Well servicing. These operations provide a full range of well services, including rig-based services, oilfield transportation services, cased-hole wireline services and other ancillary oilfield services necessary to complete, maintain and workover oil and natural gas producing wells. Our Argentina and Mexico operations are included in our well servicing segment. We aggregate our operating divisions engaged in well servicing activities into our well servicing reportable segment. 116 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Pressure pumping. These operations provide well stimulation and cementing services. Stimulation includes fracturing, nitrogen services and acidizing services and is used to enhance the production of oil and natural gas wells from formations which exhibit a restricted flow of oil and / or natural gas. Cementing services include pumping cement into a well between the casing and the wellbore. Fishing and rental. These operations provide services that include “fishing” to recover lost or stuck equipment in a wellbore through the use of “fishing tools.” In addition, this segment offers a full line of services and rental equipment designed for use both onshore and offshore for drilling and workover services and includes an inventory consisting of tubulars, handling tools, pressure-control equipment and power swivels. Corporate / Other. We apply the provisions of EITF 04-10 for our segment reporting. Under the provisions of EITF 04-10, operating segments that do not individually meet the aggregation criteria described in SFAS 131 may be combined with other operating segments that do not individually meet the aggregation criteria to form a separate reportable segment. We have combined all of our operating segments that do not individually meet the aggregation criteria established in SFAS 131 to form the “Corporate and Other” segment for our segment reporting. Corporate expenses include general expenses associated with managing all reportable operating segments. Corporate assets consist principally of cash and cash equivalents, short-term investments, deferred financing costs, investments in subsidiaries, accounts and notes receivable from subsid- iaries, the Company’s investment in IROC Services Corp., and deferred income tax assets. Well Servicing Pressure Pumping Fishing and Rental Corporate/ Other Eliminations Total (In thousands) As of and for the year ended December 31, 2008: Operating revenues . . . . . . Inter-segment revenue . . . . Direct operating expenses . . . . . . . . . . . . Depreciation and $1,509,823 4,153 $344,993 $117,272 1,221 $ — $ — $1,972,088 — (5,374) 942,886 239,870 70,706 — (3,135) 1,250,327 amortization expense . . . 125,008 22,237 11,809 11,720 — 170,774 Interest expense, net of amounts capitalized . . . . Net income (loss) . . . . . . . Property and equipment, net . . . . . . . . . . . . . . . . Total assets . . . . . . . . . . . . Capital expenditures, excluding acquisitions . . (1,880) 347,007 (1,402) 23,834 (512) 3,991 44,793 (289,329) 248 (1,445) 41,247 84,058 762,849 1,688,732 191,563 277,693 62,429 103,521 34,842 2,035,206 — 1,051,683 2,016,923 (2,088,229) 147,963 42,860 19,970 8,201 — 218,994 117 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Well Servicing Pressure Pumping Fishing and Rental Corporate/ Other Eliminations Total (In thousands) As of and for the year ended December 31, 2007: Operating revenues, net . . . . $1,264,797 Direct operating expenses . . 738,694 Depreciation and $299,348 189,645 $97,867 57,275 $ — $ — — $1,662,012 985,614 — amortization expense . . . . 90,274 16,854 8,742 13,753 — 129,623 Interest expense, net of amounts capitalized . . . . . Net income (loss) . . . . . . . . Property and equipment, net . . . . . . . . . . . . . . . . . Total assets . . . . . . . . . . . . . Capital expenditures, excluding acquisitions . . . (712) 360,617 (1,048) 83,785 (493) 22,028 38,708 (297,141) (248) — 36,207 169,289 693,804 1,500,913 133,903 247,018 48,703 89,802 34,798 402,513 — (381,169) 911,208 1,859,077 135,336 51,115 19,811 6,298 — 212,560 Well Servicing Pressure Pumping Fishing and Rental Corporate/ Other Eliminations Total (In thousands) As of and for the year ended December 31, 2006: Operating revenues, net Direct operating expenses . . . Depreciation and . . . . $1,201,228 725,008 $247,489 138,377 $97,460 57,217 $ — $ — $1,546,177 920,602 — — amortization expense . . . . 95,673 12,416 6,787 11,135 (615) 311,339 (600) 88,070 (98) 22,860 40,240 (251,236) — — — 126,011 38,927 171,033 Interest expense, net of amounts capitalized . . . . . Net income (loss) . . . . . . . . . Property and equipment, net . . . . . . . . . . . . . . . . . . Total assets . . . . . . . . . . . . . Capital expenditures, excluding acquisitions . . . . 531,685 1,022,898 97,372 190,704 35,971 79,364 29,263 206,622 — 41,810 694,291 1,541,398 143,080 35,513 12,953 4,284 — 195,830 118 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) The following table presents information related to our foreign operations (in thousands of U.S. Dollars): U.S. Argentina Mexico Canada Eliminations Total (In thousands) As of and for the year ended December 31, 2008: Revenue from external customers . . . . . . . . . . . . . . . . $1,800,199 1,434,578 Long-lived assets. . . . . . . . . . . . . Capital expenditures, excluding acquisitions . . . . . . . . . . . . . . . 181,525 $118,841 25,419 $47,200 45,547 $ 5,848 7,482 $ (55,225) — $1,972,088 1,457,801 2,677 34,792 — — 218,994 As of and for the year ended December 31, 2007: Revenue from external customers . . . . . . . . . . . . . . . . Long-lived assets. . . . . . . . . . . . . Capital expenditures, excluding 1,556,108 1,368,735 $ 93,925 29,762 $ 9,041 11,089 $ 2,938 10,782 $ (49,156) — $1,662,012 1,371,212 acquisitions . . . . . . . . . . . . . . . 197,120 3,997 11,348 95 — 212,560 As of and for the year ended December 31, 2006: Revenue from external customers . . . . . . . . . . . . . . . . $1,467,856 1,064,031 Long-lived assets. . . . . . . . . . . . . Capital expenditures, excluding acquisitions . . . . . . . . . . . . . . . 186,348 $ 78,321 30,623 9,482 $ — $ — $ — $1,546,177 1,052,792 (41,862) — — — — — 195,830 NOTE 20. SUPPLEMENTAL SCHEDULE OF CASH FLOW INFORMATION 2008 Year Ended December 31, 2007 (In thousands) 2006 Noncash investing and financing activities: Property and equipment acquired under captial lease obligations . . . Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unrealized (loss) gain on short-term investments . . . . . . . . . . . . . . Unrealized gain on cash flow hedges . . . . . . . . . . . . . . . . . . . . . . . Accrued repurchases of common stock . . . . . . . . . . . . . . . . . . . . . . Debt assumed and issued in acquisitions. . . . . . . . . . . . . . . . . . . . . Software acquired under financing arrangement . . . . . . . . . . . . . . . Supplemental cash flow information: Cash paid for interest. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash paid for taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $12,003 $ 7,654 12 397 — (8) — — — 2,949 — 40,149 — 3,985 $15,349 155 328 185 — — — $45,313 $43,494 $38,457 $96,327 $44,534 $99,048 Cash paid for interest includes cash payments for interest on our long-term debt and capital lease obligations, commitment and agency fees paid, and cash paid to settle the interest rate swaps associated with the termination of our Prior Credit Facility. 119 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) NOTE 21. UNAUDITED SUPPLEMENTARY INFORMATION — QUARTERLY RESULTS OF OPERATIONS Set forth below is unaudited summarized quarterly information for the two most recent years covered by these consolidated financial statements (in thousands, except for per share data): Year Ended December 31, 2008: Revenues . . . . . . . . . . . . . . . . . . . Direct operating expenses . . . . . . . Impairment of goodwill and equity method investment . . . . . . . . . . Income (loss) before income taxes. . . . . . . . . . . . . . . . . . . . . Net income (loss) . . . . . . . . . . . . . Earnings per share(1): First Quarter Second Quarter Third Quarter Fourth Quarter $456,399 281,641 $502,003 322,488 $535,620 342,195 $478,066 304,003 — — — 75,137 56,907 34,484 71,247 44,012 77,541 48,462 (31,639) (42,900) Basic . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . $ $ 0.27 0.27 $ $ 0.35 0.35 $ $ 0.39 0.39 $ $ (0.35) (0.35) First Quarter Second Quarter Third Quarter Fourth Quarter(2) Year Ended December 31, 2007: Revenues . . . . . . . . . . . . . . . . . Direct operating expenses . . . . . Income before income taxes . . . Net income . . . . . . . . . . . . . . . . Earnings per share(1): $408,919 235,513 84,694 52,190 Basic. . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . $ $ 0.40 0.39 $410,511 238,223 78,471 48,136 $ $ 0.37 0.36 $413,967 257,482 59,832 35,896 $ $ 0.27 0.27 $428,615 254,396 52,943 33,067 $ $ 0.25 0.25 (1) Quarterly earnings per common share are based on the weighted average number of shares outstanding during the quarter, and the sum of the quarters may not equal annual earnings per common share. (2) Revenues, gross margins, income before income taxes, net income and earnings per share were impacted in the fourth quarter of 2007 due to the acquisitions of Moncla, Kings and AMI. See “Note 2. Acquisitions.” NOTE 22. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS The Notes are guaranteed by virtually all of our domestic subsidiaries, all of which are wholly-owned. The guarantees were joint and several, full, complete and unconditional. There were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company. As a result of these guarantee arrangements, we are required to present the following condensed consolidating financial information pursuant to SEC Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered.” 120 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) CONDENSED CONSOLIDATING BALANCE SHEET Parent Company Guarantor Subsidiaries December 31, 2008 Non-Guarantor Subsidiaries (In thousands) Eliminations Consolidated Assets: Current assets . . . . . . . . . . . . . . . $ Property and equipment, net . . . . Goodwill . . . . . . . . . . . . . . . . . . Deferred financing costs, net . . . . Intercompany notes and accounts receivable and investment in subsidiaries . . . . . . . . . . . . . . . Other assets . . . . . . . . . . . . . . . . 29,673 $ 440,758 — 1,025,007 316,669 — — 10,489 $ 88,534 26,676 4,323 — $ 157 $ 559,122 — 1,051,683 320,992 — 10,489 — 1,917,522 22,597 419,554 48,237 1,775 3,803 (2,338,851) — — 74,637 TOTAL ASSETS. . . . . . . . . . . . . . $1,980,281 $2,250,225 $125,111 $(2,338,694) $2,016,923 Liabilities and equity: Current liabilities . . . . . . . . . . . . $ Capital lease obligations, less current portion . . . . . . . . . . . . Notes payable — related parties, less current portion . . . . . . . . . Long-term debt, less current portion . . . . . . . . . . . . . . . . . . Intercompany notes and accounts payable . . . . . . . . . . . . . . . . . . Deferred tax liabilities. . . . . . . . . Other long-term liabilities . . . . . . Stockholders’ equity . . . . . . . . . . TOTAL LIABILITIES AND 13,792 $ 231,528 $ 28,054 $ (1) $ 273,373 — — 612,813 305,348 187,596 — 860,732 13,714 6,000 1,015 1,624,932 — 60,386 312,650 49 — — — — — 69,204 985 260 26,559 (1,999,484) — — (339,209) 13,763 6,000 613,828 — 188,581 60,646 860,732 STOCKHOLDERS’ EQUITY . . $1,980,281 $2,250,225 $125,111 $(2,338,694) $2,016,923 121 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Parent Company Guarantor Subsidiaries December 31, 2007 Non-Guarantor Subsidiaries (In thousands) Eliminations Consolidated 39,501 — — 12,117 $ 378,865 880,907 373,283 — $ 69,499 30,301 5,267 — $ — $ 487,865 911,208 — 378,550 — 12,117 — Assets: Current assets . . . . . . . . . . . . . . . . $ Property and equipment, net . . . . . . Goodwill . . . . . . . . . . . . . . . . . . . . Deferred financing costs, net . . . . . . Intercompany notes and accounts receivable and investment in subsidiaries . . . . . . . . . . . . . . . . . Other assets . . . . . . . . . . . . . . . . . . Liabilities and equity: Current liabilities . . . . . . . . . . . . . . $ Capital lease obligations, less current portion . . . . . . . . . . . . . . Notes payable — related parties, less current portion . . . . . . . . . . . Long-term debt, less current TOTAL ASSETS. . . . . . . . . . . . . . $1,620,828 $1,860,590 $111,113 $(1,733,454) $1,859,077 1,557,993 11,217 175,461 52,074 — 6,046 (1,733,454) — — 69,337 17,278 $ 192,222 $ 25,297 $ — $ 234,797 — — 15,998 20,500 116 — — 24,408 2,388 251 58,653 — — — (1,592,445) — — (141,009) 16,114 20,500 475,000 — 160,068 63,600 888,998 portion . . . . . . . . . . . . . . . . . . . . 475,000 — Intercompany notes and accounts payable. . . . . . . . . . . . . . . . . . . . Deferred tax liabilities . . . . . . . . . . Other long-term liabilities . . . . . . . . Stockholders’ equity . . . . . . . . . . TOTAL LIABILITIES AND 78,660 157,759 3,133 888,998 1,489,377 (79) 60,216 82,356 STOCKHOLDERS’ EQUITY . . $1,620,828 $1,860,590 $111,113 $(1,733,454) $1,859,077 122 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS Revenues . . . . . . . . . . . . . . . . . . . . . $ Costs and expenses: . . . . . . . . . . . . . Direct operating expenses . . . . . . . . Depreciation and amortization expense . . . . . . . . . . . . . . . . . . . Impairment of goodwill and equity- method investment . . . . . . . . . . . General and administrative Parent Company Guarantor Subsidiaries — $1,818,736 Year Ended December 31, 2008 Non-Guarantor Subsidiaries (In thousands) $175,845 Eliminations $(22,493) Consolidated $1,972,088 — — — 1,139,006 127,374 (16,053) 1,250,327 163,257 7,517 75,137 — — — 170,774 75,137 expenses . . . . . . . . . . . . . . . . . . 1,616 237,635 19,251 (795) 257,707 Interest expense, net of amounts capitalized . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other, net Total costs and expenses, net . . . . . . (Loss) income before income taxes and minority interest . . . . . . . . . . . Income tax expense . . . . . . . . . . . . . . Minority interest . . . . . . . . . . . . . . . . 44,842 5,219 51,677 (51,677) (81,233) — (4,320) (7,073) 477 9,143 248 (4,449) 41,247 2,840 1,603,642 163,762 (21,049) 1,798,032 215,094 (4,320) — 12,083 (4,690) 245 (1,444) — — 174,056 (90,243) 245 NET (LOSS) INCOME . . . . . . . . . . $(132,910) $ 210,774 $ 7,638 $ (1,444) $ 84,058 123 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Parent Company Guarantor Subsidiaries — $1,561,059 Year Ended December 31, 2007 Non-Guarantor Subsidiaries (In thousands) $105,819 Eliminations $(4,866) — 906,254 82,980 (3,620) Revenues . . . . . . . . . . . . . . . . . . . . . $ Costs and expenses: . . . . . . . . . . . . . Direct operating expenses . . . . . . . . . Depreciation and amortization expense . . . . . . . . . . . . . . . . . . . . . General and administrative expenses. . Interest expense, net of amounts — 1,693 123,821 216,959 capitalized . . . . . . . . . . . . . . . . . . . 38,866 (3,134) Loss on early extinguishment of debt . . . . . . . . . . . . . . . . . . . . . . . . Other, net . . . . . . . . . . . . . . . . . . . . . 9,557 (449) — (5,850) 5,802 11,935 723 — 1,781 — (191) (248) — (807) Consolidated $1,662,012 — 985,614 129,623 230,396 36,207 9,557 (5,325) Total costs and expenses, net . . . . . . 49,667 1,238,050 103,221 (4,866) 1,386,072 (Loss) income before income taxes and minority interest . . . . . . . . . . . Income tax expense . . . . . . . . . . . . . . Minority interest . . . . . . . . . . . . . . . . (49,667) (105,928) — 323,009 934 — 2,598 (1,774) 117 — — — 275,940 (106,768) 117 NET (LOSS) INCOME . . . . . . . . . . $(155,595) $ 323,943 $ 941 $ — $ 169,289 124 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS Parent Company Guarantor Subsidiaries Year Ended December 31, 2008 Non-Guarantor Subsidiaries (In thousands) Eliminations Consolidated Net cash provided by operating activities. . . . . . . . . . . . . . . . . . . . . Cash flows from investing activities: Capital expenditures . . . . . . . . . . . . Acquisitions, net of cash acquired . . Acquisition of fixed assets from asset purchases . . . . . . . . . . . . . . Investment in Geostream Services Group . . . . . . . . . . . . . . . . . . . . . Intercompany notes and accounts . . . Other investing activities, net . . . . . . Net cash (used in) provided by $ 17,573 $ 364,840 $(15,249) $ — $ 367,164 — — — (214,659) (63,457) (4,335) — (34,468) — — — — (19,306) (179,501) — — (199,428) 7,151 — (1,515) — — 380,444 — (218,994) (63,457) (34,468) (19,306) — 7,151 investing activities . . . . . . . . . . . . . (198,807) (504,861) (5,850) 380,444 (329,074) Cash flows from financing activities: Borrowings on revolving credit facility . . . . . . . . . . . . . . . . . . . . . . 172,813 — — — 172,813 Repayments on revolving credit facility . . . . . . . . . . . . . . . . . . . . . . Repurchases of common stock. . . . . . . Intercompany notes and accounts. . . . . Other financing activities, net . . . . . . . Net cash provided by (used in) (38,026) (139,358) 177,698 8,107 — — 181,016 (11,506) — — 21,730 — — — (380,444) — (38,026) (139,358) — (3,399) financing activities . . . . . . . . . . . . . 181,234 169,510 21,730 (380,444) (7,970) Effect of changes in exchange rates on cash. . . . . . . . . . . . . . . . . . . . . . Net increase in cash . . . . . . . . . . . . . Cash and cash equivalents at beginning of period . . . . . . . . . . . . Cash and cash equivalents at end of — — — — 29,489 4,068 4,699 46,358 12,145 — — — 4,068 34,188 58,503 period . . . . . . . . . . . . . . . . . . . . . . $ — $ 75,847 $ 16,844 $ — $ 92,691 125 Key Energy Services, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Parent Company Guarantor Subsidiaries Year Ended December 31, 2007 Non-Guarantor Subsidiaries (In thousands) Eliminations Consolidated Net cash (used in) provided by operating activities . . . . . . . . . . . . . Cash flows from investing activities: Capital expenditures . . . . . . . . . . . . Acquisitions, net of cash acquired . . Investment in available for sale securities . . . . . . . . . . . . . . . . . . . Proceeds from the sale of available of sale securities . . . . . . . . . . . . . Intercompany notes and accounts . . . Other investing activities, net . . . . . . Net cash (used in) provided by $ (3,401) $ 264,275 $(10,955) $ — $ 249,919 — — — — (473,412) — (207,400) (157,955) (121,613) 183,177 (434,672) 6,104 (5,160) — — — — — — — — — 908,084 — (212,560) (157,955) (121,613) 183,177 — 6,104 investing activities . . . . . . . . . . . . . (473,412) (732,359) (5,160) 908,084 (302,847) Cash flows from financing activities: Repayment of long-term debt. . . . . . Proceeds from long-term debt . . . . . Borrowings on revolving credit (396,000) 425,000 facility . . . . . . . . . . . . . . . . . . . . 50,000 — — — — — — — — — Common stock acquired by purchase . . . . . . . . . . . . . . . . . . . Intercompany notes and accounts . . . . . . . . Other financing activities, net Net cash provided by (used in) (30,454) 424,822 3,445 — 458,560 (28,751) — 24,702 — — (908,084) — (396,000) 425,000 50,000 (30,454) — (25,306) financing activities . . . . . . . . . . . . . 476,813 429,809 24,702 (908,084) 23,240 Effect of changes in exchange rates on cash. . . . . . . . . . . . . . . . . . . . . . Net (decrease) increase in cash . . . . . Cash and cash equivalents at beginning of period . . . . . . . . . . . . Cash and cash equivalents at end of — — — — (38,275) (184) 8,403 84,633 3,742 — — — (184) (29,872) 88,375 period . . . . . . . . . . . . . . . . . . . . . . $ — $ 46,358 $ 12,145 $ — $ 58,503 126 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES Disclosure Controls and Procedures We maintain a set of disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 (the “Exchange Act”) is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to the Company’s management, including the Company’s principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, with the participation of the Company’s principal executive officer and principal financial officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on such evaluation, the Company’s principal executive and financial officers have concluded that, because of the material weakness described below for our payroll process, our disclosure controls and procedures were ineffective as of the end of such period. Management’s Report on Internal Control Over Financial Reporting Management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) 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. Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting can also be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk. A material weakness (as defined in SEC Rule 12b-2) is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. Management conducted an assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. In making this assessment, management used the criteria 127 described in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management concluded that the Company’s internal control over financial reporting was not effective as of December 31, 2008 due to a material weakness described below. Payroll process. We determined that ineffective control activities surrounding our payroll process constituted a material weakness in our system of internal control as of December 31, 2008. In particular, these control activities pertained to documentation and approvals of employee master file data, proper evidence concerning approval of hours worked or rate changes and deficiencies with reconciliations where payroll data was a major component. The actions taken and the controls that were in place and operating during 2008 with respect to this material weakness, which was identified in previous years, were not sufficient to effectively remediate this material weakness as of December 31, 2008. In 2008, we continued our process to improve our data quality and controls surrounding our payroll process that began in 2007. During the middle of 2008, we began to relocate the payroll function from a shared services location in Midland, Texas to our corporate offices in Houston, Texas. During this transition, the payroll department lost a significant percentage of its staff which required their replacement with new personnel. We also increased the overall size of the payroll department upon its relocation to Houston. With this change, we also added new payroll practices and procedures. Additionally, throughout 2008, we worked on the replacement of our existing payroll system with a new human resource information system, which included a payroll system, that was initiated in late 2007. However, due to the nature and functionality of the payroll system that was in place during 2008, our conversion to a new system was delayed until January 2009. The implementation of a new human resource information system allows for automated workflow and approval of information, including, among other things, employee master file data, hours worked and rate changes. We believe that as the new payroll department employees receive the proper training and with the implementation of the new human resource and payroll system that was completed in January 2009, we will further strengthen our control structure, increase our efficiency in processing payroll and provide transparency of payroll related data, allowing for the remediation of this material weakness. Our internal control over financial reporting has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report included herein. Remediation of Material Weaknesses in Internal Control Over Financial Reporting In October 2006, we filed our 2003 Financial and Informational Report on Form 8-K/A with the SEC, which described numerous material weaknesses in internal control over financial reporting that we identified during our restatement and delayed financial reporting process. In the third quarter of 2007, we filed our Annual Report on Form 10-K for the year ended December 31, 2006 and reported that nine of the material weaknesses that we had previously identified remained as of December 31, 2006. Our Annual Report on Form 10-K for the year ended December 31, 2007, filed in February 2008, reported that some of these material weaknesses had been remediated and that seven existed at December 31, 2007. Beginning in the fourth quarter of 2007 and continuing in 2008, the Company implemented numerous remediation efforts to address the material weaknesses in existence at December 31, 2007 as described in “Item 9A. Controls and Procedures” in the 2007 Report. As a result of these efforts, the Company’s management determined that as of December 31, 2008, six of the seven material weaknesses identified in the 2007 Report had been remediated, but as discussed above, the material weakness relating to the controls surrounding the payroll process had not been remediated. While many of the changes in internal control over financial reporting were made during the fourth quarter of 2007, they were not in place and operating long enough during 2007 to be assessed as effective. In addition, we made changes in internal control over financial reporting during 2008 to further address the material weaknesses identified in the 2007 Report. The material weaknesses identified in the 2007 Report that have been remediated are: Financial Close and Reporting. Management instituted substantial changes in the fourth quarter of 2007 to our internal control structure related to our financial reporting and close process. These changes included additional personnel, additional analytical procedures and reviews, revised methodologies for the preparation 128 of our financial statements, more reconciliations of our accounts and additional reconciliations between our general ledger and subledger systems as well as increased evidence validating those controls. Based upon these changes in internal control and the testing and evaluation of the effectiveness of these controls, the Company’s management has concluded that remediation of the material weakness for financial close and reporting had been achieved as of December 31, 2008. Authorizations of Expenditures. During 2007, changes concerning authorization of expenditures were made that included the establishment of approval authorities, automated controls in our procurement system and analytical procedures around expenditures. Additionally, in 2008, we implemented an application that allows for automated and paperless invoicing and an automated workflow for approvals of expenditures. Based upon these changes in internal control and the testing and evaluation of the effectiveness of these controls, the Company’s management has concluded that remediation of the material weakness for authorizations of expenditures had been achieved as of December 31, 2008. Recording of Revenues. During 2007, we added controls surrounding our recognition of revenues, such as analytical reviews of accrued revenues, analysis of aged receivables and account reconciliations between our revenue systems and general ledger. Based upon these changes in internal control and the testing and evaluation of the effectiveness of these controls, the Company’s management has concluded that remediation of the material weakness for recording of revenues had been achieved as of December 31, 2008. Property, Plant & Equipment (PP&E). In 2007, changes related to accounting for PP&E were made that included the preparation of roll forwards, reconciliations of balances and analytical reviews of balances and depreciation expense. Additionally, in 2008, we implemented analytical procedures and reviews to evaluate the status of assets recorded as work-in-progress to ensure that depreciation expense for assets transferred out of work-in-progress was correct in all material respects as well as to ensure that gains and losses associated with disposals are reflected in the appropriate periods. Based upon these changes in internal control and the testing and evaluation of the effectiveness of these controls, the Company’s management has concluded that remediation of the material weakness for PP&E had been achieved as of December 31, 2008. User Developed Applications. In 2008, we implemented a formal financial spreadsheet controls policy to govern the development, use and control of critical financial spreadsheets, which the users of these applications are following. Based upon this change in internal control and the testing and evaluation of the effectiveness of these controls within the financial spreadsheet controls policy, the Company’s management has concluded that remediation of the material weakness for user developed applications had been achieved as of December 31, 2008. Application Access and Segregation of Duties. In 2007, to address application access and segregation of duties, we implemented management reports for business owner review as well as administrative controls and procedures. In 2008, we made improvements to our business owner review of application access and segregation of duties to allow for a more thorough review of access rights and duties. Based upon these changes in internal control and the testing and evaluation of the effectiveness of these controls, the Company’s management has concluded that remediation of the material weakness for application access and segregation of duties had been achieved as of December 31, 2008. Changes in Internal Control Over Financial Reporting There were no changes in our internal control over financial reporting during our last fiscal quarter of 2008, other than those described above, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. ITEM 9B. OTHER INFORMATION Not applicable. 129 PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE Item 10 is incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2008. ITEM 11. EXECUTIVE COMPENSATION Item 11 is incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2008. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS Item 12 is incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2008. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE Item 13 is incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2008. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES Item 14 is incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2008. PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES The following financial statements, schedules and exhibits are filed as part of this report: 1. Financial Statements — See “Index to Consolidated Financial Statements” at Page 64. 2. Financial Statement Schedules filed in Part IV of this report are listed below: (cid:129) Schedule II — Valuation and other Qualifying Accounts We have omitted all other financial statement schedules because they are not required or are not applicable, or the required information is shown in the financial statements in notes to the financial statements. 3. Exhibits Exhibit No. Description 3.1 3.2 Articles of Restatement of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006, File No. 001-08038.) Unanimous consent of the Board of Directors of Key Energy Services, Inc., dated January 11, 2000, limiting the designation of the additional authorized shares to common stock. (Incorporated by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 001-08038.) 130 Exhibit No. Description 3.3 3.4 3.5 4.1 4.2 4.3 4.4 4.5 4.6* 10.1† 10.2† 10.3† 10.4† 10.5† 10.6† Second Amended and Restated By-laws of Key Energy Services, Inc., adopted September 21, 2006. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed on September 22, 2006, File No. 001-08038.) Amendment to Second Amended and Restated By-laws of Key Energy Services, Inc., adopted November 2, 2007. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed on November 2, 2007, File No. 001-08038.) Amendments to Second Amended and Restated By-laws of Key Energy Services, Inc., adopted April 4, 2008. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed on April 9, 2008, File No. 001-08038.) Warrant Agreement, dated as of January 22, 1999, between Key Energy Services, Inc. and the Bank of New York, a New York banking corporation as warrant agent. (Incorporated by reference to Exhibit 99(b) of the Company’s Current Report on Form 8-K filed on February 3, 1999, File No. 001-08038.) Warrant Registration Rights Agreement dated January 22, 1999, by and among Key Energy Services, Inc., the Guarantors named therein, Lehman Brothers Inc., Bear, Stearns & Co., Inc., F.A.C. / Equities, a division of First Albany Corporation, and Dain Rauscher Wessels, a division of Dain Rauscher Incorporated. (Incorporated by reference to Exhibit 99(e) of the Company’s Current Report on Form 8-K filed on February 3, 1999, File No. 001-08038.) Indenture, dated as of November 29, 2007, among Key Energy Services, Inc., the guarantors party thereto and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on November 30, 2007, File No. 001-08038.) Registration Rights Agreement dated as of November 29, 2007, among Key Energy Services, Inc., the subsidiary guarantors of the Company party thereto, and Lehman Brothers Inc., Banc of America Securities LLC and Morgan Stanley & Co. Incorporated, as representatives of the several initial purchasers named therein. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on November 30, 2007, File No. 001-08038.) First Supplemental Indenture, dated as of January 22, 2008, among Key Marine Services, LLC, the existing Guarantors and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.5 of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 001-08038.) Second Supplemental Indenture, dated as of January 13, 2009, among Key Energy Mexico, LLC, the existing Guarantors and The Bank of New York Trust Company, N.A., as trustee. Key Energy Group, Inc. 1997 Incentive Plan, as an amendment and restatement effective November 17, 1997 of the Key Energy Group, Inc. 1995 Outside Directors Stock Option Plan. (Incorporated by reference to Exhibit B of the Company’s Schedule 14A Proxy Statement filed November 26, 1997, File No. 001-08038.) Form of Restricted Stock Award Agreement under Key Energy Group, Inc. 1997 Incentive Plan. (Incorporated by reference to Exhibit 10.15 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 001-08038.) The 2006 Phantom Share Plan of Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 001-08038.) Form of Award Agreement under the 2006 Phantom Share Plan of Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 001-08038.) Form of Stock Appreciation Rights Agreement under Key Energy Group, Inc. 1997 Incentive Plan. (Incorporated by reference to Exhibit 99.1 of the Company’s Current Report on Form 8-K filed on August 24, 2007, File No. 001-08038.) Form of Non-Plan Option Agreement under Key Energy Group, Inc. 1997 Incentive Plan. (Incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-8 filed on September 25, 2007, File No. 333-146294.) 131 Exhibit No. 10.7† 10.8† 10.9† 10.10† 10.11† 10.12† 10.13† Description Key Energy Services, Inc. 2007 Equity and Cash Incentive Plan. (Incorporated by Reference to Appendix A of the Company’s Schedule 14A Proxy Statement filed on November 1, 2007, File No. 001-08038.) Form of Nonstatutory Stock Option Agreement under 2007 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.8 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 filed on February 28, 2008, File No. 001-08038.) Restated Employment Agreement, dated effective as of December 31, 2007, among Richard J. Alario, Key Energy Services, Inc. and Key Energy Shared Services, LLC. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on January 7, 2008, File No. 001-08038.) Acknowledgment and Waiver by Richard J. Alario, dated March 25, 2005, regarding rescinded option grant. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated March 29, 2005, File No. 001-08038.) Restated Employment Agreement, dated effective as of December 31, 2007, among William M. Austin, Key Energy Services, Inc. and Key Energy Shared Services, LLC. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on January 7, 2008, File No. 001-08038.) Restated Employment Agreement, dated effective as of December 31, 2007, among Newton W. Wilson III, Key Energy Services, Inc. and Key Energy Shared Services, LLC. (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed on January 7, 2008, File No. 001-08038.) Acknowledgment and Waiver by Newton W. Wilson III, dated March 25, 2005, regarding rescinded option grant. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K dated March 29, 2005, File No. 001-08038.) 10.14†* Amended and Restated Employment Agreement, dated October 22, 2008, between Kimberly R. 10.15† 10.16† 10.17† 10.18† 10.19† 10.20† 10.21† 10.22† Frye, Key Energy Services, Inc. and Key Energy Shared Services, LLC. Restated Employment Agreement dated effective as of December 31, 2007, among Kim B. Clarke, Key Energy Services, Inc. and Key Energy Shared Services, LLC (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K filed on January 7, 2008, File No. 001-08038.) Employment Agreement, dated as of January 1, 2004, between Key Energy Services, Inc. and Jim D. Flynt. (Incorporated by reference to Exhibit 10.6 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 001-08038.) First Amendment to Employment Agreement, dated November 26, 2007, between Key Energy Services, Inc. and Jim D. Flynt. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on November 30, 2007, File No. 001-08038.) Employment Agreement, dated November 17, 2004, between Key Energy Services, Inc. and Phil Coyne. (Incorporated by reference to Exhibit 10.8 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 001-08038.) First Amendment to Employment Agreement, effective as of January 24, 2005, between Key Energy Services, Inc. and Phil Coyne. (Incorporated by reference to Exhibit 10.9 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 001-08038.) Amended and Restated Employment Agreement, dated December 31, 2007, between Key Energy Services, Inc. and Don D. Weinheimer. (Incorporated by reference to Exhibit 10.19 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 filed on February 28, 2008, File No. 001-08038.) Employment Agreement, dated August 14, 2007, between Key Energy Shared Services, LLC and J. Marshall Dodson. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007, File No. 001-08038.) Employment Agreement, dated August 14, 2007, between Key Energy Shared Services, LLC and D. Bryan Norwood. (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007, File No. 001-08038.) 132 Exhibit No. 10.23†* 10.24†* 10.25 10.26 10.27 10.28 10.29 10.30 10.31* 10.32 10.33 10.34 10.35 10.36 Description Restated Employment Agreement, effective August 1, 2007, between Key Energy Shared Services, LLC and Tommy Pipes. Employment Agreement, effective August 1, 2007, between Key Energy Services, Inc. and John Carnett. Office Lease, effective as of January 20, 2005, between Crescent 1301 McKinney, L.P. and Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated January 26, 2005, File No. 001-08038.) First Amendment to Office Lease, dated as of March 15, 2005, between Crescent 1301 McKinney, L.P. and Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated June 30, 2005, File No. 001-08038.) Second Amendment to Office Lease, dated as of July 24, 2005, between Crescent 1301 McKinney, L.P. and Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K dated June 30, 2005, File No. 001-08038.) Credit Agreement, dated as of November 29, 2007, among Key Energy Services, Inc., each lender from time to time party thereto, Bank of America, N.A., as Paying Agent, Co-Administrative Agent, Swing Line Lender and L/C Issuer, and Wells Fargo Bank, National Association, as Co- Administrative Agent, Swing Line Lender and L/C Issuer. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on November 30, 2007, File No. 001-08038.) Stock and Membership Interest Purchase Agreement, dated as of September 19, 2007, between and among Key Energy Services, LLC, the Sellers named therein, and Moncla Well Service, Inc. and certain other affiliated companies named therein. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on September 20, 2007, File No. 001-08038.) First Amendment to Stock and Membership Interest Purchase Agreement, dated as of October 25, 2007, among Key Energy Services, LLC, the Sellers named therein, and Moncla Well Service, Inc. and certain other affiliated companies named therein. (Incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007, File No. 001-08038.) Second Amendment to Stock and Membership Interest Purchase Agreement, dated as of September 30, 2008, among Key Energy Services, LLC, the Sellers named therein, and Moncla Well Service, Inc. and certain other affiliated companies named therein. Purchase Agreement, dated November 14, 2007, by and among the Company, certain of its domestic subsidiaries, and Lehman Brothers, Inc., Banc of America Securities LLC and Morgan Stanley & Co. Incorporated, as representatives of the initial purchasers. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on November 15, 2007, File No. 001-08038.) Asset Purchase Agreement, dated December 7, 2007, among Key Energy Services, LLC, Kings Oil Tools, Inc. and Thomas Fowler. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on December 13, 2007, File No. 001-08038.) Purchase Agreement, dated April 3, 2008, among Key Energy Services, LLC, Western Drilling Holdings, Inc., and Fred S. Holmes and Barbara J. Holmes. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April 9, 2008, File No. 001-08038.) Stock Purchase Agreement, dated May 30, 2008, by and among Key Energy Services, LLC, and E. Kent Tolman, Nita Tolman, Ronald D. Jones and Melinda Jones. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on June 5, 2008, File No. 001-08038.) Asset Purchase Agreement, dated July 22, 2008, by and among Key Energy Pressure Pumping Services, LLC, Leader Energy Services Ltd., Leader Energy Services USA Ltd., and CementRite, Inc. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on July 24, 2008, File No. 001-08038.) 133 Exhibit No. 10.37 21* 23* 31.1* 31.2* 32* Description Master Agreement, dated August 26, 2008, by and among Key Energy Services, Inc., Key Energy Services Cyprus Ltd., OOO Geostream Assets Management and L-Group. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on September 2, 2008, File No. 001-08038.) Significant Subsidiaries of the Company. Consent of Independent Registered Public Accounting Firm. Certification of CEO pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. of 2002. Certification of Principal Financial Officer pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Certification of CEO and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. † Indicates a management contract or compensatory plan, contract or arrangement in which any Director or any Executive Officer participates. * Filed herewith. 134 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SIGNATURES KEY ENERGY SERVICES, INC. By: /s/ J. MARSHALL DODSON J. Marshall Dodson, Vice President and Chief Accounting Officer (Principal Financial Officer) Date: February 27, 2009 POWER OF ATTORNEY Each person whose signature appears below hereby constitutes and appoints Richard J. Alario and J. Marshall Dodson, and each of them, his true and lawful attorney-in-fact and agent, with full powers of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission granting to said attorneys- in-fact, and each of them, full power and authority to perform any other act on behalf of the undersigned required to be done in connection therewith. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated. Signature Title Date /s/ Richard J. Alario Richard J. Alario /s/ J. Marshall Dodson J. Marshall Dodson /s/ David J. Breazzano David J. Breazzano /s/ Lynn R. Coleman Lynn R. Coleman /s/ Kevin P. Collins Kevin P. Collins /s/ William D. Fertig William D. Fertig /s/ W. Phillip Marcum W. Phillip Marcum Chairman of the Board of Directors, President and Chief Executive Officer (Principal Executive Officer) February 27, 2009 Vice President and Chief Accounting Officer (Principal Financial Officer) February 27, 2009 Director February 27, 2009 Director February 27, 2009 Director February 27, 2009 Director February 27, 2009 Director February 27, 2009 Signature /s/ Ralph S. Michael, Ralph S. Michael, III /s/ William F. Owens William F. Owens /s/ Arlene M. Yocum Arlene M. Yocum /s/ Robert K. Reeves Robert K. Reeves /s/ J. Robinson West J. Robinson West Title Director Date February 27, 2009 Director February 27, 2009 Director February 27, 2009 Director February 27, 2009 Director February 27, 2009 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors and Shareholders of Key Energy Services, Inc. We have audited in accordance with the standards of the Public Company Accounting Oversight Board (United States) the consolidated financial statements of Key Energy Services, Inc. and Subsidiaries referred to in our report dated February 24, 2009, which is included in the annual report to security holders and incorporated by reference in Part II of this form. Our report on the consolidated financial statements includes explanatory paragraphs, which discuss the adoption of Financial Accounting Standards Interpretation No. 48, Accounting for Uncertainty in Income Taxes, and FSP EITF 00-19-2, Accounting for Registration Payment Arrangements. Our audits of the basic financial statements included the financial statement schedule listed in the index appearing under Item 15, which is the responsibility of the Company’s management. In our opinion, this financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. /s/ GRANT THORNTON LLP Houston, Texas February 24, 2009 S-1 Key Energy Services, Inc. and Subsidiaries Schedule II — Valuation and Qualifying Accounts Balance at Beginning of Period Charged to Expense Additions Charged to Other Accounts Acquisitions Deductions Balance at End of Period (In thousands) Allowance for doubtful accounts: As of December 31, 2008 . . . . . As of December 31, 2007 . . . . . As of December 31, 2006 . . . . . $13,501 12,998 10,843 $ 37 3,675 1,854 $ (38) — 301 $ 15 1,251 — $(2,047) (4,423) — $11,468 13,501 12,998 S-2 Information below as of April 1, 2009 MANAGEMENT DIRECTORS Richard J. Alario Chairman, President and Chief Executive Offi cer Newton W. “Trey” Wilson III Executive Vice President and Chief Operating Offi cer T.M. “Trey” Whichard III Senior Vice President and Chief Financial Offi cer Kim B. Clarke Senior Vice President, Administration and Chief People Offi cer Don D. Weinheimer Senior Vice President of Product Development, Strategic Planning and Quality David J. Breazzano President and Founding Principal DDJ Capital Management, LLC Lynn R. Coleman Retired Partner Skadden, Arps, Slate, Meagher and Flom LLP Kevin P. Collins Managing Member The Old Hill Company LLC William D. Fertig Co-Chair and Chief Investment Offi cer Context Capital Management LLC W. Phillip Marcum Principal MG Advisors, LLC Kimberly R. Frye Senior Vice President, General Counsel and Secretary Ralph S. Michael, III Former President and Chief Operating Offi cer The Ohio Casualty Insurance Company Phil G. Coyne Senior Vice President Wireline Services John R. Carnett Senior Vice President Pressure Pumping Operations Thomas R. Pipes Senior Vice President Well Service Rig Operations Dennis C. Douglas Senior Vice President U.S. Marketplace Management J. Marshall Dodson Vice President and Chief Accounting Offi cer D. Bryan Norwood Vice President and Treasurer William F. Owens Former Governor of Colorado Principal JF Companies LLC Robert K. Reeves Senior Vice President, General Counsel and Chief Administrative Offi cer Anadarko Petroleum Corporation J. Robinson West Founder and Chairman PFC Energy Arlene M. Yocum Executive Vice President and Managing Executive PNC Wealth Management and Institutional Investment Groups Annual Meeting The Company’s Annual Meeting of Stockholders will be held at 9:00 a.m. on June 4, 2009, at: Inn at the Ballpark 1520 Texas Avenue Houston, TX 77002 Financial Information and News Releases Information updates about us, including quarterly fi nancial results and current news releases, are available to the public on our Web site at keyenergy.com or upon request from our Investor Relations Department. Stock Transfer Agent and Registrar American Stock Transfer & Trust Company 59 Maiden Lane Plaza Level New York, NY 10038 (800) 937-5449 www.amstock.com Corporate Governance Certifi cation Key Energy Services has fi led the certifi cation of its Chief Executive Offi cer and Chief Financial Offi cer and each have signed and fi led the required certifi cations under Section 302 of the Sarbanes-Oxley Act of 2002 with its Annual Report on Form 10-K. Independent Auditors Grant Thornton LLP Houston, Texas Stock Listing New York Stock Exchange Symbol: KEG Form 10-K A copy of the Company’s Annual Report to the Securities and Exchange Commission (Form 10-K) is available by writing to: Investor Relations Key Energy Services, Inc. 1301 McKinney Street, Suite 1800 Houston, TX 77010 Key Energy Services 1301 McKinney Street Suite 1800 Houston, Texas 77010 713-651-4300 keyenergy.com 3.09.KES1881 © 2009 Key Energy Services 

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