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KEY ENERGY SERVICES, INC. ANNUAL REPORT ON FORM 10-K For the Year Ended December 31, 2007
ITEM 8. Consolidated Financial Statements and Supplementary Data

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)  

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

For the fiscal year ended December 31, 2007

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

Commission file number 1-8038

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 o    No ý

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

         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 ý    No o

         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 statement incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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

Large accelerated filer ý   Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a smaller reporting company)    

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

         As of June 30, 2007, the aggregate market value of the common stock of the Registrant held by non-affiliates of the Registrant, based on the $18.53 per share price for the Registrant's common stock as quoted by the National Quotation Bureau's Pink Sheets on June 29, 2007 was $2,145,411,905 (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 20, 2008, the number of outstanding shares of common stock of the Registrant was 128,149,793.

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 2008 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, 2007


INDEX

        

 
    
   Page
Number
PART I   4
ITEM 1.   Business   4
ITEM 1A.   Risk Factors   16
ITEM 1B.   Unresolved Staff Comments   22
ITEM 2.   Properties   22
ITEM 3.   Legal Proceedings   23
ITEM 4.   Submission of Matters to a Vote of Security Holders   25

PART II
 
26
ITEM 5.   Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities   26
ITEM 6.   Selected Financial Data   28
ITEM 7.   Management's Discussion and Analysis of Financial Condition and Results of Operations   30
ITEM 7A.   Quantitative and Qualitative Disclosures About Market Risk   59
ITEM 8.   Consolidated Financial Statements and Supplementary Data   61
ITEM 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   132
ITEM 9A.   Controls and Procedures   132
ITEM 9B.   Other Information   136

PART III
 
136
ITEM 10.   Directors, Executive Officers and Corporate Governance   136
ITEM 11.   Executive Compensation   136
ITEM 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   136
ITEM 13.   Certain Relationships and Related Transactions, and Director Independence   136
ITEM 14.   Principal Accountant Fees and Services   136

PART IV
 
136
ITEM 15.   Exhibits and Financial Statement Schedules   136

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 the Company, 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


PART I

ITEM 1.    Business


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. and its subsidiaries.

        We provide a broad array of services including: well servicing, oilfield transportation services, cased-hole electric wireline services, contract drilling services, pressure pumping and well stimulation services and fishing and rental services. Over the years, our business has grown primarily through acquisitions. From 1994 through 2002, we grew rapidly through a series of over 100 acquisitions. From 2003 through 2006, we grew primarily through organic growth as we were engaged in a financial reporting process that involved a restatement of financial statements for 2003 and prior periods and delays in filing periodic reports with the Securities and Exchange Commission (the "SEC"). During this period, we also focused on improving the quality and reliability of our equipment. We completed this process and became current in our financial reporting in September 2007. With the completion of our financial reporting process in 2007, we commenced a program of geographic-focused acquisitions.

        We believe that we are the leading onshore, rig-based well servicing contractor in the United States. We operate in all major energy-providing regions of the United States. We also have limited operations offshore. We operate internationally in Argentina and Mexico, and we have a technology development group based in Calgary, Canada.

        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 SEC. Information on our website is not a part of this report.


DESCRIPTION OF BUSINESS SEGMENTS

        Our business is 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 Item 8. "Consolidated Financial Statements and Supplementary Data," Note 18—"Segment Information."

Well Servicing Segment

        Through our well servicing segment (approximately 76% of our revenues for the year ended December 31, 2007), we provide a broad range of well services, including rig-based services, oilfield transportation services, cased-hole electric wireline services, contract drilling services and other ancillary oilfield services. These services collectively are necessary to complete, stimulate, maintain and workover oil and natural gas producing wells. During 2007, Key conducted well servicing operations onshore: in the continental United States in the following regions 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.

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Rig-based Services

        Rig-based services include the maintenance of existing wells, workover of existing wells, completion of newly drilled 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 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. Over 200 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 eight inland barge rigs. Inland barge rigs are mobile, self-contained, drilling and/or workover vessels that are used in the search for oil and gas 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.

        Maintenance Services.    We provide the well service rigs, equipment and crews for maintenance services, which 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. The 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.

        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.

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        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.

        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.

Oilfield Transportation Services

        We provide oilfield transportation services, which primarily include vacuum truck services, fluid transportation services and disposal services for operators whose oil or natural gas wells produce salt water and 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. We transport fresh water to the well site and provide temporary storage and disposal of produced salt water and drilling or workover fluids. These fluids are removed from the well site and transported for disposal in a salt water disposal well. Key owned or leased 47 active salt water disposal wells at December 31, 2007. 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. This service is 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

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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 operated 22 units as of December 31, 2007, and we have seven units ordered that are expected to be delivered in 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 several heavy-duty well service rigs that are capable of providing drilling services. Our drilling services are primarily provided under standard day rate, 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 approximately 10,000 feet, although one rig can drill up to approximately 15,000 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 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 (approximately 18% of our revenues for the year ended December 31, 2007), we provide well stimulation and cementing services to oil and natural gas producers. Well stimulation services include fracturing, nitrogen services, and acidizing. 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. Our pressure pumping services in 2007 were provided in the Permian Basin, the San Juan Basin, the Barnett Shale region of North Texas and the Mid-Continent region. We also provide cementing services in conjunction with our plugging and abandonment operations in California. 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.

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Fishing and Rental Services Segment

        Through our fishing and rental services segment (approximately 6% of revenues for the year ended December 31, 2007), 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 tubulars, handling tools, 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.

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. 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, which means that the equipment has a crew and is ready to work. A stacked rig or piece of equipment is defined as a unit that is in the remanufacturing process or a unit that does not have a crew assigned to it 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, 2007, our active fleet of well service rigs totaled 975 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 60% of our rigs are located in predominantly oil regions while 40% of our rigs are located in predominantly natural gas regions.

        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 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.

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Well Service Rig Fleet as of December 31, 2007

Region
   Swab(1)
   Light Duty(2)
   Medium Duty(3)
   Heavy Duty(4)
   Total
Appalachia   2   15   8   1   26
Argentina   1   3   31   7   42
Ark-La-Tex   7   0   51   4   62
California   0   86   57   9   152
Gulf Coast   2   1   41   11   55
Mexico   0   0   2   1   3
Mid-Continent   12   13   97   4   126
Permian Basin   13   36   232   66   347
Rocky Mountains   3   2   47   37   89
Southeastern(5)   6   5   46   16   73
   
 
 
 
 
  Total   46   161   612   156   975
(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.

(5)
Includes eight inland barge rigs acquired in the acquisition of Moncla Well Service, Inc. and related entities. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations—Acquisitions."

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.

Transportation Fleet as of December 31, 2007

Region
   Vacuum Truck
   Winch Truck
   Hot Oil Truck
   Other
   Total
Appalachia   16   20   0   9   45
Argentina   1   15   2   29   47
Ark-La-Tex   175   26   0   27   228
California   24   1   0   44   69
Gulf Coast   151   37   0   10   198
Mid-Continent   30   16   7   18   71
Permian Basin   183   25   63   110   381
Rocky Mountains   12   2   0   4   18
Southeastern   0   34   2   2   38
   
 
 
 
 
  Total   592   176   74   253   1,095

Pressure Pumping Equipment

        Our pressure pumping segment operates a diverse fleet of equipment, including: frac pumps, cementing units, acidizing units and nitrogen units.

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Pressure Pumping Fleet as of December 31, 2007

Region
   Frac Pumps
   Cement Units
   Acidizing Units
   Nitrogen Units
   Total
California   0   8   0   0   8
Barnett Shale   41   4   3   0   48
Four Corners   7   3   4   5   19
Mid-Continent   18   4   1   0   23
Permian Basin   20   5   3   2   30
   
 
 
 
 
  Total   86   24   11   7   128


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 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 truck 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 are the owner of 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, 2007, we had 30 patents issued and 16 patents pending. As of December 31, 2007, we had 11 patents issued and 121 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 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.

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FOREIGN OPERATIONS

        During 2007, we operated internationally in Argentina and Mexico. In Argentina, we operated 37 well service rigs and seven drilling rigs and oilfield transportation vehicles, all of which we include in our well servicing segment. We commenced operations in Mexico during the second quarter of 2007. In February 2007, 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 valued at $45.8 million (USD) to provide field production solutions and well workover services. Under the terms of the contract, we initially provided three well service rigs outfitted with our proprietary KeyView® system, and we installed two KeyView® systems on PEMEX-owned well service rigs. The contract grants PEMEX the option to call for additional rigs and KeyView® systems in the future, although these incremental services are not included in the contract. The current project covers PEMEX's North Region assets and initially focuses on oil wells in Burgos, Poza Rica-Altamira and Cerro Azul. We anticipate that we will expand our presence in Mexico during 2008. Recently, PEMEX has requested that we send additional equipment and KeyView® systems to Mexico. We anticipate that we will deploy up to an additional eight well service rigs with our proprietary KeyView® technology and will install three KeyView® units on PEMEX-owned rigs during 2008. Concurrent with the deployment of additional equipment, we intend to seek an extension of our contract with PEMEX.

        Revenue from our international operations during 2007 totaled $105.8 million, or 6.4% of total revenue. Revenue from international operations for 2006 and 2005 totaled $78.3 million and $68.2 million, respectively.

        On September 5, 2007, we acquired Advanced Measurements, Inc., a privately-held Canadian technology company focused on oilfield service equipment controls, data acquisition and digital information work flow. In addition, in connection with the acquisition, we acquired a 51% ownership interest in Advanced Flow Technologies, Inc., a privately-held Canadian technology company focused on low cost wireless gas well production monitoring. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations—Acquisitions."


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, 2007, 2006 and 2005, 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 well service rigs in the United States. At December 31, 2007, we had 975 active rigs. Based on the Weatherford-AESC ("AESC") well service rig count, which is available on Weatherford International's internet website, there were approximately 2,839 well service rigs in the United States at December 31, 2007. A recent well service industry survey published by a U.S. investment bank suggests that there are more well service rigs in the United States than are reported by the AESC count. We agree that there are likely more rigs than reported by the AESC and we believe the active rig count could be as high as 3,600 well service rigs. The difference between the AESC data and the investment bank 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

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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 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 generally the primary factor in determining which service provider is awarded the work. However, we believe that most customers are willing to pay a slight premium for the quality and efficient service we provide.

        Significant well service providers include Nabors Industries, Basic Energy Services and Complete Production Services. Other large competitors include Bronco Drilling and Forbes Energy Services. 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 competitors have greater numbers of active well service rigs than Key. In Argentina, our largest competitors are Pride International, Nabors Industries, and Allis-Chalmers Energy. Schlumberger Ltd. and Nabors Industries are our largest competitors in Mexico.

        The pressure pumping 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, Superior Well Service, Basic Energy Services, Complete Production Services, Frac-Tech and RPC. 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 pressure pumping services along with our well service rigs and fishing and rental services, thereby offering our customers the ability to minimize vendors, which, we believe, will improve efficiency. This cross marketing capability is unique to Key, because none of the three major pressure pumping contractors operate well service rigs in the United States.

        The U.S. fishing and rental equipment market is fragmented compared to our other product lines. Companies which 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, Weatherford International, Basic Energy Services, Superior Energy Services, Quail Tools (owned by Parker Drilling) 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.

        The level of our revenues, earnings and cash flows are substantially dependent upon, and affected by, the level of domestic and international oil and 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, 2007, we employed approximately 8,380 persons in our domestic operations and approximately 1,440 additional persons in Argentina, Mexico and Canada. Our domestic employees are not represented by a labor union and are not covered by collective bargaining agreements. Many of

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our field employees in Argentina are represented by formal unions. While Mexico has a strong petroleum workers union, we are currently only employing non-union workers in Mexico. We have not experienced any material work stoppages associated with labor disputes or grievances and consider our relations with our employees to be satisfactory. During 2007, we experienced an annual employee turnover rate of approximately 41%, compared to a turnover rate of approximately 45% in 2006. 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. A discussion of the risks associated with our high turnover is presented in Item 1A. "Risk Factors—Business-Related 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 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 generate materials that are regulated as hazardous substances and, as a result, may incur

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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 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

        Recent 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. 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, 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

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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 saltwater disposal 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 saltwater disposal wells are located in Texas and we also operate saltwater disposal wells in Arkansas, Louisiana and New Mexico. Regulations in these states require us to obtain a permit to operate each of our saltwater disposal 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.

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.

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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.

        The demand for our services is primarily influenced by current and anticipated oil and natural gas prices. 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 establish and maintain production quotas to support oil prices, domestic and worldwide economic conditions and political instability in oil-producing countries. Weakness in oil and natural gas prices (or the perception by our customers that oil and natural gas prices will decrease) may cause lower 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:

        Periods of diminished or weakened demand for our services have occurred in the past. Although we experienced a material decrease in the demand for our services beginning in August 2001 and continuing through September 2002, since September 2002 we have experienced continued strong demand for our services. We believe the previous decrease in demand was due to an overall weakening of demand for onshore well services, which was attributable to general uncertainty about future oil and natural gas prices and the U.S. economy, including the impact of the September 11, 2001 terrorist attacks. If any of these conditions return, demand for our services could again decrease, having 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 increased the prices on our services to offset rising costs and to generate higher returns for our shareholders. Recently, we have made some price concessions to our customers in order to maintain market share. We believe that market conditions should remain strong due to high commodity prices, and therefore anticipate that pricing for our services should be relatively stable during 2008; however, should market conditions deteriorate or additional new industry capacity increase, it may become more difficult for us to maintain prices.

        The inability to maintain our pricing could:

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Increases in industry capacity may adversely affect our business.

        Over 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 employed by existing service providers to increase their service capacity. We have been adversely affected by the new capacity as our utilization for 2007 is down from prior years. Lower utilization of our fleet has led to reduced pricing for our services. Should oilfield service companies continue to add new capacity and demand for services not increase, we could experience continued pressure on the pricing of our services and experience lower utilization. This could have a material negative impact on our operating results.

An economic downturn may adversely affect our business.

        There is a concern that the United States may enter into a recession in 2008, and if so, a downturn in the U.S. economy may cause reduced demand for petroleum-based products and natural gas. In addition, during a downturn many oil and natural gas production companies often reduce or delay expenditures to reduce costs, which in turn may cause a reduction in the demand for our services during these periods. If the economic environment should deteriorate, our business, financial condition and results of operations may be adversely impacted.

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

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

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

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

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

        We currently have operations in Argentina and Mexico and may expand our operations into other foreign countries. We also have a technology development group in Canada. As a result, we are exposed to risks of international operations, including:

        The occurrence of one or more of these risks may:

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

        We historically have experienced an annual employee turnover rate of almost 50%, although our turnover rate during 2007 improved to approximately 41%. 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.

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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:

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. Please see Item 1. "Business—Governmental Regulations" for more information.

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 vendors, 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. 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 are 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.

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Debt-Related Risk Factors

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

        Our ability to make payments on our indebtedness, and to fund planned capital expenditures, will depend on our ability to generate cash in the future. This, to a certain extent, is subject to conditions in the oil and 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.

        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:

        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 prospects.

Our debt level and the covenants in the agreements governing our debt could negatively impact our financial condition, results of operations and business prospects and prevent us from fulfilling our obligations under our debt agreements.

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

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        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 these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions.

        In addition, under the terms of our indebtedness, we must comply with certain financial covenant 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 action would have a significant negative impact on our results of operations, financial condition and cash flows.

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

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

Delayed Financial Reporting-Related Risk Factors

We are not eligible to use short-form or shelf registration.

        The securities laws require that we supply current annual and quarterly financial statements in order for us to be able to register securities for a public offering or an acquisition. Although we are able to register securities for public offerings and acquisitions, we are not eligible to use "short-form" registration that allows us to incorporate by reference our SEC reports into our registration statements, or to use shelf registration until we have filed all of our periodic reports in a timely manner for a period of twelve months. Therefore, we will be ineligible for short-form or shelf registration until October 2008. Inability to use short-form or shelf registration could increase the costs of selling securities publicly and could significantly delay such sales.

Taxing authorities may determine that we owe additional taxes from previous years.

        As a result of the restatement of our financial statements for periods prior to 2004 and delay in our financial reporting for subsequent periods, we will likely have to amend previously filed tax returns and reports. 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.

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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.

        We have identified material weaknesses in internal control over financial reporting as of December 31, 2007. We have taken and will take actions to remediate the material weaknesses and improve the effectiveness of our internal control over financial reporting; however, we cannot assure you that we will be able to correct these material weaknesses by the end of 2008. 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:

        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

        Key leases executive office space in Houston, Texas (principal executive office) and Midland, Texas. In addition, we conduct our operations using a combination of owned and leased properties in each of our geographic markets. Our leased properties are subject to various lease terms and expirations. As of December 31, 2007, we owned 142 properties, 10 of which were inactive. We also operated 75 leased

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office and yard locations. We owned or leased 57 salt water disposal wells, ten of which were inactive at December 31, 2007. The majority of our salt water disposal wells are located in Texas.

        We believe all properties that we currently occupy are suitable for their intended use. We believe that we have sufficient facilities to conduct our operations during 2008. However, we continue to evaluate the purchase or lease of additional properties or the consolidation of our properties, as our business requires.

ITEM 3.    Legal Proceedings

        Since June 2004, we were named as a defendant in six class action complaints for alleged violations of federal securities laws, which have been filed in federal district court in Texas. They are as follows:

        These six actions were consolidated into one action. On November 1, 2005, the plaintiffs filed a consolidated amended class action complaint. The complaint was brought on behalf of a putative class of purchasers of our securities between April 29, 2003 and June 4, 2004. The complaint named Key, Francis D. John, Royce W. Mitchell, Richard J. Alario and James J. Byerlotzer as defendants. The complaint generally alleged that we made false and misleading statements and omitted material information from our public statements and SEC reports during the class period in violation of the Securities Exchange Act of 1934, including alleged: (i) overstatement of revenues, net income, and earnings per share, (ii) failure to take write-downs of assets, consisting of primarily idle equipment, (iii) failure to amortize the Company's goodwill, (iv) failure to disclose that the Company lacked adequate internal controls and therefore was unable to ascertain the true financial condition of the Company, (v) material inflation of the Company's financial results at all relevant times, (vi) misrepresentation of the value of acquired businesses, and (vii) failure to disclose misappropriation of funds by employees.

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        In addition, four shareholder derivative suits were filed by certain of our shareholders. They are as follows:

        The first derivative suit was filed on August 9, 2004 in state court in Midland, Texas. Two other derivative suits were filed in federal court in El Paso, Texas on December 10, 2004 and subsequently transferred to federal court in Midland, Texas and consolidated by agreement of the parties. Following dismissal of those two actions for failure to make a demand, a fourth derivative suit was filed in Texas state court in Harris County, Texas on May 22, 2007. Francis D. John, David J. Breazzano, Kevin P. Collins, William D. Fertig, W. Phillip Marcum, Ralph S. Michael III, J. Robinson West, James J. Byerlotzer, Royce W. Mitchell, and Richard J. Alario were named as defendants in one or more of those actions. The actions were filed by individual shareholders purporting to act on our behalf, asserting various claims against the named officer and director defendants. The derivative actions generally allege the same facts as those in the shareholder class action suits. Those suits also allege breach of fiduciary duty, abuse of control, waste of corporate assets, and unjust enrichment by these defendants.

        On September 7, 2007, we reached agreements in principle to settle all pending securities 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 Key will be required to pay $1,125,000. Final approval of the settlement of the shareholder and class action claims by the court is anticipated to occur in the first quarter of 2008.

        In addition to various suits and claims that have arisen in the ordinary course of business, we continue to be involved in litigation with our former executive officers as well as a class action lawsuit in California. 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. See Item 8. "Consolidated Financial Statements and Supplementary Data," Note 12—"Commitments and Contingencies."

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ITEM 4.    Submission of Matters to a Vote of Security Holders

        At our 2007 Annual Meeting of Shareholders held on December 6, 2007, holders of 106,759,477 shares were present in person or by proxy, constituting 80.47% of the outstanding shares of common stock as of the record date for the annual meeting. The matters voted upon at the annual meeting were:

        Election of four Class I Directors.    The shareholders elected four Class I Directors to serve for a three year term, expiring in 2010:

 
   Votes cast in favor:
   Votes withheld:
Lynn R. Coleman   100,342,605   6,416,872
Kevin P. Collins   93,124,276   13,635,201
W. Phillip Marcum   93,386,783   13,372,694
William F. Owens   100,345,025   6,414,452

Four Class II Directors, David J. Breazzano, William D. Fertig, Robert K. Reeves and J. Robinson West, continued in office with terms expiring in 2008. Three Class III Directors, Richard J. Alario, Ralph S. Michael, III and Arlene M. Yocum, continued in office with terms expiring in 2009.

        Adoption of 2007 Equity and Cash Incentive Plan.    The shareholders adopted the Key Energy Services, Inc. 2007 Equity and Cash Incentive Plan:

Adoption of 2007 Equity and Cash Incentive Plan
Votes cast in favor   63,861,992
Votes cast against   27,648,235
Votes abstaining   26,350
Broker non-vote   15,222,900

        Ratification of Independent Registered Public Accounting Firm.    The shareholders ratified the selection of Grant Thornton LLP as the Company's independent registered public accounting firm for the current fiscal year:

Ratification of Independent Registered Public Accounting Firm
Votes cast in favor   106,699,110
Votes cast against   19,094
Votes abstaining   41,273
Broker non-vote   0

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PART II

ITEM 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

        Market and Share Prices.    On October 3, 2007, Key's common stock resumed trading on the New York Stock Exchange, 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 20, 2008, there were 556 registered holders of 128,149,793 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, 2007            
  1st Quarter   $ 16.90   $ 14.85
  2nd Quarter     20.07     16.52
  3rd Quarter     18.38     13.08
  4th Quarter     16.95     13.25
 
 
   High
   Low
Year Ended December 31, 2006            
  1st Quarter   $ 16.50   $ 13.46
  2nd Quarter     18.75     13.00
  3rd Quarter     15.85     12.75
  4th Quarter     16.95     13.05

        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 or the Exchange Act, 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 Oil Service Sector and to a peer group established by management. This 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 Oil Service Sector and our peer group. The graph assumes that the value of the investment in our common stock and each index (including reinvestment of dividends) was $100 at December 31, 2002 and tracks the return on the investment through December 31, 2007.

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

         GRAPHIC

        Dividend Policy.    There were no dividends paid on Key's common stock for the year ended December 31, 2007. 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.    During the fourth quarter of 2007, the Company repurchased an aggregate 2,378,283 million shares of its common stock. The repurchases were made pursuant to the Company's $300 million share repurchase program and to satisfy tax withholding obligations that arose upon vesting of restricted stock that had been granted to certain senior executives. 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
   Appropriate
Dollar Value of
Shares that May Yet Be Purchased Under the Plans or Programs
October 1, 2007 to October 31, 2007   3,528 (1) $ 15.64 (2) —     —
November 1, 2007 to November 30, 2007   820,400 (3) $ 13.53   820,400   $ 288.9 million
December 1, 2007 to December 31, 2007   1,554,355 (4) $ 13.81 (5) 1,521,000   $ 267.8 million
(1)
Related to share repurchases made to satisfy tax withholding obligations of certain executive officers upon vesting of restricted stock.

(2)
The average price paid per share on the vesting date was determined using the closing price of the common stock of the Company as quoted on the Pink Sheets on October 1, 2007 and the closing price of the common stock of the Company as quoted on the NYSE on October 29, 2007.

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(3)
In October 2007, the Company announced a $300 million share repurchase program. The program expires March 31, 2009.

(4)
Includes 33,355 shares repurchased to satisfy tax withholding obligations of certain executive officers upon vesting of restricted stock.

(5)
The price paid per share on the vesting date with respect to the tax withholding repurchases was determined using the average of the closing price and opening price on December 21, 2007 and December 24, 2007, respectively, as quoted on the NYSE.

Equity Compensation Plan Information

        The following table sets forth information as of December 31, 2007 with respect to compensation plans (including individual compensation arrangements) under which our common stock is authorized for issuance.

Plan Category
   Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights
(a)
   Weighted-average exercise
price of outstanding
options, warrants
and rights
(b)
   Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
(c)
 
   (in thousands)

    
   (in thousands)
Equity compensation plans approved by shareholders(1)   4,998   $ 11.50   4,000
Equity compensation plans not approved by shareholders(2)   180   $ 8.10   —
   
       
Total   5,178         4,000
(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 Incentive 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.

ITEM 6.    Selected Financial Data

        The following historical selected financial data for the years ended December 31, 2007, 2006, 2005 and 2004 has been derived from the audited financial statements of the Company. Although the Company emerged from an extended restatement and financial reporting process in September 2007, it is unable to provide complete audited financial information for periods prior to 2004. Therefore, the Company is not providing selected financial data for the year ended December 31, 2003, because it is unable to provide financial statements for that period (except for the December 31, 2003 balance sheet) in accordance with generally accepted accounting principles ("GAAP"). Investors should refer to the 2003 Financial and Informational Report on Form 8-K/A, filed with the SEC on October 26, 2006 for a full description of the restatement process.

        The historical selected financial data should be read in conjunction with the historical Consolidated Financial Statements and related notes thereto included in Item 8. "Consolidated Financial Statements and Supplementary Data."

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Consolidated Results of Operations Data:

 
   Year Ended December 31,
  
 
   2007
   2006
   2005
   2004
  
 
   (in thousands, except per share data)

  
Revenues   $ 1,662,012   $ 1,546,177   $ 1,190,444   $ 987,739  
Direct expenses     985,614     920,602     780,243     685,420  
   
 
 
 
 
  Gross margin     676,398     625,575     410,201     302,319  
   
 
 
 
 
General and administrative expenses     230,396     195,527     151,303     162,133  
   
 
 
 
 
  Operating income, before depreciation and amortization     446,002     430,048     258,898     140,186  
   
 
 
 
 
Depreciation and amortization     129,623     126,011     111,888     103,339  
Interest expense, net of amounts capitalized     36,207     38,927     50,299     46,206  
Other, net     4,232     (9,370 )   12,313     19,114  
   
 
 
 
 
  Income (loss) from continuing operations before income taxes     275,940     274,480     84,398     (28,473 )
   
 
 
 
 
Income tax (expense) benefit     (106,768 )   (103,447 )   (35,320 )   1,890  
Minority interest     117     —     —     —  
   
 
 
 
 
  Income (loss) from continuing operations     169,289     171,033     49,078     (26,583 )
   
 
 
 
 
Discontinued operations, net of tax     —     —     (3,361 )   (5,643 )
   
 
 
 
 
  Net income (loss)   $ 169,289   $ 171,033   $ 45,717   $ (32,226 )
   
 
 
 
 
  Income (loss) per common share from continuing operations:                          
      Basic   $ 1.29   $ 1.30   $ 0.37   $ (0.20 )
      Diluted   $ 1.27   $ 1.28   $ 0.37   $ (0.20 )
  Income (loss) per common share from discontinued operations:                          
      Basic   $ —   $ —   $ (0.03 ) $ (0.04 )
      Diluted   $ —   $ —   $ (0.03 ) $ (0.04 )
  Net income (loss) per common share:                          
      Basic   $ 1.29   $ 1.30   $ 0.34   $ (0.24 )
      Diluted   $ 1.27   $ 1.28   $ 0.34   $ (0.24 )

Cash Flow Data:

 
   Year Ended December 31,
  
 
   2007
   2006
   2005
   2004
  
 
   (in thousands)

  
Net cash provided by operating activities   $ 249,919   $ 258,724   $ 218,838   $ 69,801  
Net cash used in investing activities     (302,847 )   (245,647 )   (33,218 )   (64,081 )
Net cash provided by (used in) financing activities     23,240     (18,634 )   (111,213 )   (88,277 )
Effect of exchange rates on cash     (184 )   (238 )   (662 )   (233 )

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Selected Balance Sheet Data:

 
   December 31,
2007
   December 31,
2006
   December 31,
2005
   December 31,
2004
 
   (in thousands)
Working capital   $ 253,068   $ 265,498   $ 169,022   $ 165,920
Property and equipment, gross     1,595,225     1,279,980     1,089,826     999,414
Property and equipment, net     911,208     694,291     610,341     597,778
Total assets     1,859,077     1,541,398     1,329,244     1,316,622
Long-term debt and capital leases, net of current maturities     511,614     406,080     410,781     481,047
Total liabilities     970,079     810,887     775,187     810,956
Stockholders' equity     888,998     730,511     554,057     505,666
Cash dividends per common share     —     —     —     —

ITEM 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations

        The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes thereto in Item 8. "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." Actual results may differ materially from these expectations due to inaccurate assumptions and known or unknown risks and uncertainties. See Item 1A. "Risk Factors."

Business and Growth Strategies

        Our strategy is to improve results through acquisitions, growing our core segments, maintaining a strong balance sheet, expanding internationally, investing in technology, expanding our services offering, and training personnel in order to maintain a qualified and safety-conscious employee base.

        Acquisitions.    Our strategy contemplates that we may make acquisitions that strengthen our presence in selected regional markets. During 2007, we completed the acquisition of Moncla Well Service, Inc. and related entities (collectively, "Moncla") and Advanced Measurements, Inc. ("AMI"). In addition, we acquired the well service assets of Kings Oil Tools, Inc. ("Kings"). Through the purchase of Moncla and Kings, we increased our well service rig count by 89 units and our swab rig count by six units. We believe that these acquisitions will allow us to expand our geographic "footprint" and improve our service to our customers. See—"Acquisitions," for additional discussion.

        We are currently evaluating a number of geographic-focused acquisition candidates, primarily in our well servicing segment, and these acquisitions, if completed, would help strengthen our position in several core markets. We may seek to identify other acquisition candidates and we may evaluate acquisition opportunities in either our pressure pumping or fishing and rental services segments. Our acquisitions in 2007 were made with cash and notes payable, and our objective is to use cash for future geographic-focused acquisitions. In some limited cases, however, we may elect to use equity as a financing tool for our acquisition program.

        Organic Growth in Core Segments.    During the past three years we have significantly increased our capital expenditures, devoting more capital to organic growth. Since the beginning of 2005, we have cumulatively spent approximately $526.5 million on capital expenditures, including capital expenditures of $212.6 million in 2007. 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. While we believe that the returns on organic growth capital remain strong, we intend to reduce our capital expenditures in 2008 in order to allocate

30


more capital to our acquisition and share repurchase programs. Presently, we estimate that we will spend approximately $175.0 million in capital expenditures in 2008; however, that amount could increase if we are awarded additional international work, which would require us to build new equipment.

        Maintain Strong Balance Sheet.    We believe that our ability to maintain a strong balance sheet and exercise sound capital discipline is critical. We also believe that our ability to maintain ample liquidity and borrowing capacity is important in order to enable us to finance acquisitions and share repurchases, as well as to take advantage of other attractive business opportunities if they should develop. In order to provide more flexibility and meet our objectives, during 2007 we refinanced our outstanding indebtedness. We issued $425.0 million of long-term senior unsecured notes (the "Notes") and entered into a new $400.0 million Senior Secured Credit Facility (the "2007 Senior Secured Credit Facility"). The Notes, which have a coupon of 8.375%, require no prepayment and mature in 2014. The 2007 Senior Secured Credit Facility consists of a revolving credit facility, letter of credit sub-facility and swing line facility, all of which mature no later than 2012.

        International Expansion.    We presently operate in Argentina and Mexico and have a technology development group based in Canada. We are evaluating ways in which we can expand internationally. 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. Long term, we believe opportunities may exist in the Middle East, Russia and Latin America. See Item 1. "Business—Foreign Operations," for further discussion of our current international operations. We also have an investment in IROC Energy Services Corp. in Canada. See Item 8. "Consolidated Financial Statements and Supplementary Data," Note 7—"Investment in IROC Energy Services Corp."

        Technology Initiative.    We have invested, and will continue to invest, in technology projects that improve operating efficiencies for both ourselves and our customers, improve 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. The KeyView® system captures well-site operating data, thereby allowing customers and ourselves to monitor and analyze information about well servicing, resulting in improved efficiency. At December 31, 2007, we had 220 KeyView® units 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 Item 1. "Business—Patents, Trade Secrets, Trademarks and Copyrights."

        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.

        Expansion of Services Offering.    We believe that it is important to have a broad and diverse services offering. For this reason, we have invested in our pressure pumping segment and our fishing and rental segment. In addition, during 2006 we entered the cased-hole electric wireline business in Texas, and we expanded our cased-hole electric wireline operation during 2007. During 2008, we intend to seek opportunities to expand our wireline services to other markets and to expand our project with PEMEX in Mexico. We also have ordered six coiled-tubing units which we expect to receive during the

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second quarter of 2008. We believe that some customers prefer to consolidate vendors and we feel that our expanded services offering may provide better opportunities for customer penetration.

        Training and Developing Employees.    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 attractive and competitive compensation, benefits and incentive programs for our employees in order to ensure a steady stream of qualified, safety-conscious personnel that are able to provide quality service to our customers.

Current Financial Condition and Liquidity

        We believe our current financial condition is strong, and we believe that our current reserves of cash and cash equivalents, current availability under our 2007 Senior Secured Credit Facility, and internally generated cash flow from operations are sufficient to finance the cash requirements of our current and future operations and our budgeted capital expenditures for 2008. As of December 31, 2007, we had $58.8 million in cash and short-term investments and $288.9 million of availability under our 2007 Senior Secured Credit Facility.

        In July 2007, we adopted a near-term capital investment plan to return capital to our shareholders and to make strategic geographic-focused acquisitions. Our Board of Directors subsequently authorized a share repurchase program of up to $300 million which is effective through March 31, 2009. Through December 31, 2007, we repurchased 2,341,400 shares of our common stock for approximately $32.2 million. In addition, through February 20, 2008, we cumulatively had repurchased 5,363,096 shares for approximately $69.8 million. Our repurchase program, as well as the amount and timing of the future repurchases, is subject to market conditions and our financial condition and liquidity.

        The capital investment plan also provides for the Company to make acquisitions. During 2007, we completed three acquisitions for approximately $158.0 million in the aggregate, net of cash acquired. Our capital expenditure program for 2008 is expected to total approximately $175.0 million; however, that amount is subject to market conditions, including activity levels, commodity prices and industry capacity. Our focus in 2008 will be maximizing the utilization of our current equipment, however, we may seek to increase our 2008 capital expenditure budget in the event international expansion opportunities develop. See—"Acquisitions."

        Our stock repurchase program and acquisition program, as well as planned capital expenditures, are expected to be financed through a combination of cash on hand, cash flow from operations and borrowings under our 2007 Senior Secured Credit Facility.

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

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count. As the following table indicates, the land drilling rig count has increased significantly over the past several years as commodity prices, both oil and natural gas, have increased.

Year
   WTI Cushing
Crude Oil(1)
   NYMEX Henry Hub
Natural Gas(1)
   Average Baker Hughes
Land Drilling Rigs(2)
2002   $ 26.18   $ 3.37   717
2003   $ 31.08   $ 5.49   924
2004   $ 41.51   $ 6.18   1,095
2005   $ 56.64   $ 9.02   1,290
2006   $ 66.05   $ 6.98   1,559
2007   $ 72.34   $ 7.12   1,695

        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 2005 through 2007.

 
   Rig Hours
   Trucking Hours
2005:        
  First Quarter   621,228   641,841
  Second Quarter   661,928   635,448
  Third Quarter   668,741   607,500
  Fourth Quarter   646,810   594,762
   
 
Total 2005:   2,598,707   2,479,551

2006:
 
 
 
 
  First Quarter   663,819   609,317
  Second Quarter   679,545   602,118
  Third Quarter   677,271   587,129
  Fourth Quarter   637,994   578,471
   
 
Total 2006:   2,658,629   2,377,035

2007:
 
 
 
 
  First Quarter   625,748   571,777
  Second Quarter   611,890   583,074
  Third Quarter   597,617   570,356
  Fourth Quarter   614,444   583,191
   
 
Total 2007:   2,449,699   2,308,398

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        In our pressure pumping segment, we track the total number of jobs performed to measure activity levels. The following table presents the types and total number of jobs performed by our pressure pumping services segment for the periods presented.

Year
   Fracturing
   Cementing
   Acidizing
   Other
   Total
2005   1,329   1,558   1,057   106   4,050
2006   1,585   1,958   639   96   4,278
2007   2,152   2,074   481   77   4,784

        The majority of our pressure pumping segment revenue (approximately 80 - 85%) is derived from our fracturing jobs.

Operating Environment

2007 Operating Environment

        Activity levels in 2007 (as measured by our rig and trucking hours) were lower than 2006 due to increased supply of well service rigs and oilfield trucking assets in the market. Our activity declines occurred despite continued strength of commodity prices, including record high oil prices, and overall industry demand for well services. Rig hours for 2007 totaled 2,449,699, a decrease of 7.9% from 2006. The decrease in activity levels would have been greater absent the impact of the businesses acquired during 2007. The Moncla acquisition included 59 well service rigs and during the fourth quarter those assets contributed approximately 34,000 rig hours.

        Our trucking hours totaled 2,308,398, a decrease of 2.9% from 2006. The Baker Hughes land drilling rig count averaged 1,695 in 2007, an increase of approximately 8.7% from an average of 1,559 in 2006. The higher drilling rig count is indicative of the strength of the U.S. marketplace, which is directly associated with the strength of oil and natural gas prices. As of December 31, 2007, the Baker Hughes land drilling rig count totaled 1,719, while in 2007 the WTI Cushing price for light sweet crude averaged $72.34 per barrel and natural gas prices averaged $7.12 per MMbtu.

        Our business has been negatively impacted by new industry capacity. In our well servicing segment, both our rig and trucking hours are down year-over-year due primarily to new competition. The new capacity has entered the U.S. market place due to high returns and strong demand for oilfield services. In addition, some of our customers have elected to vertically integrate and have purchased and now operate their own equipment. Activity levels in most of our operating regions are down from 2006; the regions with the most pronounced declines include the Gulf Coast, the Rocky Mountains and East Texas. These regions are characterized by high natural gas production. In response to lower utilization of our assets, during 2007, we reduced pricing for some of our customers. These reductions have taken place in most of our regions and in all of our operating segments.

2008 Operating Environment Outlook

        Our activity levels to date in 2008, excluding the contribution of businesses acquired in 2007, are down from last year. However, our business remains strong and we believe that our activity levels will remain stable for the balance of 2008. Our belief is predicated on the fact that commodity prices through February 2008 remain at levels higher than 2007. As of February 15, 2008 crude oil prices were in excess of $90 per barrel while natural gas prices were in excess of $8.50 per MMbtu. At these high prices, we believe customer spending in 2008 could surpass spending in 2007. We also believe that our recent acquisitions in the fourth quarter of 2007 will help offset declines in our other businesses. We also believe that our recent acquisitions in the fourth quarter of 2007 will help offset declines in our other businesses. Because demand for our well servicing, pressure pumping services, and fishing and rental services is generally correlated to commodity prices and drilling activity, our activity levels may be negatively impacted in the event commodity prices decline rapidly or unexpectedly.

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        Although we believe that demand for our services will be strong because of the high commodity prices, we also believe that our business will continue to face increased competition due to additional industry capacity and new market entrants. We believe that this risk is somewhat mitigated as a number of oilfield service companies, including us, have announced capital spending reductions for 2008. This should reduce the rate of growth of new equipment entering the market. This reduction, combined with higher commodity prices, leads us to believe that 2008 could be as strong, if not stronger, than 2007. Our 2008 budget estimates that our revenues will exceed revenue for 2007. In the event new capacity does not slow, we believe that margin compression could occur in 2008 as increased equipment capacity could result in lower utilization of our assets. Further, an increase in equipment supply could lead to higher labor rates as the demand for people would correspondingly increase.

        We also have initiatives underway that we hope will maintain and possibly enhance our margins. These initiatives include a continued focus on safety improvements and reductions in employee turnover. Better safety performance, we believe, will reduce workers compensation expense and help lower our insurance premiums. Additionally, lower employee turnover will help reduce hiring and training costs. We are also seeking to reduce our reliance on third-party consultants and outside legal counsel, to the extent their services were generally attributable to matters arising out of our restatement and financial reporting process. We believe this will help reduce our general and administrative expenses.

        We also anticipate that our international operations will expand. We have received additional requests for equipment from our customer in Mexico. Presently, we operate three rigs in Mexico, and we believe that we will send up to eight additional rigs to Mexico during 2008. In addition, we have secured pricing increases in our Argentina division and anticipate that margins for that division should improve in 2008.

Acquisitions

        Moncla Acquisition.    On October 25, 2007, we purchased all of the outstanding shares and membership interests of Moncla. Moncla operated in Texas, Louisiana, Mississippi, Alabama and Florida. Headquartered in Lafayette, Louisiana, and with offices in Sour Lake, Texas and Sandersville, Mississippi, Moncla operated a total of 59 rigs (including six swabbing units) and had over 900 employees. Moncla's fleet included 37 daylight rigs for well servicing and workovers and eight twenty-four hour rigs for shallow drilling, sidetracking and deep workovers. In addition, the Moncla companies operated eight barge rigs, and owned rig-up, swab, hot oil and anchor trucks, tubing testing units and rental equipment. Revenue attributable to the Moncla business is anticipated to be approximately $140.0 million in 2008.

        The purchase price for Moncla was approximately $146.0 million, which consisted of net assets acquired of $131.3 million and assumed debt of $14.7 million. Amounts transferred at closing consisted of (i) $108.6 million of cash; (ii) the issuance of an unsecured promissory note for $12.5 million that is payable in a lump sum on October 25, 2009, with accrued interest payable on each anniversary date of the closing of the acquisition; and (iii) the issuance of an unsecured promissory note for $10.0 million that is payable in five annual installments of $2.0 million plus accrued interest on each annual anniversary date of the closing of the acquisition. Both promissory notes bear interest at the Federal Funds rate, adjusted annually on the anniversary of the closing date. The long-term debt assumed in the acquisition was repaid simultaneously with the closing of the transaction. The purchase price is subject to a working capital adjustment, which has not been finalized.

        The Moncla purchase agreement entitles the former owners of Moncla to receive earnout payments, on each of the next five anniversary dates of the closing date of the acquisition, of up to $5.0 million (up to $25.0 million in total). The earnout payments are based on the achievement of certain revenue targets and profit percentage targets over the next five years and are payable upon

35


achieving annual targets or a cumulative target on the fifth anniversary date. These payments represent an additional element of cost of the acquired entity and will be accounted for as an increase to goodwill if and when the contingent payment is made.

        Kings Acquisition.    On December 7, 2007, we acquired the well service assets and related equipment of Kings. The acquired assets, all of which are located in California, included 36 marketed well service rigs, 10 stacked well service rigs and related support equipment. We anticipate that the acquired assets will contribute revenue of approximately $36 million in 2008. Total consideration paid for the transaction was approximately $45 million in cash, which included consideration for a noncompete agreement with the owner of Kings.

        Technology Acquisition.    On September 5, 2007, we purchased, through a wholly-owned Canadian subsidiary, all of the outstanding shares of AMI, a privately-held Canadian technology company focused on oilfield service equipment controls, data acquisition, and digital information work flow. The purchase price was $6.6 million in cash and the assumption of approximately $2.9 million in debt, which has since been paid in full. The purchase agreement also provided for deferred cash payments up to a maximum of $1.8 million related to the retention of key employees. On the date of acquisition, AMI owned a 48% interest in Advanced Flow Technologies, Inc. ("AFTI"), a privately-held Canadian technology company focused on low cost wireless gas well production monitoring. As part of the purchase of AMI we were required to exercise an option to increase AMI's interest in AFTI to 51.46%. The cost to exercise this option was approximately $0.5 million. As a result, through AMI we now own a 51.46% interest in AFTI. In connection with the acquisition of AMI, we became party to a revolving credit agreement with a maximum outstanding amount of $0.9 million. This facility was extinguished in November 2007.

        We made no acquisitions during 2005 or 2006.

Discontinued Operations

        On January 15, 2005, we completed the sale to Patterson-UTI Energy, Inc. of the majority of our contract drilling assets, which included drilling rigs and associated equipment in the Permian Basin and Four Corners regions and certain rigs from the Rocky Mountain region. In consideration of the sale, we received approximately $60.5 million in cash, after paying all fees related to the sale. The sale included approximately 25 active rigs and 10 stacked rigs as well as a number of rigs which had been classified as either scrap or salvage. The active rigs were mechanical with an average of approximately 700 horsepower and depth ratings of approximately 10,000 feet. As a result of the sale, we treated our drilling business as a discontinued operation for all periods presented and recorded an after-tax loss from discontinued operations of $3.4 million, or $0.03 per diluted share, for the year ended December 31, 2005.

        Cash flows from our discontinued operations have been segregated and individually presented for all years in our consolidated statements of cash flows. We do not anticipate that the absence of these cash flows in future periods will have a material adverse impact on our liquidity, results of operations or financial position.

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Results of Operations

        The following table sets forth statements of operations for the years indicated:

 
   Year Ended December 31,
  
 
   2007
   2006
   2005
  
 
   (in thousands)

  
REVENUES:                    
  Well servicing   $ 1,264,797   $ 1,201,228   $ 956,457  
  Pressure pumping     299,348     247,489     152,320  
  Fishing and rental     97,867     97,460     81,667  
   
 
 
 
Total revenues     1,662,012     1,546,177     1,190,444  
   
 
 
 
COSTS AND EXPENSES:                    
  Well servicing     738,694     725,008     634,043  
  Pressure pumping     189,645     138,377     92,301  
  Fishing and rental     57,275     57,217     53,899  
  Depreciation and amortization     129,623     126,011     111,888  
  General and administrative     230,396     195,527     151,303  
  Interest expense, net of amounts capitalized     36,207     38,927     50,299  
  Loss on early extinguishment of debt     9,557     —     20,918  
  Loss (gain) on sale of assets, net     1,752     (4,323 )   (656 )
  Interest income     (6,630 )   (5,574 )   (2,713 )
  Other, net     (447 )   527     (5,236 )
   
 
 
 
Total costs and expenses, net     1,386,072     1,271,697     1,106,046  
   
 
 
 
Income from continuing operations before income taxes     275,940     274,480     84,398  
Income tax expense     (106,768 )   (103,447 )   (35,320 )
Minority interest     117     —     —  
   
 
 
 
INCOME FROM CONTINUING OPERATIONS     169,289     171,033     49,078  
   
 
 
 
Loss from discontinued operations, net of tax expense of $4,590     —     —     (3,361 )
   
 
 
 
NET INCOME   $ 169,289   $ 171,033   $ 45,717  
   
 
 
 

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REVIEW OF OPERATIONS

        For the year ended December 31, 2007, our revenue reached a record high. Our revenue for the year ended December 31, 2007 totaled $1.66 billion, which represents a 7.5% increase over the prior year. Our net income for the year totaled $169.3 million, which represents a 1.0% decrease from the prior year while our earnings per fully diluted share totaled $1.27 compared to $1.28 from the prior year.

        Impacting our net income and earnings per share for 2007 results were costs associated with the refinancing of our indebtedness in the fourth quarter of 2007. These include a loss related to the early extinguishment of our 2005 Senior Secured Credit Facility (defined herein) which totaled $9.6 million, or $0.04 per fully diluted share, and the termination of two interest rate swaps associated with that debt, which resulted in a loss of $2.3 million, or $0.01 per fully diluted share.

        A detailed review of our operations, including a review of our segments, is provided below.

Revenue

        Our revenue for the year ended December 31, 2007 increased $115.8 million, or 7.5%, to $1.66 billion from $1.55 billion for the year ended December 31, 2006. The increase in revenue relates to:

Revenue (in millions)
   Change from 2006
Well servicing segment   $ 63.5
Pressure pumping segment   $ 51.9
Fishing & rental segment   $ 0.4
   
Total change   $ 115.8

        Businesses acquired during 2007 contributed approximately $26.5 million of the increase in the well servicing segment over 2006. The Moncla transaction included 59 well service rigs, and during the fourth quarter those assets contributed approximately 34,000 rig hours and $23.6 million in revenue. The remaining $2.9 million of revenues from acquired businesses is attributable to AMI. Mexican operations began during the second quarter of 2007 and added $9.0 million in revenue to our well servicing segment. We presently operate three well service rigs in Mexico and the number of rigs in Mexico is anticipated to increase by eight rigs (for a total of 11 rigs) during 2008. Our cased-hole electric wireline activities in our well servicing segment also expanded during the year, providing a $13.7 million increase in revenues as we added additional units to our fleet. We believe this business offers a good growth opportunity and we intend to add additional cased-hole electric wireline units during 2008. Absent these items, overall increases in well servicing segment revenue were driven primarily by the impact of pricing increases that were implemented during the middle of 2006, though we were affected by declines in prices in the second half of 2007. Revenue was also affected by declines in rig and truck hours, as competition in the well servicing sector increased during 2007 and we lost market share to new capacity in the marketplace. Our pressure pumping segment revenue increased as we deployed additional frac pumps and cement units. This allowed us to perform more frac jobs, which is the primary revenue driver in our pressure pumping segment. Revenue in the fishing and rental segment was flat compared to 2006.

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        Our revenue for the year ended December 31, 2006 increased $355.7 million, or 29.9%, to $1.55 billion from $1.19 billion for the year ended December 31, 2005. The increase in revenue relates to:

Revenue (in millions)
   Change from 2005
Well servicing segment   $ 244.7
Pressure pumping segment   $ 95.2
Fishing & rental segment   $ 15.8
   
Total change   $ 355.7

        Our well servicing segment benefited from a 2.3% increase in our rig hours combined with a significant improvement in the pricing for our well service rig services. Our pressure pumping segment revenue increased as we deployed new frac pumps and cement units, adding to our fleet. This allowed us to perform more frac jobs, which is the primary revenue driver in our pressure pumping segment. Fishing and rental revenue increased principally due to higher activity levels and improved pricing.

Direct Costs

        Direct costs as a percentage of total revenue improved to 59.3% for the year ended December 31, 2007, compared to 59.5% for the year ended December 31, 2006. Direct costs as a percentage of total revenue improved to 59.5% for the year ended December 31, 2006, compared to 65.5% for the year ended December 31, 2005.

        Consolidated direct costs for the year ended December 31, 2007 increased $65.0 million, or 7.1%, to $985.6 million from $920.6 million for the year ended December 31, 2006. The $65.0 million increase is primarily the result of:

Direct Costs (in millions)
   Change from 2006
  
Employee compensation   $ 25.4  
Pressure pumping supplies and equipment   $ 41.6  
Well service acquisitions   $ 16.0  
Self-insurance costs   $ (21.8 )
Other costs   $ 3.8  
   
 
Total change   $ 65.0  

        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 continues to be extremely competitive. With new competitors entering the market and existing competitors adding 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 costs in 2007. Our self-insurance costs, composed of costs associated with workers compensation, vehicular liability exposure, and insurance premiums declined significantly in 2007 as compared to 2006. We have been focused on improving our safety performance, and in 2007 the number and severity of safety-

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related accidents declined. We continue to focus on safety improvements and our safety performance is a component of our incentive compensation program.

        Consolidated direct costs for the year ended December 31, 2006 increased $140.4 million, or 18.0%, to $920.6 million from $780.2 million for the year ended December 31, 2005. The $140.4 million increase is primarily the result of:

Direct Costs (in millions)
   Change from 2005
  
Employee compensation   $ 97.0  
Well service equipment and supplies   $ 17.9  
Pressure pumping equipment and supplies   $ 36.6  
Other costs   $ (11.1 )
   
 
Total change   $ 140.4  

        Our employee compensation costs, which include salaries, bonuses and related expenses increased $97.0 million, primarily as the result of increased incentive compensation and increased headcount. Wage and bonus increases during the year were necessary, as the market for our labor continues to be extremely competitive. With new competitors entering the market and existing competitors adding equipment capacity, we were forced to increase wage rates in order to maintain our high levels of quality personnel. Supplies and equipment costs for our well servicing operations increased $17.9 million in 2006 compared to 2005, primarily as a result of increases in costs associated with higher activity levels, which results in strong utilization of our equipment and therefore, more wear and tear on our operational assets. Additionally, many of the assets we acquired through acquisitions during the 1994 - 2002 timeframe are beginning to reach the end of their economic useful lives; because of this, these assets require greater repairs and maintenance to keep them productive and operating. The repair and maintenance expense is also a function of our proactive maintenance programs. Supplies and equipment for our pressure pumping operations increased $36.6 million, primarily as a result of increases in the size of our fleet as we added equipment year over year, as well as increases in the costs to purchase and transport sand and chemicals used in our operations. Other costs declined $11.1 million, primarily as a result of reductions in self-insurance costs.

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 acquisitions 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 are now 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.

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        Depreciation and amortization expense increased $14.1 million, or 12.6%, to $126.0 million for the year ended December 31, 2006, compared to $111.9 million for the year ended December 31, 2005. The increase is primarily attributable to a greater fixed asset base, which is due to increased capital expenditures. For the year ended December 31, 2006, our capital expenditures totaled approximately $195.8 million, as compared to $118.1 million for the year ended December 31, 2005. Depreciation and amortization expense as a percentage of revenue for the year ended December 31, 2006 totaled 8.1%, compared to 9.4% for the year ended December 31, 2005.

General and Administrative Expense

        General and administrative ("G&A") 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 is primarily the result of:

G&A Expense (in millions)
   Change from 2006
Employee compensation   $ 7.5
Acquisitions   $ 3.0
2006 legal settlement to the Company   $ 7.5
Professional fees   $ 9.6
Bad debt expense   $ 1.8
Other   $ 5.5
   
Total change   $ 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, excluding grants made to our outside directors, during 2007 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. G&A expenses added through acquisitions made during 2007 contributed $3.0 million to the increase in costs when compared to 2006.

        G&A also increased in 2007, because G&A in 2006 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 financial reporting process. Also contributing to the increase in G&A was an additional $1.8 million in bad debt expense and $5.5 million in other G&A costs. G&A 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.

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        G&A expense increased $44.2 million, or 29.2%, to $195.5 million for the year ended December 31, 2006 compared to $151.3 million for the year ended December 31, 2005. The increases in G&A expense are primarily attributable to:

G&A Expense (in millions)
   Change from 2005
  
Employee compensation   $ 40.5  
2006 legal settlement   $ (7.5 )
Other costs   $ 11.2  
   
 
Total change   $ 44.2  

        Compensation-related expenses increased primarily due to increased staff, higher equity-based compensation and increased incentive compensation expense. Equity-based compensation expense during 2006 totaled $5.6 million compared to $1.7 million during 2005, primarily due to incremental stock options and restricted stock granted during 2006. The 2006 period also benefited from a $7.5 million legal settlement. With the increases in staff, other general and administrative costs associated with additional employees, including but not limited to office and computer supplies and travel, also increased. These other G&A costs increased $11.2 million in 2006 as compared to 2005. G&A expense as a percentage of revenue for the year ended December 31, 2006 totaled 12.6% compared to 12.7% for the year ended December 31, 2005.

Interest Expense

        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 is 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 2005 Senior Secured Credit Facility in 2007. Interest expense as a percent of revenue for the year ended December 31, 2007 totaled 2.2%, compared to 2.5% for the year ended December 31, 2006. We anticipate that our interest expense will be higher in 2008 as our total debt has increased from the prior year.

        Interest expense decreased $11.4 million, or 22.6%, to $38.9 million for the year ended December 31, 2006, compared to $50.3 million for the year ended December 31, 2005. The decrease was the result of lower interest rates under our 2005 Senior Secured Credit Facility, which was entered into in July 2005 and used to refinance all of our then-outstanding senior notes. The refinancing eliminated the monthly consent fees which were being paid to bondholders due to our failure to file SEC reports. Interest expense as a percentage of revenue for the year ended December 31, 2006 totaled 2.5%, compared to 4.2% for the year ended December 31, 2005.

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 2005 Senior Secured Credit Facility. During 2007, we issued $425.0 million of Notes and used the proceeds to retire the term loans then outstanding under the 2005 Senior Secured Credit Facility. Concurrently, we entered into the 2007 Senior Secured Credit Facility and terminated the 2005

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Senior Secured Credit Facility. The loss represents the write-off of debt issue costs we incurred when we entered into the 2005 Senior Secured Credit Facility.

        For the year ended December 31, 2006, we did not incur any losses associated with the retirement of long-term debt obligations; however, for the year ended December 31, 2005, we incurred losses totaling $20.9 million associated with the termination of our then senior secured credit facility and the redemption or repayment of $425.0 million in senior notes.

Income Taxes

        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 is primarily attributable to the Texas Margins Tax, which added $5.5 million of state income taxes during 2007. 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.

        Our income tax expense was $103.4 million for the year ended December 31, 2006, as compared to income tax expense from continuing operations of $35.3 million for the year ended December 31, 2005. The increase in income tax was the result of higher taxable income. Our effective tax rate in 2006 was 37.7%, as compared to 41.8% in 2005. 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.

Segment Results

 
   Year Ended December 31,
  
Segments
  
  2007
   2006
   2005
  
 
   (in thousands, except for percentages)

  
Well Servicing                    
  Revenue   $ 1,264,797   $ 1,201,228   $ 956,457  
  Direct Costs     738,694     725,008     634,043  
  Gross Profit     526,103     476,220     322,414  
  Gross Margin     41.6 %   39.6 %   33.7 %

Pressure Pumping
 
 
 
 
 
 
 
 
 
 
  Revenue   $ 299,348   $ 247,489   $ 152,320  
  Direct Costs     189,645     138,377     92,301  
  Gross Profit     109,703     109,112     60,019  
  Gross Margin     36.6 %   44.1 %   39.4 %

Fishing & Rental
 
 
 
 
 
 
 
 
 
 
  Revenue   $ 97,867   $ 97,460   $ 81,667  
  Direct Costs     57,275     57,217     53,899  
  Gross Profit     40,592     40,243     27,768  
  Gross Margin     41.5 %   41.3 %   34.0 %

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Well Servicing Segment

Revenue

        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 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 segment revenues increased $244.7 million, or 25.6%, to $1.20 billion for the year ended December 31, 2006, compared to revenue of $956.5 million for the year ended December 31, 2005. The increase in revenue is largely attributable to higher pricing for our well service rigs and modestly higher activity levels. Because of continued high commodity prices and strong demand for maintenance and workover-related services, we implemented multiple price increases during 2006. This resulted in increased revenue year-over-year. Also, during the year ended December 31, 2006, our rig hours increased 2.3% compared to the year ended December 31, 2005, while our trucking hours decreased 4.1% during the comparable period. The decrease in trucking hours was due primarily to lost market share to new market entrants.

Direct Costs

        Direct costs as a percent of total well servicing segment revenue improved to 58.4% for the year ended December 31, 2007, compared to 60.4% for the year ended December 31, 2006. Direct costs as a percent of total well servicing segment revenue improved to 60.4% for the year ended December 31, 2006, compared to 66.3% for the year ended December 31, 2005.

        Well servicing direct costs increased $13.7 million, or 1.9%, 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 costs. Excluding the effect of acquisitions, well servicing direct costs 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 remains strong and we have 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.

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        Well servicing direct costs increased $91.0 million, or 14.3%, to $725.0 million for the year ended December 31, 2006, compared to $634.0 million for the year ended December 31, 2005. The overall increase in direct costs is largely attributable to higher activity levels. During the year, direct labor costs increased $83.4 million due primarily to higher compensation-related expenses and higher workers compensation expense. Compensation-related expenses increased due to increased headcount, increased payroll hours and higher wages, all of which are attributable to increased demand for our services. Further, because demand for personnel had been very high due to strong market conditions, we increased wage rates for our employees in order to retain our employees and minimize employee turnover. Equipment costs increased $17.9 million during 2006 due primarily to higher repair and maintenance expense and higher supplies expense. This is the result of increased activity levels. Other direct well servicing costs decreased $10.3 million, which is largely attributable to lower self-insurance-related costs.

Pressure Pumping Services Segment

Revenue

        Pressure pumping services ("PPS") 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 PPS segment revenue.

        PPS segment revenues increased $95.2 million, or 62.5%, to $247.5 million for the year ended December 31, 2006, compared to revenue of $152.3 million for the year ended December 31, 2005. The increase in revenue is attributable to the purchase of incremental pressure pumping equipment, higher activity levels and higher pricing for our services. Over the course of 2006 and 2005 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 2006. During 2006, we completed 1,585 fracturing jobs and 1,958 cementing jobs as compared to 1,329 and 1,558, respectively, in 2005. Fracturing and cementing jobs accounted for the substantial majority of the PPS segment revenues.

Direct Costs

        Direct costs as a percent of total PPS segment revenue worsened to 63.4% for the year ended December 31, 2007, compared to 55.9% for the year ended December 31, 2006. Direct costs as a percent of total PPS segment revenue improved to 55.9% for the year ended December 31, 2006, compared to 60.6% for the year ended December 31, 2005.

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        PPS direct costs 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 costs 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.

        PPS direct costs increased $46.1 million, or 49.9%, to $138.4 million for the year ended December 31, 2006, compared to $92.3 million for the year ended December 31, 2005. The increase in direct costs is largely attributable to costs associated with increased demand for pressure pumping services and the increased size of our pressure pumping fleet. During 2006, direct labor costs increased $9.5 million due primarily to higher compensation-related expenses and higher contract labor costs. Compensation-related expenses increased due to increased headcount, increased payroll hours and higher wages, all of which are attributable to increased demand for our services. Further, because of the expansion of our pressure pumping fleet, we hired additional personnel to operate the new equipment, and because demand for personnel had been high due to strong market conditions, we increased wage rates in order to retain our employees. Equipment costs increased $12.5 million in 2006 due primarily to higher repair and maintenance expense, higher fuel expense and higher supplies expense. These increases are all the result of increased activity levels and the expansion of our pressure pumping fleet. Other direct pressure pumping costs increased $24.1 million. This increase is due primarily to higher sand and chemical product purchases, as well as higher freight costs.

Fishing and Rental Services Segment

Revenue

        Fishing and rental services ("FRS") 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.

        FRS segment revenue increased $15.8 million, or 19.3%, to $97.5 million for the year ended December 31, 2006, compared to revenue of $81.7 million for the year ended December 31, 2005. The increase in revenue is due to higher activity levels and improved pricing for our services. In addition, the FRS segment benefited from the implementation of our management team's turnaround efforts which began during 2005.

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Direct Costs

        Direct costs as a percent of total FRS segment revenue improved to 58.5% for the year ended December 31, 2007, compared to 58.7% for the year ended December 31, 2006. Direct costs as a percent of total FRS segment revenue improved to 58.7% for the year ended December 31, 2006, compared to 66.0% for the year ended December 31, 2005.

        FRS direct costs 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.

        FRS direct costs increased $3.3 million, or 6.2%, to $57.2 million for the year ended December 31, 2006, compared to $53.9 million for the year ended December 31, 2005. The increase in direct costs is largely attributable to increased demand for our services. During the year, direct labor costs increased $4.2 million from the prior year. The FRS segment recorded higher labor costs due to higher activity levels, and incentive payments increased due to improved financial performance. Equipment costs were essentially flat, declining by $0.2 million while other direct costs decreased $0.7 million.

Liquidity and Capital Resources

Historical Cash Flows

        The following table summarizes our cash flows for the years ended December 31, 2007 and 2006:

 
   Year Ended December 31,
  
 
   2007
   2006
  
 
   (in thousands)

  
Net cash provided by operating activities   $ 249,919   $ 258,724  
Cash paid for capital expenditures     (212,560 )   (195,830 )
Cash paid for acquisitions, net of cash acquired     (157,955 )   —  
Cash paid for short-term investments     (121,613 )   (83,769 )
Cash proceeds received from sales of short-term investments     183,177     22,294  
Other investing activities     6,104     11,658  
Repayments of long-term debt and capital leases     (424,751 )   (16,975 )
Borrowings of long-term debt, net of cash paid for debt issuance costs     461,600     (479 )
Cash paid to repurchase common stock     (30,454 )   (1,180 )
Proceeds received from exercises of stock options     13,444     —  
Other financing activities     3,401     —  
Effect of exchange rates on cash     (184 )   (238 )
   
 
 
Net decrease in cash and cash equivalents   $ (29,872 ) $ (5,795 )
   
 
 

Sources of Liquidity

        Our sources of liquidity include our current cash and short-term investments, availability under our 2007 Senior Secured Credit Facility and internally generated cash flow from operations. During 2007, we refinanced our indebtedness. We issued $425.0 million of Notes and entered into the 2007 Senior Secured Credit Facility. The Notes, which have a coupon of 8.375%, require no prepayment and mature in 2014. The 2007 Senior Secured Credit Facility consists 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

47


which mature no later than 2012. As of December 31, 2007, we had $288.9 million available for borrowing under the 2007 Senior Secured Credit Facility. Approximately $50.0 million in borrowings were outstanding under the revolving credit facility, and $61.1 million of letters of credit, issued under the letter of credit sub-facility, were outstanding, which also reduces the availability under the 2007 Senior Secured Credit Facility. We believe that our liquidity position is strong. Our debt totaled $524.0 million as of December 31, 2007, and we believe that this amount is acceptable given our recent financial performance and our belief that industry activity levels in 2008 should remain stable.

Cash Requirements

        During 2008, we anticipate our cash requirements to include working capital needs, capital expenditures, acquisitions and the repurchase of shares of our common stock. We believe that our current reserves of cash and short-term investments, our availability under our 2007 Senior Secured Credit Facility and our internally generated cash flow from operations are sufficient to finance the cash requirements of our current and future operations, including our 2008 capital expenditure budget. We do not budget for acquisitions; however, we are continually evaluating opportunities that fit our specific acquisition profile. We expect to finance acquisitions through a combination of cash on hand, cash flow from operations and borrowings under our 2007 Senior Secured Credit Facility. In some limited cases, however, we may elect to use equity as a financing tool.

        We anticipate that our capital expenditures in 2008, excluding acquisitions, will be approximately $175.0 million. For the past three years we have devoted significant amounts of our cash flow from operations to support organic growth. From the beginning of 2005 through December 31, 2007, we have cumulatively invested approximately $526.5 million in our rig fleet and equipment, excluding acquisitions. Capital expenditures during the year ended December 31, 2007 were $212.6 million, excluding acquisitions.

        In October 2007, our board authorized us to repurchase up to $300.0 million of our outstanding common stock. We may from time to time repurchase shares of our common stock depending on the price of the stock, our liquidity and other considerations. During the year ended December 31, 2007, we repurchased approximately 2.3 million shares of our common stock for $32.2 million through our stock repurchase program. The 2007 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 if our debt to capitalization ratio is below 50%. As of December 31, 2007, we would have been permitted to make share repurchases in excess of $200.0 million.

        From time to time we acquire businesses that improve our footprint in certain geographic areas, increase our range of products or services or are otherwise strategic to our business. During the year ended December 31, 2007, we used approximately $158.0 million in cash (net of cash acquired) and $22.5 million in notes payable, in business acquisitions.

Outstanding Indebtedness and Working Capital as of December 31, 2007

        Our primary debt obligations, other than capital lease obligations and the notes payable incurred in the acquisition of Moncla, as of December 31, 2007, consisted of $425.0 million outstanding principal amount of the Notes and $50.0 million of borrowings under the 2007 Senior Secured Credit Facility.

        As of December 31, 2007, we had net working capital (excluding the current portion of long-term debt and capital lease obligations of $12.4 million) of $265.5 million, which includes cash, cash equivalents and short-term investments of $58.8 million, as compared to net working capital (excluding the current portion of long-term debt and capital lease obligations of $15.7 million) of $281.2 million, which includes cash and cash equivalents and short-term investments of $150.1 million, as of December 31, 2006. Our working capital declined from December 31, 2006 to December 31, 2007 primarily as a result of using cash for our acquisitions in the fourth quarter of 2007.

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Contractual Obligations

        Set forth below is a summary of our contractual obligations as of December 31, 2007. 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 (in thousands)
 
   Total
   Less than
1 Year
(2008)
   1 - 3 Years
(2009 - 2011)
   4 - 5 Years
(2012 - 2013)
   After 5 Years
(2014 +)
8.375% Senior Notes due 2014   $ 425,000   $ —   $ —   $ —   $ 425,000
Interest associated with 8.375% Senior Notes due 2014     249,361     35,693     106,785     71,288     35,595
Borrowings under 2007 Senior Secured Credit Facility     50,000     —     —     50,000     —
Interest associated with 2007 Senior Secured Credit Facility(1)     16,015     3,242     9,699     3,074     —
Commitment and availability fees associated with 2007 Senior Secured Credit Facility     22,266     4,453     13,360     4,453     —
Notes payable—related party, excluding discount     22,500     2,000     18,500     2,000     —
Interest associated with notes payable—related party(1)     2,611     1,079     1,437     95     —
Capital lease obligations, excluding interest and executory costs     26,815     10,701     15,879     235     —
Interest and executory costs associated with capital lease obligations(1)     4,838     2,441     2,388     9     —
Non-cancellable operating leases     24,224     7,428     11,111     3,030     2,655
Severance liabilities and retention payments     1,970     831     1,104     27     8
FIN 48 liabilities     6,751     782     4,039     1,930     —
Equity-based compensation liability awards     5,386     1,775     3,611     —     —
Earnout payments(2)     25,000     5,000     15,000     5,000     —
   
 
 
 
 
Total   $ 882,737   $ 75,425   $ 202,913   $ 141,141   $ 463,258
   
 
 
 
 
(1)
Interest costs on our floating rate debt were estimated using the rate in effect at December 31, 2007.

(2)
These amounts assume certain performance targets will be achieved.

Senior Notes

        On November 29, 2007, we issued $425.0 million aggregate principal amount of 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 Notes were priced at 100% of their face value to yield 8.375%. Net proceeds, after deducting initial purchasers' discounts and estimated 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 the 2005 Senior Secured Credit Facility, with the balance used for general corporate purposes. The 2005 Senior Secured Credit Facility was terminated in connection with our entry into the 2007 Senior Secured Credit Facility described below.

        The Notes are general unsecured senior obligations of Key. Accordingly, they will rank effectively subordinate to all of our existing and future secured indebtedness. The 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 Notes is payable on June 1 and December 1 of each year, beginning June 1, 2008. The Notes mature on December 1, 2014.

        On or after December 1, 2011, the 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

49


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
   Percentage
  
2011   104.188 %
2012   102.094 %
2013   100.000 %

        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 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 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 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 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 Notes the opportunity to sell to us their 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 Notes. The Indenture limits our ability to, among other things:


        These covenants are subject to certain exceptions and qualifications. In addition, substantially all of the covenants will terminate before the Notes mature if one of two specified ratings agencies assigns the 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 Notes later falls below an investment grade rating.

        In connection with the sale of the Notes, we entered into a registration rights agreement with the initial purchasers, pursuant to which we have agreed to file an exchange offer registration statement with the SEC with respect to an offer to exchange the Notes for substantially identical notes that are 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. Additionally, we have agreed to commence the registered exchange offer and to use our reasonable best efforts to issue, on or prior to the date that is 60 days after the date on which the exchange offer registration statement became effective, exchange notes in exchange for all Notes tendered prior thereto in the registered exchange

50


offer. Under some circumstances, in lieu of a registered exchange offer, we have agreed to file a shelf registration statement to cover resales of the Notes by certain holders thereof and to use reasonable best efforts to keep the shelf registration statement effective for a period of at least two years or such shorter period ending on the earlier of when all of the Notes available for sale thereunder (i) have been sold pursuant thereto and (ii) are no longer restricted securities (as defined in Rule 144 under the Securities Act, or any successor rule thereof). We are required to pay additional interest if we fail to comply with our obligations to register the Notes within the specified time periods.

2007 Senior Secured Credit Facility

        Simultaneously with the closing of the offering of the Notes, we entered into a new credit agreement (the "Credit Agreement") with the several lenders 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. The Credit Agreement provides for a senior secured credit facility (the "2007 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. The 2007 Senior Secured Credit Facility and the obligations thereunder are secured by substantially all of the assets of the Company and the Guarantors, and are or will be guaranteed by certain of our existing and future domestic subsidiaries. The 2007 Senior Secured Credit Facility replaced our 2005 Senior Secured Credit Facility, which was terminated in connection with the closing of the offering of the Notes.

        The interest rate per annum applicable to the 2007 Senior Secured Credit Facility is, at our 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, depending upon our consolidated leverage ratio.

        The 2007 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 our 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 2007 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 2007 Senior Secured Credit Facility, the consolidated leverage ratio does not exceed 2.75 to 1.00, we are in compliance with the consolidated interest coverage ratio and we have at least $25 million of availability under the 2007 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 our 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 2007 Senior Secured Credit Facility permits share repurchase 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%.

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        We may prepay the 2007 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.

Moncla Notes Payable

        In connection with the acquisition of Moncla we entered into two notes payable with its former owners. 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 date, 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 bear interest at the Federal Funds rate adjusted annually on the anniversary of the closing date.

2005 Senior Secured Credit Facility

        On July 29, 2005, we entered into a $547.3 million credit agreement (the "2005 Senior Secured Credit Facility"), among Key Energy Services, Inc., as Borrower, the several lenders from time to time party thereto, Lehman Brothers Inc., as sole lead arranger and sole book runner, Lehman Commercial Paper Inc., as syndication agent, administrative agent and as collateral agent, and Wells Fargo Foothill, Inc., as revolving administrative agent. The 2005 Senior Secured Credit Facility consisted of (i) a revolving credit facility of up to an aggregate principal amount of $65.0 million, which was to mature on July 29, 2010, (ii) a senior term loan facility in the original aggregate amount of $400.0 million, which was payable in quarterly installments of $1.0 million each commencing March 31, 2006 with the unpaid balance due on June 30, 2012 and (iii) a prefunded letter of credit facility in the aggregate amount of $82.25 million, which was to mature on July 29, 2010. The revolving credit facility included a $25.0 million sub-facility for additional letters of credit. The 2005 Senior Secured Credit Facility was terminated on November 29, 2007 in connection with us entering into the 2007 Senior Secured Credit Facility.

Lease Agreements

        We lease equipment, such as tractors, trailers, frac tanks and forklifts, from financial institutions under master lease agreements. Under the master lease agreements, the Company is required to provide current annual and quarterly reports. Because we were unable to provide audited financial statements for the year ended December 31, 2003 that complied with SEC rules, we are not in compliance with the terms of these equipment leases. We had previously sought and received waivers from these financial institutions, but we do not intend to seek any additional waivers. The equipment lessors may demand that the leases be repaid. No formal demands for repayment have been made by the lessors and the defaults do not otherwise affect the terms of our 2007 Senior Secured Credit Facility or the terms of the 2005 Senior Secured Credit Facility. As of December 31, 2007, there was approximately $2.7 million outstanding under such equipment leases.

Registration Statements

        As a result of our failure to timely file annual or quarterly reports with the SEC over the last several years, we do not have an effective shelf registration statement on file. Until we have timely filed all of our SEC reports for at least one year, our access to the public securities markets will be limited. See Item 1A. "Risk Factors" for a discussion of limitations on our ability to use "short-form" registration statements.

Off-Balance Sheet Arrangements

        At December 31, 2007 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

52


financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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 Chief Financial Officer.

        The process and preparation of our financial statements in conformity with 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 statement of cash flows:

Workers' Compensation, Vehicular Liability and Other 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 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

53


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 Statement of Financial Accounting Standards 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.

        Under the provisions of Statement of Financial Accounting Standards No. 143 "Accounting for Asset Retirement Obligations," 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 Statement of Financial Accounting Standards 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

54


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 Item 8. "Consolidated Financial Statements and Supplementary Data," Note 10—"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.

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 generally 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 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 Tangible and Intangible Assets

        On at least an annual basis as required by Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" and as required by Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," we review

55


long-lived assets, such as well-service rigs, drilling rigs, pressure pumping equipment, heavy duty trucks, investments, goodwill and identified intangible assets to evaluate whether our long-lived assets or goodwill may have been impaired.

        Impairment tests may be required annually, as with goodwill, or as management identifies certain trigger events such as negative industry or economic trends, changes in our business strategy, and underperformance relative to historical or projected operating results. 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 or, in the case of goodwill, to our reporting units. 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.

Valuation of Equity-Based Compensation

        We account for stock based compensation under the provisions of Statement of Financial Accounting Standards 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 Item 8. "Consolidated Financial Statements and Supplementary Data," Note 16—"Equity-Based Compensation" 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, 2007, 2006 and 2005:

 
   Year Ended December 31,
  
 
   2007
   2006
   2005
  
Risk-free interest rate   4.41 % 4.70 % 3.80 %
Expected life of options, years   6   6   6  
Expected volatility of the Company's stock price   39.49 % 48.80 % 53.85 %
Expected dividends   none   none   none  

        We calculate the expected volatility for our stock option grants by measuring the volatility of our historical stock price for a period equal to the expected life of the option and ending at the time the option was granted. We determine the risk-free interest rate based upon the interest rate on a U.S. Treasury Bill with a term equal to the expected life of the option at the time the option was granted. In estimating the expected lives of our stock options, we have relied primarily on our actual experience

56


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, 2007 by approximately $0.1 million and $0.2 million, respectively.

New Accounting Standards Affecting this Report

        FIN 48 and FSP FIN 48-1.    In June 2006, the Financial Accounting Standard Board ("FASB") issued "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 FIN 48-1, "Definition of a Settlement in FASB Interpretation No. 48 ("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. See Note 10—"Income Taxes" for further discussion of the impact of the adoption of these standards.

        FSP EITF 00-19-2.    In December 2006, the FASB issued FASB Staff Position No. 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 FASB Interpretation 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 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"). As of December 31, 2007, 65,000 Warrants had been exercised, leaving 85,000 Warrants outstanding that were exercisable for an aggregate of approximately 1.2 million shares. Under the terms of the Warrants, we are required to maintain an effective registration statement covering the shares of common stock issuable upon exercise. If we are unable to maintain an effective registration statement, we are required to make semiannual liquidated damages payments for periods in which an effective registration statement is not maintained.

57

        Due to our past failure to file our SEC reports in a timely manner, we do not have an effective registration statement covering the Warrants, and have been required to make liquidated damages payments, and will continue to be required to make those payments until such time as we have an effective registration statement on file for exercise of the Warrants or the warrant shares issuable thereunder are eligible for resale without registration pursuant to SEC Rule 144 or otherwise. The requirement to make liquidated damages payments constitutes 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.

Accounting Standards Not Yet Adopted in this Report

        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.

        In February 2008, the FASB issued FASB Staff Position FIN 157-2 ("FSP FIN 157-2"), which delayed the effective date by which companies must adopt the provisions of SFAS 157. FSP FIN 157-2 defers the effective date of SFAS 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The adoption of this standard is not anticipated to have a material impact on our financial position, results of operations, or cash flows.

        SFAS 159.    In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Liabilities, including an amendment of FASB Statement No. 115" ("SFAS 159"). 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 would report unrealized gains and losses on items for which the Fair Value Option has been elected in earnings at each subsequent reporting period. This standard is effective as of the beginning of the first fiscal year that begins after November 15, 2007. We adopted the provisions of this standard on January 1, 2008. 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.

        SFAS 141(R).    In December 2007, the FASB issued SFAS No. 141 (Revised 2007), "Business Combinations" ("SFAS 141(R)"). SFAS 141(R) will significantly change the accounting for business combinations. Under SFAS 141(R), an acquiring entity will be required to recognize all the assets and liabilities assumed in a transaction at the acquisition-date fair value, with limited exceptions. Specific changes in SFAS 141(R) from previously issued guidance include:

58

        SFAS 141(R) also includes new disclosure requirements related to business combinations. This statement applies to all 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, and earlier adoption is prohibited. The Company is still in the process of determining the impact of the adoption of this standard on the Company's financial position, results of operations, and cash flows.

        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 establishes new accounting and reporting standards for the noncontrolling interest (formerly referred to as "minority interests") in a subsidiary and for the deconsolidation of a subsidiary. Specifically, this statement requires the recognition of a noncontrolling interest as equity in the consolidated financial statements and separate from the parent's equity. The amount of net income attributable to a noncontrolling interest will be included in consolidated net income on the face of the income statement. SFAS 160 clarifies that changes in a parent's ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, SFAS 160 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. Such gains or loss will be measured using the fair value of the noncontrolling equity investment on the deconsolidation date. SFAS 160 also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interest. SFAS 160 is effective for fiscal years and interim periods within those fiscal years, beginning on or after December 15, 2008, with early adoption prohibited. The Company is still in the process of determining the impact of the adoption of this standard on the Company's financial position, results of operations and cash flows.

        See Item 8. "Consolidated Financial Statements and Supplementary Data," Note 1—"Organization and Summary of Significant Accounting Policies," for a discussion of accounting pronouncements issued, but not yet adopted and reflected in this report.

Impact of Inflation on Operations

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

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, 2007, our principal debt obligation was our $425.0 million 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 2007 Senior Secured Credit Facility, our capital lease obligations, and our notes payable to the former owners of Moncla all bear interest at variable interest rates, and therefore expose us to interest rate risk.

        As of December 31, 2007, the weighted average interest rate on our outstanding variable-rate debt obligations was 5.9787%. A hypothetical 10% increase in that rate would increase the annual interest expense on those instruments by approximately $0.6 million.

59

Foreign Currency Risk

        As of December 31, 2007, we conduct operations in Argentina and Mexico, and also own a Canadian subsidiary. The functional currency is the local currency for all of these entities, and therefore poses risk to us related to changes in the exchange rate between the U.S. Dollar and the respective local currencies.

        A hypothetical 10% decrease in the value of the U.S. Dollar relative to the value of all of the local currencies for our Argentinean, Mexican and Canadian subsidiaries would increase our net income by approximately $0.3 million. Our net assets would be unaffected by such an decrease because the changes in the value of our foreign subsidiaries' assets and liabilities would be offset by changes in accumulated other comprehensive income.

Equity Risk

        Equity-Based Compensation.    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, 2007 would increase annual compensation expense recognized on these awards by approximately $0.2 million.

        Equity-Method Investment in IROC.    We currently possess a 19.7% ownership interest in IROC, a publicly-traded Canadian company. We exert significant influence over the operations of IROC, but we do not control it. As such, we account for our investment as an equity-method investment under the guidance provided by Accounting Principles Board Opinion ("APB") No. 18, "The Equity Method of Accounting for Investments in Common Stock" ("APB 18").

        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. Such future conditions could therefore result in a determination a decline in fair value is other than temporary. IROC's stock price is currently depressed. If we later determine the decline is other than temporary, we would record a write-down in the carrying value of our asset to the then current fair market value.

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ITEM 8.    Consolidated Financial Statements and Supplementary Data


Key Energy Services, Inc. and Subsidiaries

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 
   Page
Report of Independent Registered Public Accounting Firm   62
Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting   63
Consolidated Balance Sheets   66
Consolidated Statements of Operations   67
Consolidated Statements of Comprehensive Income   68
Consolidated Statements of Cash Flows   69
Consolidated Statements of Stockholders' Equity   70
Notes to Consolidated Financial Statements   71

61


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, 2007 and 2006, 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, 2007. 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 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, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), "Share Based Payments."

        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, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 26, 2008 expressed an adverse opinion on the effectiveness of internal control over financial reporting.

/s/  GRANT THORNTON LLP      

Houston, Texas
February 26, 2008

62


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders of
Key Energy Services, Inc.

        We have audited Key Energy Services, Inc. and subsidiaries (a Maryland corporation) internal control over financial reporting as of December 31, 2007, 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 weaknesses have been identified and included in management's assessment.

63

        In our opinion, because of the effect of the material weaknesses 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, 2007, based on criteria established in Internal Control—Integrated Framework issued by COSO.

64

        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 weaknesses identified above were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2007 consolidated financial statements, and this report does not affect our report dated February 26, 2008, which expressed an unqualified opinion on those consolidated financial statements.

/s/  GRANT THORNTON LLP      

Houston, Texas
February 26, 2008

65


Key Energy Services, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

 
   December 31,
  
 
   2007
   2006
  
ASSETS              
Current assets:              
  Cash and cash equivalents   $ 58,503   $ 88,375  
  Short-term investments     276     61,767  
  Accounts receivable, net of allowance for doubtful accounts of $13,501 and $12,998 at December 31, 2007 and 2006, respectively     343,408     272,382  
  Inventories     22,849     19,505  
  Prepaid expenses     12,997     4,810  
  Deferred tax assets     27,676     35,968  
  Income taxes receivable     15,796     642  
  Other current assets     6,360     5,157  
   
 
 
Total current assets     487,865     488,606  
   
 
 
Property and equipment, gross     1,595,225     1,279,980  
Accumulated depreciation     (684,017 )   (585,689 )
   
 
 
Property and equipment, net     911,208     694,291  
   
 
 
Goodwill     378,550     320,912  
Other intangible assets, net     45,894     3,346  
Deferred financing costs, net     12,117     9,952  
Notes and accounts receivable—related parties     173     287  
Investment in IROC Systems Corp     11,217     10,661  
Other assets     12,053     13,343  
   
 
 
TOTAL ASSETS   $ 1,859,077   $ 1,541,398  
   
 
 

LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
 
 
 
 
Current liabilities:              
  Accounts payable   $ 35,159   $ 15,294  
  Accrued liabilities     183,364     189,570  
  Accrued interest     3,895     2,530  
  Current portion of capital lease obligations     10,701     11,714  
  Current notes payable—related party, net of discount     1,678     —  
  Current portion of long-term debt     —     4,000  
   
 
 
Total current liabilities     234,797     223,108  
   
 
 
Capital lease obligations, less current portion     16,114     14,080  
Notes payable—related party, less current portion     20,500     —  
Long-term debt, less current portion     475,000     392,000  
Workers' compensation, vehicular, health and other insurance claims     43,818     44,617  
Deferred tax liabilities     160,068     115,826  
Other non-current accrued liabilities     19,531     21,256  
Minority interest     251     —  

Commitments and contingencies
 
 
 
 
 
 
 

Stockholders' equity:
 
 
 
 
 
 
 
  Common stock, $0.10 par value; 200,000,000 shares authorized, 131,142,905 and 131,624,038 shares issued and outstanding at December 31, 2007 and 2006, respectively     13,114     13,162  
  Additional paid-in capital     704,644     711,798  
  Accumulated other comprehensive loss     (37,981 )   (36,284 )
  Retained earnings     209,221     41,835  
   
 
 
Total stockholders' equity     888,998     730,511  
   
 
 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY   $ 1,859,077   $ 1,541,398  
   
 
 

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

66


Key Energy Services, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

 
   Year Ended December 31,
  
 
   2007
   2006
   2005
  
REVENUES:                    
  Well servicing   $ 1,264,797   $ 1,201,228   $ 956,457  
  Pressure pumping     299,348     247,489     152,320  
  Fishing and rental     97,867     97,460     81,667  
   
 
 
 
Total revenues     1,662,012     1,546,177     1,190,444  
   
 
 
 

COSTS AND EXPENSES:
 
 
 
 
 
 
 
 
 
 
  Well servicing     738,694     725,008     634,043  
  Pressure pumping     189,645     138,377     92,301  
  Fishing and rental     57,275     57,217     53,899  
  Depreciation and amortization     129,623     126,011     111,888  
  General and administrative     230,396     195,527     151,303  
  Interest expense, net of amounts capitalized     36,207     38,927     50,299  
  Loss on early extinguishment of debt     9,557     —     20,918  
  Loss (gain) on sale of assets, net     1,752     (4,323 )   (656 )
  Interest income     (6,630 )   (5,574 )   (2,713 )
  Other (income) expense, net     (447 )   527     (5,236 )
   
 
 
 
Total costs and expenses, net     1,386,072     1,271,697     1,106,046  
   
 
 
 
Income from continuing operations before income taxes     275,940     274,480     84,398  
Income tax expense     (106,768 )   (103,447 )   (35,320 )
Minority interest     117     —     —  
   
 
 
 
INCOME FROM CONTINUING OPERATIONS     169,289     171,033     49,078  
   
 
 
 
Loss from discontinued operations, net of income tax expense of $4,590     —     —     (3,361 )
   
 
 
 
NET INCOME   $ 169,289   $ 171,033   $ 45,717  
   
 
 
 

EARNINGS (LOSS) PER SHARE:
 
 
 
 
 
 
 
 
 
 
  Net income from continuing operations:                    
  Basic   $ 1.29   $ 1.30   $ 0.37  
  Diluted   $ 1.27   $ 1.28   $ 0.37  
 
Discontinued operations, net of tax:
 
 
 
 
 
 
 
 
 
 
  Basic   $ —   $ —   $ (0.03 )
  Diluted   $ —   $ —   $ (0.03 )
 
Net income:
 
 
 
 
 
 
 
 
 
 
  Basic   $ 1.29   $ 1.30   $ 0.34  
  Diluted   $ 1.27   $ 1.28   $ 0.34  

WEIGHTED AVERAGE SHARES OUTSTANDING:
 
 
 
 
 
 
 
 
 
 
  Basic     131,194     131,332     131,075  
  Diluted     133,551     134,064     133,595  

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

67


Key Energy Services, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

 
   Year Ended December 31,
  
 
   2007
   2006
   2005
  
NET INCOME   $ 169,289   $ 171,033   $ 45,717  

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
 
 
 
 
 
 
 
 
 
 
  Foreign currency translation loss     (1,281 )   (51 )   (206 )
  Deferred gain from cash flow hedges     —     213     —  
  Deferred (loss) gain from short-term investments     (22 )   181     —  
   
 
 
 
COMPREHENSIVE INCOME, NET OF TAX   $ 167,986   $ 171,376   $ 45,511  
   
 
 
 

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

68


Key Energy Services, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 
   Year Ended December 31,
  
 
   2007
   2006
   2005
  
CASH FLOWS FROM OPERATING ACTIVITIES:                    
  Net income   $ 169,289   $ 171,033   $ 45,717  
  Adjustments to reconcile net income to net cash provided by operating activities:                    
    Minority interest     (117 )   —     —  
    Depreciation and amortization     129,623     126,011     111,888  
    Accretion of asset retirement obligations     585     508     511  
    Income from equity-method investment in IROC Systems Corp     (387 )   (416 )   (467 )
    Amortization of deferred financing costs, discount and premium     1,680     1,620     1,351  
    Deferred income tax expense     24,613     6,757     13,723  
    Capitalized interest     (5,296 )   (3,358 )   (1,266 )
    Loss (gain) on sale of assets, net     1,752     (4,323 )   (656 )
    Loss on early extinguishment of debt     9,557     —     20,918  
    Stock-based compensation     9,355     6,345     2,787  
    Excess tax benefits from stock-based compensation     (3,401 )   —     —  
  Changes in working capital:                    
    Accounts receivable, net     (44,712 )   (60,801 )   (21,560 )
    Stock-based compensation liability awards     3,701     —     —  
    Other current assets     (424 )   976     5,836  
    Accounts payable, accrued interest and accrued expenses     (1,360 )   35,138     42,577  
    Income tax refund receivable     (15,154 )   (642 )   —  
    Cash paid for legal settlement     (21,200 )   —     —  
  Other assets and liabilities     (8,185 )   (20,124 )   (16,278 )
  Operating cash flows provided by discontinued operations     —     —     13,757  
   
 
 
 
  Net cash provided by operating activities     249,919     258,724     218,838  
   
 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES:                    
  Capital expenditures—Well Servicing     (135,336 )   (143,080 )   (79,410 )
  Capital expenditures—Pressure Pumping     (51,115 )   (35,513 )   (27,258 )
  Capital expenditures—Fishing and Rental     (19,811 )   (12,953 )   (4,070 )
  Capital expenditures—Other     (6,298 )   (4,284 )   (7,408 )
  Proceeds from sale of fixed assets     8,427     11,658     18,694  
  Proceeds from sale-leaseback transactions     —     —     5,757  
  Acquisitions, net of cash acquired of $2,154     (157,955 )   —     —  
  Cash paid for short-term investments     (121,613 )   (83,769 )   —  
  Proceeds from sales of short-term investments     183,177     22,294     —  
  Acquisition of intangible assets     (2,323 )   —     —  
  Investing cash flows provided by discontinued operations     —     —     60,477  
   
 
 
 
  Net cash used in investing activities     (302,847 )   (245,647 )   (33,218 )
   
 
 
 
CASH FLOWS FROM FINANCING ACTIVITIES:                    
  Repayments of long-term debt     (396,000 )   (4,000 )   (436,999 )
  Proceeds from long-term debt     425,000     —     400,000  
  Borrowings under revolving credit facility     50,000     —     —  
  Payments on revolving credit facility     —     —     (48,000 )
  Repayments of capital lease obligations     (11,316 )   (12,975 )   (13,049 )
  Repayments of debt assumed in acquisitions     (17,435 )   —     —  
  Proceeds paid for debt issuance costs     (13,400 )   (479 )   (13,165 )
  Repurchases of common stock     (30,454 )   (1,180 )   —  
  Proceeds from exercise of stock options     13,444     —     —  
  Excess tax benefits from stock-based compensation     3,401     —     —  
   
 
 
 
  Net cash provided by (used in) financing activities     23,240     (18,634 )   (111,213 )
   
 
 
 
Effect of changes in exchange rates on cash     (184 )   (238 )   (662 )
   
 
 
 
Net (decrease) increase in cash and cash equivalents     (29,872 )   (5,795 )   73,745  
   
 
 
 
Cash and cash equivalents, beginning of period     88,375     94,170     20,425  
   
 
 
 
Cash and cash equivalents, end of period   $ 58,503   $ 88,375   $ 94,170  
   
 
 
 

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

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Key Energy Services, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In thousands)

 
   Common Stock
    
   Accumulated
Other
Comprehensive
Loss
    
    
  
 
   Additional
Paid-In
Capital
   Retained
Earnings
    
  
 
   Shares
   Amount
   Total
  
BALANCE AT DECEMBER 31, 2004   130,791   $ 13,079   $ 703,923   $ (36,421 ) $ (174,915 ) $ 505,666  
  Comprehensive income, net of tax   —     —     —     (206 )   —     (206 )
  Stock-based compensation   543     54     2,826     —     —     2,880  
  Net income   —     —     —     —     45,717     45,717  
   
 
 
 
 
 
 
BALANCE AT DECEMBER 31, 2005   131,334     13,133     706,749     (36,627 )   (129,198 )   554,057  
   
 
 
 
 
 
 
  Comprehensive income, net of tax   —     —     —     343     —     343  
  Common stock purchases   (81 )   (8 )   (1,172 )   —     —     (1,180 )
  Stock-based compensation   371     37     6,181     —     —     6,218  
  Tax benefits from stock-based compensation   —     —     40     —     —     40  
  Net income   —     —     —     —     171,033     171,033  
   
 
 
 
 
 
 
BALANCE AT DECEMBER 31, 2006   131,624     13,162     711,798     (36,284 )   41,835     730,511  
   
 
 
 
 
 
 
  Effect of adoption of FIN 48   —     —     —     —     (1,272 )   (1,272 )
  Effect of adoption of FSP EITF 00-19-2, net of tax   —     —     —     —     (631 )   (631 )
   
 
 
 
 
 
 
Adjusted balance, beginning of year   131,624     13,162     711,798     (36,284 )   39,932     728,608  
   
 
 
 
 
 
 
  Comprehensive income, net of tax   —     —     —     (1,697 )   —     (1,697 )
  Common stock purchases   (2,414 )   (241 )   (33,161 )   —     —     (33,402 )
  Exercise of stock options   1,592     159     13,285     —     —     13,444  
  Exercise of warrants   23     2     (2 )   —     —     —  
  Stock-based compensation   318     32     9,323     —     —     9,355  
  Tax benefits from stock-based compensation   —     —     3,401     —     —     3,401  
  Net income   —     —     —     —     169,289     169,289  
   
 
 
 
 
 
 
BALANCE AT DECEMBER 31, 2007   131,143   $ 13,114   $ 704,644   $ (37,981 ) $ 209,221   $ 888,998  
   
 
 
 
 
 
 

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

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Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The Company

        Key Energy Services, Inc. is a Maryland corporation. References to "Key," the "Company," "we," "our," or "us" are intended to refer to Key Energy Services, Inc. and subsidiaries. We provide a broad array of services including: well servicing, oilfield transportation services, cased-hole electric wireline services, contract drilling services, pressure pumping and well stimulation services and fishing and rental services.

        Key conducts onshore well servicing operations in every major oil and natural gas producing region in the continental United States. We also provide limited drilling services in the Appalachian Basin with our well servicing equipment. We conduct pressure pumping and cementing operations in a number of major domestic producing regions including California, the Permian Basin, the San Juan Basin, the Mid-Continent region and in the Barnett Shale of North Texas. Our fishing and rental services are located primarily in the Gulf Coast and Permian Basin regions of Texas, as well as in California and the Mid-Continent region. We also have limited operations offshore.

        Internationally, we conduct onshore well servicing and contract drilling operations in Argentina and during the second quarter of 2007, we began conducting well servicing operations in the Northern region of Mexico. In September 2007, we acquired Advanced Measurements, Inc. ("AMI"), a privately-held Canadian technology company.

        On October 25, 2007, Key Energy Services, LLC, a Delaware limited liability company and wholly-owned subsidiary of the Company, purchased all of the outstanding shares and membership interests of Moncla Well Service, Inc. and related entities ("Moncla"). In December 2007 we acquired the well servicing assets and related equipment of Kings Oil Tools, a privately-held well servicing company operating in California ("Kings"). See Note 2—"Acquisitions."

Basis of Presentation

        The 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, and (vii) provide allowances for our uncollectible accounts receivable. 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. These reclassifications relate to the recasting of prior periods to conform to a realignment of certain employment positions that were previously reported as a

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)


component of direct expenses and that are now reported as general and administrative. These reclassifications had no effect on previously reported income from continuing operations or net income. The following tables summarize the effects of these reclassifications on previously reported amounts (in thousands):

 
   Year Ended December 31, 2006
 
   Amounts as
Previously
Reported
   Effect of
Reclassifications
   Amounts as
Currently
Reported
Well servicing costs   $ 736,014   $ (11,006 ) $ 725,008
Pressure pumping costs     141,743     (3,366 )   138,377
Fishing and rental costs     60,073     (2,856 )   57,217
General and administrative costs     178,299     17,228     195,527
   
 
 
  Total   $ 1,116,129   $ —   $ 1,116,129
   
 
 
 
 
   Year Ended December 31, 2005
 
   Amounts as
Previously
Reported
   Effect of
Reclassifications
   Amounts as
Currently
Reported
Well servicing costs   $ 635,442   $ (1,399 ) $ 634,043
Pressure pumping costs     92,323     (22 )   92,301
Fishing and rental costs     54,361     (462 )   53,899
General and administrative costs     149,420     1,883     151,303
   
 
 
  Total   $ 931,546   $ —   $ 931,546
   
 
 

        In January 2005 we sold the majority of our contract drilling assets to Patterson-UTI Energy. We present the results of operations and cash flows related to these activities as discontinued operations in our consolidated statements of operations and consolidated statements of cash flows for 2005.

        We apply the provisions of EITF 04-10, "Determining Whether to Aggregate Operating Segments That Do Not Meet Quantitative Thresholds" ("EITF 04-10") for our segment reporting in Note 18—"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. We account for our interest in entities for which we do not have significant control or influence under 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.

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Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        As further discussed in Note 2—"Acquisitions," 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, Advanced Flow Technologies, Inc. ("AFTI"). As part of the acquisition, AMI increased its ownership percentage of AFTI to 51.46%. We now consolidate 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.

        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.

Revenue Recognition

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

        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 Presentation)" ("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.

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

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1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)


arrangements. However, at December 31, 2007, all of our obligations under the 2007 Senior Secured Credit Facility (hereinafter defined) 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. As of December 31, 2007, approximately $9.3 million of our cash and cash equivalents was held in bank accounts located in foreign countries, representing approximately 15.9% of total cash and cash equivalents. Of the total amount held in foreign bank accounts as of December 31, 2007, approximately $4.4 million was located in Argentina, $0.3 million was located in Canada, and approximately $4.5 million was held in Mexico, with the remaining $0.1 million located in other countries.

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.

        As of December 31, 2007 and 2006, the Company had no investments in debt or equity securities that were classified as "trading" or "held to maturity." In the third quarter of 2006, the Company began investing in Auction-Rate Securities ("ARS") and Variable-Rate Demand Notes ("VRDN"). These are investments in long-term bonds whose returns are tied to short-term interest rates that are periodically reset, with periods ranging from 7 days to 6 months. As a result of the long-term nature of the underlying security (bonds with contractual lives ranging from 20 to 30 years), the Company accounts for ARS and VRDN investments as "available for sale" securities. As of December 31, 2007 and 2006, the aggregate value of our investments in ARS and VRDN was zero and $44.4 million, respectively. We sold all of our ARS and VRDN investments during the third quarter of 2007 and used the proceeds to fund part of our acquisition of Moncla (see Note 2—"Acquisitions").

        In addition to the ARS and VRDN investments, the Company also began investing in 270-day commercial paper and certain other bond investments. These instruments are treated as "available for sale" securities and are carried at fair value as short-term investments on the Company's consolidated balance sheets, because their maturity dates are within one year of the date of investment. Any unrealized holding gains or losses on these securities are recorded net of tax as a separate component of stockholders' equity in other comprehensive income until the date of maturity, at which point any gains or losses are reclassified into earnings. We use the specific identification method when determining the amount of realized gain or loss upon the date of maturity. The aggregate fair value of our available for sale investments was approximately $0.3 million and $61.8 million as of December 31, 2007 and 2006, respectively.

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Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Accounts Receivable and Allowance for Doubtful Accounts

        Historically, our credit losses have not been material. 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, "Offsetting of Amounts Related to Certain Contracts, an Interpretation of APB No. 10 and FASB Statement No. 105" ("FIN 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. For all periods presented, no single customer accounted for more than ten percent of our consolidated revenues.

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. Generally, 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.

        The Company leases certain of its operating assets under capital lease obligations whose terms generally run from 55 to 60 months.

        Change in Estimate of Useful Lives.    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 due to recent market conditions. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        The following table identifies the impact of this change in depreciation and amortization expense for the year ended December 31, 2007 (in thousands):

 
   Year Ended
December 31, 2007
  
Depreciation and amortization using prior lives   $ 121,960  
Impact of change     7,663  
   
 
Depreciation and amortization, as reported   $ 129,623  
   
 

Diluted earnings per share using prior lives
 
$
1.33
 
Impact of change on diluted earnings per share     (0.06 )
   
 
Diluted earnings per share, as reported   $ 1.27  
   
 

        As of December 31, 2007, the estimated useful lives of the Company's asset classes are as follows:

Description
   Years
Well service rigs and components   3–15
Oilfield trucks, trailers and related equipment   7–12
Motor vehicles   3–5
Fishing and rental tools   4–10
Disposal wells   15–30
Furniture and equipment   3–7
Buildings and improvements   15–30

Asset Retirement Obligations

        In connection with our well servicing activities, we operate a number of salt water 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.

        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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        Annual amortization of the assets associated with the asset retirement obligations was $0.6 million, $0.5 million and $0.5 million for the years ended December 31, 2007, 2006 and 2005, respectively. A summary of changes in our asset retirement obligations is as follows (in thousands):

Balance at January 1, 2006   $ 9,634  

Additions
 
 
155
 
Costs incurred     (568 )
Accretion expense     508  
Disposals     (107 )
   
 
Balance at December 31, 2006   $ 9,622  
   
 

Additions
 
 
12
 
Costs incurred     (576 )
Accretion expense     585  
Disposals     (345 )
   
 
Balance at December 31, 2007   $ 9,298  
   
 

Long-lived Asset Impairments

        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, and in some cases 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 future cash flows and the determination of fair value for a division involves significant judgment and estimates. During 2007, 2006, and 2005, no trigger events were identified by management.

Capitalized Interest

        Interest is capitalized on the average amount of accumulated expenditures for equipment that is undergoing major modifications and reconstruction prior to being placed into service. Interest is capitalized using an effective interest rate based on related debt until the equipment is placed into service.

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Key Energy Services, Inc. and Subsidiaries

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1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Long-Term Debt

        Gains and Losses on the Early Extinguishment of Debt.    We record gains and losses from the extinguishment of debt as a part of continuing operations. As further discussed in Note 11—"Long-Term Debt," we recognized a loss of approximately $9.6 million during the fourth quarter of 2007 associated with the termination of our 2005 Senior Secured Credit Facility (hereinafter defined). During 2005 we recognized losses on the early extinguishment of debt of approximately $20.9 million in connection with the retirement of our 2003 Senior Secured Credit Facility (hereinafter defined), 6.375% Senior Notes due 2013 and 8.375% Senior Notes due 2008.

        Deferred Financing Costs.    In connection with our long-term debt, we capitalized costs and expenses of approximately $13.4 million, $0.5 million and $13.2 million for the years ended December 31, 2007, 2006 and 2005, respectively. 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. Amortization of deferred financing costs totaled $1.7 million, $1.6 million and $1.4 million for the years ended December 31, 2007, 2006 and 2005, respectively. Unamortized debt issuance costs written off and included in the determination of the gain or loss on the extinguishment of debt were $9.6 million, zero, and $8.0 million for the years ended December 31, 2007, 2006 and 2005, respectively.

Goodwill and Other Intangible Assets

        Goodwill results from business acquisitions 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, "Goodwill and Other Intangible Assets" ("SFAS 142"). Goodwill and other intangible assets not subject to amortization are tested for impairment annually on December 31, or more frequently if events or changes in circumstances indicate that the asset might be impaired. SFAS 142 requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the fair value of the reporting unit's goodwill is determined by allocating the unit's fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination. The amount of impairment for goodwill is measured as the excess of its carrying value over its fair value. We conduct annual impairment assessments, the most recent as of December 31, 2007. The assessments did not result in an indication of goodwill impairment.

        Our major classes of intangible assets subject to amortization under SFAS 142 consist of noncompete agreements, patents and trademarks, customer backlog, customer relationships and developed technology. Amortization expense for our noncompete agreements, patents and trademarks, and developed technology is calculated using the straight-line method over the period of the agreement or the estimated economic useful live of the intangible asset. Intangible assets related to customer relationships are amortized utilizing the estimated pattern of the consumption of the economic benefit over their estimated lives.

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1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Derivative Instruments and Hedging Activities

        The Company applies SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149 ("SFAS 137," "SFAS 138," and "SFAS 149," respectively) 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.

        During the years ended December 31, 2007 and 2006, the Company had interest rate swaps and foreign currency instruments that qualify as derivative instruments under SFAS 133. See Note 9—"Derivative Financial Instruments" for further discussion.

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 from the ordinary course of business are pending against us. Due 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 favor of the plaintiffs. We do not believe that the disposition of any of these items will result in a material adverse impact on our consolidated financial position, results of operations or cash flows. See Note 12—"Commitments and Contingencies" for a description of other currently pending litigation.

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

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1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)


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. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. See Note 12—"Commitments and Contingencies" for further discussion.

Guarantees

        We account for guarantees under FIN No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" ("FIN 45"). In November 2005, the FASB issued FASB Staff Position No. 45-3, "Application of FASB Interpretation No. 45 to Minimum Revenue Guarantees Granted to Business or Its Owners" ("FSP FIN 45-3"). It served as an amendment to FIN 45 by adding minimum revenue guarantees to the list of examples of contracts to which FIN 45 applies. Under FSP FIN 45-3, a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. FSP FIN 45-3 is effective for new minimum revenue guarantees issued or modified on or after January 1, 2006. As of December 31, 2007 and 2006, the Company had no guarantees that were accounted for under the guidance provided by FIN 45 and FSP FIN 45-3.

Income Taxes

        We account for income taxes based upon SFAS No. 109, "Accounting for Income Taxes" ("SFAS 109"). Under SFAS 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.

        We and our eligible subsidiaries file a consolidated U.S. federal income tax return. Certain foreign subsidiaries that are consolidated for financial reporting purposes are not eligible to be included in the consolidated U.S. federal income tax return and are subject to the jurisdiction of a number of taxing authorities. The income earned in the various jurisdictions is taxed on differing bases. 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 file separate income tax returns in the countries in which these foreign subsidiaries operate. We have not made the election as described in Accounting Principles Board ("APB") Opinion No. 23, "Accounting for Income Taxes—Special Areas," that earnings from foreign entities will be reinvested indefinitely. Our foreign subsidiaries had negative earnings and profits as of

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1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)


December 31, 2007 and 2006. Accordingly, no deferred taxes are provided on that subsidiary's current earnings during those years.

        FIN No. 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 No. FIN 48-1, "Definition of a Settlement in FASB Interpretation No. 48" ("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 recognize accrued interest and penalties related to unrecognized tax benefits as a component of income tax expense.

        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. See Note 10—"Income Taxes" for further discussion of the impact of the adoption of these standards.

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 shares of common stock actually outstanding during the year. Diluted earnings per common share is based on the increased number of shares that would be outstanding assuming conversion or exercise of dilutive outstanding securities or stock options using the "as if converted" method. See Note 5—"Earnings Per Share" for further discussion.

Stock-Based Compensation

        We account for stock-based compensation under the provisions of SFAS No. 123 (revised 2004), "Share-Based Payment" ("SFAS 123(R)"), which we adopted on January 1, 2006. Prior to January 1, 2006, we accounted for share-based payments under the provisions of SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"), which allowed companies to continue to use the intrinsic value methods established by APB Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25"). 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 stock-based compensation according to the salary classification of the award recipient, primarily as a component of general and administrative expense.

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1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        SFAS 123 set forth alternative accounting and disclosure requirements for stock-based compensation arrangements. Companies were permitted to continue following the provisions of APB 25 to measure and recognize employee stock-based compensation prior to January 1, 2006; however, SFAS 123 required disclosure of pro forma net income and earnings per share that would have been reported under the fair value recognition provisions of SFAS 123. The table below illustrates the effect on net income and earnings per share if we had applied the fair value recognition principles of SFAS 123 to stock-based employee compensation in 2005. As noted above, while we followed the guidance established by APB 25 to measure stock-based compensation during that year, the stock-based compensation expense included in net income in the table below represents the compensation expense for 875,180 options, net of forfeitures, that were granted in prior years at strike prices ranging from $0.10 to $2.53 below the market price of our common stock on the date of grant. During the years in which we applied APB 25, we elected to amortize any compensation cost on a straight-line basis over the vesting period of the award, in accordance with FIN No. 28, "Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans, an Interpretation of APB Opinions No. 15 and 25" ("FIN 28"). After the adoption of SFAS 123(R), we elected to amortize compensation cost associated with the fair value of equity-based awards over the vesting period of the award based on graded vesting using the straight-line attribution method.

 
   Year Ended
December 31, 2005
  
 
   (in thousands, except per
share amounts)

  
Net income:        
  As reported   $ 45,717  
 
Add: stock-based compensation expense included in reported net income, net of related tax effects of $955
 
 
1,643
 
 
Deduct: total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects of $1,919
 
 
(2,473
)
   
 
  Pro forma net income   $ 44,887  
   
 

Basic earnings per share:
 
 
 
 
  As reported   $ 0.34  
  Pro forma   $ 0.34  

Diluted earnings per share:
 
 
 
 
  As reported   $ 0.34  
  Pro forma   $ 0.33  

        For additional information regarding the computations presented above, see Note 16—"Equity-Based Compensation."

        In June 2005, the Company began granting shares of common stock to its non-employee directors and restricted stock to certain of its employees. These awards have vesting periods ranging from zero to three years. Subject to the provisions of SFAS 123(R), the Company recognizes expense in earnings related to these awards equal to the fair value of the shares vesting during the period, net of actual and estimated forfeitures.

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1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        In December 2006, the Company began granting "Phantom Shares" to certain of its employees, which vest ratably over a four-year period from the date of grant. The Phantom Shares convey the right to the grantee to receive a cash payment on each anniversary of the grant date equal to the fair market value of the Phantom Shares vesting on that date. Grantees are not permitted to defer the payout to a later date. The Phantom Shares qualify as "liability" awards under SFAS 123(R) and the Company accounts for these awards at fair value, with the fair value of the Phantom Shares recorded as a liability in our consolidated balance sheets. Changes in the fair value of the liability, net of actual and estimated forfeitures, are recorded in earnings as compensation expense.

        In August 2007, the Company issued stock appreciation rights ("SARs") to its executive officers. Each SAR award 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 stockholder rights. The Company accounts for SARs as equity awards under SFAS 123(R) and recognizes compensation expense over the vesting period of the award based on their fair value on the date of issuance, net of estimated and actual forfeitures.

Foreign Currency Gains and Losses

        The local currency is the functional currency for our foreign operations in Argentina, Mexico and Canada. The cumulative translation gains and losses resulting from translating each foreign subsidiary's financial statements from the functional currency to U.S. dollars are included 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 13—"Foreign Currency Translation."

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 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

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1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)


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 Affecting this Report

        FIN 48 and FSP FIN 48-1.    In June 2006, the FASB issued 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 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. See Note 10—"Income Taxes" for further discussion of the impact of the adoption of these standards.

        FSP EITF 00-19-2.    In December 2006, the FASB issued FASB Staff Position No. 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 Securities and Exchange Commission (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 FASB Interpretation 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"). As of

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1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

December 31, 2007, 65,000 Warrants had been exercised, leaving 85,000 Warrants outstanding that were exercisable for an aggregate of approximately 1.2 million shares. Under the terms of the Warrants, we are required to maintain an effective registration statement covering the shares of common stock issuable upon exercise. If we are unable to maintain an effective registration statement, we are required to make semiannual liquidated damages payments for periods in which an effective registration statement is not maintained.

        Due to our past failure to file our SEC reports in a timely manner, we do not have an effective registration statement covering the Warrants, and have been required to make liquidated damages payments, and will continue to be required to make those payments until such time as we have an effective registration statement on file for exercise of the Warrants or the warrant shares issuable thereunder are eligible for resale without registration pursuant to SEC Rule 144 or otherwise. The requirement to make liquidated damages payments constitutes 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.

Accounting Standards Not Yet Adopted in this Report

        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.

        In February 2008, the FASB issued FASB Staff Position FIN 157-2 ("FSP FIN 157-2"), which delayed the effective date by which companies must adopt the provisions of SFAS 157. FSP FIN 157-2 defers the effective date of SFAS 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The adoption of this standard is not anticipated to have a material impact on our financial position, results of operations, or cash flows.

        SFAS 159.    In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Liabilities, including an amendment of FASB Statement No. 115" ("SFAS 159"). 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 would report unrealized gains and losses on items for which the Fair Value Option has been elected in earnings at each subsequent reporting period. This standard is effective as of the beginning of the first fiscal year that begins after November 15, 2007. We adopted the provisions of this standard on January 1, 2008. 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.

        SFAS 141(R).    In December 2007, the FASB issued SFAS No. 141 (Revised 2007), "Business Combinations" ("SFAS 141(R)"). SFAS 141(R) will significantly change the accounting for business combinations. Under SFAS 141(R), an acquiring entity will be required to recognize all the assets and

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Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)


liabilities assumed in a transaction at the acquisition-date fair value, with limited exceptions. Specific changes in SFAS 141(R) from previously issued guidance include:

        SFAS 141(R) also includes new disclosure requirements related to business combinations. This statement applies to all 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, and earlier adoption is prohibited. The Company is still in the process of determining the impact of the adoption of the standard on the Company's financial position, results of operations, and cash flows.

        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 establishes new accounting and reporting standards for the noncontrolling interest (formerly referred to as "minority interests") in a subsidiary and for the deconsolidation of a subsidiary. Specifically, this statement requires the recognition of a noncontrolling interest as equity in the consolidated financial statements and separate from the parent's equity. The amount of net income attributable to a noncontrolling interest will be included in consolidated net income on the face of the income statement. SFAS 160 clarifies that changes in a parent's ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, SFAS 160 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. Such gains or loss will be measured using the fair value of the noncontrolling equity investment on the deconsolidation date. SFAS 160 also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interest. SFAS 160 is effective for fiscal years and interim periods within those fiscal years, beginning on or after December 15, 2008, with early adoption prohibited. The Company is still in the process of determining the impact of the adoption of this standard on the Company's financial position, results of operations, and cash flows.

2. ACQUISITIONS

        On October 25, 2007, we completed our acquisition of Moncla, which operates in Texas, Louisiana, Mississippi, Alabama, and Florida. Collectively, the Moncla assets included daylight rigs for well servicing and workovers and twenty-four hour rigs for shallow drilling, sidetracking and deep workovers. In addition, Moncla operated barge rigs, and owned rig-up, swab, hot oil and anchor trucks, tubing

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. ACQUISITIONS (Continued)

testing units and rental equipment. The Moncla acquisition was made in order to expand our service offerings and meet our customers' service needs in Texas, Louisiana, Mississippi, Alabama and Florida.

        The purchase price for Moncla was approximately $146.0 million, which consisted of net assets acquired of $131.3 million and assumed debt of $14.7 million. Amounts transferred at closing consisted of (i) $108.6 million of cash; (ii) the issuance of an unsecured promissory note for $12.5 million that is payable in a lump sum on October 25, 2009, with accrued interest payable on each anniversary date of the closing of the acquisition; and (iii) the issuance of an unsecured promissory note for $10.0 million that is payable in five annual installments of $2.0 million plus accrued interest on each annual anniversary date of the closing of the acquisition. Both promissory notes bear interest at the Federal Funds rate, adjusted annually on the anniversary of the closing date. The long-term debt assumed in the acquisition was repaid simultaneously with the closing of the transaction. The purchase price is subject to a working capital adjustment, which has not been finalized.

        The Moncla purchase agreement entitles the former owners of Moncla to receive earnout payments, on each of the next five anniversary dates of the closing date of the acquisition, of up to $5.0 million (up to $25.0 million in total). The earnout payments are based on the achievement of certain revenue targets and profit percentage targets over the next five years and are payable upon achieving annual targets or a cumulative target on the fifth anniversary date. These payments represent an additional element of cost of the acquired entity and will be accounted for as an increase to goodwill if and when the contingent payment is made.

        The total purchase price was allocated to Moncla's net tangible and identifiable intangible assets based on their estimated fair values. The excess of the purchase price over the net assets was recorded as goodwill. The preliminary allocation of the purchase price was based upon preliminary valuations and estimates, and these are subject to change as the valuations are finalized. The primary areas of the purchase price allocation which are not yet finalized relate to identifiable intangible assets, completion of the analysis of the acquired tax bases of the assets, and pre-merger contingencies related to environmental exposures. The final valuation of net assets is expected to be completed no later than the fourth quarter of 2008.

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2. ACQUISITIONS (Continued)

        The following table summarizes the preliminary estimated fair values of the assets acquired and liabilities assumed on the date of the acquisition (in thousands):

Cash   $ 1,527
Other current assets     28,633
Property and equipment     101,862
Goodwill     34,339
Intangible assets     28,273
Other assets     271
   
  Total assets acquired     194,905

Current liabilities
 
 
21,548
Long-term debt and capital leases     14,765
Other liabilities     671
Deferred tax liability     26,590
   
  Total liabilities assumed     63,574
   
  Net assets acquired   $ 131,331
   

        The preliminary allocation of the purchase price is based upon the fair values of assets and liabilities acquired. The fair values of property and equipment were determined using a market approach, depending on the asset being valued. The fair values of identified intangible assets were determined using an income approach to measure the present worth of anticipated economic benefits. We also performed an economic obsolescence analysis to confirm the values identified through the above methods. The allocation is still preliminary at this time, and may potentially change by a material amount once purchase accounting is finalized.

        Goodwill was recognized as part of the acquisition of Moncla as the purchase price exceeded the fair value of the acquired assets and liabilities. We believe that the goodwill associated with the Moncla acquisition is related to the acquired workforce and potential future expansion and the ability to expand our service offerings. Therefore, it was not allocated to the assets and liabilities acquired.

        All of the $28.3 million of acquired identified intangible assets is subject to amortization under SFAS 142 and has a weighted-average remaining useful life of approximately nine years. These intangible assets relate to customer relationships of $25.1 million and noncompete agreements of $3.2 million. The noncompete agreements will be amortized to expense on a straight-line basis over the expected duration of the respective agreement. The intangible asset associated with customer relationships will be amortized as the value of the relationships are realized using rates of 6.56%, 31.33%, 19.49%, 12.74%, 8.78%, and 21.10% for 2007, 2008, 2009, 2010, 2011 and the remaining periods, respectively. The $34.3 million of goodwill associated with the purchase of Moncla has been allocated to our well servicing segment; of that amount, approximately $25.6 million is expected to be deductible for income tax purposes.

        The following presents the consolidated financial information for the Company on a pro forma basis, assuming the acquisition of Moncla had occurred as of January 1, 2006. The historical financial information has been adjusted to give effect to pro forma items that are directly attributable to the acquisition and expected to have a continuing impact on the consolidated results. These items include adjustments to record incremental amortization and depreciation expense related to the increase in fair

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2. ACQUISITIONS (Continued)


value of the acquired assets, to reflect change in depreciation methodology, and to reclassify certain items to conform to the Company's financial reporting presentation.

        The unaudited financial information set forth below has been compiled from historical financial statements and other information, but is not necessarily indicative of the results that actually would have been achieved had the transaction occurred on the dates indicated or that may be achieved in the future.

 
   Year Ended December 31,
 
   2007
   2006
 
   As reported
   Proforma
Adjustments
   Proforma
   As reported
   Proforma
Adjustments
   Proforma
 
   (in thousands, except for per share data)
 
   (unaudited)
Revenues   $ 1,662,012   $ 105,341   $ 1,767,353   $ 1,546,177   $ 104,282   $ 1,650,459
Net income   $ 169,289   $ 7,418   $ 176,707   $ 171,033   $ 5,338   $ 176,371

Basic earnings per share
 
$
1.29
 
$
0.06
 
$
1.35
 
$
1.30
 
$
0.04
 
$
1.34
Diluted earnings per share   $ 1.27   $ 0.05   $ 1.32   $ 1.28   $ 0.04   $ 1.32

Kings Oil Tools, Inc.

        On December 7, 2007, the Company acquired the well service assets and related equipment of Kings, a California-based well service company. The acquired assets, all of which are located in California, include 36 marketed well service rigs, 10 stacked well service rigs and related support equipment. We made this acquisition to expand our business in California. Total consideration paid for the transaction was approximately $45.1 million in cash, including transaction-related costs. We analyzed this acquisition as required under SFAS No. 141, "Business Combinations" ("SFAS 141"), and determined that the acquired assets and facts and circumstances of this transaction met the criteria of a "business" as that term is defined under EITF 98-3, "Determining Whether a Nonmonetary Transaction Involves Receipt of Productive Assets or of a Business" ("EITF 98-3"), and have accounted for this asset purchase as a business combination.

        The following table summarizes the preliminary estimated fair values of the assets acquired and liabilities assumed on the date of acquisition (in thousands):

Property and equipment   $ 17,563
Goodwill     18,958
Intangible assets     11,000
   
  Total assets acquired     47,521
   

Current liabilities
 
 
2,400
   
  Net assets acquired   $ 45,121
   

        The preliminary allocation of purchase price to specific assets and liabilities is based upon the fair values of identified assets and liabilities acquired. The fair values of property and equipment was determined for property and equipment using a market or cost approach, depending on the asset being valued. The allocation is still preliminary at this time, and may potentially change by a material amount

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2. ACQUISITIONS (Continued)


as our purchase accounting is finalized. We believe certain customer-related intangibles were also acquired in this purchase and are utilizing an income approach to value these items as we have not completed our analysis and valuation. However, we have not allocated any purchase price to this asset in the financial statements. We anticipate finalizing our allocation of purchase price in the second quarter of 2008, once our valuation of the intangible assets is completed.

        Goodwill has been recognized as part of the acquisition of the assets of Kings as the purchase price exceeded the fair value of the acquired assets and liabilities absent the allocation of value to identified intangible assets. We believe that the goodwill associated with the acquisition is related primarily to the acquired workforce. Therefore, it was not allocated to the assets and liabilities acquired.

        All of the $11.0 million of acquired intangible assets is related to a noncompete agreement and subject to amortization under SFAS 142 and has a weighted-average remaining useful life of 5 years. The $19.0 million of purchase price preliminarily associated with goodwill has been allocated to our well servicing segment. The entire amount is expected to be deductible for income tax purposes. We are not including the pro-forma effect of this acquisition because the impact is not material to our results of operations.

Advanced Measurements, Inc.

        On September 5, 2007, the Company, through a wholly-owned Canadian subsidiary, purchased all of the outstanding shares of AMI, a privately-held Canadian technology company focused on oilfield service equipment controls, data acquisition, and digital information work flow. We made this acquisition in order to improve our access to oilfield services technology.

        The purchase price was approximately $6.6 million in cash and approximately $2.9 million of assumed debt, which was repaid in September and November 2007. The purchase agreement also provided for deferred cash payments of up to $1.8 million related to the retention of key AMI employees. These deferred payments will be recognized as an expense over the period that the services are rendered.

        On the date of acquisition, AMI owned a 48% interest in AFTI, a privately-held Canadian technology company focused on low-cost wireless gas well production monitoring. As part of the purchase of AMI, we were required to exercise an option to increase AMI's interest in AFTI to 51.46%. The cost to exercise this option was approximately $0.5 million. As a result, through our acquisition of AMI we now own a 51.46% interest in AFTI, and we consolidate AFTI into our financial statements, with the remaining 48.54% representing a minority interest.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. ACQUISITIONS (Continued)

        The following table summarizes the preliminary estimated fair values of the assets acquired and liabilities assumed at the date of acquisition (in thousands):

Cash   $ 672
Other current assets     3,240
Property and equipment     388
Goodwill     4,523
Intangible assets     5,894
Other assets     824
   
  Total assets acquired     15,541
   

Current liabilities
 
 
2,246
Long-term debt and capital leases     2,884
Deferred tax liability     2,804
   
  Total liabilities assumed     7,934
Minority interest     357
   
  Net assets acquired   $ 7,250
   

        The preliminary allocation of the purchase price is based upon the fair values of assets and liabilities acquired. The fair values of identified intangible assets were determined using an income approach to measure the present worth of anticipated economic benefits. We also performed a business enterprise valuation to confirm the values identified through the income approach. Goodwill was recognized as part of the acquisition of AMI as the purchase price exceeded the fair value of the acquired assets and liabilities. We believe that the goodwill associated with the AMI acquisition is related to the acquired workforce and the potential future development of technology by this workforce. Therefore, it was not allocated to the assets and liabilities acquired.

        All of the $5.9 million of acquired identified intangible assets is subject to amortization under SFAS 142 and has a weighted-average remaining useful life of approximately 3.6 years. The intangible assets identified relate to developed technology ($4.8 million), customer backlog ($1.0 million) and noncompete agreements ($0.1 million). The $4.5 million of goodwill associated with the purchase has been allocated to our well servicing segment, as the technologies developed are anticipated to benefit these operations; of that amount, none is expected to be deductible for income tax purposes.

        The preliminary allocation of the purchase price was based upon preliminary valuations and estimates, and these are subject to change as the valuations are finalized. The primary areas of the purchase price allocation which are not yet finalized relate to the completion of the analysis of the acquired tax bases of the assets. The final valuation of net assets is expected to be completed no later than the third quarter of 2008.

        In connection with the acquisition of AMI, we also became party to a revolving credit agreement with a maximum outstanding amount of $0.9 million. This facility was extinguished in November 2007, and the outstanding balance was paid with cash.

        We are not including the pro-forma effect of this acquisition because the impact is not material to our results of operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. SUPPLEMENTAL FINANCIAL INFORMATION

 
   December 31,
 
   2007
   2006
 
   (in thousands)
Current accrued liabilities:            
Accrued payroll, taxes and employee benefits   $ 56,744   $ 58,904
Accrued operating expenditures     52,180     41,856
Income, sales, use and other taxes     35,310     30,282
Self-insurance reserves     25,208     24,378
Unsettled legal claims     6,783     28,754
Phantom share liability     2,458     —
Assumed executory contract     1,120     —
Deferred revenue     976     —
Other     2,585     5,396
   
 
  Total   $ 183,364   $ 189,570
   
 
 
 
   December 31,
 
   2007
   2006
 
   (in thousands)
Non-current accrued liabilities:            
Asset retirement obligations   $ 9,298   $ 9,622
Environmental liabilities     3,090     4,683
Accrued rent     2,829     3,241
Accrued income taxes     2,705     2,507
Phantom share liability     896     —
Other     713     1,203
   
 
  Total   $ 19,531   $ 21,256
   
 
 
 
   December 31,
  
 
   2007
   2006
  
 
   (in thousands)

  
Major classes of property and equipment:              
Well servicing equipment   $ 1,200,069   $ 950,952  
Disposal wells     56,576     47,942  
Motor vehicles     112,986     105,858  
Furniture and fixtures     73,032     78,143  
Buildings and land     64,258     58,786  
Work in progress     88,304     38,299  
   
 
 
  Gross property and equipment     1,595,225     1,279,980  
Accumulated depreciation     (684,017 )   (585,689 )
   
 
 
  Net property and equipment   $ 911,208   $ 694,291  
   
 
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. SUPPLEMENTAL FINANCIAL INFORMATION (Continued)

 
 
   December 31,
 
   2007
   2006
 
   (in thousands)
Carrying values of assets leased under capital lease obligations:            
  Well servicing equipment   $ 19,687   $ 23,713
  Motor vehicles     5,938     2,589
   
 
    Total   $ 25,625   $ 26,302
   
 
 
 
   December 31,
  
 
   2007
   2006
  
 
   (in thousands)

  
Deferred financing costs:              
  Gross carrying value   $ 12,262   $ 12,042  
  Accumulated amortization     (145 )   (2,090 )
   
 
 
    Net carrying value   $ 12,117   $ 9,952  
   
 
 
 
 
   Year Ended December 31,
 
   2007
   2006
   2005
 
   (in thousands)
Noncash investing and financing activities:                  
Property and equipment acquired under captial lease obligations   $ 12,003   $ 15,349   $ 18,267
Equity investment in IROC Systems Corp     —     —     9,019
Asset retirement obligations     12     155     119
Unrealized gain on short-term investments     —     328     —
Unrealized gain on cash flow hedges     —     185     —
Capital lease portion of sale-leaseback transactions     —     —     4,663
Deferred gain on sale-leaseback transactions     —     —     1,094
Accrued repurchases of common stock     2,949     —     —
Debt assumed and issued in acquisitions     40,149     —     —

Supplemental cash flow information:
 
 
 
 
 
 
 
 
 
Cash paid for interest   $ 38,457   $ 44,534   $ 54,007
Cash paid for taxes     96,327     99,048     17,156

        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 2005 Senior Secured Credit Facility.

        Included in the 2007 consolidated statement of cash flows are approximately $21.2 million in cash outflows related to the settlement of litigation with our former chief executive officer. The amount was previously accrued for in 2004.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. GOODWILL AND OTHER INTANGIBLE ASSETS

        The following table presents a summarization of the activity in our goodwill accounts for the years ended December 31, 2007 and 2006:

 
   Well Servicing Segment
   Pressure Pumping Segment
   Fishing and Rental Segment
   Total
  
 
   (in thousands)

  
December 31, 2005   $ 254,116   $ 47,905   $ 18,901   $ 320,922  
  Goodwill acquired during period     —     —     —     —  
  Foreign currency translation and other     (10 )   —     —     (10 )
   
 
 
 
 
December 31, 2006   $ 254,106   $ 47,905   $ 18,901   $ 320,912  
   
 
 
 
 
  Goodwill acquired during period     57,820     —     —     57,820  
  Foreign currency translation and other     (182 )   —     —     (182 )
   
 
 
 
 
December 31, 2007   $ 311,744   $ 47,905   $ 18,901   $ 378,550  
   
 
 
 
 

        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, 2007 and 2006:

 
   December 31,
  
 
   2007
   2006
  
 
   (in thousands)

  
Noncompete agreements:              
  Gross carrying value   $ 18,402   $ 9,401  
  Accumulated amortization     (2,772 )   (7,886 )
   
 
 
    Net carrying value   $ 15,630   $ 1,515  
   
 
 
Patents and trademarks:              
  Gross carrying value   $ 4,150   $ 4,296  
  Accumulated amortization     (2,526 )   (2,465 )
   
 
 
    Net carrying value   $ 1,624   $ 1,831  
   
 
 
Customer relationships:              
  Gross carrying value   $ 25,139   $ —  
  Accumulated amortization     (1,649 )   —  
   
 
 
    Net carrying value   $ 23,490   $ —  
   
 
 
Customer backlog:              
  Gross carrying value   $ 999   $ —  
  Accumulated amortization     (214 )   —  
   
 
 
    Net carrying value   $ 785   $ —  
   
 
 
Developed technology:              
  Gross carrying value   $ 4,762   $ —  
  Accumulated amortization     (397 )   —  
   
 
 
    Net carrying value   $ 4,365   $ —  
   
 
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. GOODWILL AND OTHER INTANGIBLE ASSETS (Continued)

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

 
   Year Ended December 31,
 
   2007
   2006
   2005
 
   (in thousands)
Noncompete agreements   $ 1,919   $ 2,202   $ 2,955
Patents and trademarks     774     713     642
Customer relationships     1,649     —     —
Customer backlog     210     —     —
Developed technology     389     —     —
   
 
 
  Total intangible asset amortization expense   $ 4,941   $ 2,915   $ 3,597
   
 
 

        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)
   Expected Amortization Expense
 
   2008
   2009
   2010
   2011
   2012
 
    
   (in thousands)
Noncompete agreements   4.8   $ 4,091   $ 3,192   $ 2,622   $ 2,606   $ 2,389
Patents and trademarks   2.9     724     449     233     163     55
Customer relationships   9.8     7,877     4,900     3,201     2,208     1,648
Customer backlog   3.3     268     194     194     129     —
Developed technology   3.7     1,191     1,191     1,191     792     —
       
 
 
 
 
  Total       $ 14,151   $ 9,926   $ 7,441   $ 5,898   $ 4,092
       
 
 
 
 

        Included in capitalized costs associated with noncompete agreements during 2007 is approximately $1.8 million related to a two-year noncompete agreement with our former chief executive officer. Through December 31, 2007, amortization of this noncompete agreement was approximately $0.4 million. This noncompete agreement expires on July 1, 2009.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. EARNINGS PER SHARE

        The following table presents our basic and diluted earnings per share for the years ended December 31, 2007, 2006 and 2005:

 
   Year Ended December 31,
  
 
   2007
   2006
   2005
  
 
   (in thousands, except per share data)

  
Basic Earnings per Share Computation:                    
Numerator                    
  Income from continuing operations   $ 169,289   $ 171,033   $ 49,078  
  Discontinued operations, net of tax     —     —     (3,361 )
   
 
 
 
  Net income   $ 169,289   $ 171,033   $ 45,717  
   
 
 
 
Denominator                    
  Weighted average shares outstanding     131,194     131,332     131,075  

Basic Earnings per Share:
 
 
 
 
 
 
 
 
 
 
  Income from continuing operations   $ 1.29   $ 1.30   $ 0.37  
  Discontinued operations, net of tax     —     —     (0.03 )
   
 
 
 
  Net income   $ 1.29   $ 1.30   $ 0.34  
   
 
 
 
Diluted Earnings per Share Computation:                    
Numerator                    
  Income from continuing operations   $ 169,289   $ 171,033   $ 49,078  
  Discontinued operations, net of tax     —     —     (3,361 )
   
 
 
 
  Net income   $ 169,289   $ 171,033   $ 45,717  
   
 
 
 
Denominator                    
  Weighted average shares outstanding     131,194     131,332     131,075  
  Dilutive effect from stock options     1,518     2,180     2,017  
  Dilutive effect from unvested restricted stock     256     —     —  
  Dilutive effect from warrants     565     552     503  
  Dilutive effect from stock appreciation rights     18     —     —  
   
 
 
 
      133,551     134,064     133,595  
   
 
 
 
Diluted Earnings per Share:                    
  Income from continuing operations   $ 1.27   $ 1.28   $ 0.37  
  Discontinued operations, net of tax     —     —     (0.03 )
   
 
 
 
  Net income   $ 1.27   $ 1.28   $ 0.34  
   
 
 
 

        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, 2007, 2006 and 2005 excludes options to purchase 495,875, 381,750 and 266,875 shares of the Company's common stock at weighted average exercise prices of $14.78, $15.08, and $12.88,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. EARNINGS PER SHARE (Continued)


respectively, because their exercise prices exceeded the average price of the Company's stock during those years and would therefore be anti-dilutive.

6. SALE-LEASEBACK TRANSACTIONS

        We lease certain equipment such as tractors, trailers, frac tanks and forklifts from financial institutions under master lease agreements. Under our former master lease agreements, we were required to provide current annual and quarterly financial reports to the lessors. Due to our inability to provide audited financial statements for the year ended December 31, 2003 and subsequent periods, we were required to seek waivers and amendments from our equipment lessors or pay off the outstanding leases. Some lessors refused to grant these waivers and demanded settlement of the obligation and our purchase of the equipment.

        We entered into two new master lease agreements on August 31, 2005 and October 14, 2005 with a new lessor. Some of the equipment, which was being leased from lessors that demanded settlement, was sold to this new lessor and subsequently leased back from that lessor, which we account for as capital leases. We received an aggregate amount of $5.8 million in proceeds from the sale-leaseback transactions. We realized a gain of $1.1 million on one of the sale-leaseback transactions, which is being amortized over the term of the new lease. Amounts recognized in earnings related to the amortization of this deferred gain were $0.2 million, $0.2 million and $0.1 million for the years ended December 31, 2007, 2006 and 2005, respectively. On the other sale-leaseback transaction, we realized a loss of less than $0.1 million, which was immediately recognized in earnings.

7. INVESTMENT IN IROC ENERGY SERVICES CORP.

        On July 22, 2004, we entered into an agreement (the "IROC Agreement") with IROC Energy Services Corp., an Alberta-based oilfield services company ("IROC"), to sell IROC ten remanufactured Skytop well service rigs, along with supporting equipment and inventory. We began delivery of the rigs in the fall of 2004, and these rigs are operated by IROC in Western Canada. The purchase price for the rigs was $7.0 million USD. This amount was converted at an agreed exchange rate of 0.7634 to $9.17 million CDN, and was paid by way of the issuance of 8,187,058 common shares of IROC stock at a deemed issuance price of $1.12 CDN per share. The final four rigs were delivered in 2005, and we recognized a gain of $1.9 million upon delivery, which represents the difference between the aggregate carrying value of the delivered rigs and the fair market value on the delivery date of the IROC shares we received as consideration for those four rigs.

        In July 2005, we sold additional well service rig support equipment to IROC for $0.9 million USD. This amount was converted at an agreed exchange rate of 0.7937 to $1.1 million CDN, and was paid by way of the issuance of 547,411 shares of IROC common stock (the "Additional Shares") at a deemed issuance price of $2.09 CDN per share. We recognized a gain of $0.7 million related to this transaction, which represents the difference between the carrying value of the transferred equipment and the fair value of the Additional Shares on the transaction date.

        As of December 31, 2007, we owned approximately 8.7 million shares of IROC common stock, which represents approximately 19.7% of IROC's shares on that date. On September 15, 2005, IROC completed a private placement of a series of unsecured non-convertible debentures, which also included 1,050,000 warrants to purchase common shares of IROC. Exercises of these warrants are potentially dilutive of Key's ownership percentage in IROC. IROC shares trade on the Toronto Venture Stock

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. INVESTMENT IN IROC ENERGY SERVICES CORP. (Continued)


Exchange and had a closing price of $0.74 CDN per share on December 31, 2007. Pursuant to the terms of the IROC Agreement, Mr. William Austin, our Chief Financial Officer, and Mr. Newton W. Wilson III, our General Counsel, were appointed to the board of directors of IROC.

        We have significant influence over the operations of IROC, but do not control it. We account for our investment in IROC using the equity method. The value of our investment in IROC is recorded in our consolidated balance sheets as a non-current asset. The pro rata share of IROC's earnings and losses to which we are entitled are recorded in our consolidated statements of operations as a component of other income and expense, with an offsetting increase or decrease to the 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 value of our equity investment.

        IROC had net income of approximately $2.0 million, $1.8 million and $1.8 million USD for the years ended December 31, 2007, 2006 and 2005, respectively. IROC's total assets as of December 31, 2007 and 2006 were $140.5 million and $76.9 million USD, respectively. Our investment in IROC totaled $11.2 million and $10.7 million at December 31, 2007 and 2006, respectively. In addition to our pro-rata share of IROC's net income, the value of our investment increased during 2007 due to the strengthening of the Canadian dollar against the U.S. dollar. This increase was offset in accumulated other comprehensive income.

        During the years ended December 31, 2007, 2006, and 2005, we recorded $0.4 million, $0.4 million and $0.5 million, respectively, of equity income related to our investment in IROC. During the years ended December 31, 2007, 2006 and 2005, 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. Such future conditions could therefore result in a determination that a decline in fair value is other than temporary. IROC's stock price is currently depressed. If we later determine that the decline is other than temporary, we would record a write-down in the carrying value of our asset to the then current fair market value.

8. 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, 2007 and 2006. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

        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, 2007
   December 31, 2006
 
   Carrying Value
   Fair Value
   Carrying Value
   Fair Value
 
   (in thousands)
Financial assets:                        
  Notes receivable—related parties   $ 173   $ 173   $ 287   $ 287
  Cash flow hedges     —     —     185     185

Financial liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
  8.375% Senior Notes due 2014   $ 425,000   $ 434,563   $ —   $ —
  2007 Senior Secured Credit Facility Revolving Loans     50,000     50,000     —     —
  2005 Senior Secured Credit Facility Term Loans     —     —     396,000     396,000
  Notes payable—related parties     22,178     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.

        Cash flow hedges.    The carrying value of our cash flow hedges is equal to the fair value of those instruments on December 31, 2006. We had no cash flow hedges on December 31, 2007.

        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, 2007. The carrying value of these notes as of December 31, 2007 was $425.0 million and the fair value was $434.6 million.

        2007 Senior Secured Credit Facility Revolving Loans.    Because of their variable interest rates, the fair values of the revolving loans borrowed under our 2007 Senior Secured Credit Facility approximate their carrying values as of December 31, 2007. The carrying and fair values of these loans as of December 31, 2007 were approximately $50.0 million.

        2005 Senior Secured Credit Facility Term Loans.    Because of their variable interest rates, the fair values of the term loans borrowed under our 2005 Senior Secured Credit Facility approximate their carrying values as of December 31, 2006. The carrying and fair values of these loans as of December 31, 2006 were $396.0 million. The loans were repaid in November 2007 with the proceeds from our 8.375% Senior Notes due 2014.

        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, 2007.

9. DERIVATIVE FINANCIAL INSTRUMENTS

        Interest Rate Swaps.    Under the term loan portion of our 2005 Senior Secured Credit Facility, we were exposed to risks related to variable interest rates. On March 10, 2006 we entered into two

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

$100.0 million notional amount interest rate swaps to effectively fix the interest rate on a portion of this debt. These swaps met the criteria of derivative instruments.

        The Company uses a historic simulation based on regression analysis to assess the effectiveness of the swaps as a hedge of the future cash flows of the forecasted transaction, both on a historical and prospective basis. The simulation regresses the monthly changes in the cash flows associated with the hedging instrument and the hedged item. The results of the regression indicated the swaps were highly effective in offsetting the future cash flows of the items being hedged and could be reasonably assumed to be highly effective on an ongoing basis. Based on the results of this analysis and the Company's intent to use the instruments to reduce exposure to changes in future cash flows attributable to interest payments, the Company elected to account for the swaps as cash flow hedges.

        The measurement of hedge ineffectiveness is based on a comparison of the cumulative change in the fair value of the actual swap designated as the hedging instrument and the cumulative change in fair value of a perfectly effective hypothetical derivative ("Perfect Hypothetical Derivative") (as defined in Derivatives Implementation Group ("DIG") Issue G7). The perfectly effective hypothetical swap mimics the terms of the debt with a fixed interest rate assumed to be the same as the hedge instrument. This method of measuring ineffectiveness is known as the "Hypothetical Derivative Method." Under this method, the actual swap is recorded at fair value on the Company's consolidated balance sheets and accumulated other comprehensive income is adjusted to a balance that reflects the lesser of either the cumulative change in the fair value of the actual swap or the cumulative change in the fair value of the Perfect Hypothetical Derivative. The amount of ineffectiveness, if any, is equal to the excess of the cumulative change in the fair value of the actual swap over the cumulative change in the fair value of the Perfect Hypothetical Derivative, and is recorded currently in earnings as a component of other income and expense on the Company's consolidated statements of operations.

        In connection with the termination of the 2005 Senior Secured Credit Facility in November 2007 (see Note 11—"Long-Term Debt"), 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 11—"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 the notes 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 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.

        Foreign Currency Instruments.    In connection with our acquisition of AMI in September 2007 (see Note 2—"Acquisitions"), we became party to four swap arrangements that exchanged Singaporean Dollars for Canadian Dollars. These arrangements meet the definition of a derivative under SFAS 133.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. DERIVATIVE FINANCIAL INSTRUMENTS (Continued)


We have not elected to treat these derivatives as cash flow hedges and as a result, any gains or losses arising out of changes in the fair value of these contracts are recorded as unrealized gains or losses in our consolidated statements of operations as a component of other income and expense. As of December 31, 2007, the aggregate notional amount of these contracts was approximately $0.4 million USD and the aggregate fair value of these contracts was less than $0.1 million USD. The last of these contracts settled in January 2008. For the year ended December 31, 2007, the unrealized holding loss associated with these contracts was not material.

10. INCOME TAXES

        The components of our income tax expense are as follows:

 
   Year Ended December 31,
  
 
   2007
   2006
   2005
  
 
   (in thousands)

  
Current income tax (expense) benefit:                    
  Federal and state   $ (81,384 ) $ (92,213 ) $ (18,022 )
  Foreign     (771 )   (4,242 )   (3,610 )
   
 
 
 
      (82,155 )   (96,455 )   (21,632 )
   
 
 
 
Deferred income tax (expense) benefit:                    
  Federal and state     (24,281 )   (7,906 )   (13,952 )
  Foreign     (332 )   914     264  
   
 
 
 
      (24,613 )   (6,992 )   (13,688 )
   
 
 
 
Total income tax expense   $ (106,768 ) $ (103,447 ) $ (35,320 )
   
 
 
 

        We made net federal income tax payments of approximately $85.5 million, $87.6 million and $10.8 million for the years ended December 31, 2007, 2006 and 2005, respectively. We made net state income tax payments of approximately $6.6 million, $8.4 million and $1.0 million for the years ended December 31, 2007, 2006 and 2005, respectively. We made net foreign tax payments of approximately $4.2 million, $3.0 million and $5.4 million for the years ended December 31, 2007, 2006 and 2005, respectively. For the years ended December 31, 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 $3.4 million and less than $0.1 million, respectively. For the year ended December 31, 2005, no tax expense was allocated to stockholders' equity for compensation expense for income tax purposes less than amounts recognized for financial reporting purposes. 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.

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10. INCOME TAXES (Continued)

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

 
   Year Ended December 31,
  
 
   2007
   2006
   2005
  
Income tax computed at Federal statutory rate   35.0 % 35.0 % 35.0 %
State taxes   3.2   1.7   2.4  
Meals and entertainment   0.9   0.8   2.1  
Executive and share-based compensation   0.6   1.1   0.6  
Foreign rate differential   0.2   —   1.3  
Change in valuation allowance   0.2   (0.5 ) —  
Other   (1.4 ) (0.4 ) 0.4  
   
 
 
 
Effective income tax rate   38.7 % 37.7 % 41.8 %
   
 
 
 

        As of December 31, 2007 and 2006, our deferred tax assets and liabilities were comprised of the following:

 
   December 31,
  
 
   2007
   2006
  
 
   (in thousands)

  
Deferred tax assets:              
  Net operating loss and tax credit carryforwards   $ 6,000   $ 5,375  
  Self-insurance reserves     21,484     21,593  
  Allowance for doubtful accounts     4,731     4,793  
  Accrued liabilities     15,600     24,287  
  Equity-based compensation     3,876     2,736  
  Other     488     18  
   
 
 
Total deferred tax assets     52,179     58,802  
   
 
 
Valuation allowance for deferred tax assets     (1,458 )   (841 )
   
 
 
Net deferred tax assets     50,721     57,961  
   
 
 
Deferred tax liabilities:              
  Property and equipment     (150,802 )   (121,314 )
  Intangible assets     (31,993 )   (16,196 )
  Other     (318 )   (309 )
   
 
 
Total deferred tax liabilities     (183,113 )   (137,819 )
   
 
 
Net deferred tax liability, net of valuation allowance   $ (132,392 ) $ (79,858 )
   
 
 

        In 2007, deferred tax liabilities decreased by $0.2 million for adjustments to accumulated other comprehensive loss. In 2006, deferred tax liabilities increased by $0.2 million for adjustments to accumulated other comprehensive loss.

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10. INCOME TAXES (Continued)

        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 $5.9 million over the next ten years. With certain exceptions noted below, we believe that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to the historical evidence, it is more likely than not that these assets will be realized.

        We estimate that as of December 31, 2007, 2006 and 2005 we have available $8.2 million, $9.3 million and $14.0 million, respectively, of federal net operating loss carryforwards. Approximately $5.8 million of our net operating losses as of December 31, 2007 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, 2007 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, 2007 and 2006, respectively.

        We estimate that as of December 31, 2007, 2006 and 2005 we have available $19 million, $31 million, and $43 million, respectively, of state net operating loss carryforwards that will expire from 2008 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 $14.2 million over the next 18 years and future Pennsylvania taxable income of $3.5 million over the next 18 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, 2007 of $1.7 million includes a valuation allowance of less than $0.1 million as a result. In the second quarter of 2006, the Texas Margins Tax (see below) was enacted. At that point in time, a deferred tax asset of approximately $0.2 million related to Texas net operating losses that had a complete valuation allowance was effectively converted to a Texas Margins Tax credit that no longer requires a valuation allowance. A tax benefit net of federal tax effect was recorded in the second quarter of 2006 relating to the release of this valuation allowance. In the fourth quarter of 2006, we implemented plans for an internal reorganization of our legal entity structure to occur at year end. After the reorganization, state net operating losses previously subject to valuation allowances of $2.3 million no longer require valuation allowances. A tax benefit net of federal tax effect was recorded in the fourth quarter 2006 relating to the release of this valuation allowance.

        In 2007, the Company began operations in Mexico that resulted in a net operating loss of $2.0 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 will function in addition to

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10. INCOME TAXES (Continued)


the regular corporate tax rate of 28%. Tax expense will be calculated under both methods and if the flat tax is greater than the regular tax, the additional tax expense above the regular tax will be assessed in addition to the regular tax calculation. We have recorded a full valuation allowance related to our Mexico net operating loss carryforwards of $0.6 million at December 31, 2007, as management believes that, because of the enactment of the Mexico flat tax, all of our net operating loss carryforwards related to the Mexico operations are not more likely than not to be fully realized in the future based on the future reversal of deferred tax liabilities. The net operating loss expires in 2017.

        In 2007, the Company made a stock acquisition of AMI, a Canadian company. At December 31, 2007, the Company's Canadian operations had a net operating loss of $3.2 million and a deferred tax asset related to the net operating loss carryforward of $1.0 million. The net operating loss is comprised of approximately $2.0 million net operating loss as of the acquisition date and an additional $1.2 million net operating loss from operations for the four months ended December 31, 2007. We have recorded no valuation allowance related to our Canadian net operating loss carryforwards at December 31, 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 eight years and $3.1 million of future Canadian taxable income over the next nineteen years. The net operating losses expire from 2015 to 2027.

        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.

        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 to reflect the cumulative effect of adopting these standards.

        As part of the acquisitions we made during 2007, the Company acquired or assumed unrecognized tax benefits, as defined by FIN 48. The cumulative effect of the acquisition of the unrecognized tax benefits was $3.2 million, which consisted primarily of rig refurbishment and meals and entertainment expense.

        As of January 1, 2007 and December 31, 2007, we had approximately $3.8 million and $6.8 million, respectively, of unrecognized tax benefits net of federal benefit which, if recognized, would impact our effective tax rate. We have accrued approximately $2.3 million and $1.0 million for the payment of

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10. INCOME TAXES (Continued)


interest and penalties as of December 31, 2007 and January 1, 2007, respectively. While it is possible for changes to occur due to settlement of examinations or the expiration of statute of limitations, we do not anticipate significant changes in our unrecognized tax benefit liability in the next 12 months.

        We file income tax returns in the United States federal jurisdiction and various states and foreign jurisdictions. In January 2005, the Internal Revenue Service concluded its examination of the Company's federal tax returns for tax years June 30, 1997 through December 31, 2002. These examinations have substantially concluded all U.S. federal income tax matters through the year ended December 31, 2002. However, due to the use of net operating losses in subsequent years, these audited tax years as well as the subsequent un-audited 2003-2007 tax years remain open as of December 31, 2007. Our other significant filings are in Argentina, which has been examined through 2006, and in the State of Texas, where tax filings remain open for 2003 to 2006 for certain subsidiaries of the Company.

        There were no expirations of statutes of limitations in 2007 that would require the release of a FIN 48 reserve. However, a change in the circumstances surrounding the audit of our Egyptian operations has resulted in the decrease of the FIN 48 reserve related to that audit by approximately $0.7 million. The current reserve related to the Egyptian audit is $0.4 million.

        The following table presents the activity during 2007 related to our FIN 48 reserve (in thousands):

Balance at January 1, 2007   $ 4,123  
Additions based on tax positions related to the current year     —  
Additions based on tax positions related to prior years     104  
Increases in unrecognized tax benefits acquired or assumed in business combinations     2,403  
Reductions for tax positions from prior years     —  
Settlements     (908 )
   
 
Balance at December 31, 2007   $ 5,722  
   
 

Tax Legislative Changes

        American Jobs Creation Act of 2004.    The American Jobs Creation Act of 2004 added the Section 199 deduction to the Internal Revenue Code. This allows for tax deduction on qualifying domestic production activities, as defined and limited in the Internal Revenue Code. We concluded we will receive benefits of $2.0 million, $1.6 million and $0.6 million from this deduction for the years ended December 31, 2007, 2006 and 2005, respectively.

        Texas Margins 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. The Company recognized a tax benefit of $0.4 million in the second quarter of 2006 related to the enactment of the new law. In 2007, the Company incurred $5.5 million of state income tax expense related to the Texas Margins Tax.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. LONG-TERM DEBT

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

 
   December 31,
  
 
   2007
   2006
  
 
   (in thousands)

  
8.375% Senior Notes due 2014   $ 425,000   $ —  
2007 Senior Secured Credit Facility revolving loans due 2012     50,000     —  
Notes payable—related party, net of fair value discount     22,178     —  
2005 Senior Secured Credit Facility term loans     —     396,000  
Capital lease obligations     26,815     25,794  
   
 
 
      523,993     421,794  
   
 
 
Less: current portion     (12,379 )   (15,714 )
   
 
 
Total long-term debt and capital lease obligations, net of fair value discount   $ 511,614   $ 406,080  
   
 
 

        On November 29, 2007, the Company issued $425.0 million aggregate principal amount of its 8.375% Senior Notes due 2014 (the "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 Notes were priced at 100% of their face value to yield 8.375%. Net proceeds, after deducting initial purchasers' discounts and estimated 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 the 2005 Senior Secured Credit Facility, with the balance used for general corporate purposes. The 2005 Senior Secured Credit Facility was terminated in connection with our entry into the 2007 Senior Secured Credit Facility described below.

        The Notes are general unsecured senior obligations of Key. Accordingly, they will rank effectively subordinate to all of our existing and future secured indebtedness. The 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 Notes is payable on June 1 and December 1 of each year, beginning June 1, 2008. The Notes mature on December 1, 2014.

        On or after December 1, 2011, the 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
   Percentage
  
2011   104.188 %
2012   102.094 %
2013   100.000 %

        Notwithstanding the foregoing, at any time and from time to time before December 1, 2010, the Company may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of

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11. LONG-TERM DEBT (Continued)


the outstanding 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 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 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 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 Notes the opportunity to sell to the Company their 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 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.

        These covenants are subject to certain exceptions and qualifications. In addition, substantially all of the covenants will terminate before the Notes mature if one of two specified ratings agencies assigns the 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 Notes later falls below an investment grade rating.

        In connection with the sale of the Notes, the Company entered into a registration rights agreement with the initial purchasers, pursuant to which it has agreed to file an exchange offer registration statement with the SEC with respect to an offer to exchange the Notes for substantially identical notes that are 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. Additionally, the Company has agreed to commence the registered exchange offer and to use its reasonable best efforts to issue, on or prior to the date that is 60 days after the date on which the exchange offer registration statement became effective, exchange notes in exchange for all Notes tendered prior thereto in the registered exchange offer. Under some circumstances, in lieu of a registered exchange offer, the Company has agreed to file a shelf registration statement to cover resales of the Notes by certain holders thereof and to use reasonable best efforts to keep the shelf registration statement effective for a period of at least two years or such shorter period ending on the earlier of when all of the Notes available for sale thereunder (i) have been sold pursuant thereto and (ii) are no longer restricted securities (as defined in Rule 144 under the Securities Act, or any successor rule thereof). The Company and the Guarantors are required to pay additional interest if they fail to comply with their obligations to register the Notes within the specified time periods.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. LONG-TERM DEBT (Continued)

        As of December 31, 2007, the Company is in compliance with all the covenants required under the Notes.

        Simultaneously with the closing of the offering of the 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 "2007 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. The 2007 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 2007 Senior Secured Credit Facility replaced the Company's 2005 Senior Secured Credit Facility, which was terminated in connection with the closing of the offering of the Notes.

        The interest rate per annum applicable to amounts borrowed under the 2007 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 2007 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 2007 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 2007 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 2007 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 2007 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%.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. LONG-TERM DEBT (Continued)

        As of December 31, 2007, the Company is in compliance with all the covenants required under the 2007 Senior Secured Credit Facility.

        The Company may prepay the 2007 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.

        As of December 31, 2007, the Company had approximately $50.0 million outstanding in borrowings under the revolving portion of the 2007 Senior Secured Credit Facility. The Company also had $61.1 million in committed letters of credit under the facility, and $288.9 million available to borrow under the facility. Under the terms of the agreement, committed letters of credit count against our borrowing capacity under the revolving credit facility. In addition to interest, we also pay a quarterly commitment fee of 0.3% of our available balance under the revolver, and an annual fee for our committed letters of credit equal to 1.5% of the balance of our committed letters of credit.

        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 date of the closing date. As of December 31, 2007, the interest rate on these notes was 4.75%.

        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 No. 21, "Interest on Receivables and Payables" ("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.

        On July 29, 2005, we entered into a Credit Agreement (the "2005 Senior Secured Credit Facility"). The 2005 Senior Secured Credit Facility consisted of (i) a revolving credit facility of up to an aggregate principal amount of $65.0 million, which was to mature on July 29, 2010; (ii) a senior term loan facility in the original aggregate principal amount of $400.0 million, which was to mature on June 30, 2012; and (iii) a prefunded letter of credit facility in the aggregate amount of $82.3 million, which was to mature on July 29, 2010. The revolving credit facility included a $25.0 million sub-facility for additional letters of credit. The proceeds from the term loan facility, along with cash on hand, were used to redeem or repay our Previous Senior Notes (defined below).

        Borrowings under the 2005 Senior Secured Credit Facility through December 31, 2005 bore interest upon the outstanding principal balance, at the Company's option, at the prime rate plus a margin of 1.75% or a Eurodollar rate plus a margin of 2.75%. These margins were increased on December 31, 2005 by 0.50% and again on June 30, 2006 by 0.50% because the Company did not meet

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11. LONG-TERM DEBT (Continued)


certain filing targets for our 2003 Annual Report on Form 10-K. We were also required to pay certain fees in connection with the credit facilities, including a commitment fee as a percentage of aggregate commitments.

        Between November 1, 2005 and July 27, 2007, we amended the 2005 Senior Secured Credit Facility three times in order to, among other things, (i) extend the filing deadlines for our 2006 Annual Report on Form 10-K and quarterly reports for 2005, 2006, and the first two quarters of 2007, (ii) reduce the Eurodollar spreads and commitment fees associated with the term loans under the facility, (iii) increase the limitations on our capital expenditures, (iv) increase the permitted stock repurchase basket under the agreement, (v) increase and subsequently eliminate the permitted acquisitions basket under the agreement, and (vi) eliminate provisions requiring the Company to prepay term loans under the facility with excess cash flow. We paid a total of approximately $1.7 million in fees for these amendments.

        On November 29, 2007, the Company issued the Notes, and used the proceeds to retire the term loan amounts then outstanding under the 2005 Senior Secured Credit Facility. We recognized a loss of approximately $9.6 million upon the extinguishment of the 2005 Senior Secured Credit Facility.

        On November 10, 2003, we entered into a Fourth Amended and Restated Credit Agreement (the "2003 Senior Secured Credit Facility"). The 2003 Senior Secured Credit Facility consisted of a $175.0 million revolving loan facility with the entire amount being available for letters of credit. We previously had the right, subject to certain terms and conditions, to increase the total commitment under the facility to $225.0 million if we were unable to obtain additional lending commitments.

        Our failure to file our 2003 Annual Report on Form 10-K on a timely basis violated the covenants of the 2003 Senior Secured Credit Facility. Between March 31, 2004 and July 20, 2005, we amended the terms of the 2003 Senior Secured Credit facility six times to waive the covenants and extend the due date for our 2003 Annual Report on Form 10-K and other filings. During 2005 we paid a total of $1.1 million in fees related to the various amendments to the 2003 Senior Secured Credit Facility. On July 29, 2005, we entered into the 2005 Senior Secured Credit Facility, which replaced the 2003 Senior Secured Credit Facility.

        On May 14, 2003, we completed a public offering of $150.0 million of 6.375% Senior Notes due May 1, 2013 (the "6.375% Senior Notes"). The proceeds from the public offering, net of fees and expenses, were used to repay the balance of the revolving loan facility then outstanding under our then-existing credit facility, with the remainder being used for general corporate purposes. The 6.375% Senior Notes required semi-annual interest payments on May 1 and November 1 of each year. Interest of $8.9 million was paid on these notes during 2005.

        On March 6, 2001, we completed a private placement of $175.0 million of 8.375% Senior Notes due March 1, 2008 (the "8.375% Senior Notes"; together with the 6.375% Senior Notes, the "Previous Senior Notes"). The net cash proceeds from the private placement were used to repay all of the remaining balance of prior term loans and a portion of the revolving credit facility then outstanding under our then-existing credit facility. On March 1, 2002, we completed the public offering of an additional $100.0 million of 8.375% Senior Notes. The net cash proceeds were used to repay the

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11. LONG-TERM DEBT (Continued)


outstanding balance of the revolving loan facility under our then-existing credit facility. The 8.375% Senior Notes required semi-annual interest payments on March 1 and September 1 of each year. Interest of $27.3 million was paid on these notes during 2005.

        Our failure to file our 2003 Annual Report on Form 10-K with the SEC and deliver it to the trustee under the indentures for the Previous Senior Notes before March 30, 2004 constituted a default under those indentures. During 2004 and 2005 we amended the terms of each of the indentures three times to waive the covenant non-compliance and extend the due date for our 2003 Annual Report on Form 10-K and other filings. In order to obtain these amendments and consents we incurred costs totaling $9.0 million during 2005. The final amendment to the indentures established due dates of May 31, 2005 for filing our 2003 Annual Report on Form 10-K and of July 31, 2005 for filing our 2004 Annual Report on Form 10-K and 2004 quarterly reports on Form 10-Q. The consents also provided a due date of October 31, 2005 for filing our quarterly reports on Form 10-Q for the first and second quarters of 2005. We failed to meet these deadlines, and on June 6, 2005 the trustee for the Previous Senior Notes sent us notice of the financial reporting violation, which the triggered a 60-day cure period. Due to our failure to cure this default, on September 28, 2005 we received a valid acceleration notice from the trustee for the 6.375% Senior Notes.

        The 6.375% Senior Notes were repaid on October 5, 2005, at a price of 100% of the outstanding principal amount plus accrued and unpaid interest to the repayment date, resulting in a net cash outlay of $154.1 million. We redeemed all $275.0 million outstanding principal amount of the 8.375% Senior Notes on November 8, 2005. The 8.375% Senior Notes were redeemed at a price of 104.188% of the principal amount plus accrued and unpaid interest to the redemption date, for a net cash outlay of $290.9 million. resulting in a loss of $14.1 million. We recognized losses totaling $16.4 million related to these transactions. Proceeds from the 2005 Senior Secured Credit Facility and cash on hand were used to repay the Previous Senior Notes.

        As discussed in Note 6—"Sale-Leaseback Transactions," we lease certain equipment such as tractors, trailers, frac tanks and forklifts from financial institutions under master lease agreements. Under certain of these master lease agreements, we were required to provide current annual and quarterly financial reports. For certain of these leases, we obtained a series of waivers from the financial institutions regarding the filing of these reports, the last of which allowed us until September 30, 2006 to file an Annual Report on Form 10-K for 2003. Due to our inability to provide audited financial statements for the year ended December 31, 2003 that comply with SEC rules, we are not in compliance with the terms of these equipment leases. We do not intend to seek additional waivers from the financial institutions, and as a result the equipment lessors may demand that the leases be repaid. As of December 31, 2007, no formal demands for repayment had been made by the lessors. As of December 31, 2007, the total amount outstanding under such lease agreements was approximately $2.7 million. We have recorded a current liability of $1.7 million in our consolidated balance sheets as of December 31, 2007, which represents our obligation under these lease agreements that are accounted for as capital leases. The remaining $1.0 million represents the remaining payments under leases with those lessors that we account for as operating leases.

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11. LONG-TERM DEBT (Continued)

        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, 2007:

 
   Principal Amount of
Long-Term Debt
  
 
   (in thousands)

  
2008   $ 2,000  
2009     14,500  
2010     2,000  
2011     2,000  
2012     52,000  
Thereafter     425,000  
   
 
  Total principal payments     497,500  
   
 
Less: fair value discount     (322 )
   
 
Total long-term debt   $ 497,178  
   
 

        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, 2007:

 
   Capital Lease
Obligation Minimum
Lease Payments
  
 
   (in thousands)

  
2008   $ 13,142  
2009     9,251  
2010     6,066  
2011     2,950  
2012     244  
Thereafter     —  
   
 
Total minimum lease payments     31,653  
   
 
Less: executory costs     (2,696 )
   
 
Net minimum lease payments     28,957  
   
 
Less: amounts representing interest     (2,142 )
   
 
Present value of minimum lease payments   $ 26,815  
   
 

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        Interest expense for the years ended December 31, 2007, 2006 and 2005 consisted of the following:

 
   Year Ended December 31,
  
 
   2007
   2006
   2005
  
 
   (in thousands)

  
Cash payments   $ 33,964   $ 40,290   $ 39,098  
Commitment and agency fees paid     2,232     4,244     14,909  
Amortization of discount and premium, net     —     —     (212 )
Amortization of debt issuance costs     1,680     1,620     1,351  
Settlement of interest rate swaps     2,261     —     —  
Net change in accrued interest     1,366     (3,869 )   (3,581 )
Capitalized interest     (5,296 )   (3,358 )   (1,266 )
   
 
 
 
Total interest expense   $ 36,207   $ 38,927   $ 50,299  
   
 
 
 

        As of December 31, 2007, the weighted average interest rate of our variable rate debt was 5.9787%.

12. COMMITMENTS AND CONTINGENCIES

        Operating Lease Arrangements.    Key leases certain property and equipment under non-cancelable operating leases that generally expire at various dates through 2020, with varying payment dates throughout each month.

        As of December 31, 2007, the future minimum lease payments under non-cancelable operating leases are as follows (in thousands):

 
   Lease Payments
2008   $ 7,428
2009     5,569
2010     3,823
2011     1,719
2012     1,540
Thereafter     4,145
   
    $ 24,224
   

        Operating lease expense was $16.4 million, $17.0 million and $19.5 million for the years ended December 31, 2007, 2006 and 2005, respectively.

        Litigation in the Normal Course of Business.    Various suits and claims arising in the ordinary course of business are pending against us. Due to locations where we conduct business in the continental United States, we are often subject to jury verdicts and arbitration hearings that result in favor of the plaintiffs. We do not believe that the disposition of any of these items will result in a material adverse impact on our financial position, results of operations or cash flows.

        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

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12. COMMITMENTS AND CONTINGENCIES (Continued)


employees for travel time between the yard and the wellhead and that certain employees were denied meal and rest periods between shifts. We have recorded a liability for this matter and do not expect that the conclusion of this matter will 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 good faith and fair dealing, breach of fiduciary duty, and wrongful termination. Mr. Loftis previously filed his "whistle-blower" claim with the Department of Labor ("DOL"), which found that there was no reasonable cause to believe that we violated the Sarbanes-Oxley Act when we terminated Mr. Loftis and dismissed the complaint. On June 28, 2007, the New Jersey District Court transferred the case to the U.S. District Court for the Eastern District of Pennsylvania, where it is pending.

        On July 6, 2007, we delivered a notice to Mr. Loftis, through his counsel, of our intention to treat his termination of employment effective July 8, 2004 as "for cause" under his employment agreement. 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, as well as damages relating to the allegations of malpractice and breach of fiduciary duties. On September 21, 2007, the Company's Board of Directors determined that Mr. Loftis should be terminated "for cause" effective July 8, 2004, and further found that his vested and unvested stock options should be deemed expired.

        On September 3, 2006, our former controller and assistant controller filed a joint complaint against the Company on in 133rd District Court, Harris County, Texas alleging constructive termination and breach of contract. Discovery is now ongoing in this case. 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 Key was not current in its SEC filings, and based on Key's failure to provide him shares of restricted stock.

        We are vigorously defending against these claims; however, we cannot predict the outcome of the lawsuits.

        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 settled the matter for $0.5 million, which included reimbursement of expenses and attorneys fees of approximately $0.4 million.

        Shareholder Class Action Suits and Derivative Actions.    Since June 2004, we and certain of our officers and directors were named as a defendant in six class action complaints for alleged violations of federal securities laws, which were filed in federal district court in Texas. These six actions were consolidated into one action. On November 1, 2005, the plaintiffs filed a consolidated amended class action complaint. The complaint was brought on behalf of a class of putative class of purchasers of our securities between April 29, 2003 and June 4, 2004. The complaint generally alleges that we made false

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and misleading statements and omitted material information from our public statements and SEC reports during the class period, in violation of the Securities Exchange Act of 1934, including alleged: (i) overstatement of revenues, net income, and earnings per share, (ii) failure to take write-downs of assets, consisting of primarily idle equipment, (iii) failure to amortize the Company's goodwill, (iv) failure to disclose that the Company lacked adequate internal controls and therefore was unable to ascertain the true financial condition of the Company, (v) material inflation of the Company's financial results at all relevant times, (vi) misrepresentation of the value of acquired businesses, and (vii) failure to disclose misappropriation of funds by employees.

        Four shareholder derivative actions were filed by certain of our shareholders, purporting to act on our behalf, asserting various claims against the named officer and director defendants. The derivative actions generally allege the same facts as those in the shareholder class action suits. Those suits also allege breach of fiduciary duty, abuse of control, waste of corporate assets, and unjust enrichment by these defendants.

        On September 7, 2007, we reached agreements in principle to settle all pending securities 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 Key will be required to pay approximately $1.1 million. Final approval of the settlement of the shareholder and class action claims by the court is anticipated to occur in the first quarter of 2008. We have recorded an appropriate liability for this matter.

        Expired Option Holders.    On September 24, 2007, Belinda Taylor, on behalf of herself and all similarly situated residents of Texas, filed a lawsuit in the 11th Judicial District of Harris County, Texas, alleging that the Company breached its contracts with 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 also alleges the Company 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, based upon the alleged overstatement of assets prior to the Company's restatement. Ms. Taylor amended her lawsuit on September 25, 2007, to include all Expired Option Holders, regardless of residence. The Company has denied the allegations, and does not expect the resolution of this matter to have a material impact on its financial position, results of operations or cash flows.

        Tax Audits.    We are routinely the subject of audits by tax authorities and have received some material assessments from tax auditors. As of December 31, 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 settlement can vary from this estimate. 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, 2006 the Company had recorded a liability of approximately $1.1 million relating to open Egyptian 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.

        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

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12. COMMITMENTS AND CONTINGENCIES (Continued)


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, 2007 and December 31, 2006, we have recorded $69.0 million and $69.0 million, respectively, of self-insurance reserves related to workers' compensation, vehicular liabilities and general liability claims. Partially offsetting these liabilities, we had approximately $8.1 million and $5.7 million of insurance receivables as of December 31, 2007 and 2006, respectively.

        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 are reasonably estimated. Environmental reserves do not reflect management's assessment of the insurance coverage that may apply to these matters at issue, if such coverage is available, whereas our litigation reserves do reflect the application of our insurance coverage. As of December 31, 2007 and December 31, 2006, we have recorded $3.1 million and $4.6 million, respectively, for our environmental remediation liabilities.

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

        Argentina Payroll Matters.    Our Argentinean subsidiary, Key Energy Services S.A., had previously underpaid social security contributions to the Administración Federal de Ingressos Públicos ("AFIP") as a result of applying an incorrect rate in the calculation of our obligations. Additionally, we also underpaid AFIP as a result of our incorrect use of food stamp equivalents provided to employees as compensation. The correct amounts have been reflected in these financial statements. On May 31, 2007 we paid AFIP $3.5 million, representing the cumulative amount of underpayment and interest. As a result of our underpayment, AFIP has imposed fines and penalties against us and has begun an audit of our filings made to them in prior years. We have recorded an appropriate liability for this matter and do not expect the ultimate resolution of this matter to have a material impact to our financial position, results of operations or cash flows.

13. FOREIGN CURRENCY TRANSLATION

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

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13. FOREIGN CURRENCY TRANSLATION (Continued)


financial statements and the cumulative currency translation gains and losses, net of tax, for each of our foreign subsidiaries:

 
   Argentina
   Mexico
   Canada(1)
   Total
  
 
   (in thousands, except for conversion ratios)

  
As of December 31, 2007:                      

Conversion ratio
 
 
3.15 : 1
 
10.92 : 1
 
0.98 : 1
 
 
n/a
 
Cumulative translation adjustment   $ (38,181 ) $(143 ) $365   $ (37,959 )

As of December 31, 2006:
 
 
 
 
 
 
 
 
 
 
 

Conversion ratio
 
 
3.1 : 1
 
n/a
 
1.17 : 1
 
 
n/a
 
Cumulative translation adjustment   $ (36,896 ) $—   $218   $ (36,678 )
(1)
Foreign currency translation gains for Canada include translation gains related to the acquisition of AMI and the Company's equity-method investment in IROC Systems Corp.

14. 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 $9,000, $8,800 and $8,400 for the years ended December 31, 2007, 2006 and 2005, respectively. Our matching contributions were $10.2 million, $7.4 million and $5.8 million for the years ended December 31, 2007, 2006 and 2005, respectively.

        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.

15. STOCKHOLDERS' EQUITY

Common Stock

        On December 31, 2007, we had 200,000,000 shares of common stock authorized with a $0.10 par value; 131,142,905 of these shares of common stock were issued and outstanding, and no dividends had been issued. On December 31, 2006, we had 200,000,000 shares of common stock authorized with a $0.10 par value; 131,624,038 of these shares of common stock were issued and outstanding, and no dividends had been issued. Under the terms of the Notes and 2007 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.    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 at the end of the first quarter of 2009. In 2007, the Company repurchased an aggregate of 2,341,400 shares at a total cost of approximately $32.2 million, which represents the fair market value of the shares based on the price of the Company's stock on the dates of purchase.

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15. STOCKHOLDERS' EQUITY (Continued)

        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 executive 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 72,847 and 80,835 shares for an aggregate cost of $1.3 million and $1.2 million during 2007 and 2006, 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, 2007, under the share repurchase program, tax withholdings and share acquisitions in prior years, we have repurchased approximately 2.9 million shares of our common stock, at an aggregate cost of $44.3 million.

Common Stock Warrants

        In January 1999, we issued 150,000 Warrants that were exercisable for an aggregate of approximately 2.2 million shares of the Company's common stock at an exercise price of $4.88125 per underlying share. The Warrants were recorded at their fair value on the date of issuance as a component of stockholders' equity. During the fourth quarter of 2007, 2,500 Warrants were exercised for 23,226 shares of our common stock. These exercises were made under the "cashless" exercise provisions of the Warrants. At December 31, 2007, 85,000 warrants remained outstanding and were exercisable for approximately 1.2 million shares of our common stock. The Warrants expire on January 15, 2009.

        Under the terms of the Warrants, we are required to maintain an effective registration statement covering the shares of common stock issuable upon exercise. If we are unable to maintain an effective registration statement, we are required to pay liquidated damages for periods in which an effective registration statement is not maintained. We were unable to maintain an effective registration statement due to our past inability to timely file our required periodic reports with the SEC and we have not filed a new registration statement. As a result, we paid liquidated damages of $0.9 million, $0.9 million and $0.7 million for the years ended December 31, 2007, 2006 and 2005, respectively.

16. EQUITY-BASED COMPENSATION

        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"). 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.

        Under the 1997 Incentive Plan, Key was allowed to grant the following awards to certain key employees, directors who are not employees ("Outside Directors") and consultants of Key, our controlled subsidiaries, and our parent corporation, if any: (i) incentive stock options ("ISOs") as defined in Section 422 of the Internal Revenue Code of 1986, as amended (the "Code"), (ii)"nonstatutory" stock options ("NSOs"), (iii) stock appreciation rights ("SARs"), (iv) shares of restricted stock, (v) performance shares and performance units, (vi) other stock-based awards and (vii) supplemental tax bonuses. The number and kind of securities that were issued under the 1997 Incentive Plan and pursuant to then-outstanding incentive awards are subject to adjustments to prevent

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enlargement or dilution of rights resulting from stock dividends, stock splits, recapitalizations, reorganization or similar transactions.

        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.

        During the period 2000-2001, the Board of Directors granted 3.7 million stock options that were outside the 1997 Incentive Plan, of which 180,000 remained outstanding as of December 31, 2007. 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.

        2007 Incentive Plan.    On December 6, 2007, the Company's shareholders approved its 2007 Equity and Cash Incentive Plan (the "2007 Incentive Plan"). The 2007 Incentive Plan will be administered by the Board or a committee designated by the Board (the "Committee"). While the Company is a publicly traded company, the Committee may consist solely of two or more members of the Board who qualify as "outside directors" within the meaning of Section 162(m) of the Internal Revenue Code of 1986, as amended (the "Code"), and as "non-employee directors" under Rule 16b-3 as promulgated under Section 16 of the Securities Exchange Act of 1934. 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.

        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.

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16. EQUITY-BASED COMPENSATION (Continued)

        The 2007 Incentive Plan provides that in the event of certain corporate events or changes in the Company's common stock, Awards and the maximum number of shares subject to all Awards under the 2007 Incentive Plan and the maximum number of shares that can be awarded to any one person will be adjusted to reflect such event. Any such adjustment made to an incentive stock option will be made in accordance with Section 424(a) of the Code and any such adjustment made to a nonstatutory option will be made so as not to violate Section 409A of the Code.

        In the event of a Change in Control (as defined in the 2007 Incentive Plan), unless otherwise provided in an Award agreement, all options and stock appreciation rights will become immediately exercisable with respect to 100% of the shares subject to such option or stock appreciation rights, and the restrictions will expire immediately with respect to 100% of shares of restricted stock or restricted stock units subject to such Award (including a waiver of any applicable performance goals). In addition, unless otherwise provided in an Award agreement, all incomplete performance periods in respect of a performance compensation award will end upon the Change in Control, and the Administrator will (a) determine the extent to which performance goals with respect to each such performance period have been met, (b) cause to be paid to the applicable participant partial or full performance compensation awards with respect to performance goals for each such performance period based upon the Administrator's determination of the degree of attainment of performance goals and (c) cause the Award, if previously deferred, to be settled in full as soon as possible. Further, in the event of a Change in Control, the Administrator may in its discretion and upon advance notice to the affected persons, cancel any outstanding Awards and pay to the holders thereof, in cash or stock, or any combination thereof, the value of such Awards based upon the price per share of the Company's common stock received or to be received by other shareholders of the Company in the event.

        Upon exercise, payment or delivery pursuant to an Award, the participant will be required to certify that the participant has not engaged in any Detrimental Activity (as defined in the 2007 Incentive Plan). Subject to the terms of the applicable Award agreement, the Administrator may cancel, rescind, suspend, withhold or otherwise limit or restrict any unexpired, unpaid or deferred Awards at any time if the participant engages in any Detrimental Activity. If a participant engages in Detrimental Activity after any exercise, payment or delivery pursuant to an Award, during any period for which any restrictive covenant prohibiting such activity is applicable to the participant, such exercise, payment or delivery may be rescinded within one year thereafter. In the event of any such rescission, the participant will pay to the Company the amount of any gain realized or payment received as a result of the exercise, payment or delivery, in such manner and on such terms and conditions as may be required by the Company.

        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 stockholders of the Company to the extent stockholder approval is necessary to satisfy any applicable law or securities exchange listing requirements. As of December 31, 2007, no Awards had been granted under the 2007 Incentive Plan.

120

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. EQUITY-BASED COMPENSATION (Continued)

Stock Option Awards

        Stock option awards granted under the 1997 Incentive Plan 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 1997 Incentive Plan and the options granted outside the 1997 Incentive Plan, of which 180,000 were outstanding as of December 31, 2007 (shares in thousands):

 
   Year Ended December 31, 2007
 
   Options
   Weighted Average
Exercise Price
   Weighted Average
Fair Value
Outstanding at beginning of period   5,829   $ 9.46   $ 4.94
Granted   1,195   $ 14.41   $ 5.98
Exercised   (1,592 ) $ 8.45   $ 4.58
Cancelled or expired   (838 ) $ 10.36   $ 5.03
   
           
Outstanding at end of period   4,594   $ 11.01   $ 5.32
   
           

Exercisable at end of period
 
2,615
 
$
8.34
 
$
4.47
 
 
   Year Ended December 31, 2006
 
   Options
   Weighted Average
Exercise Price
   Weighted Average
Fair Value
Outstanding at beginning of period   9,275   $ 8.68   $ 4.79
Granted   833   $ 15.03   $ 7.21
Exercised   —   $ —   $ —
Cancelled or expired(1)   (4,279 ) $ 8.86   $ 5.06
   
           
Outstanding at end of period   5,829   $ 9.46   $ 4.94
   
           

Exercisable at end of period
 
4,791
 
$
8.42
 
$
4.51
 
 
   Year Ended December 31, 2005
 
   Options
   Weighted Average
Exercise Price
   Weighted Average
Fair Value
Outstanding at beginning of period   10,408   $ 8.47   $ 4.77
Granted   385   $ 12.20   $ 6.09
Exercised   —   $ —   $ —
Cancelled or expired   (1,518 ) $ 8.16   $ 4.97
   
           
Outstanding at end of period   9,275   $ 8.68   $ 4.79
   
           

Exercisable at end of period
 
8,628
 
$
8.49
 
$
4.75

121

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. EQUITY-BASED COMPENSATION (Continued)

        The following table summarizes information about the stock options outstanding at December 31, 2007 (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   1.46     749   $ 4.80   $ 3.42
$  7.45 - $  9.37   3.45     980   $ 8.34   $ 4.82
$  9.38 - $13.10   6.40     933   $ 11.27   $ 4.98
$13.11 - $14.70   9.56     1,196   $ 14.31   $ 5.98
$14.71 - $18.90   8.26     736   $ 15.20   $ 7.26
       
           
          4,594   $ 11.01   $ 5.32
       
           

Aggregate intrinsic value (in thousands)
 
 
 
$
16,153
 
 
 
 
 
 
 
 
   Options Exercisable
    
 
   Number of
Options
Outstanding
   Weighted Average
Exercise Price
   Weighted Average
Fair Value
Range of Exercise Prices:                  
$  3.00 - $  7.44     749   $ 4.80   $ 3.42
$  7.45 - $  9.37     958   $ 8.35   $ 4.84
$  9.38 - $13.10     882   $ 9.49   $ 4.88
$13.11 - $14.51     26   $ 14.29   $ 7.07
   
           
      2,615   $ 8.34   $ 4.47
   
           

Aggregate intrinsic value (in thousands)
 
$
15,992
 
 
 
 
 
 

        The total fair value of stock options granted during the years ended December 31, 2007, 2006 and 2005 was $7.1 million, $6.0 million and $2.3 million, respectively. For the year ended December 31, 2007, the Company recognized approximately $3.5 million in pre-tax expense related to stock options. For unvested stock option awards outstanding as of December 31, 2007, we expect to recognize approximately $7.3 million of compensation expense over a weighted average remaining vesting period of approximately 0.58 years. Tax benefits of $0.7 million were recognized for the year ended December 31, 2007 related to stock options.

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, 2007, 2006 and 2005 was $4.7 million, $5.9 million and $6.5 million, respectively.

122

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. EQUITY-BASED COMPENSATION (Continued)

        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 72,847 and 80,835 for the years ended December 31, 2007 and 2006, respectively, with aggregate repurchase values of $1.3 million and $1.2 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), we are required to account for this grant as a liability award. Compensation expense for this award during the years ended December 31, 2007, 2006 and 2005 was $0.1 million, $0.2 million and $0.1 million, respectively.

        The following table summarizes information for the years ended December 31, 2007, 2006 and 2005 about the common share awards that have been issued by the Company (shares in thousands):

 
   Year Ended December 31, 2007
 
   Outstanding
   Weighted Average
Issuance Price
   Vested
   Weighted Average
Issuance Price
Shares at beginning of year   833   $ 13.69   258   $ 12.44
Shares issued during year(1)   318   $ 14.87   54   $ 17.48
Previously issued shares vesting during year   —   $ —   239   $ 13.87
Shares repurchased during year   (73 ) $ 14.05   (73 ) $ 14.05
   
       
     
Shares at end of year   1,078   $ 14.01   478   $ 13.48
   
       
     
 
 
   Year Ended December 31, 2006
 
   Outstanding
   Weighted Average
Issuance Price
   Vested
   Weighted Average
Issuance Price
Shares at beginning of year   543   $ 11.90   43   $ 11.90
Shares issued during year(1)   371   $ 15.92   46   $ 14.95
Previously issued shares vesting during year   —   $ —   250   $ 11.90
Shares repurchased during year   (81 ) $ 11.90   (81 ) $ 11.90
   
       
     
Shares at end of year   833   $ 13.69   258   $ 12.44
   
       
     
 
 
   Year Ended December 31, 2005
 
   Outstanding
   Weighted Average
Issuance Price
   Vested
   Weighted Average
Issuance Price
Shares at beginning of year   —   $ —   —   $ —
Shares issued during year(1)   543   $ 11.90   43   $ 11.90
Previously issued shares vesting during year   —   $ —   —   $ —
Shares repurchased during year   —   $ —   —   $ —
   
       
     
Shares at end of year   543   $ 11.90   43   $ 11.90
   
       
     
(1)
Shares of common stock issued to our non-employee directors vest immediately upon issuance.

        For common stock grants that vest immediately upon issuance, we record expense equal to the fair market value of the shares on the date of grant. For common stock awards that do not immediately

123

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. EQUITY-BASED COMPENSATION (Continued)


vest, we recognize compensation expense ratably over the vesting period of the grant, net of estimated and actual forfeitures. For the years ended December 31, 2007, 2006 and 2005, we recognized $5.6 million, $3.6 million and $2.5 million, respectively, of pre-tax expense associated with common stock awards, net of estimated and actual forfeitures. In connection with the expense related to common stock awards recognized during the year ended December 31, 2007, we recognized tax benefits of approximately $1.2 million. For the unvested common stock awards outstanding as of December 31, 2007, the Company anticipates that it will recognize approximately $5.2 million of pre-tax expense over the next 0.65 years.

Phantom Share Plan

        In December 2006, we announced the implementation of a "Phantom Share Plan," in which certain of our employees were granted "Phantom Shares." 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. During 2007, we recognized approximately $3.3 million of pre-tax compensation expense associated with the Phantom Shares. As of December 31, 2007, we recorded current and non-current liabilities of $2.4 million and $0.9 million, respectively, which represented the aggregate fair value of the 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 $1.3 million in 2007. For unvested Phantom Share awards outstanding as of December 31, 2007, we expect to recognize approximately $3.4 million of compensation expense over a weighted average remaining vesting period of approximately 1.5 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 stock appreciation rights ("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.

124

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. EQUITY-BASED COMPENSATION (Continued)

        Compensation expense recognized in 2007 in connection with the SARs was approximately $0.6 million. Income tax benefits of approximately $0.2 million were recognized by the Company in connection with this expense. For the unvested SARs outstanding as of December 31, 2007, the Company anticipates that it will recognize approximately $2.8 million of expense over the next 1.6 years.

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,
  
 
   2007
   2006
   2005
  
Risk-free interest rate   4.41 % 4.70 % 3.80 %
Expected life of options, years   6   6   6  
Expected volatility of the Company's stock price   39.49 % 48.80 % 53.85 %
Expected dividends   none   none   none  

17. TRANSACTIONS WITH RELATED PARTIES

Employee Loans and Advances

        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, 2007, these loans, in the aggregate, total approximately $0.2 million. Of this 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 date 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.

125

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. TRANSACTIONS WITH RELATED PARTIES (Continued)


The discount will be recognized as interest expense over the life of the promissory notes using the effective interest method.

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 ("Anadarko"), which is one of our customers. Sales to Anadarko comprised less than 2% of our total revenues for the year ended December 31, 2007. Transactions with Anadarko for our services are made at market prices.

18. SEGMENT INFORMATION

        For 2007, our reportable operating business segments are well servicing, pressure pumping and fishing and rental. We evaluate the performance of our operating segments based on revenue and EBITDA, which is a non-GAAP measure and not disclosed below.

        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.

        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

126

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18. SEGMENT INFORMATION (Continued)


subsidiaries, accounts and notes receivable from subsidiaries, the Company's investment in IROC Services Corp., and deferred income tax assets.

 
   Well
Servicing
   Pressure
Pumping
   Fishing
and Rental
   Corporate /
Other
   Discontinued
Operations
   Eliminations
   Total
  
 
   (in thousands)
  
As of and for the year ended December 31, 2007:                                            
Operating revenues   $ 1,264,797   $ 299,348   $ 97,867   $ —   $ —   $ —   $ 1,662,012  
Gross margin     526,103     109,703     40,592     —     —     —     676,398  
Depreciation and amortization     90,274     16,854     8,742     13,753     —     —     129,623  
Interest expense     (712 )   (1,048 )   (493 )   38,708     —     (248 )   36,207  
Net income (loss)     360,617     83,785     22,028     (297,141 )   —     —     169,289  
Property and equipment, net     693,804     133,903     48,703     34,798     —     —     911,208  
Total assets     1,500,913     247,018     89,802     402,513     —     (381,169 )   1,859,077  
Capital expenditures, excluding acquisitions     (135,336 )   (51,115 )   (19,811 )   (6,298 )   —     —     (212,560 )
 
 
   Well
Servicing
   Pressure
Pumping
   Fishing
and Rental
   Corporate /
Other
   Discontinued
Operations
   Eliminations
   Total
  
 
   (in thousands)
  
As of and for the year ended December 31, 2006:                                            
Operating revenues   $ 1,201,228   $ 247,489   $ 97,460   $ —   $ —   $ —   $ 1,546,177  
Gross margin     476,220     109,112     40,243     —     —     —     625,575  
Depreciation and amortization     95,673     12,416     6,787     11,135     —     —     126,011  
Interest expense     (615 )   (600 )   (98 )   40,240     —     —     38,927  
Net income (loss)     311,339     88,070     22,860     (251,236 )   —     —     171,033  
Property and equipment, net     531,685     97,372     35,971     29,263     —     —     694,291  
Total assets     1,022,898     190,704     79,364     206,622     —     41,810     1,541,398  
Capital expenditures, excluding acquisitions     (143,080 )   (35,513 )   (12,953 )   (4,284 )   —     —     (195,830 )
 
 
   Well
Servicing
   Pressure
Pumping
   Fishing
and Rental
   Corporate /
Other
   Discontinued
Operations
   Eliminations
   Total
  
 
   (in thousands)
  
As of and for the year ended December 31, 2005:                                            
Operating revenues   $ 956,457   $ 152,320   $ 81,667   $ —   $ —   $ —   $ 1,190,444  
Gross margin     322,414     60,019     27,768     —     —     —     410,201  
Depreciation and amortization     85,772     8,785     6,024     11,307     —     —     111,888  
Interest expense     86     (328 )   35     50,506     —     —     50,299  
Net income (loss)     175,576     51,661     14,926     (193,085 )   (3,361 )   —     45,717  
Property and equipment, net     479,972     71,688     27,214     31,467     —     —     610,341  
Total assets     919,887     151,683     67,082     450,709     658     (260,775 )   1,329,244  
Capital expenditures, excluding acquisitions     (79,410 )   (27,258 )   (4,070 )   (7,408 )   —     —     (118,146 )

127

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18. SEGMENT INFORMATION (Continued)

        The following table presents information related to our foreign operations (in thousands of U.S. Dollars):

 
   Argentina
   Mexico
   Canada
   Total Foreign
As of and for the year ended December 31, 2007:                        

Operating revenues
 
$
93,925
 
$
8,956
 
$
2,938
 
$
105,819
Total assets     82,550     12,870     8,876     104,296

As of and for the year ended December 31, 2006:
 
 
 
 
 
 
 
 
 
 
 
 

Operating revenues
 
$
78,321
 
$
—
 
$
—
 
$
78,321
Total assets     77,878     —     —     77,878

As of and for the year ended December 31, 2005:
 
 
 
 
 
 
 
 
 
 
 
 

Operating revenues
 
$
68,183
 
$
—
 
$
—
 
$
68,183
Total assets     58,816     —     —     58,816

128

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. 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):

 
   First Quarter
   Second Quarter
   Third Quarter
   Fourth Quarter(2)
Year Ended December 31, 2007:                        
  Revenues   $ 408,919   $ 410,511   $ 413,967   $ 428,615
  Gross margin     173,406     172,288     156,485     174,219
  Income before income taxes     84,694     78,471     59,832     52,943
  Net income     52,190     48,136     35,896     33,067
 
Earnings per share(1):
 
 
 
 
 
 
 
 
 
 
 
 
    Basic   $ 0.40   $ 0.37   $ 0.27   $ 0.25
    Diluted   $ 0.39   $ 0.36   $ 0.27   $ 0.25
 
 
   First Quarter
   Second Quarter
   Third Quarter
   Fourth Quarter
Year Ended December 31, 2006:                        
  Revenues   $ 347,958   $ 372,036   $ 417,600   $ 408,583
  Gross margin     129,336     151,975     180,199     164,065
  Income before income taxes     48,430     63,920     98,822     63,308
  Net income     30,063     39,582     60,885     40,503
 
Earnings per share(1):
 
 
 
 
 
 
 
 
 
 
 
 
    Basic   $ 0.23   $ 0.30   $ 0.46   $ 0.31
    Diluted   $ 0.22   $ 0.29   $ 0.45   $ 0.31
(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."

20. 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."

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Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (Continued)


CONDENSED CONSOLIDATING BALANCE SHEET

 
   December 31, 2007
 
   Parent
Company
   Guarantor
Subsidiaries
   Non-Guarantor
Subsidiaries
   Eliminations
   Consolidated
 
   (in thousands)
Assets:                              
  Current assets   $ 39,501   $ 378,865   $ 69,499   $ —   $ 487,865
  Net property and equipment     —     880,907     30,301     —     911,208
  Goodwill     —     373,283     5,267     —     378,550
  Deferred costs, net     12,117     —     —     —     12,117
  Intercompany receivables and investments in subsidiaries     1,557,993     175,461     —     (1,733,454 )   —
  Other assets     11,217     52,074     6,046     —     69,337
   
 
 
 
 
TOTAL ASSETS   $ 1,620,828   $ 1,860,590   $ 111,113   $ (1,733,454 ) $ 1,859,077
   
 
 
 
 

Liabilities and equity:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Current liabilities   $ 17,278   $ 192,222   $ 25,297   $ —   $ 234,797
  Long-term debt     475,000     —     —     —     475,000
  Capital lease obligations     —     15,998     116     —     16,114
  Long-term notes payable— related party     —     20,500     —     —     20,500
  Intercompany payables     78,660     1,489,377     24,408     (1,592,445 )   —
  Deferred tax liabilities     157,759     (79 )   2,388     —     160,068
  Other long-term liabilities     3,133     60,216     251     —     63,600
  Stockholders' equity     888,998     82,356     58,653     (141,009 )   888,998
   
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY   $ 1,620,828   $ 1,860,590   $ 111,113   $ (1,733,454 ) $ 1,859,077
   
 
 
 
 

130

Key Energy Services, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (Continued)


CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

 
   Year Ended December 31, 2007
  
 
   Parent
Company
   Guarantor
Subsidiaries
   Non-guarantor
Subsidiaries
   Eliminations
   Consolidated
  
 
   (in thousands)
  
Revenues   $ —   $ 1,561,059   $ 105,819   $ (4,866 )   1,662,012  
Costs and expenses:                                
  Direct expenses     —     906,254     82,980     (3,620 )   985,614  
  Depreciation and amortization     —     123,821     5,802     —     129,623  
  General and administrative     1,693     216,959     11,935     (191 )   230,396  
  Interest expense, net of amounts capitalized     38,866     (3,134 )   723     (248 )   36,207  
  Loss on early extinguishment of debt     9,557     —     —     —     9,557  
  Other, net     (449 )   (5,850 )   1,781     (807 )   (5,325 )
   
 
 
 
 
 
Total costs and expenses, net     49,667     1,238,050     103,221     (4,866 )   1,386,072  
   
 
 
 
 
 
(Loss) income before income taxes     (49,667 )   323,009     2,598     —     275,940  
Income tax (expense) benefit     (105,928 )   934     (1,774 )   —     (106,768 )
Minority interest     —     —     117     —     117  
   
 
 
 
 
 
NET (LOSS) INCOME   $ (155,595 ) $ 323,943   $ 941   $ —   $ 169,289  
   
 
 
 
 
 


CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

 
   Year Ended December 31, 2007
  
 
   Parent
Company
   Guarantor
Subsidiaries
   Non-guarantor
Subsidiaries
   Eliminations
   Consolidated
  
 
   (in thousands)
  
Net cash provided by operating activities   $ (3,401 ) $ 264,275   $ (10,955 ) $ —   $ 249,919  
Net cash used in investing activities     (473,412 )   (732,359 )   (5,160 )   908,084     (302,847 )
Net cash provided by financing activities     476,813     429,809     24,702     (908,084 )   23,240  
Effect of exchange rates on cash     —     —     (184 )   —     (184 )
   
 
 
 
 
 
Net (decrease) increase in cash     —     (38,275 )   8,403     —     (29,872 )
   
 
 
 
 
 
Cash at beginning of period     —     84,633     3,742     —     88,375  
   
 
 
 
 
 
Cash at end of period   $ —   $ 46,358   $ 12,145   $ —   $ 58,503  
   
 
 
 
 
 

131

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 Chairman and Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

        The Company's management, with the participation of the Company's Chairman and Chief Executive Officer and Chief 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 Chairman and Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, due to the material weaknesses in our internal control over financial reporting described below, our disclosure controls and procedures were not effective.

        Changes in Internal Control Over Financial Reporting.    We believe that there have been changes in our internal control over financial reporting during the period from January 1, 2007 to December 31, 2007 that have significantly improved our internal control over financial reporting. In August 2007 we filed our Annual Report on Form 10-K for the year ended December 31, 2006 ("2006 Report") and, as described in Item 9A. "Controls and Procedures" in that report, we identified multiple material weaknesses as of December 31, 2006. During 2007 and since filing the 2006 Report, we have made numerous changes to address those weaknesses. Based on these actions, we concluded that the following material weaknesses previously identified had been remediated as of December 31, 2007:

        Improvements in 2007 for our internal control over financial reporting that remediated the 2006 weaknesses included adding a process for and controls over the accrual and recording of expenditures with appropriate reconciliations and review, an overall program of account reconciliations and review and a process, including controls and appropriate review, for our accounting for income taxes.

        In other instances, the controls that were implemented during 2007 were not sufficient to effectively remediate the material weakness, or there were not sufficient instances of the controls in operation to make a determination that these controls were operating effectively. The actions taken with respect to the material weaknesses identified as of December 31, 2006 but not remediated at December 31, 2007 are discussed below in "Management's Report on Internal Control Over Financial Reporting."

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

132


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, 2007. In making this assessment, management used the criteria 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 our internal control over financial reporting was not effective as of December 31, 2007. Management has identified the following material weaknesses of internal control over financial reporting as of December 31, 2007:

        Financial Close and Reporting:    In our 2006 Report, we identified a material weakness at December 31, 2006 in our financial close and reporting process. In third quarter of 2007 we filed our 2006 Report, our Quarterly Reports on Form 10-Q for the years 2005 and 2006 and our Quarterly Reports on Form 10-Q for the first and second quarters of 2007, and, in November 2007, we filed our Quarterly Report on Form 10-Q for the third quarter of 2007. In response to the material weaknesses in financial close and reporting disclosed in the 2006 Report, management instituted substantial changes in 2007 to our internal control structure. These changes included additional personnel, adding analytical procedures and reviews, methodologies for the preparation of our financial statements, reconciliations of our accounts and reconciliations between our general ledger and subledger systems as well as increasing the availability of evidence for those controls. However, as a result of our delayed reporting and the devotion of resources to completing our required 2006 and 2007 filings under the Exchange Act, many of these improvements were not in place and evidenced as operating effectively until the financial close and reporting activities for the fourth quarter of 2007. Due to the timing of these improvements, sufficient instances of these controls in operation had not occurred for the controls to be assessed as effective at December 31, 2007. As a result, we could not conclude that this material weakness had been remediated.

133

        Management believes that the control activities put in place in 2007 are sufficient to remediate previously identified deficiencies and that with the passage of sufficient close and reporting cycles to evidence effective operation of these controls the material weakness will be remediated.

        Authorizations of Expenditures:    In our 2006 Report, we determined that at December 31, 2006 multiple control deficiencies existed regarding our ability to appropriately ensure and evidence that expenditures, covering substantially all aspects of spending, were approved by the appropriate level of management in accordance with our established policies and, as a result, we identified this as a material weakness. Deficiencies related to authorizations for payroll were among the deficiencies identified in 2006; for 2007, those are discussed separately below. During 2007, changes were made that included the establishment of approval authorities and automated controls in our procurement system. Notwithstanding these changes, certain deficiencies remained at December 31, 2007. The remaining deficiencies resulting in our material weakness are our inability to ensure and evidence that (i) timely approvals occurred for expenditures made through our procurement system or (ii) that expenditures not made through our procurement system were appropriately approved in accordance with our policies. In addition to the changes previously discussed, we also instituted compensating controls in 2007, such as analytical procedures; however, these compensating controls were not all in place and evidenced as operating effectively until the financial close and reporting for the fourth quarter of 2007. As a result, sufficient instances of these controls in operation had not occurred for the controls to be assessed as effective at December 31, 2007.

        We are continuing to make enhancements to our procurement processes and controls and believe that these changes, coupled with the passage of sufficient close and reporting cycles for compensating controls put in place in 2007 to be evidenced as operating effectively, will remediate this weakness.

        Recording of Revenues:    In our 2006 Report, we determined that a material weakness existed at December 31, 2006 regarding the recording of revenues, as our revenue process is heavily dependent on manual reviews and approvals of credit terms, amounts to be billed and recorded and adjustments for bad debts. At December 31, 2007, we determined that a material weakness remained in our revenue process, as manual approvals at the field level necessary to evidence the recognition of revenues and sufficient evidence of those approvals could not be adequately substantiated. We put compensating controls in place in 2007, such as analytical reviews of accrued revenues, analysis of aged receivables and account reconciliations of our revenue systems and general ledger. Sufficient instances had not occurred for all of these compensating controls to be assessed as effective at December 31, 2007. As a result, we have concluded that a material weakness identified in our 2006 Report remained in 2007.

        Management believes that the compensating controls put in place in 2007 should be sufficient to compensate for the identified deficiencies in approvals and that with the passage of sufficient close and reporting cycles to evidence operation of these controls the material weakness will be remediated.

        Property, Plant & Equipment (PP&E):    In our 2006 Report, we determined that a material weakness existed at December 31, 2006 regarding the recording of PP&E. In 2007, substantial changes were made to our processes and controls; however, for two areas of our accounting for PP&E—the timing of assets being placed in service and the timing of recognition of gains and losses and approval for asset dispositions—a material weakness remained at December 31, 2007. Due to the design and utilization of our procurement system and practices, certain final costs for an asset may not be captured in a timely manner. As a result of this, the asset may be physically placed in service prior to all cost information being received. This delay in accumulating necessary cost information may delay the beginning of depreciation expense. Additionally, while we have implemented controls, including counts and observations, to ensure that information regarding asset dispositions is captured and recorded, obtaining evidence of appropriate approval for the disposition as well as the timing of the receipt of that information may result in delays in the recording of the disposition which could cross reporting periods.

134

        Management is making enhancements to our procurement processes and practices and believes that these changes, coupled with compensating controls for the identified deficiencies, including reconciliations and analytical reviews of balances and depreciation expense will remediate this weakness.

        User Developed Applications:    In the course of preparing our consolidated financial statements, numerous spreadsheets and database programs ("User Developed Applications") are employed. The User Developed Applications are utilized by us in calculating estimates, reconciling payroll hours, tracking inventory costs and making cost allocations, among other things. At December 31, 2006, we identified a material weakness as most User Developed Applications were not secured as to access, logical security, changes or data integrity. To mitigate the associated risk for situations where the above controls could not be implemented, compensating controls were put in place; however, for many of these compensating controls, sufficient instances had not occurred for these controls to be assessed as effective at December 31, 2007. As a result, we have concluded that this material weakness identified in our 2006 Report remained in 2007.

        In 2007, management began an effort to identify all of its User Developed Applications and remediate the weakness through controls in the User Developed Applications themselves or compensating controls. These efforts, along with elimination of User Developed Applications from critical processes, continue into 2008. Management believes that with the passage of sufficient close and reporting cycles to evidence operation of these compensating controls the material weakness will be remediated.

        Application Access and Segregation of Duties:    In our 2006 Report, we determined that material weaknesses existed at December 31, 2006 in four aspects of information technology general controls over security and segregation of duties of our primary financial systems. These include security administration procedures, administrator access privileges, database and file access and password controls. The weaknesses in these information technology general control areas were further evidenced by or related to deficiencies in our various access controls at the financial system level, causing inappropriate access and segregation of duties issues in significant processes. In 2007 we implemented management reports for business owner review as well as administrative controls and procedures. These controls were not fully effective in remediating the identified weakness. We put compensating controls in place in 2007, such as analytical reviews. Sufficient instances had not occurred for these controls to be assessed as effective at December 31, 2007. As a result, we have concluded that this material weakness identified in our 2006 Report remained in 2007.

        Management believes that the compensating controls put in place are sufficient to compensate for the identified deficiencies in access and segregation of duties and that with the passage of sufficient close and reporting cycles to evidence operation of these controls the risk associated with the material weakness will be remediated. Management will also be implementing additional activities around business owner review of access and segregation of duties across the systems we utilize.

        Payroll:    We determined that at December 31, 2007 control activities surrounding our payroll process, in particular, personnel involved in the process, proper documentation concerning hours worked or rate changes, coupled with deficiencies with reconciliations where payroll data was a major component, constituted a material weakness in our system of internal controls. These deficiencies had been previously identified in our 2006 Report as part of Account Reconciliations and Authorization for Expenditures.

        In 2007, we continued our process to improve our data quality and controls surrounding our payroll process, beginning with system enhancements and organizational changes. In late 2007, we initiated another phase of this process, which will encompass changes to payroll practices, further organizational changes and the replacement of our current payroll system. We believe that these

135


changes, which will further strengthen our control structure and increase our efficiency as well as transparency into payroll related data, will remediate this deficiency. We anticipate that this process will be completed in the third quarter of 2008.

        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.

ITEM 9B.    Other Information

        Not Applicable.


PART III

ITEM 10.    Directors, Executive Officers and Corporate Governance

        Item 10 is incorporated by reference pursuant to Regulation 14A under the Securities Exchange Act of 1934. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2007.

ITEM 11.    Executive Compensation

        Item 11 is incorporated by reference pursuant to Regulation 14A under the Securities Exchange Act of 1934. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2007.

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 Securities Exchange Act of 1934. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2007.

ITEM 13.    Certain Relationships and Related Transactions, and Director Independence

        Item 13 is incorporated by reference pursuant to Regulation 14A under the Securities Exchange Act of 1934. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2007.

ITEM 14.    Principal Accountant Fees and Services

        Item 14 is incorporated by reference pursuant to Regulation 14A under the Securities Exchange Act of 1934. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2007.


PART IV

ITEM 15.    Exhibits and Financial Statement Schedules

        The following financial statements, schedules and exhibits are filed as part of this Report:

        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.

136


EXHIBIT INDEX

Exhibit No.
   Description
3.1   Articles of Restatement of the Company. (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. 1-8038.)

3.2
 
Unanimous consent of the Board of Directors of the Company 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. 1-8038.)

3.3
 
Second Amended and Restated By-laws of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of the Company's Form 8-K filed on September 22, 2006, File No. 1-8038.)

3.4
 
Amendment to Second Amended and Restated By-laws of Key Energy Services, Inc. (Incorporated by Reference to Exhibit 3.1 of the Company's Form 8-K filed on November 2, 2007, File No. 1-8038.)

4.1
 
Warrant Agreement dated as of January 22, 1999 between the Company 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 Form 8-K filed on February 3, 1999, File No. 1-8038.)

4.2
 
Warrant Registration Rights Agreement dated January 22, 1999, by and among the Company and 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 Form 8-K filed on February 3, 1999, File No. 1-8038.)

4.3
 
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 Form 8-K filed on November 30, 2007, File No. 1-8038.)

4.4
 
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 Form 8-K filed on November 30, 2007, File No. 1-8038.)

10.1†
 
Key Energy Group, Inc. 1997 Incentive Plan, as an amendment and restatement effective November 17, 1997 of the Key Energy Group, Inc. 1995 Outside Directors Stock Option Plan. (Incorporated by reference to Exhibit B of the Company's Schedule 14A Proxy Statement filed November 26, 1997, File No. 000-22665.)

10.2†
 
Form of Restricted Stock Agreement under Key Energy Group, Inc. 1997 Incentive Plan.

10.3†
 
The 2006 Phantom Share Plan of Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

10.4†
 
Form of Award Agreement under the 2006 Phantom Share Plan of Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.2 of the Company's Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

137


10.5†
 
Form of Stock Appreciation Rights Agreement. (Incorporated by Reference to Exhibit 99.1 of the Company's Form 8-K filed on August 24, 2007, File No. 1-8038.)

10.6†
 
Form of Non-Plan Option Agreement. (Incorporated by Reference to Exhibit 4.1 of the Company's Registration Statement on Form S-8 filed on September 25, 2007, File No. 333-146294.)

10.7†
 
Key Energy Services, Inc. 2007 Equity and Cash Incentive Plan. (Incorporated by Reference to Appendix A of the Company's Schedule 14A Proxy Statement filed on November 1, 2007, File No. 1-8038.)

10.8†*
 
Form of Nonstatutory Stock Option Agreement under 2007 Equity and Cash Incentive Plan.

10.9†
 
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 Form 8-K filed on January 7, 2008, File No. 1-8038.)

10.10†
 
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.)

10.11†
 
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 Form 8-K filed on January 7, 2008, File No. 1-8038.)

10.12†
 
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 Form 8-K filed on January 7, 2008, File No. 1-8038.)

10.13†
 
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.)

10.14†
 
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 Form 8-K filed on January 7, 2008, File No. 1-8038.)

10.15†
 
Employment Agreement between Key Energy Services, Inc. and Jim D. Flynt dated as of January 1, 2004. (Incorporated by reference to Exhibit 10.6 of the Company's Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

10.16†
 
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 Form 8-K filed on November 30, 2007, File No. 1-8038.)

10.17†
 
Employment Agreement between Key Energy Services, Inc. and Phil Coyne dated November 17, 2004. (Incorporated by reference to Exhibit 10.8 of the Company's Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

138


10.18†
 
First Amendment to Employment Agreement between the Company and Phil Coyne effective as of January 24, 2005. (Incorporated by reference to Exhibit 10.9 of the Company's Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

10.19†*
 
Amended and Restated Employment Agreement between Key Energy Services, Inc. and Don D. Weinheimer dated December 31, 2007.

10.20†
 
Employment Agreement dated August 14, 2007 between the Company 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. 1-8038.)

10.21†
 
Employment Agreement dated August 14, 2007 between the Company 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. 1-8038.)

10.22
 
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. 1-8038.)

10.23
 
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. 1-3038.)

10.24
 
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. 1-8038.)

10.25
 
Credit Agreement, dated as of June 29, 2005, among the Company, as Borrower, the several lenders from time to time party thereto, Lehman Brothers Inc., as sole lead arranger and sole book runner, Lehman Commercial Paper Inc., as syndication agent, administrative agent and as collateral agent, and Wells Fargo Foothill, Inc., as revolving administrative agent. (Incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K dated August 4, 2005, File No. 1-8038.)

10.26
 
First Amendment to Credit Agreement and First Amendment to Guaranty and Collateral Agreement dated as of November 1, 2005, among the Company, as Borrower, the Guarantors, the Lenders, and Lehman Commercial Paper Inc., as administrative agent for the Lenders and as Collateral Agent for the Lenders and other Secured Parties. (Incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K dated November 7, 2005, File No. 1-8038.)

10.27
 
Second Amendment to Credit Agreement dated as of November 21, 2006, among the Company, as Borrower, the Guarantors, the Lenders, and Lehman Commercial Paper Inc., as administrative agent for the Lenders and as Collateral Agent for the Lenders and other secured Parties. (Incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

10.28
 
Third Amendment to Credit Agreement dated as of July 27, 2007, among the Company, as Borrower, the Guarantors, the Lenders and Lehman Commercial Paper, Inc., as administrative agent for the Lenders and as Collateral Agent for the Lenders and other Secured Parties. (Incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K dated July 31, 2007, File No. 1-8038.)

139


10.29
 
Fourth Amendment to Credit Agreement dated as of November 12, 2007, among Key Energy Services, Inc., as Borrower, the guarantors signatory thereto, the Lenders, and Lehman Commercial Paper Inc., as administrative agent for the Lenders and as Collateral Agent for the Lenders and other Secured Parties. (Incorporated by Reference to Exhibit 10.1 of the Company's Form 8-K filed on November 15, 2007, File No. 1-8038.)

10.30
 
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 Form 8-K filed on November 30, 2007, File No. 1-8038.)

10.31
 
Stock and Membership Interest Purchase Agreement dated as of September 19, 2007. (Incorporated by Reference to Exhibit 10.1 of the Company's Form 8-K filed on September 20, 2007, File No. 1-8038.)

10.32
 
First Amendment to Stock and Membership Interest Purchase Agreement dated October 25, 2007, among Key Energy Services, LLC and the Sellers (as defined 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. 1-8038.)

10.33
 
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 Form 8-K filed on December 13, 2007, File No. 1-8038.)

10.33
 
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 Form 8-K filed on November 15, 2007, File No. 1-8038.)

21*
 
Significant Subsidiaries of the Company.

23*
 
Consent of Independent Registered Public Accounting Firm.

31.1*
 
Certification of CEO pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. of 2002.

31.2*
 
Certification of CFO pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32*
 
Certification of CEO and CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
†
Indicates a management contract or compensatory plan, contract or arrangement in which any Director or any Executive Officer participates.

*
Filed herewith.

140


SIGNATURES

        Pursuant to the requirements of Section 13 of 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.

Date: February 29, 2008   KEY ENERGY SERVICES, INC.

 
 
By:
/s/  WILLIAM M. AUSTIN      
William M. Austin, Senior Vice
President and Chief Financial Officer


POWER OF ATTORNEY

        Each person whose signature appears below hereby constitutes and appoints Richard J. Alario and William M. Austin, 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		   Chairman of the Board of Directors,
President and Chief Executive Officer
(Principal Executive Officer)		   February 29, 2008

/s/  WILLIAM M. AUSTIN      
William M. Austin
 
Senior Vice President and Chief
Financial Officer
(Principal Financial Officer)
 
February 29, 2008

/s/  J. MARSHALL DODSON      
J. Marshall Dodson
 
Vice President and Chief Accounting
Officer
(Principal Accounting Officer)
 
February 29, 2008

/s/  DAVID J. BREAZZANO      
David J. Breazzano
 
Director
 
February 29, 2008

Lynn R. Coleman
 
Director
 
February 29, 2008

/s/  KEVIN P. COLLINS      
Kevin P. Collins
 
Director
 
February 29, 2008


/s/  WILLIAM D. FERTIG      
William D. Fertig
 
Director
 
February 29, 2008

/s/  W. PHILLIP MARCUM      
W. Phillip Marcum
 
Director
 
February 29, 2008

/s/  RALPH S. MICHAEL, III      
Ralph S. Michael, III
 
Director
 
February 29, 2008

/s/  WILLIAM F. OWENS      
William F. Owens
 
Director
 
February 29, 2008

/s/  ARLENE M. YOCUM      
Arlene M. Yocum
 
Director
 
February 29, 2008

/s/  ROBERT K. REEVES      
Robert K. Reeves
 
Director
 
February 29, 2008

/s/  J. ROBINSON WEST      
J. Robinson West
 
Director
 
February 29, 2008


EXHIBIT INDEX

Exhibit No.
   Description
3.1   Articles of Restatement of the Company. (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. 1-8038.)

3.2
 
Unanimous consent of the Board of Directors of the Company 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. 1-8038.)

3.3
 
Second Amended and Restated By-laws of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of the Company's Form 8-K filed on September 22, 2006, File No. 1-8038.)

3.4
 
Amendment to Second Amended and Restated By-laws of Key Energy Services, Inc. (Incorporated by Reference to Exhibit 3.1 of the Company's Form 8-K filed on November 2, 2007, File No. 1-8038.)

4.1
 
Warrant Agreement dated as of January 22, 1999 between the Company 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 Form 8-K filed on February 3, 1999, File No. 1-8038.)

4.2
 
Warrant Registration Rights Agreement dated January 22, 1999, by and among the Company and 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 Form 8-K filed on February 3, 1999, File No. 1-8038.)

4.3
 
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 Form 8-K filed on November 30, 2007, File No. 1-8038.)

4.4
 
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 Form 8-K filed on November 30, 2007, File No. 1-8038.)

10.1†
 
Key Energy Group, Inc. 1997 Incentive Plan, as an amendment and restatement effective November 17, 1997 of the Key Energy Group, Inc. 1995 Outside Directors Stock Option Plan. (Incorporated by reference to Exhibit B of the Company's Schedule 14A Proxy Statement filed November 26, 1997, File No. 000-22665.)

10.2†
 
Form of Restricted Stock Agreement under Key Energy Group, Inc. 1997 Incentive Plan.

10.3†
 
The 2006 Phantom Share Plan of Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

10.4†
 
Form of Award Agreement under the 2006 Phantom Share Plan of Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.2 of the Company's Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

10.5†
 
Form of Stock Appreciation Rights Agreement. (Incorporated by Reference to Exhibit 99.1 of the Company's Form 8-K filed on August 24, 2007, File No. 1-8038.)


10.6†
 
Form of Non-Plan Option Agreement. (Incorporated by Reference to Exhibit 4.1 of the Company's Registration Statement on Form S-8 filed on September 25, 2007, File No. 333-146294.)

10.7†
 
Key Energy Services, Inc. 2007 Equity and Cash Incentive Plan. (Incorporated by Reference to Appendix A of the Company's Schedule 14A Proxy Statement filed on November 1, 2007, File No. 1-8038.)

10.8†*
 
Form of Nonstatutory Stock Option Agreement under 2007 Equity and Cash Incentive Plan.

10.9†
 
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 Form 8-K filed on January 7, 2008, File No. 1-8038.)

10.10†
 
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.)

10.11†
 
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 Form 8-K filed on January 7, 2008, File No. 1-8038.)

10.12†
 
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 Form 8-K filed on January 7, 2008, File No. 1-8038.)

10.13†
 
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.)

10.14†
 
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 Form 8-K filed on January 7, 2008, File No. 1-8038.)

10.15†
 
Employment Agreement between Key Energy Services, Inc. and Jim D. Flynt dated as of January 1, 2004. (Incorporated by reference to Exhibit 10.6 of the Company's Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

10.16†
 
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 Form 8-K filed on November 30, 2007, File No. 1-8038.)

10.17†
 
Employment Agreement between Key Energy Services, Inc. and Phil Coyne dated November 17, 2004. (Incorporated by reference to Exhibit 10.8 of the Company's Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

10.18†
 
First Amendment to Employment Agreement between the Company and Phil Coyne effective as of January 24, 2005. (Incorporated by reference to Exhibit 10.9 of the Company's Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

10.19†*
 
Amended and Restated Employment Agreement between Key Energy Services, Inc. and Don D. Weinheimer dated December 31, 2007.


10.20†
 
Employment Agreement dated August 14, 2007 between the Company 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. 1-8038.)

10.21†
 
Employment Agreement dated August 14, 2007 between the Company 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. 1-8038.)

10.22
 
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. 1-8038.)

10.23
 
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. 1-3038.)

10.24
 
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. 1-8038.)

10.25
 
Credit Agreement, dated as of June 29, 2005, among the Company, as Borrower, the several lenders from time to time party thereto, Lehman Brothers Inc., as sole lead arranger and sole book runner, Lehman Commercial Paper Inc., as syndication agent, administrative agent and as collateral agent, and Wells Fargo Foothill, Inc., as revolving administrative agent. (Incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K dated August 4, 2005, File No. 1-8038.)

10.26
 
First Amendment to Credit Agreement and First Amendment to Guaranty and Collateral Agreement dated as of November 1, 2005, among the Company, as Borrower, the Guarantors, the Lenders, and Lehman Commercial Paper Inc., as administrative agent for the Lenders and as Collateral Agent for the Lenders and other Secured Parties. (Incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K dated November 7, 2005, File No. 1-8038.)

10.27
 
Second Amendment to Credit Agreement dated as of November 21, 2006, among the Company, as Borrower, the Guarantors, the Lenders, and Lehman Commercial Paper Inc., as administrative agent for the Lenders and as Collateral Agent for the Lenders and other secured Parties. (Incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

10.28
 
Third Amendment to Credit Agreement dated as of July 27, 2007, among the Company, as Borrower, the Guarantors, the Lenders and Lehman Commercial Paper, Inc., as administrative agent for the Lenders and as Collateral Agent for the Lenders and other Secured Parties. (Incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K dated July 31, 2007, File No. 1-8038.)

10.29
 
Fourth Amendment to Credit Agreement dated as of November 12, 2007, among Key Energy Services, Inc., as Borrower, the guarantors signatory thereto, the Lenders, and Lehman Commercial Paper Inc., as administrative agent for the Lenders and as Collateral Agent for the Lenders and other Secured Parties. (Incorporated by Reference to Exhibit 10.1 of the Company's Form 8-K filed on November 15, 2007, File No. 1-8038.)


10.30
 
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 Form 8-K filed on November 30, 2007, File No. 1-8038.)

10.31
 
Stock and Membership Interest Purchase Agreement dated as of September 19, 2007. (Incorporated by Reference to Exhibit 10.1 of the Company's Form 8-K filed on September 20, 2007, File No. 1-8038.)

10.32
 
First Amendment to Stock and Membership Interest Purchase Agreement dated October 25, 2007, among Key Energy Services, LLC and the Sellers (as defined 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. 1-8038.)

10.33
 
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 Form 8-K filed on December 13, 2007, File No. 1-8038.)

10.33
 
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 Form 8-K filed on November 15, 2007, File No. 1-8038.)

21*
 
Significant Subsidiaries of the Company.

23*
 
Consent of Independent Registered Public Accounting Firm.

31.1*
 
Certification of CEO pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. of 2002.

31.2*
 
Certification of CFO pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32*
 
Certification of CEO and CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
†
Indicates a management contract or compensatory plan, contract or arrangement in which any Director or any Executive Officer participates.

*
Filed herewith.


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 26, 2008, 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 Statement of Financial Accounting Standards No. 123 (revised 2004), Share Based Payments, 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 26, 2008

S-1


Key Energy Services, Inc. and Subsidiaries

Schedule II—Valuation and Qualifying Accounts

(in thousands)

 
    
   Additions
    
    
 
   Balance at
Beginning of
Period
   Charged to
Expense
   Charged to
Other
Accounts
   Acquisitions
   Deductions
   Balance at
End of Period
Allowance for doubtful accounts:                                    
  As of December 31, 2007   $ 12,998   $ 3,675   $ —   $ 1,251   $ (4,423 ) $ 13,501
  As of December 31, 2006     10,843     1,854     301     —     —     12,998
  As of December 31, 2005     8,990     1,853     —     —     —     10,843

S-2