Key Energy Services 8K/A Results of Operations and Financial Condition | KEGX 26 Oct 06

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KEY ENERGY SERVICES, INC.

2003 FINANCIAL AND INFORMATIONAL REPORT

Key Energy Services, Inc.

INDEX

Introduction		1
Business		5
Risk Factors		13
Properties		25
Legal Proceedings and Other Actions		26
Market for the Registrant's Common Equity and Related Stockholder Matters		29
Management's Discussion and Analysis of Results of Operations and Financial Condition		30
Quantitative and Qualitative Disclosures About Market Risk		69
Consolidated Financial Statements and Supplementary Data		F-1
Controls and Procedures		72
Directors and Executive Officers		78
Executive Compensation		85
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		105
Certain Relationships and Related Transactions		108
Principal Accountant Fees and Services		110

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. Most of these statements are found in this report under the following subheadings: "Business," "Management's Discussion and Analysis of Results of Operations and Financial Condition," "Quantitative and Qualitative Disclosures About Market Risk" and "Controls and Procedures." In some cases, you can identify these statements by terminology such as "may," "will," "should," "could," "expects," "seek to," "anticipates," "plans," "believes," "estimates," "intends," "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 and as well as the risks outlined below. 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.

INTRODUCTION

Explanatory Note

This Financial and Informational Report presents financial and other information about Key Energy Services, Inc. (the Company," "Key," "we," "our" or "us"). This Report contains consolidated balance sheets for the Company as of December 31, 2003, December 31, 2002, and June 30, 2002, and consolidated statements of operations, comprehensive income, cash flows and stockholders' equity for fiscal periods ended December 31, 2003, December 31, 2002, June 30, 2002 and June 30, 2001. Our December 31, 2003 consolidated balance sheet ("2003 Balance Sheet") presents our financial condition as of that date in accordance with Generally Accepted Accounting Principles ("GAAP"). Based on the two issues described below, we were unable to conclude that our consolidated financial statements other than the 2003 Balance Sheet fairly present the Company's financial condition or results of operations or cash flows for the periods covered in accordance with GAAP.

Our consolidated financial statements other than the 2003 Balance Sheet are not presented in accordance with GAAP because we were unable with sufficient certainty to determine the appropriate period(s) in 2003 or before in which to record certain write-offs and write-downs that were identified in the Company's restatement process (described below). This problem arose in two areas: First, the Company had to write off fixed assets of $40.5 million that were carried on its books at December 31, 2003 but which, based on a complete physical inventory of the Company's assets, were found not to be in its possession as of December 31, 2003. The Company was unable, notwithstanding comprehensive efforts described in detail in this Report, to identify records or evidence that showed the actual period(s) in which the assets left its possession. Second, the Company's physical inventory identified numerous fixed assets the condition of which had changed prior to December 31, 2003, thereby necessitating adjustments to their carrying value. We were able to determine or estimate when the change in condition occurred for a significant majority of these assets and therefore the appropriate period(s) for recording the adjustments. With respect to $10.2 million of these adjustments, the Company was unable, notwithstanding its efforts, to identify evidence to determine when the change in condition occurred. In both cases, in light of the lack of evidence to support the specific period in which the relevant charges should be recorded, we determined to record the charges in the fourth quarter of 2003.

The Company's independent public accountants, KPMG LLP, have expressed an unqualified opinion that the 2003 Balance Sheet fairly presents our financial condition on December 31, 2003, in accordance with GAAP. They have also audited the other financial statements presented in this Report. They have opined that, due to the two issues discussed above, the financial statements other than the 2003 Balance Sheet do not fairly present the Company's financial condition or results of operations or cash flows for the periods covered in accordance with GAAP. Readers should carefully review the

independent auditors' report which is included in the section entitled "Consolidated Financial Statements and Supplementary Data."

The 2003 Balance Sheet reflects the cumulative effect of all adjustments to the Company's financial statements to correct errors in previously reported financial statements that were identified during the course of the Company's restatement process. This includes the write-offs for unlocated assets and write-downs for changes in condition described above. Our inability to determine the appropriate timing of these charges precludes us from presenting the statements other than the 2003 Balance Sheet in accordance with GAAP. However, because these charges occurred prior to December 31, 2003, our balance sheet as of that date is inclusive of all charges and is therefore presented in accordance with GAAP.

The presentation of charges for unlocated assets and changes in condition also affects other items in the relevant financial statements and related disclosures. Investors should recognize that accounting for one or more material items in a financial statement in a manner other than in accordance with GAAP means that the entire financial statement is deemed not to be presented in accordance with GAAP.

Investors are strongly cautioned not to rely on any of the financial statements contained herein, other than the 2003 Balance Sheet, as fairly presenting, for the periods covered, the financial condition of the Company or its statements of operations or cash flows, in accordance with GAAP. Any information set forth in this Report that incorporates or discusses information contained in the financial statements is subject to the same caution.

In light of the foregoing, the Company cannot satisfy the requirements of Securities and Exchange Commission ("SEC") rules that it file an Annual Report on Form 10-K containing financial statements presented in accordance with GAAP, accompanied by an opinion of independent public accountants, for three fiscal years ending December 31, 2003. Instead, the Company is filing this Report, which includes the 2003 Balance Sheet and the other consolidated financial statements as discussed above. This Report also provides information about the Company's business and other information similar to what would have been provided in an Annual Report on Form 10-K. Notwithstanding the limitations on the financial statements, the Company believes that it is important to provide investors as complete a picture as possible about the Company's historical financial condition and results, as well as to allow investors to see the nature of the restatement items and how they have been reflected in the Company's historical records.

The 2003 Balance Sheet will provide an opening balance sheet for fiscal years beginning after December 31, 2003. Therefore, the Company believes that it will be able to provide financial statements conforming to GAAP for subsequent fiscal periods. The Company does not intend to file Annual Reports on Form 10-K for fiscal years ended December 31, 2004 or 2005, respectively. In both cases, it will be unable to satisfy the requirement that it provide three years of audited financial statements, because it will not be able to provide audited statements of income and cash flows presented in accordance with GAAP and SEC rules for the year ended December 31, 2003. The Company does believe that it will be able to provide financial statements conforming to GAAP for the three years ended December 31, 2006. It therefore expects to file an Annual Report on Form 10-K for that year. SEC regulations also require that our 2006 Annual Report on Form 10-K include unaudited selected financial data presented in accordance with GAAP for the years ended December 31, 2003 and 2002, respectively. We will request a waiver from the SEC with respect to this requirement. We can make no assurance that such a waiver will be granted. The Company proposes to file Quarterly Reports on Form 10-Q for the first three quarters of 2005 and 2006. The 2005 10-Qs will also include 2004 quarterly information. The Company is unable to predict at this time when any of the foregoing filings will be made.

Financial Statement Impact of Accounting Errors

As discussed below, and elsewhere in this Report, we have restated our financial statements for 2002 and prior periods to adjust for numerous accounting errors in our previously-filed reports for those periods. Some of these issues also required adjustments to our financial statements for the fiscal year ended December 31, 2003. However, because we have not previously filed full-year financial statements for 2003, our financial statements for 2003 are not restated.

Our total reduction in net income for 2002 and prior years as a result of the restatement was $167.7 million. The reduction in net income reflects several matters. We recorded an aggregate net reduction in carrying value of our fixed assets of $168.6 million. The charges for fixed assets included write-downs of assets totalling $76.7 million and impairments of long-lived assets of $19.9 million. Also included in the fixed asset reductions are charges for improperly capitalized costs and changes in depreciable lives and other adjustments relating to fixed assets in an aggregate amount of $72.0 million. In addition, in the course of the restatement process we identified numerous other accounting errors for which restatements were required. The aggregate reductions in income resulting from these other matters recorded for 2002 and prior periods were $45.5 million. All of these reductions (totalling $214.1 million) were partially offset by income tax benefit adjustments of $46.4 million.

We reported a loss of $50.4 million for 2003. As discussed above, this loss includes a charge of $40.5 million for assets recorded on our balance sheet that could not be located and for which we could not determine the appropriate period for the charge. It also includes a charge of $10.2 million for changes in the condition of certain of our equipment as to which we could not identify and evidence the period in which such assets went out of service. We also recorded a charge of $5.2 million to write-off goodwill and non-compete agreements originally recorded in connection with an acquisition in our South Texas division. The Company also identified other accounting items which affected 2003 results. These other charges totaled approximately $31.6 million. All of these 2003 reductions (totaling $87.5 million) were partially offset by income tax benefit adjustments of $30.8 million. For more information, see the section entitled "Management's Discussion and Analysis of Results of Operations and Financial Condition—Summary—Financial Impact of Restatement Matters."

Restatement Process

The process that led to the restatement began in March 2004 as a review of our fixed assets following an internal investigation into alleged misappropriation of funds and diversion of our business and assets in our South Texas Division. Our review also encompassed allegations by our former chief financial officer and our former general counsel—largely concerning possible misconduct by our former chief executive officer—and related investigations conducted by our Board of Directors.

Our inability to generate fixed asset reports for each of our yards caused us to conduct a heightened review of our fixed assets. Following a review of both our centralized maintenance management system ("CMMS") and our fixed asset accounting ledger, we determined that there were significant issues with our fixed asset accounting. We learned that the CMMS system did not agree with our fixed asset accounting ledger and that certain information in both CMMS and the fixed asset accounting ledger was incorrect. This led to a comprehensive equipment inventory process during 2004 in which we identified all of our assets and classified each asset with an appropriate status, such as "active," "stacked" or "inactive." In numerous cases, equipment shown on our books could not be located.

The fixed asset review process took substantially longer than anticipated due to the poor condition of the Company's records, including records of when assets first came into service and when assets either became inactive, were sold or were scrapped. The counting and categorization of assets was also complicated because our assets were located at dispersed locations throughout the United States, Egypt and Argentina. Poor communication between our corporate accounting department and our operations

support team on the fixed asset review, as well as poor execution of the physical asset counts by our operations support team, also contributed to the delay.

The restatement process following the fixed asset inventory also proved to be substantially more difficult and time consuming than management anticipated. Among the factors that contributed to the delay were the scope and complexity of the fixed asset review, as described above, the need to make tens of thousands of individual entries in the Company's general ledger to reflect the proper valuation and depreciation of all fixed assets, the need to check and reconcile these entries, and the need to address multiple accounting issues raised by the fixed asset restatement. The time required to complete the restatement was also affected by the need to address the many other accounting issues that were identified during the restatement process, most of which required substantial analysis and development of supporting documentation. The timing of the process was also negatively affected by the Company's lack of adequate historical documentation, absence of a disciplined "close" process, inadequate staffing, and a lack of GAAP and financial reporting expertise by many of our former internal corporate accountants. The restatement process also identified material weaknesses in our internal control over financial reporting.

The Company has made significant changes to its management team. Since the restatement process began in 2004, we have made changes to or added the following positions: Chief Executive Officer, Chief Financial Officer, General Counsel, Chief People Officer, Chief Accounting Officer, Senior Vice President—Eastern Region, Senior Vice President—Operations Support, Vice President—Procurement, Vice President—Performance Management, Vice President—Western Hemisphere International, Director of Financial Reporting, Director of Risk Management, Director of Disbursements and Director of Tax. We have significantly expanded our internal accounting staff and our internal audit department, and we have made numerous changes to our operations management team as well. Our new management has implemented and continues to implement changes to our personnel, processes and controls to address the material weaknesses identified during the restatement and to improve the reliability of our financial statements.

For a discussion of the restatement of our financial statements, see the section entitled "Consolidated Financial Statements and Supplementary Data," Note 2—"Restatement of Financial Statements." For a discussion of the effects of the restatement and other matters addressed herein on our operating results and on our liquidity and capital resources at December 31, 2003, see the section entitled "Management's Discussion and Analysis of Results of Operations and Financial Condition." For a discussion of the risks associated with the restatement, our inability to file our required periodic reports, and other matters, see the section entitled "Risk Factors." For a discussion of control weaknesses that contributed to the accounting issues and the changes we have made or are in the process of making to our control procedures, see the section entitled "Controls and Procedures." For a discussion of items pertaining to fiscal year ended December 31, 2003, see the sections entitled "Consolidated Financial Statements and Supplementary Data," Note 3—"South Texas Matters," and Note 4—"Property and Equipment."

We have not amended and do not intend to amend our previously-filed Annual Reports on Form 10-K or our Quarterly Reports on Form 10-Q for the periods that ended prior to and including September 30, 2003. Consequently, you should not rely on historical information contained in those prior filings.

This Report covers the year ended December 31, 2003 and prior periods. However, in light of the passage of time since December 31, 2003, we also include discussions of subsequent developments as we believe appropriate.

BUSINESS.

THE COMPANY

Key is a Maryland corporation that was organized in April 1977 and commenced operations in July 1978 under the name National Environmental Group, Inc. We emerged from a prepackaged bankruptcy plan in December 1992 as Key Energy Group, Inc. On December 9, 1998, we changed our name to Key Energy Services, Inc. and we believe that we are now the leading onshore, rig-based well servicing contractor in the United States. Since 1994, we have grown rapidly through a series of over 100 acquisitions, and today we provide a complete range of well services to major oil companies and independent oil and natural gas production companies, including rig-based well maintenance, workover, well completion, and recompletion services; oilfield transportation services; fishing and rental services; pressure pumping services; and ancillary oilfield services. During 2003, 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 ArkLaTex and North Texas regions), Four Corners (including the San Juan, Piceance, Uinta, and Paradox Basins), Eastern (including the Appalachian and Michigan Basins), 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, Egypt and Canada (Ontario). We also provide onshore drilling services. During 2003, we conducted land drilling operations in a number of major domestic producing basins including the Permian Basin, the San Juan Basin, the Powder River Basin, and the Appalachian Basin, as well as internationally in Argentina; however, we sold all of our Permian Basin and San Juan Basin contract drilling assets as well as certain drilling assets located in the Rocky Mountain region to Patterson-UTI Energy, Inc. on January 15, 2005. As of August 31, 2006, we continue to conduct land drilling operations domestically in the Appalachian Basin of West Virginia and the Powder River Basin of Wyoming as well as internationally in Argentina through the use of approximately 13 rigs.

Key's principal executive office is currently located at 1301 McKinney Street, Suite 1800, Houston, Texas 77010. Our phone number is (713) 651-4300 and website address iswww.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 (although, as noted above, historical information contained in our previously-filed annual and quarterly reports for the periods affected by the restatement should not be relied upon). Information on our website is not a part of this report.

DESCRIPTION OF BUSINESS SEGMENTS

Key operated in two primary business segments during 2003, which were well servicing and contract drilling. Key's operations during 2003 were conducted in various regions in the continental United States, and internationally in Argentina, Egypt and Canada; however, in 2004 we shut down our operation in Ontario, Canada, and our contract in Egypt was completed on June 30, 2005. The following is a description of both of these business segments. For financial information regarding these business segments, see the section entitled "Consolidated Financial Statements and Supplementary Data," Note 19—"Segment Information."

WELL SERVICING

Key provides a broad range of well services, including rig-based services, oilfield transportation services, fishing and rental tool services, pressure pumping services and other ancillary oilfield services necessary to complete, stimulate, maintain and workover oil and natural gas producing wells. 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.

Well Service Rigs

We use our well service rig fleet to perform four major categories of rig services for oil and natural gas producers. 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, down for repairs but with work orders assigned to it or 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, if we intend to sell the unit or if we intend to scrap the unit. The definitions of active, stacked and inactive are used for the majority of our equipment, including rigs.

Maintenance Services. Key provides 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 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, Key's rigs are used to seal off depleted zones in existing wellbores and access previously bypassed productive zones. Our workover rigs are also used to convert former producing wells to injection wells through which water or carbon dioxide is pumped into the formation for enhanced recovery operations. Other workover services include: conducting major subsurface repairs such as casing repair or replacement, recovering tubing and removing foreign objects in the wellbore, repairing downhole equipment failures, plugging back a section of a well to reduce the amount of water being produced with the oil and natural gas, cleaning out and recompleting a well if production has declined, and repairing leaks in the tubing and casing. These extensive workover operations are normally performed by a well service rig with a workover package, which may include rotary drilling equipment, mud pumps, mud tanks and blowout preventers, depending upon the particular type of workover operation. Most of our well service rigs are designed to perform complex workover operations.

Workover services are more complex and time consuming than routine maintenance operations and consequently may last from a few days to several weeks. These services are almost exclusively performed by well service rigs.

Completion Services. Key's 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 servicing rig along with wireline and cementing equipment. The services generally include the sale or disposal of equipment salvaged from the well as part of the compensation received and 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

Key provides oilfield transportation services, which primarily include vacuum truck services, fluid transportation services and disposal services for operators whose oil or natural gas wells produce saltwater 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/workover fluids. These fluids are removed from the well site and transported for disposal in a salt water disposal well. Key owned or operated 80 active salt water disposal wells at December 31, 2003. As of August 31, 2006, we owned or operated 54 active salt water disposal wells. In addition, we provide equipment trucks that are used to move large pieces of equipment from one wellsite to the next and 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 relate to demand for Key's 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.

Fishing and Rental Services

We provide fishing and rental services to major and independent oil and natural gas production companies in the Gulf Coast, Mid-Continent, and Permian Basin regions of the United States, as well as in California. Fishing services involve recovering lost or stuck equipment in the wellbore and a "fishing tool" is a downhole tool designed to recover any such equipment lost in the well. The fishing tool supervisors who manage the fishing process have extensive experience with downhole problems. In

addition, Key offers a full line of services and rental equipment designed for use both on land and offshore for drilling and workover services. Our rental tool inventory consists of tubulars, handling tools, pressure-control equipment and a fleet of power swivels. During 2003, our primary fishing and rental tool operations operated under the names Quality Tubular Services and Landmark Fishing and Rental Tools. We combined those operations effective January 1, 2004, and they now operate as Key Energy Fishing & Rental Services. Additionally, we expanded our fishing and rental operations to the Rocky Mountains with the opening of a facility in Colorado in the summer of 2004.

Pressure Pumping Services

For the year ended December 31, 2003, Key's pressure pumping business operated under the name American Energy Services; however, in February 2004 we renamed our pressure pumping services operation Key Energy Pressure Pumping Services. This division provides well stimulation and cementing services. 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. Key offers a full complement of acidizing, fracturing, nitrogen and cementing services. At December 31, 2003, Key provided over 80,000 horsepower in cementing and stimulation equipment. Key's pressure pumping services in 2003 were provided in the Permian Basin, the San Juan Basin, the North Texas region and the Mid-Continent region.

In February 2004, we expanded our pressure pumping operations through the acquisition of Fleet Cementers, Inc., a wholly owned subsidiary of Precision Drilling Corporation, for approximately $20 million in cash. Fleet Cementers provided pressure pumping services, including cementing, fracturing, acidizing, coiled tubing pumping and nitrogen pumping with primary operations in California and Texas. In connection with the Fleet acquisition, we relocated certain of the Fleet assets to the Barnett Shale region of North Texas. In late 2004, we expanded our pressure pumping operation with the purchase of approximately 12,000 horsepower of new pressure pumping equipment, and in 2005 we further expanded this business through the purchase of additional horsepower and additional cementing assets which we took delivery of during the fall of 2005 and early 2006. Our current pressure pumping and cementing capacity is approximately 162,000 horsepower.

Our pressure pumping services rely heavily on two suppliers for sized sand, a principal raw material that is critical for our pressure pumping operations. In the event we were to have a problem sourcing raw materials from either of these vendors, we could face a serious disruption in our ability to deliver pressure pumping services.

Ancillary Oilfield Services

Key provides ancillary oilfield services, which include, among others: electric wireline operations (conveying downhole tools and information); wellsite construction (preparation of a wellsite for drilling activities); roustabout services (provision of manpower to assist with activities on a wellsite); foam air services (drilling technique using air or gas to which a foaming agent has been added); 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.

CONTRACT DRILLING

During 2003, we provided contract drilling services to major oil companies and independent oil and natural gas producers onshore in the continental United States in the Permian Basin, the Four

Corners region, the Appalachian Basin and the Rocky Mountains; however, on January 15, 2005, we completed the sale of the majority of our contract drilling assets, which included the drilling rigs and associated equipment in the Permian Basin and Four Corners and certain rigs from the Rocky Mountain region. In consideration of the sale, we received $62.0 million in cash and retained net working capital of approximately $10 million. 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. Prior to the sale, our drilling rigs varied in size and capability and in some cases included specialized equipment. The majority of Key's drilling rigs were equipped with mechanical power systems and had drilling depth capabilities ranging from approximately 4,500 to 12,000 feet. We operated one drilling rig with a depth rating of approximately 18,000 feet.

We continue to provide limited drilling services to oil and natural gas producers with 13 rigs onshore in the continental United States in the Appalachian Basin and the Powder River Basin of Wyoming and internationally in Argentina. The existing drilling services are primarily provided under standard dayrate, and, to a lesser extent, footage contracts, although our coal bed methane drilling rigs in the Powder River Basin are typically priced on a footage basis. The remaining drilling rigs vary in size and capability. The Argentina rigs 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. The coal bed methane drilling rigs have depth ratings between 1,200 to 1,800 feet. Like workover services, the demand for contract drilling is directly related to expectations relating to, and changes in, oil and natural gas prices which, in turn, are driven by the supply of and demand for these commodities.

DISCONTINUED OPERATIONS

Key sold its oil and natural gas properties for $19.7 million in cash on August 28, 2003. We received net cash proceeds of $7.5 million after repaying our volumetric production payment, unwinding related hedge arrangements with our banks and paying other related costs. As a result of the sale, we treated our oil and natural gas production business as a discontinued operation for all periods and recorded an after-tax charge to discontinued operations of $4.8 million, or $0.04 per diluted share, during the year ended December 31, 2003.

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 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. Finally, during the fourth quarter, we historically have experienced significant slowdown during the Thanksgiving and Christmas holiday seasons.

PATENTS, TRADE SECRETS, TRADEMARKS AND COPYRIGHTS

Key is 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. Key has devoted significant resources to developing technological improvements in our well service business and has 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, 2003, we had 18 patents issued and 13 patents pending. In the United States, as of August 31, 2006, we had 24 patents issued and 17 patents pending. As of December 31, 2003, we had one patent issued and 15 patents pending in foreign countries. As of August 31, 2006, we had three

patents issued and 85 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 wellsite 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. Depending upon the jurisdiction, trademarks are valid as long as they are in use and/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.

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

FOREIGN OPERATIONS

At December 31, 2003, we operated internationally in Argentina, Egypt and Canada. In 2003, our operations in Argentina operated 29 well service rigs and seven drilling rigs which we included in our well service segment; our Ontario, Canada operation operated one well service rig; and our Egypt operation operated five well service rigs. We also provided oilfield transportation services in all three foreign operations. During 2004, we closed our Ontario, Canada operation and relocated those assets to our Michigan operation, which was subsequently sold on May 17, 2005. As described below, during 2005, our contract in Egypt terminated. As of August 31, 2006, we continued to operate internationally in Argentina with approximately 33 active well service rigs and six drilling rigs. Revenue from our international operations during 2003 totaled $45.2 million, or 4.9% of total revenue. For a discussion of the effects of Argentina foreign currency transactions, see the section entitled "Consolidated Financial Statements and Supplementary Data," Note 13—"Argentina Foreign Currency Translation Loss."

In Egypt we operated five well service rigs and a number of oilfield service vehicles under a two-year contract we signed with Apache Corporation on March 28, 2002. While Apache extended the contract for limited periods, Apache did not exercise its right to extend the agreement for two additional one-year periods. In July 2005, the remaining work under the contract was completed, and as of December 2005, all five rigs and oilfield service vehicles were shipped back to the United States and redeployed. Under the terms of the agreement, Apache paid all demobilization costs associated with these rigs. For information on the risks associated with our international operations, see the section entitled "Risk Factors—Business and Debt-Related Risk Factors."

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, 2005, December 31, 2004 and December 31, 2003, and the six months ended December 31, 2002, no single customer accounted for 10% or more of our consolidated revenues. One customer accounted for 10% or more of our consolidated revenues for the fiscal year ended June 30, 2002.

COMPETITION AND OTHER EXTERNAL FACTORS

Despite the significant consolidation in the domestic well servicing industry, there are numerous smaller companies that compete in Key's well servicing markets.

In the well servicing markets, we believe that we are the largest provider of well service rigs based on available industry data. At August 31, 2006, we had 867 active rigs in the United States. Based on the Weatherford-AESC well service rig count, which is available on Weatherford International's internet website, there were approximately 2,757 well service rigs in the United States at August 31, 2006 and approximately 2,550 well service rigs in the United States in December 2003. In addition, Nabors Industries has recently represented that it operates approximately 460 well service rigs, while Basic Energy Services has approximately 356 well service rigs. We do not believe that any other competitors have greater numbers of marketed well service rigs than Key. In Argentina, our largest competitor is Pride International.

We believe that an important competitive factor in establishing and maintaining long-term customer relationships is having an experienced, skilled and well-trained work force. In recent years, many of Key's larger customers have placed increased emphasis on the safety performance and quality of the crews, equipment and services provided by their contractors. Key has devoted, and will continue to devote, substantial resources toward employee safety and training programs. In addition, we believe that the KeyView® system will provide important safety enhancements. Further, we believe that most customers are willing to pay a slight premium for the quality and efficient service we provide.

The pressure pumping market is dominated by three large 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 and RPC, Inc. The pressure pumping industry is very competitive, and the three major competitors generally lead pricing in any particular region. Our pressure pumping services operate in niche markets and historically have competed effectively with these competitors based on performance and strong customer service. Where feasible, we cross-market our 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 tool 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 tools will be part of that job as well. Our primary competitors include: Baker Oil Tools, Smith International, Weatherford International, Basic Energy Services and Knight Oil Tools.

In the contract drilling market, Key competed with other regional and national oil and natural gas drilling contractors during 2003. Some of these contractors had larger rig fleets with greater average depth capabilities and most had better equipment than Key. We believe that the contract drilling industry is less consolidated than the well servicing industry, resulting in a contract drilling market that is more price competitive. As a result of the sale of a majority of our contract drilling assets in January 2005, our current domestic competition consists primarily of small, regional drilling contractors. In the fragmented Powder River Basin market, we compete primarily with other coal bed methane drillers, most of which are privately held. In Argentina, our largest competitor is Pride International.

The need for well servicing and contract drilling 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 Key's revenues, cash flows, losses and earnings are substantially dependent upon, and affected by, the level of domestic and international oil and gas exploration and development activity. For a more detailed discussion, please see the section entitled "Management's Discussion and Analysis of Results of Operations and Financial Condition."

EMPLOYEES

As of December 31, 2003, we employed approximately 8,350 persons. At December 31, 2005, we employed approximately 8,250 persons. Our contract drilling business, which was sold on January 15, 2005, had approximately 600 employees. Our domestic employees are not represented by a labor union and are not covered by collective bargaining agreements; however, many of our field employees in Argentina are represented by unions. We have not experienced any material work stoppages associated with labor disputes or grievances and consider our relations with our employees to be satisfactory. We historically have experienced an annual employee turnover rate of over 50%. 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 the Company if they can earn a higher wage with a competitor. A discussion of the risks associated with our high turnover is presented under the section entitled "Risk Factors—Business and Debt-Related Risk Factors."

ENVIRONMENTAL REGULATIONS

Key's operations are subject to various federal, state, and local laws and regulations intended to protect the environment. Key's 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 pollutants we may discharge to waters or emit to air from our activities. 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. 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 Key's financial condition, results of operations and cash flows. From time to time, claims have been made and litigation has been brought against Key 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 Key's operations or financial statements in the past, and management does not believe such costs are likely to have any such material adverse effect in the future. Management believes that it has implemented policies designed to assure that Key conducts its operations in compliance with federal, state and local requirements as they relate to the environment.

RISK FACTORS.

In addition to the other information in this report, the following factors should be considered in evaluating us and our business.

Restatement-Related Risk Factors

The process of restating our financial statements and related events has had, and will continue to have, a material adverse effect on us.

As described in greater detail in this report, we determined in March 2004 that we would need to restate our historical financial statements. Since that time, as a result of our need to complete the restatement process, we have been unable to file our required periodic reports with the SEC. Through the restatement process, we identified numerous items requiring restatement and other accounting errors affecting our 2003 financial statements, which substantially delayed our preparation of such financial statements.

We have now completed our financial statements for the year ended December 31, 2003 and the restatement of prior periods; however, these financial statements, except for the 2003 Balance Sheet, are not presented in accordance with GAAP. In light of this, our independent public accountants have opined that, except for the 2003 Balance Sheet, our financial statements for 2003 and prior periods do not fairly present our financial condition or results of operations or cash flows for the periods presented in accordance with GAAP. Therefore, we are unable to file this report with the SEC as a periodic report in compliance with the SEC's regulations. We also will not be able to file our annual reports for 2004 and 2005 with the SEC due to our inability to include the required three years of financial statements for those years. We have not yet completed our quarterly reports for 2005 and the first two quarters of 2006, and we will also be unable to timely file our quarterly report for the third quarter of 2006.

As a result of these events, we have become subject to significant risks and occurrences relating to the following matters, which are described in more detail below:

•: Impact of failure to file a compliant Form 10-K for 2003;
•: Unreliability of prior financial statements and reports;
•: Negative impact on our business;
•: Potential inability to file a compliant Form 10-K for 2006;
•: Substantial expenditures related to the restatement and the financial reporting process, including waiver fees to creditors and professional fees;
•: Restrictions on access to public capital markets;
•: Potential deregistration of our common stock;
•: Common stock unable to trade on a recognized exchange;
•: Impact of material weaknesses in internal control over financial reporting;
•: Potential changes in tax liabilities;
•: Ongoing investigations by the SEC and other governmental agencies; and
��: Civil litigation.

Our inability to file a 2003 Annual Report on Form 10-K that complies with the SEC's regulations results in non-compliance with SEC rules and will require us to get a waiver from our lenders.

As explained in more detail in the section entitled "Consolidated Financial Statements and Supplementary Data," Note 1—"Organization and Summary of Significant Accounting Policies—Basis of Presentation," our financial statements in this report, besides the 2003 Balance Sheet, are not presented in accordance with GAAP, because we were unable in the restatement process to identify and evidence the appropriate period(s) in 2003 or before in which to record certain write-offs and write-downs of fixed assets. Our independent public accountants therefore expressed an adverse opinion on our financial statements other than the 2003 Balance Sheet. As a result, we cannot file our annual reports for 2003, 2004 or 2005 with the SEC because our financial statements do not comply with the SEC's requirements.

Because of our inability to file the required reports, we are not and will not be in compliance with the SEC's regulations and the federal securities laws. We may be subject to enforcement action by the SEC.

Under the terms of our $547.25 million senior secured credit facility, we are required to provide to our lenders audited financial statements, including for the 2003 fiscal year, and unaudited quarterly financial statements, in each case meeting the requirements of SEC regulations, no later than March 16, 2007. The credit facility provides that we have 30 days from that date to fulfill this requirement before an event of default has occurred. Because we are unable to provide 2003 financial statements that comply with the SEC's regulations, we will be required by April 2007 either to seek a waiver from our lenders or refinance the credit facility, or risk an event of default. We can make no assurances that a waiver will be granted by our lenders or about the terms on which it might be granted. If we default, our lenders will no longer be obligated to extend credit to us and could elect to declare all amounts outstanding under the credit agreement, 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 and financial condition.

This report should not be relied upon as fairly presenting the financial condition of the Company or its statements of operations or cash flows in accordance with GAAP. Our prior historic reports filed with the SEC are inaccurate.

This report has not been prepared in accordance with the SEC's financial reporting requirements, and our independent public accountants have opined that certain of the financial statements contained herein are not presented in accordance with GAAP. As a result, the financial and other information included in this report other than the 2003 Balance Sheet, should not be relied upon as fairly presenting, for the periods presented, the financial condition of the Company or its statements of operations or cash flows in accordance with GAAP. In addition, although we have restated our financial statements for the historical periods presented in this report, we have not amended the periodic reports we have on file with the SEC for the historical periods. As a result, the financial and other information included in those historical reports should not be relied upon.

The restatement process has negatively affected our business in certain respects. This situation will likely continue at least until we have filed our 2006 Annual Report on Form 10-K.

While we believe our underlying business is sound, the restatement process has delayed the completion of some internal initiatives to improve operations, has curtailed our acquisition program, restricted our business development opportunities and limited our ability to refinance our debt at interest rates and on terms commensurate with our financial position. The business impact of the restatement is discussed in this report in the section entitled "Management's Discussion and Analysis of Results of Operations and Financial Condition—Business Impact of the Restatement."

Since announcing we would restate our prior period financial statements, we have had restricted access to financing for possible acquisitions, and we could not, and still cannot, issue public securities to refinance debt or finance other strategic initiatives. Until we file our 2006 Annual Report, we expect that we will not be able to consider significant acquisitions or other initiatives that require substantial external financing. We also may not be able to refinance our debt to achieve better terms and rates of interest commensurate with our financial condition. As a result, until our financial statements and related SEC filings are in compliance with the SEC's regulations, our operations may continue to be adversely affected, and our ability to lower our interest costs will be impeded. We cannot predict at this time when the 2006 Form 10-K or interim quarterly reports for 2005 and 2006 will be filed. Ongoing delays in completing these filings could adversely affect our operations, the trading market for our common stock, and our ability to obtain financing.

We may be unable to file an Annual Report on Form 10-K that complies with the SEC's regulations for the fiscal year ending December 31, 2006.

We believe that we will be able to file a 2006 Annual Report on Form 10-K that complies with SEC regulations, but there can be no assurance that this will occur, or that our independent public accountants will express an unqualified opinion on our financial statements for the period ended December 31, 2006. If we are unable to obtain unqualified audit reports on our financial statements from the independent public accountants, then we may not be able to comply with various financial covenants in our debt instruments. Also, SEC regulations require that our 2006 Annual Report on Form 10-K include unaudited selected financial data prepared in accordance with GAAP for the years ended December 31, 2003 and 2002, respectively. We will request a waiver from the SEC with respect to this requirement, but there can be no assurance that such waiver will be granted.

We have spent substantial amounts in connection with the restatement and related events and we expect to continue to incur substantial expenditures related to these matters.

We estimate that during 2004 and 2005 we spent in excess of $50.0 million to, among other things, carry out the restatement of our financial statements, conduct internal investigations and respond to government investigations. This includes payments of over $20 million to creditors to obtain waivers required as a result of our delay in making required SEC filings. It also includes fees to our independent public accountants, fees to consultants engaged to assist in the restatement process, advisory fees and legal fees. At least until we have filed our 2006 Annual Report on Form 10-K, including the review of internal control over financial reporting mandated by the Sarbanes-Oxley Act, we expect to spend substantial additional sums. We also expect to continue to incur substantial legal fees and other costs to respond to government investigations and defend litigation. We cannot predict the amount of additional future expenses that may be incurred. Payment of these amounts adversely affects our results of operations and liquidity.

We are currently unable to register securities for a public offering or an acquisition or access our shelf registration statement filed with the SEC, which could adversely affect our liquidity and ability to complete acquisitions. We also cannot repurchase our common stock.

Our current inability to file periodic reports prevents us from registering securities for a public offering or an acquisition and from issuing securities under a shelf registration statement we previously had filed with the SEC. As a result, our ability to access the capital markets is constrained, which could adversely affect our liquidity, and we are unable to consider acquisitions in which we would issue registered securities. Further, although we should be able to register securities for public offerings and acquisitions after we have filed our 2006 Annual Report on Form 10-K, under current SEC rules we will not be eligible for "short-form" registration or shelf registration until, among other things, we have timely filed reports for at least one year. This could increase the costs of selling securities publicly and

could significantly delay such sales. Further, the lack of current financial statements could impede our ability to raise capital privately. We also will be unable to engage in other transactions involving our common stock, including a stock repurchase, until we have become current in our financial disclosures.

Because we have not filed periodic reports with the SEC for a substantial length of time, the SEC could take action to revoke the registration of our common stock under the Securities Exchange Act of 1934, which would adversely affect the liquidity of our common stock.

Because our common stock is registered under the Securities Exchange Act of 1934, we are required by the SEC to file annual and quarterly reports with the SEC. Due to the restatement process and our inability to file compliant annual reports with the SEC for 2003, 2004 and 2005, we cannot meet this requirement. As a result the SEC could initiate proceedings to revoke the registration of our common stock. If the registration of our common stock were revoked, brokers and dealers would be unable to trade in or recommend our common stock until our common stock was again registered under the Exchange Act.

Our common stock no longer trades on an exchange, which could adversely affect the trading market for the shares.

The New York Stock Exchange ("NYSE") commenced delisting procedures with respect to our common stock due to our failure to file our 2003 Annual Report on Form 10-K by March 31, 2005. We ceased trading on the NYSE on April 7, 2005 and were officially delisted on May 5, 2005. Since April 8, 2005, we have been trading on the Pink Sheets Electronic Quotation Service.

Being quoted only on the Pink Sheets could (though we believe has not to date) lead to significantly less liquidity in our common stock. The trading volume of our common shares could be less than the trading volume that would have occurred had our common stock been listed, which could negatively affect the market price of the stock. In addition, our ability to raise capital through equity financing could be impaired by our shares not trading on a recognized exchange. Furthermore, our failure to be listed on a recognized exchange could decrease institutional demand for our common stock or there may be less individual investor demand, analyst coverage, market making activity and available information concerning trading prices and volume. Fewer broker-dealers may be willing to execute trades in our common stock. All of these factors could adversely affect the trading market—and potentially the market price—for our common stock.

If we are unable to obtain unqualified independent audit reports on our financial statements, our ability to have our securities relisted on a recognized securities exchange would be adversely affected.

We have identified material weaknesses in our internal control over financial reporting. Failure to remediate these weaknesses, or the identification of other weaknesses, could affect the reliability of our financial statements and have other adverse consequences. A qualified or disclaimed auditor attestation report on our internal control over financial reporting could also have adverse effects.

Since 2004, Section 404 of the Sarbanes-Oxley Act and the related SEC rules have required 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, that results in a more than remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

As described in the section entitled "Controls and Procedures," the restatement process identified material weaknesses in our internal control over financial reporting. These material weaknesses resulted in misstatements in our financial statements. We cannot predict at this time whether our independent public accountants will be able to deliver an attestation report, or whether the independent public accountants will qualify their report, or disclaim a report, with respect to our internal control over financial reporting when we file our 2006 Annual Report on Form 10-K.

While we are implementing steps to ensure the effectiveness of our internal control over financial reporting, we or our independent public accountants may identify additional material weaknesses as part of the Section 404 assessment process. If a weakness is identified, we would be required to take additional actions to remediate the weakness.

The existence of a material weakness would indicate that there is a risk of a material misstatement of our financial statements, and, depending on the nature of the material weakness, could be viewed negatively by investors and result in an adverse impact on the market price for our common stock. If our independent public accountants qualify their attestation report or disclaim an opinion, this could adversely affect our ability to be relisted on a securities exchange. This also could be viewed negatively by investors and have an adverse impact on the market for our common stock.

Taxing authorities may determine that we owe additional taxes from previous years due to our restatement.

As a result of the restatement, we may have to amend previously filed tax returns and reports if we determine that the restatement, or findings from the restatement process, has affected our tax positions reflected in such returns or 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.

Governmental investigations could result in significant fines and penalties and have other adverse effects on us.

In March 2004, we contacted the SEC in connection with our issuance of a press release announcing the delay in the filing of our 2003 annual report, the expected restatement and our internal investigations. The Fort Worth office of the SEC commenced an inquiry relating to such matters shortly thereafter, and the SEC opened a formal investigation in July 2004. In addition, in January 2005, we received a federal grand jury subpoena for the production of documents in connection with an investigation being conducted by the U.S. Attorney's Office for the Western District of Texas. The SEC and grand jury investigations remain pending. Responding to the inquiries has required, and is likely to continue to require, significant management attention and corporate resources. The filing of our restated financial statements will not resolve the pending investigations.

The resolution of the SEC investigation could require additional restatements of our financial statements or other actions not presently contemplated. If the SEC were to assert that we violated the securities laws, an adverse decision by the SEC or the courts, or a settlement of such a matter, could lead to significant fines and penalties, as well as limitations on our activities and on our ability to rely on certain securities law safe harbors available to other companies. Similarly, if the U.S. Attorney's office were to bring criminal charges against us, that too could lead to significant fines and restrictions on our activities if we were convicted of an offense.

We believe that we have cooperated fully during the course of these investigations. If the SEC's investigation or the criminal investigation result in any regulatory or criminal proceedings against the

Company, our financial condition, results of operations, and business could be adversely affected. We cannot predict the length or the ultimate outcome of these matters, nor their potential impact on us.

Litigation arising in connection with the restatement of our financial statements could adversely affect our financial condition and operations.

The restatement has led to litigation. Several securities class action lawsuits and derivative cases have been filed against us, members of our Board of Directors and present and former members of management. Further, in response to our notice to terminate him for cause effective May 1, 2004, our former chief executive officer, Francis D. John, has filed a lawsuit against us. He alleges, among other things, that we breached stock option agreements and his employment agreement. We have filed an answer and counterclaim in response to Mr. John's complaint. We have also been named in a lawsuit by our former general counsel, Jack D. Loftis, Jr. Mr. Loftis alleges breach of contract, breach of good faith and fair dealing, breach of fiduciary duty, wrongful termination, and violation of the "whistle-blower" provisions of the Sarbanes-Oxley Act. Mr. Loftis previously filed a "whistle-blower" claim under the Sarbanes-Oxley Act with the Department of Labor ("DOL"). The DOL 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. Additionally, on August 21, 2006, our former chief financial officer, Royce W. Mitchell, filed a suit against us alleging breach of contract with regard to alleged bonuses, benefits and expense reimbursements, conditional stock grants and stock options to which he believes himself entitled; as well as relief under theories of quantum meruit, promissory estoppel, and specific performance. Further, our former controller and assistant controller filed a joint complaint against us alleging constructive termination and breach of contract.

Due to our inability to issue shares of common stock upon exercise of options because we cannot maintain an effective SEC registration statement for those shares, or to rely on an exemption from registration, some previously granted options that were in-the-money have expired without the optionees being able to exercise them. Although we believe the plan agreements permit our actions taken thus far with respect to stock options, we are defending lawsuits by some option holders and may face lawsuits from other option holders. The lawsuits and other legal matters in which we have become involved following the announcement of the restatement are described under the section entitled "Legal Proceedings and Other Actions."

Other than actions that have been previously settled, we are unable at this time to predict the outcome of pending actions or to reasonably estimate a range of damages in the event the plaintiffs in these, or other lawsuits that might be filed relating to the same events, prevail on one or more of their claims. The ultimate resolution of these matters could have a material adverse impact on our financial results, financial condition or liquidity, and on the trading price of our common stock.

These lawsuits and other legal matters also could have a disruptive effect upon the operation of our business and consume the time and attention of our senior management. In addition, we are likely to incur substantial expenses in connection with such matters, including substantial fees for attorneys.

We maintain insurance that may provide coverage for some or all of these matters. We have given notice to our insurers of the claims. The insurers have responded by requesting additional information and by reserving their rights under the policies, including the rights to deny coverage under various policy exclusions or to rescind the policies in question as a result of our announced restatement of our financial statements. There is risk that the insurers will rescind the policies; that some or all of the claims will not be covered by such policies; or that, even if covered, our ultimate liability will exceed the available insurance.

Business and Debt-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 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 rates for, and lower utilization of, available well service equipment. 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 drilling and maintenance work for us. Additional factors that affect demand for our services include:

•: the level of development, exploration and production activity of, and corresponding capital spending by, oil and natural gas companies;
•: oil and natural gas production costs;
•: government regulation; and
•: conditions in the worldwide oil and natural gas industry.

In addition, we anticipate that prices for oil and natural gas will continue to be volatile and affect the demand for and pricing of our services. Decreases in oil and natural gas prices can result in a reduction in the trading prices and value of our securities, even if the decreases in oil and natural gas prices do not affect our business directly. Moreover, a material decline in oil or natural gas prices or activities over a sustained period of time could materially adversely affect the demand for our services and, therefore, our results of operations and financial condition.

Periods of diminished or weakened demand for our services have occurred in the past. Although we experienced a decrease in the demand for our services beginning in August 2001 and continuing through September 2002, since September 2002 we have experienced continued improvement in the 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.

An economic downturn may adversely affect our business.

The U.S. economy is currently strong; however a downturn in the U.S. economy may cause reduced demand for petroleum-based products and natural gas. In addition, 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. We view the Baker Hughes U.S. land drilling rig count as a good barometer of oilfield service activity, which is driven by capital spending from oil and natural gas production companies. According to available industry data, in 2003, the average U.S. land drilling rig count was approximately 924 working rigs, as compared to an average of approximately 717 working rigs in 2002. In 2005, there were on average approximately 1,290 land drilling rigs working in the United States, as compared to an average of 1,095 land drilling rigs in 2004. As of August 31, 2006, the number of drilling rigs had increased to 1,639. During the last economic

downturn in 2002, the number of land drilling rigs averaged 717. The number of land drilling rigs may be seen as indicative of the demand for services such as those we provide. If the economic environment worsens, 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:

•: blow-outs, the uncontrolled flow of natural gas, oil or other well fluids into the atmosphere or an underground formation;
•: reservoir damage;
•: fires and explosions;
•: accidents resulting in serious bodily injury and the loss of life or property;
•: pollution and other damage to the environment; and
•: liabilities from accidents or damage by our fleet of trucks, rigs and other equipment.

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

We self-insure a significant portion of these liabilities. For losses in excess of our self-insurance limits, we maintain insurance from unaffiliated commercial carriers. However, our insurance may not be adequate to cover all losses or liabilities that we might incur in our operations. Furthermore, our insurance may not adequately protect us against liability from all of the hazards of our business. We also are subject to the risk that we may not be able to maintain or obtain insurance of the type and amount we desire at a reasonable 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 and results of operations.

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 may expand our operations into other foreign countries. As a result, we are exposed to risks of international operations, including:

•: increased governmental ownership and regulation of the economy in the markets where we operate;
•: inflation and adverse economic conditions stemming from governmental attempts to reduce inflation, such as imposition of higher interest rates and wage and price controls;
•: increased trade barriers, such as higher tariffs and taxes on imports of commodity products;
•: exchange controls or other currency restrictions;
•: war, civil unrest or significant political instability;
•: expropriation, confiscatory taxation and nationalization of our assets located in the markets where we operate;
•: governmental policies limiting investments by and returns to foreign investors;
•: labor unrest and strikes; and
•: restrictive governmental regulation and bureaucratic delays.

The occurrence of one or more of these risks may:

•: negatively impact our results of operations;
•: restrict the movement of funds;
•: inhibit our ability to collect receivables; and
•: lead to U.S. government or international sanctions.

We have experienced significant turnover of senior management. Our current management team has been, and will continue to be, required to devote a significant amount of time to financial reporting matters, which could impede their ability to implement our business objectives.

Since January 2004, there have been significant changes in our senior management team. Our previous chairman and chief executive officer, chief financial officer, chief operating officer and general counsel are no longer with Key. Richard J. Alario was appointed President and Chief Operating Officer in January 2004 and subsequently appointed Chief Executive Officer in May 2004 and Chairman in August 2004. In November 2004, Kim B. Clarke was named Vice President and Chief People Officer. In January 2005, we named William M. Austin as our Chief Financial Officer and Newton W. Wilson, III as our Senior Vice President and General Counsel. In August 2005, we named J. Marshall Dodson as our Vice President and Chief Accounting Officer. Our future performance depends, in part, on the ability of our management team to effectively work together, manage our workforce and successfully develop and implement business strategies. If our new management team is unable to do so, our ability to grow our business and successfully meet operational challenges could be impaired.

In addition, our senior management team has devoted a significant amount of time to the restatement process, including restating our financial statements, reviewing and improving our internal controls and procedures, developing effective corporate governance procedures and responding to government inquiries and litigation. If senior management continues to have to devote a significant amount of time to financial reporting matters, that will reduce the time they can dedicate to developing and attaining our strategic business initiatives and running ongoing business operations, or should there be turnover in our current management team, there could be a material adverse effect on our results of operations, financial condition and business.

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 over 50%. 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. While we hired a new Chief People Officer in November 2004 and subsequently hired additional human resource professionals to address these issues, 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.

We are subject to environmental, health and safety laws and regulations that expose us to potential liability.

Our operations are regulated under a number of federal, state, local and foreign laws that govern, among other things, the handling, storage and disposal of waste materials, some of which are classified

as hazardous substances, and the discharge of hazardous materials into the environment. In addition to potential liability if we should fail to comply, environmental regulations may expose us to liability for noncompliance of other parties, without regard to whether we were negligent. Sanctions for noncompliance with applicable environmental laws and regulations may include administrative, civil and criminal penalties, revocation of permits and corrective action orders. Furthermore, we may be liable for costs for environmental clean-up at currently or previously owned or operated properties or off-site locations where we sent, disposed of, or arranged for disposal of hazardous materials.

Our expenditures for environmental compliance have not been significant in the past but may increase in the future. Compliance with existing laws or regulations, adoption of new laws or regulations or more vigorous enforcement of environmental laws or regulations could have a material adverse effect on our operations by increasing our expenses and limiting our future business opportunities.

In addition, we conduct electric wireline logging, which entails the use of various down-hole sondes that acquire geologic data from the surrounding well bore. The data is set up down-hole using armored, insulated cable which has from one to seven electrical conductors inside. We use radioactive isotopes along with other nuclear, electrical, acoustic, and mechanical devices to evaluate down-hole formations, such as Americium Beryllium 241, Cesium 137, Iodine 131, and other isotopes. Our activities involving the use of isotopes are regulated by the U.S. Nuclear Regulatory Commission and specified agencies of applicable agreement states that work cooperatively in implementing the federal regulations. Additionally, we use high explosive charges for perforating casing and formations, and various explosive cutters to assist in well bore cleanout. Such operations are regulated by the U.S. Department of Justice, Bureau of Alcohol, Tobacco, Firearms, and Explosives. Standards implemented by these regulatory agencies require us to obtain licenses or other approvals for the use of such densitometers are well as explosive charges.

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

We had $557.0 million of total indebtedness and capital lease obligations outstanding at December 31, 2003. As of August 31, 2006, we had $427.0 million of total indebtedness and capital lease obligations outstanding.

Our ability to make payments on and to refinance 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 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 that 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 under our senior secured credit facility 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 not able to refinance our indebtedness. We may not be able to continue to implement the parts of our business strategy relating to strengthening our balance sheet by reducing debt, making acquisitions and remanufacturing our rigs and related equipment.

Additional indebtedness could materially adversely affect our financial condition, results of operations and business prospects and prevent us from fulfilling our obligations under our outstanding indebtedness.

Under our new senior secured credit facility, we are limited in our ability to incur additional debt at least until we have filed our 2006 Annual Report on Form 10-K. If and when such restrictions are lifted and we can incur additional debt, increased leverage could, for example:

•: make it more difficult for us to satisfy our obligations under our indebtedness; if we fail to comply with the requirements of our indebtedness, that failure could result in an event of default of such indebtedness;
•: require us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other business activities;
•: limit our ability to obtain additional financing in the future for working capital, capital expenditures and other general corporate purposes;
•: limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
•: diminish our ability to successfully withstand a downturn in our business or the economy generally; and
•: place us at a competitive disadvantage against less leveraged competitors.

If new debt is added to our and our subsidiaries' current debt levels, the related risks that we and they now face could increase.

Our debt instruments impose restrictions on us that may affect our ability to successfully operate our business.

Our senior secured credit facility limits our ability to take various actions, such as:

•: incurring additional indebtedness;
•: paying dividends;
•: repurchasing junior indebtedness;
•: making investments;
•: entering into transactions with affiliates;
•: merging or consolidating with other entities; and
•: selling all or substantially all of our assets.

These restrictions also could limit our ability to obtain additional financing, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct our business.

We may be unable to comply with covenants contained in our senior secured credit facility, which could result in the impairment of our working capital and alter our ability to operate our business.

We are a party to a $547.25 million senior secured credit facility. To maintain the right to borrow under this credit facility and avoid a default, we are required to maintain certain financial covenant ratios and satisfy certain financial condition tests, several of which become more restrictive over time and may 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. We are also required to provide to our lenders audited financial statements no later than March 2007. A breach of any of these covenants, ratios or tests could result in a default under our credit agreement. If we default, our lender will no longer be obligated to extend credit to us and could elect to declare all amounts outstanding under the credit agreement, 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 and financial condition.

Our business may be adversely affected if we cannot successfully execute acquisitions or effectively integrate acquired operations.

Our strategy has historically included acquiring complementary businesses, and we believe that additional niche acquisitions are likely. In addition, we will also evaluate international acquisitions. Any such strategy will involve a number of risks and challenges, including:

•: our ability to integrate acquired operations;
•: potential loss of key employees and customers of the acquired companies; and
•: an increase in our expenses and working capital requirements.

Any of these factors could adversely affect our ability to achieve anticipated levels of earnings and cash flow from acquisitions or realize other anticipated benefits. Furthermore, competition from other potential buyers could reduce our acquisition opportunities or cause us to pay a higher price than we otherwise might pay.

The trading price of our common stock could be subject to significant fluctuations.

The trading price of our common stock has been volatile. The uncertainty associated with the restatement of our financial statements, our ability to file a 2006 Annual Report, government investigations and our ability to relist our common stock on the NYSE may cause significant declines in our stock price, and continued uncertainty or negative developments may cause the price of our common stock to decline further. Also, factors such as announcements of fluctuations in our or our competitors' operating results and market conditions for oil and gas-related stocks in general could have a significant impact on the future trading prices of our common stock. In particular, the trading price of the common stock of many oilfield service companies has experienced extreme price and volume fluctuations, which have at times been unrelated to the operating performance of the companies whose stocks were affected. In addition, the trading prices and value of our common stock could be subject to significant fluctuations in response to variations in our prospects and operating results, which may in turn be affected by weakness in commodity prices, changes in interest rates and other factors. There can be no assurance that these factors will not have an adverse effect on the trading prices of our common stock.

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:

•: establish a classified Board of Directors, generally providing for three-year staggered terms of office for all members of our Board;
•: set limitations on the removal of directors;
•: provide our Board of Directors the ability to set the number of directors and to fill vacancies on the Board occurring between stockholder meetings; and

•: set limitations on who may call a special meeting of stockholders.

These provisions may have the effect of entrenching management and may deprive investors of the opportunity to sell their shares to potential acquirers at a premium over prevailing prices. This potential inability to obtain a control premium could reduce the price of our common stock.

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:

•: limit our ability to improve our market position;
•: increase our operating costs; and
•: limit our ability to recoup the investments made in technology initiatives.

Further, the inability to successfully demonstrate the benefits of our technology could negatively impact our stock price as investors might lose confidence in our ability to execute on our business strategy.

We may be unable to implement pricing increases on our core services.

A component of our business strategy includes charging higher prices on our core services in order to generate higher returns. During periods of strong industry activity when demand for our services increases, we have been able to increase our prices. These increases have been initiated to offset our rising cost structure and to enhance our margins. We believe that we have been able to increase our prices due to strong industry conditions, our capabilities and our leading market position. In the event market conditions deteriorate, it may become more difficult for us to increase prices, and if demand for our services declines dramatically, some customers may seek pricing concessions. Additionally, in some cases, we have not been able to successfully increase prices without adversely affecting demand for our services. Specifically, some customers have elected to use our competition rather than to pay our higher price.

The inability to secure further price increases could:

•: limit our ability to offset rising costs; and
•: impact our ability to generate higher free cash flow which would be used to expand our business.

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

We rely heavily on two 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 from either of these vendors, our ability to provide pressure pumping services could be limited.

PROPERTIES.

We conduct our operations using a combination of owned and leased properties. Our leased properties are subject to various lease terms and expirations. We currently own or operate 202 offices and yards in 15 states. We owned or operated 54 active salt water disposal wells at August 31, 2006, and 80 active salt water disposal wells at December 31, 2003. 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 2006. However, we continue to evaluate the purchase or lease of additional properties, as our business requires.

LEGAL PROCEEDINGS AND OTHER ACTIONS.

Class Action Lawsuits

Cause No. MO-04-CV-082;Peter Kaltman, on behalf of himself and all others similarly situated v. Key Energy Services, Inc., Francis D. John, Royce W. Mitchell, Richard J. Alario and James J. Byerlotzer, filed in the United States District Court for the Western District of Texas

Cause No. MO-04-CV-083;Malcolm Lord, Individually and on Behalf of all Others Similarly Situated vs. Key Energy Services, Inc., Francis D. John, Richard J. Alario, James J. Byerlotzer, and Royce W. Mitchell, filed in the United States District Court Western District of Texas

Cause No. MO-04-CV-090;Celeste Navon, on behalf of herself and all others similarly situated v. Key Energy Services, Inc., Francis John, Royce Mitchell, James Byerlotzer and Richard Alario, filed in the United States District Court for the Western District of Texas

Cause No. MO-04-CV-104;David W. Ortbals, on Behalf of Himself and All Others Similarly Situated v. Key Energy Services, Inc., Richard J. Alario, James J. Byerlotzer, Francis D. John, and Royce Mitchell, filed in the United States District Court for the Western District of Texas

Cause No. EP-04-CA-0254;Paul E. Steward, on Behalf of Himself and All Others Similarly Situated vs. Key Energy Services, Inc., Francis D. John and Royce W. Mitchell, filed in the United States District Court Western District of Texas

Cause No. EP-04-CA-0227;Garco Investments LLP Individually and on Behalf of all Others Similarly Situated vs. Key Energy Services, Inc., Richard J. Alario, James J. Byerlotzer, Francis D. John and Royce Mitchell, filed in the United States District Court for the Western District of Texas

These six actions have been consolidated into one action. On November 1, 2005, the plaintiffs filed a consolidated amended class action complaint. The complaint is brought on behalf of a putative class of purchasers of our securities between April 29, 2003 and June 4, 2004. The complaint names Key, Francis D. John, Royce W. Mitchell, Richard J. Alario and James J. Byerlotzer as defendants. The complaint generally alleges 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. We have filed a motion to dismiss the case. The individual defendants also filed motions to dismiss the case. On August 11, 2006, the court denied our motion to dismiss, but granted dismissals as to Messrs. Alario and Byerlotzer. We filed our answer to the consolidated amended complaint on September 11, 2006. The case is set for trial on April 2, 2007.

Derivative Actions

Three shareholder derivative actions have been filed by certain of our shareholders. They are as follows:

Cause No. 2004-CV-44728;Moonlight Investments, LTD. on Behalf of Nominal Defendant Key Energy Services, Inc., vs. Francis D. John, Richard J. Alario, James J. Byerlotzer, Royce W. Mitchell, Kevin P. Collins, W. Phillip Marcum, and Ralph S. Michael, III, v. Key Energy Services, Inc., filed in the 385^th Judicial District Court, Midland County, Texas

Cause No. EP-04-CA-0457;Sandra Weissman, Derivatively on Behalf of Key Energy Services, Inc., vs. 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, Richard J. Alario and Key Energy Services, Inc., a Maryland Corporation, filed in the United States District Court Western District of Texas

Cause No. EP-04-CA-0456;Daniel Bloom, Derivatively on Behalf of Key Energy Services, Inc., vs. 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, Richard J. Alario and Key Energy Services, Inc., a Maryland Corporation, filed in the United States District Court Western District of Texas

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 have been named as defendants in one or more of those actions. Those actions are 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. The first derivative suit was filed on August 9, 2004 in state court in Midland. The plaintiff amended that suit to assert claims against our independent public accountants, KPMG LLP. We filed a motion to dismiss all claims in that action, which was granted by the court on March 29, 2005 for failure to make demand on the directors before filing suit. The plaintiff appealed that ruling. On May 18, 2006, the intermediate Court of Appeals issued an opinion affirming the trial court's ruling that the plaintiff had not pleaded sufficient facts to excuse its failure to make demand, but reversing on procedural grounds. We filed a motion for rehearing, which was denied June 15, 2006, and we have commenced an appeal to the Texas Supreme Court. The two other derivative suits were filed in federal court in El Paso, Texas on December 10, 2004. Those actions were transferred to federal court in Midland, Texas and consolidated by agreement of the parties. We filed a motion to dismiss or to stay that consolidated action. The individual defendants also filed a motion to dismiss. On July 10, 2006, the court entered an order dismissing those two derivative actions for failure to make a demand. The remaining derivative case is still on appeal.

In each of the matters described above, plaintiffs are seeking an unspecified amount of monetary damages. At this time, we cannot ascertain the ultimate aggregate amount of monetary liability or financial impact of the class actions and derivative lawsuits. While we have directors and officers insurance in the aggregate amount of $50 million, we cannot determine whether these actions, suits, claims, and proceedings will, individually or collectively, have a material adverse effect on our business, results of operations, and financial condition. We and any named director and officer intend to vigorously defend these actions, suits, claims and proceedings.

Government Investigations

On March 29, 2004, we were notified by the Fort Worth office of the SEC that it had commenced an inquiry regarding the Company. The SEC issued a formal order of investigation on July 15, 2004.

The investigation includes, without limitation, inquiry into our accounting practices and the events that led to the restatement of our financial statements. The investigation also includes inquiry into matters raised by our former chief financial officer and former general counsel.

In addition, on January 5, 2005, we were served with a subpoena issued by a grand jury in Midland, Texas, that asked for the production of documents in connection with an investigation being conducted by the U.S. Attorney's Office for the Western District of Texas. We do not currently believe that we are a target of this investigation.

We are continuing our efforts to cooperate fully with the SEC and the U.S. Attorney's Office in their respective investigations. We cannot predict the outcome of those investigations.

Litigation with Former Officers and Employees

On April 7, 2006, we delivered a notice to our former chief executive officer, Francis D. John, of our intention to treat his termination of employment effective May 1, 2004, as "for cause" under his employment agreement with us. In response to the notice, Mr. John filed a lawsuit against us in the U.S. District Court for the Southern District of Texas, Houston Division on May 19, 2006, in which he alleges, among other things, that we breached stock option agreements and his employment agreement. On June 13, 2006, we filed an answer and counterclaim, as well as a motion to dismiss parts of his claims, in response to Mr. John's lawsuit. In addition to denying Mr. John's claims, we asserted claims against Mr. John for breach of contract and declaratory judgment including, among other things, a declaration that "cause" exists under Mr. John's employment agreement. We previously recorded a $16.4 million severance expense in connection with Mr. John's termination of employment, of which $9.0 million represented a non-cash charge for the write-off of the unamortized balance of Mr. John's prepaid retention bonus, and the balance consisted of a reserve for severance and other termination costs. We have not paid any severance or termination costs to Mr. John, other than his base salary for the 90-day period after the date of his termination. Mr. John would not be entitled to severance under a "for cause" termination. In addition, the Company may be able to recover the unamortized balance of his prepaid retention bonus and stock options. On August 8, 2006, the court denied our motion to dismiss certain of Mr. John's claims, and denied in part and granted in part Mr. John's motion to dismiss certain of our claims. Discovery is underway.

We have also been 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.

Additionally, on August 21, 2006, our former chief financial officer, Royce W. Mitchell, filed a suit against the Company in 385^th District Court, Midland County, Texas alleging breach of contract with regard to alleged bonuses, benefits and expense reimbursements, conditional stock grants and stock options, to which he believes himself entitled; as well as relief under theories of quantum meruit, promissory estoppel, and specific performance. Further, our former controller and assistant controller filed a joint complaint against the Company on September 3, 2006 in 133^rd District Court, Harris County, Texas alleging constructive termination and breach of contract.

We intend to vigorously defend against these claims; however, we cannot predict the outcome of the lawsuits.

Other Matters

A class action lawsuit,Gonzalez v. Key Energy Services, Inc., was filed in Ventura County, California, Superior Court in September 2005 alleging that Key did not pay its hourly employees for travel time between the yard and wellhead and that certain employees were denied meal and rest periods during shifts. Our preliminary investigations into these allegations are ongoing and a class has not been certified. We intend to vigorously defend against this action; however, we cannot predict the outcome of the lawsuit.

In addition, we are involved in various suits and claims that have arisen in the ordinary course of business. We do not believe that the disposition of any of these items will result in a material adverse impact to the consolidated financial position, results of operations or cash flows of Key.

MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

Key's common stock was traded on the New York Stock Exchange, under the symbol "KEG," until April 7, 2005, when the NYSE suspended the trading of our common stock based on our failure to timely file our SEC reports. The common stock was delisted on May 5, 2005. Beginning April 8, 2005, our stock has been quoted on the Pink Sheets Electronic Quotation Service under the symbol "KEGS." As of December 31, 2003, there were 645 registered holders of 130,561,308 issued and outstanding shares of common stock, net of 416,666 shares of common stock held in treasury. As of December 31, 2004, there were 614 registered holders of 130,791,338 issued and outstanding shares of common stock, net of 416,666 shares of common stock held in treasury. As of December 31, 2005, there were 626 registered holders of 131,334,196 issued and outstanding shares of common stock, net of 416,666 shares of common stock held in treasury. As of August 31, 2006, there were 628 registered holders of 131,299,038 issued and outstanding shares of common stock, net of 497,501 shares of common stock held in treasury.

There were no dividends paid on Key's common stock during the year ended December 31, 2003, the six months ended December 31, 2002 and the years ended June 30, 2002 and 2001. Key must meet certain financial covenants before it may pay dividends under the terms of its current credit facility.

SALES OF UNREGISTERED EQUITY SECURITIES

We did not make any unregistered sales of our securities during the year ended December 31, 2003.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION.

Introduction and Overview

We are filing this Report more than two years after the Annual Report on Form 10-K for the year ended December 31, 2003 was due. As more fully described elsewhere, since March 2004, we have engaged in a comprehensive review of our fixed assets as well as a comprehensive re-examination of our financial statements, accounting processes and internal controls. Our 2003 Balance Sheet presents our financial condition as of December 31, 2003 in accordance with GAAP. We are not presenting the other consolidated financial statements in accordance with GAAP. We were unable to determine with sufficient certainty the appropriate period(s) in 2003 or before in which to record certain write-offs and write-downs that were identified in our restatement process (described below). The Company's independent public accountants, KPMG LLP, have expressed an unqualified opinion that the 2003 Balance Sheet fairly presents our financial condition on December 31, 2003, in accordance with GAAP. They have also audited the other financial statements presented in this Report. They have opined that, due to the two issues discussed below, the financial statements other than the 2003 Balance Sheet do not fairly present the Company's financial condition or results of operations or cash flows for the periods covered in accordance with GAAP. Readers should carefully review the independent auditors' report, which is included in the section entitled "Consolidated Financial Statements and Supplementary Data."

The 2003 Balance Sheet will provide an opening balance sheet for fiscal years beginning after December 31, 2003. Therefore, we believe that we will be able to provide financial statements conforming to GAAP for subsequent fiscal periods. We do not intend to file Annual Reports on Form 10-K for fiscal years ended December 31, 2004 or 2005, respectively. In both cases, we will be unable to satisfy the SEC's requirement that we provide three years of audited financial statements, because we will not be able to provide statements of income and cash flows presented in accordance with GAAP for the year ended December 31, 2003. We do believe that we will be able to provide financial statements conforming to GAAP and SEC rules for the three years ended December 31, 2006, and therefore expect to file an Annual Report on Form 10-K for that year. SEC regulations also require that our 2006 Annual Report on Form 10-K include unaudited selected financial data presented in accordance with GAAP for the years ended December 31, 2003 and 2002, respectively. We will request a waiver from the SEC with respect to this requirement. We can make no assurance that such a waiver will be granted. We propose to file Quarterly Reports on Form 10-Q for 2005 and 2006. The 2005 10-Qs will also include 2004 quarterly information. We are unable to predict at this time when any of the foregoing filings will be made.

This report covers the year ended December 31, 2003 and prior periods. As a result, this management's discussion and analysis addresses Key's liquidity, financial condition and results of operations as of and for the year ended December 31, 2003. Notwithstanding the limitations on the financial statements, we have included management's discussion and analysis to provide investors as complete a picture as possible about our historical financial condition and results as well as to allow investors to see the nature of the restatement items, and how they have been reflected in the company's historical records. We also include discussions of subsequent developments as we believe appropriate, including our current liquidity and financial condition, our current strategy and key performance measures, risks and uncertainties we currently face, divestitures and similar matters. We also describe the circumstances leading up to the restatement and the matters affected by the restatement.

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

Our consolidated financial statements other than the 2003 Balance Sheet are not presented in accordance with GAAP because we were unable with sufficient certainty to determine the appropriate period(s) in 2003 or before in which to record certain write-offs and write-downs that were identified in the Company's restatement process. This problem arose in two areas: First, the Company had to write off fixed assets of $40.5 million that were carried on its books at December 31, 2003 but which, based on a complete physical inventory of the Company's assets, were found not to be in its possession as of December 31, 2003. The Company was unable, notwithstanding comprehensive efforts described in detail in this Report, to identify records or evidence that showed the actual period(s) in which the assets left its possession. Second, the Company's physical inventory identified numerous fixed assets the condition of which had changed prior to December 31, 2003, thereby necessitating adjustments to their carrying value. We were able to determine or estimate when the change in condition occurred for a significant majority of these assets and therefore the appropriate period(s) for recording the adjustments. With respect to $10.2 million of these adjustments, the Company was unable, notwithstanding its efforts, to identify evidence to determine when the change in condition occurred. In both cases, in light of the lack of evidence to support the specific period in which the relevant charges should be recorded, the Company determined to record the charges in the fourth quarter of 2003.

APB 20 requires that the correction of an error be made through a restatement of the financial statements for the period in which the error occurred. There is no clear accounting guidance for the situation like ours, where a company lacks sufficient records to determine, or support a determination of, the period in which an error occurred. Because we are unable to identify and appropriately evidence the period(s) in which the errors related to the write-offs and write-downs for unlocated assets and some changes in condition of assets may have occurred, we cannot conclude that recording the charges in the fourth quarter of 2003 is consistent with APB 20. Therefore, the consolidated statements of operations, comprehensive income, cash flows and stockholders' equity for 2003 are not presented in accordance with GAAP. For the same reasons, the inability of the Company to identify the appropriate prior period(s) for these charges means that the financial statements for periods prior to December 31, 2003 also are not presented in accordance with GAAP.

The presentation of these charges for unlocated assets and changes in condition also affects other items in the relevant financial statements and related disclosures. Investors should recognize that accounting for one or more material items in a financial statement in a manner other than in accordance with GAAP means that the entire financial statement is deemed not to be presented in accordance with GAAP.

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

We have not amended and do not intend to amend our previously-filed Annual Reports on Form 10-K or our Quarterly Reports on Form 10-Q for the periods affected by the restatement that ended prior to and including September 30, 2003. Consequently, you should not rely on historical information contained in those prior filings.

Summary—Financial Impact of Restatement Matters

The following table sets forth the increase (decrease) in net income (loss), accumulated other comprehensive income and additional paid-in capital, due to the restatement for each period shown (in thousands). As discussed above, these amounts are not presented in accordance with GAAP.

		Fixed Asset Restatement Matters			Other Restatement Matters			Income Taxes		Total Effect on Net Income			Accumulated Other Comprehensive Income(2)			Additional Paid-In Capital(3)		Total
Prior years(1)			(110,116	)		(22,219	)		24,601		(107,734	)	$	76		$	7,132	$	(100,526	)
June 30, 2001			(9,002	)		(10,747	)		1,599		(18,150	)		(158	)		2,440		(15,868	)
June 30, 2002			(41,744	)		(10,591	)		18,310		(34,025	)		4,868			4,546		(24,611	)
December 31, 2002			(7,720	)		(1,924	)		1,902		(7,742	)		(3,234	)		2,556		(8,420	)

	Total	$	(168,582	)	$	(45,481	)	$	46,412	$	(167,651	)	$	1,552		$	16,674	$	(149,425	)

(1): The adjustments for prior years represent cumulative adjustments to retained earnings to reflect restatements for prior periods to July 1, 2000.
(2): The adjustments for Accumulated Other Comprehensive Income relate to foreign exchange-related restatement effects.
(3): The adjustments for Additional Paid-In Capital relate to restatement effects for stock options.

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

As set forth on the following table, our reported results for our fiscal year ended December 31, 2003, which, as discussed elsewhere, are not presented in accordance with GAAP, include certain charges that were recorded in 2003 (in thousands).

		Decrease (Increase)
South Texas Matters		$	(5,225	)
Physical inventory write-down			(40,543	)
Write-down due to condition/intended use(1)			(22,950	)
Impairment of long-lived assets			7,364
Improperly capitalized costs			(3,342	)
Change in depreciable lives			(7,712	)
Other fixed assets related matters			(2,716	)
Aggregate depreciation and amortization adjustments			8,183
Accrual for environmental remediation costs and related expenses			(3,052	)
Worker's compensation			1,259
Accrual for vacation pay			1,355
Accrued taxes, other than income taxes			(8,451	)
Derivatives			5,507
Egypt			(2,798	)
Vehicle general liability insurance			(8,944	)
Other			(5,462	)

	Total (decrease) due to accounting matters	$	(87,527	)
	Income tax adjustments	$	30,786

	Total (decrease) increase in net income (loss)	$	(56,741	)

(1): Included in this charge is $10.2 million of write-downs for changes in condition or intended use that could not be evidenced to a particular period.

Background of the Restatement

On March 15, 2004, we announced that we had filed a notice with the SEC to extend the period in which we could file our Annual Report on Form 10-K for the year ended December 31, 2003. Subsequently, on March 29, 2004, we announced that we would not file our 2003 Annual Report on Form 10-K by the March 30, 2004 extended deadline. In connection with this announcement, we indicated that our review and analysis of certain of our idle equipment was continuing. In addition, our Audit Committee authorized a review of the South Texas Matters, and an independent investigation into aspects of our disclosure controls and procedures and our internal controls structure and processes (the "Audit Committee Investigation"). We also stated that we expected that write-downs would be

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

recorded in 2003 and prior periods and, therefore, we would be restating our prior period financial statements.

In light of the South Texas Matters, which raised issues with respect to our controls relating to fixed assets, we conducted a review and determined that we were also unable to generate a balance sheet for each of our yards in order to identify our fixed assets on a yard-by-yard basis. Further, in March 2004, while we were attempting to complete our 2003 consolidated financial statements, a review of reports generated by our centralized maintenance management system ("CMMS") raised questions about whether certain fixed assets (primarily rigs and heavy duty trucks) were being accounted for appropriately. CMMS is an operational system installed in 2001 for tracking asset locations and condition. CMMS was upgraded in 2003 for purchasing and preventative maintenance tracking. It was and is a separate system from the fixed asset sub-ledger supporting our consolidated financial statements. Prior to the implementation of CMMS, a multitude of systems and manual processes were used. The CMMS reports reviewed in March 2004 identified certain fixed assets which were no longer in operating condition, had been retired or had been sold. This necessitated an analysis of these specific assets to determine whether the net carrying value of the assets was appropriate at December 31, 2003 or earlier and whether the depreciable life of the assets had been adjusted to reflect their physical condition, reduction in usefulness or whether these assets could even be located. Ultimately, we determined that certain data contained in CMMS was not only incorrect, but did not agree with data contained in our fixed asset ledger, which we determined also contained errors. In addition, where the data in CMMS was determined to be accurate, we determined that the information it contained had previously not been utilized in the accounting process.

We decided that a comprehensive review of our fixed assets was necessary to determine the equipment's existence, condition or intended use, value, and remaining depreciable life, as well as other related property asset accounting matters. Accordingly, during the remainder of 2004 and into 2005, we engaged in an intensive review of fixed assets. The process involved, among other things:

•: Dispatch of count teams using CMMS asset listings to our domestic and international locations to physically inventory individual pieces of equipment owned by our well servicing, drilling and pressure pumping divisions to determine the equipment's existence, condition, and intended use;
•: cataloging in CMMS of the results of the on-site inspection of assets;
•: a physical inventory, on-site inspection or appraisal of the items comprising our fishing and rental equipment;
•: matching of the physically-inventoried fixed assets to the fixed asset ledger via reference to equipment identification numbers, vendor invoices, acquisition-related documentation and other relevant documentation; and
•: valuation of equipment determined to be salvaged, scrapped or intended for use in our equipment remanufacture program.

While the restatement originated with the identification of issues regarding our fixed asset accounting ("Fixed Asset Restatement Matters"), in the course of the restatement process, we identified numerous accounting errors for which restatements and adjustments were required ("Other Restatement Matters"). The Fixed Asset Restatement Matters and Other Restatement Matters are described below. In addition, during the restatement process, we also identified other instances of accounting errors that affected our 2003 financial statements. These items are included in our results for the fiscal year ended December 31, 2003.

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

We believe that the problems that led to the restatement are in large measure attributable to the effects of Key's decentralized management practices and growth through multiple acquisitions, which were not effectively managed. Domestically, Key services its customers from over 200 locations and has international operations in Argentina, until July 2005, Egypt and, until April 2004, Canada (Ontario). Since 1994, we have made over 100 acquisitions. These acquisitions ranged in size from small "mom and pop" operations consisting of a small number of well servicing rigs or heavy duty trucks and related ancillary equipment to mid-size corporations that owned several hundred well servicing rigs and heavy duty trucks and related ancillary equipment. Excluding the acquisition of Q Services, Inc. ("QSI"), which occurred in 2002, the most significant of these acquisitions occurred between 1995 and 1999. These acquired businesses had different operating cultures, separate accounting systems (until January 2000), and varying management philosophies. We believe that a number of factors contributed, over time, to a deterioration of our fixed asset accounting records and related data and financial records and disclosures. We believe that the principal factors were rapid growth; untimely integration or failed integration of acquisitions; incomplete supporting documentation and poor internal due diligence with respect to acquisitions; and inadequate accounting resources. The result was a failure to establish and consolidate effective internal controls over our decentralized businesses.

Current management's and the Board of Directors' experience with the restatement process, and the accounting, documentation and control weaknesses it revealed, leads us to conclude that at many operational levels of the Company there was a lack of accountability and managerial discipline. We believe that former senior management did not create an effective control environment for the organization, did not employ a sufficient number of qualified accounting personnel in key accounting and reporting functions, and did not maintain adequate channels of communication to report operational and accounting issues and implement consistent solutions for such issues. We also believe that the physical separation of our executive office, which until 2004 was located in the Northeast, from our operational headquarters in Midland, Texas, also contributed to the lack of accountability, discipline and consistency in the recording of financial information. We further believe that these problems were exacerbated by turnover among senior management, including chief financial officers and controllers.

The fixed asset review process identified substantial deficiencies in the record-keeping and accounting for our fixed assets and resulted in write-offs and restatements of prior period results as described below. The process took substantially longer than anticipated due to the poor condition of the Company's records, including records of when assets first came into service and when assets either stopped working, were sold or were scrapped. The actual counting and categorization of assets was also complicated because assets were located at dispersed locations throughout the United States, Egypt and Argentina. Poor communication between our corporate accounting department and our operations support team, as well as poor execution of the physical asset counts by our operations support team, also contributed to the delay.

We encountered additional difficulties in locating supporting documentation for prior accounting entries, many of which affect periods prior to 2000 but which flow through into subsequent periods. Reconciling or documenting certain accounting matters revealed other accounting matters for which additional work was required. The scope of this problem became increasingly apparent as we sought to verify and support many of the accounting adjustments required by the restatement. In certain instances, either no records or supporting documentation for accounting entries existed at all, or the documentation that did exist was inadequate. As a result, the resolution of each of the accounting issues affected the timing of the restatement, and in certain instances the resolution of particular issues took considerably longer than anticipated by management. Other factors that we believe contributed to

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

the delay were the absence of a disciplined "close" process, inadequate staffing and a lack of GAAP and financial reporting expertise among many of our former corporate accountants.

Beginning in July 2006, we conducted an additional review of the timing of stock option grants and the associated documentation for such grants. In addition to other accounting errors relating to stock options that had previously been identified during the restatement process, we concluded that there were also material errors with respect to stock option grants that were evidenced by written consents of directors.

Description of Restatement Items

This section describes the accounting issues that are encompassed within the categories of "Fixed Asset Restatement Matters" and "Other Restatement Matters," respectively.

Fixed Asset Restatement Matters

The fixed asset adjustments identified by the restatement process are categorized as follows:

•: Write-down due to condition or intended use—changes in our cost, depreciation expense, and accumulated depreciation for fixed assets based on the condition or intended use (e.g., scrap or salvage) of the asset, as determined in the physical inventory;
•: Impairment of long-lived assets—changes resulting from reviews of testing for impairment of long-lived assets;
•: Improperly capitalized costs—capitalized fixed asset costs that should have been expensed;
•: Change in depreciable lives—adjustments resulting from various issues relating to the appropriate depreciable life for fixed assets;
•: Other fixed assets related matters—reconciliation of fixed asset subledger and general ledger, and aggregate effect on depreciation, depletion and amortization as a result of the Fixed Asset Restatement Matters.

Other Restatement Matters

We made the following adjustments with respect to Other Restatement Matters:

•: Cost deferrals and capitalization of certain operating expenses—costs related to certain transactions that were capitalized but should have been expensed;
•: Accrual for environmental remediation costs and related expenses—overstatement of environmental liabilities recognized in connection with the QSI acquisition;
•: Adjustment to investment in gas trusts—correction of prior accounting for investment in certain gas trusts;
•: Accrual for abandonment of disposal wells—correction of incorrect accounting under Statement of Financial Accounting Standards No. 143 for abandonment liabilities and errors in calculations;
•: Workers' compensation—several issues related to workers' compensation accrual methodology and calculations;
•: Settlement of claim with workers' compensation insurance provider—probable and estimable liability that should have been recorded in 2001;

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

•: Accrual for vacation pay—correction of erroneous prior methodology for calculating and recording accrued vacation liabilities;
•: Accrued taxes, other than income taxes—changes resulting from incorrect computations of accrued taxes other than income taxes;
•: Stock option grants and modifications—charges related to options granted to a non-employee, charges resulting from application of incorrect measurement dates for option awards, and other charges related to grants outside of relevant option plans or in non-conformance with plans;
•: Derivatives—reassessment of a volumetric production payment transaction entered into March 2000;
•: Egypt—improper accounting for Egyptian operations, which included the use of computer spreadsheets to record certain accounting transactions instead of the accounting system, the improper capitalization of certain start-up activity costs, and the overpayment of corporate taxes, among others;
•: Amortization of debt issuance costs—recalculation of amortization method for deferred financing costs and correction of other errors in recording of deferred financing costs; and
•: Other—other matters identified in the restatement process that reduced operating results.

Income Tax Adjustments

We recomputed income tax expense and related deferred income tax accounts for the periods under restatement to reflect the effect of restatement matters described above. We also corrected certain errors in our previous accounting for income taxes that were identified in the course of the restatement.

See the section entitled "Consolidated Financial Statements and Supplementary Data," Note 2—"Restatement of Financial Statements" for additional information on these matters. Also see "Impact on Net Income (Loss) by Category of Adjustments" below, which presents the impact on net income (loss) resulting from the categories of restatement and other adjustments described above.

Financial Statement Effects in 2003

In the course of the restatement process, we identified accounting matters that had financial restatement effects in prior periods contained in this report and continued throughout fiscal year December 31, 2003. These included:

•: South Texas matters—write-off of goodwill and intangible assets previously recorded in connection with acquisition in our South Texas Division;
•: Physical inventory write-down—fixed assets recorded in our financial records that could not be physically located or identified in our physical counts;
•: Write-down due to condition or intended use—changes in our cost, depreciation expense, and accumulated depreciation for fixed assets based on the condition or intended use (e.g., scrap or salvage) of the asset, as determined in the physical inventory;
•: Impairment of long-lived assets—changes resulting from reviews of testing for impairment for long-lived assets;
•: Improperly capitalized costs—capitalized fixed asset costs that should have been expensed;
•: Change in depreciable lives—adjustments resulting from various issues relating to the appropriate depreciable life for fixed assets;

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

•: Other fixed assets related matters—reconciliation of fixed asset subledger and general ledger;
•: Aggregate depletion, depreciation and amortization adjustments—aggregate effect on depreciation, depletion and amortization as a result of the Fixed Asset Restatement Matters;
•: Accrued environmental liabilities—accrual for environmental remediation liabilities other than QSI liabilities;
•: Accrual for abandonment of disposal wells—correction of incorrect accounting under Statement of Financial Accounting Standards No. 143 for abandonment liabilities and errors in calculations;
•: Workers' compensation—several issues related to workers' compensation accrual methodology and calculations;
•: Accrual for vacation pay—correction of erroneous prior methodology for calculating and recording accrued vacation liabilities;
•: Accrued taxes, other than income taxes—changes resulting from changes in estimate for the calculation of accrued taxes other than income taxes;
•: Derivatives—reassessment of the volumetric production payment entered into March 2000;
•: Egypt—improper accounting for Egyptian operations, which included the use of computer spreadsheets to record certain accounting transactions instead of the accounting system, the improper capitalization of certain start-up activity costs, and the overpayment of corporate taxes, among others;
•: Vehicle general liability insurance—increase in accruals for self-insurance of vehicle liabilities; and
•: Other—liability for a separation agreement structured as a consulting and non-compete agreement, costs deferrals and capitalization of certain operating expenses, adjustments to an investment in gas trusts, stock option grants and modifications, debt issuance costs, accrual for abandonment of disposal wells and changes to contingent liabilities based on post-period events.

See the sections entitled "Consolidated Financial Statements and Supplementary Data," Note 3—"South Texas Matters," and Note 4—"Property and Equipment."

Audit Committee Investigation

The Audit Committee Investigation included a review, directed by the Audit Committee with the assistance of special counsel, of the prior investigation of the South Texas Matters and an independent investigation of aspects of our disclosure controls and procedures, our internal controls structure and processes, and other matters that arose in connection with the investigation. Among the matters considered in the investigation were the circumstances surrounding communications by our former chief executive officer, Francis D. John, with analysts following our March 15, 2004 press release, and allegations by our former chief financial officer, Royce W. Mitchell, and our former general counsel, Jack D. Loftis, Jr., about possible misconduct by Mr. John. Several of the concerns raised by Messrs. Mitchell and Loftis led to the review of accounting for debt issuance costs, a consulting arrangement and certain stock option grants.

The investigation by the Audit Committee and its special counsel were conducted over a span of 15 weeks and consisted of a review of thousands of pages of documents and interviews of more than 70 current and former officers and employees of Key. On August 25, 2004, we announced that the Audit Committee confirmed that our earlier investigation of the South Texas Matters was appropriate and also confirmed that no member of Key's executive management had participated in any of the South Texas improprieties. We also announced that we were taking several actions to enhance our internal controls and governance processes in light of the investigation carried out by the Audit Committee as

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

well as control issues identified during the restatement process. See the section entitled "Controls and Procedures," for a discussion of issues relating to our disclosure controls and procedures and internal control over financial reporting and our actions in this regard.

Impact on Net Income (Loss) by Category of Adjustments

The following table presents details by category of adjustments described above, which aggregate to the net change to previously reported income (loss) resulting from the restatement for the applicable periods. As discussed elsewhere herein, these amounts are not presented in accordance with GAAP.

		Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years(1)
		(in thousands)
Fixed Asset Restatement Matters:
	Write down due to condition/intended use		(76,726	)		(5,726	)		(17,584	)		(6,771	)		(46,645	)
	Impairment of long-lived assets		(19,879	)		—			(19,879	)		—			—
	Improperly capitalized costs		(51,972	)		(1,857	)		(5,713	)		(3,754	)		(40,648	)
	Change in depreciable lives		(45,444	)		(4,019	)		(8,453	)		(8,744	)		(24,228	)
	Other fixed assets related matters		25,439			3,882			9,885			10,267			1,405

Total Fixed Asset Restatement Matters			(168,582	)		(7,720	)		(41,744	)		(9,002	)		(110,116	)

Other Restatement Matters
	Cost deferrals and capitalization of certain operating expenses		(367	)		27			(124	)		(72	)		(198	)
	Accrual for environmental remediation costs and related expenses		(83	)		(83	)		—			—			—
	Adjustment to investment in gas trusts		(47	)		62			350			(117	)		(342	)
	Accrual for abandonment of disposal wells		1,763			1,763			—			—			—
	Workers' compensation		(14,841	)		2,856			(7,330	)		(4,523	)		(5,844	)
	Settlement of claim with workers' compensation insurance provider		(2,206	)		—			—			—			(2,206	)
	Accrual for vacation pay		(2,638	)		275			93			(3,006	)		—
	Accrued taxes, other than income taxes		(3,658	)		(2,653	)		(216	)		(192	)		(597	)
	Stock option grants and modifications		(16,112	)		(2,385	)		(3,642	)		(2,686	)		(7,399	)
	Derivatives		(6,032	)		(1,327	)		(639	)		794			(4,860	)
	Egypt		(881	)		(952	)		71			—			—
	Amortization of debt issuance costs		(487	)		596			622			(481	)		(1,224	)
	Other		108			(103	)		224			(464	)		451

Total Other Restatement Matters			(45,481	)		(1,924	)		(10,591	)		(10,747	)		(22,219	)

Total adjustment to costs and expenses			(214,063	)		(9,644	)		(52,335	)		(19,749	)		(132,335	)
Income tax adjustments			46,412			1,902			18,310			1,599			24,601

Change to previously reported net income or loss		$	(167,651	)	$	(7,742	)	$	(34,025	)	$	(18,150	)	$	(107,734	)

(1): The amount in prior years relates to net adjustments in the years through June 30, 2000 which have been reflected as an adjustment to retained earnings as of July 1, 2000.

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

Business Impact of the Restatement

While we believe our underlying business is sound, we have been negatively impacted by the restatement process. We believe some internal initiatives that we had intended to pursue during 2004 and 2005 were put on hold as the resources needed for such projects were assigned to the restatement process. For example, we had planned to significantly improve our procurement process during 2004. Historically, we have purchased many of our supplies and equipment on a local basis. We believe that by consolidating our vendors at a national or regional level, we can leverage our buying power and reduce our costs. Additionally, we believe centralized purchasing of major supplies and parts will enhance our internal controls. In 2006, we added a Vice President of Procurement, Director of Procurement Operations, Director of Procurement Systems, and Manager of Procurement Compliance to improve our processes. The restatement process and subsequent inventorying of all of our assets delayed us in completing value-added initiatives such as this because our operations support group, which then managed the procurement process, was also responsible for counting and valuing our property and equipment. Other initiatives which were impacted include our acquisition program, our business development opportunities, and our debt refinancing plan.

Because of the restrictions established under our waivers with the lenders under our former revolving credit facility since April 2004 and under our new senior secured credit facility (which are discussed below in connection with our liquidity and capital resources), we have been prohibited from making acquisitions. When the restatement process commenced, we were in the process of evaluating several acquisitions and had hoped to make several of those acquisitions during the 2004 fiscal year. Specifically, we sought to further expand both our fishing and rental services and pressure pumping operations. While we believe additional acquisition opportunities do exist, we are unable to capitalize on acquisition opportunities, thereby causing a delay in executing certain growth strategies. There is no assurance that these initiatives or acquisitions would have been successfully completed absent the restatement.

The restatement process has been and continues to be expensive. We estimate that during 2004 and 2005 we incurred additional expenses related to the restatement process in excess of $50.0 million. In addition, we estimate that we incurred fees and expenses of approximately $9.7 million through June 2006.

Business and Growth Strategies

Historically, our strategy has been to grow through the acquisition and consolidation of smaller, regional competitors. More recently, we have focused on improving results by evaluating our core business, reviewing possible niche acquisitions, reducing debt, expanding internationally, investing in technology, expanding our product line, remanufacturing rigs and related equipment, and training personnel to maintain a qualified and safety-conscious employee base.

Evaluation of Core Business and Sale of Non-Core Assets. During 2004 we conducted a detailed review of our operations with the purpose of identifying businesses that were either non-core to our production services platform or were underperforming relative to our other operations. In the course of this review, we determined that our domestic contract drilling assets located primarily in the Permian Basin and San Juan Basin, including two active rigs from our Rocky Mountain division, did not fit with our strategy. Further, these rigs had not performed well during the 2003 or 2004 period, a time in which many U.S. drilling contractors were experiencing strong improvement in operating results. We attribute our underperformance in this business to the markets in which we were located, the size and depth capabilities of our rigs and the poor quality of our drilling fleet. We determined that for us to be

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

successful in this business, we would need to devote significant capital resources to it. We did not, however, believe this was an appropriate allocation of resources as we were a small player in the fragmented contract drilling market and had other business units that we believed could provide better returns to our shareholders. We continue to provide drilling services through the use of 13 drilling rigs in three regions: the Powder River Basin of Wyoming, the Appalachian Basin of West Virginia and Argentina.

During 2004, we also commenced a review of our Eastern division. This division provides well servicing, fluid hauling services, contract drilling services and wireline services in the Appalachian Basin of West Virginia and Pennsylvania, as well as well servicing and fluid hauling services in the Michigan Basin. This division had performed poorly, generating pre-tax losses during the last few years. Additionally, few of our major customers were located in this region, and the business is highly seasonal due to weather impacts and restrictions during the winter months. Upon completion of the review, we elected to divest our Michigan operations and to retain and restructure our Appalachian Basin operations. The Michigan assets were sold in May 2005 for a price of $6.5 million. We elected to retain our Appalachian Basin operation and have changed its management. We believe that opportunities exist to improve this operation through the addition of new wireline and well service rig assets.

In addition, on August 28, 2003, we sold our oil and natural gas properties for $19.7 million in cash. We received net cash proceeds of $7.5 million after repaying our volumetric production payment, unwinding related hedge arrangements and paying other related costs. As a result of the sale, we treated our oil and natural gas production business as a discontinued operation for all periods and recorded an after-tax charge to discontinued operations of $4.8 million, or $0.04 per diluted share, during the year ended December 31, 2003.

Niche Acquisitions. We have historically grown through acquisitions. We believe that additional niche acquisitions in our fishing and rental services and pressure pumping operations are likely as we seek to expand those product lines. We will also evaluate international acquisitions so that we can obtain a platform in a particular international market and then use that platform to grow organically.

Debt Reduction. One of our primary objectives since the rollup of the well servicing industry in the late 1990's has been to pursue an aggressive debt reduction plan. As we began 2004, one of our goals was to continue the debt reduction initiative. The debt repayment effort was hampered during 2004 by the costs incurred with the restatement. However, as a result of improving cash flow and cash received from asset sales during 2005, at August 31, 2006, total indebtedness had declined $130.0 million from $557.0 million at December 31, 2003. As of August 31, 2006, total indebtedness totaled $427.0 million while our cash and short term investments totaled $143.4 million. While we will continue to reduce debt with cash flow from operations, we do not intend to forego growth opportunities, including acquisitions, if we believe those opportunities may provide a better return for shareholders. We will continue to evaluate opportunities to lower our cash interest costs through appropriate debt refinancing.

International Expansion. We are evaluating ways in which we can expand internationally. Our objective is to redeploy assets to international markets. In addition, we will consider strategic international acquisitions in order to establish a presence in a particular market, if necessary. We have evaluated a number of international markets, and our top two priorities are Canada and Mexico. Long term, we believe opportunities may exist in the Middle East, Russia and Latin America. We presently operate in Argentina. In Argentina, we expanded our operation during 2004 by redeploying five well

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

service rigs to that region, and we announced in 2005 that two additional rigs would be deployed to that market.

During 2004, we made progress in our international growth initiative through our relationship with IROC Systems Corp. ("IROC"), whereby we sold IROC ten remanufactured well service rigs in exchange for shares of IROC's common stock. IROC is an Alberta, Canada-based oilfield services company that has provided equipment and personnel in the area of downwind air quality monitoring and safety services to the energy sector since 1982. IROC also offers well service rigs and environmental remediation and abandonment services. IROC has developed key technologies to address remote air quality monitoring, has designed and deployed new air breathing systems and provides a full line of safety services for drilling, completion, production and plant shut down operations. We received 8.2 million shares of IROC shares at a deemed issuance price of $1.12 CDN per share. Our interest in IROC is accounted for as an equity investment. In June 2005, we expanded our relationship with IROC through the sale of rig components valued at approximately $917,000, in exchange for the 547,411 additional shares of IROC. The closing price of IROC shares on the Toronto Venture Stock Exchange on August 31, 2006 was $2.60 CDN per share. Further details of the transaction are provided under the section entitled "Consolidated Financial Statements and Supplementary Data," Note 22—"Subsequent Events."

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. At the end of 2003, a number of technology projects were underway, including the development of a work management system and the implementation of wireless communication and GPS technology for our fluid hauling operations. These initiatives are designed to enhance our ability to maximize equipment utilization, improve management reporting capabilities, and increase operating leverage.

In addition, we began deployment of our proprietary well service technology in 2003. The KeyView® system captures well-site operating data, thereby allowing customers and us to monitor and analyze information about well servicing, resulting in improved efficiency.

At December 31, 2003, we had 11 KeyView® units installed, and as of August 31, 2006, 205 units had been installed. The KeyView® system is expected to increase our and our customers' visibility into activities at the wellsite. Through this technology, we expect to (i) be able to ensure proper rod and tubing make-up which will result in reduced down hole failures, (ii) improve efficiency through better logistics and planning, and (iii) improve safety. We believe that this system will provide us a competitive advantage as it is a patented technology. For a further discussion of the KeyView® system, see the section entitled "Business—Patents, Trade Secrets, Trademarks and Copyrights."

In addition, during 2003 we commenced the rollout of our new work management system ("KeyOps™"), which is used to manage our dispatch, order entry, ticketing, employee time tracking and invoicing processes. KeyOps™ provides a standard software platform related to these functions allowing for the improvement of our internal business processes, such as management of equipment utilization and invoicing. We completed the deployment of the KeyOps™ system in all of our domestic well servicing operations in 2004.

Expanded Product Line. In the past several years, we have expanded our product lines, investing in our pressure pumping and cementing operations, our fishing and rental services and, recently, in a new cased-hole electric wireline business. Historically, growth came through acquisitions; however, the focus since 2004 has been on organic growth. We will continue to expand our product line through organic growth and anticipate making additional investments in our asset base in 2007. We intend to

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

evaluate acquisitions that will allow us to further expand our product line and to provide additional higher technology services to our customers.

Remanufacturing Rigs and Related Equipment. We intend to continue to actively remanufacture our rigs and related equipment in order to improve the quality of our rig fleet. We believe that the remanufacturing program results in increased efficiency and improved safety. These benefits, we believe, result in more reliability for our customers. We believe that our cash flow (as well as other financial resources) is sufficient for us to continue to make the capital expenditures necessary to remanufacture our equipment. Although we believe our remanufactured rigs are more economical and equal in quality to new rigs, we may elect to order new rigs during periods of very strong demand when our remanufacturing centers are operating at or near capacity.

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 two training centers in Texas. In addition, in conjunction with local community colleges, we operate four training centers in California, New Mexico, Oklahoma and Wyoming. 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 and are committed to offering compensation, benefits and incentive programs for our employees that are attractive and competitive in the industry, in order to ensure a steady stream of qualified, safety-conscious personnel to provide quality service to our customers.

Current Financial Condition and Liquidity

Despite our significant restatement costs, we believe our current financial condition is strong, and we believe that our current reserves of cash and cash equivalents, current availability of our revolving credit facility, and internally generated cash flow from operations are sufficient to finance the cash requirements of our current and future operations and budgeted capital expenditures for 2006. As of August 31, 2006, we had $143.4 million in cash and $65.0 million of availability under our revolving credit facility. However, we are required under the terms of the facility to provide to our lenders audited financial statements, including for the 2003 fiscal year, and unaudited quarterly financial statements, in each case, meeting the requirements of SEC regulations, no later than March 16, 2007. Under the terms of the senior credit facility, we would have 30 days from such date to satisfy the covenant before an event of default has occurred. Due to our inability to provide audited financial statements for the year ended December 31, 2003, we will be required to either seek a waiver from the lenders under our new senior credit facility by April 2007 or refinance our current senior credit facility or risk an event of default. See "—Liquidity and Capital Resources" below.

During 2005, we refinanced our former senior credit facility and our 8.375% Senior Notes due 2008 (the "8.375% Senior Notes") and 6.375% Senior Notes due 2013 (the "6.375% Senior Notes; together with the 8.375% Senior Notes, the "Senior Notes"). This eliminated the need to secure waivers from the lenders and holders of the Senior Notes due to our failure to timely file our periodic SEC reports. It also freed us from having to pay fees to these creditors to secure the waivers.

On July 29, 2005, we entered into a new $547.3 million senior secured credit facility, which provided us with the ability to refinance our former senior credit facility and to repay our outstanding Senior Notes. On October 5, 2005, we repaid all $150.0 million principal amount of the 6.375% Senior Notes, which had been accelerated on September 27, 2005. We redeemed all $275.0 million principal amount of the 8.375% Senior Notes on November 8, 2005. The Senior Note repayments were funded with the proceeds of a seven-year, $400 million term loan under our new senior secured credit facility

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

and cash on hand. The new facility also includes an $82.3 million synthetic letter of credit facility and a five-year $65.0 million revolving credit facility including a $25.0 million sub-limit for additional letters of credit. The letter of credit facility and revolving credit facility replaced the Company's prior $150.0 million revolving credit facility. We paid fees totaling approximately $7.2 million at closing, which consisted of legal, administrative, closing and other fees.

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 the data is made publicly available on a weekly basis. Historically, the drilling rig count and our rig hours have correlated with capital spending by oil and natural gas producers. When commodity prices are strong and capital spending is high, the drilling rig count tends to increase. During 2003, the Baker Hughes U.S. land drilling rig count improved from an average of approximately 717 for 2002 to approximately 924 for 2003. The rig count continued to improve in 2004 averaging approximately 1,095 for the year and as of August 31, 2006, the rig count was approximately 1,639 rigs.

Internally, we measure activity levels primarily through our rig and trucking hours. 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 provide fewer rig and trucking services, which results in lower hours worked. We publicly release our monthly rig and trucking hours, and our historical annual rig and trucking hour data is provided later in this document.

Operating Environment in 2002 and 2003

Our results of operations for the year ended December 31, 2003 compared to the year ended December 31, 2002 improved as demand for Key's services increased due to the continued strength of commodity prices, which resulted in higher capital spending by our customers. We believe that changes in oil and natural gas prices drive capital and other spending by our customers, which results in increases or decreases in demand for our services. We believe that with strong commodity prices, our customers benefit by increasing production from their oil and natural gas reserves. Therefore, to accomplish this objective, these customers will increase their drilling and workover activities. Conversely, when oil and gas prices decline, our customers will typically curtail capital or other spending, reducing demand for our services. During 2003, WTI Cushing prices for light sweet crude averaged $30.99 per barrel and Nymex Henry Hub natural gas prices averaged $5.49 per MMbtu, as compared to an average WTI Cushing price for light sweet crude of $26.15 per barrel and an average Nymex Henry Hub natural gas price of $3.37 per MMbtu during the year ended December 31, 2002.

Industry conditions during 2002 were weak as commodity prices declined in late 2001 and into the first quarter of 2002. The decline in commodity prices, specifically natural gas, was due primarily to the warm winter in 2001 and 2002 and weak economic conditions following the September 11, 2001 terrorist attacks, all of which resulted in reduced demand for natural gas. This reduced demand caused natural gas inventory levels to remain high, placing additional downward pressure on both oil and natural gas prices. At their low in January 2002, oil prices declined to $18.00 per barrel while natural gas prices declined to $2.00 per MMbtu. We believe that this decline, coupled with the uncertainty over future commodity prices at that time, led many oil and natural gas producers to reduce their capital spending programs. The reduced drilling programs and development spending in early 2002, together with an unusually warm summer, led to only small increases in natural gas storage during the summer build season. These small increases, in our opinion, caused many industry analysts to predict that there

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

might not be sufficient gas in storage for the 2002 and 2003 winter heating season. This resulted in a gradual improvement in commodity prices. Despite the rise in commodity prices through the summer of 2002, oil and natural gas producers were reluctant to significantly increase spending as concern over longer term commodity prices, specifically the stability of oil and natural gas prices, still existed. We believe that most oil and natural gas producers wanted to see indications of either improvement in the U.S. economy and/or a cold winter in 2002 and 2003 that would, in their estimation, provide stability for the higher commodity prices.

The winter of 2002-2003, which was one of the colder winters in recent years, led to early withdrawals from natural gas storage. The withdrawals, which were larger than expected, and the forecast of an unusually cold winter, caused a sharp increase in natural gas prices. By December 2002, natural gas prices were over $5.00 per MMbtu and oil prices had increased to over $30.00 per barrel. In addition, most industry analysts were forecasting strong commodity prices for 2003. This renewed confidence, coupled with improving cash flow for oil and natural gas producers and signs that the U.S. economy was improving, resulted in many U.S. oil and natural gas producers increasing their capital budget plans for 2003.

As commodity prices remained high for most of 2003, many of our customers generated record cash flows and earnings, a portion of which was used to increase spending on exploration and development of oil and natural gas properties. This increased spending is evidenced by the increase in the Baker Hughes U.S. land drilling rig count for the year ended 2003, which averaged 924 rigs versus an average of 717 rigs during 2002. Further, the increase in spending is also reflected in our activity levels, as our rig hours in 2003 increased 8.9% to 2,368,127 hours from 2,174,266 during 2002. Further, in 2003 our trucking hours increased 28.5% to 2,969,564 from 2,310,977 in 2002. The increase in trucking hours in 2003 is due primarily to the full year impact of the QSI acquisition.

Operating Environment since 2003

High commodity prices continued into and through 2004, reflecting concerns about the long-term U.S. supply of natural gas, the limited ability to increase oil and natural gas production despite strong increases in U.S. land drilling, declining U.S. inventories of crude oil, declining Canadian imports and Middle East instability, among other factors. For 2004, WTI Cushing prices for light sweet crude averaged $41.47 per barrel and Nymex Henry Hub natural gas prices averaged $6.18 per MMbtu, as compared to an average WTI Cushing price for light sweet crude of $30.99 per barrel and an average Nymex Henry Hub natural gas price of $5.49 per MMbtu during the year ended December 31, 2003. During 2004, the Baker Hughes U.S. land drilling rig count improved from an average of approximately 924 in 2003 to approximately 1,095 in 2004 and 1,290 in 2005. As of August 31, 2006, the Baker Hughes U.S. land drilling rig count totaled approximately 1,639. Since January 1999, the Baker Hughes U.S. land drilling rig count peaked at 1,663 in August 2006 and bottomed at 392 in April 1999.

We continued to experience positive trends in our operating activities during 2004 and 2005. Rig hours in 2004 increased 9.6% to 2,594,504 hours from 2,368,127 in 2003, while our trucking hours in 2004 decreased 4.8% to 2,827,519 from 2,969,564 in 2003. In 2005 our rig hours totaled 2,598,706 compared to 2,594,504 hours in 2004, although the 2004 rig hours include approximately 173,718 rig hours associated with the contract drilling assets that were divested in January 2005. In 2005 our trucking hours declined 12.3% to 2,479,551 from 2,827,519 in 2004 due to lost market share, primarily to new entrants into the trucking market, and the closing of our Michigan operation in 2005.

We again attribute the increase in activity in both years to high commodity prices and the expectation by many customers that commodity prices will remain strong. We believe that with strong

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

commodity prices, our customers benefit by increasing production from their oil and natural gas reserves. Therefore, to accomplish this objective, we expect these customers will increase their drilling and workover activities as evidenced by the rise in the Baker Hughes land drilling rig count since 2003 and the improvement in our rig hours during this period.

Overall activity levels for 2006 have been stronger than 2005 due to continued strength of commodity prices and demand for our services. Through August 31, 2006, WTI Cushing price for light sweet crude averaged $68.81 per barrel while natural gas prices through same period averaged $7.08 per MMbtu. As a result of these strong commodity prices and higher capital spending by our customers, the Company anticipates that full year 2006 rig hours will approach 2,690,000 hours, which will exceed 2005 results.

We again attribute the strong activity levels since 2004 to high commodity prices and the expectation by many customers that commodity prices will remain strong as evidenced by the NYMEX futures contracts for both oil and natural gas. We attribute the strength of the commodity prices to the following:

•: world demand for oil and natural gas increased as world economies continue to improve;
•: oil is generally priced in U.S. dollars, therefore, the impact of the weak U.S. dollar has resulted in foreign producers seeking a higher oil price; and
•: the war in Iraq and terrorist threats have resulted in a "war" premium which is reflected in higher oil prices.

We recognize that commodity prices are volatile and could decline; however, based on current commodity prices, we believe that our activity levels will remain strong for the balance of 2006 and assuming no material decline in commodity prices, should also remain strong for 2007. Because our focus on well-servicing, pressure pumping, and fishing and rental correlates to drilling activity and commodity prices, our activity levels may be negatively impacted in the event commodity prices decline rapidly or unexpectedly.

In light of the continued strong industry conditions and our expectation that industry conditions will remain strong during the remainder of 2006 and 2007, we have made significant investments in our asset base. Over the past two years, we have continued to rebuild our rig fleet by remanufacturing 81 rigs. In addition, during 2005 we ordered 35 new well service rigs which will be delivered in 2006, and our 2006 capital budget contemplates that we will remanufacture approximately 60 rigs during the year. As of August 31, 2006, we had remanufactured 42 rigs. Further, we announced in August 2006 that we presently intend to remanufacture approximately 70-80 rigs in 2007.

We have made capital expenditures across all product lines, particularly in our pressure pumping and cementing fleet. We opened a new pressure pumping facility in Cleburne, Texas during the June 2006 quarter and we are presently evaluating a new pressure pumping facility in the Fayetteville Shale of Arkansas, which could open as early as June 2007. Our total capital expenditures in 2006 are expected to total approximately $215 million. While our 2007 capital budget is not yet complete, in light of the long lead times on equipment deliveries, our Board of Directors has authorized us to order up to $150 million of new equipment for 2007.

Apache Contract

On March 28, 2002, we entered into a two-year agreement with Apache Corporation to provide workover services to Apache's onshore wells in the Western Desert of the Arab Republic of Egypt.

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

Under the agreement, we provided five well service rigs. The first rig was originally scheduled to come off contract in August 2004, and the last rig was scheduled to come off contract in February 2005. Although Apache had the right to extend the agreement for two additional one-year periods, it did not exercise this right. Apache did, however, extend the contract on one rig through March 31, 2005 and extended the contract on the remaining four rigs through June 30, 2005. Apache did not extend the contract on any of the five rigs beyond June 30, 2005. We have shipped all five rigs back to the United States. Under terms of the agreement with Apache, Apache paid for all demobilization costs associated with these rigs. While the contribution of our Egyptian operations in 2003 to overall revenue was not significant, its contribution to total pre-tax income was material. Specifically, revenue generated by our Egyptian operations during the six months ended December 31, 2002 and the year ended December 31, 2003 was $3.0 million and $16.7 million (or 0.7% and 1.8%, respectively, of Key's total revenue). No revenue was generated from our Egyptian operations for fiscal years 2001 and 2002, as commercial operations did not commence until September 2002. Income from continuing operations before income taxes generated by our Egyptian operations during the six months ended December 31, 2002 and the years ended December 31, 2003 was $1.1 million and $6.0 million, respectively.

Acquisitions

During the year ended December 31, 2003, we completed several small acquisitions for total consideration of $27.7 million, which consisted of a combination of cash, notes payable and shares of our common stock. The acquisitions included niche acquisitions to expand our transportation services and our fishing and rental services. Each of the acquisitions was accounted for using the purchase method, and results of operations generated from the acquired assets are included in our results of operations as of the completion date of each acquisition.

In February 2004, we announced the acquisition of Fleet Cementers, Inc., a wholly owned subsidiary of Precision Drilling Corporation, for approximately $20.0 million in cash (of which, $6.0 million was paid back to us in 2005 in consideration of our agreeing to remove certain non-compete restrictions from the agreement). Fleet Cementers provided pressure pumping services, including cementing, fracturing, acidizing, coil tubing pumping and nitrogen pumping, with primary operations in California and Texas. In connection with the Fleet acquisition, we relocated certain of the Fleet assets to the Barnett Shale region (North Texas). This acquisition was accounted for using the purchase method, and the results of the operations generated from the acquired assets are included in our results of operations as of the completion date of the acquisition. In addition to the Fleet acquisition, we completed several other small acquisitions in 2004 for total consideration of $2.0 million.

Divestitures

On January 15, 2005, we completed the sale to Patterson-UTI Energy, Inc. of the majority of our contract drilling assets, which included the drilling rigs and associated equipment in the Permian Basin and Four Corners and certain rigs from the Rocky Mountain region. In consideration of the sale, we received $62.0 million in cash and retained net working capital of approximately $10 million. 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. The Company estimates that the contract drilling assets contributed $62.0 million of revenue in 2003. See the section entitled "Consolidated Financial Statements and Supplementary Data," Note 22—"Subsequent Events."

In addition, on May 17, 2005 we sold the assets of our Michigan operation for $6.5 million.

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

Discontinued Operations

Fiscal Year Change

In December 2002, our Board of Directors approved a change in Key's fiscal year from a year ended June 30 to a year ended December 31. The consolidated statements of operations, comprehensive income (loss), cash flows and stockholders' equity are presented for the six-month transition period of July 1, 2002 to December 31, 2002. The following is a comparative summary of the operating results for the years ended December 31, 2003 and 2002 and the six-month periods ended December 31, 2002 and 2001.

As more thoroughly described under the section entitled "Consolidated Financial Statements and Supplementary Data," Note 2—"Restatement of Financial Statements," the selected financial data for the year ended December 31, 2002 and the six months ended December 31, 2002 and December 31,

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

2001, respectively, have been restated. As discussed elsewhere herein, these amounts are not presented in accordance with GAAP.

			Year Ended December 31,						Six Months Ended December 31,
			2003			2002			2002			2001
						(Restated) (Unaudited)			(Restated)			(Restated) (Unaudited)
			(in thousands, except per share data)
*REVENUES:*
	Well servicing		$	859,697		$	683,561		$	372,280		$	404,258
	Contract drilling			65,942			56,577			32,137			53,861

Total revenues				925,639			740,138			404,417			458,119

*COSTS AND EXPENSES:*
	Well servicing			621,175			503,295			262,346			261,377
	Contract drilling			48,632			42,828			22,695			35,137
	Depreciation, depletion and amortization			98,067			86,732			47,919			37,893
	Write-off and impairment of property and equipment			63,417			42,800			7,199			4,509
	Loss associated with the South Texas Matters			5,225			—			—			—
	General and administrative			103,519			83,218			51,924			33,167
	Interest expense			48,991			44,593			21,823			20,311
	Loss (gain) on early extinguishment of debt			(16	)		6,811			(18	)		(2,810	)
	Loss (gain) on sales of assets, net			848			639			477			(850	)
	Interest income			(565	)		(513	)		(208	)		(311	)
	Other income, net			(82	)		(1,587	)		(734	)		(128	)

Total costs and expenses, net				989,211			808,816			413,423			388,295

Income (loss) from continuing operations before income taxes				(63,572	)		(68,678	)		(9,006	)		69,824
Income tax benefit (expense)				17,955			26,315			985			(29,949	)

INCOME (LOSS) FROM CONTINUING OPERATIONS				(45,617	)		(42,363	)		(8,021	)		39,875

	Discontinued operations including loss on sale of $5,851 during 2003, net of tax benefit (expense) of $2,763, $2,964, $1,437 and $(896), respectively			(4,754	)		(4,834	)		(2,472	)		1,277
	Cumulative effect on prior years of a change in accounting principle, net of tax expense of $(944)			—			(1,625	)		(1,625	)		—

*NET INCOME (LOSS)*			$	(50,371	)	$	(48,822	)	$	(12,118	)	$	41,152

EARNINGS (LOSS) PER SHARE:
	Net income (loss) from continuing operations
		Basic	$	(0.35	)	$	(0.37	)	$	(0.06	)	$	0.39
		Diluted	$	(0.35	)	$	(0.37	)	$	(0.06	)	$	0.38
	Discontinued operations
		Basic	$	(0.04	)	$	(0.04	)	$	(0.02	)	$	0.01
		Diluted	$	(0.04	)	$	(0.04	)	$	(0.02	)	$	0.01
	Cumulative effect
		Basic	$	—		$	(0.01	)	$	(0.01	)	$	—
		Diluted	$	—		$	(0.01	)	$	(0.01	)	$	—
	Net income (loss)
		Basic	$	(0.39	)	$	(0.42	)	$	(0.09	)	$	0.40
		Diluted	$	(0.39	)	$	(0.42	)	$	(0.09	)	$	0.39
WEIGHTED AVERAGE SHARES OUTSTANDING:
		Basic		129,460			114,800			125,367			102,421
		Diluted		129,460			114,800			125,367			103,898

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

Comparability of Periods

Results of operations and financial condition have been affected by acquisitions, such as the purchase of QSI, and other reclassifications during certain periods discussed, which may affect the comparability of the financial information. We have presented our 2003 Balance Sheet in conformity with GAAP. The other consolidated financial statements are not presented in accordance with GAAP. Because the Company is unable to identify and appropriately evidence the period(s) in which the errors—here, the failure to record the write-offs and write-downs for unlocated assets and some changes in condition—occurred, the comparability of the financial information is affected. Notwithstanding the limitations on the financial statements, we have included such comparisons to provide investors as complete a picture as possible about our historical financial condition and results.

YEAR ENDED DECEMBER 31, 2003 VERSUS YEAR ENDED DECEMBER 31, 2002

Overall

Our revenue for the year ended December 31, 2003 increased $185.5 million, or 25%, to $925.6 million from $740.1 million for the year ended December 31, 2002. For the year ended December 31, 2003 we recognized a net loss of $50.4 million, which was an increased loss of $1.6 million, or 3%, over a net loss of $48.8 million for the year ended December 31, 2002. The increase in revenues is principally due to higher levels of activity and the full year effect of the acquisition of QSI. The additional net loss during 2003 is principally due to a number of non-cash charges, such as write-downs following our physical inventory, examination of condition and intended use, and write-down due to an acquisition in our South Texas division, which collectively totaled $68.7 million. The charges are primarily associated with the Company's fixed assets and include write-downs due to our inability to locate assets in the course of the physical inventory, write-downs due to the condition and intended use of the fixed assets and a charge related to the write-off of goodwill and non-compete agreements originally recorded in connection with an acquisition in our South Texas division. The charges are more fully described in the sections entitled "Consolidated Financial Statements and Supplementary Data," Note 2—"Restatement of Financial Statements," and Note 4—"Property and Equipment." We believe that the increase in activity during the year ended December 31, 2003 was, in part, a result of strong oil and natural gas prices. However, the level of development, exploration and production activity, and corresponding spending by our oil and natural gas customers on well servicing and workover services, did not immediately reflect strong commodity prices. This trend was a break from prior experience. We believe that the primary reason for this change is that some of our major customers were slow to increase spending due to their plans to sell a portion of their properties. Historically, it has been our experience that oil and natural gas producers will harvest the oil and natural gas production and may defer maintenance on their properties before such properties are sold. However, once those properties have changed owners, the acquirer tends to increase activity in order to increase production on the wells. This generally results in increased activity for well service companies. We also believe that our pricing strategy, which is to be the price leader, resulted in some lost market share during the year ended December 31, 2003. We believe that some customers elected to use lower-priced competitors instead of us as industry conditions improved during the year.

For the year ended December 31, 2003, total rig and truck hours increased approximately 9% and 28%, respectively. The increase in rig hours is due to increased activity in the United States and the full year impact of five well service rigs in Egypt. Trucking hours improved principally due to the full year impact of the acquisition of QSI.

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

Set forth below are hours for each our primary service lines for 2002 and 2003.

Service Line Hours	2003	2002	% Change
Well Service Rig	2,182,941	2,011,837	8.5	%
Drilling Rig	185,186	162,429	14.0	%

Total Rig Hours	2,368,127	2,174,266	8.9	%

Trucking Hours	2,969,564	2,310,997	28.5	%

**: Trucking hours includes 69,681 hours for 2003 and 51,830 hours for 2002 from our Argentina division. Historically, we have not reported these hours because the trucking business is primarily used to haul our own equipment to and from well site locations. However, in 2005, we elected to include these trucking hours, since a portion of the trucking business is used to move third party equipment, thereby generating revenue for the Company. The revenue from the Argentina trucking business is less than 0.1% of our total Company revenue.

Operating Revenues

Well Servicing. Well servicing revenues for the year ended December 31, 2003 increased $176.1 million, or 26%, to $859.7 million from $683.6 million for the year ended December 31, 2002. The increase in revenue for the year ended December 31, 2003 is primarily due to the full year impact of the QSI acquisition, which closed in July 2002, and the overall increase in well servicing rig activity levels. We also benefited, to a lesser extent, from the increase in our rates.

During the year ended December 31, 2003, we experienced strong growth in several key markets, including Argentina and both the ArkLaTex and Rocky Mountain regions. We attribute the improvements in Argentina to the strengthening of its economy. We believe that the ArkLaTex and Rocky Mountain regions rebounded more quickly than our other domestic markets due to the customer mix in those regions and the emphasis on natural gas drilling and development. Additionally, during 2003, we benefited from the full year impact of our Egypt operation, in which five well service rigs operated at near full utilization, generating rig hours for the year totaling 41,217. However, during 2003 we experienced activity declines in our California and Michigan markets. The decline in Michigan is due primarily to the consolidation of facilities in addition to the exodus of major oil and natural gas producers from that region and the pressure of several new competitors. The decline in California is due primarily to the impact of increased competition and lost work associated with the implementation of price increases.

Trucking hours increased 28.5% for the year ended December 31, 2003. The increase is due primarily to the full year impact of the acquisition of QSI, as well as the acquisition of several small, regional trucking competitors during the year ended December 31, 2003. Trucking hours were also favorably impacted by increased drilling activity in the Gulf Coast, ArkLaTex and North Texas regions, where we have strong trucking positions.

Contract Drilling. Contract drilling revenues for the year ended December 31, 2003 increased $9.3 million, or 16%, to $65.9 million from $56.6 million for the year ended December 31, 2002. The increase in revenues was primarily due to an increase in equipment utilization, as drilling hours increased 14% to 185,186 for the year ended December 31, 2003 compared to 162,429 for the year ended December 31, 2002. The increase in drilling activity is attributable to significant increases in drilling activity in our Permian Basin division. We believe that the increase in the Permian Basin region

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

coincides with the strong increase in U.S. land drilling activity, as evidenced by the increase in the Baker Hughes U.S. land drilling rig count.

Operating Expenses

Well Servicing. Well servicing expenses for the year ended December 31, 2003 increased $117.9 million, or 23%, to $621.2 million from $503.3 million for the year ended December 31, 2002. As a percentage of well servicing revenues, well servicing expenses were essentially flat as such expenses were 72.3% and 73.6% of revenue for the years ended December 31, 2003 and 2002, respectively. The improved margin is a result of the impact of (i) modestly higher truck and well servicing rig rates, (ii) efficiencies gained from increased activity levels and increased revenue over our fixed cost structure and (iii) lower health insurance costs.

Contract Drilling. Contract drilling expenses for the year ended December 31, 2003 increased $5.8 million, or 14%, to $48.6 million from $42.8 million for the year ended December 31, 2002. The increase in expenses corresponded to higher activity levels. Compared to the year ended December 31, 2002, contract drilling expenses as a percentage of contract drilling revenues modestly improved to 73.7% compared to 75.6% for the year ended December 31, 2002. Despite higher activity levels and modestly improved pricing, our contract drilling operations were negatively impacted by increased repair and maintenance costs.

Depreciation, Depletion and Amortization Expense

Our depreciation, depletion and amortization expense for the year ended December 31, 2003 increased $11.4 million, or 13%, to $98.1 million from $86.7 million for the year ended December 31, 2002. The acquisition of QSI added $139.0 million in net depreciable assets, which contributed to the increase, as did $98.4 million in capital expenditures made during the year ended December 31, 2003, which increased our depreciable asset base as we continued major remanufactures of well servicing and contract drilling equipment.

Write-off and Impairment of Property and Equipment

Based on our comprehensive physical inventory of our fixed assets during 2004, we recognized a $40.5 million loss in the year ended December 31, 2003 for fixed assets that could not be located. Further, in connection with our physical inventory of fixed assets, we identified a portion of our stacked fleet that, based on its condition, was no longer suitable for remanufacture or spare parts. We concluded that the depreciable lives and salvage values of these fixed assets needed to be changed. We were able to determine or estimate when a change in condition occurred for a significant majority of these assets and therefore the appropriate period(s) for recording the adjustments. With respect to a portion of these adjustments, we were unable to identify evidence to determine when the change in condition occurred and determined to record these changes in the fourth quarter of 2003. Accordingly, losses related to condition and intended use of $23.0 million were recognized for the year ended December 31, 2003, of which $10.2 million could not be identified and evidenced as occuring in 2003.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2003 increased $20.3 million, or 24%, to $103.5 million from $83.2 million for the year ended December 31, 2002. The increase is due to the full year impact of the acquisition of QSI, increased compensation costs associated with the acquisition of QSI and additional personnel and higher professional fees. As a result, general and administrative expenses, as a percentage of revenues, were slightly higher for the year ended December 31, 2003 compared to the year ended December 31, 2002.

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

Interest Expense

Interest expense for the year ended December 31, 2003 increased $4.4 million, or 10%, to $49.0 million from $44.6 million for the year ended December 31, 2002. The increase was primarily due to higher average long term debt in the year ended December 31, 2003 as compared to the year ended December 31, 2002. This resulted from the issuance of the 6.375% Senior Notes, a majority of the proceeds of which were ultimately used to repay our outstanding indebtedness, including the early extinguishment of our 14% Senior Subordinated Notes in January 2004.

Income Taxes

Our income tax benefit for the year ended December 31, 2003 totaled $18.0 million compared to an income tax benefit of $26.3 million for the year ended December 31, 2002. Our effective tax rate for the years ended December 31, 2003 and 2002 was 28.2% and 38.3%, respectively. This decrease is due to changes in pre-tax income. The effective tax rates are different from the statutory rate of 35% primarily because of non-deductible expenses, foreign tax rates and the effects of state and local taxes.

SIX MONTHS ENDED DECEMBER 31, 2002 VERSUS SIX MONTHS ENDED DECEMBER 31, 2001

Overall

Revenue for the six months ended December 31, 2002 decreased $53.7 million, or 12%, to $404.4 million from $458.1 million for the six months ended December 31, 2001. For the six months ended December 31, 2002, we incurred a net loss of $12.1 million, a decrease of $53.3 million from net income of $41.2 million for the six months ended December 31, 2001. The decrease in revenues and net income is principally due to lower levels of activity and lower pricing, which were partially offset by the acquisition of QSI. Overall rig hours declined approximately 20% from the six months ended December 31, 2001 compared to the six months ended December 31, 2002, and this decline was coupled with a decrease in pricing from the six months ended December 31, 2001. While trucking hours increased approximately 27% for the six months ended December 31, 2002 compared to the six months ended December 31, 2001, the increase was principally due to the acquisition of QSI. The net loss in the six months ended December 31, 2002 was also affected by the cumulative effect of our adoption of Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"), costs associated with the integration of QSI, and unusually high general liability costs and higher depreciation costs.

Operating Revenues

Well Servicing. Revenues decreased $32.0 million, or 8%, for the six months ended December 31, 2002 to $372.3 million from $404.3 million for the six months ended December 31, 2001. The decrease in revenues was primarily due to a decline in activity and in well servicing rig rates, which were partially offset by the acquisition of QSI. Well servicing hours declined approximately 18% from the six months ended December 31, 2001, and this decline was exacerbated by a decline in pricing. While trucking hours increased approximately 27% for the six-month period ended December 31, 2002 compared to the six months ended December 31, 2001, the increase was principally due to the acquisition of QSI.

Contract Drilling. Revenues decreased $21.8 million, or 40%, for the six months ended December 31, 2002 to $32.1 million from $53.9 million for the six months ended December 31, 2001. The decrease in revenues was primarily due to a decline in equipment utilization and in contract drilling rig rates. Contract drilling hours declined approximately 39% for the six months ended December 31, 2002 compared to the six months ended December 31, 2001.

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

Operating Expenses

Well Servicing. Expenses increased $1.0 million or less than one percent for the six months ended December 31, 2002 to $262.4 million from $261.4 million for the six months ended December 31, 2001. Although well servicing hours decreased, expenses increased due to the acquisition and integration costs associated with QSI. Well servicing expenses as a percentage of well servicing revenues increased from 64.7% for the six months ended December 31, 2001 to 70.4% for the six months ended December 31, 2002.

Contract Drilling. Expenses decreased $12.4 million or 35% for the six months ended December 31, 2002 to $22.7 million from $35.1 million for six months ended December 31, 2001. The decrease is primarily due to lower activity levels. Contract drilling expenses as a percentage of contract drilling revenues increased from 65.1% for the six months ended December 31, 2001 to 70.7% for the six months ended December 31, 2002.

Depreciation, Depletion and Amortization Expense

Our depreciation, depletion and amortization expense for the six months ended December 31, 2002 increased $10.0 million, or 26%, to $47.9 million from $37.9 million for the six months ended December 31, 2001. The increase was primarily due to the acquisition of QSI, which added $139.0 million in net depreciable property, equipment and intangible assets, and our capital expenditure program, as we continued major remanufactures of well servicing and contract drilling equipment.

Write-off and Impairment of Property and Equipment

Based on our analysis of the status and condition of our fixed assets performed in connection with the restatement, we concluded that the depreciable lives and salvage values should be adjusted to reflect the assets' condition and intended use. As a result, we recognized additional expense of $7.2 million and $4.5 million for the six-month period ended December 31, 2002 and December 31, 2001, respectively.

General and Administrative Expenses

Our general and administrative expenses for the six months ended December 31, 2002 increased $18.7 million, or 56%, to $51.9 million from $33.2 million for the six months ended December 31, 2001. The increase was primarily due to the acquisition of QSI, costs associated with the integration of QSI, higher general liability costs including settlement expenses, and additional personnel supporting the implementation of information technology. General and administrative expenses, as a percentage of revenues, increased from 7.2% for the six months ended December 31, 2001 to 12.8% for the six months ended December 31, 2002.

Income Taxes

Our income tax benefit for the six months ended December 31, 2002 totaled $1.0 million compared to income tax expense of $29.9 million for the six months ended December 31, 2001. The decrease in income tax expense is due to decreased pre-tax income. Our effective tax rates for the six-month periods ended December 31, 2002 and 2001 were 10.9% and 43.1%, respectively. The effective tax rates are different from the statutory rate of 35% primarily because of non-deductible expenses foreign tax rates and the effects of state and local taxes.

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

YEAR ENDED JUNE 30, 2002 VERSUS YEAR ENDED JUNE 30, 2001

Overall

Our results of operations for the year ended June 30, 2002 reflect the impact of a decline in industry conditions resulting from decreased commodity prices (and, we believe, our customers' perception that commodity prices would decrease further), which in turn caused a decline in demand for our equipment and services, partially offset by our limited rate concessions and lower interest charges during the year ended June 30, 2002.

Revenues for the year ended June 30, 2002 decreased $72.1 million, or 8%, to $793.8 million from $865.9 million for the year ended June 30, 2001, while net income for the year ended June 30, 2002 decreased $40.5 million, or 91%, to $4.1 million from a net income of $44.6 million for the year ended June 30, 2001. The decrease in revenues and net income is due to an impairment of long-lived assets of $19.9 million for the year ended June 30, 2002 and lower levels of activity, partially offset by higher pricing, with lower interest expense from debt reduction also contributing to net income. Rig and truck hours for the year ended June 30, 2002 decreased approximately 14% and 6%, respectively, compared to the corresponding period in the prior year.

Operating Revenues

Well Servicing. Revenues decreased $58.2 million, or 8%, for the year ended June 30, 2002 to $712.6 million from $770.8 million for the year ended June 30, 2001. The decrease was due to lower demand for our well servicing equipment and services, partially offset by higher pricing. Well servicing hours for the year ended June 30, 2002 decreased approximately 13%.

Contract Drilling. Revenues decreased $13.9 million, or 15%, for the year ended June 30, 2002 to $81.2 million from $95.1 million for the year ended June 30, 2001. The decrease was due to lower demand for our contract drilling equipment and services, partially offset by higher pricing. Contract drilling hours for the year ended June 30, 2002 declined approximately 28%.

Operating Expenses

Well Servicing. Expenses decreased $18.1 million, or 3%, for the year ended June 30, 2002 to $500.9 million from $519.0 million for the year ended June 30, 2001. The decrease in expenses was due to lower activity levels partially offset by higher insurance costs, primarily for workers' compensation and health care. Despite the decreased costs, well servicing expenses as a percentage of well servicing revenues increased from 67.3% for the year ended June 30, 2001 to 70.3% for the year ended June 30, 2002, primarily due to the increase in insurance costs.

Contract Drilling. Expenses decreased $9.3 million, or 14%, for the year ended June 30, 2002 to $56.7 million from $66.0 million for the year ended June 30, 2001. The decrease was due to lower activity levels, partially offset by higher insurance costs primarily in workers' compensation and health care. Contract drilling expenses as a percentage of contract drilling revenues were flat from 69.4% for the year ended June 30, 2001 to 69.8% for the year ended June 30, 2002. The marginal improvement in operating efficiencies and the effects of higher pricing were partially offset by the increase in insurance costs.

Depreciation, Depletion and Amortization Expense

Our depreciation, depletion and amortization expense for the year ended June 30, 2002 decreased $0.1 million to $77.0 million from $77.1 million for the year ended June 30, 2001. The decrease was

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

due to recent acquisitions and increased capital expenditures during the year as we continued major remanufactures of well servicing and contract drilling equipment, partially offset by discontinued amortization of goodwill, which amounted to $9.3 million for the year ended June 30, 2001, because of our adoption of Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142.")

Write-off and Impairment of Property and Equipment

In connection with the restatement, we identified as a trigger event under Statement of Financial Accounting Standards No. 144, "Impairment of Long-Lived Assets" ("SFAS 144") a build up of costs associated with our well servicing and drilling assets. As a result, we performed an impairment test for all divisions as of June 30, 2002. The future cash flows exceeded the carrying amount of all divisions except for our Eastern division. We concluded that the carrying value of our Eastern Division assets had been impaired and recognized impairment write-offs of $19.9 million and zero for the years ended June 30, 2002 and June 30, 2001, respectively.

General and Administrative Expenses

Our general and administrative expenses for the year ended June 30, 2002 increased $1.7 million to $64.5 million from $62.8 million for the year ended June 30, 2001. General and administrative expenses as a percentage of total revenues was 8.1% for the year ended June 30, 2002 and 7.3% for the year ended June 30, 2001.

Interest Expense

Our interest expense for the year ended June 30, 2002 decreased $10.3 million, or 19%, to $43.1 million from $53.4 million for the year ended June 30, 2001. The decrease was primarily due to a significant reduction in our long-term debt using proceeds from a December 2001 equity offering and operating cash flow, and to a lesser extent, lower interest rates.

Early Extinguishment of Debt

During the year ended June 30, 2002, we repurchased $150.1 million of our long-term debt at various discounts and premiums to par value and expensed related unamortized debt issuance costs, all of which resulted in an after-tax loss of $4.0 million. In January 2002, we exercised a clawback provision in our 14% Senior Subordinated Notes. We chose to repurchase these Notes, which represented our highest coupon debt, using cash proceeds from a December 2001 equity issuance.

Income Taxes

Our income tax expense for the year ended June 30, 2002 decreased $31.7 million to $4.6 million from $36.3 million for the year ended June 30, 2001. The decrease in income tax expense was due to decreased pre-tax income. Our effective tax rates for the years ended June 30, 2002 and 2001 were 47.0% and 44.7%, respectively. The effective tax rates vary from the statutory federal rate of 35% principally because of the disallowance of certain goodwill amortization (for the year ended June 30, 2001), other non-deductible expenses, foreign tax rates and the effects of state and local taxes.

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

LIQUIDITY AND CAPITAL RESOURCES

General

We have historically funded our operations, including capital expenditures, from cash flow from operations and have funded growth opportunities, including acquisitions, through bank borrowings and the issuance of equity and long-term debt. In recent years, we have pursued a strategy of repaying indebtedness and have accomplished this objective by using cash generated by operations and cash proceeds from equity offerings. We intend to continue to reduce debt with our cash flow from operations and proceeds from asset sales; however, we do not intend to forego growth opportunities, whether they are acquisitions or capital expenditures, if we believe those opportunities may provide a better return for our shareholders than debt reduction. We will continue to evaluate our opportunities to lower our cash interest costs through debt refinancing.

We believe that our current reserves of cash and cash equivalents, availability under our revolving 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 2006. As of August 31, 2006, we had $143.4 million in cash and $65.0 million of availability under our revolving credit facility.

However, we are required under the terms of the facility to provide to our lenders audited financial statements, including for the 2003 fiscal year, and unaudited quarterly financial statements, in each case, meeting the requirements of SEC regulations, no later than March 16, 2007. Under the terms of the senior credit facility, we would have 30 days from such date to satisfy the covenant before an event of default has occurred. Due to our inability to provide financial statements for the year ended December 31, 2003 that comply with SEC rules, we will be required before April 2007 to either seek a waiver from the lenders under our new senior credit facility or refinance our current senior credit facility or risk an event of default.

Effect of Failure to Make SEC Filings

Our failure to file our 2003 Annual Report on Form 10-K on a timely basis violated covenants under our former senior credit facility. Since March 31, 2004, we amended the terms of our then-existing facility six times to waive the covenant non-compliance and to extend the due date for this and other filings. Details of each amendment are set forth below. The final due date under the then-existing facility for the filing of the 2003 Annual Report on Form 10-K was July 31, 2005. In addition, pursuant to the last amendment, the due date for filing of our Annual Report on Form 10-K for 2004 and the Quarterly Reports on Form 10-Q for the first three quarters of 2004 was October 31, 2005. The last amendment also extended the date by which the Quarterly Reports on Form 10-Q for the first quarter and second quarter of 2005 had to be filed to December 31, 2005. On July 29, 2005, we entered into a new senior secured credit facility, which replaced our then-existing senior credit facility.

In addition, our failure to file our 2003 Annual Report on Form 10-K on a timely basis violated covenants under the indentures for the Senior Notes. Since March 31, 2004, we amended the terms of each of the Senior Note indentures three times to waive the covenant non-compliance and to extend the due date for this and other filings. Details of the consents are provided below. We were required under the last consent by the holders of each series of Senior Notes to file our 2003 Annual Report on Form 10-K on or before May 31, 2005 and our 2004 Quarterly Reports on Form 10-Q and our Annual Report on Form 10-K for 2004 on or before July 31, 2005. The consent also provided that the Quarterly Reports on Form 10-Q for the first quarter and second quarter of 2005 had to be filed no later than August 31, 2005. We failed to meet those deadlines, and as a result, on June 6, 2005, the

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

trustee for the Senior Notes sent us notice of the financial reporting violation, which then 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, and the 6.375% Senior Notes were repaid on October 5, 2005. We also redeemed all of the 8.375% Senior Notes on November 8, 2005. The 6.375% Senior Notes and the 8.375% Senior Notes were repaid with funds from our new senior secured credit facility and cash on hand.

Liquidity and Capital Resources for Year Ended December 31, 2003

Our primary debt obligations, other than capital lease obligations and miscellaneous notes payable, as of December 31, 2003, were (i) our then-existing senior credit facility, (ii) the 6.375% Senior Notes, (iii) the 8.375% Senior Notes, (iv) a series of 14% Senior Subordinated Notes Due 2009 ("the 14% Senior Subordinated Notes"), and (v) a series of 5% Convertible Subordinated Notes Due 2004 ("the 5% Convertible Notes").

On January 15, 2004, we retired the outstanding $97.5 million principal amount of our 14% Senior Subordinated Notes. The notes were redeemed at a redemption price of 107% of the principal amount outstanding plus accrued and unpaid interest to the redemption date for a total cash outlay of $111.2 million. We used our cash on hand and borrowings under our then-existing senior credit facility to redeem the 14% Senior Subordinated Notes.

During the year ended December 31, 2003, we repurchased (and canceled) $30.9 principal amount of the 5% Convertible Notes, leaving $18.7 million outstanding as of December 31, 2003. On September 25, 2004, we used cash on hand and borrowings under our revolving credit facility to repay the outstanding $18.7 million principal amount of our 5% Convertible Notes at par.

As of December 31, 2003, we had working capital (excluding the current portion of long-term debt and capital lease obligations of $24.3 million) of $176.1 million, which includes cash and cash equivalents of $103.2 million, as compared to working capital (excluding the current portion of long-term debt and capital lease obligations of $7.0 million) of $74.0 million, which includes cash and cash equivalents of $9.0 million, as of December 31, 2002. The increase is principally due to our issuance of $150.0 million of 6.375% Senior Notes on May 14, 2003. The net cash proceeds from that issuance were used to repay the balance of the revolving loan facility then outstanding, and the remainder was used for general corporate purposes and early extinguishment of debt, including the 14% Senior Subordinated Notes.

On November 10, 2003, we entered into an amended senior credit facility that provided, among things, for a $175.0 million revolving facility.

Credit Facility Waivers

As a result of the delays in filing our Annual Report on Form 10-K for the year ending December 31, 2003, we had to seek multiple waivers from our lenders due to our non-compliance with several terms in the then-existing senior credit facility.

On April 5, 2004, the lenders amended the terms of the facility to waive non-compliance with covenants requiring delivery of audited financial statements and to extend to September 30, 2004 the date by which we were required to deliver audited financial statements for 2003 and quarterly unaudited financial statements for the first two quarters of 2004.

In connection with the waiver, we agreed to deliver to the lenders draft, internal, unaudited financial statements setting forth our financial position and results of operations as of and for the year

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

ended December 31, 2003 and the quarters ended March 31, 2004 and June 30, 2004, subject to any write-downs, write-offs, charges and adjustments required as a result of the restatement. We also agreed that until we delivered audited 2003 financial statements and unaudited quarterly financial statements (in each case reflecting the impact of the restatement), we would be prohibited from making acquisitions (other than a few specified acquisitions permitted by the waiver), from paying any dividends or repurchasing stock, and from making optional payments or prepayments on our Senior Notes, subordinated debt and certain other unsecured debt. The waiver permitted us to repay the remaining $18.7 million principal amount of our 5% Convertible Notes on the maturity date of such notes, if we had at least $50.0 million in availability under the senior credit facility after giving effect to such repayment. We met this condition of the waiver and subsequently retired the remaining $18.7 million of 5% Convertible Notes.

The waiver further stipulated that until the audited financial statements and unaudited quarterly financial statements were delivered, applicable interest rate margins for LIBOR and base rate loans would not be reduced below 1.75% and 0.25%, respectively, and applicable commitment fee rates would not be reduced below 0.375%. These pricing levels could, however, be increased above those levels in accordance with the terms of the facility.

The waiver also provided that it would be an event of default if we determined that the write-downs, write-offs, charges or other adjustments to be recorded in connection with the restatements would exceed $100.0 million. Under the waiver, a default arising from the failure to deliver periodic reports under any of the indentures pursuant to which the Senior Notes and the 5% Convertible Notes were issued would not constitute a cross-default under the revolving credit facility unless the requisite notice of default had been given under the applicable indenture and the 60-day cure period after such notice had expired.

On August 31, 2004, the lenders again amended the terms of the facility to extend their waiver of non-compliance with covenants requiring delivery of audited financial statements. The lenders agreed to extend to December 31, 2004, the date by which we were required to deliver audited financial statements for 2003 and quarterly unaudited financial statements for the first three quarters of 2004.

Under the terms of this amendment, until the later of (1) the delivery of final audited financial statements for the year ended December 31, 2003 and unaudited quarterly financial statements for the first three quarters of 2004, or (2) the date on which our senior secured debt was rated BB- or higher by Standard & Poor's or Ba3 or higher by Moody's, applicable interest rate margins for LIBOR and base rate loans would not be reduced below 2.25% and 0.75%, respectively, and applicable commitment fee rates would not be reduced below 0.375%. This amendment also provided that it would be an event of default if we determined that the write-downs, write-offs, charge-offs or other adjustments to be recorded in connection with the restatement of our financial statements would exceed $200.0 million. The terms of the amendment were otherwise similar to those set forth in the prior amendment entered into on April 5, 2004.

On December 17, 2004, the senior credit facility lenders provided a third amendment to the terms of the facility to extend their waiver of non-compliance with covenants requiring delivery of audited financial statements. The lenders agreed to extend to March 31, 2005, the date by which we would deliver audited financial statements for 2003 and quarterly unaudited financial statements for the first three quarters of 2004. In addition, the amendment stated that until we received the consent of the holders of our Senior Notes to extend the date by which we would deliver our financial statements, the outstanding borrowings under the revolving credit facility could not exceed $150.0 million. We subsequently received the required consent of the bondholders on January 20, 2005.

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

On March 30, 2005, the senior credit facility lenders provided a fourth amendment to the terms of the facility to extend their waiver of non-compliance with covenants requiring delivery of audited financial statements. The lenders agreed to (i) extend to April 30, 2005, the date by which we would deliver audited financial statements for 2003, (ii) extend to June 30, 2005, the date by which we would deliver audited financial statements for 2004 and quarterly unaudited financial statements for the first three quarters of 2004, and (iii) extend to August 31, 2005, the date by which we would deliver quarterly unaudited financial statements for the first two quarters of 2005. In addition, the amendment also permanently reduced the maximum borrowings under the revolving credit facility to $150.0 million from $175.0 million.

On April 29, 2005, the senior credit facility lenders provided a fifth amendment to the terms of the facility to extend their waiver of non-compliance with covenants requiring delivery of audited financial statements. The lenders agreed to (i) extend to May 31, 2005, the date by which we would deliver audited financial statements for 2003, (ii) extend to July 31, 2005, the date by which we would deliver audited financial statements for 2004 and quarterly unaudited financial statements for the first three quarters of 2004 and (iii) extend to August 31, 2005, the date by which we would deliver quarterly unaudited financial statements for the first two quarters of 2005. In addition, the amendment also permanently increased the pricing grid by 0.250%.

On May 26, 2005, the senior credit facility lenders provided a sixth amendment to the terms of the facility to extend their waiver of non-compliance with covenants requiring delivery of audited financial statements. The lenders agreed to (i) extend to July 31, 2005, the date by which we would deliver audited financial statements for 2003, (ii) extend to October 31, 2005, the date by which we would deliver audited financial statements for 2004 and quarterly unaudited financial statements for the first three quarters of 2004, and (iii) extend to December 31, 2005, the date by which we must deliver quarterly unaudited financial statements for the first three quarters of 2005.

We paid a total of $5.6 million to the lenders under the credit facility between April 2004 and July 2005 to secure waivers of the information covenants.

Senior Note Consents

Our failure to file our 2003 Annual Report on Form 10-K report with the SEC and deliver it to noteholders on or before March 30, 2004 was a default under each of the indentures for the Senior Notes. On June 1, 2004, we received a notice from the indenture trustee for each series of Senior Notes notes that gave us 90 days to cure the default. We commenced a consent solicitation to amend the indentures to give us until December 31, 2004 to comply with the financial reporting covenants in the indentures. The consent would also constitute a waiver of all defaults with respect to the financial reporting covenants in the indentures and of any and all rights to accelerate the notes as a result of the defaults. On July 19, 2004, we received and accepted consents from holders of a majority of our 6.375% Senior Notes and a majority of our 8.375% Senior Notes to extend until December 31, 2004 the period in which we had to deliver our 2003 annual and 2004 quarterly reports.

We paid each valid consenting holder of Senior Notes a consent fee of $5.00 per $1,000 principal amount. Further, under the terms of the waiver, the noteholders were paid an additional consent fee of $2.50 per $1,000 principal amount for each month after September 30, 2004 and before January 1, 2005, that the financial statements were not delivered. We also agreed to disclose certain selected financial information on a monthly basis.

On January 7, 2005, we received notice from the trustee under each of the Senior Note indentures that we breached the financial reporting covenants contained in the indentures, as amended, by failing

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

to make the 2003 annual and 2004 quarterly filings by December 31, 2004. The notice stated that unless the default was remedied within 60 days, an event of default would occur under the indentures.

By January 19, 2005, we had received and accepted consents from holders of a majority of each series of Senior Notes to extend until March 31, 2005 the period within which we had to deliver our 2003 annual and 2004 quarterly reports. We paid each valid consenting holder of the 6.375% Senior Notes and 8.375% Senior Notes a consent fee of $2.50 per $1,000 principal amount. In addition, we agreed to pay within three business days of each of February 1, 2005 and March 1, 2005 to each consenting holder, an additional $2.50 in cash for each $1,000 principal amount of consenting notes if we had not provided, by such dates, the 2003 annual and 2004 quarterly reports.

On April 5, 2005, we accepted consents from holders of a majority of each series of Senior Notes to extend the dates by which we had to file annual and quarterly reports for 2003, 2004 and 2005. As a result, we had until May 31, 2005 to file the Annual Report on Form 10-K for 2003. In addition, we had (i) until July 31, 2005 to file our Annual Report on Form 10-K for 2004 and the Quarterly Reports on Form 10-Q for the first three quarters of 2004, and (ii) until August 31, 2005, to file our Quarterly Reports on Form 10-Q for the first two quarters of 2005. In consideration of the consents, we paid $3.75 for each $1,000 in principal amount of the Notes, due to the delay in our financial reporting for the years ended December 31, 2003 and December 31, 2004. In addition, we paid all noteholders $1.25 for each $1,000 in principal amount on the 1st day of each month for which the reporting covenants were not satisfied with respect to filings for the 2004 year and first three quarters of 2004, beginning May 1, 2005. Further, on July 1, 2005, we made an additional one-time consent payment to the noteholders equal to $1.25 per $1,000 principal amount of the Notes for our failure to file our Quarterly Report on Form 10-Q for the first quarter of 2005 with the SEC prior to July 1, 2005. We made an additional one-time consent payment to the noteholders equal to $1.25 per $1,000 principal amount of the Notes for our failure to file Quarterly Reports on Form 10-Q for the first and second quarters of 2005 with the SEC prior to August 10, 2005.

Finally, in April 30, 2005, we agreed to pay on May 1, 2005 a one-time additional consent fee of $3.75 for each $1,000 in principal amount of the Notes to all noteholders. This payment was in addition to the fee described above that was unpaid on that date with respect to the filing delay with respect to the Annual Report on Form 10-K for the year ended December 31, 2004.

Due to our failure to file our Annual Report on Form 10-K for the year ended December 31, 2003 by May 31, 2005, the trustee for the Notes sent us notices of default, which provided that an event of default would occur if we failed to cure the default by August 6, 2005. Our failure to file the 2003 Annual Report on Form 10-K by August 6, 2005 allowed the holders to make demand for payment at any time thereafter. On September 28, 2005, we received a valid acceleration notice for the 6.375% Senior Notes, which were repaid upon demand on October 5, 2005. In addition, we redeemed the outstanding principal amount of the 8.375% Senior Notes on November 8, 2005.

We paid a total of $14.1 million in consent payments to our noteholders between July 2004 and May 2005 in connection with the delays in filing our SEC reports.

New Senior Secured Credit Facility

On July 29, 2005, the Company entered into a Credit Agreement (the "New Senior Secured Credit Facility") among the Company, as Borrower, the several lenders from time to time party thereto, Lehman Brothers Inc., as sole lead arranger and sole bookrunner, Lehman Commercial Paper Inc., as syndication agent, administrative agent and as collateral agent, and Wells Fargo Foothill, Inc., as revolving administrative agent. The New Senior Secured Credit Facility consists of (i) a revolving credit

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

facility of up to an aggregate principal amount of $65.0 million, which will mature on July 29, 2010, (ii) a senior term loan facility in the original aggregate amount of $400.0 million, which is 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 will mature on July 29, 2010. The proceeds from the New Senior Secured Credit Facility may be used (i) to refinance the Company's indebtedness under its existing revolving credit facility and the Senior Notes and (ii) for general corporate purposes. The revolving credit facility includes a $25.0 million sub-facility for additional letters of credit.

The New Senior Secured Credit Facility contains certain covenants, which, among other things, require the maintenance of a prescribed consolidated leverage ratio and a consolidated interest coverage ratio. Upon the occurrence of certain events of default, the Company's obligations under the New Senior Secured Credit Facility may be accelerated. Such events of default include payment defaults to lenders under the New Senior Secured Credit Facility, covenant defaults and other customary defaults.

Further, the covenants require the Company to provide to our lenders audited financial statements, including for the 2003 fiscal year, and unaudited quarterly financial statements, in each case, meeting the requirements of SEC regulations, no later than March 16, 2007. Under the terms of the senior credit facility, we would have 30 days from such date to satisfy the covenant before an event of default has occurred. Due to the Company's inability to provide financial statements for the year ended December 31, 2003 that comply with SEC rules, the Company will be required by April 2007 to either seek a waiver from the lenders under its New Senior Secured Credit Facility or refinance its New Senior Secured Credit Facility, or risk an event of default. The Company can make no assurances that it will be granted a waiver or be able to obtain alternative financing on reasonable commercial terms.

14% Senior Subordinated Note Warrants

In January 1999, we issued 150,000 warrants (the "Warrants") to purchasers of our 14% Senior Subordinated Notes. At December 31, 2003, there were 86,500 Warrants outstanding, which are exercisable for 1,253,350 shares of common stock at an exercise price of $4.88125 per share. 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 have been unable to maintain our effective registration statement due to our failure to timely file our SEC reports. As a result, we paid liquidated damages starting at $0.05 per Warrant per week and escalating to $0.20 per Warrant per week. The total amounts paid to the holders of the Warrants were $69,200 and $730,925 in the years ended December 31, 2004, and 2005, respectively.

Other Waivers and Consents

Our primary casualty insurance carrier extended to September 30, 2004, the date by which we had to deliver audited annual financial statements and reduced the credit ratings triggers contained in certain security agreements between the insurance carrier and Key. After we amended the agreement with our casualty carrier, our credit ratings were downgraded and, as a result, we were required to post letters of credit. We subsequently arranged for a letter of credit to be available to meet this obligation for the benefit of the carrier.

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

We also obtained a series of waivers from financial institutions that leased equipment such as tractors, trailers, frac tanks and forklifts, to the Company under certain master lease agreements. Under the master lease agreements, the Company was required to provide current annual and quarterly reports. The most current waivers allowed until September 30, 2006 to provide the 2003 Annual Report on Form 10-K, and allow until January 2007 to provide the Annual Report on Form 10-K for the years ended 2004 and 2005. Due to our inability to provide audited financial statements for the year ended December 31, 2003, we will have to seek additional waivers and amendments from our equipment lessors or pay-off the outstanding leases. As of August 31, 2006, there was approximately $18.0 million outstanding under such equipment leases.

Some lessors refused to grant such waivers and demanded to be repaid. Between June 1, 2005 and August 4, 2005, we paid three lessors an aggregate amount of $16.1 million to satisfy lease obligations and to exercise equipment purchase options.

We entered into two new master lease agreements on August 31, 2005 and on October 14, 2005 with a new lessor. Some of the equipment, which was being leased from lessors that had demanded to be repaid, was transferred to this new lessor through sale/leaseback transactions. We received an aggregate amount of $10.5 million from the sale/leaseback transactions. However, we will also need to seek waivers from this new lessor.

Registration Statements

At December 31, 2003, we had a shelf registration statement on file with the SEC; however, as a result of our restatement process, the shelf registration statement is no longer available. Until we are current in our SEC reports, our access to the public securities markets will be limited. See the section entitled "Risk Factors" for a discussion of our ability to become current and to file compliant reports.

Cash Flow

Our net cash provided by operating activities for the year ended December 31, 2003, totaled $124.6 million. Our net cash used in investing activities for the year ended December 31, 2003 totaled $84.0 million. During the year ended December 31, 2003, the Company spent $98.4 million on capital expenditures and received $4.2 million from the sale of fixed assets. Our net cash provided by financing activities totaled $53.3 million for the year ended December 31, 2003. The Company issued $150.0 million of 6.375% Senior Notes during the year and used a portion of the proceeds to repay outstanding indebtedness.

Our net cash provided by operating activities for the six months ended December 31, 2002, totaled $39.5 million. Our net cash used in investing activities for the year ended December 31, 2002 totaled $132.2 million. During the six months ended December 31, 2002, the Company spent $110.8 million on acquisitions, of which the majority relates to the acquisition of QSI in July 2002. Our net cash provided by financing activities totaled $47.2 million for the six months ended December 31, 2002.

Off-Balance Sheet Arrangements

At December 31, 2003 we did not and we currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

Contractual Obligations

Set forth below is a summary of contractual obligations as of December 31, 2003:

		Payments Due by Period (thousands)
		Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Long-term debt, excluding discount and premium		$	541,232	$	18,732	$	—	$	275,000	$	247,500
Capital lease obligations			16,794		5,588		11,206		—		—
Operating leases			40,015		13,245		18,748		6,431		1,591
Non compete and severance liabilities			2,407		137		1,570		340		360

	Total	$	600,448	$	37,702	$	31,524	$	281,771	$	249,451

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:

•: Estimate of reserves for workers' compensation, vehicular liability and other self-insured retentions;
•: Accounting for contingencies;
•: Accounting for income taxes;
•: Estimate of fixed asset depreciable lives; and
•: Valuation of tangible and intangible assets.

Our 2003 Balance Sheet presents our financial condition as of that date in accordance with GAAP. The other consolidated financial statements are not presented in accordance with GAAP.

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

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

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 the company 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 and injury or death to our employees or third parties. Although the company purchases insurance to protect against large losses, much risk is retained in the form of large deductibles or self-insured retentions.

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

Based on the risks discussed above, we estimate our liability arising out of potentially insured events, including workers' compensation, employer's liability, vehicular liability, and general liability, and record accruals in our consolidated financial statements. Reserves related to 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," 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 reserves recorded on the balance sheet. We adjust these reserves 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 judgment 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. If different estimates and judgments were applied with respect to these matters, it is likely that reserves would be recorded for different amounts. Actual results could vary materially from these reserves.

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

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

Under the provisions of SFAS 143, we record legal obligations to retire tangible, long-lived assets on our balance sheet as liabilities, which are recorded at a discount when we incur the liability. Significant judgment is involved in estimating our future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. If our estimates on the amount or timing of the cash flows change, the change may have a material impact on our results of operations.

Accounting for Income Taxes

We follow Statement of Financial Accounting Statements No. 109, "Accounting for Income Taxes," which requires that we account for deferred income taxes using the asset and liability method and provide income taxes for all significant temporary differences. Management determines our current tax liability as well as taxes incurred as a result of current operations, yet deferred until future periods. Current taxes payable represent our liability related to our income tax return for the current year, while net deferred tax expense or benefit represents the change in the balance of deferred tax assets and liabilities reported on our consolidated balance sheets. Management estimates the changes in both deferred tax assets and liabilities using the basis of assets and liabilities for financial reporting purposes and for enacted rates that management estimates will be in effect when the differences reverse. Further, management makes certain assumptions about the timing of temporary tax differences for the differing treatment of certain items for tax and accounting purposes or whether such differences are permanent.

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. As a result, we can give no assurance that loss carryforwards will be realized or available in the future. Additionally, we record reserves for uncertain tax positions that are subject to management judgment related to the resolution of the tax positions and completion audits by tax authorities in the domestic and international tax jurisdictions in which we operate.

Please see the section entitled "Consolidated Financial Statements and Supplementary Data," Note 9—"Income Taxes" for further discussion of accounting for our income taxes, changes in our valuation allowance, components of our rate reconciliation and realization of loss carryforwards.

Estimate of Depreciable Lives

We use the estimated depreciable lives of our long-lived assets, such as rigs, heavy duty trucks, trailers, etc., to compute depreciation expense, to estimate future asset retirement obligations and to conduct impairment tests. We base the estimate of our depreciable lives on a number of factors, such

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

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.

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

We periodically analyze the depreciable lives of our fixed assets to determine depreciable periods and salvage value. We also analyze useful lives and salvage value when events or conditions occur that could shorten the remaining depreciable life of the 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 shorter than originally estimated, depreciation expense may increase 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 SFAS 142 and as required by SFAS 144, we review long-lived assets, such as well-service rigs, drilling rigs, heavy duty trucks, investments, goodwill and non-compete agreements 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, 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.

Financial Accounting Standards Affecting This Report

In June 2002, the FASB issued Statement of Financial Accounting Standards No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS 146"). SFAS 146 establishes requirements for financial accounting and reporting for costs associated with exit or disposal activities. SFAS 146 is effective for exit or disposal activities initiated after June 30, 2002. The adoption of SFAS 146 did not have a material impact on us.

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others, an interpretation of FASB Statements No. 5, 57 and 107 and a rescission of FASB Interpretation No. 34" ("FIN 45"). FIN 45 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees it has issued. FIN 45 also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation that has been undertaken. The initial recognition and measurement provisions of FIN 45 are applicable to guarantees issued or modified after December 31, 2002 and are not expected to have a

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

material effect on our financial statements. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002 and have been adopted.

In December 2002, the FASB issued Statement of Financial Accounting Standards No. 148, "Accounting for Stock-Based Compensation—Transition and Disclosure, an amendment of FASB Statement No. 123" ("SFAS 148"). SFAS 148 amends FASB Statement No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of Statement No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002 and are included in the notes to our consolidated financial statements.

In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities, an interpretation of ARB No. 51" ("FIN 46"). FIN 46 addresses the consolidation by business enterprises of variable interest entities as defined in FIN 46. FIN 46 applies immediately to variable interests in variable interest entities created after January 31, 2003, and to variable interests in variable interest entities obtained after January 31, 2003. The application of FIN 46 is not expected to have a material effect on our financial statements. FIN 46 requires certain disclosures in financial statements issued after January 31, 2003 if it is reasonably possible that we will consolidate or disclose information about variable interest entities.

Impact of Inflation on Operations

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

This management's discussion and analysis includes discussion of financial information contained in our consolidated financial statements that are not presented in accordance with GAAP.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about Key's potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in foreign currency exchange risk, interest rates and oil and natural gas prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how Key views and manages its ongoing market risk exposures.

INTEREST RATE RISK

At December 31, 2003, Key had long-term debt and other obligations outstanding of $557.0 million. Of this amount, $540.1 million or 97% bears interest at fixed rates. The $16.8 million in capital lease obligations bears interest at an imputed rate of 4.0%. These capital lease obligations relate to scheduled payments to a third-party service provider for fleet rentals of company sedans and light trucks.

	As of December 31, 2003
	(in thousands)
6.375% Senior Notes Due 2013		150,000
8.375% Senior Notes Due 2008		276,106
14% Senior Subordinated Notes Due 2009		95,339
5% Convertible Subordinated Notes Due 2004		18,699
Capital lease obligations		16,795
Other at 8%		33

	$	556,972

FOREIGN CURRENCY RISK

During the year ended June 30, 2002, the Argentine government suspended the law tying the Argentine peso to the U.S. dollar at the conversion ratio of 1:1 and created a dual currency system in Argentina. Key's net assets of its Argentina subsidiaries are based on the U.S. dollar equivalent of such amounts measured in Argentine pesos as of December 31, 2003, December 31, 2002 and June 30, 2002. Assets and liabilities of the Argentine operations were translated to U.S. dollars at December 31, 2003, December 31, 2002 and June 30, 2002 using the applicable free market conversion ratios, of 2.9:1, 3.4:1 and 3.9:1, respectively, and will be translated at future dates using the applicable free market conversion ratio on such dates. Key's net earnings and cash flows from its Argentina subsidiaries were tied to the U.S. dollar for the fiscal year ended June 30, 2001 and are based on the U.S. dollar equivalent of such amounts measured in Argentine pesos for periods after June 30, 2001. Revenues, expenses and cash flow will be translated using the average exchange rates during the periods after June 30, 2001. For more detailed information, see the section entitled "Consolidated Financial Statements and Supplementary Data," Note 13—"Argentina Foreign Currency Translation Loss."

The change in the Argentine peso to the U.S. dollar exchange rate since June 30, 2001 has reduced stockholders' equity by $33.3 million, through a charge to other comprehensive income (loss) through December 31, 2003. The change in the Argentine peso to the U.S. dollar exchange rate from December 31, 2002 to December 31, 2003 had the effect of increasing stockholders' equity by $4.0 million, through a credit to other comprehensive income (loss) through December 31, 2003. For a further discussion regarding foreign currency losses, see the section entitled "Consolidated Financial Statements and Supplementary Data," Note 13—"Argentina Foreign Currency Translation Loss."

Key's net assets, net earnings and cash flows from its former Canadian subsidiary were based on the U.S. dollar equivalent of such amounts measured in Canadian dollars. Assets and liabilities of the Canadian operations are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues and expenses are translated using the average exchange rate during the reporting period. During 2004, we closed our Ontario, Canada operation and relocated those assets to our Michigan operation, which was subsequently divested. See the section entitled "Consolidated Financial Statements and Supplementary Data," Note 2—"Restatement of Financial Statements" for a discussion of our failure to translate our Canadian assets and results of operations.

A 10% change in the Canadian-to-U.S. Dollar exchange rate would not be material to our net assets, net earnings or cash flows. In addition, our Egypt operations were denominated in U.S. dollars.

COMMODITY PRICE RISK

We sold substantially all of our oil and natural gas properties during August 2003. As a result of the sale, we terminated our remaining oil option contracts. Prior to the sale, Key's major market risk exposure for its oil and natural gas production operations was in the pricing applicable to its oil and natural gas sales. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices for natural gas. Pricing for oil and natural gas production has been volatile and unpredictable for several years.

Prior to the sale of our oil and natural gas properties in August 2003, we periodically entered into derivative contracts to reduce our exposure to a portion of our oil and natural gas production through collar and option agreements. The purpose of the contracts was to provide a measure of stability in the volatile environment of oil and natural gas prices and to manage exposure to commodity price risk under existing sales commitments. Our risk management objective was to lock in a range of pricing for expected production volumes. This allowed us to forecast future earnings within a predictable range. We met this objective by entering into collar and option arrangements which allow for acceptable cap and floor prices.

Further, in March 2000, we sold a portion of our future oil and natural gas production to Norwest Energy Capital for $20 million in exchange for future production of oil and natural gas. Through this transaction, we reduced our exposure to commodity price risk and fluctuation by entering into option collars for this production.

As of December 31, 2003, Key had no open forward contracts. A 10% variation in the market price of oil or natural gas from their levels at December 31, 2003 would not have a material impact on our net assets, net earnings or cash flows (as derived from commodity option contracts).

The following table sets forth the future volumes by year and the weighted-average strike price of the option contracts at December 31, 2002, June 30, 2002 and June 30, 2001:

		Monthly Income			Strike Price Per Bbl/MMbtu
		Oil (Bbls)	Gas (MMbtu)		Strike Price Per Bbl/MMbtu
		Oil (Bbls)	Gas (MMbtu)	Term	Floor		Cap		Fair Value
At December 31, 2002
	Oil Put	5,000	—	Mar 2002-Feb 2003	$	22.00		—	$	—
	Oil Put	4,000	—	Mar 2003-Feb 2004	$	21.00		—	$	18,594
	Gas Put	—	75,000	Mar 2002-Feb 2003	$	3.00		—	$	—
At June 30, 2002
	Oil Put	5,000	—	Mar 2002-Feb 2003	$	22.00		—	$	5,903
	Oil Put	4,000	—	Mar 2003-Feb 2004	$	21.00		—	$	37,044
	Gas Put	—	75,000	Mar 2002-Feb 2003	$	3.00		—	$	52,010
At June 30, 2001
	Oil Collar	5,000	—	Mar 2001-Feb 2002	$	19.70	$	23.70	$	(107,413	)
	Oil Put	5,000	—	Mar 2002-Feb 2003	$	22.00		—	$	33,508
	Gas Collar	—	40,000	Mar 2001-Feb 2002	$	2.40	$	2.91	$	(169,881	)
	Gas Put	—	75,000	Mar 2002-Feb 2003	$	3.00		—	$	264,561

The strike prices for the oil collars and puts are based on the NYMEX spot price for West Texas Intermediate; the strike prices for the natural gas options are based on the Inside FERC-West Texas Waha spot price.

CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Presented herein are the consolidated financial statements of Key Energy Services, Inc. as of December 31, 2003, December 31, 2002 and June 30, 2002, and for the year ended December 31, 2003, the six months ended December 31, 2002, and the years ended June 30, 2002 and 2001. The Company has presented its December 31, 2003 consolidated balance sheet in conformance with Generally Accepted Accounting Principles ("GAAP"). The other consolidated financial statements are not presented in accordance with GAAP.

Also included is the report of KPMG LLP, independent certified public accountants, on such consolidated financial statements as of December 31, 2003, December 31, 2002 and June 30, 2002, the year ended December 31, 2003, the six months ended December 31, 2002, and the years ended June 30, 2002 and 2001.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

		Page
Consolidated Balance Sheets		F-2
Consolidated Statements of Operations		F-3
Consolidated Statements of Comprehensive Income (Loss)		F-4
Consolidated Statements of Cash Flows		F-5
Consolidated Statements of Stockholders' Equity		F-6
Notes to Consolidated Financial Statements		F-7
Independent Auditors' Report		F-109

F-1

Key Energy Services, Inc.

Consolidated Balance Sheets

		December 31, 2003			December 31, 2002 (Restated)			June 30, 2002 (Restated)
		(in thousands, except share data)
*ASSETS*
Current assets:
	Cash and cash equivalents	$	103,210		$	8,992		$	54,241
	Accounts receivable, net of allowance for doubtful accounts of $5,662, $4,439 and $3,969, at December 31, 2003 and 2002 and June 30, 2002, respectively		158,673			140,013			115,798
	Inventories		14,998			9,991			7,524
	Prepaid expenses		7,518			5,682			5,358
	Other current assets		30,903			31,236			23,622

Total current assets			315,302			195,914			206,543

Property and equipment:
	Well servicing equipment		722,866			811,228			657,628
	Contract drilling equipment		110,563			104,143			100,135
	Motor vehicles		83,676			79,688			69,555
	Oil and natural gas properties and other related equipment, successful efforts method		—			46,888			44,439
	Furniture and equipment		64,240			51,472			39,183
	Buildings and land		51,207			49,594			40,937

Total property and equipment			1,032,552			1,143,013			951,877
Accumulated depreciation and depletion			(343,475	)		(349,613	)		(302,654	)

Net property and equipment			689,077			793,400			649,223

Goodwill, net			333,729			316,541			203,075
Deferred costs, net			14,433			13,324			11,405
Notes and accounts receivable—related parties			221			351			342
Other assets			23,476			30,858			24,066

TOTAL ASSETS		$	1,376,238		$	1,350,388		$	1,094,654

*LIABILITIES AND STOCKHOLDERS' EQUITY*
Current liabilities:
	Accounts payable	$	45,478		$	30,195		$	25,299
	Other accrued liabilities		77,644			71,766			60,582
	Accrued interest		16,107			15,325			14,865
	Current portion volumetric production payment		—			4,599			4,355
	Current portion of long-term debt and capital lease obligations		24,320			7,005			7,674

Total current liabilities			163,549			128,890			112,775

Long-term debt, less current portion			521,445			472,972			421,378
Volumetric production payment ("VPP")			—			7,569			8,388
Capital lease obligations, less current portion			11,206			14,122			15,219
Deferred revenue			722			1,078			1,161
Non-current accrued expenses			48,190			38,987			21,322
Deferred tax liability			105,039			136,211			118,012
Commitments and contingencies (Note 15)			—			—			—
Stockholders' equity:
	Common stock, $0.10 par value; 200,000,000 shares authorized, 130,561,000, 128,341,000 and 109,891,000 shares issued and outstanding at December 31, 2003 and 2002 and June 30, 2002, respectively		13,098			12,876			11,031
	Additional paid-in capital		711,455			689,923			528,871
	Treasury stock, at cost; 416,666 shares at December 31, 2003 and 2002 and June 30, 2002		(9,682	)		(9,682	)		(9,682	)
	Accumulated other comprehensive loss		(36,118	)		(40,263	)		(43,645	)
	Accumulated deficit		(152,666	)		(102,295	)		(90,176	)

Total stockholders' equity			526,087			550,559			396,399

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY		$	1,376,238		$	1,350,388		$	1,094,654

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

As discussed in Note 1—“Organization and Summary of Significant Accounting Policies—Basis of Presentation," these consolidated financial statements (other than the December 31, 2003 consolidated balance sheet) are not presented in accordance with GAAP.

F-2

Key Energy Services, Inc.

Consolidated Statements of Operations

			Year Ended December 31, 2003			Six Months Ended December 31, 2002 (Restated)			Year Ended June 30, 2002 (Restated)			Year Ended June 30, 2001 (Restated)
			(in thousands, except per share data)
*REVENUES:*
	Well servicing		$	859,697		$	372,280		$	712,635		$	770,783
	Contract drilling			65,942			32,137			81,204			95,127

Total revenues				925,639			404,417			793,839			865,910

*COSTS AND EXPENSES:*
	Well servicing			621,175			262,346			500,848			518,969
	Contract drilling			48,632			22,695			56,746			66,024
	Depreciation, depletion and amortization			98,067			47,919			77,032			77,062
	Write-off and impairment of property and equipment			63,417			7,199			40,110			5,683
	Loss associated with the South Texas Matters			5,225			—			—			—
	General and administrative			103,519			51,924			64,460			62,819
	Interest expense			48,991			21,823			43,084			53,430
	Loss (gain) on early extinguishment of debt			(16	)		(18	)		4,019			1,979
	Loss (gain) on sales of assets, net			848			477			(688	)		198
	Interest income			(565	)		(208	)		(616	)		(1,123	)
	Other income, net			(82	)		(734	)		(981	)		(963	)

Total costs and expenses, net				989,211			413,423			784,014			784,078

Income (loss) from continuing operations before income taxes				(63,572	)		(9,006	)		9,825			81,832
Income tax benefit (expense)				17,955			985			(4,619	)		(36,275	)

*INCOME (LOSS) FROM CONTINUING OPERATIONS*				(45,617	)		(8,021	)		5,206			45,557

Discontinued operations including loss on sale of $5,851 during 2003, net of tax benefit of $2,763, $1,437, $631 and $616, respectively				(4,754	)		(2,472	)		(1,085	)		(997	)
Cumulative effect on prior years of a change in accounting principle, net of tax (expense) of $(944)				—			(1,625	)		—			—

*NET INCOME (LOSS)*			$	(50,371	)	$	(12,118	)	$	4,121		$	44,560

*EARNINGS PER SHARE:*
	Net income (loss) from continuing operations
		Basic	$	(0.35	)	$	(0.06	)	$	0.05		$	0.46
		Diluted	$	(0.35	)	$	(0.06	)	$	0.05		$	0.45
	Discontinued operations
		Basic	$	(0.04	)	$	(0.02	)	$	(0.01	)	$	(0.01	)
		Diluted	$	(0.04	)	$	(0.02	)	$	(0.01	)	$	(0.01	)
	Cumulative effect
		Basic	$	—		$	(0.01	)	$	—		$	—
		Diluted	$	—		$	(0.01	)	$	—		$	—
	Net income (loss)
		Basic	$	(0.39	)	$	(0.09	)	$	0.04		$	0.45
		Diluted	$	(0.39	)	$	(0.09	)	$	0.04		$	0.44
WEIGHTED AVERAGE SHARES OUTSTANDING:
	Basic			129,460			125,367			105,782			98,214
	Diluted			129,460			125,367			107,467			101,588

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

F-3

Key Energy Services, Inc.

Consolidated Statements of Comprehensive Income (Loss)

	Year Ended December 31, 2003			Six Months Ended December 31, 2002 (Restated)			Year Ended June 30, 2002 (Restated)			Year Ended June 30, 2001 (Restated)
	(in thousands)
*NET INCOME (LOSS)*	$	(50,371	)	$	(12,118	)	$	4,121		$	44,560
*OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:*
Foreign currency translation gain (loss)		4,145			3,382			(43,625	)		(104	)

*COMPREHENSIVE INCOME (LOSS), NET OF TAX*	$	(46,226	)	$	(8,736	)	$	(39,504	)	$	44,456

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

F-4

Key Energy Services, Inc.

Consolidated Statements of Cash Flows

		Year Ended December 31, 2003			Six Months Ended December 31, 2002 (Restated)			Year Ended June 30, 2002 (Restated)			Year Ended June 30, 2001 (Restated)
		(in thousands)
*CASH FLOWS FROM OPERATING ACTIVITIES:*
	Net income (loss)	$	(50,371	)	$	(12,118	)	$	4,121		$	44,560
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
	Depreciation, depletion and amortization		98,067			47,919			77,032			77,062
	Amortization of deferred debt issuance costs, discount and premium		3,113			1,505			2,938			2,348
	Deferred income tax expense (benefit)		(41,046	)		4,652			(2,170	)		22,901
	Loss (gain) on sale of assets		848			477			(688	)		198
	Loss (gain) on early extinguishment of debt		(16	)		(18	)		4,019			1,979
	Cumulative effect on prior years of a change in accounting principle		—			1,625			—			—
	Write-off and impairment of property and equipment		63,417			7,199			40,110			5,683
	Loss associated with the South Texas Matters		5,225			—			—			—
	Changes in working capital:
	Accounts receivable		(19,839	)		(24,323	)		59,244			(51,382	)
	Other current assets		1,403			(4,021	)		7,006			669
	Accounts payable, accrued interest and accrued expenses		30,322			15,775			(7,641	)		22,511
	Other assets and liabilities		42,749			636			(7,359	)		11,644
	Operating cash flows provided (used) by discontinued operations		(9,279	)		165			(604	)		(254	)

	Net cash provided by operating activities		124,593			39,473			176,008			137,919

*CASH FLOWS FROM INVESTING ACTIVITIES:*
	Capital expenditures—well servicing		(91,558	)		(12,736	)		(73,881	)		(71,967	)
	Capital expenditures—contract drilling		(228	)		—			(2,719	)		(3,763	)
	Capital expenditures—other		(6,662	)		(9,928	)		(13,096	)		(15,003	)
	Proceeds from sale of fixed assets		4,202			1,265			3,590			3,588
	Acquisitions, net of cash acquired		(7,228	)		(110,779	)		(25,454	)		(1,776	)
	Investing cash flows provided (used) by discontinued operations		17,428			(27	)		(371	)		217

	Net cash used in investing activities		(84,046	)		(132,205	)		(111,931	)		(88,704	)

*CASH FLOWS FROM FINANCING ACTIVITIES:*
	Repayment of long-term debt		(30,928	)		(431	)		(150,086	)		(58,762	)
	Net borrowings (repayments) under revolving credit facility, net of issuance costs		(54,168	)		48,974			(2,110	)		(289,948	)
	Net borrowings (repayments) under capital lease obligations		(4,393	)		(1,798	)		(135	)		1,053
	Proceeds from long-term debt, net of issuance costs		147,254			—			99,667			175,210
	Proceeds from equity offering, net of expenses		—			—			42,585			—
	Proceeds from exercise of stock options and warrants		3,402			433			3,218			15,464
	Financing cash flows used by discontinued operations		(7,900	)		—			—			—

	Net cash provided by (used in) financing activities		53,267			47,178			(6,861	)		(156,983	)

	Effect of exchange rates on cash		404			305			(5,087	)		—

	Net increase (decrease) in cash and cash equivalents		94,218			(45,249	)		52,129			(107,768	)
	Cash and cash equivalents, beginning of period		8,992			54,241			2,112			109,880

	Cash and cash equivalents, end of period	$	103,210		$	8,992		$	54,241		$	2,112

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

F-5

Key Energy Services, Inc.

Consolidated Statements of Stockholders' Equity

		Common Stock
		Common Stock										Accumulated Other Comprehensive Income
		Number of Shares Outstanding		Amount at par		Additional Paid-in Capital			Treasury Stock			Accumulated Other Comprehensive Income			Retained Earnings			Total
		(Restated, in thousands)
BALANCE AT JUNE 30, 2000 (As previously reported)		97,210		$	9,723	$	413,962		$	(9,682	)	$	8		$	(31,124	)	$	382,887

	Restatement adjustments	(417	)		—		7,132			—			76			(107,735	)		(100,527	)

BALANCE AT JUNE 30, 2000 (Restated)		96,793			9,723		421,094			(9,682	)		84			(138,859	)		282,360

	Foreign currency translation adjustment	—			—		—			—			(104	)		—			(104	)
	Exercise of warrants	185			19		828			—			—			—			847
	Exercise of options	3,106			308		14,309			—			—			—			14,617
	Conversion of 7% debentures	101			10		947			—			��			—			957
	Issuance of common stock for acquisitions	838			84		8,036			—			—			—			8,120
	Deferred tax benefit—compensation expense	—			—		6,805			—			—			—			6,805
	Other	—			—		2,321			—			—			—			2,321
	Net income (Restated)	—			—		—			—			—			44,560			44,560

BALANCE AT JUNE 30, 2001 (Restated)		101,023			10,144		454,340			(9,682	)		(20	)		(94,299	)		360,483

	Foreign currency translation adjustment	—			—		—			—			(43,625	)		—			(43,625	)
	Exercise of warrants	7			1		(1	)		—			—			—			—
	Exercise of options	659			66		3,152			—			—			—			3,218
	Issuance of common stock for acquisitions	2,801			280		24,787			—			—			—			25,067
	Issuance of common stock in equity offering, net of offering costs	5,400			540		42,050			—			—			—			42,590
	Deferred tax benefit compensation expense	—			—		847			—			—			—			847
	Other	1			—		3,696			—			—			2			3,698
	Net income (Restated)	—			—		—			—			—			4,121			4,121

BALANCE AT JUNE 30, 2002 (Restated)		109,891			11,031		528,871			(9,682	)		(43,645	)		(90,176	)		396,399

	Foreign currency translation adjustment	—			—		—			—			3,382			—			3,382
	Exercise of options	139			14		419			—			—			—			433
	Issuance of common stock for acquisitions	18,311			1,831		158,115			—			—			—			159,946
	Deferred tax benefit compensation expense	—			—		171			—			—			—			171
	Other	—			—		2,347			—			—			(1	)		2,346
	Net loss (Restated)	—			—		—			—			—			(12,118	)		(12,118	)

BALANCE AT DECEMBER 31, 2002 (Restated)		128,341			12,876		689,923			(9,682	)		(40,263	)		(102,295	)		550,559

	Foreign currency translation adjustment	—			—		—			—			4,145			—			4,145
	Exercise of options	580			58		3,343			—			—			—			3,401
	Issuance of common stock for acquisitions	1,627			163		16,541			—			—			—			16,704
	Deferred tax benefit compensation expense	—			—		482			—			—			—			482
	Other	13			1		1,166			—			—			—			1,167
	Net loss (Restated)	—			—		—			—			—			(50,371	)		(50,371	)

BALANCE AT DECEMBER 31, 2003		130,561		$	13,098	$	711,455		$	(9,682	)	$	(36,118	)	$	(152,666	)	$	526,087

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

F-6

Key Energy Services, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2003 and 2002 and June 30, 2002

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The Company

Key Energy Services, Inc. (the "Company," "Key," "we," "our" or "us") is a leading onshore, rig-based well servicing contractor. We provide a complete range of well services to major oil companies and independent oil and natural gas production companies, including rig-based well maintenance, workover, completion, and recompletion services (reentering a well to complete the well in a new geologic zone or formation); oilfield transportation services; fishing and rental services; pressure pumping services; and ancillary oilfield services. During 2003, 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 ArkLaTex and North Texas regions), Four Corners (including the San Juan, Piceance, Uinta, and Paradox Basins), Eastern (including the Appalachian and Michigan Basins), 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, Egypt and Canada (Ontario). We also provide land drilling services. During 2003, we conducted land drilling operations in a number of major domestic producing basins including the Permian Basin, the San Juan Basin, the Powder River Basin, and the Appalachian Basin, as well as internationally, in Argentina; however, we sold all of our Permian Basin and San Juan Basin contract drilling assets as well as certain drilling assets located in the Rocky Mountain region to Patterson-UTI Energy, Inc. on January 15, 2005. As of August��31, 2006, we continue to conduct limited land drilling operations domestically in the Appalachian Basin of West Virginia and the Powder River Basin of Wyoming, as well as internationally in Argentina, through the use of approximately 13 rigs.

Basis of Presentation

Our December 31, 2003 consolidated balance sheet ("2003 Balance Sheet") presents our financial condition as of that date in accordance with Generally Accepted Accounting Principles ("GAAP"). The consolidated balance sheets for the Company as of December 31, 2002, and June 30, 2002, and consolidated statements of operations, comprehensive income, cash flows and stockholders' equity for fiscal periods ended December 31, 2003, December 31, 2002, June 30, 2002 and June 30, 2001 do not present our financial condition or results of operations or cash flows for the periods presented in accordance with GAAP. The consolidated financial statements other than the 2003 Balance Sheet are not presented in accordance with GAAP because we were unable to identify and appropriately evidence the period(s) in 2003 or before in which to record certain write-offs and write-downs that were identified in the Company's restatement process. The Company wrote off fixed assets of $40.5 million that were carried on its books at December 31, 2003 but which, based on a complete physical inventory of the Company's assets, were found not to be in its possession as of December 31, 2003. The Company was unable to identify records or evidence that showed the actual period(s) in which the assets left its possession. Additionally, the Company's physical inventory identified numerous fixed assets the condition of which had changed prior to December 31, 2003, thereby necessitating adjustments to their carrying value. We were able to determine or estimate when the change in condition occurred for a significant majority of these assets and therefore the appropriate period(s) for

F-7

recording the adjustments. With respect to $10.2 million of these adjustments, the Company was unable to identify evidence to determine when the change in condition occurred. In both cases, in light of the lack of evidence to support the specific period in which the relevant charges should be recorded, the Company determined to record the charges in the fourth quarter of 2003.

Accounting Principles Board Opinion No. 20 "Accounting Changes" ("APB 20") requires that the correction of an error be made through a restatement of the financial statements for the period in which the error occurred. There is no accounting guidance for the situation where a company lacks sufficient records to determine, or support a determination of, the period in which an error occurred. Because the Company is unable to identify and appropriately evidence the period(s) in which the errors related to the write-offs and write-downs for unlocated assets and some changes in condition in of assets may have occurred, it cannot conclude that recording the charges in the fourth quarter of 2003 is consistent with APB 20. Therefore, the consolidated statements of operations, comprehensive income, cash flows and stockholders' equity for 2003 are not presented in accordance with GAAP. For the same reasons, the inability of the Company to identify the appropriate prior period(s) for these charges means that the financial statements for periods prior to December 31, 2003 also are not presented in accordance with GAAP. The 2003 Balance Sheet reflects the cumulative effect of all adjustments to the Company's financial statements to correct errors in previously reported financial statements that were identified during the course of the Company's restatement process. This includes the write-offs for unlocated assets and write-downs for changes in condition described above. Our inability to determine the appropriate timing of these charges precludes us from presenting the statements other than the 2003 Balance Sheet in accordance with GAAP. However, because these charges occurred prior to December 31, 2003, our balance sheet as of that date is inclusive of all charges and is therefore presented in accordance with GAAP. For a further discussion of these items, please see Note 2—"Restatement of Financial Statements," and Note 4—"Property and Equipment."

The presentation of these charges for unlocated assets and changes in condition affects other items in the relevant financial statements and related disclosures. Accounting for one or more material items in a manner other than in accordance with GAAP means that the entire financial statement is deemed not to be presented in accordance with GAAP.

The preparation of these consolidated financial statements requires us to develop estimates and to make assumptions that affect our results of operation and statement of financial position. These estimates also impact the nature and extent of our disclosure, if any, of contingent liabilities. We use estimates to (1) analyze fixed assets for possible impairment, (2) determine depreciable lives for our assets, (3) assess future tax exposure and realization of deferred tax assets, (4) determine amounts to accrue for contingencies, (5) value tangible and intangible assets, and (6) assess workers' compensation, vehicular liability, self-insured risk accruals and other insurance reserves. Our actual results may differ materially from these estimates. We believe that our estimates are reasonable.

Within our consolidated financial statements, we include our accounts and the accounts of our majority-owned or controlled subsidiaries and any proportionate share of assets, liabilities, revenues and expenses for oil and gas assets in which we have an interest, which ceased upon the divestiture of OEI. We eliminate intercompany accounts and transactions. Certain reclassifications have been made to prior-period amounts to conform with current-period financial statement classifications. We account for our interest in entities for which we do not have significant control or influence under the cost method.

F-8

Restatement of Financial Statements

In October 2006, we completed the restatement process which is more fully described in Note 2—"Restatement of Financial Statements." This process resulted in the restatement of our historical financial statements for the six months ended December 31, 2002 and all applicable prior year-end periods. We have not amended and do not intend to amend our previously-filed Annual Reports on Form 10-K or our Quarterly Reports on Form 10-Q for the periods affected by the restatement that ended prior to and including September 30, 2003 as these comparable restated results are reflected in Note 20—"Unaudited Supplementary Information—Results of Operations." Consequently, no reliance should be placed on historical information contained in those prior filings.

Revenue Recognition

Well Servicing Rigs. Well servicing revenue consists primarily of maintenance services, workover services, completion services and plugging and abandonment services. We recognize revenue when services are performed, collection of the relevant receivable is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Primarily, we price well servicing rig services by the hour of service performed. Depending on the type of job, we may charge by the project or by the day.

Oilfield Transportation. Oilfield transportation revenue consists primarily of fluid and equipment transportation services and frac tanks which are used in conjunction with fluid hauling services. We recognize revenue when services are performed, collection of the relevant receivable is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Primarily, we price oilfield trucking services by the hour or by the quantities hauled.

Pressure Pumping and Fishing and Rental Services. We recognize revenue when services are performed, collection of the relevant receivable is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Generally, we price fishing and rental tool services by the day and the pressure pumping services by the job.

Ancillary Oilfield Services. Ancillary oilfield services include services such as wireline operations, wellsite construction, roustabout services, foam units and air drilling services. We recognize revenue when services are performed, collection of the relevant receivable is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. We price ancillary oilfield services by the hour, day or project depending on the type of services performed.

Contract Drilling. We recognize revenue when services are performed, collection of the relevant receivable is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. Contract drilling services are primarily provided under standard day rate, and, to a lesser extent, footage contracts. We recognize revenues on day rate contracts as earned daily. The percentage of completion method of accounting is followed for footage contracts. Under this method, revenues are recognized over the time it takes to drill the well based on the footage completed. For the years ended December 31, 2003; June 30, 2002; June 30, 2001 and the six-months ended December 31, 2002, our revenue recognized under percentage of completion totaled $0.3 million, $0.1 million, $0.1 million and $0.3 million, respectively, for our contract drilling assets in the Permian Basin.

F-9

Cash and Cash Equivalents

We consider short-term investments with an original maturity of less than three months to be cash equivalents. None of our cash is restricted and we have not entered into any compensating balance arrangements. However, at December 31, 2003, all of our obligations under the Existing Senior Credit Facility (hereinafter defined) were secured by most of our assets, including assets held by our subsidiaries, which includes cash, among other assets. We restrict investment of cash to financial institutions with high credit standing and limit the amount of credit exposure to any one financial institution.

Allowance for Doubtful Accounts

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. 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 balance. We regularly review collectiblity and establish or adjust our allowance as necessary using the specific identification method.

Inventories

Inventories, which consist primarily of oilfield service parts 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 and depletion. Depreciation is provided for oilfield service and related equipment, excluding our drilling rigs, using the straight-line method, over the following estimated depreciable lives of the assets:

Description		Years
Well service rigs and components		3 - 17
Oilfield trucks, trailers and related equipment		7 - 15
Motor vehicles		3 - 5
Fishing and rental tools		4 - 10
Disposal wells		15 - 30
Furniture and equipment		3 - 7
Buildings and improvements		15 - 30

The modified units-of-production method is used to depreciate our drilling rigs. This method takes into consideration the number of days the rigs are actually in service each month, and depreciation is recorded for at least 15 days each month for each rig that is available for service. Key defines a rig available for service as an active rig that has a crew and is ready to work. Although some well service rigs have the ability to drill shallow wells, their main function is servicing wells. Key applies the straight-line method to depreciate these rigs. Certain rigs are able to perform drilling and well service activities and are road-ready and self-propelled. These rigs, as they are generally utilized on a regular

F-10

basis to perform either well service or drilling activity, are depreciated on a straight-line basis as a well service rig.

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 fair value approximates 10% of a rig's acquisition cost. When a rig 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.

See Note 2—"Restatement of Financial Statements" for a discussion of the review of our depreciable lives during the restatement process.

Asset Retirement Obligations. In accordance with Statement of Financial Accounting Standards 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. Properties used in our oil and natural gas operations (prior to August 2003) and salt water disposal facilities used in connection with certain of our well servicing operations are subject to future costs associated with the abandonment of these properties. Significant judgment is involved in estimating future cash flows associated with such obligations, as well as the ultimate timing of the 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.

Adoption of SFAS 143 was required for all companies with fiscal years beginning after June 15, 2002. On July 1, 2002, we adopted SFAS 143 and we recorded assets, net of accumulated depreciation, of $4.3 million and a non-current liability of $9.3 million, resulting in a charge of $5.0 million for the cumulative effect on prior years for depreciation of the additional costs and accretion expense on the liability related to expected abandonment costs of our oil and natural gas producing properties and salt water disposal wells. In July 2002, through the acquisition of Q Services Inc. ("QSI"), we recorded asset retirement obligations and a corresponding long-lived asset totaling $2.1 million. Annual amortization of the assets associated with the asset retirement obligations was $0.5 million and

F-11

$0.3 million for the year ended December 31, 2003 and the six months ended December 31, 2002, respectively. A summary of changes in our asset retirement obligations is as follows (in millions):

		(Restated)
Balance at July 1, 2002		$	9.3

	Accretion expense		0.3
	Acquisition of QSI		2.1
	Other		—

Balance at December 31, 2002		$	11.7

	Accretion expense		0.5
	Sale of OEI		(3.4	)
	Other(1)		0.3

Balance at December 31, 2003		$	9.1

(1): During the six months ended December 31, 2002 and year ended December 31, 2003, the Company purchased and sold various immaterial saltwater disposal wells ("SWDs") and recorded asset retirement obligations relating to these properties.

The following pro forma financial information has been prepared to give effect to the adoption of SFAS 143 for the years ended June 30, 2002 and June 30, 2001 as if it had been adopted July 1, 2000 (in millions, except per share amounts):

		June 30, 2002 (Restated)			June 30, 2001 (Restated)
Income from continuing operations—as reported		$	5.2		$	45.6
	Pro forma adjustments to reflect retroactive adoption of SFAS 143		(0.6	)		(0.6	)

Income from continuing operations—pro forma			4.6			45.0

Income before cumulative effect of change in accounting principles—as reported			4.1			44.6
	Pro forma adjustments to reflect retroactive adoption of SFAS 143		(0.9	)		(3.1	)

Income (loss) before cumulative effect of change in accounting principles—pro forma			3.2			41.5

Net income—as reported			4.1			44.6
	Pro forma adjustments to reflect retroactive adoption of SFAS 143		(0.9	)		(4.6	)

Net income (loss)—pro forma		$	3.2		$	40.0

F-12

		June 30, 2002 (Restated)						June 30, 2001 (Restated)
		As Reported			Pro Forma			As Reported			Pro Forma
Basic earnings per share:
	Income from continuing operations	$	0.05		$	0.04		$	0.46		$	0.45
	Loss from discontinued operations		(0.01	)		(0.01	)		(0.01	)		(0.04	)
	Cumulative effect of change in accounting principle		—			—			—			(0.01	)

Basic earnings per share		$	0.04		$	0.03		$	0.45		$	0.40

Diluted earnings per share:
	Income from continuing operations	$	0.05		$	0.04		$	0.45		$	0.44
	Loss from discontinued operations		(0.01	)		(0.01	)		(0.01	)		(0.03	)
	Cumulative effect of change in accounting principle		—			—			—			(0.01	)

Diluted earnings per share		$	0.04		$	0.03		$	0.44		$	0.40

Asset and Investment Impairments. On July 1, 2002, we adopted Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). This statement requires that long-lived assets, including certain identifiable intangibles, held and used by us, 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 applying this statement, we group our long-lived assets on a division-by-division basis and 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 market conditions, such as adverse changes in the prices of oil and natural gas, which could reduce the fair value of certain fixed assets. The development of future cash flows and the determination of fair value for a division involves significant judgment and estimates. As of December 31, 2003, and 2002, June 30, 2002 and 2001, management identified a trigger event related to the errors in the performance of the impairment tests and the potential build-up in costs in excess of fair value, and performed an impairment test as of those periods. This resulted in an impairment of the Eastern Division of $19.9 million as of June 30, 2002. See Note 2— "Restatement of Financial Statements" for a more detailed discussion. Prior to July 1, 2002, we applied the provisions of FASB Statement No. 121, "Accounting for Impairment or Disposal of Long Lived Assets."

Oil and Natural Gas Properties. Prior to the sale of our oil and natural gas properties in August 2003 (see Note 7—"Discontinued Operations—Sale of Oil and Natural Gas Properties"), the successful efforts method of accounting was used for our oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs and geological and geophysical costs (if any) are expensed. Capitalized costs relating to proved properties are depleted using the units-of-production method. Due to the

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immateriality of the oil and natural gas operations in terms of revenue, net income and total assets, we do not provide disclosures on our oil and gas properties in accordance with FASB Statement No. 69, "Disclosures about Oil and Gas Producing Activities."

Gains and Losses on Extinguishment of Debt. On July 1, 2002, we adopted Statement of Financial Accounting Standards No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" ("SFAS 145"). The provisions of SFAS 145, which are currently applicable to us, rescind Statement No. 4, which required all gains and losses from extinguishment of debt to be aggregated and classified as an extraordinary item. Instead, SFAS 145 requires that such gains and losses be reported as a part of continuing operations. We now record gains and losses from the extinguishment of debt as a part of continuing operations and have reclassified such gains and losses in the financial statements for the years ended June 30, 2002 and 2001 to conform to the presentation for the year ended December 31, 2003 and the six months ended December 31, 2002.

Deferred Costs

We capitalized a total of $4.9 million, $3.0 million, $1.9 million and $5.0 million in fees and costs in connection with our various financings during the year ended December 31, 2003, the six months ended December 31, 2002 and the years ended June 30, 2002 and 2001, respectively. Deferred costs are amortized to interest expense using the effective interest method over the life of each applicable debt instrument or to gain (loss) on early extinguishment of debt. Amortization of deferred costs totaled $3.0 million, $1.5 million, $2.4 million and $1.3 million for the year ended December 31, 2003, the six months ended December 31, 2002 and the years ended June 30, 2002 and 2001, respectively. Unamortized debt issuance costs written off and included in the determination of the gain (loss) on the early extinguishment of debt for the years ended December 31, 2003, June 30, 2002 and 2001, totaled $0.2 million, $3.8 million and $5.2 million, respectively. For the six months ended December 31, 2002, there was no unamortized debt issue cost included in the determination of gain (loss) on the early extinguishment of debt.

			December 31, 2003			December 31, 2002 (Restated)			June 30, 2002 (Restated)
			(in thousands)
Deferred Costs
	Gross carrying value		$	40,307		$	35,976		$	32,576
	Accumulated amortization			(25,874	)		(22,652	)		(21,171	)

		Net carrying value	$	14,433		$	13,324		$	11,405

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 adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142") on July 1, 2001. SFAS 142 eliminates amortization for goodwill and other intangible assets with indefinite lives. Intangible assets with lives

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restricted by contractual, legal, or other means will continue to be amortized over their expected useful lives. Goodwill and other intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. 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 completed our assessment of goodwill impairment as of the date of adoption during the three months ended December 31, 2001, as allowed by SFAS 142, and conducted subsequent annual impairment assessments, the most recent as of December 31, 2003. The assessments did not result in an indication of goodwill impairment as of either date.

Prior to July 1, 2001, goodwill was amortized on a straight-line basis over periods ranging from ten to 25 years. For goodwill that could be included with the potential carrying value of long-lived assets, the test for recoverability and possible impairment would include the carrying value of the asset and identified goodwill, according to the provisions of Statement of Financial Accounting Standard No. 121, "Accounting for Impairment or Disposal of Long Lived Assets" ("SFAS 121").

We have identified our reporting units to be well servicing and contract drilling. The change in the carrying amount of goodwill for the year ended December 31, 2003, the six months ended December 31, 2002 and the year ended June 30, 2002 was $17.2 million, $113.5 million and $11.2 million, respectively. For the year ended December 31, 2003 and the six months ended December 31, 2002, the change in the carrying amount of goodwill was primarily due to the acquisition of QSI (see Note 5—"Business and Property Acquisitions") and, to a lesser extent, the foreign currency translation adjustments for our Argentine operations. For the year ended June 30, 2002, the change in the carrying amount of goodwill relates principally to goodwill from well servicing assets acquired during each period and translation adjustments for Argentina.

Intangible assets subject to amortization under SFAS 142 consist of noncompete agreements and patents and trademarks. Amortization expense for the noncompete agreements is calculated using the straight-line method over the period of the agreement, ranging from three to seven years. The cost and accumulated amortization are retired when the noncompete agreement is fully amortized and no longer enforceable. Amortization expense for patents and trademarks is calculated using the straight-line method over the useful life of the patent or trademark, ranging from five to seven years. We first acquired patents on July 16, 2002. Amortization expense for noncompete agreements for the next five succeeding years is estimated to be $3.3 million, $2.7 million, $2.2 million, $1.1 million and $0.4 million, respectively. Amortization expense for patents and trademarks is estimated to be $0.4 million for each of the next succeeding four years and $0.3 million in the fifth succeeding year. The weighted average

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amortization periods of our noncompete agreements and patents and trademarks are three years and five years, respectively.

			December 31, 2003			December 31, 2002 (Restated)			June 30, 2002 (Restated)
			(in thousands)
Goodwill
	Well servicing segment, net carrying value(1)		$	319,439		$	302,274		$	188,828
	Contract drilling segment, net carrying value(1)			14,290			14,267			14,247

		Net carrying value	$	333,729		$	316,541		$	203,075

Noncompete agreements
	Gross carrying value		$	15,524		$	18,669		$	11,730
	Accumulated amortization			(5,847	)		(7,366	)		(6,017	)

		Net carrying value	$	9,677		$	11,303		$	5,713

Patents and trademarks
	Gross carrying value		$	2,513		$	2,380		$	—
	Accumulated amortization			(546	)		(156	)		—

		Net carrying value	$	1,967		$	2,224		$	—

(1): Effective July 1, 2001, we adopted SFAS 142 and ceased depreciation for goodwill and other intangible assets with indefinite lives. Net carrying values reflected cumulative amortization prior to the adoption of this statement and cumulative amortization as of the balance sheet date for our non-compete agreements.

		Year Ended December 31, 2003		Six Months Ended December 31, 2002 (Restated)		Year Ended June 30, 2002 (Restated)		Year Ended June 30, 2001 (Restated)
		(in thousands)
Amortization expense
	Noncompete agreements	$	4,207	$	2,204	$	1,948	$	1,648
	Patents and trademarks		390		156		—		—

	Total intangible asset amortization expense	$	4,597	$	2,360	$	1,948	$	1,648

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The effects of the adoption of SFAS 142 on net income and earnings per share for the year ended June 30, 2001 is as follows:

	Year Ended June 30, 2001 (Restated)
	(in thousands, except per share data)
Reported net income	$	44,560
Add back: goodwill amortization		8,902

Adjusted net income	$	53,462

Basic Earnings Per Share:
Reported net income	$	0.45
Add back: goodwill amortization		0.09

Adjusted net income	$	0.54

Diluted Earnings Per Share:
Reported net income	$	0.44
Add back: goodwill amortization		0.09

Adjusted net income	$	0.53

Hedging and Derivative Financial Instruments

Prior to the sale of our oil and natural gas properties in August 2003 (see Note 7—"Discontinued Operations—Sale of Oil and Natural Gas Properties" and Note 12—"Derivative Financial Instruments"), we used derivative financial instruments, primarily commodity option contracts, to reduce our exposure to changes in the market price of natural gas and crude oil and to fix the price for natural gas and crude oil independently of the physical sale. As of December 31, 2003, there were no open forward sale or derivative contracts. See Note 2—"Restatement of Financial Statements" for a discussion of the accounting treatment of the derivative agreements related to our oil and natural gas properties.

To account for a financial instrument as a hedge, the contract must meet the following criteria: the underlying asset or liability must expose us to price risk that is not offset in another asset or liability, the hedging contract must reduce that price 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 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 will be offset by the effect of price rate changes on the exposed items.

Effective July 1, 2000, we adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") as amended by Statement of Financial Accounting Standards No. 137 and No. 138 ("SFAS 138"). 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 our 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. For derivatives designated as cash flow hedges, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings.

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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 that limit the pollutants we may discharge to waters or emit to air from our activities. Failure to comply with such environmental requirements or permits may result in fines and penalties, remediation orders and revocation of permits. Laws and regulations have become more stringent over the years, and in certain circumstances may impose "strict liability," rendering us liable for environmental damage without regard to negligence or fault on our part. Cleanup costs, penalties, and other damages arising as a result of environmental laws and costs associated with changes in environmental laws and regulations, could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows. From time to time, claims have been made and litigation has been brought against us under such laws. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. 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 2—"Restatement of Financial Statements" for a discussion of the change in the liability established with the acquisition of QSI.

Income Taxes

We account for income taxes based upon Statement of Financial Accounting Standards 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 Opinion No. 23, "Accounting for Income Taxes—Special Areas," that earnings from foreign entities will be reinvested indefinitely.

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Earnings Per Share

We present earnings per share information in accordance with the provisions of Statement of Financial Accounting Standards No. 128, "Earnings Per Share" ("SFAS 128"). Under SFAS 128, basic earnings per common share is determined by dividing net earnings applicable to common stock by the weighted average number of common shares actually outstanding during the year. Diluted earnings per common share is based on the increased number of shares that would be outstanding assuming conversion of dilutive outstanding convertible securities using the "as if converted" method.

		Year Ended December 31, 2003			Six Months Ended December 31, 2002 (Restated)			Year Ended June 30, 2002 (Restated)			Year Ended June 30, 2001 (Restated)
		(in thousands, except per share data)
Basic EPS Computation:
Numerator
	Income (loss) from continuing operations	$	(45,617	)	$	(8,021	)	$	5,206		$	45,557
	Discontinued operations, net of tax		(4,754	)		(2,472	)		(1,085	)		(997	)
	Cumulative effect of a change in accounting principle, net of tax		—			(1,625	)		—			—

	Net income (loss)	$	(50,371	)	$	(12,118	)	$	4,121		$	44,560

Denominator
	Weighted average common shares outstanding		129,460			125,367			105,782			98,214

Basic EPS:
	Income (loss) from continuing operations	$	(0.35	)	$	(0.06	)	$	0.05		$	0.46
	Discontinued operations, net of tax		(0.04	)		(0.02	)		(0.01	)		(0.01	)
	Cumulative effect of a change in accounting principle, net of tax		—			(0.01	)		—			—

	Net income (loss)	$	(0.39	)	$	(0.09	)	$	0.04		$	0.45

Diluted EPS Computation:
Numerator
	Income (loss) from continuing operations		(45,617	)		(8,021	)		5,206			45,557
	Discontinued operations, net of tax		(4,754	)		(2,472	)		(1,085	)		(997	)
	Convertible Securities		—			—			—			5
	Cumulative effect of a change in accounting principle, net of tax		—			(1,625	)		—			—

	Net income (loss)	$	(50,371	)	$	(12,118	)	$	4,121		$	44,565

Denominator
	Weighted average common shares outstanding		129,460			125,367			105,782			98,214
	Warrants		—			—			401			497
	Stock options		—			—			1,277			2,519
	Convertible securities		—			—			7			358

			129,460			125,367			107,467			101,588

Diluted EPS:
	Income (loss) from continuing operations	$	(0.35	)	$	(0.06	)	$	0.05		$	0.45
	Discontinued operations, net of tax		(0.04	)		(0.02	)		(0.01	)		(0.01	)
	Cumulative effect of a change in accounting principle, net of tax		—			(0.01	)		—			—

	Net income (loss)	$	(0.39	)	$	(0.09	)	$	0.04		$	0.44

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The diluted earnings per share calculation for the year ended December 31, 2003, and the six months ended December 31, 2002 excludes the effect of the potential conversion of all then-outstanding convertible debt and the potential exercise of all then-outstanding warrants and stock options, because the effects of such instruments on loss per share would be anti-dilutive. The diluted earnings per share calculation for the years ended June 30, 2002 and 2001 excludes the effect of the potential exercise of stock options in the amounts of 1,304,778 and 517,778, respectively, and the potential conversion of our 5% Convertible Subordinated Notes, because the effects of such instruments on earnings per share would be anti-dilutive.

Stock-Based Compensation

We account for stock option grants to employees using the intrinsic value method of accounting prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25"). Our stock incentive plan, which is described more fully in Note 17—"Stockholders' Equity," provides that the amount an employee must pay to exercise the option to acquire the stock should be at or above the closing market price on the trading day prior to the date of grant. In that event, the options have no intrinsic value at grant date, and in accordance with the provisions of APB 25, no compensation cost is recognized. However, in connection with the restatement process, we identified certain stock options that were granted to an individual who was not an employee of Key at the date of the grant. This resulted in us reviewing all of the options granted under the 1997 Incentive Plan. Based on this review, we determined that we had not properly accounted for certain option grants and modifications.

During this review of all options granted under the 1997 Incentive Plan, we also identified stock options that were granted at strike prices that were below the closing price of our common stock on the trading day before the grant date that was specified in the relevant documentation of the options. In addition, beginning in July 2006, we conducted a further review of the timing of stock option grants and the associated documentation for such grants. In addition to other accounting errors relating to stock options that had previously been identified during the restatement process, we concluded that there were also material accounting errors with respect to stock option grants that were evidenced by written consents of directors. We concluded that the grant dates set forth in these written consents did not reflect the dates on which the terms and recipients of the option grants were determined with finality. The timing of the execution of the consents cannot be attributed to administrative delay, and therefore the respective grant dates set forth in the consents could not be considered to be the appropriate measurement date. We estimated revised measurement dates for each stock option grant based on information now available to the Company with respect to when the terms and recipients of the option grants were determined with finality. Since we follow APB 25 to account for our stock-based compensation, we recognize the difference between the strike price and market price for "in-the-money" option grants granted to employees as compensation expense in the general and administrative expense line on our Consolidated Statements of Operations. See Note 2—"Restatement of Financial Statements."

Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation"("SFAS 123"), sets forth alternative accounting and disclosure requirements for

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stock-based compensation arrangements. Companies may continue to follow the provisions of APB 25 to measure and recognize employee stock-based compensation; however, SFAS 123 requires 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 following table illustrates the effect on net income and earnings per share if we had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation. As noted above, while we follow APB 25 to account for stock-based compensation, the stock-based employee compensation expense included in reported net income (loss) in the following table represents compensation expense for the 8,894,015 options, net of forfeitures, that were granted at strike prices ranging from $0.13 to $5.56 below the market price of our common stock on the date of grant as described above and more fully in Note 2—"Restatement of Financial Statements."

		Year Ended December 31, 2003			Six Months Ended December 31, 2002 (Restated)			Year Ended June 30, 2002 (Restated)			Year Ended June 30, 2001 (Restated)
		(in thousands, except per share data)
Net income (loss):
	As reported	$	(50,371	)	$	(12,118	)	$	4,121		$	44,560
	Add: Stock-based employee compensation expense included in reported net income (loss), net of related tax effects		428			877			1,339			759
	Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax		(7,364	)		(6,153	)		(14,004	)		(11,661	)

	Pro forma	$	(57,307	)	$	(17,394	)	$	(8,544	)	$	33,658

Basic earnings per share:
	As reported	$	(0.39	)	$	(0.09	)	$	0.04		$	0.45
	Pro forma	$	(0.44	)	$	(0.13	)	$	(0.08	)	$	0.34
Diluted earnings per share:
	As reported	$	(0.39	)	$	(0.09	)	$	0.04		$	0.44
	Pro forma	$	(0.44	)	$	(0.13	)	$	(0.08	)	$	0.32

For additional information regarding the computations presented above, see Note 2—"Restatement of Financial Statements" and Note 17—"Stockholders' Equity." The prior year changes in the "Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of tax" line above reflect the inclusion of certain stock option grants identified in the restatement that were made to non-employees and changes to the inputs for our Black-Scholes option-pricing model. Both items are more fully described in Note 2—"Restatement of Financial Statements."

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Foreign Currency Gains and Losses

The local currency is the functional currency for our foreign operations in Argentina and Canada. The U.S. dollar is the functional currency for our former operations in Egypt. 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.

Reclassifications

Certain of our property and equipment, which may be used in either well servicing or drilling and that had been previously classified as drilling, has now been reclassified as well servicing along with related operating results. The reclassification was made because the majority of the services performed by this property and equipment are well servicing in nature. As a result of the sale of our oil and natural gas properties in the second quarter of 2003, we have presented our oil and natural gas production business as discontinued operations for all periods.

Accounting Principles Adopted In This Report

SFAS 132. In December 2003, the FASB released Statement of Financial Accounting Standards No. 132 (revised 2003), "Employers' Disclosures about Pensions and Other Postretirement Benefits." The revised standard requires disclosures for pensions and other postretirement benefit plans and replaces existing pension disclosure requirements. While we adopted the new disclosure requirements as of December 31, 2003, we do not have pension or postretirement benefit plans, other than our 401(K) plan as described in Note 16—"Employee Benefit Plans."

SFAS 143. In June 2001, the FASB issued SFAS 143, which we adopted July 1, 2002. For further discussion, see Note 1—"Organization and Summary of Significant Accounting Policies—Asset Retirement Obligations."

FIN 45. In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" ("FIN 45"). As required by FIN 45, we adopted the disclosure requirements on December 31, 2002. On January 1, 2003, we adopted the initial recognition and measurement provisions for guarantees issued or modified after December 31, 2002. The adoption of the recognition and measurement provisions did not materially impact our financial statements.

EITF 04-10. We adopted the provisions under EITF Issue 04-10, "Determining Whether to Aggregate Operating Segments That Do Not Meet the Quantitative Thresholds," in our segment reporting in Note 19—"Segment Information." Several of our operating segments do not meet the quantitative thresholds as described in SFAS 131, and under this standard, we are permitted to combine information about this segment with other similar segments that individually do not meet the quantitative thresholds to produce a reportable segment of "Well Servicing," since the operating segments meet the aggregation criteria.

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Accounting Principles Not Yet Adopted In This Report

SFAS 123(R). In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123(R), "Share-Based Payment," which revises SFAS No. 123, ("SFAS 123(R)"). SFAS 123(R) is effective July 1, 2005 for all calendar year-end companies and requires companies to expense the fair value of employee stock options and other forms of stock-based compensation. This expense will be recognized over the period during which an employee is required to provide services in exchange for the award. Compensation cost for the unvested portion of awards that are outstanding as of January 1, 2006 will be recognized ratably over the remaining vesting period. The compensation cost for the unvested portion of awards will be based on the fair value at date of grant as calculated for our pro forma disclosure under SFAS 123. However, we will continue to account for any portion of awards outstanding on January 1, 2006 that were initially measured using intrinsic value method in accordance with APB 25. We will recognize compensation expense under SFAS 123(R) for new awards granted after January 1, 2006. We will use the Black-Scholes option pricing model to calculate fair value of awards granted after January 1, 2006, and we will estimate forfeitures and volatility for the calculation of compensation expense and grant date fair value. We adopted SFAS 123(R) effective January 1, 2006. The adoption of this will not materially impact our financial statements.

SFAS 148. In December 2002, the FASB issued SFAS 148, which was an amendment to SFAS 123 and provided transitional guidance for a voluntary change to the fair value based method of accounting for employee stock-based compensation expense. As noted in Note 1—"Organization and Summary of Significant Accounting Policies—Stock-Based Compensation," we continue to follow APB 25 to account for stock-based compensation until adopting SFAS 123(R) on January 1, 2006.

SFAS 149. In April 2003, the FASB issued Statement of Financial Accounting Standards No. 149, "Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities," ("SFAS 149") which clarifies and amends various issues related to derivatives and financial instruments addressed in SFAS 133 and interpretations issued by the Derivatives Implementation Group. In particular, SFAS 149: (1) clarifies when a contract with an initial net investment meets the characteristics of a derivative; (2) clarifies when a derivative contains a financing component that should be recorded as a financing transaction on the balance sheet and the statement of cash flows; (3) amends the definition of an "underlying" in SFAS 133 to conform to the language used in FIN 45; and (4) clarifies other derivative concepts. SFAS 149 is applicable to all contracts entered into or modified after June 30, 2003 and to all hedging relationships designated after June 30, 2003. While we utilized derivative financial instruments to manage commodity price risks and periodically hedged a portion of our oil and natural gas production prior to the sale of OEI in August 2003, as described in Note 12—"Derivative Financial Instruments," we have no open hedging contracts at December 31, 2003. The adoption of this standard did not materially impact our financial statements.

SFAS 150. In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity," ("SFAS 150") which establishes how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. Instruments that have an unconditional obligation requiring the issuer to redeem the instrument by transferring an asset at a specified date are required to be

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classified as liabilities on the balance sheet. Instruments that require the issuance of a variable number of equity shares by the issuer generally do not have the risks associated with equity instruments and as such should also be classified as liabilities on the balance sheet. SFAS 150 was effective for contracts in existence or created or modified for the first interim period beginning after June 15, 2003. The adoption of this standard did not materially impact our financial statements.

FIN 46R. In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51." In December 2003, the FASB issued the updated and final interpretation FIN 46R. FIN 46R requires that an equity investor in a variable interest entity have significant equity at risk (generally a minimum of 10%, which is an increase from the 3% required under previous guidance) 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 variable interest entity as the primary beneficiary. FIN No. 46R was applicable immediately to variable interest entities created or obtained after March 15, 2004. The adoption of this interpretation did not materially impact our financial statements.

FIN 47. Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations" ("FIN 47") became effective for all for fiscal years ending after December 15, 2005, which is outside the dates contained in this report, although early adoption is encouraged. This interpretation clarifies the term of conditional asset retirement obligation used in SFAS 143 and refers to a legal obligation to perform an asset retirement obligation to perform an asset retirement activity in which the timing and method of settlement are conditional on a future event that may or may not be within our control. However, our obligation to perform the asset retirement activity is unconditional, despite the uncertainties that exist. Accordingly, we are required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value can be reasonably estimated. The adoption of this will not materially impact our financial statements.

FIN No. 48. FIN No. 48, "Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement No. 109, clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements. This interpretation describes a two-step process—recognition and measurement—for evaluation of a tax position taken or expected to be taken in a tax return and also provides guidance on derecognition, classification, interest and penalties, disclosure and transition. However, FIN No. 48 does not change the classification requirements for deferred taxes or the requirement to assess the need for a valuation allowance for deferred tax assets based on the sufficiency of future taxable income. FIN No. 48 is effective for fiscal years beginning after December 15, 2006 with early application encouraged. We have not yet completed an evaluation of the financial statement impacts for the adoption of FIN No. 48.

SFAS 154. In May 2005, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 154, "Accounting Changes and Error Corrections—A Replacement of APB Opinion No. 20 and SFAS No. 3," ("SFAS 154"). SFAS 154 changes the requirements for the accounting for and reporting of a change in accounting principle and applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the

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unusual instance that the pronouncement does not include specific transition provisions. SFAS 154 requires retrospective application to prior periods' financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. While the provisions of SFAS 154 are effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005, we considered the financial effects of these provisions throughout our restatement process for the periods contained in this report.

FSP FIN No. 45-3. In November 2005, the FASB issued FASB Staff Position No. 45-3, "Application of FASB Interpretation No. 45 to Minimum Revenue Guarantees Granted to a Business or Its Owners" ("FSP FIN No. 45-3"). It served as an amendment FIN 45 by adding minimum revenue guarantees to the list of examples of contracts to which FIN 45 applies. Under FSP FIN No. 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 No. 45-3 is effective for new minimum revenue guarantees issued or modified on or after January 1, 2006. The adoption of this will not materially impact our financial statements.

2. RESTATEMENT OF FINANCIAL STATEMENTS

We identified numerous accounting issues that resulted in a restatement of our historical financial statements for 2002 and prior periods, as described below. Fiscal year 2003 is not part of the periods being restated because no financial statements covering that period were previously issued. However, many of the financial reporting issues described below also affected fiscal year 2003 and the quarterly information previously issued in our 2003 Quarterly Reports on Form 10-Q. The impact of these quarterly adjustments is presented in Note 20—"Unaudited Supplementary Information—Quarterly Results of Operations."

Our total reduction in net income for 2002 and prior years as a result of the restatement was $167.7 million. The reduction in net income reflects several matters. We recorded an aggregate net reduction in carrying value of our fixed assets in these periods of $168.6 million. The charges for fixed assets included write-downs of our fixed assets in the amount of $76.7 million and an impairment of long-lived assets of $19.9 million. Also included in the fixed asset reductions are charges for improperly capitalized costs and changes in depreciable lives and other adjustments relating to fixed assets in an aggregate amount of $72.0 million. In addition, in the course of the restatement process we identified numerous other accounting matters for which restatements were required. The aggregate reductions in income resulting from these other matters recorded for 2002 and prior periods were $45.5 million. All of these reductions (totalling $214.1 million) were partially offset by income tax benefit adjustments of $46.4 million. This Note will provide detailed explanations of the numerous changes to our financial statements. As we discuss this information, we will present the impact on our results of operations.

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Financial Impact of Restatement

The overall change to previously reported net income (loss) due to the restatement and other adjustments in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	(167,651	)	$	(7,742	)	$	(34,025	)	$	(18,150	)	$	(107,734	)

Background of the Restatement

On March 15, 2004, we announced that we had filed a notice with the SEC to extend the period in which we could file our Annual Report on Form 10-K for the year ended December 31, 2003. Subsequently, on March 29, 2004, we announced that we would not file our 2003 Annual Report on Form 10-K by the March 30, 2004 extended deadline. In connection with this announcement, we indicated that our review and analysis of certain of our idle equipment was continuing. In addition, our Audit Committee authorized a review of the South Texas Matters (see Note 3—"South Texas Matters") and an independent investigation into aspects of our disclosure controls and procedures and our internal controls structure and processes (the "Audit Committee Investigation"). We also stated that we expected write-downs would be recorded in 2003 and prior periods and, therefore, we would be restating our prior period financial statements.

While the restatement originated with the identification of issues regarding our fixed asset accounting ("Fixed Asset Restatement Matters"), in the course of the restatement process and the Audit Committee Investigation, we identified numerous other accounting matters for which restatements and adjustments were required ("Other Restatement Matters"). Beginning in July 2006, we conducted an additional review of matters related to stock option grants and determined that there were also material errors with respect to stock option grants that were evidenced by written consents of directors. In addition, during the restatement process, we identified other items that affected our 2003 financial statements. These items are included in our results for the fiscal year ended December 31, 2003.

The following sections provide additional information about the accounting issues that are encompassed within the categories of "Fixed Asset Restatement Matters" and "Other Restatement Matters," respectively.

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Fixed Asset Restatement Matters

Set forth below is a description of significant categories of Fixed Asset Restatement matters. The financial statement impact of each category is also set forth in total and by reportable period as contained in this Report.

Write-down Due to Condition or Intended Use. During the physical inventory performed in connection with the restatement process, we identified a significant portion of our stacked fleet that, based on its condition, was no longer suitable for operation, remanufacture or use as spare parts. We categorize our rigs as active, stacked and inactive. We define a stacked rig as a piece of equipment that is in the remanufacturing process, does not have assigned crews or could not be put to work without significant investment in repairs and additional equipment. Inactive rigs or equipment are those that we intend to salvage for parts, to sell or to scrap. We use these definitions for the majority of our equipment, including rigs. We determined that the remaining depreciable lives of these assets and the salvage values for these assets should have been reviewed and adjusted at the time the condition of these assets changed, due to casualty or other events.

The lack of detail in our accounting records for equipment acquired in prior years, including the inability to locate certain source documents for such assets, increased the difficulty and complexity of our fixed asset review processes as described in Note 4—"Property and Equipment." Further, with respect to all prior periods, evidence necessary to determine the exact dates that any particular asset might have gone out of service was limited. Historically, we tracked the utilization of our well servicing rigs and heavy duty trucks through detailed, equipment-specific utilization records maintained at the yard level. We concluded that these utilization records represented the best available indication of when the remaining useful life and salvage value of a well servicing rig or heavy duty truck should have been reviewed and adjusted. If we were unable to identify utilization records, we determined when the condition of the assets changed using work tickets, vehicle registration or company knowledge. We were able to identify the period in which an asset went out of service based on these records for approximately 80% of our well servicing rigs and 67% of our heavy duty trucks. If we were unable to identify the period in which the assets went out of service, we adjusted the depreciable lives in the fourth quarter of 2003. Our inability to identify and appropriately evidence a date when a change in condition may have occurred with respect to $10.2 million in fixed asset write-downs precludes us from presenting these financial statements other than the 2003 Balance Sheet in accordance with GAAP. APB 20 requires that the correction of an error be made through a restatement of the financial statements for the period in which the error occurred. Thus, we cannot conclude that recording the charges in the fourth quarter of 2003 is consistent with APB 20. Additionally, as a portion of this charge may relate to prior periods, the financial statements for these periods also are not presented in accordance with GAAP. See Note 4—"Property and Equipment."

With respect to ancillary equipment that is utilized in performing well servicing or contract drilling operations in conjunction with our primary assets of rigs and heavy duty trucks, such as light duty vehicles, trailers, pumps, and frac tanks, we determined the period to record the change in condition based upon changes in the condition of the primary assets. Utilization or other records were not maintained or available for the majority of these ancillary assets to identify a specific period to record

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the change of condition. Where such information was available it was used. For ancillary equipment where no utilization or other records were maintained, we considered the dates the primary assets went out of service from June 1999 and prior to December 2002 and determined the percentage of the total adjustment by quarter. We then applied this percentage by quarter to allocate the total adjustment to ancillary equipment across all periods. As these assets were operated in conjunction with the primary assets whose activity was tracked, we believe this allowed us to reasonably estimate the time period that these assets' condition would have changed. Adjustments allocated under this methodology totaled $20.1 million across 2002 and prior periods.

The overall change to previously reported income (loss) due to the condition or intended use of the equipment in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001 Year Ended			Prior Years
$	(76,726	)	$	(5,726	)	$	(17,584	)	$	(6,771	)	$	(46,645	)

Impairment of Long-Lived Assets and Change in Methodology. In light of the errors identified with our fixed asset accounting, we reviewed our testing for impairment of long-lived assets. For periods prior to July 1, 2002, we performed the test under SFAS 121. For all periods thereafter, we performed the impairment test using SFAS 144. Prior to the restatement, we had disclosed that the impairment tests were performed at the yard level, which, we believed at the time, represented the lowest level of identifiable cash flows. A yard is a place where our assets are located and dispatched to service customer locations. Yards are aggregated to form divisions, which are then aggregated into our operating segments. For the year ended December 31, 2003, we define our operating segments as "Well Servicing" and "Contract Drilling" as presented in Note 19—"Segment Information." These operating segments are based on the region in which they operate and, in some instances, by the services that they provide. Each division engages in similar activity and uses similar assets and resources to generate revenue, and while some assets are used for different activities, these activities can be and have been aggregated with other services that share personnel and resources and have similar, long-term financial performance and economic characteristics. In the course of the restatement process, we were unable to generate yard level balance sheet information. We therefore determined that discrete financial information that would have been necessary to perform an impairment test at the yard level did not in fact exist, and that prior impairment tests had actually involved allocations of future cash flows and fixed assets which were only identifiable at the division level. As a result, it was determined that the tests were in fact performed at a division level. Therefore, we have determined that the division is the lowest level of identifiable cash flows. Additionally, we considered the issues identified during our restatement process to be trigger events under SFAS 144 and accordingly performed an impairment test on all divisions as of December 31, 2003, 2002 and June 30, 2002 and 2001, respectively. In this test, we determined that the future cash flows for our Eastern Division, comprising well servicing and drilling operations in the Appalachian and Michigan regions, were not sufficient as of June 30, 2002 and recorded an impairment.

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The overall change to previously reported income (loss) due to the impairment of long-lived assets in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	(19,879	)	$	—		$	(19,879	)	$	—		$	—

Improperly Capitalized Costs. In addition to the physical counts of fixed assets, expenditures capitalized as part of our fixed assets were reviewed. The majority of our fixed assets were acquired through business combinations accounted for using the purchase method. Through our restatement process, we investigated entries recorded at the time of these acquisitions and reviewed the support used to assign fair values. Where we identified an error, we recorded a correcting journal entry at the date of acquisition. We additionally reviewed costs capitalized with asset purchases or cost capitalized with the internal construction of assets. In the course of this exercise, we identified an aggregate of $52.0 million in costs which were not eligible for capitalization, and recorded them to expense in the period incurred.

The overall change to previously reported income (loss) due to improperly capitalized costs in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	(51,972	)	$	(1,857	)	$	(5,713	)	$	(3,754	)	$	(40,648	)

Change in Depreciable Lives. For our rig and non-rig assets, we identified situations where the depreciable life assigned differed from our accounting policy. In those instances where we determined that the assigned useful life was in error, whether longer or shorter than prescribed by the policy, we adjusted the depreciable life to conform with the policy.

We also reviewed the depreciable lives assigned to well service rigs. Through this review, we noted that in 1998 we seperated a well service rig into two units—the core, which includes the derrick, carrier and cab, and the related components. We then assigned a 25-year life to the core component, which had been determined to be 90% of the acquisition costs of a well service rig. The resulting depreciable life of the complete well service rig was thereby extended to over 20 years. We reviewed the application of this 1998 change and identified instances where the change was not applied and made necessary corrections. We then reviewed the basis for the change in estimate and could not locate concurrent support for this change in depreciable lives of well service rigs other than those in the policies of certain peer companies. Further, management could not identify current evidence to support the assertion that 90% of the acquisition cost of a well service rig, that had been previously placed in service, had a useful life of 25 years.

As a result, through the restatement, we concluded that the change in 1998 was an error and reverted to the previous useful life of 17 years for 90% of the cost of a well service rig. This resulted in a cumulative increase in depreciation expense of $21.1 million. As a result of the reversion to the

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17-year life, the historical cost for the majority of our rigs will be fully depreciated prior to the conclusion of the remanufacturing program for our rig fleet.

We also investigated the service inception date and commencement of depreciation for our fixed assets. We reviewed additions to fixed assets, including the related invoices, and through this effort we determined that our fixed asset accounting records did not accurately reflect the proper periods that certain fixed assets (primarily remanufactured equipment) were placed in service. Based on a review of the purchasing and remanufacturing activity, we determined the period in which such fixed assets should have been placed in service. This resulted in a cumulative increase in net book value of $10.1 million as of December 31, 2002.

Thus, we determined that the depreciable lives in our fixed asset accounting records were incorrect and, in other cases, did not accurately reflect the period that fixed assets, primarily remanufactured equipment, were placed in service. We corrected our fixed asset subledger with respect to these assets, and the overall change to previously reported income (loss) due to changes in depreciable lives and in-service dates in total, for the six months, each fiscal year and prior years was as follows (in thousands).

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	(45,444	)	$	(4,019	)	$	(8,453	)	$	(8,744	)	$	(24,228	)

Excluding these occurrences, we concluded that our estimated depreciable lives were otherwise appropriate and had been properly disclosed in our prior consolidated financial statements.

Other Fixed Asset Restatement Matters. Other fixed asset restatement matters include primarily the following:

Fixed Asset Subledger Reconciliation. Through the course of the restatement, we determined that the fixed asset subledger and general ledger did not agree for the reportable periods presented in this report. In some cases, fixed asset entries were made to the general ledger that were not recorded to the subledger. Assets were recorded which were then not depreciated or subsequently added to the subledger without removal from the general ledger. For the reportable periods contained in this report, we have made adjustments to remove these balances.

Other. The adjustments to the historical cost basis of our fixed assets described above also required us to adjust depreciation, depletion and amortization expense previously recorded for those assets.

The overall change to previously reported income (loss) due to all of the foregoing other fixed asset related matters in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	25,439		$	3,882		$	9,885		$	10,267		$	1,405

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Other Restatement Matters

The restatement process surrounding our fixed assets also caused us to undertake a comprehensive re-examination of our financial statements, accounting processes and internal controls. As a result, we identified other errors in our financial statements. Accordingly, we made the adjustments described below:

Cost Deferrals and Capitalization of Certain Operating Expenses. During the course of the Audit Committee Investigation, we identified certain costs incurred by our former chief executive officer that had been deferred or capitalized in connection with some of our debt and equity issuances and acquisitions, which we concluded were not directly attributable to such transactions and should have been expensed when incurred. The costs also included expenses for a private jet used by our former chief executive officer that lacked sufficient documentation to support the deferral of such costs as part of the acquisition or offering. As a result, we reviewed all aircraft-related charges from January 1999 through August 2004 and related financing costs that had been deferred or capitalized. Based on this review, we determined that, in the aggregate, $0.7 million should have been expensed when incurred, which affects deferred financing costs, goodwill, additional paid-in capital, general and administrative and non-cash interest expense. In expensing the $0.7 million of improperly capitalized or deferred financing costs, we also reversed $0.3 million in previously recorded amortization expense, which reduced the overall net expense of this adjustment for all periods contained in this report to $0.4 million.

The overall change to previously reported income (loss) due to the improper capitalization of certain operating expenses and cost deferrals in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	(367	)	$	27		$	(124	)	$	(72	)	$	(198	)

Accrual for Environmental Remediation Costs and Related Expenses. In connection with the review of our prior purchase accounting treatment of our QSI acquisition, we determined that environmental liabilities recognized in connection with the purchase of QSI were overstated by $11.0 million. The original liability, which was recorded through purchase accounting and did not impact income, included estimates for costs to upgrade facilities, safety related expenditures, new permitting or other future costs that do not qualify as liabilities under Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies," ("SFAS 5") or Statement of Position 96-1, "Environmental Remediation Liabilities." We determined that the amount of environmental remediation liabilities that should have been recorded was $2.8 million, which affects non-current accrued environmental liabilities and goodwill in the applicable periods in 2002 and subsequent periods. We recorded this liability at its value in accordance with SFAS 5 as of the date of the financial statements and not at fair value. This adjustment to our purchase accounting did not result in any change to net income (loss). We also reviewed amounts which had been charged against the original reserve and identified an aggregate $0.1 million of costs charged against accrued environmental liabilities that should have been capitalized,

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and costs that should have been recorded as operating expenses, which were incorrectly charged against the environmental accrual. Additionally, we identified costs which we charged to expense that should have been charged against the reserve.

The overall change to previously reported income (loss) due to the improper accrual for environmental liabilities in connection with the QSI acquisition in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	(83	)	$	(83	)	$	—		$	—		$	—

Investment in Gas Trusts. We reviewed our prior accounting treatment for our investment in certain gas trusts described in Note 18—"Transactions with Related Parties—Investment in Gas Trusts." This review resulted in the determination that prior accounting for our investment in the gas trusts was incorrect, which affects the carrying value of the investment and other income in the applicable periods. We determined that the prior accounting treatment attempted to account for the investment as a cost method investment; however, the investment should have been accounted for using the equity method due to our ownership level, the nature of the entity and the significance of our influence, given that three of our directors had other involvement with the trusts. The overall change to previously reported income (loss) due to our accounting for our investment in gas trusts in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	(47	)	$	62		$	350		$	(117	)	$	(342	)

Accrual for Abandonment of Disposal Wells. We reviewed our adoption of SFAS 143 and determined that it was in error. Additional legal obligations existed that were incorrectly excluded from our prior calculation. We also identified numerous errors in our original calculation of asset retirement obligations. These errors resulted in a reduction in the cumulative effect of adopting SFAS 143 and reduced depletion and accretion expense in the applicable periods. The overall change to previously reported income (loss) due to recognition of these additional obligations that affected accrued abandonment liabilities and operating expenses in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	1,763		$	1,763		$	—		$	—		$	—

Workers' Compensation. The restatement process identified several issues related to workers' compensation. These errors related to the practices utilized to estimate and record our liability and the recording of receivables for insurance recoveries. Prior to the restatement, our estimate of the liability for workers' compensation claims contained errors in the underlying calculation and the determination

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of short- and long-term components, as well as presenting assets and liabilities on a net basis where there was no right of offset.

We had previously identified claims as being eligible for recovery from insurance providers and reduced our expense and recorded a receivable for those claims. Prior to the restatement, when it was determined that we would not recover those claims from an insurance provider we recorded reserves against those receivable balances. In the course of the restatement we determined that those claims were not eligible for recovery under our policies and have revised our calculations to eliminate the recovery and increase expense for these items. The overall change to previously reported income (loss) due to our changes in workers' compensation in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	(14,841	)	$	2,856		$	(7,330	)	$	(4,523	)	$	(5,844	)

Settlement of Claim with Workers' Compensation Insurance Provider. A claim by an insurance provider and processor for reimbursement of workers' compensation claims paid by them under our policy was reviewed. Upon further investigation, we determined that while there may have been a basis for the dispute, the liability was probable and reasonably estimable in 2000 and should have been recorded at that time. The liability was not recorded, based on the potential for offsetting claims against others, which were gain contingencies. Gain contingencies should not have been used to offset a loss contingency. The potential to negotiate a lower settlement amount was also used as a basis to not record a liability; however this would not have reduced the likely outcome in a range of outcomes to zero. We have concluded that $2.2 million, the amount of our final 2005 settlement, should have been accrued in 1999. The increase in other accrued liabilities and operating expenses changed previously reported income (loss) in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	(2,206	)	$	—		$	—		$	—		$	(2,206	)

Accrual for Vacation Pay. A review of the data previously used to record our accrued vacation pay determined that our prior methodology for calculating and recording accrued vacation liabilities and related expenses was in error. Our prior methodology did not accrue a liability as vacation was earned and was inconsistently calculated and recorded across our operating divisions. Further, we did not accrue a current liability for unearned vacation; nor did we record a decrease to this unearned component as vacation was earned with a corresponding increase to the earned vacation liability. Prior to 2001, when we developed and implemented a company-wide vacation policy, a reasonable estimate of this liability could not be made due to the lack of documented policies. As a result, we have recomputed our accrued vacation pay for each of the applicable periods beginning in 2001, when the liability could be reasonably estimated for the first time. The financial effect of this correction was to

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increase vacation expense. The overall change to previously reported income (loss) in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	(2,638	)	$	275		$	93		$	(3,006	)	$	—

Accrued Taxes, Other Than Income Taxes. Based upon the completion of audits and findings by various taxing authorities, we determined that in certain instances our accrued taxes other than income taxes (i.e., franchise taxes, property taxes, and sales and use taxes) were either computed incorrectly or erroneously considered changes in estimate. We reviewed our prior calculations of accrued taxes, other than income taxes, and determined that, in the aggregate, those accrued taxes and related expenses were understated by $3.7 million at December 31, 2002, which affects general and administrative expenses in the applicable periods. The overall change to previously reported income (loss) due to our adjustments for taxes, other than income taxes, in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	(3,658	)	$	(2,653	)	$	(216	)	$	(192	)	$	(597	)

Stock Option Grants and Modifications. Through the Audit Committee Investigation, we became aware that certain stock options had been granted to an individual who at the date of the grant of the options was not an employee or a non-employee director of Key. This resulted in a review all of the options granted under the 1997 Incentive Plan and all predecessor plans (as defined in Note 17—"Stockholders' Equity"). Based on this review, we determined that we did not properly account for the following option grants and modifications.

•: 25,000 options were granted to the individual referred to above subsequent to this individual's employment with Key. These options were subsequently exercised and the shares issued upon exercise were not covered by an effective registration statement, as required by the Securities Act of 1933.
•: 150,000 options were granted with accelerated vesting terms based on pre-determined stock price performance price triggers with no underlying vesting schedule.
•: 180,000 options were granted to individuals on dates prior to their employment by Key.
•: 479,733 options were modified to receive accelerated vesting upon the termination of the employees.
•: 321,249 options were modified to extend the exercise periods after the termination of the employees.
•: 75,000 options granted to a former employee were repriced subsequent to the date of grant.

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During the course of the foregoing review, we also identified stock options that were granted at strike prices that were below the closing market price of our common stock on the trading day before the grant date that was specified in the relevant documentation of the options. In addition, beginning in July 2006, we conducted a further review of the timing of stock option grants and the associated documentation for such grants. In addition to other accounting errors relating to stock options that had previously been identified during the restatement process, we concluded that there were also material accounting errors with respect to stock option grants that were evidenced by written consents of directors. We concluded that the grant dates set forth in these written consents did not reflect the dates on which the terms and recipients of the option grants were determined with finality. The timing of the execution of the consents cannot be attributed to administrative delay, and therefore the respective grant dates set forth in the consents could not be considered to be the appropriate measurement date. We estimated revised measurement dates for each stock option grant based on information now available to the Company with respect to when the terms and recipients of the option grants were determined with finality.

In our restated financial statements, we accounted for the 25,000 options granted to the individual who, at the date of the grant, was not an employee or a non-employee director of Key, at fair value at the date of grant. For all other options granted outside of the provisions of the 1997 Incentive Plan, we accounted for stock-based compensation under the provisions of APB 25 and computed the cost to be recognized for each of the grants intrinsically, that is, as the difference between the price of the stock on the measurement date and exercise price.

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The following summarizes the additional compensation charges resulting from errors related to stock options (in thousands, except number of options data) identified during the restatement process:

		Number of Options (net of forfeitures)	Cumulative Expense (in thousands, net of forfeitures)
Options granted to a non-employee		25,000	$	59
Options granted with accelerated vesting terms based on stock price performance triggers		150,000	$	732
Options granted prior to employment start dates		180,000	$	195
Options modified to received accelerated vesting upon termination		479,733	$	617
Options modified to extend vesting period after termination		321,249	$	2,713
Options granted to a former employee that were repriced subsequent to the date of grant		75,000	$	272
Options granted below fair value at measurement date:
	Options granted between $0.10 to $1.00 below fair value	6,912,891	$	4,169
	Options granted between $1.01 to $2.00 below fair value	149,916	$	209
	Options granted between $2.01 to $4.00 below fair value	1,111,663	$	3,536
	Options granted over $4.01 below fair value	719,545	$	3,610

Total—stock options granted below fair value		8,894,015	$	11,524

Total—all stock options		10,124,997	$	16,112

These changes also impacted additional paid-in capital for the years presented. The overall change to previously reported income (loss) due to errors related to the accounting for stock options in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	(16,112	)	$	(2,385	)	$	(3,642	)	$	(2,686	)	$	(7,399	)

Volumetric Production Payment and Associated Derivatives. We reassessed the accounting treatment for a March 2000 volumetric production payment transaction (the "VPP") and determined that the transaction did not meet the criteria set forth in Statement of Financial Accounting Standards No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies," for deferred revenue accounting. As a result, the transaction should have been recorded as a financing transaction with the proceeds received being recorded as a payable, not deferred revenue. We have corrected that error through this restatement for the periods the liability was outstanding.

We also determined that the VPP contained two embedded derivatives, one for the repayment of the initial loan amount and one for the commodity risk. We determined that the embedded derivative for commodity risk was not clearly and closely related to the underlying debt instrument. We determined that the embedded derivative for the repayment option was clearly and closely related to

F-36

the underlying debt instrument. Accordingly, we bifurcated the commodity risk embedded derivative and recorded it at fair value with changes in fair value being recorded in earnings during the periods presented. While the VPP was entered into prior to the effective date of the adoption of SFAS 133, we believe that the accounting for the VPP would have been the same prior to our adoption of SFAS 133 under the accounting required by EITF 86-28, "Accounting Implications of Indexed Debt Instruments." Therefore, there was no change in these restated financial statements for the adoption of SFAS 133 on July 1, 2000.

Additionally, we entered into separate forward derivative contracts with our counterparty in the VPP to hedge commodity price risk. We originally accounted for these contracts as hedges under Statement of Financial Accounting Standards No. 80, "Accounting for Future Contracts" ("SFAS 80") and subsequently as cash flow hedges under SFAS 133; however, we did not maintain cash flow hedge documentation to initially account for these contracts as hedges. Through the course of this restatement, we determined that these derivatives did not qualify as hedges under SFAS 80 or SFAS 133. We corrected this error by recording the derivatives at fair value with changes in fair value being recorded in earnings in our financial statements for all periods presented.

We also subsequently entered into other derivative transactions, which were also accounted for as cash flow hedges. In the course of our restatement, we determined that the cash flow hedge documentation was not adequate, and, accordingly, we determined that these derivatives also did not qualify as hedges under SFAS 80 or SFAS 133. We corrected this error by recording the derivatives at fair value with changes in fair value being recorded in earnings in our financial statements for all periods presented.

Please see Note 12—"Derivative Financial Instruments" for a more detailed description of the derivative contract agreements.

The overall change to previously reported income (loss) due to errors related to the accounting for our VPP transaction and associated derivative instruments, in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	(6,032	)	$	(1,327	)	$	(639	)	$	794		$	(4,860	)

Egypt. In May 2002, we established Misr Key Energy Services L.L.C. ("Misr") in Cairo, Egypt, to conduct commercial operations with one client, Apache Corporation ("Apache"). Operations commenced in September 2002, and the last rig completed work for Apache in July 2005. To date, most equipment has been returned to the United States.

Restatement categories relating to Egypt include the following:

•: Incomplete accounting records—Misr hired local employees to account for its operations, most of whom had limited knowledge of GAAP and the accounting system used to record transactions. Instead, Misr employees used computer spreadsheets to record certain transactions. These transactions were recorded by Key corporate accounting in Midland,

F-37

which instructed Misr to record entries using the accounting system on a go-forward basis. Nonetheless, Misr continued to use computer spreadsheets to record transactions and did not communicate with corporate accounting in Midland.

•: Improper capitalization of start-up activity costs.
•: Overpayment of corporate taxes to Egypt.
•: Other adjustments to reconcile accounting records between subledgers and the general ledger.

The overall change to previously reported income (loss) due to improper accounting for our Egyptian operations in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	(881	)	$	(952	)	$	71		$	—		$	—

Debt Issuance Costs. We previously amortized deferred financing costs using the straight line method and disclosed that we believed this was materially the same as using the effective interest method. In the course of the restatement process, we recalculated the amortization of deferred financing costs using the effective interest method and corrected amortization recorded in interest expense. In addition, we determined through this process that costs recorded as deferred financing costs were not attributed to the correct financing transaction, resulting in incorrect calculation of amortization and of gains or losses on the extinguishment of debt. The overall change to previously reported income (loss) due to errors in the amortization of capitalized deferred financing costs in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	(487	)	$	596		$	622		$	(481	)	$	(1,224	)

Other. We became aware of other matters during the restatement process which, in the aggregate through December 31, 2002, increased operating results by $0.1 million. None of these matters individually exceeded $1 million per quarter. The restated consolidated financial statements reflect these matters, and the overall change to previously reported income (loss) due to these other matters in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	108		$	(103	)	$	224		$	(464	)	$	451

Foreign Currency Translations. The restatement of our consolidated financial statements affects certain of our foreign operations that resulted in the re-calculation of the foreign currency translation. The re-calculation affects accumulated other comprehensive income, as well as the carrying value of

F-38

our foreign owned net assets. In addition, during the restatement process, we determined that we failed to translate our Canadian owned net assets and results of operations in any of the applicable periods, which reduced operating results by less than $10,000 cumulatively through December 31, 2002. This also affects accumulated other comprehensive income and the net carrying value of our Canadian assets for the applicable periods.

Restatement Items Impacting Financial Statement Presentation and Classification Only

In the course of the restatement, we determined that the financial statement presentation of the following items should be changed:

•: Other Revenues. We had previously recorded gains and losses on asset sales, interest income and other income/expense in the line "Other Revenue" on our income statement. In these restated financial statements, we have reclassified the amounts recorded in separate captions in our income statement.
•: Accounts Receivable. We determined that we had inappropriately offset credit balances against receivable balances for transactions that did not meet the criteria set forth in Financial Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts," in the Accounts Receivable line of our condensed consolidated balance sheet. As a result, we reclassified $0.7 million, $1.4 million and $1.2 million of credit balances to Accounts Payable as of June 30, 2002 and December 31, 2002 and 2003, respectively.

Restatement Items Impacting Footnote Disclosure Only

In the course of the restatement, we identified three footnotes which contained incorrect disclosures:

•: Note 11—Fair Value of Financial Instruments. We erroneously calculated the fair value of our 8.375% Senior Notes and 14% Senior Subordinated Notes. We used the carrying value of each instrument as of the balance sheet date instead of the face value of the instrument. The resulting values that were presented in the prior periods as of December 31, 2002 and June 30, 2002 and the previously filed Annual Reports on Form 10-K for these reportable periods incorrectly included premiums and discounts associated with these instruments. We have corrected these fair value calculations using the face value for all periods presented.
•: Note 12—Derivative Financial Instruments—Freestanding Derivatives. During the course of the restatement, we reviewed our derivative instruments associated with our oil and gas puts and collars and determined that fair values as disclosed in our tabular discussion for the future volumes and terms were unsupported and incorrect. We recalculated these fair values and have corrected this information currently presented in the "Fair Value" column of Note 12—"Derivative Financial Instruments—Freestanding Derivatives."
•: Note 17—Stockholders' Equity—Stock Incentive Plans. We erroneously calculated the fair value of stock options in our pro forma disclosure of net income. We also determined that due to the failure to properly administer our stock option program, we had not made proper disclosure

F-39

with respect to our options, including the number of options outstanding, as of and for the six-months and years ended December 31, 2002; June 30, 2002 and June 30, 2001 as disclosed in prior Annual Reports on Form 10-K for these reportable periods. We used the incorrect expected term and risk-free interest rate for options valuations. We have corrected the information currently presented and the pro forma financial effects in Note 1—"Organization and Summary of Significant Accounting Policies—Stock-Based Compensation."

Income Tax Adjustments

Income tax expense and related deferred income tax accounts have been recomputed for the six months ended December 31, 2002 and the applicable prior year periods to reflect the effect of the restated items. In addition, through the course of the restatement, certain errors in our previous accounting for income taxes were identified. In our prior accounting for income taxes, we had not directly and consistently provided for the effects of state income taxes and had incorrectly attributed certain excess deferred income tax liability as an appropriate liability for state income tax effects. We also attributed errors in our federal income taxes, primarily in the exclusion of meals and entertainment deductions and employee vehicle reimbursements, to this excess income tax liability. Upon identification of the underlying book and tax basis differences resulting in the excess, we made corrections for the items originally attributed to such differences. Correction of these errors, along with changes in our accounting for income taxes due to restated items, resulted in an income tax benefit of $45.9 million for all periods presented in this report and prior years.

The overall change to previously reported income (loss) due to income tax adjustments in total, for the six months, each fiscal year and prior years was as follows (in thousands):

Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years
$	46,412		$	1,902		$	18,310		$	1,599		$	24,601

F-40

The following table presents details by category, aggregating the net change to previously reported income (loss) resulting from the restatement for the applicable periods.

					Restatement Adjustments
		Total			Six Months Ended December 31, 2002			Year Ended June 30, 2002			Year Ended June 30, 2001			Prior Years⁽¹⁾
		(in thousands)
Fixed Asset Restatement Matters:
	Write down due to condition/intended use		(76,726	)		(5,726	)		(17,584	)		(6,771	)		(46,645	)
	Impairment of long lived assets		(19,879	)		—			(19,879	)		—			—
	Improperly capitalized costs		(51,972	)		(1,857	)		(5,713	)		(3,754	)		(40,648	)
	Change in depreciable lives		(45,444	)		(4,019	)		(8,453	)		(8,744	)		(24,228	)
	Other fixed assets related matters		25,439			3,882			9,885			10,267			1,405

Total Fixed Asset Restatement Matters			(168,582	)		(7,720	)		(41,744	)		(9,002	)		(110,116	)

Other Restatement Matters
	Cost deferrals and capitalization of certain operating expenses		(367	)		27			(124	)		(72	)		(198	)
	Accrual for environmental remediation costs and related expenses		(83	)		(83	)		—			—			—
	Adjustment to Investment in Gas Trusts		(47	)		62			350			(117	)		(342	)
	Accrual for abandonment of disposal wells		1,763			1,763			—			—			—
	Workers' compensation		(14,841	)		2,856			(7,330	)		(4,523	)		(5,844	)
	Settlement of claim with worker's compensation insurance provider		(2,206	)		—			—			—			(2,206	)
	Accrual for vacation pay		(2,638	)		275			93			(3,006	)		—
	Accrued taxes, other than income taxes		(3,658	)		(2,653	)		(216	)		(192	)		(597	)
	Stock option grants and modifications		(16,112	)		(2,385	)		(3,642	)		(2,686	)		(7,399	)
	Derivatives		(6,032	)		(1,327	)		(639	)		794			(4,860	)
	Egypt		(881	)		(952	)		71			—			—
	Amortization of debt issuance costs		(487	)		596			622			(481	)		(1,224	)
	Other		108			(103	)		224			(464	)		451

Total Other Restatement Matters			(45,481	)		(1,924	)		(10,591	)		(10,747	)		(22,219	)

Total adjustment to costs and expenses			(214,063	)		(9,644	)		(52,335	)		(19,749	)		(132,335	)
Income tax adjustments			46,412			1,902			18,310			1,599			24,601

Change to previously reported net income or loss		$	(167,651	)	$	(7,742	)	$	(34,025	)	$	(18,150	)	$	(107,734	)

(1): The amount in prior years relates to net adjustments in the years through June 30, 2000 which have been reflected as an adjustment to retained earnings as of June 30, 2000.

We have not amended and do not intend to amend our previously-filed Annual Report on Form 10-K or our Quarterly Reports on Form 10-Q for the periods effected by the restatement that ended prior to and including September 30, 2003.

F-41

The following tables present the financial impacts of the restatement on balance sheet line item captions for the periods presented in the accompanying consolidated financial statements.

Consolidated Balance Sheet as of December 31, 2002

		December 31, 2002
		As Previously Reported			Adjustments			As Restated
		(in thousands)
ASSETS
Current assets:
	Cash and cash equivalents	$	9,044		$	(52	)	$	8,992
	Accounts receivable, net of allowance for doubtful accounts of $4,439		141,958			(1,945	)		140,013
	Inventories		10,243			(252	)		9,991
	Prepaid expenses		5,692			(10	)		5,682
	Other current assets		8,637			22,599			31,236

Total current assets			175,574			20,340			195,914

Property and equipment:
	Well servicing equipment		935,911			(124,683	)		811,228
	Contract drilling equipment		128,199			(24,056	)		104,143
	Motor vehicles		79,110			578			79,688
	Oil and natural gas properties and other related equipment, sucessful efforts method		48,362			(1,474	)		46,888
	Furniture and equipment		51,349			123			51,472
	Buildings and land		48,922			672			49,594

Total property and equipment			1,291,853			(148,840	)		1,143,013
Accumulated depreciation and depletion			(335,348	)		(14,265	)		(349,613	)

Net property and equipment			956,505			(163,105	)		793,400

Goodwill, net			322,270			(5,729	)		316,541
Deferred costs, net			13,503			(179	)		13,324
Notes and accounts receivable—related parties			251			100			351
Other assets			33,899			(3,041	)		30,858

TOTAL ASSETS		$	1,502,002		$	(151,614	)	$	1,350,388

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable	$	28,818		$	1,377		$	30,195
	Other accrued liabilities		57,823			13,943			71,766
	Accrued interest		15,226			99			15,325
	Current portion of volumetric production payment ("VPP")		—			4,599			4,599
	Current portion of long-term debt and capital lease obligations		7,008			(3	)		7,005

Total current liabilities			108,875			20,015			128,890

Long-term debt, less current portion			472,336			636			472,972
Volumetric Production Payment			—			7,569			7,569
Capital lease obligations, less current portion			14,221			(99	)		14,122
Deferred revenue			8,460			(7,382	)		1,078
Non-current accrued expenses			40,477			(1,490	)		38,987
Deferred tax liability			145,618			(9,407	)		136,211
Commitments and contingencies (Note 15)			—			—			—
Stockholders' equity:
	Common stock, $0.10 par value; 200,000,000 shares authorized, 128,341,000 shares issued and outstanding		12,876			—			12,876
	Additional paid-in capital		673,249			16,674			689,923
	Treasury stock, at cost; 416,666 shares		(9,682	)		—			(9,682	)
	Accumulated other comprehensive loss		(29,784	)		(10,479	)		(40,263	)
	Retained earnings		65,356			(167,651	)		(102,295	)

Total stockholders' equity			712,015			(161,456	)		550,559

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY		$	1,502,002		$	(151,614	)	$	1,350,388

F-42

Consolidated Balance Sheet as of June 30, 2002

		June 30, 2002
		As Previously Reported			Adjustments			As Restated
		(in thousands)
ASSETS
Current assets:
	Cash and cash equivalents	$	54,147		$	94		$	54,241
	Accounts receivable, net of allowance for doubtful accounts of $3,969		117,907			(2,109	)		115,798
	Inventories		7,776			(252	)		7,524
	Prepaid expenses		5,613			(255	)		5,358
	Other current assets		6,630			16,992			23,622

Total current assets			192,073			14,470			206,543

Property and equipment:
	Well servicing equipment		776,271			(118,643	)		657,628
	Contract drilling equipment		124,191			(24,056	)		100,135
	Motor vehicles		68,977			578			69,555
	Oil and natural gas properties and other related equipment, sucessful efforts method		44,439			—			44,439
	Furniture and equipment		38,979			204			39,183
	Buildings and land		40,247			690			40,937

Total property and equipment			1,093,104			(141,227	)		951,877
Accumulated depreciation and depletion			(284,204	)		(18,450	)		(302,654	)

Net property and equipment			808,900			(159,677	)		649,223

Goodwill, net			201,069			2,006			203,075
Deferred costs, net			12,580			(1,175	)		11,405
Notes and accounts receivable—related parties			274			68			342
Other assets			28,099			(4,033	)		24,066

TOTAL ASSETS		$	1,242,995		$	(148,341	)	$	1,094,654

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable	$	36,915		$	(11,616	)	$	25,299
	Other accrued liabilities		37,175			23,407			60,582
	Accrued interest		14,864			1			14,865
	Current portion of volumetric production payment ("VPP")		—			4,355			4,355
	Current portion of long-term debt and capital lease obligations		7,674			—			7,674

Total current liabilities			96,628			16,147			112,775

Long-term debt, less current portion			420,717			661			421,378
Volumetric Production Payment			—			8,388			8,388
Capital lease obligations, less current portion			15,219			—			15,219
Deferred revenue			10,001			(8,840	)		1,161
Non-current accrued expenses			13,574			7,748			21,322
Deferred tax liability			133,047			(15,035	)		118,012
Commitments and contingencies (Note 15)			—			—			—
Stockholders' equity:
	Common stock, $0.10 par value; 200,000,000 shares authorized, 109,891,000 shares issued and outstanding		11,031			—			11,031
	Additional paid-in capital		514,752			14,119			528,871
	Treasury stock, at cost; 416,666 shares		(9,682	)		—			(9,682	)
	Accumulated other comprehensive loss		(32,024	)		(11,621	)		(43,645	)
	Retained earnings		69,732			(159,908	)		(90,176	)

Total stockholders' equity			553,809			(157,410	)		396,399

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY		$	1,242,995		$	(148,341	)	$	1,094,654

F-43

The following tables present the financial impacts of the restatement on income statement line item captions for the periods presented in the accompanying consolidated financial statements.

Consolidated Statements of Operations for the Six Months Ended December 31, 2002

			As Previously Reported			Adjustments			As Restated
			(in thousands, except per share data)
*REVENUES:*
	Well servicing		$	373,060		$	(780	)	$	372,280
	Contract drilling			31,443			694			32,137

Total revenues				404,503			(86	)		404,417

*COSTS AND EXPENSES:*
	Well servicing			264,324			(1,978	)		262,346
	Contract drilling			22,546			149			22,695
	Depreciation, depletion and amortization			49,974			(2,055	)		47,919
	Write-off and impairment of property and equipment			—			7,199			7,199
	General and administrative			47,759			4,165			51,924
	Interest expense			22,743			(920	)		21,823
	Gain on early extinguishment of debt			(18	)		—			(18	)
	Loss on sales of assets, net			477			—			477
	Interest income			(208	)		—			(208	)
	Other income, net			(1,300	)		566			(734	)

Total costs and expenses, net				406,297			7,126			413,423

Loss from continuing operations before income taxes				(1,794	)		(7,212	)		(9,006	)
Income tax benefit (expense)				463			522			985

*LOSS FROM CONTINUING OPERATIONS*				(1,331	)		(6,690	)		(8,021	)

Loss from discontinued operations, net of tax				(172	)		(2,300	)		(2,472	)
Cumulative effect on prior years of a change in accounting principle, net of tax				(2,873	)		1,248			(1,625	)

*NET LOSS*			$	(4,376	)	$	(7,742	)	$	(12,118	)

*EARNINGS PER SHARE:*
	Net loss from continuing operations
		Basic	$	(0.01	)	$	(0.05	)	$	(0.06	)
		Diluted	$	(0.01	)	$	(0.05	)	$	(0.06	)
	Discontinued operations
		Basic	$	—		$	(0.02	)	$	(0.02	)
		Diluted	$	—		$	(0.02	)	$	(0.02	)
	Cumulative effect
		Basic	$	(0.02	)	$	0.01		$	(0.01	)
		Diluted	$	(0.02	)	$	0.01		$	(0.01	)
	Net loss
		Basic	$	(0.03	)	$	(0.06	)	$	(0.09	)
		Diluted	$	(0.03	)	$	(0.06	)	$	(0.09	)

F-44

Consolidated Statements of Operations for the Year Ended June 30, 2002

			As Previously Reported			Adjustments			As Restated
			(in thousands, except per share data)
*REVENUES:*
	Well servicing		$	707,743		$	4,892		$	712,635
	Contract drilling			85,963			(4,759	)		81,204

Total revenues				793,706			133			793,839

*COSTS AND EXPENSES:*
	Well servicing			490,739			10,109			500,848
	Contract drilling			59,440			(2,694	)		56,746
	Depreciation, depletion and amortization			75,532			1,500			77,032
	Write-off and impairment of property and equipment			—			40,110			40,110
	General and administrative			58,841			5,619			64,460
	Interest			43,332			(248	)		43,084
	Foreign currency transaction gain, Argentina			1,443			(1,443	)		—
	Loss on early extinguishment of debt			4,812			(793	)		4,019
	Gain on sale of assets			(688	)		—			(688	)
	Interest income			(616	)		—			(616	)
	Other income			(1,028	)		47			(981	)

Total costs and expenses				731,807			52,207			784,014

Income from continuing operations before income taxes				61,899			(52,074	)		9,825
Income tax expense				(22,906	)		18,287			(4,619	)

*INCOME FROM CONTINUING OPERATIONS*				38,993			(33,787	)		5,206

Loss from discontinued operations, net of tax				(847	)		(238	)		(1,085	)

*NET INCOME*			$	38,146		$	(34,025	)	$	4,121

*EARNINGS PER SHARE:*
	Net income from continuing operations
		Basic	$	0.37		$	(0.32	)	$	0.05
		Diluted	$	0.36		$	(0.31	)	$	0.05
	Discontinued operations
		Basic	$	(0.01	)	$	—		$	(0.01	)
		Diluted	$	(0.01	)	$	—		$	(0.01	)
	Net income
		Basic	$	0.36		$	(0.32	)	$	0.04
		Diluted	$	0.35		$	(0.31	)	$	0.04

F-45

Consolidated Statements of Operations for the Year Ended June 30, 2001

			As Previously Reported			Adjustments			As Restated
			(in thousands, except per share data)
*REVENUES:*
	Well servicing		$	758,463		$	12,320		$	770,783
	Contract drilling			107,449			(12,322	)		95,127

Total revenues				865,912			(2	)		865,910

*COSTS AND EXPENSES:*
	Well servicing			500,239			18,730			518,969
	Contract drilling			77,261			(11,237	)		66,024
	Depreciation, depletion and amortization			72,658			4,404			77,062
	Write-off and impairment of property and equipment			—			5,683			5,683
	General and administrative			59,509			3,310			62,819
	Interest			56,560			(3,130	)		53,430
	Loss (gain) on early extinguishment of debt			(684	)		2,663			1,979
	Loss on sales of assets, net			198			—			198
	Interest income			(1,123	)		—			(1,123	)
	Other income, net			(963	)		—			(963	)

Total costs and expenses				763,655			20,423			784,078

Income from continuing operations before income taxes				102,257			(20,425	)		81,832
Income tax expense				(38,121	)		1,846			(36,275	)

*INCOME FROM CONTINUING OPERATIONS*				64,136			(18,579	)		45,557

Loss from discontinued operations, net of tax				(1,426	)		429			(997	)

*NET INCOME*			$	62,710		$	(18,150	)	$	44,560

*EARNINGS PER SHARE:*
	Net income from continuing operations
		Basic	$	0.65		$	(0.19	)	$	0.46
		Diluted	$	0.63		$	(0.18	)	$	0.45
	Discontinued operations
		Basic	$	(0.01	)	$	—		$	(0.01	)
		Diluted	$	(0.01	)	$	—		$	(0.01	)
	Net income
		Basic	$	0.64		$	(0.19	)	$	0.45
		Diluted	$	0.62		$	(0.18	)	$	0.44

F-46

The following tables present the financial impacts of the restatement on consolidated statements of comprehensive income (loss) line item captions for the periods presented in the accompanying consolidated financial statements.

Consolidated Statement of Comprehensive Income (Loss) for the Six-Months Ended December 31, 2002

	Six Months Ended December 31, 2002
	As Previously Reported			Adjustments			As Restated
	(in thousands)
NET LOSS	$	(4,376	)	$	(7,742	)	$	(12,118	)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Oil and natural gas derivatives adjustment		(775	)		775			—
Amortization of oil and natural gas derivatives		609			(609	)		—
Foreign currency translation gain		3,702			(320	)		3,382

COMPREHENSIVE LOSS, NET OF TAX	$	(840	)	$	(7,896	)	$	(8,736	)

F-47

Consolidated Statement of Comprehensive Income (Loss) for the Year Ended June 30, 2002

	Year ended June 30, 2002
	As Previously Reported			Adjustments			As Restated
	(in thousands)
NET INCOME	$	38,146		$	(34,025	)	$	4,121
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Oil and natural gas derivatives adjustment		(279	)		279			—
Amortization of oil and natural gas derivatives		(367	)		367			—
Foreign currency translation loss		(48,383	)		4,758			(43,625	)

COMPREHENSIVE LOSS, NET OF TAX	$	(10,883	)	$	(28,621	)	$	(39,504	)

F-48

Consolidated Statement of Comprehensive Income (Loss) for the Year Ended June 30, 2001

	Year ended June 30, 2001
	As Previously Reported			Adjustments			As Restated
	(in thousands)
NET INCOME	$	62,710		$	(18,150	)	$	44,560
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Derivative transition adjustment		(778	)		778			—
Oil and natural gas derivatives adjustment		306			(306	)		—
Amortization of oil and natural gas derivatives		558			(558	)		—
Foreign currency translation loss		(32	)		(72	)		(104	)

COMPREHENSIVE INCOME, NET OF TAX	$	62,764		$	(18,308	)	$	44,456

F-49

As to cash flow, the following reflects the effects of the restatement.

Consolidated Statements of Cash Flows for the Six Months Ended December 31, 2002

			As Previously Reported			Adjustments			As Restated
			(in thousands)
*CASH FLOWS FROM OPERATING ACTIVITIES:*
	Net loss		$	(4,376	)	$	(7,742	)	$	(12,118	)
	Adjustments to reconcile net loss to net cash provided by operating activities:
	Depreciation, depletion and amortization			51,111			(3,192	)		47,919
	Amortization of deferred debt issuance costs, discount and premium			2,154			(649	)		1,505
	Deferred income taxes			(552	)		5,204			4,652
	Loss on sale of assets			477			—			477
	Gain on early extinguishment of debt			(18	)		—			(18	)
	Cumulative effect of a change in accounting principle			2,873			(1,248	)		1,625
	Write-off and impairment of property and equipment			—			7,199			7,199
	Changes in working capital:
		Accounts receivable		(4,951	)		(19,372	)		(24,323	)
		Other current assets		7,655			(11,676	)		(4,021	)
		Accounts payable, accrued interest and accrued expenses		(3,562	)		19,337			15,775
	Other assets and liabilities			6,783			(6,147	)		636
	Operating cash flows provided by discontinued operations			—			165			165

	Net cash provided by operating activities			57,594			(18,121	)		39,473

*CASH FLOWS FROM INVESTING ACTIVITIES:*
	Capital expenditures—well servicing			(27,422	)		14,686			(12,736	)
	Capital expenditures—contract drilling			(3,894	)		3,894			—
	Capital expenditures—other			(10,180	)		252			(9,928	)
	Proceeds from sale of fixed assets			788			477			1,265
	Acquisitions, net of cash acquired			(105,365	)		(5,414	)		(110,779	)
	Investing cash flows used by discontinued operations			—			(27	)		(27	)

	Net cash used in investing activities			(146,073	)		13,868			(132,205	)

*CASH FLOWS FROM FINANCING ACTIVITIES:*
	Repayments of long-term debt			(16,413	)		15,982			(431	)
	Net borrowings under revolving credit facility, net of issuance costs			—			48,974			48,974
	Net repayments under capital lease obligations			(4,902	)		3,104			(1,798	)
	Proceeds from long-term debt, net of issuance costs			68,000			(68,000	)		—
	Proceeds paid for debt issuance costs			(3,026	)		3,026			—
	Proceeds from exercise of stock options and warrants			433			—			433

	Net cash provided by financing activities			44,092			3,086			47,178

	Effect of exchange rates on cash			(678	)		983			305

	Net decrease in cash and cash equivalents			(45,065	)		(184	)		(45,249	)

	Cash and cash equivalents at beginning of period			54,147			94			54,241

	Cash and cash equivalents at end of period		$	9,082		$	(90	)	$	8,992

F-50

Consolidated Statements of Cash Flows for the Year Ended June 30, 2002

			As Previously Reported			Adjustments			As Restated
			(in thousands)
*CASH FLOWS FROM OPERATING ACTIVITIES:*
	Net income		$	38,146		$	(34,025	)	$	4,121
	Adjustments to reconcile net income to net cash provided by operating activities:
	Depreciation, depletion and amortization			78,265			(1,233	)		77,032
	Amortization of deferred debt issuance costs, discount and premium			3,005			(67	)		2,938
	Deferred income taxes			21,385			(23,555	)		(2,170	)
	Gain on sale of assets			(668	)		(20	)		(688	)
	Foreign currency transaction loss, Argentina			1,443			(1,443	)		—
	Loss on early extinguishment of debt			4,812			(793	)		4,019
	Write-off and impairment of property and equipment			—			40,110			40,110
	Changes in working capital:
		Accounts receivable		48,907			10,337			59,244
		Other current assets		(4,410	)		11,416			7,006
		Accounts payable, accrued interest and accrued expenses		(12,180	)		4,539			(7,641	)
	Other assets and liabilities			11			(7,370	)		(7,359	)
	Operating cash flows used by discontinued operations			—			(604	)		(604	)

	Net cash provided by operating activities			178,716			(2,708	)		176,008

*CASH FLOWS FROM INVESTING ACTIVITIES:*
	Capital expenditures—well servicing			(57,857	)		(16,024	)		(73,881	)
	Capital expenditures—contract drilling			(19,861	)		17,142			(2,719	)
	Capital expenditures—other			(15,979	)		2,883			(13,096	)
	Proceeds from sale of fixed assets			4,258			(668	)		3,590
	Acquisitions, net of cash acquired			(19,310	)		(6,144	)		(25,454	)
	Investing cash flows used by discontinued operations			—			(371	)		(371	)

	Net cash used in investing activities			(108,749	)		(3,182	)		(111,931	)

*CASH FLOWS FROM FINANCING ACTIVITIES:*
	Repayments of long-term debt			(309,559	)		159,473			(150,086	)
	Net repayments on revolving credit facility, net of issuance costs			—			(2,110	)		(2,110	)
	Net repayments of capital leases			(10,182	)		10,047			(135	)
	Proceeds from equity offerings, net of expenses			42,590			(5	)		42,585
	Proceeds from long-term debt, net of issuance costs			258,500			(158,833	)		99,667
	Proceeds paid for debt issuance costs			(1,585	)		1,585			—
	Proceeds from exercise of stock options and warrants			3,219			(1	)		3,218
	Other financing			(298	)		298			—

	Net cash used in financing activities			(17,315	)		10,454			(6,861	)

	Effect of exchange rates on cash			(603	)		(4,484	)		(5,087	)

	Net increase in cash and cash equivalents			52,049			80			52,129
	Cash and cash equivalents, beginning of period			2,098			14			2,112

	Cash and cash equivalents, end of period		$	54,147		$	94		$	54,241

F-51

Consolidated Statements of Cash Flows for the Year Ended June 30, 2001

			As Previously Reported			Adjustments			As Restated
			(in thousands)
*CASH FLOWS FROM OPERATING ACTIVITIES:*
	Net income		$	62,710		$	(18,150	)	$	44,560
	Adjustments to reconcile net income to net cash provided by operating activities:
	Depreciation, depletion and amortization			75,147			1,915			77,062
	Amortization of deferred debt issuance costs, discount and premium			4,947			(2,599	)		2,348
	Deferred income taxes			34,953			(12,052	)		22,901
	Loss on sale of assets			173			25			198
	Gain (loss) on early extinguishment of debt			(684	)		2,663			1,979
	Write-off and impairment of property and equipment			—			5,683			5,683
	Changes in working capital:
		Accounts receivable		(53,813	)		2,431			(51,382	)
		Other current assets		(4,485	)		5,154			669
		Accounts payable, accrued interest and accrued expenses		29,414			(6,903	)		22,511
	Other assets and liabilities			(5,015	)		16,659			11,644
	Operating cash flows used by discontinued opertions			—			(254	)		(254	)

	Net cash provided by operating activities			143,347			(5,428	)		137,919

*CASH FLOWS FROM INVESTING ACTIVITIES:*
	Capital expenditures—well servicing			(51,064	)		(20,903	)		(71,967	)
	Capital expenditures—contract drilling			(15,884	)		12,121			(3,763	)
	Capital expenditures—other			(15,802	)		799			(15,003	)
	Proceeds from sale of fixed assets			3,415			173			3,588
	Payment of note receivable from related parties			(1,500	)		1,500			—
	Acquisitions, net of cash acquired			(3,145	)		1,369			(1,776	)
	Investing cash flows provided by discontinued opertions			—			217			217

	Net cash used in investing activities			(83,980	)		(4,724	)		(88,704	)

*CASH FLOWS FROM FINANCING ACTIVITIES:*
	Repayments of long-term debt			(373,998	)		315,236			(58,762	)
	Net repayments on revolving credit facility, net of issuance costs			—			(289,948	)		(289,948	)
	Net borrowings (repayments) of capital lease obligations			(8,542	)		9,595			1,053
	Proceeds from long-term debt, net of issuance costs			205,210			(30,000	)		175,210
	Proceeds paid for debt issuance costs			(4,958	)		4,958			—
	Proceeds from exercise of warrants and options			15,464			—			15,464
	Other			(318	)		318			—

	Net cash used in financing activities			(167,142	)		10,159			(156,983	)

	Net decrease in cash and cash equivalents			(107,775	)		7			(107,768	)
	Cash and cash equivalents, beginning of period			109,873			7			109,880

	Cash and cash equivalents, end of period		$	2,098		$	14		$	2,112

A summary of the effects of the restatement on reported amounts for the six months ended December 31, 2002, for the years ended June 30, 2002 and 2001, and for each of the quarters in those periods is presented in Note 20—"Unaudited Supplementary Information—Quarterly Results of Operations."

F-52

3. SOUTH TEXAS MATTERS

As a result of our investigation into the South Texas Matters, we determined that $4.8 million of goodwill and $0.4 million pertaining to a non-compete arrangement previously recorded in connection with an acquisition in our South Texas Division in the second quarter of 2003 (out of an aggregate purchase price of $10.4 million) should be charged to earnings as of the date of the acquisition.

4. PROPERTY AND EQUIPMENT

Physical Inventory Write-off. In light of the South Texas Matters (see Note 3—"South Texas Matters"), which raised issues with respect to our controls relating to fixed assets, we conducted a review and determined that we were also unable to generate a balance sheet for each of our yards in order to identify our fixed assets on a yard-by-yard basis. Further, in March 2004, while we were attempting to complete our 2003 consolidated financial statements, a review of reports generated by our centralized maintenance management system ("CMMS") raised questions whether certain fixed assets (primarily rigs and heavy duty trucks) were being accounted for appropriately. CMMS is an operational system installed in 2001 for tracking asset locations and condition. CMMS was upgraded in 2003 for purchasing and preventative maintenance tracking. It was and is a separate system from the fixed asset sub-ledger supporting our consolidated financial statements. Prior to the implementation of CMMS, a multitude of systems and manual processes were used. The CMMS reports reviewed in March 2004 identified certain fixed assets which were no longer in operating condition, had been retired or had been sold. This necessitated an analysis of these specific assets to determine whether the net carrying value of the assets was appropriate at December 31, 2003 or earlier and whether the depreciable life of the assets had been adjusted to reflect their physical condition, reduction in usefulness or whether these assets could even be located. Ultimately, we determined that certain data contained in CMMS was not only incorrect, but did not agree with data contained in our fixed asset ledger, which we determined also contained errors. In addition, even where the data in CMMS was determined to be accurate, we determined that the information it contained had previously not been utilized in the accounting process.

We decided that a comprehensive review of our fixed assets was necessary to determine the equipment's existence, condition or intended use, value, and remaining depreciable life, as well as other

F-53

related property asset accounting matters. Accordingly, with respect to property and equipment, the process for completing our 2003 consolidated financial statements involved, among other things:

•: Dispatch of count teams using CMMS asset listings to our domestic and international locations to physically inventory individual pieces of equipment owned by our well servicing, drilling and pressure pumping divisions to determine the equipment's existence, condition, and intended use;
•: cataloging in CMMS of the results of the on-site inspection of assets;
•: a physical inventory, on-site inspection or appraisal of the items comprising our fishing and rental equipment, which utilizes our rental tool management system or "RTMS;"
•: matching of the physically-inventoried fixed assets to the fixed asset ledger via reference to equipment identification numbers, vendor invoices, acquisition-related documentation and other relevant documentation; and
•: valuation of equipment determined to be scrapped or salvaged and intended for use in our equipment remanufacture program.

Through the course of matching physically inventoried items to the fixed asset subledger we identified certain assets currently employed in operations for which records to tie them to a corresponding entry in the subledger could not be located. In some cases, we were able to match like assets that were identified in both CMMS and the fixed asset sub-ledger, even though the records in the two systems did not specifically tie them together. This process resulted in matches for 1,362 non-rig assets and 69 rig assets, constituting $5.5 million and $5.3 million of net book value, respectively, at December 31, 2003.

Through our physical inventory counts using CMMS and RTMS, we determined that $40.5 million of equipment recorded in our financial statements could not be located. As we were unable to evidence the period in which certain of our assets left our possession, we recognized a $40.5 million charge in the fourth quarter of 2003. Our inability to identify and evidence a date when these assets left our possession and determine the appropriate timing of the charges preclude us from presenting these financial statements other than the 2003 Balance Sheet in accordance with GAAP. APB 20 requires that the correction of an error be made through a restatement of the financial statements for the period in which the error occurred. Thus, we cannot conclude that recording the charges in the fourth quarter of 2003 is consistent with APB 20. Additionally, as a portion of this charge may relate to prior periods, the financial statements for these periods also are not presented in accordance with GAAP.

Write-down Due to Condition or Intended Use. As stated in Note 2—"Restatement of Financial Statements—Fixed Asset Restatement Matters—Write-down Due to Condition or Intended Use," during the physical inventory, we identified a significant portion of our stacked fleet that, based on its condition, was no longer suitable for operation, remanufacture or use as spare parts. For rigs categorized as stacked and inactive, we determined that the remaining depreciable lives of these assets and the salvage values for these assets should have been reviewed and adjusted at the time the condition of these assets changed, due to casualty or other events.

F-54

The lack of detail in our accounting records for equipment acquired in prior years, including the inability to locate certain source documents for such assets, increased the difficulty and complexity of the processes described above. Further, for fiscal year 2003, evidence necessary to determine the exact dates that any particular asset might have gone out of service was limited. Historically, we tracked the utilization of our well servicing rigs and heavy duty trucks through detailed, equipment-specific utilization records maintained at the yard level. We concluded that these utilization records represented the best available indication of when the remaining useful life and salvage value of a well servicing rig or heavy duty truck should have been reviewed and adjusted. If we were unable to identify utilization records, we determined when the condition of the assets changed using work tickets, vehicle registration or company knowledge. For ancillary equipment used in conjunction with our primary assets, rigs and heavy duty trucks, data to indicate a date the condition of the asset changed was generally not available; therefore amounts recorded in 2003 were calculated based upon changes in primary assets. Overall, we recorded a charge of $23.0 million for the year ended December 31, 2003 related to the condition or intended use of equipment. This charge includes $10.2 million for adjustments of carrying value of equipment due to change in condition or intended use where we were unable to identify the appropriate period(s) in which to record the charge. The balance represents changes in condition of primary and ancillary assets in 2003 of $4.4 million and $8.4 million in changes for ancillary equipment calculated based on changes in primary assets. Our inability to identify and evidence a date when a change in condition occurred with respect to $10.2 million in fixed asset write- downs precludes us from presenting these financial statements other than the 2003 Balance Sheet in accordance with GAAP. APB 20 requires that the correction of an error be made through a restatement of the financial statements for the period in which the error occurred. Thus, we cannot conclude that recording the charges in the fourth quarter of 2003 is consistent with APB 20. Additionally, as a portion of this charge may relate to prior periods, the financial statements for these periods also are not presented in accordance with GAAP.

5. BUSINESS AND PROPERTY ACQUISITIONS

During the year ended December 31, 2003, the six months ended December 31, 2002 and the years ended June 30, 2002 and 2001, we completed several small acquisitions, exclusive of the acquisition of Q Services, Inc. described below, for total consideration of approximately $28 million, $16 million, $44 million and $10 million, respectively, which consisted of combinations of cash, notes payable and shares of our common stock. Other than the acquisition of QSI, none of the acquisitions completed in the foregoing periods were material individually or in the aggregate, thus the pro forma effect of these acquisitions is not presented. Each of the acquisitions was accounted for using the purchase method, and the results of the operations generated from the acquired assets are included in the Company's results of operations as of the completion date of each acquisition.

Acquisition of Q Services, Inc.

On July 19, 2002, we acquired QSI pursuant to an Agreement and Plan of Merger dated May 13, 2002, as amended, by and among us, Key Merger Sub, Inc. and QSI. As consideration for the acquisition, we issued 17.2 million shares of our common stock to the QSI shareholders and paid

F-55

$94.2 million in cash at the closing to retire debt and preferred stock of QSI and to satisfy certain other obligations of QSI. In addition to assuming the positive working capital of QSI, we incurred other direct acquisition costs and assumed certain other liabilities of QSI, resulting in Key recording an aggregate purchase price of $248.4 million.

The value of the shares issued was based on the opening price of the Company's common stock on the closing date of $8.75 per share. The number of shares issued as consideration was subject to a formula specified in the Agreement and Plan of Merger with QSI. The formula included, among other factors, the average price of our common stock for 10 days preceding the closing and the final balance sheet of QSI as of the date of closing. The results of QSI's operations have been included in the consolidated financial statements since the closing date.

The following table summarizes the restated estimated fair value of the assets acquired and liabilities assumed at the date of acquisition:

		Net Assets Acquired (Restated)
		(thousands)
Current assets		$	37,734
Property and equipment, net			139,023
Intangible assets, net			3,242
Other assets			344
Goodwill			110,860

	Total assets acquired		291,203

Current liabilities			18,597
Capital lease obligations			77
Non-current accrued expenses			6,745
Deferred tax liablity			17,424

	Total liabilities assumed		42,843

Net assets acquired		$	248,360

The $3.2 million of intangible assets consists of noncompete agreements which have a weighted-average useful life of approximately two years. The $110.9 million of goodwill was allocated to the well servicing reporting segment. Of that amount, $11.6 million is expected to be deductible for income taxes.

In the first quarter of 2003, Key engaged a third-party appraiser to perform an appraisal of Key's fishing and rental equipment acquired with QSI. The appraisal was performed using customary appraisal techniques and methods. Based on this appraisal, we changed the purchase accounting of QSI in the first quarter of 2003, which reduced fixed assets and increased goodwill by $22.0 million.

6. VOLUMETRIC PRODUCTION PAYMENT ("VPP")

In March 2000, Key sold 1,402,800 barrels of oil equivalent ("boe") of future oil and natural gas production from Odessa Exploration Incorporated ("OEI"), its wholly owned subsidiary, to Norwest Energy Capital ("Norwest") for gross proceeds of $20 million.

F-56

Under the terms of the agreement, OEI was required to deliver to Norwest either 1,402,800 boe of future oil and natural gas production in-kind or to remit to Norwest the proceeds from OEI's sale of Norwest's share of the production under OEI's existing marketing and sales contracts. The agreement conveyed production from certain specified oil and gas producing properties. Additionally, OEI received the right to repurchase the VPP through a cash payment to Norwest. This repurchase right was based upon pricing fixed at the time the agreement was entered into, plus a rate of return for Norwest and fees. Over the six-year period, estimated future production of OEI would range from 3,500 to 10,000 barrels of oil and 58,800 to 122,100 Mmbtus of natural gas per month. The total volume of the forward sale was 439,200 barrels of oil and 5.782 million Mmbtus of natural gas.

Due to the ability of OEI to settle its obligation to Norwest for cash, either through remittance of proceeds from sales or through the termination provisions allowing termination at other than fair value, the VPP does not meet the criteria set forth in Statement of Financial Accounting Standards No. 19 "Financial Accounting and Reporting by Oil and Gas Producing Companies" for accounting for the VPP as a sale of oil and gas production and allowing for treatment of the initial payment as deferred revenue. As a result, the transaction has been treated as a financing transaction with the proceeds received being recorded as a payable. See Note 2—"Restatement of Financial Statements" for a more detailed discussion of the volumetric production payment and associated derivatives.

The VPP contains two embedded derivatives for the commodity forward sale component and the repayment right. Based on our analysis of the VPP contracts, we determined that the commodity forward sale derivative was not clearly and closely related to the underlying debt and therefore bifurcated it from the debt host contract. We determined that the repayment right was clearly and closely related to the underlying debt and did not bifurcate it. The embedded instrument associated with forward commodity prices is recorded at fair value with changes in fair value being recorded in income.

To account for debt in the VPP, we first determined the fair value of the debt principal at the inception of the transaction and reduced the debt principal based on the difference between the debt principal and the cash received, which was recorded as debt discount. The debt discount has been amortized over the life of the agreement as interest expense.

For the twelve months ended December 31, 2003, six months ended December 31, 2002, and twelve months ended June 30, 2002 and June 30, 2001, we recorded $2.8 million, $1.8 million, $1.2 million and $5.4 million, respectively, of net expense relating to changes in the fair value of the commodity forward embedded in the VPP and present these effects in discontinued operations. Additionally, we recorded $0.2 million, $0.2 million, $0.4 million and $0.4 million relating to interest expense for the twelve months ended December 31, 2003; six months ended December 31, 2002, and twelve months ended June 30, 2002 and June 30, 2001, respectively, for the VPP debt discount amortization and include these expenses in discontinued operations.

Concurrently with entering into the VPP, we entered into forward price collar transactions with Norwest to reduce exposure to changes in commodity prices. These freestanding derivative instruments did not qualify as hedging arrangements. See Note 12—"Derivative Financial Instruments" for a description of our derivative transactions.

F-57

In August 2003, we sold OEI to Stallion Panhandle, LP for $19.7 million and paid $7.9 million to terminate the VPP and $4.2 million to unwind third-party hedges. We made these payments to Norwest prior to the closing of the sale of OEI.

7. DISCONTINUED OPERATIONS—SALE OF OIL AND NATURAL GAS PROPERTIES

On August 28, 2003, we sold our oil and natural gas properties for $19.7 million in cash. We received net cash proceeds of $7.5 million after repaying our volumetric production payment, unwinding related hedge arrangements with our banks and paying other related costs. As a result of the sale, our oil and natural gas production business, which was previously classified as a component of contract drilling for our segment reporting, has been presented as a discontinued operation for all periods, and we recorded an after-tax charge to discontinued operations of $4.8 million, or $0.04 per diluted share, during the year ended December 31, 2003.

Results for activities reported as discontinued operations were as follows:

	Year Ended December 31, 2003			Six Months Ended December 31, 2002 (Restated)			Year Ended June 30, 2002 (Restated)			Year Ended June 30, 2001 (Restated)
	(in thousands)
Revenues	$	5,793		$	3,695		$	8,362		$	13,009
Costs and expenses		7,459			7,604			10,078			14,622

Loss before income taxes and loss on disposal		(1,666	)		(3,909	)		(1,716	)		(1,613	)
Loss on disposal		(5,851	)		—			—			—
Income tax benefit		2,763			1,437			631			616

Loss from discontinued operations	$	(4,754	)	$	(2,472	)	$	(1,085	)	$	(997	)

Balance sheet data attributable to discontinued operations were as follows:

		December 31, 2003		December 31, 2002 (Restated)		June 30, 2002 (Restated)
		(in thousands)
Current assets		$	40	$	980	$	1,005
Property and equipment, net			—		30,890		31,304
Other assets			—		435		436

	Total assets	$	40	$	32,305	$	32,745

Current liabilities		$	316	$	6,587	$	6,098
Non-current liabilities			2,518		23,758		22,214

	Total liabilities	$	2,834	$	30,345	$	28,312

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8. OTHER CURRENT AND NON-CURRENT ACCRUED LIABILITIES

Our other current accrued liabilities consist of the following:

	December 31, 2003		December 31, 2002 (Restated)		June 30, 2002 (Restated)
	(in thousands)
Accrued payroll, taxes and employee benefits	$	28,849	$	27,102	$	24,540
Income, sales, use and other taxes		15,874		6,097		3,357
Workers' Compensation accrual		13,100		14,743		14,543
Vehicular Insurance Accrual(1)		12,288		105		55
Other		7,533		23,719		18,087

Total	$	77,644	$	71,766	$	60,582

(1): For additional detail relating to our vehicular insurance accrual balances and charges for years prior to December 31, 2003, see Note 15—"Commitments and Contingencies—Self-Insurance Reserves."

Our non-current accrued expenses consist of the following:

	December 31, 2003		December 31, 2002 (Restated)		June 30, 2002 (Restated)
Workers' compensation liability	$	29,808	$	21,310	$	19,094
Asset retirement obligations		9,084		11,749		—
Environmental liabilities		5,495		2,988		—
Other		3,803		2,940		2,228

	$	48,190	$	38,987	$	21,322

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9. INCOME TAXES

Components of income tax expense benefit (expense) are as follows:

		Year Ended December 31, 2003			Six Months Ended December 31, 2002 (Restated)			Year Ended June 30, 2002 (Restated)			Year Ended June 30, 2001 (Restated)
		(in thousands)
Current income tax (expense)
	Federal and state	$	(427	)	$	(327	)	$	(719	)	$	(276	)
	Foreign		(3,479	)		(1,292	)		(9	)		(302	)

			(3,906	)		(1,619	)		(728	)		(578	)

Deferred income tax benefit (expense)
	Federal and state		22,025			2,957			(3,954	)		(33,604	)
	Foreign		(164	)		(353	)		63			(2,093	)

			21,861			2,604			(3,891	)		(35,697	)

Income tax benefit (expense)		$	17,955		$	985		$	(4,619	)	$	(36,275	)

We made net federal income tax payments of $7,000 and $3.6 million during the year ended December 31, 2003 and the twelve months ended June 30, 2002, respectively. We received net federal income tax refunds of $6.0 million and $5.5 million for the six months ended December 31, 2002 and the twelve months ended June 30, 2001, respectively. We made net state income tax payments of approximately $0.07 million, $0.2 million, $1.5 million and $0.08 million during the year ended December 31, 2003, the six months ended December 31, 2002, and the years ended June 30, 2002 and 2001, respectively. We made foreign tax payments of approximately $1.0 million, $2,000, $0.1 million and $6,700 during the year ended December 31, 2003, the six months ended December 31, 2003, and the years ended June 30, 2002 and 2001, respectively. Additionally, deferred tax benefits of $0.5 million, $0.2 million, $0.8 million and $6.8 million have been allocated to stockholders' equity for the year ended December 31, 2003, the six months ended December 31, 2002 and the years ended June 30, 2002 and 2001, respectively, for compensation expense for income tax purposes in excess of amounts recognized for financial reporting purposes.

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

	Year Ended December 31, 2003		Six Months Ended December 31, 2002 (Restated)		Year Ended June 30, 2002 (Restated)		Year Ended June 30, 2001 (Restated)
Income tax computed at statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Amortization of goodwill disallowance	—		—		—		3.1
State taxes	1.2		(6.3	)	(36.6	)	3.8
Meals and entertainment	(2.0	)	(6.5	)	8.8		1.1
Foreign rate differential	(4.0	)	(10.0	)	1.8		0.3
Change in valuation allowance	(0.1	)	4.7		20.7		(0.3	)
Other	(1.9	)	(6.0	)	17.3		1.3

Effective income tax rate	28.2	%	10.9	%	47.0	%	44.3	%

Deferred tax assets (liabilities) are comprised of the following:

			Year Ended December 31, 2003			Six Months Ended December 31, 2002 (Restated)			Year Ended June 30, 2002 (Restated)
			(in thousands)
Deferred tax assets
	Net operating loss and tax credit carry forwards		$	53,760		$	57,604		$	43,355
	Self insurance reserves			17,965			12,973			13,454
	Allowance for bad debts			2,330			1,619			1,447
	Accrued liabilities			7,774			6,181			3,665
	Stock options			3,705			3,788			2,995
	Other			1,662			1,859			1,258

		Total deferred tax assets		87,196			84,024			66,174

		Valuation allowance for deferred tax assets		(10,555	)		(11,635	)		(11,061	)

		Net deferred tax assets		76,641			72,389			55,113

Deferred tax liabilities
	Property and equipment			148,100			176,324			143,032
	Intangibles			8,329			10,239			13,978

		Total deferred tax liabilities		156,429			186,563			157,010

Net deferred tax liability, net of valuation allowance			$	(79,788	)	$	(114,174	)	$	(101,897	)

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, we will need to generate future taxable income of approximately

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$135 million over the next ten years. 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, 2003, we will have available $133.4 million of federal net operating loss carryforwards. Net operating loss carryforwards of $45.1 million are subject to annual limitations under Sections 382 and 383 of the Internal Revenue Code and will expire from 2004 to 2021. 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, it does not appear more likely than not that we will be able to utilize all available carryforwards prior to their ultimate expiration. The remaining net operating loss carryforwards of $88.3 million will expire from 2018 to 2022.

10. SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES

	Year Ended December 31, 2003		Six Months Ended December 31, 2002 (Restated)		Year Ended June 30, 2002 (Restated)		Year Ended June 30, 2001 (Restated)
	(in thousands)
Fair value of common stock issued in purchase transactions	$	16,704	$	159,946	$	25,067	$	8,120
Fair value of non-compete liability issued in purchase transactions		2,581		7,794		4,470		950
Fair value of common stock issued upon conversion of long-term debt		—		—		—		957
Capital lease obligations		5,950		3,107		10,047		9,595

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11. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following table presents the carrying amounts and estimated fair values of our financial instruments at December 31, 2003, December 31, 2002 and June 30, 2002. FASB Statement No. 107, "Disclosures about Fair Value of Financial Instruments," 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.

			December 31, 2003				December 31, 2002				June 30, 2002
							(Restated)				(Restated)
			Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value
			(in thousands)
Financial Assets:
	Cash and cash equivalents		$	103,210	$	103,210	$	8,992	$	8,992	$	54,241	$	54,241
	Accounts receivable, net			158,673		158,673		140,013		140,013		115,798		115,798
	Notes receivable—related parties			221		221		351		351		342		342
	Commodity option contracts			—		—		34		34		246		246
Financial Liabilities:
	Accounts payable			45,478		45,478		30,195		30,195		25,299		25,299
	Volumetric Production Payment ("VPP")			—		—		12,168		12,168		12,743		12,743
	Long-term debt
		Senior Credit Facility		—		—		52,000		52,000		—		—
		6.375% Senior Notes		150,000		145,305		—		—		—		—
		8.375% Senior Notes		276,106		298,073		276,327		288,063		276,431		286,000
		14% Senior Subordinated Notes		95,338		104,325		95,049		113,344		94,921		113,100
		5% Convertible Subordinated Notes		18,699		18,699		49,554		47,324		49,951		46,942
		Capital lease obligations		16,795		16,795		21,062		21,062		22,829		22,829
		Other notes payable		33		33		107		107		140		140

The following methods and assumptions were used to estimate the fair value of each class of financial instruments:

Cash, trade receivables and trade payables. The carrying amounts approximate fair value because of the short maturity of those instruments.

Notes receivable-related parties. The amounts reported relate to notes receivable from officers of Key made in December 2001 to satisfy certain Medicare tax obligations incurred by them and notes receivable from other employees.

Commodity option contracts. Under SFAS 133, the carrying amount of the commodity option contracts approximate fair value. The fair value of the commodity option contracts is estimated using the discounted forward prices of each option's index price for the term of each option contract.

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Volumetric Production Payment ("VPP"). As more fully described in Note 2—"Restatement of Financial Statements" and Note 12—"Derivative Financial Instruments," we treated the VPP as a financing transaction with the proceeds received recorded as a payable. We determined the fair value of the debt component at the inception of the transaction, reduced principal based on production sold, and calculated interest for the transaction. As a result, we believe the carrying value, which considers the bifurcated commodity forward that is carried at fair value, approximates fair value at each balance sheet date.

Long-term debt. 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, 2003, December 31, 2002 and June 30, 2002, respectively, and the amounts outstanding under our senior credit facility.

12. DERIVATIVE FINANCIAL INSTRUMENTS

Prior to the sale of our oil and natural gas properties in August 2003, we utilized derivative financial instruments to manage commodity price risks and periodically hedged a portion of our oil and natural gas production through collar and option agreements. The purpose of the instruments was to provide a measure of stability in the volatile environment of oil and natural gas prices and to manage exposure to commodity price risk under then existing sales commitments. Our risk management objective was to lock in acceptable ranges of pricing for expected production volumes. The objective was to allow us to forecast future earnings within a predictable range. We met this objective by entering into collar and option arrangements which allowed for acceptable cap and floor prices. We have no open hedging contracts as of December 31, 2003.

We did not enter into derivative instruments for purposes other than for economic hedging, and we do not use derivative instruments to assume speculative positions. However, in connection with the restatement, we identified an embedded derivative in our volumetric production payment, which was accounted for as a financing arrangement (See Note 2—"Restatement of Financial Statements" and Note 6—"Volumetric Production Payment"). This embedded derivative was tied to future commodity prices and unrelated to the underlying debt host contract.

Freestanding Derivatives. On March 30, 2000, we entered into a collar arrangement for a 22-month period whereby we would pay if the specified price was above the cap index and the counter-party would pay if the price fell below the floor index. The instrument defined a range of cash flows bounded by the cap and floor prices. On May 25, 2001, we entered into an option arrangement for a 12-month period beginning March 2002 whereby the counter-party would pay if the price fell below the floor index. On May 2, 2002, we entered into an option arrangement for a 12-month period beginning March 2003 whereby the counter-party would pay if the price should fall below the floor index.

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The following table sets forth the future volumes hedged by year and the weighted-average strike price of the option contracts at December 31, 2002, June 30, 2002 and 2001:

		Monthly Income			Strike Price⁽¹⁾ Per Bbl/MMbtu
		Oil (Bbls)	Gas (MMbtu)		Strike Price⁽¹⁾ Per Bbl/MMbtu
		Oil (Bbls)	Gas (MMbtu)	Term	Floor		Cap		Fair Value
At December 31, 2002
	Oil Put	5,000	—	Mar 2002 - Feb 2003	$	22.00		—	$	—
	Oil Put	4,000	—	Mar 2003 - Feb 2004	$	21.00		—	$	18,594
	Gas Put	—	75,000	Mar 2002 - Feb 2003	$	3.00		—	$	—
At June 30, 2002
	Oil Put	5,000	—	Mar 2002 - Feb 2003	$	22.00		—	$	5,903
	Oil Put	4,000	—	Mar 2003 - Feb 2004	$	21.00		—	$	37,044
	Gas Put	—	75,000	Mar 2002 - Feb 2003	$	3.00		—	$	52,010
At June 30, 2001
	Oil Collar	5,000	—	Mar 2001 - Feb 2002	$	19.70	$	23.70	$	(107,413	)
	Oil Put	5,000	—	Mar 2002 - Feb 2003	$	22.00		—	$	33,508
	Gas Collar	—	40,000	Mar 2001 - Feb 2002	$	2.40	$	2.91	$	(169,881	)
	Gas Put	—	75,000	Mar 2002 - Feb 2003	$	3.00		—	$	264,561

(1): The strike prices for the oil collars and puts are based on the NYMEX spot price for West Texas Intermediate; the strike prices for the natural gas options are based on the Inside FERC-West Texas Waha spot price.

13. ARGENTINA FOREIGN CURRENCY TRANSLATION LOSS

The local currency is the functional currency for our foreign operations in Argentina and Canada. The functional currency for our Egyptian operations is the U.S. dollar. 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.

From 1991 until December 2001, the Argentine peso was tied to the U.S. dollar at a conversion ratio of 1:1. However, in December 2001, the Government of Argentina announced an exchange holiday and, as a result, Argentine pesos could not be exchanged into other currencies at December 31, 2001. On January 5 and 6, 2002, the Argentine Congress and Senate gave the President of Argentina emergency powers and the ability to suspend the law that created the fixed conversion ratio of 1:1. The Government subsequently announced the creation of a dual currency system in which certain qualifying transactions would be settled at an expected fixed conversion ratio of 1.4:1 while all other transactions would be settled using a free floating market conversion ratio. Under existing guidance, dividends would not receive the fixed conversion ratio. On January 11, 2002, the exchange holiday was lifted,

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making it possible again to buy and sell Argentine pesos. Banks were legally allowed to exchange currencies, but transactions were limited and generally took place at exchange houses. These transactions were conducted primarily by individuals as opposed to commercial transactions, and occurred at free conversion ratios ranging between 1.6:1 and 1.7:1.

Due to the events described above, which resulted in the temporary lack of exchangeability of the two currencies at December 31, 2001, we translated the assets and liabilities of our Argentine subsidiary at December 31, 2001 using a conversion ratio of 1.6:1, which management believes was indicative of the free floating conversion ratio when the currency market re-opened on January 11, 2002. We used conversion ratios of 2.9:1, 3.4:1 and 3.9:1 to translate the assets and liabilities of our Argentine subsidiary, resulting in cumulative foreign currency translation losses, net of tax, of $33.3 million, $37.3 million, and $40.6 million, at December 31, 2003, December 31, 2002 and June 30, 2002, respectively. The foreign currency translation loss is included in other comprehensive income, a component of stockholders' equity. Since the 1:1 conversion ratio was in existence prior to December 2001, income statement and cash flows information for the six months ended December 31, 2001 has been translated using the historical 1:1 conversion ratio. After December 31, 2001, revenues and expenses are translated using the weighted average exchange rate during the reporting period.

Additionally, the Argentine government re-denominated certain consumer loans from U.S. dollar-denominated to Argentine peso-denominated as part of its monetary policy change in 2001. As a result, we recorded a foreign currency transaction loss of $1.8 million in the three months ended December 31, 2001 related to certain accounts receivable subject to certain U.S. dollar-denominated contracts held by our Argentine subsidiary which were subject to re-denomination. In 2002, we recovered $0.4 million from our customers related to the foreign currency transaction loss receivable.

14. LONG-TERM DEBT

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

	December 31, 2003		December 31, 2002		June 30, 2002
	(thousands)
Senior Credit Facility Revolving Loans	$	—	$	52,000	$	—
6.375% Senior Notes Due 2013		150,000		—		—
8.375% Senior Notes Due 2008		276,106		276,327		276,431
14% Senior Subordinated Notes Due 2009		95,339		95,049		94,921
5% Convertible Subordinated Notes Due 2004		18,699		49,554		49,951
Capital lease obligations		16,795		21,062		22,829
Other notes payable		32		107		139

		556,971		494,099		444,271
Less: current portion		24,320		7,005		7,674

Total long-term debt	$	532,651	$	487,094	$	436,597

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Senior Credit Facility

On November 10, 2003, we entered into a Fourth Amended and Restated Credit Agreement (the "Existing Senior Credit Facility"). At December 31, 2003 the Existing Senior Credit Facility consisted of a $175.0 million revolving loan facility with the entire revolving credit facility available for letters of credit. We previously had the right, subject to certain conditions, to increase the total commitment under the Existing Senior Credit Facility from $175.0 million to up to $225.0 million if we were able to obtain additional lending commitments. The revolving loan commitments were scheduled to terminate on November 10, 2007, and all revolving loans would have been required to be paid on or before that date. The revolving loans bore interest based upon, at our option, the agent's base rate for loans or the agent's reserve-adjusted LIBOR rate for loans, plus, in either case, a margin which would fluctuate based upon our consolidated total leverage ratio and, in either case, according to the pricing grid set forth in the Existing Senior Credit Facility.

The Existing Senior Credit Facility contained various financial covenants applicable to specific periods, including: (i) a maximum consolidated total leverage ratio, (ii) a minimum consolidated interest coverage ratio, and (iii) a minimum net worth. The Existing Senior Credit Facility subjected us to other restrictions, including restrictions upon our ability to incur additional debt, liens and guarantee obligations, to merge or consolidate with other persons, to make acquisitions, to sell assets, to pay dividends, repurchase our stock or subordinated debt, to make investments, loans and advances or to make changes to debt instruments and organizational documents. All obligations under the Existing Senior Credit Facility were guaranteed by most of our subsidiaries and were secured by most of our assets, including our accounts receivable, inventory and most equipment. After giving effect to the restatement, at December 31, 2003 the Company would not have been in compliance with the Company's financial covenants under the terms of the Existing Senior Credit Facility at that time. In addition, as described in Note 22—"Subsequent Events," during 2004 and 2005, the restatement process caused us to seek amendments to the Existing Senior Credit Facility to extend and waive certain financial reporting requirements. These amendments included a reduction in the amount of the facility from $175.0 million to $150.0 million. The Existing Senior Credit Facility was terminated on July 29, 2005 and we entered into a new senior secured credit facility. See Note 22—"Subsequent Events" for a description of the new senior secured credit facility.

As of December 31, 2003, no revolving loans were outstanding under the Existing Senior Credit Facility and $57.2 million of letters of credit related to workers' compensation insurance were outstanding.

The Existing Senior Credit Facility amended and restated the Company's Third Amended and Restated Credit Agreement (the "Prior Senior Credit Facility") dated July 15, 2002, which provided for a $150.0 million revolving loan facility with a $75.0 million sublimit for letters of credit. The loans were secured by most of the tangible and intangible assets of the Company. The Prior Senior Credit Facility had customary affirmative and negative covenants including a maximum leverage ratio, a minimum fixed charge coverage ratio and a minimum net worth, as well as limitations on liens and indebtedness and restrictions on dividends, acquisitions and dispositions. A portion of the net cash proceeds from the

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debt offering of the 6.375% Senior Notes (hereinafter defined) completed in May 2003 was used to repay the balance of the revolving loan facility then outstanding under the Prior Senior Credit Facility.

During the year ended June 30, 2001, a portion of the net proceeds from a June 30, 2000 equity offering was used to repay $25.3 million of then-outstanding term loans under a previous credit facility. In addition, $65.0 million of the net proceeds from the June 30, 2000 equity offering were used to reduce the principal amount outstanding under the revolving credit facility. The remainder of the net proceeds from the June 30, 2000 equity offering was used to retire other long-term debt and other general corporate purposes. A portion of the proceeds from our 8.375% Senior Notes offering in calendar year 2001 was used to repay the term loan then-outstanding and $59.1 million under the revolving credit facility.

6.375% Senior Notes

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 the Prior Senior Credit Facility, with the remainder being used for general corporate purposes. The 6.375% Senior Notes were senior unsecured obligations and were fully and unconditionally guaranteed by substantially all of our subsidiaries. The 6.375% Senior Notes were effectively subordinated to Key's secured indebtedness, which included borrowings under the Existing Senior Credit Facility.

At December 31, 2003, $150.0 million principal amount of the 6.375% Senior Notes remained outstanding. The 6.375% Senior Notes required semi-annual interest payments on May 1 and November 1 of each year. Interest of $4.4 million was paid on November 1, 2003. As of December 31, 2003, we were in compliance with all covenants contained in the 6.375% Senior Notes indenture. However, as described in Note 22—"Subsequent Events" below, during 2004 and 2005, the restatement process caused us to seek the consent of the majority of the holders of the 6.375% Senior Notes to extend certain financial reporting requirements. On September 27, 2005, we received a valid acceleration notice with respect to the 6.375% Senior Notes. The 6.375% Senior Notes were repaid on October 5, 2005.

8.375% Senior Notes

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 "Senior Notes"). The net cash proceeds from the private placement were used to repay all of the remaining balance of the original term loans and a portion of the revolving loans then outstanding under our credit facility. On March 1, 2002, we completed a public offering of an additional $100.0 million of 8.375% Senior Notes. The net cash proceeds from the public offering were used to repay the then-outstanding balance of the revolving loan facility under our credit facility. The 8.375% Senior Notes were senior unsecured obligations. The 8.375% Senior Notes were effectively subordinated to Key's secured indebtedness which included borrowings under the Existing Senior Credit Facility.

At December 31, 2003, $275 million principal amount of the 8.375% Senior Notes remained outstanding. The 8.375% Senior Notes required semi-annual interest payments on March 1 and

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September 1 of each year. Interest of $11.5 million was paid on March 1, 2003 and September 1, 2003. As of December 31, 2003, we were in compliance with all covenants contained in the 8.375% Senior Notes. However, as described in Note 22—"Subsequent Events", during 2004 and 2005, the restatement process caused us to seek the consent of the majority of the holders of the 8.375% Senior Notes to extend certain financial reporting requirements. We redeemed all $275.0 million principal amount of the 8.375% Notes on November 8, 2005.

14% Senior Subordinated Notes

On January 22, 1999, we completed the private placement of 150,000 units (the "Units") consisting of $150.0 million of 14% Senior Subordinated Notes due January 15, 2009 (the "14% Senior Subordinated Notes") and 150,000 warrants to purchase 2,173,433 shares of the Company's Common Stock at an exercise price of $4.88125 per share (the "Warrants"). The net cash proceeds from the private placement were used to repay substantially all of the remaining $148.6 million principal amount (plus accrued interest) owed under our bridge loan facility arranged in connection with the acquisition of Dawson Production Services, Inc.

The 14% Senior Notes paid interest semi-annually on January 15 and July 15 of each year. The maturity date of the 14% Senior Subordinated Notes was January 15, 2009. The 14% Senior Subordinated Notes were subordinated to our other senior indebtedness, which included borrowings under the Existing Senior Credit Facility, the 8.375% Senior Notes and the 6.375% Senior Notes.

On and after January 15, 2004, we had the right to redeem some or all of the 14% Senior Subordinated Notes at any time at varying redemption prices in excess of par, plus accrued interest. In addition, before January 15, 2002, we were allowed to redeem up to 35% of the aggregate principal amount of the 14% Senior Subordinated Notes at 114% of par, plus accrued interest with the proceeds of certain sales of equity. During the year ended June 30, 2001, we exercised our right of redemption for $10.3 million principal amount of the 14% Senior Subordinated Notes at a price of 114% of the principal amount plus accrued interest. This transaction resulted in a loss of $2.6 million. On January 14, 2002 we exercised our right of redemption for $35.4 million principal amount of the 14% Senior Subordinated Notes at a price of 114% of the principal amount plus accrued interest. This transaction resulted in a loss of $8.5 million. Also, during the year ended June 30, 2002, the Company purchased and canceled $6.8 million principal amount of the 14% Senior Subordinated Notes at a price of 116% of the principal amount plus accrued interest. At December 31, 2003, $97.5 million principal amount of the 14% Senior Subordinated Notes remained outstanding.

As of December 31, 2003, 63,500 Warrants had been exercised, providing $4.2 million of proceeds to us and leaving 86,500 Warrants outstanding. On the date of issuance, the value of the Warrants was estimated at $7.4 million and was classified as equity. The discount was amortized to interest expense over the term of the 14% Senior Subordinated Notes.

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 have been unable to maintain our effective registration

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statement due to our failure to timely file our SEC reports. As a result, we paid liquidated damages starting at $0.05 per Warrant per week and escalating to $0.20 per Warrant per week. The total amounts paid to the holders of the Warrants were $69,200 and $730,925 in the years ended December 31, 2004, and 2005, respectively.

We repaid all outstanding 14% Senior Subordinated Notes. Please see Note 22—"Subsequent Events," for information about our redemption of the 14% Senior Subordinated Notes.

5% Convertible Subordinated Notes

In 1997, we completed a private placement of $216.0 million of 5% Convertible Subordinated Notes due September 15, 2004 (the "5% Convertible Notes"). The 5% Convertible Notes were subordinated to our senior indebtedness. The 5% Convertible Subordinated Notes were convertible, at the holder's option, into shares of Key's common stock at a conversion price of $38.50 per share, subject to certain adjustments. The 5% Convertible Notes were redeemable, at our option, on and after September 15, 2000, in whole or part, together with accrued and unpaid interest. The initial redemption price was 102.86% for the year beginning September 15, 2000 and declined ratably thereafter on an annual basis.

During the year ended June 30, 2001, we repurchased through open market transactions (and canceled) $47.4 million principal amount of the 5% Convertible Notes. These repurchases resulted in gains of $4.6 million. During the year ended June 30, 2002, we repurchased through open market transactions (and canceled) $108.5 million principal amount of the 5% Convertible Notes. These repurchases resulted in gains of $7.1 million. During the six months ended December 31, 2002, we repurchased through open market transactions (and canceled) an additional $397,000 principal amount of the 5% Convertible Notes. These repurchases resulted in a gain of approximately $18,000. During the year ended December 31, 2003, we repurchased through open market transactions (and canceled) an additional $30.9 million principal amount of the 5% Convertible Notes, leaving $18.7 million outstanding as of December 31, 2003. These repurchases resulted in a gain of approximately $0.2 million. Interest on the 5% Convertible Notes was payable on March 15 and September 15 of each year. Interest of approximately $1.2 million was paid on March 15, 2003 and interest of $487,000 was paid on September 15, 2003. As of December 31, 2003, we were in compliance with all covenants contained in the 5% Convertible Subordinated Notes.

As described in Note 22—"Subsequent Events," the 5% Convertible Notes matured and were repaid on September 15, 2004.

Long-Term Debt Principal Repayment and Interest Expense

Presented below is a schedule of the repayment requirements of long-term debt (excluding the discount on the 14% Senior Subordinated Notes, the premium on the 8.375% Senior Notes and the

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revolving loans under the revolving credit facilities) for each of the next five years and thereafter as of December 31, 2003:

As of December 31, 2003	Principal Amount Long-Term Debt		Capital Leases		Total
	(in thousands)
2004	$	18,732	$	5,588	$	24,320
2005		—		5,603		5,603
2006		—		5,603		5,603
2007		—		—		—
2008		275,000		—		275,000
Thereafter		247,500		—		247,500

	$	541,232	$	16,794	$	558,026

Interest expense for the year ended December 31, 2003, the six months ended December 31, 2002 and the years ended June 30, 2002 and 2001 consisted of the following:

	December 31, 2003			Six Months Ended December 31, 2002 (Restated)			June 30, 2002 (Restated)			June 30, 2001 (Restated)
	(in thousands)
Cash payments	$	45,277		$	20,965		$	42,086		$	51,676
Commitment and agency fees paid		2,275			665			1,183			1,039
Amortization of discount and premium on notes		69			24			496			1,003
Amortization of debt issuance costs		3,044			1,481			2,442			1,345
Net change in accrued interest		782			362			(1,276	)		145
Capitalized interest		(2,456	)		(1,674	)		(1,847	)		(1,778	)

Total interest expense	$	48,991		$	21,823		$	43,084		$	53,430

15. COMMITMENTS AND CONTINGENCIES

Litigation. 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 consolidated financial position, results of operations or cash flows. See Note 22—"Subsequent Events" for a description of currently pending litigation and governmental investigations.

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Over the course of the period taken to complete this Report, additional information regarding certain liabilities that existed at December 31, 2003 has become available, either through additional facts about the liability or the ultimate settlement of the liability. Due to the delay in completing our financial statements for 2003, we have taken into account these facts in our estimate of the liability as of December 31, 2003, in accordance with SFAS 5.

Tax Audits. We are routinely the subject of audits by tax authorities and have received some material assessments from tax auditors. While we have fully reserved for these assessments, the ultimate amount of settlement can vary from this estimate. Based on audits and correspondence with certain taxing authorities subsequent to December 31, 2003, we determined that additional amounts were owed. As this change in estimate was based on new information pertaining to liabilities that were incurred prior to December 31, 2003, we increased our liability for accrued taxes, other than income taxes, by approximately $5.5 million at December 31, 2003, which affects general and administrative expenses in 2003. Additionally, in connection with our Egyptian operations, we are undergoing income tax audits for all periods in which we had operations. Based on our work to date, we have determined that additional income taxes will be owed and have recorded a liability of approximately $1.0 million.

Self-Insurance Reserves. 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. Prior to 2003, we recognized Vehicle Insurance costs when paid and accrued for incurred but unpaid claims based on our assessment of pending or threatened claims in accordance with SFAS 5. In many cases, our judgment was that the lower end of a range of possible outcomes for these incidents was zero, resulting in no accrual of a liability. For 2003, with the consolidation of insurance providers, additional information became available which allowed us to estimate a more likely outcome in a range of potential outcomes, which resulted in an increase to our vehicle general liability reserve of approximately $12.0 million in 2003. We maintain reserves on our balance sheet based on our judgment and estimates using an actuarial method based on claims incurred for workers' compensation and vehicle liability. We estimate general liability claims on a case-by-case basis.

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. See Note 1—"Organization and Summary of Significant Accounting Policies—Environmental" for further discussion of accounting for our environmental reserves, compliance with applicable federal and state environmental laws, and how our operations may affect the environment and may require remediation. Environmental reserves do not reflect management's assessment of the insurance coverage that may apply to these matters at issue, whereas our litigation reserves do reflect the application of our insurance coverage. At December 31, 2003, we have recorded $5.5 million for our environmental remediation liabilities. Of these reserves, $2.8 million were established with our purchase of QSI (see Note 5—"Business and Property Acquisitions—Acquisition of Q Services, Inc."), and $2.7 million were recorded in 2003.

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Guarantees. We provide performance bonds to provide financial surety assurances for the remediation and maintenance of our saltwater disposal well ("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). However, despite our estimates and maintenance of performance bonds relating to SWDs, we are not able to estimate the potential future maximum payments for these performance bonds and other guarantees.

Employment Agreements. To retain qualified senior management, we enter into employment agreements with our executive officers. These employment agreements run for periods ranging from one to three years, but can be automatically extended on a yearly basis unless terminated by us or the executive officer according to the terms of the employment agreement. In addition to providing a base salary for each executive officer, the employment agreements provide for severance payments for each executive officer equal to one to three years of the executive officer's base salary depending on the terms of the specific agreement. At December 31, 2003, the annual base salaries for the executive officers covered under such employment agreements totaled $1.8 million.

On December 1, 2001, we paid to our then-chief executive officer, Francis D. John, an incentive retention payment in connection with his amended and restated employment agreement, which Mr. John would earn over a ten year period beginning on June 30, 2002 (see Note 18—"Transactions with Related Parties").

We enter into employment agreements with other key employees as we deem necessary to retain qualified personnel. Since January 2004 there have been significant changes in our senior management team, and the former members of management have employment agreements that provide for severance payments. See Note 22—"Subsequent Events" for a description of these changes in management.

Consulting Agreement. In the first quarter of 2003, we entered into an agreement with a former employee styled as a consulting and non-compete agreement. The agreement required us to make bi-weekly payments to the former employee in exchange for an agreement not to compete and to provide consulting services upon request. Key entered into this contract after the former employee threatened litigation against us, even though the employee had granted the Company a complete release upon his separation in 1998. The agreement did not require the former employee to provide any consulting services to us and the amounts payable for consulting services remained due to the former employee's estate even if he died. Therefore, a liability existed at the time the agreement was signed by Key and the former employee. As a result, we recorded an expense and corresponding liability of $1.0 million in the first quarter of 2003.

Operating Lease Arrangements. Key leases certain property and equipment under non-cancelable operating leases that generally expire at various dates through calendar 2008. The term of the operating leases generally run from 24 to 60 months with varying payment dates throughout each month.

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As of December 31, 2003, the future minimum lease payments under non-cancelable operating leases are as follows (in thousands):

Year Ending December 31, 2003	Lease Payments
	(in thousands)
2004	$	13,245
2005		11,408
2006		7,340
2007		4,932
2008		1,499
Thereafter		1,591

	$	40,015

Operating lease expense was $11.1 million, $4.2 million, $6.5 million and $6.1 million for the year ended December 31, 2003, the six months ended December 31, 2002 and the years ended June 30, 2002 and 2001, respectively.

16. EMPLOYEE BENEFIT PLANS

In order to retain quality personnel, we maintain a 401(k) plan as part of our employee benefits package. Commencing April 1, 2000, we matched 100% of employee contributions up to 3% of the employee's salary into our 401(k) plan up to a maximum of $250 per participant per year. The maximum limit was increased to $500 effective October 1, 2000, $750 effective January 1, 2001 and $1,000 effective July 1, 2001. Our matching contributions were $2.5 million, $0.9 million, $2.3 million and $1.9 million for the year ended December 31, 2003, the six months ended December, 31, 2002, and the years ended June 30, 2002 and 2001, 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 company stock into another 401(k) plan fund, which did not affect the ability of plan participants to manage these contributions.

17. STOCKHOLDERS' EQUITY

Common Stock

On December 31, 2003, we had 200,000,000 shares of common stock authorized with a $0.10 par value; 130,561,308 shares of common stock issued and 416,666 shares held in treasury and no dividends issued. On December 31, 2002, we had 200,000,000 shares of common stock authorized with a $0.10 par value; 128,341,027 shares of common stock issued and 416,666 shares held in treasury and no dividends issued.

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Common Stock Warrants

At December 31, 2003, we had 86,500 Warrants outstanding that were issued in January 1999 in connection with our 14% Senior Subordinated Notes, which we recorded as equity. As of December 31, 2003, the Warrants were exercisable for 1,253,350 shares of common stock at an exercise price of $4.88125 per underlying share. 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 have been unable to maintain our effective registration statement due to our failure to timely file our SEC reports. As a result, we paid liquidated damages starting at $0.05 per Warrant per week and escalating to $0.20 per Warrant per week. The total amounts paid to the holders of the Warrants were $69,200 and $730,925 in the years ended December 31, 2004, and 2005, respectively.

Equity Offerings

On December 19, 2001, we closed a public offering of 5.4 million shares of common stock, yielding $43.2 million, or $8.00 per share, to us (the "Equity Offering"). Net proceeds from the Equity Offering of $42.6 million were used to temporarily reduce amounts then outstanding under our revolving credit facility. The net proceeds of the Equity Offering were ultimately used in January 2002 to redeem a portion of our 14% Senior Subordinated Notes pursuant to our equity "claw-back" rights for up to 35% of the original $150.0 million issued.

Stock Incentive Plans

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" (the "1995 Option Plan") and the "Key Energy Group, Inc. 1995 Outside Directors Stock Option Plan" (the "1995 Directors Plan") (collectively, the "Prior Plans").

All options previously granted under the Prior Plans and outstanding as of November 17, 1997 (the date on which our board of directors adopted the plan) were assumed and continued, without modification, under the 1997 Incentive Plan.

Under the 1997 Incentive Plan, Key may 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 (collectively, "Incentive Awards"). ISOs and NSOs are sometimes referred to collectively herein as "Options."

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Key may grant Incentive Awards covering an aggregate of the greater of (i) 3.0 million shares of our common stock or (ii) 10% of the shares of our common stock issued and outstanding on the last day of each calendar quarter, provided, however, that a decrease in the number of issued and outstanding shares of our common stock from the previous calendar quarter shall not result in a decrease in the number of shares available for issuance under the 1997 Incentive Plan. As a result of the equity offering discussed above, as of December 31, 2003, the number of shares of our common stock that may be covered by Incentive Awards has increased to approximately 13.1 million shares.

Any shares of our common stock that are issued and are forfeited or are subject to Incentive Awards under the 1997 Incentive Plan that expire or terminate for any reason will remain available for issuance with respect to the granting of Incentive Awards during the term of the 1997 Incentive Plan, except as may otherwise be provided by applicable law. Shares of Key's common stock issued under the 1997 Incentive Plan may be either newly issued or treasury shares, including shares of Key's common stock that we receive in connection with the exercise of an Incentive Award. The number and kind of securities that may be issued under the 1997 Incentive Plan and pursuant to then-outstanding Incentive Awards are subject to adjustments to prevent enlargement or dilution of rights resulting from stock dividends, stock splits, recapitalizations, reorganization or similar transactions.

The maximum number of shares of Key's common stock subject to Incentive Awards that may be granted or that may vest, as applicable, to any one Covered Employee (defined below) during any calendar year shall be 500,000 shares, subject to adjustment under the provisions of the 1997 Incentive Plan.

The maximum aggregate cash payout subject to Incentive Awards (including SARs, performance units and performance shares payable in cash, or other stock-based awards payable in cash) that may be granted to any one Covered Employee during any fiscal year is $2.5 million. For purposes of the 1997 Incentive Plan, "Covered Employees" means a named executive officer who is one of the group of covered employees defined in Section 162(m) of the Code and the regulations promulgated thereunder (i.e., generally the chief executive officer and the other four most highly compensated executive officers for a given year.)

The 1997 Incentive Plan is administered by the Compensation Committee appointed by the Board of Directors (the "Committee") and consisting of not less than two directors, each of whom is (i) an "outside director" under Section 162(m) of the Code and (ii) a "non-employee director" under Rule 16b-3 of the Securities Exchange Act of 1934. In addition, subject to applicable shareholder approval requirements, we may issue NSOs outside the 1997 Incentive Plan. During the period 1999-2001, the Board of Directors granted 3.7 million stock options that were outside the 1997 Incentive Plan. The 3.7 million non-plan options are in addition to and do not include other options which were granted under the Plan, but not in conformity with certain of the terms of the Plan.

The exercise price of options granted under the 1997 Incentive Plan is to be at or above the fair market value per share on the date the options are granted. Under the 1997 Incentive Plan, while the common shares are listed on a securities exchange, fair market value is determined using the closing sales price on the immediate preceding business day as reported on such securities exchange. As discussed above, however, we have determined that the Company incorrectly determined the

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measurement date for many grants of options pursuant to written board consents and, therefore, the exercise price for these options was not at or above fair market value on the measurement date. For the year ended December 31, 2003, total compensation expense for these options was approximately $1.2 million and related to 668,311 options. See Note 2—"Restatement of Financial Statements."

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.

The following table summarizes the stock option activity related to the plans (shares in thousands):

	Year Ended December 31, 2003				Six Months Ended December 31, 2002				Year Ended June 30, 2002				Year Ended June 30, 2001
	Options		Weighted Average Exercise Price		Options		Weighted Average Exercise Price		Options		Weighted Average Exercise Price		Options		Weighted Average Exercise Price
Outstanding at beginning of period, restated	9,876		$	7.88	9,862		$	7.91	8,709		$	7.64	9,514		$	6.31
Granted	1,540		$	10.21	183		$	8.59	1,980		$	8.16	2,507		$	8.04
Exercised	(580	)	$	5.72	(139	)	$	3.14	(657	)	$	4.87	(3,107	)	$	4.70
Cancelled or expired	(214	)	$	7.51	(30	)	$	7.41	(170	)	$	8.22	(205	)	$	5.55

Outstanding at end of period, restated	10,622		$	8.39	9,876		$	7.88	9,862		$	7.91	8,709		$	7.64

Exercisable at end of period, restated	7,895		$	8.03	7,428		$	7.74	5,961		$	8.06	4,736		$	8.19
Weighted average fair value of options granted during the period at market			$	3.97			$	4.63			$	5.03			$	—
Weighted average fair value of options granted during the period at less than market			$	3.90			$	4.46			$	4.29			$	4.96

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The following table summarizes information about the stock options outstanding at December 31, 2003, of which 3.7 million were granted outside the 1997 Incentive Plan between 1999 and 2001 (shares in thousands):

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Weighted Average Remaining Contractual Life (Years)	Number of Options Outstanding December 31, 2003	Weighted Average Exercise Price		Number of Options Exerciseable December 31, 2003	Weighted Average Exercise Price
$ 3.00 - $ 6.81	4.13	993	$	3.74	993	$	3.74
6.82 - 8.13	6.19	2,123	$	7.73	1,722	$	7.66
8.14 - 8.43	6.43	2,383	$	8.27	2,332	$	8.27
8.44 - 9.75	5.73	3,237	$	8.82	2,407	$	8.90
9.76 - 15.00	8.02	1,886	$	10.89	441	$	13.18

		10,622			7,895

The total fair value of stock options granted during the year ended December 31, 2003, the six months ended December 31, 2002 and the years ended June 30, 2002 and 2001 was $6.2 million, $0.8 million, $8.6 million and $12.5 million, respectively. The fair value of each stock option grant 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, 2003		Six Months Ended December 31, 2002		Year Ended June 30, 2002		Year Ended June 30, 2001
Risk-free interest rate	3.11	%	3.66	%	4.52	%	5.58	%
Expected life of options, years	6		6		6		6
Expected volatility of the Company's stock price	34	%	52	%	50	%	59	%
Expected dividends	none		none		none		none

The expected life of options and risk-free interest rate for the six-months ended December 31, 2002; year ended June 30, 2002; and year ended June 30, 2001 changed from our previous filings due to our review of stock options during the restatement process. The review of our option program during the restatement process is more fully described in Note 2—"Restatement of Financial Statements."

18. TRANSACTIONS WITH RELATED PARTIES

Francis D. John Employment Agreement

Effective as of July 1, 2001, we entered into an amended and restated employment agreement with Francis D. John (the "2001 Employment Agreement") pursuant to which Mr. John served as the Chairman of the Board, President and Chief Executive Officer of Key. The 2001 Employment Agreement provided for the payment of a one-time retention incentive payment of $13.1 million. The purpose of this retention incentive payment was to retire all amounts owed by Mr. John under

As discussed in Note 1—“Organization and Summary of Significant Accounting Policies—Basis of
Presentation," these consolidated financial statements (other than the December 31, 2003 consolidated balance
sheet) are not presented in accordance with GAAP.

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incentive-based loans previously made to him (which, because certain performance criteria had been previously met, we were scheduled to forgive ratably over a ten-year period as long as Mr. John continued to serve Key in his present capacity) and in the process provide Mr. John with an incentive to remain with Key for the next ten years. On December 1, 2001, the incentive retention payment was paid to Mr. John and was comprised of two components: (i) $7.5 million in loan principal and interest accrued through the date of the payment and (ii) $5.6 million in a tax "gross-up" payment. The entire payment was withheld by us and used to satisfy Mr. John's tax obligations and his obligations under the loans. Pursuant to the 2001 Employment Agreement, Mr. John would earn the incentive retention payment over a ten-year period beginning July 1, 2001, with one-tenth of the total bonus being earned on June 30 of each year, beginning on June 30, 2002. For the year ended December 31, 2003, the six months ended December 31, 2002 and the year ended June 30, 2002, Mr. John earned $1.3 million, $0.6 million and $1.3 million, respectively, of the retention incentive payment. The 2001 Employment Agreement was amended and restated effective December 31, 2003 (the "2003 Employment Agreement"). Under the 2003 Employment Agreement, if Mr. John voluntarily terminated his employment with Key or if Mr. John was terminated by Key for Cause (as defined in the 2003 Employment Agreement), Mr. John would be obligated to repay the entire remaining unearned balance of the retention incentive payment immediately upon such termination. However, if Mr. John's employment with Key was terminated (i) by Key other than for Cause, (ii) by Mr. John for Good Reason, (iii) as a result of Mr. John's death or Disability (as defined in the 2003 Employment Agreement), or (iv) as a result of a Change in Control (as defined in the 2003 Employment Agreement), the remaining unearned balance of the retention incentive payment would be treated as earned as of the date of such event. See Note 22—"Subsequent Events" for a discussion of subsequent events concerning Mr. John.

Investment in Gas Trusts

On December 3, 1997, Odessa Exploration Incorporated ("OEI"), a Delaware corporation and wholly-owned subsidiary of Key, purchased 13.333 Performance Shares and 1.88333 Preferred Shares in the 1995-2 Marcum Midstream Business Trust ("1995 Trust"), which operated three salt water disposal facilities, and 5.666 Performance Shares and 3.08333 Preferred Shares in the 1997-1 Marcum Midstream Business Trust ("1997 Trust"), which operated a natural gas and liquids processing plant.

Also included in the purchases of the 1995 and 1997 Trusts were one-third of future management fees received by Marcum Gas Transmission, Inc. ("Marcum") as managing trustee of each trust and Purchase Price Revenue Interest ("PPRI") and Purchase Price Purchased Shares ("PPPS"). Pursuant to the purchase agreement, PPRI are the cash payments that Marcum is required to pay OEI for amounts equal to one-third of the aggregate gross program fees that Marcum receives from both the 1995 and 1997 Trusts for its role as managing trustee, and PPPS represent OEI's right to receive distributions with respect to the shares of each trust. The trusts are owned by Marcum, a wholly-owned subsidiary of Metretek Technologies, Inc. ("Metretek"). Three Key directors are also involved with Metretek.

•: W. Phillip Marcum is the Chairman and chief executive officer of Metretek and serves as a director of Key.

As discussed in Note 1—“Organization and Summary of Significant Accounting Policies—Basis of
Presentation," these consolidated financial statements (other than the December 31, 2003 consolidated balance
sheet) are not presented in accordance with GAAP.

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•: Kevin P. Collins is a director for both Key and Metretek.
•: David J. Breazzano, a Key director, is a founding principal of DDJ Capital Management, LLC, an investment firm, which managed funds that had interests in Metretek ranging from 7.7% to 26.9% over the course of OEI's investments in the 1995 Trust and the 1997 Trust.

OEI committed to invest a total of $1.0 million in the two trusts ($475,129 for the 1995 Trust and $524,871 for the 1997 Trust) with an initial contribution of $600,000 made in December 1997 and eight quarterly contributions of $50,000 beginning on March 31, 1998. OEI ultimately paid only two quarterly installments. In September 1999, Marcum forgave the remaining $300,000 of the commitment. The $1.0 million commitment provided OEI a general partnership ownership interest in the 1995 Trust beginning at 0.0312% and increasing to 5.834818% and a limited partnership ownership interest beginning at 5.11657% and increasing to 5.226508%. For the 1997 Trust, the $1 million commitment provided OEI a limited partnership interest ownership beginning at 3.1993% and increasing to 3.3444%. In December 1999, OEI funded $257,590 to the 1995 Trust by forgoing certain PPPS distributions and PPRI payments. On December 31, 2003, Marcum commenced a tender offer to purchase all OEI outstanding shares in the 1995 Trust, which was sold to Marcum on March 22, 2004 at an aggregate purchase price of $454,000 and supported by a fairness opinion of $26,549 per share. As of June 30, 2002, December 31, 2002 and December 31, 2003, we had no outstanding capital contributions to the 1995 and 1997 Trusts. Over the course of the investment, OEI made contributions of $0.95 million and received distributions of $1.25 million, which includes the $0.45 million sales price. We recorded a loss upon disposition of these investments of approximately $30,000 in 2003.

Employee Loans and Advances

In 2001, Key provided Medicare tax obligation advances to certain members of then-senior management in connection with their exercise of options in connection with a block sale by such officers. As of June 1, 2006 all of the advances, except those made to Mr. Loftis, have been repaid.

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, 2003, these loans, in the aggregate, total less than $100,000.

Related Persons

Craig Owen, Mr. Flynt's son-in-law, is currently a manager in our Rocky Mountain Division. He received approximately $129,066 in salary and bonus as of December 31, 2003. We believe that Mr. Owen's compensation is comparable to what he would receive absent his relationship to Mr. Flynt.

As discussed in Note 1—“Organization and Summary of Significant Accounting Policies—Basis of
Presentation," these consolidated financial statements (other than the December 31, 2003 consolidated balance
sheet) are not presented in accordance with GAAP.

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19. SEGMENT INFORMATION

For 2003, our reportable business segments are well servicing and contract drilling.

Well Servicing. These operations provide a full range of well services, including rig-based services, oilfield transportation services, fishing and rental tool services, pressure pumping services and other ancillary oilfield services necessary to complete, maintain and workover oil and natural gas producing wells. Included in our well servicing segment are our Argentina operations. We aggregate our operating divisions engaged in well servicing activities into our well servicing reportable segment.

Contract Drilling. These operations provide contract drilling services to major and independent oil and natural gas companies onshore in the continental United States and Canada. See Note 22—"Subsequent Events" for a discussion of the sale of substantially all of our contract drilling division.

We evaluate the performance of our operating segments based on revenue and EBITDA, which is a non-GAAP measure and not disclosed below. Corporate expenses include general corporate expenses associated with managing all reportable operating segments. Corporate assets consist principally of cash and cash equivalents, deferred debt financing costs and deferred income tax assets.

As discussed in Note 1—“Organization and Summary of Significant Accounting Policies—Basis of
Presentation," these consolidated financial statements (other than the December 31, 2003 consolidated balance
sheet) are not presented in accordance with GAAP.

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	Well Servicing			Contract Drilling			Corporate / Other			Total
	(in thousands)
As of and for the year ended December 31, 2003
Operating revenues	$	859,697		$	65,942		$	—		$	925,639
Gross margin		238,522			17,310			—			255,832
Depreciation, depletion and amortization		84,021			7,841			6,205			98,067
Interest expense		—			—			48,991			48,991
Net income (loss) from continuing operations*		24,300			4,595			(74,512	)		(45,617	)
Property, plant and equipment, net		575,506			60,227			53,344			689,077
Total assets		1,079,438			87,759			209,041			1,376,238
Capital expenditures, excluding acquisitions	$	(91,558	)	$	(228	)	$	(6,662	)	$	(98,448	)
As of and for the six months ended December 31, 2002 (restated)
Operating revenues	$	372,280		$	32,137		$	—		$	404,417
Gross margin		109,934			9,442			—			119,376
Depreciation, depletion and amortization		41,308			4,544			2,067			47,919
Interest expense		—			—			21,823			21,823
Net income (loss) from continuing operations*		30,474			2,240			(40,735	)		(8,021	)
Property, plant and equipment, net		682,356			64,726			46,318			793,400
Total assets		1,065,797			92,516			192,075			1,350,388
Capital expenditures, excluding acquisitions	$	(12,736	)	$	—		$	(9,928	)	$	(22,664	)
As of and for the year ended June 30, 2002 (restated)
Operating revenues	$	712,635		$	81,204		$	—		$	793,839
Gross margin		211,787			24,458			—			236,245
Depreciation, depletion and amortization		66,470			9,192			1,370			77,032
Interest expense		—			—			43,084			43,084
Net income (loss) from continuing operations*		79,257			6,408			(80,459	)		5,206
Property, plant and equipment, net		550,776			65,822			32,625			649,223
Total assets		856,588			93,772			144,294			1,094,654
Capital expenditures, excluding acquisitions	$	(73,881	)	$	(2,719	)	$	(13,096	)	$	(89,696	)
As of and for the year ended June 30, 2001 (restated)
Operating revenues	$	770,783		$	95,127		$	—		$	865,910
Gross margin		251,814			29,103			—			280,917
Depreciation, depletion and amortization		68,533			7,578			951			77,062
Interest expense		323			40			53,067			53,430
Net income (loss) from continuing operations*		140,074			15,218			(110,388	)		44,904
Property, plant and equipment, net		577,392			75,693			20,819			673,904
Total assets		930,694			110,460			90,089			1,131,243
Capital expenditures, excluding acquisitions	$	(71,967	)	$	(3,763	)	$	(15,003	)	$	(90,733	)

*: Net income (loss) from continuing operations for the contract drilling segment includes a portion of well servicing general and administrative expenses allocated on a percentage of revenue basis.

As discussed in Note 1—“Organization and Summary of Significant Accounting Policies—Basis of
Presentation," these consolidated financial statements (other than the December 31, 2003 consolidated balance
sheet) are not presented in accordance with GAAP.

F-82

Operating revenues for our foreign operations were $45.2 million, $14.8 million, $33.4 million and $54.7 million for the year ended December 31, 2003, the six months ended December 31, 2002 and the years ended June 30, 2002 and 2001, respectively. Gross margins for our foreign operations were $17.3 million, $5.2 million, $6.5 million and $12.9 million for the year ended December 31, 2003, the six months ended December 31, 2002 and the years ended June 30, 2002 and 2001, respectively. We allocated general and administrative overhead of $1.3 million to our Egypt operations for the year ended December 31, 2003.

We have $49.4 million, $46.7 million and $36.4 million of identifiable assets related to our foreign operations as of December 31, 2003, December 31, 2002 and June 30, 2002, respectively. Capital expenditures for our foreign operations were $3.8 million, $3.1 million, $4.5 million and $6.7 million for the year ended December 31, 2003, the six months ended December 31, 2002 and the years ended June 30, 2002 and 2001, respectively.

As discussed in Note 1—“Organization and Summary of Significant Accounting Policies—Basis of
Presentation," these consolidated financial statements (other than the December 31, 2003 consolidated balance
sheet) are not presented in accordance with GAAP.

F-83

20. UNAUDITED SUPPLEMENTARY INFORMATION—QUARTERLY RESULTS OF OPERATIONS

Set forth below is unaudited summarized quarterly information for the periods covered by these consolidated financial statements. See Note 2—"Restatement of Financial Statements" for a description of the effect of the restatement.

Summarized quarterly financial data for the year ended December 31, 2003, and the six months ended December 31, 2002, are as follows:

			First Quarter						Second Quarter						Third Quarter						Fourth Quarter
			As Previously Reported			Restated			As Previously Reported			Restated			As Previously Reported			Restated
			(in thousands, except per share data)
Year Ended December 31, 2003(1)(2)
	Revenues		$	213,753		$	213,836		$	238,481		$	238,484		$	243,070		$	243,071		$	230,248
	Income (loss) before income taxes			(2,205	)		(19,214	)		10,002			9,159			11,544			12,562			(66,079	)
	Net income (loss) from continuing operations			(1,515	)		(23,142	)		6,364			(346	)		6,340			213			(22,342	)
	Discontinued operations, net of tax			(259	)		(304	)		(211	)		(339	)		(7,396	)		(3,846	)		(265	)
	Net income (loss)			(1,774	)		(23,446	)		6,153			(685	)		(1,056	)		(3,633	)		(22,607	)
	Earnings (loss) per share:
		Basic—Net income (loss) from continuing operations, net of tax	$	(0.01	)	$	(0.18	)	$	0.05		$	—		$	0.05		$	—		$	(0.17	)
		Discontinued operations, net of tax		—			—			—			—			(0.06	)		(0.03	)		—
		Basic—Net income (loss)	$	(0.01	)	$	(0.18	)	$	0.05		$	—		$	(0.01	)	$	(0.03	)	$	(0.17	)
		Diluted—Net income (loss) from continuing operations, net of tax	$	(0.01	)	$	(0.18	)	$	0.05		$	—		$	0.05		$	—		$	(0.17	)
		Discontinued operations, net of tax		—			—			—			—			(0.06	)		(0.03	)		—
		Diluted—Net income (loss)	$	(0.01	)	$	(0.18	)	$	0.05		$	—		$	(0.01	)	$	(0.03	)	$	(0.17	)
Six Months Ended December 31, 2002
	Revenues		$	200,366		$	200,351		$	204,137		$	204,066
	Income (loss) before income taxes			(3,753	)		18,402			1,959			(27,408	)
	Net income (loss) from continuing operations			(2,327	)		16,684			996			(24,705	)
	Discontinued operations, net of tax			(2,524	)		(981	)		138			(1,705	)
	Cumulative effect of a change in accounting principle, net of tax			(658	)		(2,569	)		—			944
	Net income (loss)			(5,510	)		13,134			1,134			(25,252	)
	Earnings (loss) per share:
		Basic—Net income (loss) from continuing operations, net of tax	$	(0.02	)	$	0.14		$	0.01		$	(0.19	)
		Discontinued operations, net of tax		(0.02	)		(0.01	)		—			(0.01	)
		Cumulative effect, net of tax		(0.01	)		(0.03	)		—			0.01
		Basic—Net income (loss)	$	(0.05	)	$	0.10		$	0.01		$	(0.19	)
		Diluted—Net income (loss) from continuing operations, net of tax	$	(0.02	)	$	0.14		$	0.01		$	(0.19	)
		Discontinued operations, net of tax		(0.02	)		(0.01	)		—			(0.01	)
		Cumulative effect, net of tax		(0.01	)		(0.03	)		—			0.01
		Diluted—Net income (loss)	$	(0.05	)	$	0.10		$	0.01		$	(0.19	)

(1): The fourth quarter of 2003 includes the net write-off of $40.5 million in the carrying value of net property and equipment determined not to exist and $23.0 million write-down in fixed assets due to condition or intended use.
(2): The third and fourth quarters of 2003 include write-offs totalling $1.3 million in receivables previously recorded in error under our re-insurance workers' compensation plans.

As discussed in Note 1—“Organization and Summary of Significant Accounting Policies—Basis of
Presentation," these consolidated financial statements (other than the December 31, 2003 consolidated balance
sheet) are not presented in accordance with GAAP.

F-84

Summarized quarterly financial data for the years ended June 30, 2002 and 2001 are as follows:

			First Quarter						Second Quarter						Third Quarter						Fourth Quarter
			As Previously Reported			Restated			As Previously Reported			Restated			As Previously Reported			Restated			As Previously Reported			Restated
			(in thousands, except per share data)
Year Ended June 30, 2002
	Revenues		$	246,137		$	246,125		$	211,992		$	211,995		$	168,396		$	168,397		$	167,181		$	167,322
	Income (loss) before income taxes			46,636			41,124			32,237			28,373			(7,188	)		(6,469	)		(9,786	)		(53,203	)
	Net income (loss) from continuing operations			29,309			21,102			19,833			18,446			(4,710	)		(3,030	)		(5,439	)		(31,312	)
	Discontinued operations, net of tax			(133	)		1,090			(374	)		187			84			(1,473	)		(424	)		(889	)
	Net income (loss)			29,176			22,192			19,459			18,633			(4,626	)		(4,503	)		(5,863	)		(32,201	)
	Earnings (loss) per share:
		Basic—Net income (loss) from continuing operations, net of tax	$	0.29		$	0.21		$	0.19		$	0.18		$	(0.04	)	$	(0.02	)	$	(0.05	)	$	(0.29	)
		Discontinued operations, net of tax		—			0.01			—			0.01			—			(0.01	)		—			—
		Basic—Net income (loss)	$	0.29		$	0.22		$	0.19		$	0.19		$	(0.04	)	$	(0.03	)	$	(0.05	)	$	(0.29	)
		Diluted—Net income (loss) from continuing operations, net of tax	$	0.28		$	0.20		$	0.19		$	0.18		$	(0.04	)	$	(0.02	)	$	(0.05	)	$	(0.29	)
		Discontinued operations, net of tax		—			0.01			—			0.01			—			(0.01	)		—			—
		Diluted—Net income (loss)	$	0.28		$	0.21		$	0.19		$	0.19		$	(0.04	)	$	(0.03	)	$	(0.05	)	$	(0.29	)
Year Ended June 30, 2001
	Revenues		$	188,711		$	188,709		$	202,828		$	202,827		$	226,317		$	226,304		$	248,056		$	248,070
	Income (loss) before income taxes			14,780			9,374			18,618			14,416			28,892			27,057			39,967			30,985
	Net income from continuing operations			9,077			4,998			11,436			6,605			18,204			14,013			25,419			19,951
	Discontinued operations, net of tax			(370	)		(2,302	)		(274	)		(1,174	)		(784	)		49			2			2,430
	Cumulative effect on prior years of a change in accounting principle, net of tax			—			—			—			—			—			—			—			—
	Net income			8,707			2,686			11,162			5,431			17,420			14,062			25,421			22,381
	Earnings (loss) per share:
		Basic—Net income from continuing operations, net of tax	$	0.09		$	0.04		$	0.12		$	0.07		$	0.19		$	0.14		$	0.25		$	0.19
		Discontinued operations, net of tax		—			(0.02	)		—			(0.01	)		(0.01	)		—			—			0.02
		Cumulative effect, net of tax		—			—			—			—			—			—			—			—
		Basic—Net income	$	0.09		$	0.02		$	0.12		$	0.06		$	0.18		$	0.14		$	0.25		$	0.21
		Diluted—Net income from continuing operations, net of tax	$	0.09		$	0.05		$	0.11		$	0.06		$	0.18		$	0.14		$	0.24		$	0.19
		Discontinued operations, net of tax		—			(0.02	)		—			(0.01	)		(0.01	)		—			—			0.02
		Cumulative effect, net of tax		—			—			—			—			—			—			—			—
		Diluted—Net income	$	0.09		$	0.03		$	0.11		$	0.05		$	0.17		$	0.14		$	0.24		$	0.21

As discussed in Note 1—“Organization and Summary of Significant Accounting Policies—Basis of
Presentation," these consolidated financial statements (other than the December 31, 2003 consolidated balance
sheet) are not presented in accordance with GAAP.

F-85

The following tables present the balance sheet and income statement impacts of the restatement for the interim periods of March 31, 2003; June 30, 2003 and September 30, 2003, which were previously filed pursuant to Quarterly Reports on Form 10-Q during the fiscal year ended December 31, 2003.

Consolidated Statements of Operations for the Three Months Ended March 31, 2003

			As Previously Reported			Adjustments			As Restated
			(in thousands, except per share data)
*REVENUES:*
	Well servicing		$	197,600		$	2,722		$	200,322
	Contract drilling			16,153			(2,639	)		13,514

Total revenues				213,753			83			213,836

*COSTS AND EXPENSES:*
	Well servicing			146,111			22,372			168,483
	Contract drilling			10,952			(385	)		10,567
	Depreciation, depletion and amortization			24,986			(1,897	)		23,089
	General and administrative			21,956			453			22,409
	Interest			11,048			(2,534	)		8,514
	Gain on early extinguishment of debt			(2	)		—			(2	)
	Loss (gain) on sale of assets			(90	)		101			11
	Interest income			(36	)		—			(36	)
	Other income & expense			1,033			(1,018	)		15

Total costs and expenses				215,958			17,092			233,050

Loss from continuing operations before income taxes				(2,205	)		(17,009	)		(19,214	)
Income tax benefit (expense)				690			(4,618	)		(3,928	)

LOSS FROM CONTINUING OPERATIONS				(1,515	)		(21,627	)		(23,142	)

	Loss from Discontinued Operations, net of tax			(259	)		(45	)		(304	)

*NET LOSS*			$	(1,774	)	$	(21,672	)	$	(23,446	)

EARNINGS (LOSS) PER SHARE:
	Net loss from continuing operations
		Basic	$	(0.01	)	$	(0.17	)	$	(0.18	)
		Diluted	$	(0.01	)	$	(0.17	)	$	(0.18	)
	Discontinued operations
		Basic	$	—		$	—		$	—
		Diluted	$	—		$	—		$	—
	Net loss
		Basic	$	(0.01	)	$	(0.17	)	$	(0.18	)
		Diluted	$	(0.01	)	$	(0.17	)	$	(0.18	)

F-86

Consolidated Statements of Operations for the Three Months Ended June 30, 2003

			As Previously Reported			Adjustments			As Restated
			(in thousands, except per share data)
*REVENUES:*
	Well servicing		$	219,970		$	989		$	220,959
	Contract drilling			18,511			(986	)		17,525

Total revenues				238,481			3			238,484

*COSTS AND EXPENSES:*
	Well servicing			154,333			(2,182	)		152,151
	Contract drilling			12,133			322			12,455
	Depreciation, depletion and amortization			25,076			(1,182	)		23,894
	Loss associated with the South Texas Matters			—			5,135			5,135
	General and administrative			23,318			(180	)		23,138
	Interest			12,166			(107	)		12,059
	Gain on early extinguishment of debt			(14	)		(1	)		(15	)
	Loss on sale of assets			114			114			228
	Interest income			(127	)		—			(127	)
	Other income & expense			1,480			(1,073	)		407

Total costs and expenses				228,479			846			229,325

Income from continuing operations before income taxes				10,002			(843	)		9,159
Income tax expense				(3,638	)		(5,867	)		(9,505	)

INCOME (LOSS) FROM CONTINUING OPERATIONS				6,364			(6,710	)		(346	)

	Loss from Discontinued Operations, net of tax			(211	)		(128	)		(339	)

*NET INCOME (LOSS)*			$	6,153		$	(6,838	)	$	(685	)

EARNINGS (LOSS) PER SHARE:
	Net income (loss) from continuing operations
		Basic	$	0.05		$	(0.05	)	$	—
		Diluted	$	0.05		$	(0.05	)	$	—
	Discontinued operations
		Basic	$	—		$	—		$	—
		Diluted	$	—		$	—		$	—
	Net income (loss)
		Basic	$	0.05		$	(0.05	)	$	—
		Diluted	$	0.05		$	(0.05	)	$	—

F-87

Consolidated Statements of Operations for the Six Months Ended June 30, 2003

			As Previously Reported			Adjustments			As Restated
			(in thousands, except per share data)
*REVENUES:*
	Well servicing		$	417,570		$	3,711		$	421,281
	Contract drilling			34,664			(3,625	)		31,039

Total revenues				452,234			86			452,320

*COSTS AND EXPENSES:*
	Well servicing			300,444			20,190			320,634
	Contract drilling			23,085			(63	)		23,022
	Depreciation, depletion and amortization			50,062			(3,080	)		46,982
	Loss associated with the South Texas Matters			—			5,135			5,135
	General and administrative			45,274			273			45,547
	Interest			23,214			(2,641	)		20,573
	Gain on early extinguishment of debt			(16	)		(1	)		(17	)
	Loss on sale of assets			24			215			239
	Interest income			(163	)		—			(163	)
	Other income & expense			2,513			(2,091	)		422

Total costs and expenses				444,437			17,937			462,374

Income (loss) from continuing operations before income taxes				7,797			(17,851	)		(10,054	)
Income tax expense				(2,948	)		(10,486	)		(13,434	)

INCOME (LOSS) FROM CONTINUING OPERATIONS				4,849			(28,337	)		(23,488	)

	Loss from Discontinued Operations, net of tax			(470	)		(173	)		(643	)

*NET INCOME (LOSS)*			$	4,379		$	(28,510	)	$	(24,131	)

EARNINGS (LOSS) PER SHARE:
	Net income (loss) from continuing operations
		Basic	$	0.04		$	(0.22	)	$	(0.18	)
		Diluted	$	0.04		$	(0.22	)	$	(0.18	)
	Discontinued operations
		Basic	$	—		$	—		$	—
		Diluted	$	—		$	—		$	—
	Net income (loss)
		Basic	$	0.04		$	(0.22	)	$	(0.18	)
		Diluted	$	0.04		$	(0.22	)	$	(0.18	)

F-88

Consolidated Statements of Operations for the Three Months Ended September 30, 2003

			As Previously Reported			Adjustments			As Restated
			(in thousands, except per share data)
*REVENUES:*
	Well servicing		$	224,251		$	930		$	225,181
	Contract drilling			18,819			(929	)		17,890

Total revenues				243,070			1			243,071

*COSTS AND EXPENSES:*
	Well servicing			154,564			62			154,626
	Contract drilling			13,676			(733	)		12,943
	Depreciation, depletion and amortization			25,898			(1,295	)		24,603
	General and administrative			24,974			854			25,828
	Interest			12,726			(153	)		12,573
	Loss (gain) on sale of assets			(249	)		257			8
	Interest income			(168	)		(1	)		(169	)
	Other income & expense			105			(8	)		97

Total costs and expenses				231,526			(1,017	)		230,509

Income from continuing operations before income taxes				11,544			1,018			12,562
Income tax expense				(5,204	)		(7,145	)		(12,349	)

INCOME FROM CONTINUING OPERATIONS				6,340			(6,127	)		213

	Income (loss) from Discontinued Operations, net of tax			(7,396	)		3,550			(3,846	)

*NET INCOME (LOSS)*			$	(1,056	)	$	(2,577	)	$	(3,633	)

EARNINGS (LOSS) PER SHARE:
	Net income from continuing operations
		Basic	$	0.05		$	(0.05	)	$	—
		Diluted	$	0.05		$	(0.05	)	$	—
	Discontinued operations
		Basic	$	(0.06	)	$	0.03		$	(0.03	)
		Diluted	$	(0.06	)	$	0.03		$	(0.03	)
	Net income (loss)
		Basic	$	(0.01	)	$	(0.02	)	$	(0.03	)
		Diluted	$	(0.01	)	$	(0.02	)	$	(0.03	)

F-89

Consolidated Statements of Operations for the Nine Months Ended September 30, 2003

			As Previously Reported			Adjustments			As Restated
			(in thousands, except per share data)
*REVENUES:*
	Well servicing		$	641,821		$	4,641		$	646,462
	Contract drilling			53,483			(4,554	)		48,929

Total revenues				695,304			87			695,391

*COSTS AND EXPENSES:*
	Well servicing			455,008			20,252			475,260
	Contract drilling			36,761			(796	)		35,965
	Depreciation, depletion and amortization			75,960			(4,374	)		71,586
	Loss associated with the South Texas Matters			—			5,135			5,135
	General and administrative			70,248			1,127			71,375
	Interest			35,940			(2,794	)		33,146
	Gain on early extinguishment of debt			(16	)		(1	)		(17	)
	Loss (gain) on sale of assets			(225	)		472			247
	Interest income			(331	)		(1	)		(332	)
	Other income & expense			2,618			(2,099	)		519

Total costs and expenses				675,963			16,921			692,884

Income from continuing operations before income taxes				19,341			(16,834	)		2,507
Income tax expense				(8,152	)		(17,630	)		(25,782	)

INCOME (LOSS) FROM CONTINUING OPERATIONS				11,189			(34,464	)		(23,275	)

	Loss from Discontinued Operations, net of tax			(7,866	)		3,377			(4,489	)

*NET INCOME (LOSS)*			$	3,323		$	(31,087	)	$	(27,764	)

EARNINGS (LOSS) PER SHARE:
	Net income (loss) from continuing operations
		Basic	$	0.09		$	(0.27	)	$	(0.18	)
		Diluted	$	0.09		$	(0.27	)	$	(0.18	)
	Discontinued operations
		Basic	$	(0.06	)	$	0.03		$	(0.03	)
		Diluted	$	(0.06	)	$	0.03		$	(0.03	)
	Net income (loss)
		Basic	$	0.03		$	(0.24	)	$	(0.21	)
		Diluted	$	0.03		$	(0.24	)	$	(0.21	)

F-90

Key Energy Services, Inc.

Consolidated Balance Sheet

		March 31, 2003
		As Previously Reported			Adjustments			As Restated
		(in thousands)
ASSETS
Current assets:
	Cash and cash equivalents	$	3,562		$	(67	)	$	3,495
	Accounts receivable, net of allowance for doubtful accounts of $4,769		151,534			(3,995	)		147,539
	Inventories		11,684			(252	)		11,432
	Prepaid expenses		6,440			128			6,568
	Other current assets		7,273			7,261			14,534

Total current assets			180,493			3,075			183,568

Property and equipment:
	Well servicing equipment		928,733			(144,024	)		784,709
	Contract drilling equipment		129,510			(23,943	)		105,567
	Motor vehicles		78,987			578			79,565
	Oil and natural gas properties and other related equipment, sucessful efforts method		48,365			(1,475	)		46,890
	Furniture and equipment		53,853			123			53,976
	Buildings and land		49,274			672			49,946

Total property and equipment			1,288,722			(168,069	)		1,120,653
Accumulated depreciation and depletion			(359,548	)		(12,494	)		(372,042	)

Net property and equipment			929,174			(180,563	)		748,611

Goodwill, net			337,746			(7,082	)		330,664
Deferred costs, net			12,783			(212	)		12,571
Notes and accounts receivable—related parties			322			100			422
Other assets			32,096			(2,593	)		29,503

TOTAL ASSETS		$	1,492,614		$	(187,275	)	$	1,305,339

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable	$	26,903		$	(23	)	$	26,880
	Other accrued liabilities		59,768			15,107			74,875
	Accrued interest		5,466			99			5,565
	Current portion of Volumetric Production Payment ("VPP")		—			4,813			4,813
	Current portion of long-term debt and capital lease obligations		6,637			(6	)		6,631

Total current liabilities			98,774			19,990			118,764

Long-term debt, less current portion			479,300			622			479,922
Volumetric Production Payment			—			7,187			7,187
Capital lease obligations, less current portion			13,132			(99	)		13,033
Deferred revenue			7,590			(6,683	)		907
Non-current accrued expenses			43,922			(5,109	)		38,813
Deferred tax liability			150,688			(34,913	)		115,775
Commitments and contingencies			—			—			—
Stockholders' equity:
	Common stock, $0.10 par value; 200,000,000 shares authorized, 128,887,088 shares issued		12,899			—			12,899
	Additional paid-in capital		673,867			16,661			690,528
	Treasury stock, at cost; 416,666 shares		(9,682	)		—			(9,682	)
	Accumulated other comprehensive loss		(41,458	)		4,393			(37,065	)
	Retained earnings		63,582			(189,324	)		(125,742	)

Total stockholders' equity			699,208			(168,270	)		530,938

Total liabilities and stockholders' equity		$	1,492,614		$	(187,275	)	$	1,305,339

F-91

Key Energy Services, Inc.

Consolidated Balance Sheet

		June 30, 2003
		As Previously Reported			Adjustments			As Restated
		(in thousands)
ASSETS
Current assets:
	Cash and cash equivalents	$	72,664		$	95		$	72,759
	Accounts receivable, net of allowance for doubtful accounts of $5,131		162,410			(4,377	)		158,033
	Inventories		13,491			(686	)		12,805
	Prepaid expenses		6,862			(75	)		6,787
	Other current assets		6,199			7,192			13,391

Total current assets			261,626			2,149			263,775

Property and equipment:
	Well servicing equipment		952,364			(143,785	)		808,579
	Contract drilling equipment		132,008			(24,022	)		107,986
	Motor vehicles		79,349			578			79,927
	Oil and natural gas properties and other related equipment, sucessful efforts method		48,365			(1,474	)		46,891
	Furniture and equipment		58,208			123			58,331
	Buildings and land		50,229			672			50,901

Total property and equipment			1,320,523			(167,908	)		1,152,615
Accumulated depreciation and depletion			(382,879	)		(11,260	)		(394,139	)

Net property and equipment			937,644			(179,168	)		758,476

Goodwill, net			344,664			(12,675	)		331,989
Deferred costs, net			14,765			(481	)		14,284
Notes and accounts receivable—related parties			191			100			291
Other assets			28,570			(2,973	)		25,597

TOTAL ASSETS		$	1,587,460		$	(193,048	)	$	1,394,412

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable	$	22,663		$	(35	)	$	22,628
	Other accrued liabilities		63,148			19,128			82,276
	Accrued interest		15,855			99			15,954
	Current portion of Volumetric Production Payment ("VPP")		—			5,097			5,097
	Current portion of long-term debt and capital lease obligations		6,441			—			6,441

Total current liabilities			108,107			24,289			132,396

Long-term debt, less current portion			539,506			606			540,112
Volumetric Production Payment			—			6,822			6,822
Capital lease obligations, less current portion			12,753			(99	)		12,654
Deferred revenue			6,570			(6,040	)		530
Non-current accrued expenses			48,725			(9,816	)		38,909
Deferred tax liability			153,309			(33,040	)		120,269
Commitments and contingencies			—			—			—
Stockholders' equity:
	Common stock, $0.10 par value; 200,000,000 shares authorized, 130,051,496 shares issued		13,004			—			13,004
	Additional paid-in capital		684,538			16,646			701,184
	Treasury stock, at cost; 416,666 shares		(9,682	)		—			(9,682	)
	Accumulated other comprehensive loss		(39,111	)		3,753			(35,358	)
	Retained earnings		69,741			(196,169	)		(126,428	)

Total stockholders' equity			718,490			(175,770	)		542,720

Total liabilities and stockholders' equity		$	1,587,460		$	(193,048	)	$	1,394,412

F-92

Key Energy Services, Inc.

Consolidated Balance Sheet

		September 30, 2003
		As Previously Reported			Adjustments			As Restated
		(in thousands)
ASSETS
Current assets:
	Cash and cash equivalents	$	89,427		$	34		$	89,461
	Accounts receivable, net of allowance for doubtful accounts of $5,813		162,819			(35	)		162,784
	Inventories		14,022			(687	)		13,335
	Prepaid expenses		7,461			(129	)		7,332
	Other current assets		4,985			8,526			13,511

Total current assets			278,714			7,709			286,423

Property and equipment:
	Well servicing equipment		967,013			(143,009	)		824,004
	Contract drilling equipment		132,556			(24,056	)		108,500
	Motor vehicles		81,554			578			82,132
	Furniture and equipment		61,937			123			62,060
	Buildings and land		50,003			673			50,676

Total property and equipment			1,293,063			(165,691	)		1,127,372
Accumulated depreciation and depletion			(389,329	)		(10,058	)		(399,387	)

Net property and equipment			903,734			(175,749	)		727,985

Goodwill, net			346,335			(12,694	)		333,641
Deferred costs, net			14,182			(683	)		13,499
Notes and accounts receivable—related parties			190			100			290
Other assets			24,446			(738	)		23,708

TOTAL ASSETS		$	1,567,601		$	(182,055	)	$	1,385,546

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable	$	20,885		$	(75	)	$	20,810
	Other accrued liabilities		70,504			21,723			92,227
	Accrued interest		8,841			99			8,940
	Oil and gas collars		—			—			—
	Current portion of long-term debt and capital lease obligations		24,616			(5	)		24,611

Total current liabilities			124,846			21,742			146,588

Long-term debt, less current portion			520,837			591			521,428
Capital lease obligations, less current portion			11,722			(99	)		11,623
Deferred revenue			726			—			726
Non-current accrued expenses			36,919			(1,749	)		35,170
Deferred tax liability			154,182			(29,514	)		124,668
Commitments and contingencies			—			—			—
Stockholders' equity:
	Common stock, $0.10 par value; 200,000,000 shares authorized, 130,337,664 shares issued		13,034			—			13,034
	Additional paid-in capital		687,421			17,828			705,249
	Treasury stock, at cost; 416,666 shares		(9,682	)		—			(9,682	)
	Accumulated other comprehensive loss		(41,082	)		3,716			(37,366	)
	Retained earnings		68,678			(194,570	)		(125,892	)

Total stockholders' equity			718,369			(173,026	)		545,343

Total liabilities and stockholders' equity		$	1,567,601		$	(182,055	)	$	1,385,546

F-93

21. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Our Senior Notes were guaranteed by all of our domestic subsidiaries, all of which are wholly-owned. The guarantees are joint and several, full, complete and unconditional. There are no restrictions on the ability of the subsidiary guarantors to transfer funds to the parent company.

The accompanying condensed consolidating financial information has been prepared and presented pursuant to SEC Regulation S-X Rule 3-10, "Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered." The information is not intended to present the financial position, results of operations and cash flows of the individual companies or groups of companies in accordance with accounting principles generally accepted in the United States of America.

The 6.375% Senior Notes were guaranteed by the Guarantor A group of subsidiaries, which consists of substantially all of our subsidiaries. The 8.375% Senior Notes and the 14% Senior Subordinated Notes were guaranteed by the Guarantor A group of subsidiaries and Guarantor B, which is OEI. Substantially all of the assets of OEI were oil and gas properties which were sold by us in August 2003 (see Note 7—"Discontinued Operations—Sale of Oil and Natural Gas Properties").

CONDENSED CONSOLIDATING BALANCE SHEET

		December 31, 2003
		Parent Company			Guarantor A Subsidiaries		Guarantor B Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
		(in thousands)
Assets:
	Current assets	$	140,844		$	153,716	$	40		$	20,702		$	—		$	315,302
	Net property and equipment		53,344			607,309		—			28,424			—			689,077
	Goodwill, net		(11,856	)		344,631		—			954			—			333,729
	Deferred costs, net		14,433			—		—			—			—			14,433
	Inter-company receivables		629,175			—		—			—			(629,175	)		—
	Other assets		12,276			11,538		—			(117	)		—			23,697

TOTAL ASSETS			838,216			1,117,194		40			49,963			(629,175	)		1,376,238

Liabilities and equity:
	Current liabilities		86,700			64,943		316			11,590			—			163,549
	Long-term debt		521,445			—		—			—			—			521,445
	Capital lease obligations		(4,355	)		15,561		—			—			—			11,206
	Inter-company payables		—			599,443		707			29,025			(629,175	)		—
	Deferred tax liability		101,203			20		1,811			2,005			—			105,039
	Other long-term liabilities		48,223			400		—			289			—			48,912
	Stockholders' equity		85,000			436,827		(2,794	)		7,054			—			526,087

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY		$	838,216		$	1,117,194	$	40		$	49,963		$	(629,175	)	$	1,376,238

F-94

		December 31, 2002 (Restated)
		Parent Company			Guarantor A Subsidiaries		Guarantor B Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
		(in thousands)
Assets:
	Current assets	$	38,773		$	138,851	$	980		$	17,310		$	—		$	195,914
	Net property and equipment		46,318			687,493		30,890			28,699			—			793,400
	Goodwill, net		75,491			240,255		—			795			—			316,541
	Deferred costs, net		13,324			—		—			—			—			13,324
	Inter-company receivables		645,042			—		—			—			(645,042	)		—
	Other assets		18,169			12,696		435			(91	)		—			31,209

TOTAL ASSETS			837,117			1,079,295		32,305			46,713			(645,042	)		1,350,388

Liabilities and equity:
	Current liabilities		62,321			54,348		6,587			5,634			—			128,890
	Long-term debt		472,972			—		—			—			—			472,972
	Capital lease obligations		(5,391	)		19,513		—			—			—			14,122
	Inter-company payables		—			597,626		13,082			34,334			(645,042	)		—
	Deferred tax liability		134,088			3		(186	)		2,306			—			136,211
	Other long-term liabilities		35,670			1,078		10,862			24			—			47,634
	Stockholders' equity		137,457			406,727		1,960			4,415			—			550,559

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY		$	837,117		$	1,079,295	$	32,305		$	46,713		$	(645,042	)	$	1,350,388

		June 30, 2002 (Restated)
		Parent Company			Guarantor A Subsidiaries		Guarantor B Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
		(in thousands)
Assets:
	Current assets	$	79,289		$	115,202	$	1,005		$	11,047		$	—		$	206,543
	Net property and equipment		32,625			560,681		31,304			24,613			—			649,223
	Goodwill, net		3,269			199,031		—			775			—			203,075
	Deferred costs, net		11,405			—		—			—			—			11,405
	Inter-company receivables		486,405			—		—			—			(486,405	)		—
	Other assets		17,706			6,266		436			—			—			24,408

TOTAL ASSETS			630,699			881,180		32,745			36,435			(486,405	)		1,094,654

Liabilities and equity:
	Current liabilities		58,783			44,520		6,098			3,374			—			112,775
	Long-term debt		421,378			—		—			—			—			421,378
	Capital lease obligations		(6,153	)		21,372		—			—			—			15,219
	Inter-company payables		—			449,017		13,964			23,424			(486,405	)		—
	Deferred tax liability		115,764			18		(137	)		2,367			—			118,012
	Other long-term liabilities		21,238			1,261		8,387			(15	)		—			30,871
	Stockholders' equity		19,689			364,992		4,433			7,285			—			396,399

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY		$	630,699		$	881,180	$	32,745		$	36,435		$	(486,405	)	$	1,094,654

F-95

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

		Year Ended December 31, 2003
		Parent Company			Guarantor A Subsidiaries			Guarantor B Subsidiary			Non- Guarantor Subsidiaries			Consolidated
		(in thousands)
Revenues		$	—		$	880,521		$	—		$	45,118		$	925,639
Costs and expenses:
	Direct expenses		—			642,026			—			27,781			669,807
	Depreciation, depletion and amortization expense		6,205			87,669			—			4,193			98,067
	Write-off and impairment of property and equipment		(2,914	)		64,706			—			1,625			63,417
	Loss associated with the South Texas Matters		—			5,225			—			—			5,225
	General and administrative expense		44,809			54,217			—			4,493			103,519
	Interest		49,456			(537	)		—			72			48,991
	Gain on early extinguishment of debt		(16	)		—			—			—			(16	)
	Other		(636	)		21			—			816			201

Total costs and expenses			96,904			853,327			—			38,980			989,211

Income (loss) from continuing operations before income taxes			(96,904	)		27,194			—			6,138			(63,572	)
Income tax benefit (expense)			21,927			—			—			(3,972	)		17,955

Income (loss) from continuing operations			(74,977	)		27,194			—			2,166			(45,617	)

Discontinued operations, net of tax benefit of $2,763			—			—			(4,754	)		—			(4,754	)

NET INCOME (LOSS)		$	(74,977	)	$	27,194		$	(4,754	)	$	2,166		$	(50,371	)

F-96

		Six Months Ended December 31, 2002 (Restated)
		Parent Company			Guarantor A Subsidiaries			Guarantor B Subsidiary			Non- Guarantor Subsidiaries			Consolidated
		(in thousands)
Revenues		$	—		$	389,646		$	—		$	14,771		$	404,417
Costs and expenses:
	Direct expenses		—			275,539			—			9,502			285,041
	Depreciation, depletion and amortization expense		2,067			44,852			—			1,000			47,919
	Write off and impairment of property and equipment		(1	)		7,294			—			(94	)		7,199
	General and administrative expense		19,382			31,641			—			901			51,924
	Interest		22,947			(1,196	)		—			72			21,823
	Gain on early extinguishment of debt		(18	)		—			—			—			(18	)
	Other		(360	)		35			—			(140	)		(465	)

Total costs and expenses			44,017			358,165			—			11,241			413,423

Income (loss) from continuing operations before income taxes			(44,017	)		31,481			—			3,530			(9,006	)
Income tax benefit (expense)			2,159			—			—			(1,174	)		985

Income (loss) from continuing operations		$	(41,858	)	$	31,481		$	—		$	2,356		$	(8,021	)

Discontinued operations, net of tax benefit of $1,437			—			—			(2,472	)		—			(2,472	)
Cumulative effect on prior years of a change in accounting principle, net of tax expense of $(944)			—			(1,625	)		—			—			(1,625	)

NET INCOME (LOSS)		$	(41,858	)	$	29,856		$	(2,472	)	$	2,356		$	(12,118	)

F-97

		Year Ended June 30, 2002 (Restated)
		Parent Company			Guarantor A Subsidiaries			Guarantor B Subsidiary			Non- Guarantor Subsidiaries			Consolidated
		(in thousands)
Revenues		$	—		$	760,524		$	—		$	33,315		$	793,839
Costs and expenses:
	Direct expenses		—			530,706			—			26,888			557,594
	Depreciation, depletion and amortization expense		1,852			71,093			—			4,087			77,032
	Write off and impairment of property and equipment		66			39,835			—			209			40,110
	General and administrative expense		28,424			33,700			—			2,336			64,460
	Interest		43,478			(725	)		—			331			43,084
	Loss on early extinguishment of debt		4,019			—			—			—			4,019
	Other		(1,159	)		(1,133	)		—			7			(2,285	)

Total costs and expenses			76,680			673,476			—			33,858			784,014

Income (loss) from continuing operations before income taxes			(76,680	)		87,048			—			(543	)		9,825
Income tax benefit (expense)			(4,654	)		—			—			35			(4,619	)

Income (loss) from continuing operations			(81,334	)		87,048			—			(508	)		5,206

Discontinued operations, net of tax benefit of $631			—			—			(1,085	)		—			(1,085	)

NET INCOME (LOSS)		$	(81,334	)	$	87,048		$	(1,085	)	$	(508	)	$	4,121

		Year Ended June 30, 2001 (Restated)
		Parent Company			Guarantor A Subsidiaries			Guarantor B Subsidiary			Non- Guarantor Subsidiaries			Consolidated
		(in thousands)
Revenues		$	—		$	811,214		$	—		$	54,696		$	865,910
Costs and expenses:
	Direct expenses		—			543,157			—			41,836			584,993
	Depreciation, depletion and amortization expense		951			71,345			—			4,766			77,062
	Write off and impairment of property and equipment		428			7,714			—			(2,459	)		5,683
	General and administrative expense		22,101			37,289			—			3,429			62,819
	Interest		53,067			31			—			332			53,430
	Loss (gain) on early extinguishment of debt		1,979			—			—			—			1,979
	Other		(2,018	)		(50	)		—			180			(1,888	)

Total costs and expenses			76,508			659,486			—			48,084			784,078

Income (loss) from continuing operations before income taxes			(76,508	)		151,728			—			6,612			81,832
Income tax expense			(33,880	)		—			—			(2,395	)		(36,275	)

Income (loss) from continuing operations			(110,388	)		151,728			—			4,217			45,557

Discontinued operations, net of tax benefit of $616			—			—			(997	)		—			(997	)

NET INCOME (LOSS)		$	(110,388	)	$	151,728		$	(997	)	$	4,217		$	44,560

F-98

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

	Year Ended December 31, 2003
	Parent Company			Guarantor A Subsidiaries			Guarantor B Subsidiary			Non- Guarantor Subsidiaries			Consolidated
	(in thousands)
Net cash provided by (used in) operating activities	$	(54,255	)	$	178,719		$	(9,279	)	$	9,408		$	124,593
Net cash provided by (used in) investing activities		84,061			(175,278	)		17,428			(10,257	)		(84,046	)
Net cash provided by (used in) financing activities		65,119			(3,952	)		(7,900	)		—			53,267
Effect of exchange rate changes on cash		—			—			—			404			404

Net increase (decrease) in cash		94,925			(511	)		249			(445	)		94,218

Cash at beginning of period		5,184			1,166			(258	)		2,900			8,992

Cash at end of period	$	100,109		$	655		$	(9	)	$	2,455		$	103,210

	Six Months Ended December 31, 2002 (Restated)
	Parent Company			Guarantor A Subsidiaries			Guarantor B Subsidiary			Non- Guarantor Subsidiaries			Consolidated
	(in thousands)
Net cash provided by (used in) operating activities	$	(62,707	)	$	103,124		$	165		$	(1,109	)	$	39,473
Net cash used in investing activities		(33,886	)		(100,338	)		(28	)		2,047			(132,205	)
Net cash provided by (used in) financing activities		49,037			(1,859	)		—			—			47,178
Effect of exchange rate changes on cash		—			—			—			305			305

Net increase (decrease) in cash		(47,556	)		927			137			1,243			(45,249	)

Cash at beginning of period		52,740			239			(395	)		1,657			54,241

Cash at end of period	$	5,184		$	1,166		$	(258	)	$	2,900		$	8,992

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	Year Ended June 30, 2002 (Restated)
	Parent Company			Guarantor A Subsidiaries			Guarantor B Subsidiary			Non- Guarantor Subsidiaries			Consolidated
	(in thousands)
Net cash provided by (used in) operating activities	$	103,584		$	65,153		$	(604	)	$	7,875		$	176,008
Net cash used in investing activities		(43,941	)		(64,018	)		(371	)		(3,601	)		(111,931	)
Net cash provided by (used in) financing activities		(8,547	)		1,686			—			—			(6,861	)
Effect of exchange rate changes on cash		—			—			—			(5,087	)		(5,087	)

Net increase (decrease) in cash		51,096			2,821			(975	)		(813	)		52,129

Cash at beginning of period		1,644			(2,582	)		580			2,470			2,112

Cash at end of period	$	52,740		$	239		$	(395	)	$	1,657		$	54,241

	Year Ended June 30, 2001 (Restated)
	Parent Company			Guarantor A Subsidiaries			Guarantor B Subsidiary			Non- Guarantor Subsidiaries			Consolidated
	(in thousands)
Net cash provided by operating activities	$	97,325		$	31,502		$	(254	)	$	9,346		$	137,919
Net cash used in investing activities		(43,588	)		(38,497	)		217			(6,836	)		(88,704	)
Net cash provided by (used in) financing activities		(163,508	)		6,525			—			—			(156,983	)

Net increase (decrease) in cash		(109,771	)		(470	)		(37	)		2,510			(107,768	)

Cash at beginning of period		111,415			(2,112	)		617			(40	)		109,880

Cash at end of period	$	1,644		$	(2,582	)	$	580		$	2,470		$	2,112

22. SUBSEQUENT EVENTS

Repayment of 14% Senior Subordinated Notes

On January 15, 2004, we redeemed the $97.5 million outstanding principal amount of our 14% Senior Subordinated Notes. The notes were redeemed at a redemption price of 107% of the principal amount outstanding plus accrued and unpaid interest to the redemption date, for a total cash outlay of $111.2 million.

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Litigation

Class Action Lawsuits

Since June 2004, we have been named as a defendant in six class action complaints, which have been filed in federal district court in Texas, for alleged violations of federal securities laws. These six complaints have been consolidated into one action. The complaint names Richard J. Alario, James J. Byerlotzer, Francis D. John, and Royce W. Mitchell as defendants. The complaint is brought on behalf of a putative class of purchasers of our securities between April 29, 2003 and June 4, 2004. The complaints generally allege that we made false and misleading statements and omitted material information from our public statements and Commission reports during the class period in violation of the Exchange Act, 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. We have filed a motion to dismiss the case. Each of the individual defendants have also filed a motion to dismiss. On August 11, 2006, the court denied our motion to dismiss, but granted dismissals as to Messrs. Alario and Byerlotzer. We filed our answer to the consolidated amended complaint on September 11, 2006. The case is set for trial on April 2, 2007.

Derivative Actions

Three shareholder derivative actions have also been filed by certain of our shareholders. 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 have been named as defendants in one or more of those actions. Those actions are 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. The first derivative suit was filed in state court in Midland, Texas. The plaintiff in that case has amended its petition to assert claims against our independent public accountants, KPMG LLP. We have filed a motion to dismiss all claims in that action, which was granted by the court on March 29, 2005 for failure to make demand on the directors before filing suit. The plaintiff appealed that ruling. On May 18, 2006, the intermediate Court of Appeals issued an opinion affirming the trial court's ruling that the plaintiff had not pleaded sufficient facts to excuse its failure to make demand, but reversing on procedural grounds. We filed a motion for rehearing, which was denied June 15, 2006, and we have commenced an appeal to the Texas Supreme Court. The two other derivative suits were filed in federal court in El Paso, Texas on December 10, 2004. Those actions were transferred to federal court in Midland, Texas and consolidated by agreement of the parties. We filed a motion to dismiss or to stay that consolidated action. The individual defendants filed motions to dismiss as well. On July 10, 2006, the court entered an order dismissing

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those two derivative actions for failure to make a demand. The remaining derivative case is still on appeal.

In each of the matters described above, plaintiffs are seeking an unspecified amount of monetary damages. At this time, we cannot ascertain the ultimate aggregate amount of monetary liability or financial impact of the class actions and derivative lawsuits. We cannot determine whether these actions, suits, claims, and proceedings, will, individually or collectively, have a material adverse effect on our business, results of operations, and financial condition. We and any named director and officer intend to vigorously defend these actions, suits, claims and proceedings.

Litigation with Former Officers and Employees

On April 7, 2006, we delivered a notice to our former chief executive officer, Francis D. John, of our intention to treat his termination of employment effective May 1, 2004, as "for cause" under his employment agreement with us. In response to the notice, Mr. John has filed a lawsuit against us, in which he alleges, among other things, that we breached stock option agreements and his employment agreement. On June 13, 2006, we filed an answer and counterclaim, as well as a motion to dismiss parts of his claims in response to Mr. John's lawsuit. In addition to denying Mr. John's claims, we asserted claims against Mr. John for breach of contract and declaratory judgment including, among other things, a declaration that "cause" exists under Mr. John's employment agreement. We previously recorded a $16.4 million severance expense in connection with Mr. John's termination of employment, of which $9.0 million represented a non-cash charge for the write-off of the unamortized balance of Mr. John's prepaid retention bonus, and the balance consisted of a reserve for severance and other termination costs. We have not paid any severance or termination costs to Mr. John, other than his base salaries in the 90-day period after the date of his termination. Mr. John would not be entitled to severance, certain other previously paid compensation or stock options under a "for cause" termination. In addition, the Company may be able to recover the unamortized balances of his prepaid retention bonus and stock options. On August 8, 2006, the court denied our motion to dismiss certain of Mr. John's claims, and denied in part and granted in part Mr. John's motion to dismiss certain of our claims. Discovery is underway.

We have also been named in a lawsuit by our former general counsel, Jack D. Loftis, Jr., 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.

Additionally, on August 21, 2006, our former chief financial officer, Royce W. Mitchell, filed a suit against the Company in 385^th District Court, Midland County, Texas alleging breach of contract with regard to alleged bonuses, benefits and expense reimbursements, conditional stock, stock options, to which he believes himself entitled; as well as relief under theories of quantum meruit, promissory estoppel, and specific performance. Further, our former controller and assistant controller filed a joint

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complaint against the Company on September 3, 2006 in 133^rd District Court, Harris County, Texas alleging constructive termination and breach of contract.

We intend to vigorously defend against these claims; however, we cannot predict the outcomes of these cases.

Other Matters

In addition, a class action lawsuit,Gonzalez v. Key Energy Services, Inc., was filed in Ventura County, California, Superior Court in September 2005 alleging that Key did not pay its hourly employees for travel time between the yard and wellhead and that certain employees were denied meal and rest periods during shifts. Our preliminary investigations into these allegations are ongoing and a class has not been certified. We intend to vigorously defend against this action; however, we cannot predict the outcome of the lawsuit.

Investigations

Audit Committee Investigation

Beginning in March 2004, the Audit Committee of our Board of Directors, with the assistance of outside counsel, conducted an investigation, which included a review of the prior investigation of the South Texas Matters and an independent investigation of aspects of our disclosure controls and procedures, our internal control structure and processes, and other matters that arose in connection with the investigation. Among the matters considered in the investigation were the circumstances surrounding communications by our former chief executive officer, Francis D. John, with analysts following our March 15, 2004 press release, and allegations by our former chief financial officer, Royce W. Mitchell, and our former general counsel, Jack D. Loftis, about possible misconduct by Mr. John. Several of the concerns raised by Messrs. Mitchell and Loftis led to the review of accounting for debt issuance costs, a consulting arrangement and certain stock option grants. See Note 2—"Restatement of Financial Statements—Background of the Restatement."

SEC Investigation

On March 29, 2004, we were notified by the Fort Worth Office of the SEC that it had commenced an inquiry regarding the Company. The SEC issued a formal order of investigation on July 15, 2004. The investigation includes, without limitation, inquiry into our accounting practices and the events that led to the restatement of our financial statements. The investigation also includes inquiry into matters raised by our former chief financial officer and former general counsel.

While we are continuing our efforts to cooperate fully with the SEC in its investigation, we cannot predict the outcome of its investigation.

Grand Jury Subpoena

On January 5, 2005, we were served with a subpoena issued by a grand jury in Midland, Texas, which asked for the production of documents in connection with an investigation being conducted by

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the U.S. Attorney's Office for the Western District of Texas. We do not currently believe that we are a target of this investigation.

While we are continuing our efforts to cooperate fully with the U.S. Attorney's Office in its investigation, we cannot predict the outcome of its investigation.

Management Changes

Richard J. Alario joined us on January 1, 2004 as President and Chief Operating Officer. On May 1, 2004, he was appointed to serve as our Chief Executive Officer and a Director, replacing the former chairman and chief executive officer, Francis D. John, in such executive capacity. On August 25, 2004, the Board of Directors appointed Mr. Alario as Chairman upon the resignation of Mr. John as non-executive chairman and director. We also announced the appointment of David Breazzano as Lead Director.

We paid Mr. John's regular salary for 90 days after the termination of his employment. Other cash payments possibly owed under Mr. John's employment agreement, including salary, bonuses, and severance, have been suspended by us. See "—Litigation—Litigation with Former Officers" above for a description of litigation between Mr. John and the Company.

The employment of our former senior vice president and general counsel Jack D. Loftis, Jr, was terminated on July 8, 2004.

On December 31, 2004, James J. Byerlotzer, who was then serving as vice chairman-safety, retired pursuant to the terms of his employment agreement.

The employment our former chief financial officer, Royce W. Mitchell, was terminated on January 19, 2005.

On January 20, 2005, we named William M. "Bill" Austin as Chief Financial Officer. Mr. Austin succeeded Mr. Mitchell. Mr. Austin had served as our consultant since July 2004.

Newton W. "Trey" Wilson III was hired effective January 24, 2005 as Senior Vice President and General Counsel.

Kim B. Clarke was hired effective November 22, 2004 as Vice President and Chief People Officer. Ms. Clarke was appointed Senior Vice President in December 2005.

J. Marshall Dodson was hired August 22, 2005 to serve as Vice President and Chief Accounting Officer.

New Credit Facility

On July 29, 2005, we entered into a Credit Agreement (the "New Senior Secured Credit Facility") among us, the several lenders from time to time party thereto, Lehman Brothers Inc., as sole lead arranger and sole bookrunner, Lehman Commercial Paper Inc., as syndication agent, administrative agent and as collateral agent, and Wells Fargo Foothill, Inc., as revolving administrative agent. The New Senior Secured Credit Facility consists of (i) a revolving credit facility up to an aggregate principal

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amount of $65.0 million, which will mature on July 29, 2010, (ii) a senior term loan facility in the original aggregate amount of $400.0 million, which will mature on June 30, 2012 and (iii) a prefunded letter of credit facility in the aggregate amount of $82.3 million, which will mature on July 29, 2010. We will pay certain fees in connection with the use of the credit facilities, including a commitment fee as a percentage of the aggregate commitments. The proceeds from the New Senior Secured Credit Facility were used to refinance our existing 8.375% Senior Notes and its 6.375% Senior Notes and for general corporate purposes.

This New Senior Secured Credit Facility contains certain covenants, which, among other things, require the maintenance of a consolidated leverage ratio (defined in the New Senior Secured Credit Agreement generally as the ratio of consolidated total debt to consolidated EBITDA) as follows:

Fiscal Quarter		Consolidated Leverage Ration
Fourth Fiscal Quarter, 2005		3.5 : 1.0
First Fiscal Quarter, 2006		3.0 : 1.0
Second Fiscal Quarter, 2006		3.0 : 1.0
Third Fiscal Quarter, 2006, and thereafter		2.75 : 1.0

Borrowings under the New Senior Credit Facility bear interest based upon, at the Company's option, the prime rate plus a margin of 1.75% or a Eurodollar rate plus a margin of 2.75%. At December 31, 2005 the margins were increased by .50% because the Company did not meet certain filing targets for the 2003 Annual Report on Form 10-K as set forth in the agreement. As of June 30, 2006, the Company had no borrowings under the revolving portion of the New Senior Credit Facility and $398.0 million borrowed at three-month Eurodollar rates, plus a margin of 3.75%, which includes an additional 50 basis points effective June 30, 2006, following our inability to file the 2003 Annual Report on Form 10-K by such date.

The New Senior Secured Credit Facility also requires that we maintain a consolidated interest coverage ratio generally as the ratio of consolidated EBITDA to consolidated interest expense as of the last day of any fiscal quarter beginning with the fourth fiscal quarter of 2005 of not less than 3.0 to 1.0. Upon the occurrence of certain events of default, our obligations under the New Senior Secured Credit Facility may be accelerated. Such events of default include payment defaults to lenders under the New Senior Secured Credit Facility, covenant defaults and other customary defaults. They also include failure to provide audited financial statements to the lenders by March 16, 2007.

Amendment to New Senior Secured Credit Facility for Increased Capital Expenditures

On November 3, 2005, we amended New Senior Credit Facility to increase the amount of capital expenditures allowed under the facility during 2005 and 2006. Under the terms of the amendment, we may make annual capital expenditures of $175.0 million for 2005 and $200 million for 2006. Additionally, under certain conditions, up to $25.0 million of the capital expenditure limit, if not spent in the permitted fiscal year, may be carried over for expenditure in the next succeeding fiscal year. Previously, we were limited in both years to annual capital expenditures of $150.0 million.

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Subsequent Amendments to the Existing Senior Credit Facility

Our failure to file our 2003 Annual Report on Form 10-K on a timely basis violated covenants under the Existing Senior Credit Facility. Since March 31, 2004, we amended the terms of our then-existing facility six times to waive the covenant for non-compliance and extend the due date for this and other filings. The final due date under the then existing facility for the filing of the 2003 Annual Report on Form 10-K was July 31, 2005. In addition, pursuant to the last amendment, the due date for filing of our Annual Report on Form 10-K for 2004 and the Quarterly Reports on Form 10-Q for the first three quarters of 2004 was October 31, 2005. The last amendment also extended the date by which the Quarterly Reports on Form 10-Q for the first quarter and second quarter of 2005 had to be filed to December 31, 2005. On July 29, 2005, we entered into the New Senior Secured Credit Facility, which replaced the Existing Senior Credit Facility.

Subsequent Consents to Amend to Extend the Reporting Requirements Under the Senior Note Indentures

Our failure to file our 2003 Annual Report on Form 10-K report with the SEC and deliver it to the trustee under the Senior Note indentures on or before March 30, 2004 was a default under each of the indentures for the Senior Notes. Since March 31, 2004, we amended the terms of each of the Senior Note indentures three times to waive the covenant non-compliance and extend the due date for this and other filings. We were required under the last consent by the holders of each series of Senior Notes to file our 2003 Annual Report on Form 10-K on or before May 31, 2005 and our 2004 Quarterly Reports on Form 10-Q and our Annual Report on Form 10-K for 2004 on or before July 31, 2005. The consent also provided that the Quarterly Reports on Form 10-Q for the first quarter and second quarter of 2005 had to be filed no later than October 31, 2005. We failed to meet those deadlines, and as a result, on June 6, 2005, the trustee for the Senior Notes sent us notice of the financial reporting violation, which then 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 and, the 6.375% Senior Notes were repaid on October 5, 2005. We also redeemed all of the 8.375% Senior Notes on November 8, 2005. The 6.375% Senior Notes and the 8.375% Senior Notes were repaid with funds from our New Senior Secured Credit Facility and cash on hand.

Other Extensions and Modifications

On December 1, 2002, we entered into an agreement with Liberty Mutual, our primary casualty insurance carrier, which provided security for future payments to be made by Liberty Mutual under various insurance policies. The security included a $6 million promissory note and a $3 million bond. Additional security was in the form of a letter of credit. The security agreement required the presentation of audited annual financial statements and maintenance of an S&P rating of BB and a Moody's rating of Ba3. On April 5, 2004, Liberty Mutual amended the date by which we must deliver audited annual financial statements and reduced the credit ratings triggers to September 30, 2004. After we amended the agreement with our primary casualty carrier, our Standard & Poor's long-term corporate and senior unsecured debt rating was downgraded from B+ to B and our Moody's senior unsecured issuer rating was downgraded from B1 to B2. As a result of these downgrades, we were

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required to replace the promissory note and bond with letters of credit within 30 days after such downgrade. Such 30-day period was set to expire on July 8, 2004; however, we entered into a letter agreement effective as of July 2, 2004, that required us to provide a letter of credit for the $6 million promissory note within 20 days from July 2, 2004. The primary casualty carrier agreed that it would not exercise any other remedies under the agreement until the 20-day period expired. We subsequently arranged in July 2004 to increase the amount of the letter of credit by $9 million to replace both the promissory note and the bond.

Some lessors refused to grant such waivers and demanded a payoff. Between June 1, 2005 and August 4, 2005, three lessors were paid an aggregate amount of $16.1 million to satisfy lease obligations and exercise equipment purchase options.

We entered into two new master lease agreements on August 31, 2005 and on October 14, 2005 with a new lessor. Some of the equipment, which was being leased under those leases that had demanded pay-off, was transferred to this new lessor through sale/leaseback transactions. We received an aggregate amount of $10.5 million from the sale/leaseback transactions. We will be required to seek a waiver with this lessor.

Investment in IROC Systems Corp.

On July 22, 2004, we announced that we entered into an agreement with IROC Systems Corp. ("IROC"), an Alberta-based oilfield services company, to sell ten remanufactured Skytop well service rigs with supporting equipment and inventory. We delivered the service rigs in the fall of 2004 and these rigs are being operated by IROC in Western Canada.

The purchase price for the service rigs was $7.0 million USD, which amount was converted at an agreed exchange rate of 0.7634 to $9.17 million dollars CDN, and was paid by way of the issuance of 8,187,058 common shares of IROC (the "Consideration Shares") at a deemed issuance price of $1.12 CDN per share. On June 2005, we announced that we would sell additional well service rig support equipment to IROC for $0.9 million USD and in return would receive an additional 547,411 shares of IROC at a deemed issuance price of $2.09 CDN per share. As of August 31, 2006, we own 8,734,469 shares of IROC (representing 23.1% of IROC's shares). The shares trade on the Toronto Venture Stock Exchange and had a closing price of $2.60 CDN per share on August 31, 2006. Pursuant to the terms of the agreement with IROC, Mr. Austin, our Chief Financial Officer, and Mr. Wilson, our General Counsel, were appointed to the board of IROC.

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Extinguishment of 5% Convertible Notes

On September 25, 2004, we retired the $18.7 million principal amount outstanding of our 5% Convertible Notes. The notes were paid at par. We used cash on hand and borrowings under our revolving credit facility to redeem the 5% Convertible Notes.

Sale of Contract Drilling Assets

On December 7, 2004, we announced that we signed a definitive agreement with Patterson-UTI Energy, Inc. to sell a portion of our U.S. land drilling assets for $62.0 million in cash, excluding working capital, net of other liabilities, of which approximately $10.0 million Key will retain. The assets consisted of 25 active rigs in the Permian Basin, San Juan Basin and Rocky Mountain regions. In addition, our land drilling business sold to Patterson-UTI included ten stacked rigs as well as heavy haul transport vehicles and other related drilling equipment. The active rigs were mechanical with an average of approximately 700 horsepower and depth ratings of approximately 10,000 feet. The sale of the contract drilling assets subsequently closed on January 15, 2005. We continue to provide limited contract drilling services to oil and natural gas producers in the continental United States in the Northeast, Powder River Basin of Wyoming and internationally in Argentina.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors
Key Energy Services, Inc.:

We have audited the accompanying consolidated balance sheets of Key Energy Services, Inc. and subsidiaries (the Company) as of December 31, 2003 and 2002 and June 30, 2002, and the related consolidated statements of operations, stockholders' equity, comprehensive income, and cash flows for the year ended December 31, 2003, the six months ended December 31, 2002 and each of the years in the two-year period ended June 30, 2002. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated 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.

As discussed in Note 1 to the consolidated financial statements, in connection with the year ended December 31, 2003, the Company identified errors in its accounting for fixed assets. Specifically, the Company determined that certain fixed assets were not in its possession and that certain fixed assets were impaired. As a result, the Company recorded a $40.6 million write-off for fixed assets not in its possession and $10.2 million in write-downs for fixed asset impairments. The Company was unable to identify and appropriately evidence the periods to which such errors relate but elected to record the corrections in the year ended December 31, 2003. This accounting is not in accordance with APB Opinion No. 20,Accounting Changes, which requires that the correction of an error be made through a restatement of the financial statements for the period in which the error occurred.

In our opinion, because of the effects of the matters discussed in the preceding paragraph, the financial statements referred to above do not present fairly, in conformity with accounting principles generally accepted in the United States of America, the financial position of Key Energy Services, Inc. and subsidiaries as of December 31, 2002 and June 30, 2002, or the results of its operations or its cash flows for the year ended December 31, 2003, the six months ended December 31, 2002 and each of the years in the two-year period ended June 30, 2002.

In our opinion, the consolidated balance sheet of Key Energy Services, Inc. and subsidiaries as of December 31, 2003, presents fairly, in all material respects, the financial position of Key Energy Services, Inc. and subsidiaries as of December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations in the six months ended December 31, 2002, the Company changed its method of accounting for goodwill and other intangible assets in the year ended June 30, 2002, and the Company changed it method of accounting for derivative instruments and hedging activities in the year ended June 30, 2001.

/s/ KPMG LLP
Dallas, Texas
October 19, 2006

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CONTROLS AND PROCEDURES

Section 404 of the Sarbanes-Oxley Act and the SEC's regulations require management to assess the effectiveness of our internal control over financial reporting as of the end of our fiscal year. Our independent public accountants are also required to audit our assessment and to provide a report based on their audit. These requirements apply to fiscal years ended December 31, 2004 and thereafter. Therefore, we have not conducted a formal assessment of our internal control over financial reporting or obtained an auditor report on internal control over financial reporting in connection with this report. During the course of the restatement, however, we identified material weaknesses in our internal control over financial reporting that lead us to conclude that our internal control over financial reporting was not effective as of December 31, 2003. SEC regulations also require us to assess the effectiveness of our disclosure controls and procedures as of December 31, 2003. We also determined that our disclosure controls and procedures were not effective as of December 31, 2003.

Background

During the third quarter of 2003, our Internal Audit department conducted an operations audit of our South Texas Division. As a result of certain improprieties found during this audit (as well as previous indications of malfeasance at the South Texas Division that were investigated in 2002 but could not be substantiated at that time), we began an investigation in the fourth quarter of 2003. In light of the South Texas matters, which raised issues with respect to our controls relating to fixed assets, we conducted a review and determined that we were also unable to generate a balance sheet for each of our yards in order to identify our fixed assets on a yard-by-yard basis. Further, in March 2004, while we were attempting to complete our 2003 consolidated financial statements, a review of reports generated by our centralized maintenance management system ("CMMS") raised questions whether certain fixed assets (primarily rigs and heavy duty trucks) were being accounted for appropriately. This prompted a company-wide enhanced level of review relating to our fixed assets to confirm the equipment's existence, condition, and values and whether the accounting treatment had been appropriate. In March 2004, we determined that this review would result in a restatement of prior period financial statements. While the restatement originated with the identification of issues concerning fixed asset accounting, in the course of the restatement process we identified numerous other accounting matters for which restatements and adjustments were required. As set forth in this report, we have restated our financial statements for fiscal years prior to 2003, and have made adjustments in the 2003 fiscal year, in order to reflect asset values in historical periods, to address other fixed asset accounting issues, and to correct numerous other accounting errors that were identified during the course of the restatement process. This restatement process, as well as information regarding its impact, is discussed in the sections entitled "Management's Discussion and Analysis of Results of Operations and Financial Condition—Background of the Restatement" and "—Business Impact of the Restatement" and "Consolidated Financial Statements and Supplementary Data," Note 2—"Restatement of Financial Statements."

Disclosure Controls and Procedures

Disclosure controls and procedures include, without limitation, controls and procedures designed to reasonably assure that information required to be disclosed in our reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures are also designed to reasonably assure that such information is accumulated and communicated to our management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. In light of the restatement and the events leading up to it, management concluded that our disclosure controls and procedures were not effective as of December 31, 2003.

In addition, the following events raised questions regarding the adequacy of our disclosure controls and procedures as of March 2004. Preceding the March 15, 2004 issuance of a press release announcing our inability to timely file our 2003 Annual Report on Form 10-K, several members of management, the Audit Committee and outside counsel emphasized to our former chief executive officer, Francis D. John, the importance of staying within the boundaries of the press release when speaking to investors about the matters reported in the release. Shortly after the issuance of the March 15th announcement, our Vice President of Investor Relations, John Daniel, reported to our former general counsel, Jack D. Loftis, Jr., that Mr. John had made statements to certain analysts that were inconsistent with the content of the press release. Mr. Loftis and our former chief financial officer, Royce W. Mitchell, reported this issue plus other matters to the Audit Committee. We reported this matter to the SEC.

Following these events, the Board of Directors adopted a formal Regulation FD policy governing communications with market participants. We engaged outside counsel to conduct a training session for management on the selective disclosure rules shortly after the adoption of our policy. We have had subsequent Regulation FD training with management and will continue to provide regular training to insure compliance with the policy.

Internal Control Over Financial Reporting

Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Internal control over financial reporting includes policies and procedures, and the proper implementation and execution of such policies and procedures that:

•: pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the issuer;
•: provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the issuer are made in accordance with authorizations of management and directors of the issuer; and
•: provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the issuer's assets that could have a material effect on the financial statements.

A material weakness is a control deficiency, or combination of control deficiencies, that results in a more than remote likelihood that a material misstatement of the annual or interim financial statements of an issuer will not be prevented or detected on a timely basis by management or employees in the normal course of their assigned functions.

While we have not conducted a formal assessment of internal control over financial reporting, we identified material weaknesses in our internal control over financial reporting that existed as of December 31, 2003. The following is a description of the steps we have taken or are taking to remediate such weaknesses.

Fixed Asset Matters

In our review of fixed assets, we identified numerous issues in internal controls affecting our fixed assets that culminated in the identification of material weaknesses in (1) our controls surrounding our monitoring of the status and condition of our fixed assets and the appropriate recording of the results of any changes in our financial statements, and (2) the lack of controls to ensure proper capitalization of costs in accordance with GAAP, all of which resulted in misstatements of fixed assets on our balance

sheets for the restated periods and of depreciation expense for those periods. The combination of factors that led to these material weaknesses included:

•: CMMS, an operational equipment tracking system that was not integrated with the fixed asset sub-ledger that supports the consolidated financial statements, failure to accurately record information on either CMMS or the fixed asset sub-ledger and failure to integrate or reconcile the equipment shown on CMMS to the accounting records;
•: failure to properly inventory, monitor or track assets identified in CMMS;
•: failure to adequately safeguard assets at various company locations;
•: a procurement system that allowed management overrides at the yard and division levels, including purchase authorizations and invoice approvals;
•: a weak control environment surrounding the recording and tracking of our fixed assets and the maintenance records of such assets;
•: inadequate controls for system access at the yard, division and corporate levels, which allowed management overrides;
•: lack of managerial oversight at the yard and division level to insure proper accounting of fixed assets;
•: inadequate documentation of policies and procedures;
•: ineffective monitoring of compliance with existing policies and procedures; and
•: insufficient documentation and performance of due diligence procedures for fixed asset transactions.

Since December 31, 2003, we have implemented, or are in the process of implementing, control improvements with respect to fixed assets in the following areas:

•: a company-wide physical inventory of all fixed assets, which was completed in 2004 and reconciled to CMMS and to the fixed asset ledger;
•: establishment of several full-time divisional asset manager positions independent of facility operations;
•: procedures for physical inventories to be performed on a periodic basis, but at least annually, at each facility;
•: procedures established domestically for identification of all capitalized equipment (including numbering and digital photographing) and tracking of such information in CMMS;
•: enhanced physical security safeguards for idle fixed assets at company facilities;
•: monthly physical counts of idle assets and reconciliation of findings to CMMS, and, prospectively, reconciling CMMS information to information in the fixed asset sub-ledger;
•: prospectively, periodic reviews of changes in condition of equipment and, when an event occurs that results in an asset no longer being in working condition, determination of the asset's remaining useful life and salvage value;
•: procedures for monitoring equipment transfers between our physical locations and approval by each of the yard manager, division manager, asset manager, division controller and division vice president for the disposition of assets; and
•: enhanced procedures for approvals and documentation of capital expenditures, including confirmation that authorizations for expenditures conform to approved capital expenditure criteria and that equipment is timely and properly recorded to fixed asset ledger when placed into service.

Other Matters

As a result of the restatement process, we became aware of a material weakness in our internal control over financial reporting consisting of the lack of accounting processes and lack of qualified accounting personnel to develop such processes or execute such processes, which contributed to misstatements in our financial statements for the periods that have been restated or which resulted in charges or adjustments in our 2003 financial statements. The combination of factors that led to the material weakness included:

•: no disciplined "close" process—such as formal desk procedures for recurring entries, analysis of general ledger account balances and timely reconciliation and resolution of long-outstanding items—at the corporate level;
•: inadequate GAAP, financial reporting expertise and tax expertise within the accounting organization;
•: inadequate communication between accounting and other departments, such as environmental or legal;
•: inadequate administration of stock option program;
•: lack of supervision and review among the internal accounting staff;
•: insufficient number of accounting personnel at the corporate level;
•: lack of segregation of duties related to manual journal entry preparation;
•: inadequate review and lack of segregation for procurement activities;
•: lack of formal documentation of policies and procedures;
•: absence of formal evidence to substantiate that monitoring activities were adequately performed and inadequate staffing to provide effective monitoring of processes;
•: allowing "shared service" accounting functions, such as payables and receivables, to be handled at the yard or division level, which created inconsistent accounting treatment on a consolidated basis; and
•: absence of appropriate financial reporting support for previously filed Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q.

With respect to the foregoing deficiencies in our accounting processes, we have implemented, or are in the process of implementing, the following control enhancements:

•: implementation of policies, procedures, directives and processes covering the activities for the "shared service" accounting functions of payroll, accounts payable, fixed assets and accounts receivable;
•: realignment of personnel to strengthen the segregation of duties and increase the independence of reporting and monitoring ability;
•: modification of systems and procedures to ensure appropriate segregation of responsibilities; and
•: training sessions on internal control processes and activities.

In addition, our accounting team, lead by the new Chief Accounting Officer, has initiated the following improvements:

•: addition of 14 new accountants with experience in public accounting and financial reporting, tax accounting and reporting and Sarbanes-Oxley Section 404 compliance;
•: centralization of accounting close and reporting responsibilities by transferring such responsibilities from divisional controllers at field locations to newly-created corporate close, reporting and special projects groups located in Houston;

•: centralization of fixed asset accounting responsibility by transferring such responsibility from the division controllers to a dedicated group located at our Midland office; and
•: enhancement of processes for the accounting close, including account reconciliation, journal entry review, reporting and analysis.

In order to monitor the ongoing improvements, we have improved our internal audit function. Since March 2005, we have added three new experienced internal auditors.

Control Environment

We believe that many of the identified deficiencies in our internal control over financial reporting are in large measure attributable to the effects of the Company's decentralized management practices and growth through multiple acquisitions, which were not effectively managed. Since 1994, we have made over 100 acquisitions. These acquired businesses had differing operating cultures, separate accounting systems (until January 2000) and varying management philosophies. We believe that a number of factors contributed, over time, to a deterioration of our fixed asset accounting records and related data and financial disclosures. We believe that the principal factors were rapid growth; untimely integration or failed integration of acquisitions; incomplete supporting documentation and poor due diligence procedures with respect to acquisitions; and inadequate accounting resources. The result was a failure to establish and consolidate effective internal controls over our decentralized businesses.

Current management's and the Board of Directors' experience with the restatement process, and the accounting, documentation and control deficiencies it revealed, leads us to conclude that at many operational levels of the Company there was a lack of accountability and managerial discipline. We believe that former senior management did not create an effective control environment for the organization, did not employ an adequate number of qualified accounting personnel in key accounting and reporting functions, and did not maintain adequate channels of communication to report operational and accounting issues and implement consistent solutions for such issues. We also believe that the physical separation of our executive office, which until 2004 was located in the Northeast, from our operational headquarters in Midland, Texas, also contributed to the lack of accountability, discipline and consistency in the recording of financial information. We further believe that these problems were exacerbated by turnover among senior management, including chief financial officers and controllers.

Beginning in March 2004, the Audit Committee of our Board of Directors, with the assistance of outside counsel, conducted an investigation which included a review of the Company's investigation into the South Texas Matters, as well as an investigation of the disclosure control matter involving communications with analysts described above and other allegations made by Messrs. Loftis and Mitchell about possible misconduct by Mr. John. Several of the concerns raised by Mr. Mitchell and Mr. Loftis led to the review of the accounting for debt issuance costs, a consulting arrangement and certain stock option grants. Based on the results of the Audit Committee investigation, the Committee concluded, among other things, that there had been inadequate communication among members of the Board and between the Board and senior management, including Mr. John, Mr. Mitchell and Mr. Loftis.

Based in part on the findings of the Audit Committee Investigation as well as on subsequent factual investigation, the Company notified Mr. John that it intends to treat his termination of employment effective May 1, 2004 as "for cause" under his employment agreement. In response to the notice, Mr. John has filed a lawsuit against the Company, in which he alleges, among other things, that the Company breached stock option agreements and his employment agreement. The Company has filed an answer to Mr. John's complaint and counterclaim. In addition, the Executive Committee of the Board of Directors requested that Morton Wolkowitz, a member of the Board of Directors and a former chairman of the compensation committee, resign as a director of the Company, effective immediately. Mr. Wolkowitz declined to resign. For additional discussion of these matters, see the sections entitled "Legal Proceedings and Other Actions," and "Executive Compensation—Employment

Agreements and Termination and Change-in-Control Agreements with Named Executive Officers—Termination of Mr. John."

Our Board of Directors has worked actively to remedy the weaknesses identified by the restatement process. Since March 2004, we have appointed a new senior management team comprised of executives who were not involved in the subjects of the restatement and the Audit Committee investigation. Richard J. Alario, who joined us as President and Chief Operating Officer effective January 1, 2004, was promoted to Chief Executive Officer on May 1, 2004 and became Chairman of the Board effective August 25, 2004. In addition, the Board of Directors appointed David J. Breazzano as lead director on August 25, 2004. In November 2004, the Board of Directors appointed Kim B. Clarke as Vice President and Chief People Officer. On January 20, 2005, William M. ("Bill") Austin was named Senior Vice President, Chief Financial Officer and Chief Accounting Officer, succeeding Mr. Mitchell, whose employment was terminated on January 19, 2005. Mr. Austin had served as our advisor, including advising on financial issues, in the six months preceding his appointment to Chief Financial Officer. Newton W. ("Trey") Wilson, III joined as Senior Vice President and General Counsel effective January 24, 2005, replacing Mr. Loftis, whose employment was terminated on July 8, 2004. Finally, J. Marshall Dodson was hired as Vice President and Chief Accounting Officer on August 22, 2005. In addition, since May 11, 2005 the Executive Committee, which has been delegated all of the powers of the Board of Directors except those powers reserved to the full Board under Maryland law, has largely been acting in the place of the Board of Directors. The members of the Executive Committee consist of all the members of the Board of Directors except Mr. Wolkowitz.

Current management, in turn, has undertaken to improve the corporate-level control environment. Management has significantly expanded our accounting organization and internal audit department as noted above. It has centralized accounting and other control functions, implemented consistent policies and procedures for all parts of the organization, and increased oversight. Management has sought to impress on personnel at all levels the importance of an effective system of controls and of compliance with corporate policies and procedures.

Our Board of Directors has also sought to enhance our governance and compliance systems. It approved and issued our Code of Business Conduct and Ethics company-wide in October 2004. In April 2006, the Board of Directors (acting through its Executive Committee) adopted a revised Code of Business Conduct, which enhanced the provisions of our prior Code of Business Conduct and Ethics. In addition, in October 2004 the Board of Directors adopted new committee charters for each of the Corporate Governance and Nominating, Compensation and Audit Committees and a set of Corporate Governance Guidelines. Among other things, these policies establish formal mechanisms to promote direct communications between management (in addition to the chief executive officer) and the Board. Also, in April 2005 the Board of Directors adopted a Code of Conduct for itself as well as an Affiliate Transaction Policy requiring advance review and approval of any proposed transactions between the Company and an affiliate of the Company, such as an officer, a major shareholder or a director. Copies of our Code of Business Conduct, each of the committee charters, the Corporate Governance Guidelines, the Code of Conduct for the Board of Directors and the Affiliate Transaction Policy are available on our website atwww.keyenergy.com.

We have taken several steps to improve the administration of our stock option program, including approving grants only at meetings of the compensation committee or executive committee and recording grants in the minutes of the meetings of the compensation or executive committee rather than using written consents; authorizing our Chief Executive Officer to make up to 150,000 option grants per year to non-officer employees, with grants to new employees made contemporaneously with their start date; maintaining documentation establishing the fair market value of the grant; and establishing timely communication of the grants. Further, we expect to have a contract in place with a third-party provider by the end of 2006 that will automate the stock option exercise process.

DIRECTORS AND EXECUTIVE OFFICERS.

Directors and Executive Officers at March 15, 2004

The following table sets forth the names and ages, as of March 15, 2004, of each of the Company's executive officers and directors and includes their positions as of March 15, 2004. We have had significant changes in our management since March 15, 2004, which are described below.

Name	Age	Position
Francis D. John	50	Chairman of the Board and Chief Executive Officer
David J. Breazzano	47	Director
Kevin P. Collins	53	Director
William D. Fertig	47	Director
W. Phillip Marcum	60	Director
Ralph S. Michael, III	49	Director
J. Robinson West	57	Director
Morton Wolkowitz	75	Director
Richard J. Alario	49	President and Chief Operating Officer
Royce W. Mitchell	49	Executive Vice President, Chief Financial Officer and Chief Accounting Officer
Jack D. Loftis, Jr.	41	Senior Vice President, General Counsel and Secretary
Jim D. Flynt	59	Senior Vice President—Production Services
Steven A. Richards	52	Senior Vice President—Drilling and International
James J. Byerlotzer	57	Vice Chairman—Safety

Set forth below is biographical information regarding these individuals, which is current as of June 1, 2006, or the date on which this individual ceased to be an officer or director of the Company, if earlier.

Francis D. John was a Director from June 1988 until August 25, 2004 and the Chairman of the Board from August 1996 until August 25, 2004. Mr. John served as President from June 1988 until January 2004 and Chief Executive Officer from October 1989 until May 1, 2004. In addition, he served as the Chief Financial Officer from October 1989 through July 1997 and as Chief Operating Officer from April 1999 through December 2001. Before joining the Company, he was Executive Vice President of Finance and Manufacturing of Fresenius U.S.A., Inc. Mr. John previously held operational and financial positions with Unisys, Mack Trucks and Arthur Andersen. He received a BS from Seton Hall University and an MBA from Fairleigh Dickinson University. Mr. John's employment as Chief Executive Officer ceased on May 1, 2004, and Mr. John resigned as a member of the board of the directors on August 25, 2004.

David J. Breazzano has been a Director since October 1997 and Lead Director since August 2004. Mr. Breazzano is one of the founding principals of DDJ Capital Management, LLC, an investment management firm established in 1996. Mr. Breazzano previously served as a Vice President and Portfolio Manager at Fidelity Investments ("Fidelity") from 1990 to 1996. Prior to joining Fidelity, Mr. Breazzano was President and Chief Investment Officer of the T. Rowe Price Recovery Fund. He is also a director of Avado Brands Inc., Bush Industries, Inc. and Samuels Jewelers, Inc. He holds a BA from Union College, where he serves on the Board of Trustees, and an MBA from Cornell University.

Kevin P. Collins has been a Director since March 1996. Mr. Collins has been Managing Member of The Old Hill Company LLC since 1997. From 1992 to 1997, he served as a principal of JHP Enterprises, Ltd., and from 1985 to 1992, as Senior Vice President of DG Investment Bank, Ltd., both of which were engaged in providing corporate finance and advisory services. Mr. Collins was a director of WellTech, Inc. ("WellTech") from January 1994 until March 1996, when WellTech was merged into the Company. Mr. Collins is also a director of The Penn Traffic Company, Metretek Technologies, Inc.,

Malden Mills Industries, Inc. and Contractors Holding, Inc. He holds BS and MBA degrees from the University of Minnesota. Mr. Collins is a CFA Chartholder.

William D. Fertig has been a Director since April 2000. Mr. Fertig is Co-Chairman and Chief Investment Officer of Context Capital Management, an investment advisory firm. Mr. Fertig was a Principal and a Senior Managing Director of McMahan Securities from 1990 through April 2002. Mr. Fertig previously served as a Senior Vice President and Manager of Convertibles at Drexel Burnham Lambert prior to joining McMahan Securities in 1990, and from 1979 to 1989, served as Vice President and Convertible Securities Sales Manager at Credit Suisse First Boston. He holds a BS from Allegheny College and an MBA from the Stern Business School of New York University.

W. Phillip Marcum has been a Director since March 1996. Mr. Marcum was a director of WellTech from January 1994 until March 1996, when WellTech was merged into the Company. From October 1995 until March 1996, Mr. Marcum was the acting Chairman of the Board of Directors of WellTech. He has been Chairman of the Board, President and Chief Executive Officer of Metretek Technologies, Inc., formerly known as Marcum Natural Gas Services, Inc., since January 1991 and serves as a director of TestAmerica, Inc. He holds a BBA from Texas Tech University.

Ralph S. Michael, III has been a Director since April 2003. Since July 25, 2005, Mr. Michael has been President and Chief Operating Officer of the Ohio Casualty Insurance Company. From 2004 through July 2005, Mr. Michael served as Executive Vice President and Manager of West Commercial Banking for US Bank, National Association and then as Executive Vice President and Manager of US Bank. He also served as President of U.S. Bank Oregon from 2003 to 2005. From 2001 to 2002, he served as Executive Vice President and Group Executive of PNC Financial Services Group, with responsibility for PNC Advisors, PNC Capital Markets and PNC Leasing. From 1996 to 2001, he served as Executive Vice President and Chief Executive Officer of PNC Corporate Banking. He has been a director of Integrated Alarm Services Group since January 2003, a director of T.H.E. Inc. from 1991 to 2004 and a director at Cincinnati Bengals, Inc. since April 2005. Mr. Michael also served as a director of Ohio Casualty Corporation from April 2002 until July 25, 2005, and began serving as a director of Friedman, Billings, Ramsey Group, Inc. in June 2006. He holds a BA from Stanford University and an MBA from the Graduate School of Management of the University of California Los Angeles.

J. Robinson West has been a Director since November 2001. Mr. West is the founder, and since 1984 has served as Chairman and a director of PFC Energy, strategic advisers to international oil and gas companies national oil companies, and petroleum ministries, since 1984. Previously, Mr. West served as U.S. Assistant Secretary of the Interior with responsibility for offshore oil leasing policy from 1981 through 1983. He was Deputy Assistant Secretary of Defense for International Economic Affairs from 1976 through 1977 and a member of the White House Staff from 1974 through 1976. He is currently a member of the Council on Foreign Relations and Chairman of the Board of the United States Institute of Peace. Mr. West is also a director of Cheniere Energy, Inc. He holds a BA with advanced standing from the University of North Carolina at Chapel Hill and a JD from Temple University.

Morton Wolkowitz has been a Director since December 1989. Mr. Wolkowitz served as President and Chief Executive Officer of Wolkow Braker Roofing Corporation, a company that provided a variety of roofing services, from 1958 through 1989. Mr. Wolkowitz has been a private investor since 1989. He holds a BS from Syracuse University. On June 16, 2006, the Executive Committee requested that Mr. Wolkowitz tender his resignation as a director of the Company, effective immediately. To date, Mr. Wolkowitz has declined to resign.

Richard J. Alario joined the Company as President and Chief Operating Officer effective January 1, 2004. On May 1, 2004, Mr. Alario was promoted to Chief Executive Officer and appointed to the Board of Directors. He was elected Chairman of the Board of Directors on August 25, 2004. Prior to joining the Company, Mr. Alario was employed by BJ Services Company ("BJ Services"),

where he served as Vice President from May 2002 when OSCA, Inc. was acquired by BJ Services. Prior to joining BJ Services, Mr. Alario had over 21 years of service in various capacities with OSCA, an oilfield services company, most recently serving as its Executive Vice President. Mr. Alario received a BA from Louisiana State University.

Royce W. Mitchell was elected Executive Vice President, Chief Financial Officer and Chief Accounting Officer effective January 2002. Before joining the Company, he was a partner with KPMG LLP from April 1986 through December 2001 specializing in the oil and gas industry. He received a BBA from Texas Tech University and is a certified public accountant. Mr. Mitchell's employment with the Company ceased effective January 20, 2005.

Jack D. Loftis, Jr. was elected Senior Vice President, General Counsel and Secretary in July 1999. Mr. Loftis first joined Key in 1996 as General Counsel and Secretary. Prior to joining Key he was an associate at Porter and Hedges, L.L.P. from March 1995 to November 1996. He received a BS in Mechanical Engineering from the University of Houston in 1985 and a JD from the University of Houston Law Center in 1993. Mr. Loftis' employment with the Company ceased effective July 8, 2004.

Jim D. Flynt became an executive officer of the Company effective March 5, 2003 when he was promoted to Senior Vice President—Production Services. Mr. Flynt's current title, effective September 2004, is Senior Vice President—Western Region. From December 1999 to March 2003, Mr. Flynt previously served as Vice President—Western Operations. Mr. Flynt joined the Company in September 1998 as the President of the Company's California Division following the Company's acquisition of Dawson Production Services, Inc. From February 1997 to September 1998, Mr. Flynt served as the Regional Vice President of Dawson Production Services, Inc. Before joining Dawson Production Services, Inc., he was Vice President, Area Manager, of Pride Petroleum Services, Inc. from January 1996 to February 1997. From June 1995 to January 1996, he served as District Manager of Pool California Production Service, a subsidiary of Pool Energy Services Co. From March 1976 to June 1995, he served as Vice President, Operations, of California Production Services, Inc.

Steven A. Richards became an executive officer of the Company effective March 5, 2003 when he was promoted to Senior Vice President—Drilling and International. Mr. Richards' current title, effective January 2006, is Senior Vice President—Operations Support. Mr. Richards joined the Company in February 2001 as Vice President of Drilling Operations. He was promoted to Group Vice President—Drilling and International Operations effective May 2002 and served in that position until March 2003. He was Senior Vice President—Drilling and International from March 2003 until December 9, 2005 when he was appointed Senior Vice President—Operations Support. Before joining the Company, he served as Senior Vice President—Business Development at Aker Maritime ASA from January 1999 to February 2001. From August 1998 to December 1998, Mr. Richards served as Vice President of Aker Maritime, Inc. From July 1997 to July 1998, he served as President of Maritime Hydraulics U.S., Inc., an Aker subsidiary. From November 1990 until June 1997 Mr. Richards served in various senior management positions in subsidiaries of Nabors Industries, Inc., including President of Nabors Loffland Drilling, Inc. and Senior Vice President—Operations of Nabors Drilling USA, Inc. Mr. Richards holds a BS in Petroleum Engineering from the University of Oklahoma.

James J. Byerlotzer was Executive Vice President and Chief Operating Officer from January 2002 until December 2003. Mr. Byerlotzer served as Vice Chairman—Safety, from January 2004 until December 2004. Mr. Byerlotzer served as Executive Vice President of Domestic Well Service and Drilling Operations from July 1999 through December 1999 and Executive Vice President of Domestic Operations from December 1999 through December 2001. He joined the Company in September 1998 as Vice President—Permian Basin Operations after the Company's acquisition of Dawson Production Services, Inc. From February 1997 to September 1998, he served as the Senior Vice President and Chief Operating Officer of Dawson Production Services, Inc. From 1981 to 1997, Mr. Byerlotzer was employed by Pride Petroleum Services, Inc. Beginning in February 1996, Mr. Byerlotzer served as the

Vice President—Domestic Operations of Pride Petroleum Services, Inc. Prior to that time, he served as Vice President—Permian Basin of Pride Petroleum Services, Inc. and in various other operating positions in its Gulf Coast and California operations. Mr. Byerlotzer holds a BA from the University of Missouri in St. Louis. Mr. Byerlotzer's employment with the Company ceased effective December 31, 2004.

Current Directors and Executive Officers

We have had significant changes in our management since March 15, 2004. The following table sets forth the names and ages, as of August 31, 2006, of each of the Company's current executive officers and directors and includes their positions as of August 31, 2006.

Name	Age	Position
Richard J. Alario	51	Chairman of the Board, President, Chief Executive Officer, and Chief Operating Officer
David J. Breazzano	50	Lead Director
Kevin P. Collins	55	Director
Daniel L. Dienstbier	66	Director
William D. Fertig	49	Director
W. Phillip Marcum	62	Director
Ralph S. Michael, III	51	Director
J. Robinson West	59	Director
Morton Wolkowitz	79	Director
William M. Austin	60	Senior Vice President, Chief Financial Officer
Newton W. Wilson, III	55	Senior Vice President and General Counsel
Kim B. Clarke	50	Senior Vice President and Chief People Officer
Phil G. Coyne	55	Senior Vice President—Eastern Region
Jim D. Flynt	61	Senior Vice President—Western Division
Steven A. Richards	54	Senior Vice President—Operations Support
J. Marshall Dodson	35	Vice President and Chief Accounting Officer

Set forth below is biographical information on individuals who were not directors or executive officers on March 15, 2004:

Effective January 9, 2006, Daniel L. Dienstbier was appointed to our Board of Directors. Mr. Dienstbier served as non-executive Chairman of the Board of Dynegy, Inc. from May 2002 to May 2004 and as a director of Dynegy since 1995. In addition, he served as interim Chief Executive Officer of Dynegy from May 2002 to November 2002 and as President of Northern Natural Gas Company, a Dynegy subsidiary, from February 2002 until May 2002. Prior to joining the board of directors of Dynegy, Mr. Dienstbier served as President and Chief Operating Officer at two publicly-traded companies, American Oil & Gas Corporation and Arkla, Inc., as President of Jule, Inc., and as President and Chief Executive Officer of Dyco Petroleum Corporation, a subsidiary of Diversified Energies, Inc. In addition, he spent twenty years with Northern Natural Gas Company ("Northern"), the last four as president. Northern was a division of InterNorth Inc. Mr. Dienstbier served on the Board of Directors of Latigo Petroleum, a private oil and gas exploration company until it was acquired in May 2006 by Pogo Producing Company, and has previously served as a director on a number of other publicly traded companies. He holds a degree from the University of Omaha and an MBA from Creighton University.

On January 20, 2005, William M. ("Bill") Austin was named Senior Vice President, Chief Financial Officer and Chief Accounting Officer. Mr. Austin served as an advisor, principally in a financial capacity, to the Company for the six months prior to becoming an officer with Key. Prior to joining the Company, Mr. Austin served as Chief Restructuring Officer of Northwestern Corporation from 2003 to

2004. Mr. Austin served as Chief Executive Officer, U.S. Operations, of Cable & Wireless/Exodus Communications from 2001 to 2002 and as Chief Financial Officer of BMC Software from 1997 to 2001. Prior to that, Mr. Austin spent nearly six years at McDonnell Douglas Aerospace, a subsidiary of McDonnell Douglas Corporation, serving most recently as Vice President and Chief Financial Officer, and eighteen years at Bankers Trust Company. Mr. Austin received a BS in Electrical Engineering from Brown University and an MBA from Columbia University.

Newton W. ("Trey") Wilson, III joined the Company as Senior Vice President and General Counsel effective January 24, 2005. He also was appointed Secretary effective January 24, 2005. Previously, Mr. Wilson served as Senior Vice President, General Counsel and Secretary of Forest Oil Corporation, which he joined in November 2000. Prior to joining Forest, Mr. Wilson was a consultant to the oil industry as well as an executive for two oil and gas companies, Union Texas Petroleum and Transco Energy Company. Mr. Wilson received a BBA from Southern Methodist University and a JD from the University of Texas.

In January 2005, Kim B. Clarke was elected as an executive officer. Ms. Clarke joined Key on November 22, 2004 as Vice President and Chief People Officer. Ms. Clarke previously served as Vice President of Human Resources for GC Services from 1999 to 2004. She was appointed Senior Vice President and Chief People Officer effective as of January 2006. Prior to that she served in a number of senior level human resource roles for Browning-Ferris Industries (BFI) from 1988 to 1997 and as BFI's Vice President Human Resources from 1997 to 1999. Ms. Clarke's 25 years of work experience also includes industry experience with Baker Service Tools and National Oilwell. Ms. Clarke holds a Bachelor of Science Degree from the University of Houston.

Phil G. Coyne became Senior Vice President of Key's Eastern Region in September 2004. He was appointed as an executive officer in April 2005. Mr. Coyne joined Key as Vice President Eastern Region in April of 2004. Before joining Key, Mr. Coyne was Vice President of North America for Owen Oil Tools, an explosive manufacturer and a division of Core Laboratories from 2001 to 2004. He served as U.S. Operations Support Manager for Wood Group (a British based company) from 1999-2001. Mr. Coyne served in various positions with Western Atlas from 1984 to 2000 most recently serving as the District Manager of Atlas's Broussard, Louisiana offshore operations. Mr. Coyne is a Vietnam era veteran and was in the Air Force stationed primarily in Thailand.

J. Marshall Dodson joined us as Vice President and Chief Accounting Officer on August 22, 2005. Prior to joining Key, Mr. Dodson served in various capacities at Dynegy, Inc. from 2002 to August 2005, most recently serving as Managing Director and Controller, Dynegy Generation since 2003. Mr. Dodson started his career with Arthur Andersen LLP in Houston, Texas in 1993 serving mostly as a senior manager until joining Dynegy, Inc. Mr. Dodson is a Certified Public Accountant and received a BBA at the University of Texas at Austin in 1993.

Executive Committee

By unanimous written consent dated May 11, 2005, the Board of Directors expanded the membership of the Executive Committee of the Board. The members of the Committee are Messrs. Alario, Breazzano, Collins, Dienstbier, Fertig, Marcum, Michael and West. Mr. Wolkowitz is not a member of the Executive Committee. The Executive Committee has been delegated all of the powers of the Board, except those powers reserved to the full Board of Directors under Maryland law. Since May 11, 2005, the Executive Committee has largely been acting in place of the Board of Directors.

Board Composition and Election

Directors are elected at annual meetings of stockholders. We amended and restated our Bylaws effective September 21, 2006 to provide for a classified Board of Directors, consisting of three

staggered classes of directors, as nearly equal in number as possible. As a result, stockholders will elect a portion of our Board of Directors each year. The Class I directors' term will expire at our first annual meeting held after September 21, 2006 (the date of establishment of the classified Board), the Class II directors' terms will expire at our second annual meeting held after September 21, 2006, and the Class III directors' terms will expire at our third annual meeting held after September 21, 2006. The successors to these directors will be elected for a term expiring at the third annual meeting following election.

Currently, the Class I directors are Messrs. Collins, Marcum and Wolkowitz, the Class II directors are Messrs. Breazzano, Fertig and West, and the Class III directors are Messrs. Alario, Dienstbier and Michael.

In addition, our Bylaws provide that the authorized number of directors may be changed only by action of a majority of the Board of Directors. Any additional directorships resulting from an increase in the number of directors will be distributed among the three classes so that, as nearly as possible, each class will consist of one-third of the total number of directors. Vacancies and newly created directorships may be filled by the affirmative vote of a majority of our directors then in office, even if less than a quorum. Our Bylaws also provide that no director may be removed except for cause and then only by a vote of at least two-thirds of the total eligible stockholder votes, and also require the vote of a majority of the stockholders of the Company to call a special meeting of stockholders.

Because we have not filed required reports with the SEC, we have not been able to hold an annual meeting of stockholders since 2003.

Director Nomination Process

On October 29, 2004, the Board of Directors adopted guidelines for nomination as a director of the Company and process for the selection of new candidates for the Board of Directors. These guidelines include procedures to be followed by stockholders who wish to recommend candidates to the Corporate Governance and Nominating Committee for its consideration in connection with its selection of director candidates to the Board of Directors. Stockholders may nominate candidates to the Company's Board of Directors by submitting such nominations in writing to the Company's Secretary no later than 120 days prior to the scheduled date for the Annual Meeting of Stockholders. The Corporate Governance and Nominating Committee will consider candidates proposed by stockholders in the same manner as other candidates, so long as the stockholder meets certain eligibility standards.

Stockholder nominations must include the name, age, business and residence address and principal occupation or employment of the proposed nominee. An explanation of how the nominee meets the Company's selection criteria, as set forth in the guidelines, is required. The nomination also must include the name and residence address of the stockholder and the number of shares of Company common stock owned by the stockholder. The stockholder must also provide the total number of shares of Company common stock that, to the stockholder's knowledge, will be voted for the proposed nominee and are owned by the proposed nominee. A signed consent of the proposed nominee to serve if elected must be submitted, and any other information relating to the proposed nominee that is required to be disclosed in solicitations of proxies for the election of directors under Regulation 14A of the Securities Exchange Act of 1934.

Audit Committee Financial Expert

The Company has a separately designated standing Audit Committee. The Audit Committee plays an important role in promoting effective corporate governance, and members of the Audit Committee must possess the requisite financial literacy and expertise. All members of Key's Audit Committee meet the financial literacy standard required by the NYSE rules and at least one member qualifies as having accounting or related financial management expertise under the NYSE rules. In addition, as required

by the Sarbanes-Oxley Act of 2002, the SEC adopted rules requiring that each public company disclose whether or not its audit committee has an "audit committee financial expert" as a member. An "audit committee financial expert" is defined as a person who, based on his or her experience, satisfies all of the following attributes:

•: An understanding of generally accepted accounting principles and financial statements;
•: An ability to assess the general application of such principles in connection with the accounting for estimates, accruals, and reserves;
•: Experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and level of complexity of issues that can reasonably be expected to be raised by Key's financial statements, or experience actively supervising one or more persons engaged in such activities;
•: An understanding of internal controls over financial reporting; and
•: An understanding of audit committee functions.

The Board of Directors has affirmatively determined that Mr. Michael satisfies the definition of "audit committee financial expert," and has designated Mr. Michael as an "audit committee financial expert." Messrs. Collins and Marcum also serve on the Company's Audit Committee. In addition, all of the members of the Audit Committee are independent within the meaning of SEC regulations, the NYSE listing standards and the Company's Corporate Governance Guidelines.

Section 16(a) Beneficial Ownership Reporting Compliance

�� Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the Company's directors, executive officers and persons who beneficially own more than 10% of a registered class of the Company's equity securities, to file initial reports of ownership on Form 3 and changes in ownership on Forms 4 or 5 with the SEC. Such officers, directors and 10% stockholders also are required by SEC rules to furnish the Company with copies of all Section 16(a) reports they file. Except as noted below, based solely on its review of the copies of such forms furnished or available to the Company, the Company believes that its directors, executive officers and 10% stockholders complied with all Section 16(a) filing requirements for the period from January 1, 2003 through December 31, 2005. In connection with the preparation of this report, the Company's Executive Committee on June 19, 2006 determined that Jack D. Loftis, Jr. was an executive officer during the fiscal year ended December 31, 2003, and as such is included as an executive officer in this report. Due to the timing of this determination, Mr. Loftis did not file Forms 3, 4 or 5 with respect to this time period.

Code of Ethics

On October 29, 2004, we adopted a code of ethics, the "Code of Business Conduct and Ethics," that applied to all of our employees, including our Chief Executive Officer, Chief Financial Officer and senior financial and accounting officers. We adopted a new Code of Business Conduct on April 5, 2006 which currently applies to all of our employees, including our Chief Executive Officer, Chief Financial Officer and senior financial and accounting officers. In addition, we adopted a Code of Conduct for members of the Board of Directors on April 18, 2005. In addition to other matters, the Code of Business Conduct and the Board Code of Conduct establish policies to deter wrongdoing and to promote both honest and ethical conduct, including ethical handling of actual or apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications and prompt internal reporting of violations of the Code of Business Conduct. We also have an Ethics Committee, composed of members of management, which administers our ethics and compliance program with respect to our employees. In addition, we

provide an ethics line for reporting any violations of the code on a confidential basis. Copies of our Code of Business Conduct and the Board Code of Conduct are available on our website at www.keyenergy.com. We will post on our internet website all waivers to or amendments of our Code of Business Conduct and the Board Code of Conduct, that are required to be disclosed by applicable law and the NYSE listing standards.

Election of Executive Officers

Each executive officer holds office until the first meeting of the Board of Directors following the annual meeting of stockholders and until his successor has been duly elected and qualified. Because we have not filed required reports with the SEC, we have not been able to hold an annual meeting of stockholders since 2003.

EXECUTIVE COMPENSATION

In this section, we provide information about executive compensation in accordance with SEC rules otherwise required for an annual reports on Form 10-K. In light of the passage of time, we also include this information for the fiscal years ended December 31, 2004 and December 31, 2005.

Summary Compensation Table. The following tables provide, for the periods stated, compensation information concerning our current and former "named executive officers," which definition includes each person who served as our chief executive officer during those periods, as well as our other most highly compensated executive officers serving at the end of each period or who would have qualified had they not left the Company prior to the end of such period.

Named Executive Officers in Office as of December 31, 2003

			Annual Compensation				Long Term Compensation Awards
Name And Principal Position	Fiscal Year		Salary ($)	Bonus ($)	Other Annual Compensation ($)(2)		Restricted Stock Awards ($)		Shares Underlying Options(3)	All Other Compensation ($)
Francis D. John President and Chief Executive Officer	2003 2002 2002 2001	(1)	744,225 424,188 595,000 594,616	250,000 — 300,000 835,000	302,867 — — —	(4)	2,525,000 — — —	(5)	300,000 400,000 1,460,000 2,000,000	— — 13,080,662 —	(6)
James J. Byerlotzer Executive Vice President and Chief Operating Officer	2003 2002 2002 2001	(1)	338,923 170,133 250,000 248,750	150,000 140,000 275,000	8,123 — — —	(7)	505,000 — — —	(5)	100,000 150,000 115,000 300,000	1,000 — 35,615 101,000	(8) (9) (10)
Royce W. Mitchell Executive Vice President and Chief Financial Officer	2003 2002 2002 2001	(1)	332,962 147,500 140,692 —	200,000 — — —	10,597 41,666 5,538 —	(11) (12) (13)	1,515,000 — — —	(5)	200,000 200,000 — —	— — 100,000 —	(14)
Jack D. Loftis, Jr.(15) Senior Vice President and General Counsel	2003 2002 2002 2001	(1)	257,286 107,500 215,000 214,231	75,000 50,000 110,000 219,500	91,240 — — —	(16)	858,500 — — —	(5)	100,000 — — 100,000	1,000 — 1,000 1,000	(8) (8) (8)
Jim D. Flynt Senior Vice President—Production Services	2003 2002 2002 2001	(1)	182,881 90,961 139,615 161,827	30,000 41,702 55,000 80,000	26,784 119,398 7,500 9,000	(17) (18) (13) (13)	757,500 — — —	(5)	50,000 25,000 35,000 25,000	1,000 — 1,000 1,000	(8) (8) (8)
Steven A. Richards Senior Vice President—Drilling and International	2003 2002 2002 2001	(1)	202,015 87,500 175,000 67,308	70,000 — 30,000 —	5,626 4,200 8,400 3,285	(19) (13) (13) (13)	303,000 — — —	(5)	25,000 85,000 — —	1,000 — 1,000 1,000	(8) (8) (8)

(1): Change in fiscal year end. As a result of the Company having changed its fiscal year end from June 30 to December 31, the Company is providing summary compensation information for the six-month transition period ended December 31, 2002. All categories of summary compensation presented in this table conform to the statement of operations periods presented in this report for the six months ended December 31, 2002 and fiscal years ended December 31, 2003, June 30, 2002, and June 30, 2001.
(2): During the relevant periods, certain Named Executive Officers had use of corporate credit cards, private aircraft and other corporate assets for both business and personal use. The Company's information from these periods to support an allocation between personal and business use is limited and we are unable at this time to ascertain whether additional compensation amounts should be attributed to Mr. John or other Named Executive Officers in excess of those reflected in the table.
(3): Represents the number of shares issuable pursuant to vested and non-vested stock options granted during the applicable fiscal year.
(4): Represents reimbursement of miscellaneous personal expenses for telephone and security usage of $6,997 and premiums paid by the Company for health insurance and life insurance policies of $277,314. The remaining $18,556 represents the Company's estimate of the value of Mr. John's use of a company-provided vehicle for personal business.
(5): Represents a conditional deferred stock award granted under the Company's 2003 Long-Term Share Incentive Plan as approved by the Board on December 12, 2003. The awards were conditioned upon shareholder approval of the plan on or prior to September 30, 2004. Such approval was not obtained; therefore, the plan expired in accordance with its terms and no stock was issued.
(6): Represents (i) a ten-year incentive retention payment, the after-tax proceeds of which were used to repay all principal and interest on the loans previously granted to Mr. John (for more information on the incentive retention payment, see the section entitled "Consolidated Financial Statements and Supplementary Data,"

Note 18—"Transactions with Related Parties."), and (ii) contributions by the Company on behalf of the executive to the Key Energy Services, Inc. 401(k) Savings and Retirement Plan of $1,000.

(7): Represents premium payments by the Company for life insurance.
(8): Represents contributions by the Company on behalf of the executive to the Key Energy Services, Inc. 401(k) Savings and Retirement Plan.
(9): Represents (i) payments to Mr. Byerlotzer pursuant to a non-competition agreement entered into in connection with the Company's acquisition of Dawson Production Services, Inc. of $34,615, and (ii) contributions by the Company on behalf of the executive to the Key Energy Services, Inc. 401(k) Savings and Retirement Plan of $1,000.
(10): Represents (i) payments to Mr. Byerlotzer pursuant to a non-competition agreement entered into in connection with the Company's acquisition of Dawson Production Services, Inc. of $100,000, and (ii) contributions by the Company on behalf of the executive to the Key Energy Services, Inc. 401(k) Savings and Retirement Plan of $1,000.
(11): Represents an auto allowance of $3,231 and premium payments by the Company for life insurance of $7,366.
(12): Represents an auto allowance of $6,000 and moving expenses of $35,666.
(13): Represents an auto allowance paid by the Company to the executive.
(14): Represents a one-time signing bonus that is subject to repayment if Mr. Mitchell terminates his employment with the Company under certain circumstances. See "Employment Agreements with Executive Officers."
(15): In connection with the preparation of this report, the Company's Executive Committee on June 19, 2006 determined that Mr. Loftis was an executive officer during the year ended December 31, 2003.
(16): Represents a $50,000 loan to Mr. Loftis and gross-up payment of $41,240 related to such loan.
(17): Represents reimbursement of $26,288 for moving expenses and $496 for auto expenses paid by the Company.
(18): Represents payments by Company of $114,898 for moving expenses and $4,500 for the Company's estimate of the value of use of a company vehicle.
(19): Represents premium payments by the Company for life insurance of $3,364 and an auto allowance of $2,262.

Named Executive Officers for the fiscal years ended December 31, 2004 and December 31, 2005

		Annual Compensation						Long Term Compensation Awards
Name and Principal Position	Fiscal Year	Salary ($)		Bonus ($)		Other Annual Compensation ($)		Restricted Stock Awards ($)		Shares Underlying Options(1)		All Other Compensation ($)
Francis D. John President and Chief Executive Officer	2004	504,804	(2)	250,000		118,434	(3)(4)	—		—		8,200	(5)
Richard J. Alario President, Chief Executive Officer and Chief Operating Officer	2005 2004	700,000 571,538		727,375 625,000	(6) (10)	43,746 32,814	(7) (11)	3,272,500 —	(8)	200,000 250,000	(12)	66,733 —	(9)
James J. Byerlotzer Vice Chairman	2004	353,077		—		10,905	(13)	—		—		1,026,230	(14)
Royce Mitchell Executive Vice President and Chief Financial Officer	2005 2004	337,000 349,962		— —		9,300 9,300	(15) (15)	— —		— —		— —
Jack D. Loftis, Jr. Senior Vice President and General Counsel	2004	301,750		—		24,658	(16)	—		—		8,200	(5)
Jim D. Flynt Senior Vice President—Western Division	2005 2004	250,000 259,018		156,250 116,250	(17) (18)	— —		— —		— —		8,354 7,538	(5) (5)
Steven A. Richards Senior Vice President—Operations Support	2004	217,662		158,307	(19)	—		—		—		8,200	(5)
Newton W. Wilson, III Senior Vice President and General Counsel	2005	329,808		313,688	(20)	139,358	(21)	1,190,000	(22)	250,000	(23)	208,567	(24)
William M. Austin Senior Vice President, Chief Financial Officer	2005	380,000		387,500	(25)	1,530	(26)	1,190,000	(27)	—		8,400	(5)
Kim B. Clarke Vice President and Chief People Officer	2005	206,538		210,445	(28)	—		297,500	(29)	15,000		7,309	(5)

(1): Represents the number of shares issuable pursuant to vested and non-vested stock options granted during the applicable fiscal year.
(2): Represents salary paid to Mr. John for 2005. Mr. John's employment with the Company ceased effective May 1, 2004. The Company paid Mr. John's regular salary for 90 days after the termination. All other cash payments which might have been required under Mr. John's employment agreement, including salary, bonuses, and severance, were suspended by the Company pending completion of the SEC investigation.
(3): Represents reimbursement of miscellaneous personal expenses of $75,724 and premiums paid by the Company for health insurance and life insurance policies of $39,829. The remaining $2,881 represents reimbursement of premiums paid for insurance policy coverage of Mr. John's airplane pilot.
(4): During 2004, Mr. John had use of corporate credit cards, private aircraft and other corporate assets for both business and personal use. The Company's information from this period to support an allocation between personal and business use is limited and we are unable at this time to ascertain whether additional compensation amounts should be attributed to Mr. John in excess of those reflected in the table.
(5): Represents contributions by the Company on behalf of the executive to the Key Energy Services, Inc. 401(k) Savings and Retirement Plan.

(6): Represents first and second half incentive bonus for 2005 of $299,250 and $328,125, respectively. Mr. Alario was also paid a $100,000 retention bonus pursuant to the terms of his employment agreement.
(7): Represents premium payments of $16,727 by the Company for life insurance, $19,911 payment for relocation expenses, and auto allowances of $7,108.
(8): Represents awards of restricted stock granted on June 24, 2005 under the Company's 1997 Key Energy Group, Inc. Incentive Plan. These restricted stock grants vests as follows: 175,000 shares on June 24, 2006; 50,000 shares on June 24, 2007 and 50,000 shares on June 24, 2008.
(9): Represents payment by the Company of relocation bonus of $58,333 payable pursuant to the Company's relocation policy and contributions by the Company on behalf of the executive to the Key Energy Services, Inc. 401(k) Savings and Retirement Plan of $8,400.
(10): Represents $100,000 retention bonus payable pursuant to Mr. Alario's employment agreement and $525,000 incentive bonus payable for Mr. Alario's service to the Company during 2004.
(11): Represents premium payments of $25,130 by the Company for life insurance and reimbursement of premiums paid for health insurance of $6,994. The remaining $690 represents payments for legal expenses paid by the Company.
(12): Represents the number of shares issuable pursuant to vested and non-vested stock options granted during the applicable fiscal year, of which 250,000 shares were rescinded on March 25, 2005.
(13): Represents premium payments by the Company for term life insurance.
(14): Represents (i) payment of severance compensation in accordance with terms of employment agreement of $1,020,000, and (ii) contributions by the Company on behalf of the executive to the Key Energy Services, Inc. 401(k) Savings and Retirement Plan of $6,230.
(15): Represents premium payments by the Company for term life insurance.
(16): Represents reimbursement by the Company of personal legal expenses of the executive of $15,000, the Company's estimate of personal use of Company vehicle of $2,637, auto allowances of $4,062 and miscellaneous expenses reimbursed by the Company for continuing education and healthcare expenses of $2,959.
(17): Represents first and second half incentive bonus for 2005 of $78,125 and $78,125, respectively.
(18): Represents discretionary bonus of $30,000 and first and second half incentive bonus for 2004 of $31,250 and $55,000, respectively.
(19): Represents discretionary bonus of $52,400 and first and second half incentive bonus for 2004 of $55,020, and $50,887, respectively.
(20): Represents first and second half incentive bonus for 2005 of $149,625 and $164,063, respectively.
(21): Represents premium payments of $4,178 by the Company for term life insurance and payments of $135,180 by Company for relocation expenses.
(22): Represents an award of restricted stock granted on June 24, 2005 under the Company's 1997 Key Energy Group, Inc. Incentive Plan. The restricted stock grant vests as follows: (i) 33,333 shares on June 24, 2006; (ii) 33,333 shares on June 24, 2007 and (iii) 33,334 shares on June 24, 2008.
(23): Represents the aggregate number of shares issuable pursuant to vested and non-vested stock options granted during the applicable fiscal year, of which 125,000 shares were rescinded on March 25, 2005.
(24): Represents $171,000 relocation bonus, which was guaranteed pursuant to the terms of his employment agreement, a $29,167 relocation bonus payable pursuant to the Company's relocation policy, and contributions by the Company on behalf of the executive to the Key Energy Services, Inc. 401(k) Savings and Retirement Plan of $8,400.
(25): Represents first and second half incentive bonus for 2005 of $200,000 and $187,500, respectively. Mr. Austin was guaranteed a minimum of $200,000 for 2005 pursuant to the terms of his employment agreement.
(26): Represents premium payments of $1,530 by the Company for term life insurance.
(27): Represents an award of restricted stock granted on June 24, 2005 under the Company's 1997 Key Energy Group, Inc. Incentive Plan. The restricted stock grant vests as follows: (i) 33,333 shares on June 24, 2006; (ii) 33,333 shares on June 24, 2007 and (iii) 33,334 shares on June 24, 2008.
(28): Represents first and second half incentive bonus for 2005 of $104,976 and $105,469, respectively. Ms. Clarke was guaranteed a minimum bonus of $69,375 for 2005, pursuant to the terms of her employment agreement.

(29): Represents an award of restricted stock granted on June 24, 2005 under the Company's 1997 Key Energy Group, Inc. Incentive Plan. The restricted stock grant vests as follows: (i) 8,333 shares on June 24, 2006; (ii) 8,333 shares on June 24, 2007 and (iii) 8,334 shares on June 24, 2008.

Option Grants in Last Fiscal Year (For Years Ended December 31, 2003, 2004 and 2005)

The following table sets forth certain information relating to options granted under the Key Energy Group, Inc. 1997 Incentive Plan (the "Plan") and outside the Plan to the Named Executive Officers during the fiscal years ended December 31, 2003, December 31, 2004 and December 31, 2005. The Company did not grant any stock appreciation rights during fiscal 2003, 2004 or 2005.

Name	Year	Number of Securities Underlying Options Granted		Individual Grants as % of Total Options Granted Employees in Fiscal Year		Exercise Price Per Share		Expiration Date		Grant Date Present Value
Francis D. John	2003 2004	300,000 —	(7)	19.23 —	(1)	$	10.22 —	07/18/13 —	(19)	$	1,191,000 —	(2)
Richard J. Alario	2004 2005	250,000 200,000	(14) (15)	58.96 31.50	(12) (13)	$ $	9.96 11.90	06/03/14 06/24/15		$	NA 1,290,000	(3) (4)
Royce W. Mitchell	2003 2004 2005	200,000 — —	(8)	12.82 — —	(1)	$	10.22 — —	07/18/13 — —	(19)	$	794,000 — —	(2)
James J. Byerlotzer	2003 2004	100,000 —	(9)	6.41 —	(1)	$	10.22 —	07/18/13 —	(19)	$	397,000 —	(2)
Jack D. Loftis, Jr.	2003 2004	100,000 —	(9)	6.41 —	(1)	$	10.22 —	07/18/13 —	(19)	$	397,200 —	(2)
Jim D. Flynt	2003 2004 2005	50,000 — —	(10)	3.21 — —	(1)	$	10.22 — —	07/18/13 — —		$	198,500 — —	(2)
Steven A. Richards	2003 2004	25,000 —	(11)	1.6 —	(1)	$	10.22 —	07/18/13 —		$	99,250 —	(2)
Newton W. Wilson, III	2005	125,000 125,000	(16) (17)	19.69 19.69	(13) (13)	$ $	11.70 11.90	01/24/15 06/24/15		$	NA 806,250	(5) (4)
William M. Austin	2005	—		—			—	—			—
Kim B. Clarke	2005	15,000	(18)	2.36	(13)	$	14.25	12/08/15		$	119,700	(6)

(1): Based on options to purchase a total of 1,560,000 shares of Common Stock granted during the fiscal year ended December 31, 2003.
(2): The grant date value of stock options was estimated using the Black-Scholes option pricing model with the following assumptions: expected volatility—34.32%; risk-free interest rate—3.06%; estimated term of 6 years; and no dividend yield.
(3): This option award was rescinded effective March 25, 2005.
(4): The grant date value of stock options was estimated using the Black-Scholes option pricing model with the following assumptions: expected volatility—36.71%; risk-free interest rate—3.92%; estimated term of 6 years; and no dividend yield.
(5): This option award was rescinded effective March 25, 2005.
(6): The grant date value of stock options was estimated using the Black-Scholes option pricing model with the following assumptions: expected volatility—32.90%; risk-free interest rate—4.47%; estimated term of 6 years; and no dividend yield.
(7): These options were granted on July 18, 2003 and vest as follows: 100,000 on May 7, 2004; 100,000 on May 7, 2005; and 100,000 on May 7, 2006. Assumes the options are not otherwise cancelled or forfeited.

(8): These options were granted on July 18, 2003 and vest as follows: 66,666 on May 7, 2004; 66,667 on May 7, 2005; 66,667 on May 7, 2006. Assumes the options are not otherwise cancelled or forfeited.
(9): These options were granted on July 18, 2003 and vest as follows: 33,333 on May 7, 2004; 33,333 on May 7, 2005; and 33,334 on May 7, 2006.
(10): These options were granted on July 18, 2003 and vest as follows: 16,666 on May 7, 2004; 16,667 on May 7, 2005; and 16,667 on May 7, 2006.
(11): These options were granted on July 18, 2003 and vest as follows: 8,333 on May 7, 2004; 8,333 on May 7, 2005; and 8,334 on May 7, 2006.
(12): Based on options to purchase a total of 424,000 shares of Common Stock granted during the fiscal year ended December 31, 2004. 250,000 shares granted to Mr. Alario were rescinded effective March 25, 2005.
(13): Based on options to purchase a total of 635,000 shares of Common Stock granted during the fiscal year ended December 31, 2005. 125,000 shares granted to Mr. Wilson were rescinded effective March 25, 2005.
(14): These options were granted on June 3, 2004 and vest as follows: 250,000 on June 3, 2005. The option was rescinded effective March 25, 2005.
(15): These options were granted on June 24, 2005 and vest as follows: 66,666 on June 24, 2006; 66,667 on June 24, 2007 and 66,667 on June 24, 2008.
(16): These options were granted on January 24, 2005. The option was rescinded effective March 25, 2005.
(17): These options were granted on June 24, 2005 and vest as follows: 41,666 on June 24, 2005; 41,667 on June 24, 2006 and 41,667 on June 24, 2007.
(18): These options were granted on December 8, 2005 and vest as follows: 5,000 on December 8, 2006; 5,000 on December 8, 2007 and 5,000 on December 8, 2008.
(19): Assuming such options are vested and not otherwise cancelled or forfeited, under the terms of the executive's employment agreement, options vested at termination will expire on the earlier of the third anniversary of the date of termination, or the stated expiration date.

Aggregated Option Exercises and Values as of Fiscal Year End

The following table sets forth certain information as of December 31, 2003 relating to the number and value of unexercised options held by the Named Executive Officers. None of the Named Executive Officers exercised Stock Options during fiscal 2003.

	Number of Securities Underlying Unexercised Options at December 31, 2003		Value of Unexercised In-The Money-Options at December 31, 2003(1)
Name
Name	Exercisable	Unexercisable	Exercisable		Unexercisable
Francis D. John(2)	3,143,333	766,667	$	5,258,391	$	938,334
Royce W. Mitchell(3)	100,000	300,000	$	141,000	$	159,000
James J. Byerlotzer	460,000	300,000	$	1,708,856	$	396,000
Jack D. Loftis, Jr.(3)	246,666	233,334	$	499,798	$	267,002
Jim D. Flynt	113,333	83,334	$	383,884	$	69,002
Steven A. Richards	56,666	53,304	$	130,898	$	67,702

(1): The dollar values in this column are calculated by determining the difference between the fair market value of the Common Stock for which the relevant options are exercisable as of the end of the fiscal year and the exercise price of the options. The fair market value is based on the last sale price of the Common Stock on the NYSE on December 31, 2003, which was $10.31.
(2): Assumes the options are vested and are not otherwise cancelled or forfeited. See the section entitled "Legal Proceedings and Other Actions—Litigation with Former Officers."
(3): Assumes the options are vested and are not otherwise cancelled or forfeited.

The following table sets forth certain information as of December 31, 2004 relating to the number and value of unexercised options held by the Named Executive Officers. None of the Named Executive Officers exercised stock options during fiscal 2004.

	Number of Securities Underlying Unexercised Options at December 31, 2004			Value of Unexercised In-The-Money Options at December 31, 2004(1)
Name
Name	Exercisable	Unexercisable		Exercisable		Unexerciseable
Francis D. John(3)	3,910,000	—		$	13,103,048		—
Richard J. Alario	—	250,000	(2)	$	—	$	460,000
Royce W. Mitchell(4)	216,666	183,334		$	540,332	$	355,668
James J. Byerlotzer	660,000	—		$	2,763,250	$	—
Jack D. Loftis, Jr.(4)	480,000	—		$	1,482,000		—
Jim D. Flynt	138,333	58,334		$	610,752	$	135,168
Steven A. Richards	93,333	16,667		$	336,166	$	26,334

(1): The dollar values in this column are calculated by determining the difference between the fair market value of the Common Stock for which the relevant options are exercisable as of the end of the fiscal year and the exercise price of the options. The fair market value is based on the last sale price of the Common Stock on the NYSE on December 31, 2004, which was $11.80.
(2): Represents option grant that was made effective as of June 3, 2004 at an exercise price of $9.96 per share. The option grant was rescinded effective March 25, 2005.
(3): Assumes the options are vested and are not otherwise cancelled or forfeited. See the section entitled "Legal Proceedings and Other Actions—Litigation with Former Officers."
(4): Assumes the options are vested and not otherwise cancelled or forfeited.

The following table sets forth certain information as of December 31, 2005 relating to the number and value of unexercised options held by the Named Executive Officers. None of the Named Executive Officers exercised stock options during fiscal 2005.

	Number of Securities Underlying Unexercised Options at December 31, 2005		Value of Unexercised In-The-Money Options at December 31, 2005(1)
Name
Name	Exercisable	Unexercisable	Exercisable	Unexercisable
Richard J. Alario	—	200,000	—	314,000
Newton W. Wilson, III	41,666	83,334	65,416	130,834
William M. Austin	66,666	33,334	195,998	98,002
Royce W. Mitchell(2)	400,000	—	1,564,000	—
Jim D. Flynt	155,000	41,667	895,936	298,501
Kim B. Clarke	3,333	21,667	5,733	11,467

(1): The dollar values in this column are calculated by determining the difference between the fair market value of the Common Stock for which the relevant options are exercisable as of the end of the fiscal year and the exercise price of the options. The fair market value is based on the last sale price of the Common Stock on the Pink Sheets Electronic Quotation Service on December 31, 2005, which was $13.47.
(2): Assumes the options are vested and not otherwise cancelled or forfeited.

Employment Agreements and Termination and Change-in-Control Arrangements with Named Executive Officers

Employment Agreement of Francis D. John.

Effective as of January 1, 2004, the Company entered into an amended and restated employment agreement with Mr. John, which provided that Mr. John would serve as Chairman of the Board and Chief Executive Officer of the Company for a three-year term commencing January 1, 2004 and continuing until December 31, 2006, with an automatic one-year renewal on each December 31, commencing on December 31, 2006, unless terminated by the Company or by Mr. John with proper notice. As discussed below, Mr. John's employment with the Company ceased effective May 1, 2004.

Under this employment agreement, Mr. John's annual base salary was $875,000 per year, subject to increase after annual reviews by the Board of Directors. This employment agreement also provided that Mr. John would be entitled to (i) participate in the Company's Performance Compensation Plan, with performance criteria to be approved by the Compensation Committee, (ii) receive additional bonuses at the discretion of the Compensation Committee, and (iii) participate in stock option grants made to the Company's executives.

In addition to salary and bonus, Mr. John was entitled to medical, dental, accident and life insurance, reasonable fees for personal financial advisory, counseling, accounting and related services, legal advisory or attorneys' fees and income tax return preparation and tax audit services. The Company agreed to lease or purchase one automobile for Mr. John, and pay all expenses in connection with its use, and also to pay or reimburse for the cost of the services of a car and driver contracted for by Mr. John. Mr. John would be reimbursed for all expenses incurred by him in carrying out his duties, including expenses for him to be able to perform his duties from his home or any other location from time to time. Mr. John had the authority to contract for the services of a private aircraft for travel related to his duties. To the extent Mr. John would be taxed on any such reimbursement or benefit, the Company agreed to pay Mr. John an amount that, on an after-tax basis, equaled the amount of such taxes.

Under the agreement, in the event that Mr. John's employment were terminated (1) by the Company voluntarily or by nonrenewal, (2) by Mr. John for "Good Reason," (3) by either the Company or Mr. John following a "Change in Control" (in each case as defined in the employment agreement), or (4) as a result of Mr. John's disability, Mr. John would be entitled to receive: (i) his accrued but unpaid salary and bonuses to the date of termination, and a pro rata bonus for the year in which termination occured; (ii) a severance payment in an amount equal to three times his average total annual compensation (calculated based on salary plus bonus for the preceding three years) (except that in the case of termination as a result of Mr. John's disability, such compensation would be reduced by the amount of any Company-paid disability insurance proceeds paid to Mr. John); (iii) immediate vesting and exercisability of all stock options held by him (to the extent not already vested and exercisable) for the remainder of the original terms of the options; (iv) any other amounts or benefits earned, accruing or owing to him, but not yet paid; (v) continued participation in medical, dental and life insurance coverage until the first to occur of the third year anniversary of the date his employment was terminated or the date on which he received equivalent coverage and benefits under the plans and programs of a subsequent employer (or, in the event of a "Change in Control," an amount in cash equal to the reasonable expenses that the Company would incur if it were to provide these benefits for three years) and (vi) office space at a location specified by Mr. John, secretarial services, and executive job search and employment services at the Company's expense until the first to occur of the third year anniversary of the date his employment was terminated or the date on which he commences full-time employment with another employer.

In the event that Mr. John's employment were terminated by the Company for "Cause," as defined in the employment agreement, or by Mr. John voluntarily or by nonrenewal, he would be

entitled to receive only (i) and (v) above and will forfeit any restricted stock or options not previously vested. In the event Mr. John's employment were terminated by reason of his death, he would be entitled to receive (i), (iii), (iv) and (v) above, except that his family would be entitled to receive the medical and dental insurance coverage provided in (v) above until the death of Mr. John's spouse. In addition, if any of the above benefits were subject to the tax imposed by Section 4999 of the Internal Revenue Code, the Company would reimburse Mr. John for such tax on an after-tax basis.

The employment agreement contained a comprehensive non-compete provision prohibiting Mr. John from engaging in any activities that are competitive with the Company for a period of three years after the termination of his employment.

Termination of Mr. John.

Mr. John's employment with the Company ceased effective May 1, 2004. The Company paid Mr. John's regular salary for 90 days after the termination. All other cash payments which might have been required under Mr. John's employment agreement, including salary, bonuses, and severance, were suspended by the Company pending completion of the SEC investigation.

On April 7, 2006, we delivered a notice to Mr. John of our intention to treat his termination of employment effective May 1, 2004, for Cause under his employment agreement with us. Mr. John's employment agreement defines "Cause" as "the willful engaging by [Mr. John] in misconduct which is materially injurious to the Company, monetarily or otherwise." We delivered a revised notice on September 28, 2006. In our notice, as revised, we identified seven particular aspects of Mr. John's conduct that constitute Cause, any one of which is sufficient Cause for termination: (1) matters relating to certain undisclosed financial relationships between Mr. John and Mr. Wolkowitz, (2) Mr. John's abuse of credit card privileges, failure to establish and implement relevant adequate control procedures, failure timely to reimburse the company for hundreds of thousands of dollars in personal charges, and submission of false expense reports, (3) Mr. John improperly caused the Company to issue stock options to a former employee in violation of Board authority, and Mr. John failed to disclose his personal relationship with that former employee in connection with issuance of the options and a severance package for the former employee, (4) Mr. John caused Key to enter into a purported consulting agreement with a former employee that did not require the former employee to provide any services, failed to disclose relevant facts relating to the arrangement, and then caused the Company to account improperly for that consulting agreement, (5) Mr. John, in violation of Texas law, improperly authorized the reimbursement to two company employees who had made political campaign contributions in Texas, (6) Mr. John ignored admonitions to stay within the boundaries of the March 15, 2004 press release announcing our inability timely to file the 2003 Annual Report on Form 10-K and instead made statements to certain analysts that were outside the text of the press release, and (7) Mr. John failed to discharge his responsibility for the general management and operation of the Company, ultimately resulting in the company's restatement of prior period earnings and resulting adverse consequences to the Company. We also reserved the right to notify Mr. John of other matters that constitute Cause. As required by his employment agreement, we undertook to give Mr. John and his counsel the opportunity to be heard before the Board before a final determination to terminate him for Cause is made.

In response to the notice, Mr. John has filed a lawsuit against us, in which he alleges, among other things, that we breached stock option agreements and his employment agreement. On June 13, 2006, we filed an answer and counterclaim, as well as a motion to dismiss parts of his claims, in response to Mr. John's lawsuit. In addition to denying Mr. John's claims, we asserted claims against Mr. John for breach of contract and declaratory judgment including, among other things, a declaration that Cause exists under Mr. John's employment agreement.

On August 8, 2006, the court denied our motion to dismiss certain of Mr. John's claims, and denied in part and granted in part Mr. John's motion to dismiss certain of our claims. Discovery is underway.

We previously recorded a $16.4 million severance expense in connection with Mr. John's termination of employment, of which $9.0 million represented a non-cash charge for the write-off of the unamortized balance of Mr. John's prepaid retention bonus, and the balance consisted of severance and other termination costs. Mr. John would not be entitled to severance, certain other previously paid compensation or stock options under a "for cause" termination.

Employment Agreement of James J. Byerlotzer.

Effective as of January 1, 2004, Mr. Byerlotzer entered into an employment agreement with the Company pursuant to which he served as the Company's Vice Chairman. Mr. Byerlotzer previously served the Company as its Executive Vice President and Chief Operating Officer pursuant to a prior written employment agreement. The term of the January 1, 2004 agreement was until December 31, 2004, unless terminated earlier. As discussed below, Mr. Byerlotzer's employment with the Company ceased on December 31, 2004. Under the agreement, Mr. Byerlotzer's annual base compensation was $340,000 and Mr. Byerlotzer was eligible to participate in all of the Company's cash performance compensation plans providing for the payment of cash bonuses or other cash incentives. Mr. Byerlotzer's agreement also provided for a conditional deferred stock award with respect to 50,000 shares of the Company's common stock. The award was based on the Company's 2003 Long-Term Share Incentive Plan as approved by the Board, which was subject to and conditioned upon shareholder approval of the plan on or prior to September 30, 2004. Such approval was not obtained; therefore, the plan expired in accordance with its terms and no stock was issued. Mr. Byerlotzer was eligible to participate in awards of stock options, restricted stock, and other equity-based incentives at the discretion of the Board of Directors or the Compensation Committee. In addition, under the agreement, Mr. Byerlotzer was entitled to certain fringe benefits at the Company's expense, including insurance plans, retirement plans and supplemental and excess retirement benefits, and the payment of reasonable fees for personal financial advisory, counseling, accounting and related services, legal advisory or attorneys' fees and related expenses, and income tax return preparation and tax audit services. The Company agreed to pay the initiation fee and any other initial membership fee and all annual or other periodic fees for Mr. Byerlotzer to become and remain a member of one private country club or similar club or association for business use, as approved by the Chief Executive Officer.

Under the agreement, if Mr. Byerlotzer's employment with the Company ceased due to the expiration of the employment period on December 31, 2004, or if his employment were terminated by the Company for any reason other than for "Cause," or if Mr. Byerlotzer were to terminate his employment because of a material breach by the Company or following a change of control of the Company, he would be entitled to severance compensation equal to three times his base compensation in effect at the time of termination payable in one lump sum at on the termination date;provided, however, that if termination resulted from a change of control of the Company, severance compensation would be increased by an amount equal to three times the average annual total cash bonuses received by Mr. Byerlotzer over the past three years.

In addition, if Mr. Byerlotzer's employment with the Company ceased due to the expiration of the employment period on December 31, 2004, or if his employment were terminated by the Company for any reason other than for "Cause," or if Mr. Byerlotzer were to terminate his employment because of a material breach by the Company or following a change of control of the Company, any equity-based incentives held by Mr. Byerlotzer that had not vested prior to the termination date would immediately vest and all vested equity-based incentives would remain exercisable until the earlier of the third anniversary date of the termination or the stated expiration date of the equity-based incentive. If a change of control were to occur while Mr. Byerlotzer was employed by the Company, any equity-based

incentives that had not vested prior to such change of control would immediately vest, and if termination were to occur for any reason on or prior to December 30, 2004 and following a change in control, all equity-based incentives held by Mr. Byerlotzer would remain exercisable until their respective stated expiration dates.

At the expiration of the employment period on December 31, 2004, or if Mr. Byerlotzer were to terminate his employment because of a material breach by the Company or following a change in control, or if the Company were to terminate his employment for any reason other than for "Cause," Mr. Byerlotzer would continue to receive coverage at the Company's expense under the Company's group medical and dental plans for himself and his spouse until they each reach the age of 62;provided that, if termination were to occur for any reason on or prior to December 31, 2004 and following a change in control or in anticipation of a change of control, in lieu of such benefits the Company would pay an amount in cash equal to the aggregate reasonable expenses the Company would incur to pay such benefits. Also, if Mr. Byerlotzer were subject to the tax imposed by Section 4999 of the Internal Revenue Code, the Company agreed to reimburse him for such tax on an after-tax basis.

The agreement contained a comprehensive non-compete provision prohibiting Mr. Byerlotzer from engaging in any activities that are competitive with the Company for a period of three years after the termination of his employment. However, if Mr. Byerlotzer were to terminate his employment for any reason other than a material breach by the Company or following a change in control or if his employment were terminated for "Cause" by the Company, the time period would be reduced to 12 months.

Payment to Mr. Byerlotzer.

Mr. Byerlotzer's employment with the Company ceased due to the expiration of the employment period on December 31, 2004 under the terms of his employment agreement. Under the terms of the agreement, he was paid on the termination date severance compensation in one lump sum equal to three times his base compensation in effect at the time of termination. In addition, Mr. Byerlotzer will continue to receive coverage at the Company's expense under the Company's group medical and dental plans for himself and his spouse until they each reach the age of 62.

Employment Agreement of Royce W. Mitchell.

Effective as of January 1, 2004, Mr. Mitchell entered into an employment agreement with the Company pursuant to which he served as the Company's Executive Vice President and Chief Financial Officer. This agreement superseded a prior written employment agreement. The January 1, 2004 agreement was for a three-year term and thereafter for successive one-year terms unless terminated 90 days prior to the commencement of an extension term. As described below, Mr. Mitchell's employment was terminated by the Company effective January 20, 2005. Under the agreement, Mr. Mitchell received an annual base compensation of $325,000, which could be increased but not decreased. Mr. Mitchell was eligible to participate in the Company's cash performance compensation plans providing for cash bonuses or other cash incentives. In 2002, Mr. Mitchell received a one-time signing bonus of $100,000. The agreement provided that in the event that, prior to December 31, 2004, Mr. Mitchell were terminated by the Company for "Cause", or by Mr. Mitchell voluntarily or by non-renewal, Mr. Mitchell would repay to the Company an amount of such bonus equal to $33,333. In addition, the Company agreed to pay all expenses required for Mr. Mitchell to remain a member in good standing of the American Institute of Certified Public Accountants and to maintain his practice as an accountant or auditor in Texas. Mr. Mitchell's agreement also provided for a conditional deferred stock grant with respect to 150,000 shares of the Company's common stock. The award was based on the Company's 2003 Long-Term Share Incentive Plan as approved by the Board, which was subject to and conditioned upon shareholder approval of the plan on or prior to September 30, 2004. Such approval was not obtained; therefore, the plan expired in accordance with its terms and no stock was

issued. Mr. Mitchell was eligible to participate in awards of stock options, restricted stock, and other equity-based incentives at the discretion of the Board of Directors or the Compensation Committee. In addition, under the agreement, Mr. Mitchell was entitled to certain fringe benefits at the Company's expense, including insurance plans, retirement plans and supplemental and excess retirement benefits (to the extent provided for senior management) and the payment of reasonable fees up to $15,000 per year, for personal fees such as financial advisory, counseling, accounting and related services, legal advisory or attorneys' fees and related expenses, and income tax return preparation and tax audit services. Mr. Mitchell was entitled to an allowance of $1000 per month, plus reimbursement for reasonable insurance and maintenance, for the use of his automobile. The Company also agreed to pay the initiation fee and any other initial membership fee and all annual or other periodic fees for Mr. Mitchell to become and remain a member of one private country club or similar club or association for business use, as approved by the Chief Executive Officer.

If, during the term of his employment agreement, Mr. Mitchell were terminated by the Company for any reason other than for "Cause" (as defined in the agreement), or if he were to terminate his employment because of a material breach by the Company or following a change of control of the company, he would have been entitled to severance compensation in an aggregate amount equal to three times his base compensation in effect at the time of termination payable in equal installments over a 36-month period following termination;provided, however, that if termination were to result from a change of control of the Company, severance compensation would have been increased by an amount equal to three times the average annual total cash bonuses received by Mr. Mitchell over the prior three years and would have been payable in a lump sum on the date of termination. In addition, if Mr. Mitchell's employment were terminated by the Company for any reason other than for "Cause," or if Mr. Mitchell were to terminate his employment because of a material breach by the Company or following a change of control of the Company, any equity-based incentives held by Mr. Mitchell that had not vested prior to the termination date would immediately vest and all vested equity-based incentives would remain exercisable until the earlier of the third anniversary date of the termination or the stated expiration date of the equity-based incentive. If a change of control were to occur while Mr. Mitchell was employed by the Company, any equity-based incentives that had not vested prior to such change of control would immediately vest, and if termination were to occur for any reason within one year following a change in control or in anticipation of a change in control, all equity-based incentives held by Mr. Mitchell would remain exercisable until their respective stated expiration dates.

If Mr. Mitchell were to terminate his employment because of a material breach by the Company or following a change in control or the Company were to terminate his employment for any reason other than for "Cause," Mr. Mitchell would continue to receive the benefits that he was receiving at the Company's expense until the earlier of three years after the termination date or the date on which Mr. Mitchell commences full-time employment with another employer that provides equivalent benefits;provided that, if termination were to occur for any reason within one year of a change in control or in anticipation of a change of control, in lieu of such benefits the Company would pay an amount in cash equal to the aggregate reasonable expenses the Company would incur to pay such benefits. Also, if Mr. Mitchell were subject to the tax imposed by Section 4999 of the Internal Revenue code, the Company agreed to reimburse him for such tax on an after-tax basis.

The agreement contained a comprehensive non-compete and non-solicit provision prohibiting Mr. Mitchell from engaging in any activities that are competitive with the Company during his employment, for any period in which he is receiving severance compensation from the Company, or if payment of severance compensation is accelerated due to a change of control, for a period of three years after the termination of his employment. However, if Mr. Mitchell were to terminate his employment for any reason other than a material breach by the Company or following a change of control or if his employment were terminated for "Cause" by the Company, the time period would be reduced to 12 months.

Payment to Mr. Mitchell.

Mr. Mitchell's employment was terminated by the Company effective January 20, 2005. Under the terms of his employment agreement, Mr. Mitchell continues to receive his salary and other benefits that he was receiving at the Company's expense until the earlier of three years after the termination date or the date on which Mr. Mitchell commences full-time employment with another employer that provides equivalent benefits.

Employment Agreement of Jack D. Loftis, Jr.

Effective as of January 1, 2004, Mr. Loftis entered into an employment agreement with the Company pursuant to which he served as the Company's Senior Vice President and General Counsel. This agreement superseded a prior written employment agreement. The January 1, 2004 agreement was for a three-year term and thereafter for successive one-year terms unless terminated 90 days prior to the commencement of an extension term. As described below, Mr. Loftis' employment was terminated by the Company effective July 8, 2004. Under the agreement, Mr. Loftis received an annual base compensation of $275,000, which could be increased but not decreased. Mr. Loftis was eligible to participate in the Company's cash performance compensation plans providing for cash bonuses or other cash incentives. In addition, the Company agreed to pay all expenses required for Mr. Loftis to remain a member in good standing of the American Bar Association and the State Bar of Texas and to maintain his license to practice as an attorney in Texas. Mr. Loftis' agreement also provided for a conditional deferred stock grant with respect to 85,000 shares of the Company's common stock. The award was based on the Company's 2003 Long-Term Share Incentive Plan as approved by the Board, which was subject to and conditioned upon shareholder approval of the plan on or prior to September 30, 2004. Such approval was not obtained; therefore, the plan expired in accordance with its terms and no stock was issued. Mr. Loftis was eligible to participate in awards of stock options, restricted stock, and other equity-based incentives at the discretion of the Board of Directors or the Compensation Committee. In addition, under the agreement, Mr. Loftis was entitled to certain fringe benefits at the Company's expense, including insurance plans, retirement plans and supplemental and excess retirement benefits (to the extent provided for the senior management), and the payment of reasonable fees up to $15,000 per year, for personal fees such as financial advisory, counseling, accounting and related services, legal advisory or attorneys' fees and related expenses, and income tax return preparation and tax audit services. Mr. Loftis was entitled to an allowance of $1,100 per month, plus reimbursement for reasonable insurance and maintenance, for the use of his automobile. The Company also agreed to pay the initiation fee and any other initial membership fee and all annual or other periodic fees for Mr. Loftis to become and remain a member of one private country club or similar club or association for business use, as approved by the Chief Executive Officer.

If, during the term of his employment agreement, Mr. Loftis were terminated by the Company for any reason other than for "Cause" (as defined in the agreement), or if he were to terminate his employment because of a material breach by the Company or following a change of control of the company, he would have been entitled to severance compensation in an aggregate amount equal to three times his base compensation in effect at the time of termination payable in equal installments over a 36-month period following termination;provided, however, that if termination were to result from a change of control of the Company, severance compensation would have been increased by an amount equal to three times the average annual total cash bonuses received by Mr. Loftis over the prior three years and would have been payable in a lump sum on the date of termination. In addition, if Mr. Loftis' employment were terminated by the Company for any reason other than for "Cause," or if Mr. Loftis were to terminate his employment because of a material breach by the Company or following a change of control of the Company, any equity-based incentives held by Mr. Loftis that had not vested prior to the termination date would immediately vest and all vested equity-based incentives would remain exercisable until the earlier of the third anniversary date of the termination or the stated

expiration date of the equity-based incentive. If a change of control were to occur while Mr. Loftis was employed by the Company, any equity-based incentives that had not vested prior to such change of control would immediately vest, and if termination were to occur for any reason within one year following a change in control or in anticipation of a change in control, all equity-based incentives held by Mr. Loftis would remain exercisable until their respective stated expiration dates.

If Mr. Loftis were to terminate his employment because of a material breach by the Company or following a change in control or the Company were to terminate his employment for any reason other than for "Cause," Mr. Loftis would continue to receive the benefits that he was receiving at the Company's expense until the earlier of three years after the termination date or the date on which Mr. Loftis commences full-time employment with another employer that provides equivalent benefits;provided that, if termination were to occur for any reason within one year of a change in control or in anticipation of a change of control, in lieu of such benefits the Company would pay an amount in cash equal to the aggregate reasonable expenses the Company would incur to pay such benefits. Also, if Mr. Loftis were subject to the tax imposed by Section 4999 of the Internal Revenue code, the Company agreed to reimburse him for such tax on an after-tax basis.

The agreement contained a comprehensive non-compete and non-solicit provision prohibiting Mr. Loftis from engaging in any activities that are competitive with the Company during his employment, for any period in which he is receiving severance compensation from the Company, or if payment of severance compensation is accelerated due to a change of control, for a period of three years after the termination of his employment. However, if Mr. Loftis were to terminate his employment for any reason other than a material breach by the Company or following a change of control or if his employment were terminated for "Cause" by the Company, the time period would be reduced to 12 months.

Payment to Mr. Loftis.

Mr. Loftis' employment was terminated by the Company effective July 8, 2004. Under the terms of his employment agreement, Mr. Loftis continues to receive his salary and other benefits that he was receiving at the Company's expense until the earlier of three years after the termination date or the date on which Mr. Loftis commences full-time employment with another employer that provides equivalent benefits.

Employment Agreement of Jim D. Flynt.

Effective as of January 1, 2004, Mr. Flynt entered into an employment agreement with the Company pursuant to which he serves as the Company's Senior Vice President—Production Services. The employment agreement is for a three-year term and thereafter for successive one-year terms unless notice of non-renewal is given no later than 30 days preceding the relevant anniversary date. Under this agreement, Mr. Flynt receives an annual base compensation of $250,000, which can be increased at the discretion of the Company's senior management. Mr. Flynt is eligible to participate in the Company's incentive plans, and is eligible to earn a discretionary cash bonus in an amount up to 100% of his base salary, as determined by the Company's senior management or the Board of Directors. In addition, under the agreement, Mr. Flynt is entitled to certain fringe benefits at the Company's expense, including insurance plans, retirement plans and supplemental and excess retirement benefits.

If Mr. Flynt's employment is terminated by the Company for any reason other than for "Cause," he will be entitled to severance compensation in an aggregate amount equal to two times his base salary in effect at the time of termination payable in equal installments over a 24-month period following termination;provided, however, that if termination results within six months from a change of control of the Company or in anticipation of a change in control, the severance compensation will be payable in one lump sum on the date of termination. The agreement contains a non-compete provision

that prohibits Mr. Flynt from engaging in any activities that are competitive with the Company during his employment, and for an additional period of 24 months following termination if Mr. Flynt is receiving severance compensation from the Company, or for an additional period of 12 months following termination if Mr. Flynt is not receiving severance compensation from the Company.

Employment Agreement of Steven A. Richards.

Effective as of February 5, 2001, Mr. Richards entered into an employment agreement with the Company pursuant to which he served as the Company's Vice President of Drilling Operations. Effective March 5, 2003, Mr. Richards became an executive officer when he was promoted to Senior Vice President—Drilling and International. Mr. Richards then served as Senior Vice President International after the sale of our contract drilling division on January 15, 2005, and he now serves as Senior Vice President—Operations Support. Mr. Richards' employment agreement is for a two-year term and thereafter for successive one-year terms unless terminated 30 days prior to the commencement of an extension term. The agreement provides for an annual base compensation of $209,600, which can be increased but not decreased. Mr. Richards is eligible for additional annual incentive bonuses.

If during the term of his employment agreement, Mr. Richards is terminated by the Company for any reason other than for cause, he will be entitled to severance compensation equal to two times his annual base compensation in effect at the time of termination payable in equal installments over a 24-month period following termination; provided, however, in the event his employment should be terminated by the Company other than for cause within six months following a change of control of the Company or a sale of substantially all the Company's drilling assets, or in anticipation of a change of control of the Company or a sale of substantially all the Company's drilling assets, severance compensation will be payable in a lump sum on the date of termination.

Employment Agreements with Current Named Executive Officers

Richard J. Alario. Under an employment agreement, entered into as of December 31, 2003, Mr. Alario agreed to serve as the Company's President and Chief Operating Officer for a term commencing January 1, 2004 until December 31, 2006, with an automatic one-year renewal on each December 31, commencing on December 31, 2006, unless terminated by the Company or by Mr. Alario with proper notice. Under this employment agreement, Mr. Alario's annual base salary was $300,000 per year, subject to increase after annual reviews by the Chief Executive Officer and the Board of Directors. Mr. Alario was also entitled to participate in the Company's Performance Cash Compensation Plan, with performance criteria to be approved by the Compensation Committee and to receive additional bonuses at the discretion of the Compensation Committee. Mr. Alario would also receive the following bonuses if he were employed by the Company on the specified dates: (i) $100,000, if employed on January 1, 2004; (ii) $100,000, if employed on January 1, 2005; (iii) $200,000, if employed on January 1, 2006 and (iv) $232,190, if employed on December 31, 2006. Mr. Alario was also eligible to participate in stock option grants made to the Company's executives. Mr Alario's agreement also provided for a conditional deferred stock grant with respect to 125,000 shares of the Company's common stock. In addition to salary and bonuses, under this employment agreement Mr. Alario was entitled to the same additional benefits described above in connection with the May 1, 2004 employment agreement.

Under this agreement, in the event that Mr. Alario's employment was terminated (1) by Mr. Alario for "Good Reason," (2) by the Company other than for "Cause," disability or by nonrenewal, (in each case as defined in the employment agreement) or (3) as a result of Mr. Alario's disability, Mr. Alario would be entitled to receive a severance payment in an amount equal to three times his Base Salary at the rate in effect on the termination date, payable in thirty-six monthly installments, and payment of specified bonuses on January 1, 2004, January 1, 2005, January 1, 2006

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and December 31, 2006 (except that in the case of termination as a result of Mr. Alario's disability, such compensation would be reduced by the amount of any Company-paid disability insurance proceeds paid to Mr. Alario). In addition, all stock options held by Mr. Alario would become immediately vested and exerciseable (to the extent not already vested and exercisable) for the remainder of the original terms of the options or until the third anniversary of the date of termination, he would be entitled to continued participation in medical, dental and life insurance coverage until the first to occur of the third year anniversary of the date his employment was terminated or the date on which he receives equivalent coverage and benefits under the plans and programs of a subsequent employer, and he would receive any other amounts or benefits earned, accruing or owing to him, but not yet paid.

Effective as of May 1, 2004, the Company entered into a new employment agreement with Mr. Alario superseding the employment agreement of December 31, 2003, which provides that Mr. Alario will serve as Chief Executive Officer and President of the Company until December 31, 2007, with an automatic one-year renewal on each December 31, commencing on December 31, 2007, unless terminated by the Company or by Mr. Alario with proper notice. Under this employment agreement, Mr. Alario's annual base salary is $700,000 per year, subject to increase (but not decrease) after annual reviews by the Compensation Committee or the Board of Directors. This employment agreement also provides that Mr. Alario will be entitled to participate in the Company's Performance Cash Compensation Plan, with performance criteria to be approved by the Compensation Committee and to receive additional bonuses at the discretion of the Compensation Committee. Mr. Alario will be entitled to receive the following bonuses if he is employed by the Company on the specified dates: (i) $100,000, if employed on January 1, 2005; (ii) $200,000, if employed on January 1, 2006 and (iii) $232,190, if employed on December 31, 2006. Mr. Alario will also participate in stock option grants made to the Company's executives, including a deferred stock grant with respect to 125,000 shares of the Company's common stock, an additional deferred stock grant of 125,000 shares of the Company's common stock to be granted by the Compensation Committee once performance goals are set for the period from July 1, 2004 through December 31, 2005, and non-qualified stock options for 250,000 shares of the Company's common stock with the exercise price set as of the date of grant and with cliff vesting as of the first anniversary of the date of grant. In order to comply with the requirements of Regulation BTR, the 250,000 stock option grant was rescinded effective March 25, 2005.

In addition to salary and bonus, Mr. Alario is entitled to medical, dental, accident and life insurance, reasonable fees for personal financial advisory, counseling, accounting and related services, legal advisory or attorneys' fees and income tax return preparation and tax audit services. The Company will provide an allowance of $1,100 per month, plus reimbursement for reasonable insurance and maintenance expenses, to cover the costs incurred for the use of Mr. Alario's automobile during his employment. The Company also agreed to pay the initiation fee and any other initial membership fee and all annual or other periodic fees for Mr. Alario to become and remain a member of one private country club or similar club or association for business use, as approved by the Compensation Committee. The Company also will pay certain expenses and costs incurred in connection with Mr. Alario's relocation to the Company's executive offices, including a cash gross-up bonus payment calculated to pay all of the federal, state and local income and payroll taxes which Mr. Alario will incur as a result of the Company's reimbursement of relocation expenses and the amount of such bonus.

In the event that Mr. Alario's employment is terminated (1) by Mr. Alario for "Good Reason," (2) by the Company other than for "Cause," disability or by nonrenewal, (in each case as defined in the employment agreement) or (3) as a result of Mr. Alario's disability, Mr. Alario will be entitled to receive a severance payment in an amount equal to three times his Base Salary at the rate in effect on the termination date, payable in thirty-six monthly installments, and payment of specified bonuses on January 1, 2005, January 1, 2006 and December 31, 2006 (except that in the case of termination as a result of Mr. Alario's disability, such compensation will be reduced by the amount of any Company-paid disability insurance proceeds paid to Mr. Alario). In addition, all stock options held by

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Mr. Alario will become immediately vested and exerciseable (to the extent not already vested and exercisable) for the remainder of the original terms of the options or until the third anniversary of the date of termination, he will be entitled to continued participation in medical, dental and life insurance coverage until the first to occur of the third year anniversary of the date his employment was terminated or the date on which he receives equivalent coverage and benefits under the plans and programs of a subsequent employer, and he will receive any other amounts or benefits earned, accruing or owing to him, but not yet paid.

As amended effective June 24, 2005, the employment agreement specifies that if Mr. Alario's employment is terminated by either the Company or Mr. Alario in anticipation of, or within one year following, a "Change in Control" (as defined in the employment agreement), his severance compensation will be an amount equal to three times his Base Salary then in effect plus an amount equal to three times his annual target cash bonus, and will be payable in one lump sum on the effective date of the termination. Also, all stock options held by Mr. Alario will become immediately vested and exercisable (to the extent not already vested and exercisable) for the remainder of the original terms of the options, he will be entitled to an amount in cash equal to the reasonable expenses that the Company would incur if it were to provide continued participation in medical, dental and life insurance coverage for three years, and he will receive any other amounts or benefits earned, accruing or owing to him, but not yet paid. In the event that Mr. Alario's employment is terminated by the Company for "Cause," as defined in the employment agreement, or by Mr. Alario voluntarily or by nonrenewal, he will forfeit any restricted stock or options not previously vested. In addition, if any of the above benefits are subject to the tax imposed by Section 4999 of the Internal Revenue Code, the Company will reimburse Mr. Alario for such tax on an after-tax basis.

The employment agreement contains a comprehensive non-compete provision that prohibits Mr. Alario from engaging in any activities that are competitive with the Company for a period of three years after the termination of his employment (or twelve months, if Mr. Alario's employment is terminated by the Company for Cause or by Mr. Alario for other than Good Reason).

William M. Austin. Effective as of March 1, 2005, Mr. Austin entered into an employment agreement with the Company pursuant to which he serves as the Company's Senior Vice President and Chief Financial Officer. The employment agreement was amended on June 24, 2005. The employment agreement, as amended, is for a three-year term and thereafter for successive one-year terms unless notice of non-renewal is given no later than the December 1 preceding the relevant anniversary date. Under this agreement, Mr. Austin receives an annual base compensation of $400,000, which can be increased but not decreased. Mr. Austin is eligible to participate in the Company's cash performance compensation plans providing for cash bonuses or other cash incentives, and, for the period from January to July 2005, was eligible to receive a bonus of the greater of the amount provided under such plans or $200,000, assuming continued employment by the Company through the end of that period. Mr. Austin previously received non-qualified stock options with respect to 100,000 shares of the Company's common stock in his capacity as a consultant to Key. He is eligible to participate in awards of stock options, restricted stock, and other equity-based incentives at the discretion of the Board of Directors or the Compensation Committee. The agreement noted the Compensation Committee's intent to grant shares of restricted stock to Mr. Austin equal to a target of 100,000 shares, which were granted in June 2005. In addition, under the agreement, Mr. Austin is entitled to certain fringe benefits at the Company's expense, including medical and dental plans.

If, during the term of his employment agreement, Mr. Austin is terminated by the Company for any reason other than for "Cause" or disability, or if he terminates his employment because of a material breach by the Company or following a change of control of the company, he will be entitled to severance compensation in an aggregate amount equal to two times his base salary in effect at the time of termination payable in equal installments over a 24-month period following termination. However, the employment agreement specifies that if termination is in anticipation of, or within one year

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following a change of control of the Company, severance compensation will be an amount equal to three times his base salary in effect at the time of termination plus an amount equal to three times his annual target cash bonus and will be payable in a lump sum on the date of termination. In addition, if Mr. Austin's employment is terminated by the Company for any reason other than for "Cause," or if Mr. Austin terminates his employment because of a material breach by the Company or following a change of control of the Company, any equity-based incentives held by Mr. Austin that have not vested prior to the termination date shall immediately vest and all vested equity-based incentives shall remain exercisable until the earlier of the first anniversary date of the termination or the stated expiration date of the equity-based incentive.

If Mr. Austin terminates his employment because of a material breach by the Company or following a change in control or the Company terminates his employment for any reason other than for "Cause," Mr. Austin will continue to receive the benefits that he was receiving at the Company's expense until the earlier of two years after the termination date or the date on which Mr. Austin commences full-time employment with another employer that provides equivalent benefits;provided that, if termination occurs for any reason within one year of a change in control or in anticipation of a change of control, in lieu of such benefits the Company will pay an amount in cash equal to the aggregate reasonable expenses the Company would incur to pay such benefits. Also, if Mr. Austin is subject to the tax imposed by Section 4999 of the Internal Revenue code, the Company has agreed to reimburse him for such tax on an after-tax basis.

The agreement contains a comprehensive non-compete provision that prohibits Mr. Austin from engaging in any activities that are competitive with the Company during his employment, for any period in which he is receiving severance compensation from the Company, or if payment of severance compensation is accelerated due to a change of control, for a period of three years after the termination of his employment. However, if Mr. Austin terminates his employment for any reason other than a material breach by the Company or following a change of control or if his employment is terminated for "Cause" by the Company, the time period is reduced to 12 months.

Newton W. Wilson, III. Effective as of January 24, 2005, Mr. Wilson entered into an employment agreement with the Company pursuant to which he serves as the Company's Senior Vice President and General Counsel. This employment agreement was amended on June 24, 2005. Mr. Wilson also serves as Secretary of the Company. As amended, the employment agreement is for a three-year term and thereafter for successive one-year terms unless terminated 90 days prior to the commencement of an extension term. Under this agreement, Mr. Wilson receives an annual base compensation of $350,000, which can be increased but not decreased. Mr. Wilson is eligible to participate in the Company's cash performance compensation plans providing for cash bonuses or other cash incentives. Mr. Wilson will also receive the following bonuses if he is employed by the Company on the specified dates: (i) $100,000, if employed on January 24, 2006; (ii) $100,000, if employed on January 24, 2007 and (iii) $100,000, if employed on January 24, 2008. Mr. Wilson is entitled to receive a grant of stock options to purchase to 125,000 shares of the Company's common stock and is eligible to participate in awards of stock options, restricted stock, and other equity-based incentives at the discretion of the Board of Directors or the Compensation Committee. In order to comply with the requirements of Regulation BTR, the 125,000 stock option grant was rescinded effective March 25, 2005. In addition, under the agreement, Mr. Wilson is entitled to certain fringe benefits at the Company's expense, including medical and dental plans. The Company also will pay certain expenses and costs incurred in connection with Mr. Wilson's relocation to the Company's executive offices, including a cash gross-up bonus payment calculated to pay all of the federal, state and local income and payroll taxes which Mr. Wilson will incur as a result of the Company's reimbursement of relocation expenses and the amount of such bonus. In addition, Mr. Wilson will receive a payment of $171,000 on or around the completion of his relocation.

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If, during the term of his employment agreement, Mr. Wilson is terminated by the Company for any reason other than for "Cause," or if he terminates his employment because of a material breach by the Company or following a change of control of the company, he will be entitled to severance compensation in an aggregate amount equal to two times his base compensation in effect at the time of termination payable in equal installments over a 24-month period following termination;provided, however, that if termination is in anticipation of, or within one year following, a change of control of the Company, severance compensation will be an amount equal to three times his base compensation in effect at the time of termination plus an amount equal to three times his annual cash target bonus and will be payable in a lump sum on the date of termination. In addition, if Mr. Wilson's employment is terminated by the Company for any reason other than for "Cause," or if Mr. Wilson terminates his employment because of a material breach by the Company or following a change of control of the Company, any equity-based incentives held by Mr. Wilson that have not vested prior to the termination date shall immediately vest and all vested equity-based incentives shall remain exercisable until the earlier of the first anniversary date of the termination or the stated expiration date of the equity-based incentive.

If Mr. Wilson terminates his employment because of a material breach by the Company or following a change in control, or the Company terminates his employment for any reason other than for "Cause," Mr. Wilson will continue to receive the benefits that he was receiving at the Company's expense until the earlier of two years after the termination date or the date on which Mr. Wilson commences full-time employment with another employer that provides equivalent benefits;provided that, if termination occurs for any reason within one year of a change in control or in anticipation of a change of control, in lieu of such benefits the Company will pay an amount in cash equal to the aggregate reasonable expenses the Company would incur to pay such benefits. Also, if Mr. Wilson is subject to the tax imposed by Section 4999 of the Internal Revenue code, the Company has agreed to reimburse him for such tax on an after-tax basis.

The agreement contains a comprehensive non-compete provision that prohibits Mr. Wilson from engaging in any activities that are competitive with the Company during his employment, for any period in which he is receiving severance compensation from the Company, or if payment of severance compensation is accelerated due to a change of control, for a period of three years after the termination of his employment. However, if Mr. Wilson terminates his employment for any reason other than a material breach by the Company or following a change of control or if his employment is terminated for "Cause" by the Company, the time period is reduced to 12 months.

Kim B. Clarke. Effective as of November 22, 2004, Ms. Clarke entered into an employment agreement with the Company pursuant to which she serves as the Company's Vice President—Chief People Officer. The agreement was subsequently amended effective June 24, 2005 and April 1, 2006. As a result of the June 24, 2005 amendment, Ms. Clarke's title was changed to Senior Vice President—Chief People Officer. The employment agreement, as amended, is for a two-year term and thereafter for successive one-year terms unless notice of non-renewal is given no later than 30 days preceding the relevant anniversary date. Under this agreement, Ms. Clarke receives an annual base compensation of $185,000, which can be increased at the discretion of the Company's senior management. Ms. Clarke is eligible to participate in the Company's incentive plans, and is eligible to earn a discretionary cash bonus in an amount up to 50% of her base salary, as determined by the Company's senior management or the Board of Directors. Notwithstanding the foregoing, Ms. Clarke's cash bonuses for 2005 will total not less than $69,375 and will be payable as follows: (i) $46,250 for the six-months ended June 30, 2005, and (ii) $23,125 for the six-months ended December 31, 2005. Ms. Clarke also received options to purchase 10,000 shares of Key's common stock.

If Ms. Clarke's employment is terminated by the Company for any reason other than for "Cause," she will be entitled to severance compensation in an aggregate amount equal to one time her base salary in effect at the time of termination payable in equal installments over a 12-month period

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following termination. However, the employment agreement specifies that if termination results within twelve months following a change of control of the Company or in anticipation of a change in control, the severance compensation will be equal to three times her base salary in effect at the time of termination, plus an amount equal to three times the annual total cash bonus payable for the fiscal year in which notice of termination is given, and will be payable in one lump sum on the date of termination. Also, if Ms. Clarke is subject to the tax imposed by Section 4999 of the Internal Revenue Code, the Company has agreed, subject to certain conditions, to reimburse her for such tax on an after-tax basis. In addition, effective April 1, 2006, Ms. Clarke was entitled to participate in the Company's benefit plan for senior management that provides for the reimbursement of out of pocket health care expenses.

The agreement contains a non-compete provision that prohibits Ms. Clarke from engaging in any activities that are competitive with the Company during her employment and for an additional period of 12 months from the date of termination of employment.

Jim D. Flynt. The terms of Mr. Flynt's agreement are as discussed above.

Steven A. Richards. The terms of Mr. Richards' agreement are as discussed above.

Director Compensation

No director who is also an employee of the Company or any of its subsidiaries received any fees from the Company for his services as a Director or as a member of any committee of the Board during the fiscal years ended December 31, 2003, 2004 or 2005. During the fiscal years ended December 31, 2003 and December 31, 2004, all other Directors ("Non-employee Directors"), other than the Audit Committee Chairman who received $80,000 per year, received a fee equal to $65,000 per year and were reimbursed for travel and other expenses directly associated with Company business.

Effective July 1, 2005, the Non-employee Directors receive a fee equal to $65,000 per year and an annual award of Common Stock of the Company having a fair market value of $85,000, and are reimbursed for travel and other expenses directly associated with Company business. Each Non-Employee Director received the annual award of Common Stock in 2005 and 2006, except Mr. Wolkowitz, who declined such awards. The chairs of the Compensation Committee and the Corporate Governance and Nominating Committee each receive an additional $10,000 per year for their service, and the chair of the Audit Committee and the Lead Director each receive an additional $20,000 per year. All other members of the Audit Committee (other than the chair) receive an additional $10,000 per year.

Compensation Committee Interlocks and Insider Participation

The following members of our Board of Directors served on our Compensation Committee for the years ended December 31, 2003, December 31, 2004 and December 31, 2005:

David J. Breazzano
William D. Fertig
Ralph S. Michael, III
J. Robinson West

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Management

The following table sets forth as of August 31, 2006, the number of shares of Common Stock beneficially owned by each of the Company's directors and the individuals named in both of the

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Summary Compensation Tables set forth above under "Executive Compensation," as well as by the current directors and executive officers of the Company as a group. We are providing this information as of the most recent practicable date as we believe this information is most relevant to our investors. Except as noted below, each holder has sole voting and investment power with respect to all shares of Common Stock listed as owned by such person.

Name of Beneficial Owner	Number of Shares(1)	Percentage of Outstanding Shares(2)
Richard J. Alario(3)	247,083	*
David J. Breazzano(4)	332,828	*
Kevin P. Collins(5)	237,900	*
Daniel L. Dienstbier	11,567	*
William D. Fertig(6)	117,828	*
W. Phillip Marcum(7)	237,900	*
Ralph S. Michael, III(8)	36,628	*
J. Robinson West(9)	52,828	*
Morton Wolkowitz(10)	840,302	*
William M. Austin(11)	91,665	*
Newton W. Wilson, III(12)	108,332	*
Kim B. Clarke(13)	8,749	*
Jim D. Flynt(14)	172,167	*
Steven A. Richards(15)	110,000	*
Francis J. John(16)	4,000,500	3.05	%
Royce W. Mitchell(17)	400,000	*
James J. Byerlotzer(18)	776,760	*
Jack D. Loftis, Jr.(19)	480,000	*
Current Directors and Executive Officers as a group (16 persons)(20)	2,615,776	1.99	%

*: Less than 1%
(1): Includes all shares with respect to which each director or executive officer directly or indirectly, through any contract, arrangement, understanding, relationship or otherwise, has or shares the power to vote or to direct voting of such shares and/or to dispose or to direct the disposition of such shares. Includes shares that may be purchased under currently exercisable stock options and warrants.
(2): Based on 131,299,038 shares of Common Stock outstanding at August 31, 2006, plus, for each beneficial owner, those numbers of shares underlying currently exercisable options held by each executive officer or director.
(3): Includes 133,333 shares issuable upon the exercise of vested options. Does not include 66,667 shares issuable pursuant to options that have not vested. Does not include 100,000 shares issuable pursuant to Restricted Stock that have not vested.
(4): Includes 250,000 shares issuable upon the exercise of vested options.
(5): Includes 220,000 shares issuable upon the exercise of vested options.
(6): Includes 100,000 shares issuable upon the exercise of vested options.
(7): Includes 220,000 shares issuable upon the exercise of vested options.
(8): Includes 20,000 shares issuable upon the exercise of vested options.
(9): Includes 40,000 shares issuable upon the exercise of vested options.

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(10): Includes 257,000 shares issuable upon the exercise of vested options.
(11): Includes 66,666 shares issuable upon the exercise of vested options. Does not include 33,334 shares issuable pursuant to options that have not vested. Does not include 66,667 shares issuable pursuant to Restricted Stock that have not vested.
(12): Includes 83,333 shares issuable upon the exercise of vested options. Does not include 41,667 shares issuable pursuant to options that have not vested. Does not include 66,667 shares issuable pursuant to Restricted Stock that have not vested.
(13): Includes 3,333 shares issuable upon the exercise of vested options. Does not include 21,667 shares issuable pursuant to options that have not vested. Does not include 16,667 shares issuable pursuant to Restricted Stock that have not vested.
(14): Includes 171,667 shares issuable upon the exercise of vested options. Does not include 25,000 shares issuable pursuant to options that have not vested or 500 shares held by Mr. Flynt's spouse.
(15): Includes 110,000 shares issuable upon the exercise of vested options. Mr. Richards was a named executive officer in 2003 and 2004.
(16): Assumes 3,910,000 shares which may be issuable upon exercise of certain options if determined to be vested and not otherwise forfeited. Mr. John ceased to be president of the Company effective January 1, 2004, and ceased to be chief executive officer of the Company on May 1, 2004. He resigned as a member of the Board of Directors on August 25, 2004. See the section entitled "Legal Proceedings and Other Actions—–Litigation with Former Officers."
(17): Assumes 400,000 shares, which may be issuable upon the exercise of certain options if determined to be vested and not otherwise forfeited. Mr. Mitchell ceased to be an executive officer of the Company on January 20, 2005.
(18): Includes 760,000 shares issuable upon the exercise of vested options. Does not include 7,484 shares held by Mr. Byerlotzer's children. Mr. Byerlotzer ceased to be an executive officer of the Company on December 31, 2004.
(19): Assumes 480,000 shares, which may be issuable upon the exercise of certain options if determined to be vested and not otherwise forfeited. Mr. Loftis ceased to be an executive officer of the Company on July 8, 2004.
(20): Does not include the beneficial ownership of Messrs. John, Mitchell, Byerlotzer or Loftis.

Certain Beneficial Owners

The following table sets forth, as of August 31, 2006, certain information regarding the beneficial ownership of Common Stock by each person, other than the Company's directors or executive officers, who is known by the Company to own beneficially more than 5% of the outstanding shares of Common Stock. We are providing this information as of the most recent practicable date as we believe this information is most relevant to our investors.

	Shares Beneficially Owned at June 30, 2006
Name and Address of Beneficial Owner	Shares Beneficially Owned at June 30, 2006
Name and Address of Beneficial Owner	Number	Percent
Eubel Brady & Suttman Asset Management, Inc.(1) 7777 Washington Village Dr., Suite 210 Dayton, OH 45459	8,483,648	6.5	%

(1): As reported on Schedule 13G/A filed with the SEC on February 14, 2006. Eubel Brady & Suttman Asset Management, Inc. ("EBS") holds 8,483,508 shares. Ronald L. Eubel, Mark E. Brady,

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Robert J. Suttman, William E. Hazel and Bernard J. Holtgreive may, as a result of their ownership in a position with EBS and other affiliated entities, be deemed to be indirect beneficial owners of the 8,483,648 shares held by EBS and one affiliated entity, EBS Partners, LP. Mr. Hazel is the beneficial owner of an additional 510 shares. None of Mr. Eubel, Mr. Brady, Mr. Suttman, Mr. Hazel or Mr. Holtgreive admit beneficial ownership of the securities for which they report shared dispositive and voting power.

Equity Compensation Plan Information

The following table sets forth information as of December 31, 2005 with respect to compensation plans (including individual compensation arrangements) under which our common stock are authorized for issuance. We are providing this information as of the most recent practicable date as we believe this information is most relevant to our investors.

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(in thousands) (a)	(b)	(in thousands)(c)
Equity compensation plans approved by shareholders(1)	6,195	8.89	1,581
Equity compensation plans not approved by shareholders(2)	3,300	8.49	—

Total	9,495		1,581

(1): Represents options and other stock-based awards granted under the Key Energy Group, Inc. 1997 Incentive Plan (the "Plan").
(2): Represents non-statutory stock options granted outside the Plan. The options have a ten-year term and other terms and conditions as those options granted under the Plan. These options were issued during 2000 and 2001.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Loan Agreement and Retention Incentive Payment to Mr. John.

In 1999, in connection with the negotiation of the terms of a five-year employment agreement with Mr. John and as an inducement to Mr. John to enter into such employment agreement, the Company entered into a separate loan agreement with Mr. John dated as of August 2, 1999, which, as amended through June 30, 2001, provided that $6.5 million in loans previously made by the Company to Mr. John, together with the accrued interest payable thereon (accruing at a rate equal to 125 basis points above LIBOR, adjusted monthly) would be forgiven ratably during the ten-year period commencing on July 1, 2001 and ending on June 30, 2011. The loan agreement provided that the foregoing forgiveness of indebtedness was predicated and conditioned upon Mr. John remaining employed by the Company during such period. In addition, in the event that Mr. John had been terminated by the Company for "Cause" (as defined in the agreement), or in the event that Mr. John had voluntarily terminated his employment with the Company, the loan agreement further provided that the entire remaining principal balance of these loans, together with accrued interest payable thereon, would become immediately due and payable by Mr. John. However, in the event that Mr. John's employment had been terminated for "Good Reason", or as a result of Mr. John's death or

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"Disability", or as a result of a "Change in Control" (all as defined in that agreement), the loan agreement stipulated that the remaining principal balance outstanding on the loans, together with accrued interest thereon will be forgiven. This loan agreement further provided that with respect to any forgiveness of the payment of principal and interest on the loans, Mr. John would be entitled to receive a "gross-up" payment in an amount sufficient for him to pay any federal, state, or local income taxes that may be due and payable by him with respect to the forgiveness of such indebtedness (principal and interest). The loan agreement was effectively superseded by Mr. John's new employment agreement that provided for a one-time retention incentive payment that was made and used to repay all amounts owed under the loan agreement.

Under the employment agreement entered into in 2001, the Company paid to Mr. John, on December 1, 2001, a one-time retention incentive payment of $13.1 million equal to the aggregate amount of all principal and interest on loans previously made by the Company to Mr. John that were to be forgiven over a ten year period beginning July 1, 2001, as well as the amount, on an after-tax basis, required to pay the taxes incurred by Mr. John in connection with such payment. The after-tax proceeds of the payment were used to repay such loans. For the year ended December 31, 2003, the six months ended December 31, 2002 and the year ended June 30, 2002, Mr. John earned $1.3 million, $0.6 million and $1.3 million, respectively, of the retention incentive payment. If Mr. John were to have voluntarily terminated his employment with Key or if Mr. John were terminated by Key for Cause (as defined in the Employment Agreement), Mr. John would have been obligated to repay the entire remaining unearned balance of the retention incentive payment immediately upon such termination. However, if Mr. John's employment with Key were terminated (i) by Key other than for Cause, (ii) by Mr. John for Good Reason (as defined in the Employment Agreement), (iii) as a result of Mr. John's death or Disability (as defined in the Employment Agreement), or (iv) as a result of a Change in Control (as defined in the Employment Agreement), the remaining unearned balance of the retention incentive payment would have been treated as earned as of the date of such event.

See the section entitled "Executive Compensation—Employment Agreements and Termination and Change-in-Control Arrangements with Named Executive Officers."

From July 2004 to January 2005, Mr. Austin, our current Senior Vice President and Chief Financial Officer, served as an advisor, principally in a financial capacity, to the Company. Through his consulting company, Arrowhead Associates, LLC, Mr. Austin was paid an aggregate of $427,056 for his work with Key. Mr. Austin also was granted 100,000 non-qualified stock options at an exercise price of $10.53 per share.

During the period from the beginning of the Company's 2003 fiscal year until June 2003, Jim D. Flynt was indebted to the Company in the principal amount of $140,000 pursuant to a temporary relocation bridge loan that has since been repaid in full. Prior to its repayment, the loan accrued interest at a rate of 6% per annum. Craig Owen, Mr. Flynt's son-in-law, is our Operations Manager in our Mid-Continent Division. He received $87,314, $110,065 and $129,066 in salary and bonus as of December 31, 2005, December 31, 2004 and December 31, 2003, respectively.

On March 22, 2004, Odessa Exploration Incorporated, a Delaware corporation and wholly-owned subsidiary of Key ("OEI"), sold to Marcum Gas Transmission, Inc., a Colorado corporation and wholly-owned subsidiary of Metretek Technologies, Inc., all of its interest in the Marcum Midstream 1995-2 Business Trust, a Delaware statutory trust. Mr. Phil Marcum is the chairman and chief executive officer of Metretek. The aggregate purchase price for the shares was $454,000. The shares were originally acquired by OEI in 1997 for an aggregate investment of approximately $700,000, plus forgone distributions of $257,590 to cover capital calls. Over the course of the investment, OEI made contributions of $0.95 million and received distributions of $1.25 million, which include the $0.45 million sales proceeds. We recorded a loss upon disposition of these investments of approximately $30,000 in 2003. The effective date of the sale was December 31, 2003. Please see the sections entitled

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"Consolidated Financial Statements and Supplementary Data," Note 2—"Restatement of Financial Statements" in a detailed discussion of the accounting associated with OEI's investment in Marcum Gas Transmission and Note 18—"Transactions with Related Parties" for greater detail on the investment.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Aggregate fees for professional services rendered for the Company by KPMG LLP for the years ended December 31, 2005, 2004, 2003 and 2002, were

		December 31, 2005		December 31, 2004		December 31, 2003		December 31, 2002
Audit Fees		$	5,398,000	$	2,368,117	$	978,482	$	441,231
Audit Related Fees			150,000		100,000		154,631		174,916
Tax Fees			181,516		1,462,972		1,002,771		198,052
All Other Fees			19,324		—		83,175		3,100

	Total Fees	$	5,748,840	$	3,931,089	$	2,219,059	$	817,299

The Audit fees for the years ended December 31, 2003 and 2002, respectively, were for professional services rendered for the audits of the consolidated financial statements of Key Energy and it subsidiaries, audits, the review of documents filed with the SEC, consents, and the issuance of comfort letters.

The Audit Related fees for the years ended December 31, 2003, 2004 and 2005 were for professional services rendered for Sarbanes-Oxley Act of 2002 Section 404 readiness assessment, accounting consultations, and other attest services. Fees for the year ended December 31, 2002 were for services rendered for internal audit services, due diligence related to acquisitions, accounting consultations pertaining to divestitures, and other attest services.

Tax fees for the years ended December 31, 2005, 2004, 2003 and 2002, respectively, were for professional services related to tax compliance and tax planning.

All Other fees for the years ended December 31, 2005, 2004, 2003 and 2002 were for professional services rendered for other advisory services.

Policy for Approval of Audit and Non-Audit Fees. During 2003, 2004 and 2005, the Audit Committee approved all the types of audit and non-audit services which KPMG LLP was to perform during the year and the range of fees for each of these categories, as required under applicable law. The Audit Committee's current practice is to consider for pre-approval annually all categories of audit and non-audit services proposed to be provided by our independent public accountants for the fiscal year. The Audit Committee will also consider for pre-approval annually the range of fees and the manner in which the fees are determined for each type of pre-approved audit and non-audit services proposed to be provided by our independent public accountants for the fiscal year. The Audit Committee must separately pre-approve any service that is not included in the approved list of services or any proposed services exceeding pre-approved cost levels. The Audit Committee has delegated pre-approval authority to the Chairman of the Audit Committee for services that need to be addressed between Audit Committee meetings. The Audit Committee is then informed of these pre-approval decisions, if any, at the next meeting of the Audit Committee. In selecting KPMG LLP as our independent public accountants, the Audit Committee believes the provision of the audit and non-audit services rendered by KPMG LLP is compatible with maintaining that firm's independence.

The Audit Committee has considered whether the provision of non-audit services by KPMG LLP is compatible with maintaining auditor independence and has determined that auditor independence has not been compromised.

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KEY ENERGY SERVICES, INC. 2003 FINANCIAL AND INFORMATIONAL REPORT
Key Energy Services, Inc. INDEX
CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS
INTRODUCTION

BUSINESS.