ITEM 1. BUSINESS.
THE COMPANY
Key Energy Services, Inc. (the "Company" or "Key"), is the largest onshore, rig-based well servicing contractor in the world, with approximately 1,486 well service rigs and 1,719 oilfield service vehicles as of June 30, 2002. Key provides 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 (including horizontal recompletions); oilfield trucking services; and ancillary oilfield services. Key conducts well servicing operations onshore 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 region), Four Corners (including the San Juan, Piceance, Uinta, and Paradox Basins), Eastern (including the Appalachian, Michigan and Illinois 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 Ontario, Canada. Key is also a leading onshore drilling contractor, with 79 land drilling rigs as of June 30, 2002. Key conducts land drilling operations in a number of major domestic producing basins, as well as in Argentina and in Ontario, Canada. Key also produces and develops oil and natural gas reserves in the Permian Basin region and Texas Panhandle.
Key's principal executive office is located at 6 Desta Drive, Midland, Texas 79705. Key's phone number is (915) 620-0300 and website address is www.keyenergy.com.
BUSINESS STRATEGY
Key has built its leadership position through the consolidation of smaller, less viable competitors. This
consolidation, together with a continuing decline in the number of available domestic well service rigs due to attrition, cannibalization and transfers outside of the United States, has given Key the opportunity to strengthen its position within the industry during fiscal 2001 and 2002. Key has focused on maximizing results by reducing debt, building strong customer alliances, refurbishing rigs and related equipment, and training personnel to maintain a qualified and safe employee base.
REDUCING DEBT. Over the past fiscal year, Key has significantly reduced debt and strengthened its balance sheet. At June 30, 2002, Key's long-term funded debt net of cash and capitalized leases ("net funded debt") was approximately $366,634,000 and its net funded debt to capitalization ratio was approximately 41% as compared to approximately $468,845,000 and 50%, respectively, at June 30, 2001. Key expects to be able to continue to reduce debt from available cash flow from operations and from anticipated interest savings resulting from prior and future debt reductions and future debt refinancings.
BUILDING STRONG CUSTOMER ALLIANCES. Key seeks to maximize customer satisfaction by offering a broad range of equipment and services combined with a highly trained and motivated labor force. As a result, Key is able to offer proactive solutions for most of its customer's wellsite needs. Key ensures consistent high standards of quality and customer satisfaction by continually evaluating its performance. Key maintains strong alliances with major oil companies as well as numerous independent oil and natural gas production companies and believes that such alliances improve the stability of demand for its oilfield services.
REFURBISHING RIGS AND RELATED EQUIPMENT. Key intends to continue actively refurbishing its rigs and related equipment to maximize the utilization of its rig fleet. The increase in Key's cash flow, both from operations and from anticipated interest savings from reduced levels of debt, combined with Key's borrowing availability under its revolving credit facility, has provided ample liquidity and resources necessary to make the capital expenditures to refurbish such equipment.
TRAINING AND DEVELOPING EMPLOYEES. Key has, and will continue to, devote significant resources to the training and professional development of its employees with a special emphasis on safety. Key currently has two training centers in Texas and one training center in California to improve its employees' understanding of operating and safety procedures. Key recognizes the historically high turn-over rate in the industry and is committed to offering compensation, benefits and incentive programs for its employees that are attractive and competitive in its industry, in order to ensure a steady stream of qualified, safe personnel to provide quality service to its customers.
MAJOR DEVELOPMENTS DURING AND SUBSEQUENT TO FISCAL 2002
DEPRESSED INDUSTRY CONDITIONS
Operating conditions declined significantly during fiscal 2002 as capital spending by oil and natural gas producers for well servicing and contract drilling services decreased from prior year levels. The decreased spending was primarily due to lower commodity prices (and the perception by the Company's customers that commodity prices will decrease further) with WTI Cushing prices for light sweet crude averaging approximately $23.81 per barrel and Nymex Henry Hub natural gas prices averaging approximately $2.77 per MMbtu during fiscal 2002, as compared to an average WTI Cushing price for light sweet crude of $26.97 per barrel and an average Nymex Henry Hub natural gas price of $5.09 per MMbtu during fiscal 2001.
The lower commodity prices during fiscal 2002 led to a rapid decrease in the demand for Key's services and equipment beginning in the December 2001 quarter as Key's customers reduced their exploration and development activity in Key's primary market areas. Beginning in late calendar 2001, rising natural gas inventories and the prospect of a slowing economy caused concern in the commodity markets which resulted in a steady decline in commodity prices. The lower commodity prices, along with the change in market sentiment, forced some of our customers to reduce/delay their capital spending plans. Despite the decline in activity, Key was successful in minimizing rate concessions; however, the decrease in demand and moderately lower rates resulted in sequential decreases in revenues, cash flow and net income in the last three quarters of fiscal 2002 over the same quarters of fiscal 2001. Key expects demand for its services to gradually improve from its existing levels as commodity prices have improved with WTI Cushing prices averaging $28.35 per barrel and Nymex Henry Hub natural gas prices averaging $3.05 per MMbtu during the month of August 2002.
Despite the decline from fiscal 2001, crude oil prices continued to trade at healthy levels during fiscal 2002 due largely to the ability of the Organization of Petroleum Exporting Countries ("OPEC") to adhere to its production quotas designed to keep crude oil prices in the range of $22.00 to $28.00 per barrel. The adherence to the production quotas brought more stability to crude oil prices; however, between November 2001 and February 2002, crude oil prices did decline and averaged less than $20 per barrel. The decline in pricing led many oil and gas producers to reduce their capital spending until such time that commodity prices recovered. Since February 2002, crude oil prices have strengthened due to concerns of a potential Middle East conflict, lower oil inventories and the prospects of an improving economy. During this same period, natural gas prices have also improved. Since February 2002, Nymex Henry Hub prices have improved to $3.05 per MMbtu from $2.23 per MMbtu. Despite today's strong commodity prices, activity continues to remain modest, although the Company has experienced slight improvements in rig hours during the past few months. While management believes that many of its customers generally base their capital spending budgets on a crude oil price of $18.00 to $22.00 per barrel and a natural gas price of $2.00 to $2.75 per MMbtu, there can be no assurances that its customers will not postpone and/or reduce their capital spending plans if crude oil prices and natural gas prices continue to remain at or below their current levels. Assuming no further weakening in the U.S. economy and a normal winter in the United States, management believes that activity levels should improve during calendar 2003.
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 (See Part II-Item 7 - Management's Discussion and Analysis of Results of Operations and Financial Condition).
DEBT REDUCTION
During fiscal 2002, Key significantly reduced its long-term debt and strengthened its balance sheet. At June 30, 2002, Key's net funded debt was approximately $366,634,000 and its net funded debt to capitalization ratio was approximately 41% as compared to approximately $468,845,000 and 50%, respectively, at June 30, 2001. Proceeds from the Equity Offering (defined below) and the Debt Offering (defined below), as well as cash flow from operations were used to accomplish this reduction in net funded debt (see Part II-Item 7 - Management's Discussion and Analysis of Results of Operations and Financial Condition-Long-Term Debt).
EQUITY OFFERING
On December 19, 2001, the Company closed a public offering of 5,400,000 shares of common stock, yielding approximately $43.2 million, or $8.00 per share, to the Company, (the "Equity Offering"). Net proceeds from the Equity Offering of approximately $42.6 million were used to temporarily reduce amounts outstanding under the Company's revolving line of credit. The net proceeds of the Equity Offering were ultimately used in January 2002 to redeem a portion of the Company's 14% Senior Subordinated Notes fully utilizing the Company's equity "claw-back" rights for up to 35% of the original $150 million issued.
DEBT OFFERING
On March 1, 2002, Key completed a public offering of $100,000,000 of 8 3/8% Senior Notes Due 2008 at 101.5% of par (the "Debt Offering"). The cash proceeds from the public offering, net of fees and expenses, were used to repay the entire balance of the revolving loan facility then outstanding under Key's senior credit facility, with the remainder of such proceeds held in cash and ultimately used to retire a portion of Q Services, Inc.'s long-term debt.
EGYPT PROJECT
On March 28, 2002, Key entered into a multi-year contract with Apache Corporation under which Key is providing five newly refurbished well servicing rigs for work on Apache concessions in the Western Desert of the Arab Republic of Egypt. In addition to the five well servicing rigs, Key is also providing Apache with ten heavy oilfield service vehicles under the contract.
ACQUISITIONS
During fiscal 2002, the Company completed a series of small acquisitions for total consideration of $44,378,000, which consisted of a combination of cash and shares of the Company's common stock. None of the acquisitions completed in fiscal 2002 were individually material, thus the pro forma effect of these acquisitions is not required to be 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, Key acquired Q Services, Inc. ("QSI") pursuant to an Agreement and Plan of Merger dated May 13, 2002, as amended, by and among Key, Key Merger Sub, Inc. and QSI. As consideration for the merger, the Company issued approximately 17.2 million shares of its common stock to QSI shareholders and assumed approximately $74 million of QSI's indebtedness, net of working capital. The aggregate value of the consideration, including assumed debt, was approximately $221 million. Prior to the acquisition, QSI was a privately held corporation conducting field production, pressure pumping and other service operations in Louisiana, New Mexico, Oklahoma, Texas and the Gulf of Mexico.
NEW SENIOR CREDIT FACILITY
On July 15, 2002, the Company entered into a Third Amended and Restated Credit Agreement (the "New Senior Credit Facility"). The New Senior Credit Facility consists of a $150,000,000 revolving loan facility with a $40,000,000 sublimit for letters of credit. The loans are secured by most of the tangible and intangible assets of the Company. The revolving loan commitment will terminate on July 15, 2005 and all revolving loans must be paid on or before that date. The revolving loans bear interest based upon, at the Company's option, the prime rate plus a variable margin of 0.00% to 0.75% or a Eurodollar rate plus a variable margin of 1.25% to 2.75%. The New Senior Credit Facility has 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.
DESCRIPTION OF BUSINESS SEGMENTS
Key operates in two primary business segments which are well servicing and contract drilling. Key's operations are conducted domestically and in Argentina, Egypt and Canada. The following is a description of each of these business segments (for financial information regarding these business segments, see Note 13 to Consolidated Financial Statements-Business Segment Information).
WELL SERVICING
Key provides a full range of well services, including rig-based services, oilfield trucking services, fishing and rental tool services, pressure pumping services and other ancillary oilfield services, necessary to maintain and workover oil and natural gas producing wells. Rig-based services include: maintenance of existing wells, workovers of existing wells, completion of newly drilled wells, recompletion of existing wells (including horizontal recompletions) and plugging and abandonment of wells at the end of their useful lives.
WELL SERVICE RIGS
Key uses its well service rig fleet to perform four major categories of rig services for oil and natural gas producers.
MAINTENANCE SERVICES. Key estimates that there are approximately 600,000 producing oil wells and approximately 300,000 producing natural gas wells in the United States. Key provides the well service rigs, equipment and crews for maintenance services, which are performed on both oil and natural gas wells, but which are more commonly required 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 installed. Few natural gas wells have mechanical pumping systems in the wellbore, and, as a result, maintenance work on natural gas wells is less frequent.
Maintenance services are required throughout the life of most producing oil and natural gas 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 current production of existing wells. Such services include extensions of existing wells to drain new formations either through deepening wellbores to new zones or through drilling of horizontal lateral wellbores to improve reservoir drainage patterns. In less extensive workovers, Key's rigs are used to seal off depleted zones in existing wellbores and access previously bypassed productive zones. Key's workover rigs are also used to convert former producing wells to injection wells through which water or carbon dioxide is then pumped into the formation for enhanced recovery operations. Other workover services include: major subsurface repairs such as casing repair or replacement, recovery of tubing and removal of foreign objects in the wellbore, repairing downhole equipment failures, plugging back the bottom 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 Key's well service rigs are designed for and can be equipped 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.
The demand for workover services is more sensitive to expectations relating to, and changes in, oil and natural gas prices than the demand for maintenance services. As oil and natural gas prices increase, the level of workover activity tends to increase as operators seek to increase production by enhancing the efficiency of their wells at higher commodity prices with correspondingly higher rates of return.
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. Key typically provides a well service rig and may also provide other equipment such as a workover package to assist in the completion process. Producers use well service rigs to complete their wells because the rigs have specialized equipment, properly trained employees and the experience necessary to perform these services. However, during periods of weak drilling rig demand, drilling contractors may compete with service rigs for completion work.
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 can be provided 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 closing 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, as well operators are required by state regulations to plug a well that it is no longer productive. The need for these services is also driven by lease and/or operator policy requirements.
OILFIELD TRUCKING
Upon completion of the acquisition of QSI, Key has established itself as a leading provider of
liquid/vacuum truck services and fluid transportation and disposal services for operators whose wells produce saltwater and other fluids, in addition to oil and natural gas. Of the 2,233 heavy oilfield service vehicles operated by the Company following the acquisition of QSI, the Company operates 1,026 vacuum and transport trucks in the United States. In addition, Key owns approximately 2,972 frac tanks which are used in conjunction with the fluid hauling operations.
Fluid hauling trucks are utilized in connection with drilling and workover projects, which tend to produce and use large amounts of various oilfield fluids. Fluid hauling companies transport fresh water to the well site and provide temporary storage and disposal of produced salt water and drilling/workover fluids. These fluids are picked up at the well site and transported for disposal in a salt water disposal well of which Key owns approximately 130. In addition, Key provides haul/equipment trucks that are used to move large pieces of equipment from one wellsite to the next and operates a fleet of hot oilers. Demand and pricing for these services are generally related to demand for Key's well service and drilling rigs. Fluid hauling and equipment hauling services are typically priced on a per hour basis while frac tank rentals typically are billed on a per day basis.
WELL INTERVENTION SERVICES
Through its acquisition of QSI in July 2002, Key expanded its fishing and rental tool operations and added a pressure pumping business. These operations comprise Key's Well Intervention Services Division which is part of the well servicing line of business.
Founded in 1993, QSI's fishing and rental tool operation, Quality Tubular Services, Inc. ("QTS"), provides fishing and rental tool services to major and independent oil and natural gas production companies primarily in the Gulf Coast region of the United States. QTS operates nine 24-hour service locations and four regional sales offices. The fishing tool supervisors have extensive experience with downhole problems. In addition, QTS offers a full line of services and equipment designed for the harsh elements from land to offshore. The rental tool inventory consists of tubulars, handling tools, pressure-control equipment and a fleet of power swivels. Key also provides fishing and rental tools through its Landmark Fishing and Rental Tools operation in the Mid-Continent region and at various locations throughout the country.
Key's pressure pumping business operates under the name American Energy Services, Inc. ("AES"). AES provides stimulation services, cementing services, nitrogen services, hydro-testing and production chemistry services to oil and natural gas producers. Key offers a full complement of acidizing technology, fracturing technology, nitrogen technology and cementing technology services. With over 64,000 horsepower in cementing and stimulation equipment, AES is one of the largest U.S. providers of pressure pumping services. AES was established in December 1996 and operates in the Permian Basin, the San Juan Basin, and the Mid-Continent Region.
ANCILLARY OILFIELD SERVICES
Key provides ancillary oilfield services, which include among others: wireline; well site construction; roustabout services; and foam units and air drilling services. Demand and pricing for these services are generally related to demand for Key's well service and drilling rigs.
CONTRACT DRILLING
Key provides contract drilling services to major oil companies and independent oil and natural gas producers onshore the continental United States in the Permian Basin, the Four Corners region, Michigan, the Northeast, and the Rocky Mountains and internationally in Argentina and Ontario, Canada. Contract drilling services are primarily provided under standard dayrate, and, to a lesser extent, footage or turnkey contracts. Drilling rigs vary in size and capability and may include specialized equipment. The majority of Key's drilling rigs is equipped with mechanical power systems and has depth ratings ranging from approximately 4,500 to 12,000 feet. Key has one drilling rig with a depth rating of approximately 18,000 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.
FOREIGN OPERATIONS
Key also operates each of its business segments discussed above in Argentina, Ontario, Canada and Egypt. Key's foreign operations currently own 25 well servicing rigs, 75 oilfield trucks and seven drilling rigs in Argentina, four well servicing rigs, four oilfield trucks and two drilling rigs in Ontario, Canada and five well servicing rigs in the Arab Republic of Egypt.
CUSTOMERS
Key's customers include major oil companies, independent oil and natural gas production companies, and foreign national oil and natural gas production companies. One customer in fiscal 2002, Occidental Petroleum Corporation, accounted for 10% of Key's consolidated revenues.
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. Nonetheless, Key believes that its performance, equipment, safety, and availability of equipment to meet customer needs and availability of experienced, skilled personnel is superior to that of its competitors.
In the well servicing markets, 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 records and quality of the crews, equipment and services provided by their contractors. Key has, and will continue to devote substantial resources toward employee safety and training programs. Management believes that many of Key's competitors, particularly small contractors, have not undertaken similar training programs for their employees. Management believes that Key's safety record and reputation for quality equipment and service are among the best in the industry.
In the contract drilling market, Key competes with other regional and national oil and natural gas drilling contractors, some of which have larger rig fleets with greater average depth capabilities and a few that have better capital resources than Key. Management believes that the contract drilling industry is less consolidated than the well servicing industry, resulting in a contract drilling market that is more price competitive. Nonetheless, Key believes that it is competitive in terms of drilling performance, equipment, safety, pricing, availability of equipment to meet customer needs and availability of experienced, skilled personnel in those regions in which it operates.
The need for well servicing and contract drilling fluctuates, primarily, in relation to the price of oil and natural gas which, in turn, is driven by the supply of and demand for oil and natural gas. As supply of those commodities decreases and demand increases, service and maintenance requirements increase as oil and natural gas producers attempt to maximize the producing efficiency of their wells in a higher priced environment.
EMPLOYEES
As of June 30, 2002, Key employed approximately 7,850 persons (approximately 7,746 employees in its well servicing and contract drilling businesses and approximately 104 employees on its corporate staff). Key's employees are not represented by a labor union and are not covered by collective bargaining agreements. Key has not experienced work stoppages associated with labor disputes or grievances and considers its relations with its employees to be satisfactory.
ENVIRONMENTAL REGULATIONS
Key's operations are subject to various local, state and federal laws and regulations intended to protect the environment. Key's operations routinely involve the handling of waste materials, some of which are classified as hazardous substances. Consequently, the regulations applicable to Key's operations include those with respect to containment, disposal and controlling the discharge of any hazardous oilfield waste and other non-hazardous waste material into the environment,
requiring removal and cleanup under certain circumstances, or otherwise relating to the protection of the environment. Laws and regulations protecting the environment have become more stringent in recent years, and may in certain circumstances impose "strict liability," rendering a party liable for environmental damage without regard to negligence or fault on the part of such party. Such laws and regulations may expose Key to liability for the conduct of, or conditions caused by, others, or for Key's acts, which were in compliance with all applicable laws at the times such acts were performed. Cleanup costs 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. 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 any material adverse effect on Key's operations or financial statements in the past, and management is not currently aware of any situation or condition that it believes is likely to have any such material adverse effect in the future. Management believes that it conducts Key's operations in substantial compliance with all material federal, state and local regulations as they relate to the environment. Although Key has incurred certain costs in complying with environmental laws and regulations, such amounts have not been material to Key's financial results during the past three fiscal years.
ITEM 2.
ITEM 2. PROPERTIES.
Key's corporate headquarters are located in Midland, Texas. Key leases office space at this location from an independent third party.
WELL SERVICING AND CONTRACT DRILLING
The following table sets forth the type, number and location of the major equipment owned and operated by Key's operating divisions as of June 30, 2002:
The Permian Basin Well Servicing division owns 36 and leases seven office and yard locations. The Gulf Coast division owns 14 and leases six office and yard locations. The Mid-Continent division owns 30 and leases 22 office and yard locations. The Four Corners division owns six and leases two office and yard locations. The Eastern division owns three and leases ten office and yard locations. The Rocky Mountain division owns 18 and leases two office and yard locations. The California division owns one and leases two office and yard locations. The Permian Basin Drilling division owns two and leases two office and yard locations. The Argentina division owns one and leases one office and yard locations. The
Canadian operation owns one yard location. Odessa Exploration owns interests in 223 gross (172 proved developed) oil leases and 57 gross (50 proved developed) gas leases. The corporate division leases two office locations in addition to its headquarters.
All operating facilities are one story office and/or shop buildings. All buildings are occupied and considered to be in satisfactory condition.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS AND OTHER ACTIONS.
See Note 3 to Consolidated Financial Statements-Commitments and Contingencies.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Key's common stock is currently traded on the New York Stock Exchange, under the symbol "KEG". As of June 30, 2002, there were 645 registered holders of 110,308,463 issued and outstanding shares of common stock, including 416,666 shares of common stock held in treasury (109,891,797 net of treasury shares).
The following table sets forth, for the periods indicated, the high and low sales prices of Key's common stock on the New York Stock Exchange for fiscal 2002 and fiscal 2001, as derived from published sources.
There were no dividends paid on Key's common stock during the fiscal years ended June 30, 2002, 2001 or 2000. Key does not intend, for the foreseeable future, to pay dividends on its common stock. In addition, Key is contractually restricted from paying dividends under the terms of its existing credit facilities.
RECENT SALES OF UNREGISTERED SECURITIES
Key did not make any unregistered sales of its securities during the twelve months ended June 30, 2002 that were not previously included in its Quarterly Reports filed for such period.
EQUITY COMPENSATION PLAN INFORMATION
The following table summarizes information, as of June 30, 2002, about the Company's common stock that may be issued upon the exercise of options that have been granted (i) under equity compensation plans that have been approved by the Company's shareholders and (ii) outside such plans. The only equity compensation plan that has been approved by the Company's shareholders is the Key Energy Group, Inc. 1997 Incentive Plan (the "Incentive Plan"). For a description of the Incentive Plan, see Note 8 to Consolidated Financial Statements - Stockholders' Equity. All options not issued under the Incentive Plan (the "Non-Plan Options") were approved by the Board or the Compensation Committee under individual option grants (rather than under a separate equity compensation plan not approved by the Company's shareholders). The Non-Plan Options (i) expire in ten years, (ii) vest either on the grant date or ratably over a three-year period following the grant date, (iii) have exercise prices equal to or greater than the market price at the date of grant and (iv) have other terms similar to those options granted under the Incentive Plan.
(1) The number of shares of the Company's common stock available for issuance under the Incentive Plan on any given date, subject to adjustment in certain circumstances, is equal to (i) 10% of the number of shares of the Company's common stock issued and outstanding on the last day of the calendar quarter immediately preceding such date (provided, however, that such number cannot decrease from one quarter to the next quarter), less (ii) the number of shares of the Company's common stock previously granted under the Incentive Plan through such date, plus (iii) the number of shares of the Company's common stock previously granted under the Incentive Plan that have been forfeited through such date.
(2) Because the Non-Plan Options are comprised of individual grants outside the Incentive Plan, all shares available for issuance under the Non-Plan Options are reflected in column (a).
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
(1) FINANCIAL DATA FOR THE YEAR ENDED JUNE 30, 1999 INCLUDES THE ALLOCATED PURCHASE PRICE OF DAWSON PRODUCTION SERVICES, INC. AND THE RESULTS OF THEIR OPERATIONS, BEGINNING SEPTEMBER 15, 1998. (2) ADJUSTED EBITDA IS NET INCOME BEFORE INTEREST EXPENSE, INCOME TAXES, DEPRECIATION, DEPLETION AND AMORTIZATION, BAD DEBT EXPENSE, DEBT ISSUANCE COSTS CHARGED TO EARNINGS, RESTRUCTURING CHARGE, FOREIGN CURRENCY TRANSACTION LOSS AND EXTRAORDINARY ITEMS. ADJUSTED EBITDA IS PRESENTED BECAUSE OF ITS ACCEPTANCE AS A COMPONENT OF A COMPANY'S POTENTIAL VALUATION IN COMPARISON TO COMPANIES IN THE SAME INDUSTRY AND OF A COMPANY'S ABILITY TO SERVICE OR INCUR DEBT. MANAGEMENT INTERPRETS TRENDS INDICATED BY CHANGES IN ADJUSTED EBITDA AS AN INDICATOR OF THE EFFECTIVENESS OF ITS STRATEGIES IN ACHIEVING REVENUE GROWTH AND CONTROLLING DIRECT AND INDIRECT COSTS OF SERVICES PROVIDED. INVESTORS SHOULD CONSIDER THAT THIS MEASURE DOES NOT TAKE INTO CONSIDERATION DEBT SERVICE, INTEREST EXPENSES, COSTS OF CAPITAL, IMPAIRMENTS OF LONG LIVED ASSETS, DEPRECIATION OF PROPERTY, THE COST OF REPLACING EQUIPMENT OR INCOME TAXES. ADJUSTED EBITDA SHOULD NOT BE CONSIDERED AS AN ALTERNATIVE TO NET INCOME, INCOME BEFORE TAXES, CASH FLOWS FROM OPERATING ACTIVITIES OR ANY OTHER MEASURE OF FINANCIAL PERFORMANCE PRESENTED IN ACCORDANCE WITH GENERALLY ACCEPTED ACCOUNTING PRINCIPLES AND IS NOT INTENDED TO REPRESENT CASH FLOW. ADJUSTED EBITDA MAY NOT BE COMPARABLE TO SIMILARLY TITLED MEASURES OF OTHER COMPANIES. (3) BOOK VALUE PER COMMON SHARE IS STOCKHOLDERS' EQUITY AT PERIOD END DIVIDED BY THE NUMBER OF ISSUED COMMON SHARES AT PERIOD END. (4) INCLUDES UNUSUAL ITEMS OF APPROXIMATELY $8.5 MILLION FOR DIRECT COSTS AND APPROXIMATELY $1.0 MILLION FOR GENERAL AND ADMINISTRATIVE DURING FISCAL 2002 AS PREVIOUSLY DISCUSSED IN THE COMPANY'S AUGUST 20, 2002 PRESS RELEASE.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION.
Special Note: Certain statements set forth below under this caption constitute "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. See "Special Note Regarding Forward-Looking Statements" for additional factors relating to such statements.
The following discussion provides information to assist in the understanding of the Company's financial condition and results of operations. It should be read in conjunction with the consolidated financial statements and related notes appearing elsewhere in this report. Certain reclassifications have been made to the consolidated financial statements for the years ended June 30, 2001 and 2000 to conform to the year end June 30, 2002 presentation. The reclassifications consist primarily of reclassifying certain items from general and administrative expense to direct expense.
RESULTS OF OPERATIONS
FISCAL YEAR ENDED JUNE 30, 2002 VERSUS FISCAL YEAR ENDED JUNE 30, 2001
The Company's 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 its customers' perception that commodity prices may decrease further) which in turn caused a decline in demand for the Company's equipment and services partially offset by minimizing rate concessions and lower interest charges during fiscal 2002 (see Part I - Item 1 - Major Developments During Fiscal 2002 - Unfavorable Industry Conditions
THE COMPANY
Revenues for the year ended June 30, 2002 decreased $70,698,000, or 8.1%, to $802,564,000 from $873,262,000 in fiscal 2001, while net income for fiscal 2002 decreased $24,564,000, or 39.2%, to $38,146,000 from a net income of $62,710,000 in fiscal 2001. The decrease in revenues and net income is due to lower levels of activity partially offset by higher pricing, with lower interest expense from debt reduction also contributing to net income.
OPERATING REVENUES
WELL SERVICING. Well servicing revenues for the year ended June 30, 2002 decreased $51,644,000, or 6.8%, to $706,629,000 from $758,273,000 in fiscal 2001. The decrease was due to lower demand for the Company's well servicing equipment and services partially offset by higher pricing.
CONTRACT DRILLING. Contract drilling revenues for the year ended June 30, 2002 decreased $20,562,000, or 19.1%, to $87,077,000 from $107,639,000 in fiscal 2001. The decrease was due to lower demand for the Company's contract drilling equipment and services partially offset by higher pricing.
OPERATING EXPENSES
WELL SERVICING. Well servicing expenses for the year ended June 30, 2002 decreased $10,643,000, or 2.1%, to $489,681,000 from $500,324,000 in fiscal 2001. The decrease in expenses is due to lower activity levels partially offset by higher insurance costs primarily in workers compensation and health care. Despite the decreased costs, well servicing expenses as a percentage of well servicing revenues increased from 66.0% for fiscal 2001 to 69.3% for fiscal 2002 primarily due to the increase in insurance costs.
CONTRACT DRILLING. Contract drilling expenses for the year ended June 30, 2002, decreased $16,805,000, or 21.7%, to $60,561,000 from $77,366,000 in fiscal 2001. The decrease is 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 decreased from 71.9% in fiscal 2001 to 69.5% in fiscal 2002. The margin improvement is due to improved
operating efficiencies and the effects of higher pricing partially offset by the increase in insurance costs.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE
The Company's depreciation, depletion and amortization expense for the year ended June 30, 2002 increased $3,118,000, or 4.1%, to $78,265,000 from $75,147,000 in fiscal 2001. The increase is due to recent acquisitions and increased capital expenditures during the past year as the Company continued major refurbishments of well servicing and contract drilling equipment partially offset by discontinued amortization of goodwill, which amounted to $9,322,000 in fiscal 2001, because of the Company's adoption of SFAS 142.
GENERAL AND ADMINISTRATIVE EXPENSES
The Company's general and administrative expenses for the year ended June 30, 2002 decreased $624,000, or 1.0%, to $59,494,000 from $60,118,000 in fiscal 2001. The decrease was due to reductions in incentive payroll costs partially offset by additional expenses incurred as a result of moving the corporate headquarters to Midland, Texas from East Brunswick, New Jersey and increases in personnel supporting information technology functions. Despite the decreased costs, general and administrative expenses as a percentage of total revenues increased from 6.9% in fiscal 2001 to 7.4% in fiscal 2002.
INTEREST EXPENSE
The Company's interest expense for the year ended June 30, 2002 decreased $13,228,000, or 23.4%, to $43,332,000 from $56,560,000 in fiscal 2001. The decrease was primarily due to a significant reduction in the Company's long-term debt using proceeds from the equity offering, the debt offering and operating cash flow, and to a lesser extent, lower interest rates. Included in the interest expense was the amortization of debt issuance costs of $2,581,000 and $3,578,000 for the years ended June 30, 2002 and 2001, respectively.
FOREIGN CURRENCY TRANSACTION LOSS
During fiscal 2002, the Company recorded an Argentine foreign currency transaction loss of approximately $1,443,000 related to dollar-denominated receivables resulting from the recent devaluation of Argentina's currency.
EXTRAORDINARY GAIN (LOSS)
During fiscal 2002, the Company repurchased $150,908,000 of its 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 extraordinary loss of $3,037,000.
INCOME TAXES
The Company's income tax expense for the year ended June 30, 2002 decreased $12,928,000 to $24,074,000 from $37,002,000 in fiscal 2001. The decrease in income tax expense is due to decreased pre-tax income. The Company's effective tax rate for fiscal 2002 and 2001 was 36.9% and 37.3%, 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), and other non-deductible expenses and the effects of state and local taxes.
CASH FLOW
The Company's net cash provided by operating activities for the year ended June 30, 2002 increased $35,369,000 to $178,716,000 from $143,347,000 in fiscal 2001. The increase, despite lower net income in fiscal 2002, is primarily due to a decrease in accounts receivable in fiscal 2002 compared to an increase in accounts receivable in fiscal 2001.
The Company's net cash used in investing activities for the year ended June 30, 2002 increased $24,769,000 to
$108,749,000 from $83,980,000 in fiscal 2001. The increase is due primarily to higher capital expenditures and an increase in acquisitions.
The Company's net cash used in financing activities for the year ended June 30, 2002 decreased $149,827,000 to $17,315,000 from $167,142,000 in fiscal 2001. The decrease is primarily the result of higher proceeds from debt and equity offerings in fiscal 2002 compared to fiscal 2001. While the Company continued its strategy and significantly reduced debt in fiscal 2002, total debt reductions in fiscal 2002 decreased compared to fiscal 2001.
The effect of exchange rates on cash for the year ended June 30, 2002 was a use of $603,000. This was a result of the devaluation of the Argentine peso in fiscal 2002.
FISCAL YEAR ENDED JUNE 30, 2001 VERSUS FISCAL YEAR ENDED JUNE 30, 2000
The Company's results of operations for the year ended June 30, 2001 reflect the impact of favorable industry conditions resulting from increased commodity prices which in turn caused increased demand for the Company's equipment and services during fiscal 2001. The positive impact of this increased demand on the Company's operating results was partially offset by increased operating expenses incurred as a result of the increase in the Company's business activity.
THE COMPANY
Revenues for the year ended June 30, 2001 increased $235,530,000, or 36.9%, to $873,262,000 from $637,732,000 in fiscal 2000, while net income for fiscal 2001 increased $81,669,000 to $62,710,000 from a net loss of $18,959,000 in fiscal 2000. The increase in revenues and net income is due to improved operating conditions, higher rig hours, and increased pricing, with lower interest expense from debt reduction also contributing to net income.
OPERATING REVENUES
WELL SERVICING. Well servicing revenues for the year ended June 30, 2001 increased $198,781,000 or 35.5%, to $758,273,000 from $559,492,000 in fiscal 2000. The increase was due to increased demand for the Company's well servicing equipment and services and higher pricing.
CONTRACT DRILLING. Contract drilling revenues for the year ended June 30, 2001 increased $39,211,000, or 57.3%, to $107,639,000 from $68,428,000 in fiscal 2000. The increase was due to increased demand for the Company's contract drilling equipment and services and higher pricing.
OPERATING EXPENSES
WELL SERVICING. Well servicing expenses for the year ended June 30, 2001 increased $91,601,000, or 22.4%, to $500,324,000 from $408,723,000 in fiscal 2000. The increase in expenses is due to higher utilization of the Company's well servicing equipment, higher labor costs and the overall increase in the Company's well servicing business. Despite the increased costs, well servicing expenses as a percent of well servicing revenues decreased from 73.1% for fiscal 2000 to 66.0% for fiscal 2001. The margin improvement is due to improved operating efficiencies and the effects of higher pricing.
CONTRACT DRILLING. Contract drilling expenses for the year ended June 30, 2001, increased $19,067,000, or 32.7%, to $77,366,000 from $58,299,000 in fiscal 2000. The increase is due to higher utilization of the Company's contract drilling equipment, higher labor costs and the overall increase in the Company's contract drilling business. Despite the increased costs, contract drilling expenses as a percentage of contract drilling revenues decreased from 85.2% in fiscal 2000 to 71.9% in fiscal 2001. The margin improvement is due to improved operating efficiencies and the effects of higher pricing.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE
The Company's depreciation, depletion and amortization expense for the year ended June 30, 2001 increased $4,175,000, or 5.9%, to $75,147,000 from $70,972,000 in fiscal 2000. The increase is due to higher capital expenditures
incurred during fiscal 2001 as the Company refurbished equipment and increased utilization of its contract drilling equipment (which it depreciates partially based on utilization).
GENERAL AND ADMINISTRATIVE EXPENSES
The Company's general and administrative expenses for the year ended June 30, 2001 increased $8,481,000, or 16.4%, to $60,118,000 from $51,637,000 in fiscal 2000. The increase was due to higher administrative costs resulting from the growth of the Company's operations as a result of improved industry conditions. Despite the increased costs, general and administrative expenses as a percentage of total revenues declined from 8.1% in fiscal 2000 to 6.9% in fiscal 2001.
INTEREST EXPENSE
The Company's interest expense for the year ended June 30, 2001 decreased $15,370,000, or 21.4%, to $56,560,000 from $71,930,000 in fiscal 2000. The decrease was primarily due to the impact of the long-term debt reduction during fiscal 2001 and, to a lesser extent, lower short-term interest rates and borrowing margins on floating rate debt.
EXTRAORDINARY GAIN
During fiscal 2001, the Company repurchased $257,115,000 of its long-term debt at various discounts and premiums to par value and expensed related unamortized debt issue costs, all of which resulted in an after-tax extraordinary gain of $429,000.
INCOME TAXES
The Company's income tax expense for the year ended June 30, 2001 increased $44,408,000 to $37,002,000 from a benefit of $7,406,000 in fiscal 2000. The increase in income tax expense is due to increased pre-tax income. The Company's effective tax rate for fiscal 2001 and 2000 was 37.3% and (26.5)%, respectively. The effective tax rates vary from the statutory federal rate of 35% principally because of certain non-deductible goodwill amortization, other non-deductible expenses and state and local taxes.
CASH FLOW
The Company's net cash provided by operating activities for the year ended June 30, 2001 increased $108,487,000 to $143,347,000 from $34,860,000 in fiscal 2000. The increase is due to higher revenues resulting from increased demand for the Company's equipment and services and higher pricing, partially offset by higher operating and general and administrative expenses resulting from increased business activity.
The Company's net cash used in investing activities for the year ended June 30, 2001 increased $46,214,000 to $83,980,000 from $37,766,000 in fiscal 2000. The increase is due primarily to higher capital expenditures.
The Company's net cash used in financing activities for the year ended June 30, 2001 increased $256,443,000 to a use of $167,142,000 from cash provided of $89,301,000 in fiscal 2000. The increase is primarily the result of significant debt reduction during fiscal 2001, partially offset by proceeds from the Company's fiscal 2001 debt offering and the exercise of stock options and warrants.
LIQUIDITY AND CAPITAL RESOURCES
The Company has historically funded its operations, acquisitions, capital expenditures and working capital requirements from cash flow from operations, bank borrowings and the issuance of equity and long-term debt. The Company believes that its current reserves of cash and cash equivalents, availability of its existing credit lines, access to capital markets and internally generated cash flow from operations are sufficient to finance the cash requirements of its current and future operations.
The Company's cash and cash equivalents increased $52,049,000 to $54,147,000 as of June 30, 2002 from $2,098,000 as of June 30, 2001.
The Company expects to finance its capital expenditures using net cash provided by operating activities and available credit. The Company believes that its cash flow and, to the extent required, borrowings under its current and future credit facilities, will be sufficient to fund such expenditures.
As of June 30, 2002 the Company had working capital (excluding the current portion of long-term debt of $7,674,000) of approximately $103,119,000, which includes cash and cash equivalents of approximately $54,147,000, as compared to working capital (excluding the current portion of long-term debt of $7,946,000) of approximately $98,543,000, which includes cash and cash equivalents of approximately $2,098,000, as of June 30, 2001. The increase in working capital is primarily due to an increase in cash and cash equivalents, a decrease in accounts payable and is partially offset by a decrease in accounts receivable and inventories.
LONG-TERM DEBT
Other than capital lease obligations and miscellaneous notes payable, as of June 30, 2002, the Company's long-term debt was comprised of (i) a senior credit facility, (ii) a series of 8 3/8% Senior Notes Due 2008, (iii) a series of 14% Senior Subordinated Notes Due 2009, and (iv) a series of 5% Convertible Subordinated Notes Due 2004.
SENIOR CREDIT FACILITY
During fiscal 2002, the Company had a senior credit facility (the "Prior Senior Credit Facility") with a syndicate of banks led by PNC Bank, N.A. which consisted of a $100,000,000 revolving loan facility. In addition, up to $30,000,000 of letters of credit could be issued under the Prior Senior Credit Facility, but any outstanding letters of credit reduced the borrowing availability under the revolving loan facility. As of June 30, 2002, no funds were outstanding under the revolving loan facility and approximately $27,963,000 of letters of credit related to workman's compensation insurance were outstanding. The Company drew down approximately $43 million on January 14, 2002 in order to redeem the 14% Senior Subordinated Notes. The funds were repaid with the issuance of additional 8 3/8% Notes in March 2002.
The revolving loan bore interest based upon, at the Company's option, the prime rate plus a variable margin of 0.75% to 2.00% or a Eurodollar rate plus a variable margin of 2.25% to 3.50%.
On July 15, 2002, the Company entered into a Third Amended and Restated Credit Agreement (the "New Senior Credit Facility"). The New Senior Credit Facility consists of a $150,000,000 revolving loan facility with a $40,000,000 sublimit for letters of credit. The loans are secured by most of the tangible and intangible assets of the Company. The revolving loan commitment will terminate on July 15, 2005 and all revolving loans must be paid on or before that date. The revolving loans bear interest based upon, at the Company's option, the prime rate plus a variable margin of 0.00% to 0.75% or a Eurodollar rate plus a variable margin of 1.25% to 2.75%. The New Senior Credit Facility has 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.
8 3/8% SENIOR NOTES
On March 6, 2001, the Company completed a private placement of $175,000,000 of 8 3/8% Senior Notes due 2008 (the "8 3/8% Senior Notes"). The net cash proceeds from the private placement were used to repay all of the remaining balance of the original term loans under the Senior Credit Facility, and a portion of the revolving loan facility under the Senior Credit Facility then outstanding. On March 1, 2002, the Company completed a public offering of an additional $100,000,000 of 8 3/8% Senior Notes due 2008. The net cash proceeds from the public offering were used to repay all of the remaining balance of the revolving loan facility under the Senior Credit Facility. The 8 3/8% Senior Notes are senior unsecured obligations. The 8 3/8% Senior Notes are effectively subordinated to Key's secured indebtedness which includes borrowings under the Senior Credit Facility.
On and after March 1, 2005, the Company may redeem some or all of the 8 3/8% Senior Notes at any time at varying redemption prices in excess of par, plus accrued interest. In addition, before March 1, 2004, the Company may redeem up to
35% of the aggregate principal amount of the 8 3/8% Senior Notes with the proceeds of certain sales of equity at 108.375% of par plus accrued interest.
At June 30, 2002, $275,000,000 principal amount of the 8 3/8% Senior Notes remained outstanding. The 8 3/8% Senior Notes require semi-annual interest payments on March 1 and September 1 of each year. Interest payments of approximately $7,125,000 and $7,328,000 were paid on September 1, 2001 and March 1, 2002, respectively.
14% SENIOR SUBORDINATED NOTES
On January 22, 1999, the Company completed the private placement of 150,000 units (the "Units") consisting of $150,000,000 of 14% Senior Subordinated Notes due 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 "Unit Warrants"). The net cash proceeds from the private placement were used to repay substantially all of the remaining $148,600,000 principal amount (plus accrued interest) owed under the Company's bridge loan facility arranged in connection with the acquisition of Dawson Production Services, Inc. ("Dawson").
On and after January 15, 2004, the Company may 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, the Company was 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 fiscal 2001, the Company exercised its right of redemption for $10,313,000 principal amount of the 14% Senior Subordinated Notes at a price of 114% of the principal amount plus accrued interest. This transaction resulted in an extraordinary loss before taxes of approximately $2,561,000. On January 14, 2002, the Company exercised its right of redemption for $35,403,000 principal amount of the 14% Senior Subordinated Notes at a price of 114% of the principal amount plus accrued interest. This transaction resulted in an extraordinary loss before taxes of approximately $8,468,000. Also, during fiscal 2002, the Company purchased and canceled $6,784,000 principal amount of the 14% Senior Subordinated Notes at a price of 116% of the principal amount plus accrued interest. These transactions resulted in extraordinary losses before taxes of approximately $1,821,000.
The Unit Warrants have separated from the 14% Senior Subordinated Notes and became exercisable on January 25, 2000. On the date of issuance, the value of the Unit Warrants was estimated at $7,434,000 and is classified as a discount to the 14% Senior Subordinated Notes on the Company's consolidated balance sheet. The discount is being amortized to interest expense over the term of the 14% Senior Subordinated Notes. The 14% Senior Subordinated Notes mature and the Unit Warrants expire on January 15, 2009. The 14% Senior Subordinated Notes are subordinate to the Company's senior indebtedness, which includes borrowings under the Senior Credit Facility and the 8 3/8% Senior Notes.
At June 30, 2002, $97,500,000 principal amount of the 14% Senior Subordinated Notes remained outstanding. The 14% Senior Subordinated Notes pay interest semi-annually on January 15 and July 15 of each year. Interest payments of approximately $9,778,000 and $6,825,000 were made on July 15, 2001 and January 15, 2002, respectively. As of June 30, 2002, 63,500 Unit Warrants had been exercised, producing approximately $4,173,000 of proceeds to the Company and leaving 86,500 Unit Warrants outstanding.
5% CONVERTIBLE SUBORDINATED NOTES
In late September and early October 1997, the Company completed a private placement of $216,000,000 of 5% Convertible Subordinated Notes due 2004 (the "5% Convertible Subordinated Notes"). The 5% Convertible Subordinated Notes are subordinate to the Company's senior indebtedness which includes borrowings under the Senior Credit Facility, the 14% Senior Subordinated Notes and the 8 3/8% Senior Notes. The 5% Convertible Subordinated Notes are convertible, at the holder's option, into shares of the Company's common stock at a conversion price of $38.50 per share, subject to certain adjustments. The 5% Convertible Subordinated Notes are redeemable, at the Company's option, on and after September 15, 2000, in whole or part, together with accrued and unpaid interest. The initial redemption price is 102.86% for the year beginning September 15, 2000 and declines ratably thereafter on an annual basis.
During fiscal 2001, the Company repurchased (and canceled) $47,384,000 principal amount of the 5% Convertible Subordinated Notes. These repurchases resulted in extraordinary gains before taxes of approximately $4,564,000. During fiscal 2002, the Company repurchased (and canceled) $108,475,000 principal amount of the 5% Convertible Subordinated Notes, leaving $49,951,000 principal amount of the 5% Convertible Subordinated Notes outstanding at June 30, 2002. These repurchases resulted in extraordinary gains before taxes of approximately $5,633,000. Since June 30, 2002, the Company has repurchased (and canceled) an additional $204,000 principal amount of the 5% Convertible Subordinated Notes, leaving $49,747,000 outstanding as of September 30, 2002. Interest on the 5% Convertible Subordinated Notes is payable on March 15 and September 15 of each year. Interest of approximately $3,027,000 and $1,259,000 was paid on September 15, 2001 and March 15, 2002, respectively.
CRITICAL ACCOUNTING POLICIES
The Company follows certain significant accounting policies when preparing its consolidated financial statements. A complete summary of these policies is included in Note 1 to the consolidated financial statements included herein.
Certain of the policies require management to make significant and subjective estimates which are sensitive to deviations of actual results from management's assumptions. In particular, management makes estimates regarding the fair value of the Company's reporting units in assessing potential impairment of goodwill. In addition, the Company makes estimates regarding future undiscounted cash flows from the future use of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset may not be recoverable.
In assessing impairment of goodwill, the Company has used estimates and assumptions in estimating the fair value of its reporting units. Actual future results could be different than the estimates and assumptions used. Events or circumstances which might lead to an indication of impairment of goodwill would include, but might not be limited to, prolonged decreases in expectations of long-term well servicing and/or drilling activity or rates brought about by prolonged decreases in oil or natural gas prices, changes in government regulation of the oil and natural gas industry or other events which could affect the level of activity of exploration and production companies.
In assessing impairment of long-lived assets other than goodwill where there has been a change in circumstances indicating that the carrying amount of a long-lived asset may not be recoverable, the Company has estimated future undiscounted net cash flows from use of the asset based on actual historical results and expectations about future economic circumstances including oil and natural gas prices and operating costs. The estimate of future net cash flows from use of the asset could change if actual prices and costs differ due to industry conditions or other factors affecting the Company's performance.
RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS
Recently the Financial Accounting Standards Board, ("FASB") issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations ("SFAS 143"), Statement of Financial Accounting Standards No. 144, Accounting for the Impairment of Disposal of Long-Lived Assets ("SFAS 144"), 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") and Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities ("SFAS 146"). SFAS 143 requires the Company to recognize a liability for all legal obligations associated with the retirement of tangible long lived assets and capitalize and equal amount as a cost of the asset and depreciate it over the estimated remaining useful life of the asset. The adoption of SFAS 143 could have a material impact to the Company depending on the lives of its oil and gas properties and salt water disposal wells. SFAS 144 addresses financial accounting and reporting for the impairment of disposal of long-lived assets. SFAS 145 rescinds Statement No. 4, which required all gains and losses from extinguishment of debt to be aggregated and classified as an extraordinary item, and amends Statement No. 13 to require that certain lease modifications that have economic effects similar to sale-leaseback transactions be accounted for in the same manner as sale-leaseback transactions. Upon adoption of SFAS 145, the Company will no longer record the gains and losses from the extinguishment of debt as extraordinary items. The impact of the adoption of SFAS 145 to the Company will depend
on the Company's early retirements of debt. SFAS 146 establishes requirements for financial accounting and reporting for costs associated with exit or disposal activities. SFAS 143 is effective for fiscal years beginning after June 15, 2002, with earlier adoption encouraged. SFAS 144 is effective for fiscal years beginning after December 15, 2001 and interim periods within those fiscal years. SFAS 145 is effective for fiscal years beginning after May 15, 2002, with earlier adoption encouraged. SFAS 146 is effective for exit or disposal activities initiated after December 31, 2002. The Company is currently assessing the impact of these standards on its consolidated financial statements.
IMPACT OF INFLATION ON OPERATIONS
Management is of the opinion that inflation has not had a significant impact on Key's business.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Special Note: Certain statements set forth below under this caption constitute "forward-looking statements". See "Special Note Regarding Forward-Looking Statements" for additional factors relating to such statements.
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 June 30, 2002 Key had long-term debt outstanding of $443,610,000. Of this amount, $420,781,000 or 94.9%, bears interest at fixed rates as follows:
The remaining $22,829,000 debt outstanding as of June 30, 2002 bears interest at floating rates which averaged approximately 6.66% at June 30, 2002. A 10% increase in short-term interest rates on the floating-rate debt outstanding at June 30, 2002 would equal approximately 67 basis points. Such an increase in interest rates would increase Key's fiscal 2003 interest expense by approximately $200,000 assuming borrowed amounts remain outstanding.
The above sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments.
FOREIGN CURRENCY RISK
During fiscal 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, 2001. Assets and liabilities of the Argentine operations were translated to U.S. dollars at June 30, 2002 using the applicable free market conversion ratio of 3.9:1 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 six months ended December 31, 2001 and are based on the U.S. dollar equivalent of such amounts measured in Argentine pesos for periods after December 31, 2001. Revenues, expenses and cash flow will be translated using the average exchange rates during the periods after December 31, 2001. See Note 18 to the consolidated financial statements.
The change in the Argentine peso to the U.S. dollar exchange rate since December 31, 2001 has reduced stockholders' equity by $48,383,000, through a charge to other comprehensive loss through June 30, 2002.
Key's net assets, net earnings and cash flows from its Canadian subsidiary are 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.
A 10% change in the Canadian-to-U.S. Dollar exchange rate would not be material to the net assets, net earnings or cash flows of the Company.
COMMODITY PRICE RISK
Key's major market risk exposure for its oil and natural gas production operations is 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.
The Company periodically hedges a portion of its oil and natural gas production through collar and option agreements. The purpose of the hedges is 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. The Company's risk management objective is to lock in a range of pricing for expected production volumes. This allows the Company to forecast future earnings within a predictable range. The Company meets this objective by entering into collar and option arrangements which allow for acceptable cap and floor prices.
As of June 30, 2002, Key had oil and natural gas price collars and put options in place, as detailed in the following table. The total fiscal 2002 hedged oil and natural gas volumes represent approximately 41% and 32%, respectively, of expected 2002 calendar year total production. A 10% variation in the market price of oil or natural gas from their levels at June 30, 2002 would have no material impact on the Company's net assets, net earnings or cash flows (as derived from commodity option contracts).
The following table sets forth the future volumes hedged by year and the weighted-average strike price of the option contracts at June 30, 2002 and 2001:
(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 collars are based on the Inside FERC-West Texas Waha spot price; the strike price for the natural gas put is based on the Inside FERC-El Paso Permian spot price.)
ITEM 8.
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Presented herein are the consolidated financial statements of Key Energy Services, Inc. as of June 30, 2002 and 2001 and for the years ended June 30, 2002, 2001 and 2000.
Also included is the report of KPMG LLP, independent certified public accountants, on such consolidated financial statements as of June 30, 2002 and 2001 and for the years ended June 30, 2002, 2001 and 2000.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
KEY ENERGY SERVICES, INC.
CONSOLIDATED BALANCE SHEETS
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED FINANCIAL STATEMENTS.
KEY ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED FINANCIAL STATEMENTS.
KEY ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED FINANCIAL STATEMENTS.
KEY ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED FINANCIAL STATEMENTS.
KEY ENERGY SERVICES INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (THOUSANDS)
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED FINANCIAL STATEMENTS.
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2002, 2001 AND 2000
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
THE COMPANY
Key Energy Services, Inc. (the "Company" or "Key"), is the largest onshore, rig-based well servicing contractor in the world, with approximately 1,486 well service rigs and 1,719 oilfield service vehicles as of June 30, 2002. The Company provides 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 (including horizontal recompletions); oilfield trucking services; and ancillary oilfield services. Key conducts well servicing operations onshore 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 region), Four Corners (including the San Juan, Piceance, Uinta, and Paradox Basins), Eastern (including the Appalachian, Michigan and Illinois 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 and Ontario, Canada. The Company is also a leading onshore drilling contractor, with 79 land drilling rigs as of June 30, 2002. Key conducts land drilling operations in a number of major domestic producing basins, as well as in Argentina and in Ontario, Canada. Key also produces and develops oil and natural gas reserves in the Permian Basin region and Texas Panhandle.
BASIS OF PRESENTATION
The Company's consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. All significant inter-company transactions and balances have been eliminated. The accounting policies presented below have been followed in preparing the accompanying consolidated financial statements.
ESTIMATES AND UNCERTAINTIES
Preparation of the accompanying consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amount of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
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
The Company provides for depreciation and amortization of oilfield service and related equipment using the straight-line method, excluding its drilling rigs, over the following estimated useful lives of the assets:
The components of a well service rig that generally require replacement during the rig's life are depreciated over their estimated useful lives, which range from three to 15 years. The basic rigs, excluding components, have estimated useful lives from date of original manufacture ranging from 25 to 35 years. Salvage values are assigned to the rigs based on an estimate of 10%.
The Company uses the units-of-production method to depreciate its 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. The Company believes that this method appropriately reflects its financial results by matching revenues with expenses and appropriately reflects how the assets are to be used over time.
The Company uses the successful efforts method of accounting for its 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. The Company does not provide disclosures on its oil and gas properties in accordance with FASB Statement No. 69, Disclosures about Oil and Gas Producing Activities.
The Company follows the provisions of FASB Statement No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. This statement requires that long-lived assets including certain identifiable intangibles, held and used by the Company, 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, the Company groups its long-lived assets on a yard-by-yard basis and compares the estimated future cash flows of each yard to the yard's net carrying value. The Company would record an impairment charge, reducing the yard's net carrying value to an estimated fair value, if the estimated future cash flows were less than the yard's net carrying value. No impairment charges have been required.
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
The Company uses derivative financial instruments, primarily commodity option contracts to reduce the exposure of its oil and gas producing operations 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.
The financial instruments that the Company accounts for as hedging contracts must meet the following criteria: the underlying asset or liability must expose the Company 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 designated as a hedge at the inception of the contract and throughout the contract period. In order to qualify as a hedge, there must be clear 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.
Prior to the adoption of SFAS 133, premiums paid for commodity option contracts, which qualify as hedges, are amortized to oil and natural gas sales over the terms of the contracts. Unamortized premiums are included in other assets in the consolidated balance sheet. Amounts receivable under the commodity option contracts are accrued as an increase in oil and natural gas sales for the applicable periods.
Effective July 1, 2000, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") as amended by SFAS 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 in the Company's 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. See Note 6.
COMPREHENSIVE INCOME
The Company follows the provisions of Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income" ("SFAS 130"). SFAS 130 establishes standards for reporting and presentation of comprehensive income and its components. SFAS 130 requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements. In accordance with the provisions of SFAS 130, the Company has presented the components of comprehensive income in its Consolidated Statements of Comprehensive Income.
ENVIRONMENTAL
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the adverse environmental effects of the disposal or release of petroleum or chemical substances at various sites. 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.
GOODWILL AND OTHER INTANGIBLE ASSETS
The Company has adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets ("SFAS 142") on July 1, 2001. SFAS 142 eliminates the amortization for goodwill and other intangible assets with indefinite lives. Intangible assets with lives restricted by contractual, legal, or other means will continue to be amortized over their 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. The Company completed its assessment of goodwill impairment as of the date of adoption during the three months ended December 31, 2001, as allowed by SFAS 142, and a subsequent annual impairment assessment as of June 30, 2002. The assessments did not result in an indication of goodwill impairment as of either date.
Intangible assets subject to amortization under SFAS 142 consist of noncompete agreements. Amortization expense is calculated using the straight-line method over the period of the agreement, ranging from three to five years.
The gross carrying amount of noncompete agreements subject to amortization totaled approximately $11,727,000 and $8,324,000 at June 30, 2002 and 2001, respectively. Accumulated amortization related to these intangible assets totaled approximately $6,130,000 and $4,953,000 at June 30, 2002 and 2001, respectively. Amortization expense for the years ended June 30, 2002, 2001 and 2000 was approximately $1,914,000, $1,801,000 and $1,410,000, respectively. Amortization expense for the next five succeeding fiscal years is estimated to be $2,126,000, $1,143,000, $968,000, $797,000 and $513,000.
The Company has identified its reporting segments to be well servicing and contract drilling. Goodwill allocated to such reporting segments at June 30, 2002 is $186,819,000 and $14,250,000, respectively. The change in the carrying amount of goodwill for the year ended June 30, 2002 of $11,194,000 relates principally to goodwill from well servicing assets acquired during the period and the translation adjustment for Argentina.
The effects of the adoption of SFAS 142 on net income and earnings per share for the years ended June 30, 2001 and 2000 are as follows:
DEFERRED COSTS
Deferred costs totaling $32,928,000 and $31,052,000 at June 30, 2002 and 2001, respectively, represent debt issuance costs and are recorded net of accumulated amortization of $20,348,000 and $13,428,000 at June 30, 2002 and 2001, respectively. Deferred costs are amortized to interest expense using the straight-line method over the life of each applicable debt instrument or to extraordinary loss as related debt is retired early. This method approximates the amortization which would be recorded using the effective interest method. Amortization of deferred costs totaled approximately $2,581,000, $3,578,000 and $5,176,000 for fiscal 2002, 2001 and 2000, respectively. Unamortized debt issuance costs written off and included in the determination of the extraordinary loss on retirement of debt, before tax, for fiscal 2002, totaled approximately $4,339,000 and the extraordinary gain on retirement of debt, before tax for fiscal 2001, totaled approximately $2,583,000.
INCOME TAXES
The Company accounts 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.
The Company and its eligible subsidiaries file a consolidated U. S. federal income tax return. Certain subsidiaries that are consolidated for financial reporting purposes are not eligible to be included in the consolidated U. S. federal income tax return and separate provisions for income taxes have been determined for these entities or groups of entities.
EARNINGS PER SHARE
The Company presents 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 are 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.
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 of 1,177,000 and 360,000, respectively, and the potential conversion of the Company's 5% Convertible Subordinated Notes because the effects of such instruments on earnings per share would be anti-dilutive.
The diluted earnings per share calculation for the year ended June 30, 2000 excludes the effect of the potential conversion of all of the Company's then outstanding convertible debt and the potential exercise of all of the Company's then outstanding warrants and stock options because the effects of such instruments on loss per share would be anti-dilutive.
CONCENTRATION OF CREDIT RISK
Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of temporary cash investments and trade receivables. The Company restricts investment of temporary cash investments to financial institutions with high credit standing and, by policy, limits the amount of credit exposure to any one financial institution. The Company's customer base consists primarily of multi-national and independent oil and natural gas producers. This may affect the Company's overall exposure to credit risk either positively or negatively in as much as its customers are affected by economic conditions in the oil and gas industry, which have historically been cyclical. However, account receivables are well diversified among many customers and a significant portion of the receivables are from major oil companies, which management believes minimizes potential credit risk. Historically, credit losses have been insignificant. Receivables are generally not collateralized, although the Company may generally secure a receivable at any time by filing a mechanic's or material-man's lien on the well serviced. The Company maintains reserves for potential credit losses, and such losses have been within management's expectations.
Key's customers include major oil companies, independent oil and natural gas production companies, and foreign national oil and natural gas production companies. One customer in fiscal 2002, Occidental Petroleum Corporation, accounted for 10% of Key's consolidated revenues. The Company did not have any one customer which represented 10% or more of consolidated revenues for the fiscal years ended June 30, 2001 or 2000.
STOCK-BASED COMPENSATION
The Company accounts for stock option grants to employees using the intrinsic value method of accounting prescribed by APB Opinion No. 25, Accounting for Stock Issued to Employees ("APB 25"). Under the Company's stock incentive plans, the price of the stock on the grant date is the same as the amount an employee must pay to exercise the option to acquire the stock; accordingly, the options have no intrinsic value at grant date, and in accordance with the provisions of APB 25, no compensation cost is recognized.
Statement of Financial Accounting Standards No. 123 ("SFAS 123"), "Accounting for Stock-Based Compensation," sets forth alternative accounting and disclosure requirements for 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 based recognition provisions of SFAS 123. The Company has disclosed in Note 8 the pro forma information required under SFAS 123.
FOREIGN CURRENCY GAINS AND LOSSES
The local currency is the functional currency for the Company's foreign operations in Argentina and Canada. The cumulative translation gains and losses, resulting from translating each foreign subsidiary's financial statements from the functional currency to U.S. dollars, is included in other comprehensive income and accumulated in stockholders' equity until a partial or complete sale or liquidation of the Company's net investment in the foreign entity.
CASH AND CASH EQUIVALENTS
The Company considers all unrestricted highly liquid investments with less than a three-month maturity when purchased, as cash equivalents.
RECLASSIFICATIONS
Certain reclassifications have been made to the consolidated financial statements for the years ended June 30, 2001 and 2000 to conform to the year end June 30, 2002 presentation. The reclassifications consist primarily of reclassifying certain items from general and administrative expense to direct expenses.
2. BUSINESS AND PROPERTY ACQUISITIONS
During fiscal 2002 and 2001, the Company completed several small acquisitions for a total consideration of $44,378,000 and $11,965,000, respectively, which consisted of a combination of cash, notes and shares of the Company's common stock. None of the acquisitions completed in fiscal 2002 were individually material, thus the pro forma effect of these acquisitions is not required to be 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. There were no acquisitions completed by the Company in fiscal 2000.
3. COMMITMENTS AND CONTINGENCIES
Various suits and claims arising in the ordinary course of business are pending against the Company. Management does 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 the Company.
In order to retain qualified senior management, the Company enters into employment agreements with its executive officers. These employment agreements run for periods ranging from three to five years, but can be automatically extended on a yearly basis unless terminated by the Company or the executive officer. In addition to providing a base salary for each executive officer, the employment agreements provide for severance payments for each executive officer varying from three to five years of the executive officer's base salary. At June 30, 2002 the annual base salaries for the executive officers covered under such employment agreements totaled $1,165,000. The Company also enters into employment agreements with other key employees as it deems necessary in order to retain qualified personnel.
4. LONG-TERM DEBT
The components of the Company's long-term debt are as follows:
(i) SENIOR CREDIT FACILITY
During the fiscal 2002, the Company's senior credit facility (the "Prior Senior Credit Facility") consisted of a $100 million revolving credit facility. In addition, up to $30 million of letters of credit could be issued under the Prior Senior Credit Facility, but any outstanding letters of credit reduced borrowing availability under the revolver. The Company drew down approximately $43 million on January 14, 2002 in order to redeem the 14% Senior Subordinated Notes. The funds were repaid with the issuance of additional 8 3/8% Notes in March 2002.
The revolving loans bore interest at rates based upon, at the Company's option, either the prime rate plus a variable margin of 0.75% to 2.00% or a Eurodollar rate plus a variable margin of 2.25% to 3.50%. The Company paid commitment fees on the unused portion of the revolving loan at a varying rate (depending upon the pricing ratio) of between 0.25% and 0.50%.
During fiscal 2001, a portion of the net proceeds from the 2000 Equity Offering (see Note 8) was used to repay the entire outstanding balance of the Tranche A term loan then outstanding under the Prior Senior Credit Facility and $2.3 million of the Tranche B term loan then outstanding under the Prior Senior Credit Facility. In addition, $65 million of the net proceeds from the 2000 Equity Offering were used to reduce the principal amount outstanding under the revolver. The remainder of the net proceeds of the 2000 Equity Offering was used to retire other long-term debt. A portion of the proceeds from the Company's 8 3/8% Senior Note offering in fiscal 2001 was used to repay the entire outstanding balance of the Tranche B term loan then outstanding under the Prior Senior Credit Facility and approximately $59.1 million under the revolver.
At June 30, 2002, there was no balance outstanding under the revolving loans. Additionally, the Company had outstanding letters of credit of $27,963,000 and $11,995,000 as of June 30, 2002 and 2001, respectively, under the senior credit facility related to its workers compensation insurance.
(ii) 8 3/8% SENIOR NOTES
On March 6, 2001, the Company completed a private placement of $175,000,000 of 8 3/8% Senior Notes due 2008 (the "8 3/8% Senior Notes"). The net cash proceeds from the private placement were used to repay all of the remaining balance of the original term loans under the Senior Credit Facility, and a portion of the revolving loan facility under the Senior Credit Facility then outstanding. On March 1, 2002, the Company completed a public offering of an additional $100,000,000 of 8 3/8% Senior Notes due 2008. The net cash proceeds from the public offering were used to repay all of the remaining balance of the revolving loan facility under the Senior Credit Facility. The 8 3/8% Senior Notes are senior unsecured obligations. The 8 3/8% Senior Notes are effectively subordinated to Key's secured indebtedness which includes borrowings under the Senior Credit Facility.
On and after March 1, 2005, the Company may redeem some or all of the 8 3/8% Senior Notes at any time at varying redemption prices in excess of par, plus accrued interest. In addition, before March 1, 2004, the Company may redeem up to 35% of the aggregate principal amount of the 8 3/8% Senior Notes with the proceeds of certain sales of equity at 108.375% of par plus accrued interest.
At June 30, 2002, $275,000,000 principal amount of the 8 3/8% Senior Notes remained outstanding. The 8 3/8% Senior Notes require semi-annual interest payments on March 1 and September 1 of each year. Interest payments of approximately $7,125,000 and $7,328,000 were paid on September 1, 2001 and March 1, 2002, respectively.
(iii) 14% SENIOR SUBORDINATED NOTES
On January 22, 1999, the Company completed the private placement of 150,000 units (the "Units") consisting of $150,000,000 of 14% Senior Subordinated Notes due 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 "Unit Warrants"). The net cash proceeds from the private placement were used to repay substantially all of the remaining $148,600,000 principal amount (plus accrued interest) owed under the Company's bridge loan facility arranged in connection with the acquisition of Dawson Production Services, Inc. ("Dawson").
On and after January 15, 2004, the Company may 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, the Company was 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 fiscal 2001, the Company exercised its right of redemption for $10,313,000 principal amount of the 14% Senior Subordinated Notes at a price of 114% of the principal amount plus accrued interest. This transaction resulted in an extraordinary loss before taxes of approximately $2,561,000. On January 14, 2002 the Company exercised its right of redemption for $35,403,000 principal amount of the 14% Senior Subordinated Notes at a price of 114% of the principal amount plus accrued interest. This transaction resulted in an extraordinary loss before taxes of approximately $8,468,000. Also, during fiscal 2002, the Company purchased and canceled $6,784,000 principal amount of the 14% Senior Subordinated Notes at a price of 116% of the principal amount plus accrued interest. These transactions resulted in extraordinary losses before taxes of approximately $1,821,000.
The Unit Warrants have separated from the 14% Senior Subordinated Notes and became exercisable on January 25, 2000. On the date of issuance, the value of the Unit Warrants was estimated at $7,434,000 and is classified as a discount to the 14% Senior Subordinated Notes on the Company's consolidated balance sheet. The discount is being amortized to interest expense over the term of the 14% Senior Subordinated Notes. The 14% Senior Subordinated Notes mature and the Unit Warrants expire on January 15, 2009. The 14% Senior Subordinated Notes are subordinate to the Company's senior indebtedness, which includes borrowings under the Senior Credit Facility and the 8 3/8% Senior Notes.
At June 30, 2002, $97,500,000 principal amount of the 14% Senior Subordinated Notes remained outstanding. The 14% Senior Subordinated Notes pay interest semi-annually on January 15 and July 15 of each year. Interest payments of approximately $9,778,000 and $6,825,000 were made on July 15, 2001 and January 15, 2002, respectively. As of June 30, 2002, 63,500 Unit Warrants had been exercised, producing approximately $4,173,000 of proceeds to the Company and leaving 86,500 Unit Warrants outstanding.
(iv) 5% CONVERTIBLE SUBORDINATED NOTES
In late September and early October 1997, the Company completed a private placement of $216,000,000 of 5% Convertible Subordinated Notes due 2004 (the "5% Convertible Subordinated Notes"). The 5% Convertible Subordinated Notes are subordinate to the Company's senior indebtedness which includes borrowings under the Senior Credit Facility, the 14% Senior Subordinated Notes and the 8 3/8% Senior Notes. The 5% Convertible Subordinated Notes are convertible, at the holder's option, into shares of the Company's common stock at a conversion price of $38.50 per share, subject to certain adjustments. The 5% Convertible Subordinated Notes are redeemable, at the Company's option, on and after September 15, 2000, in whole or part, together with accrued and unpaid interest. The initial redemption price is 102.86% for the year beginning September 15, 2000 and declines ratably thereafter on an annual basis.
During fiscal 2001, the Company repurchased (and canceled) $47,384,000 principal amount of the 5% Convertible Subordinated Notes. These repurchases resulted in extraordinary gains before taxes of approximately $4,564,000. During fiscal 2002, the Company repurchased (and canceled) $108,475,000 principal amount of the 5% Convertible Subordinated Notes, leaving $49,951,000 principal amount of the 5% Convertible Subordinated Notes outstanding at June 30, 2002. These repurchases resulted in extraordinary gains before taxes of approximately $5,633,000. Interest on the 5% Convertible Subordinated Notes is payable on March 15 and September 15 of each year. Interest of approximately $3,027,000 and $1,259,000 was paid on September 15, 2001 and March 15, 2002, respectively.
CAPITALIZED DEBT ISSUANCE COSTS, REPAYMENT SCHEDULE AND INTEREST EXPENSE
The Company capitalized a total of approximately $1,877,000 and $4,958,000 in fees and costs in connection with its various financings during fiscal 2002 and 2001, respectively. The Company did not incur any fees or costs in connection with financing activities in fiscal 2000.
Presented below is a schedule of the repayment requirements of long-term debt (excluding the discount on the 14% Senior Subordinated Notes and the premium on the 8 3/8% Senior Notes) for each of the next five years and thereafter as of June 30, 2002:
The Company's interest expense for the years ended June 30, 2002, 2001, and 2000 consisted of the following:
5. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair values of the Company's financial instruments at June 30, 2002 and 2001. 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.
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.
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.
Notes receivable-related parties: The amounts reported relate to notes receivable from officers of the Company.
Long-term debt: The fair value of the Company's long-term debt is based upon the quoted market prices for the various notes and debentures at June 30, 2002 and 2001, and the carrying amounts outstanding under the Company's senior credit facility.
6. DERIVATIVE FINANCIAL INSTRUMENTS
The Company utilizes derivative financial instruments to manage well defined commodity price risks. The Company is exposed to credit losses in the event of nonperformance by the counter-parties to its commodity hedges. The Company only deals with reputable financial institutions as counter-parties and anticipates that such counter-parties will be able to fully satisfy their obligations under the contracts. The Company does not obtain collateral or other security to support financial instruments subject to credit risk but monitors the credit standing of the counter-parties.
The Company periodically hedges a portion of its oil and natural gas production through collar and option agreements. The purpose of the hedges is 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. The Company's risk
management objective is to lock in a range of pricing for expected production volumes. This allows the Company to forecast future earnings within a predictable range. The Company meets this objective by entering into collar and option arrangements which allow for acceptable cap and floor prices.
The Company does not enter into derivative instruments for any purpose other than for economic hedging. The Company does not speculate using derivative instruments. The Company has identified the following derivative instruments:
FREESTANDING DERIVATIVES. On March 30, 2000 the Company entered into a collar arrangement for a 22-month period whereby the Company will pay if the specified price is above the cap index and the counter-party will pay if the price should fall below the floor index. The hedge defines a range of cash flows bounded by the cap and floor prices. On May 25, 2001 the Company entered into an option arrangement for a 12-month period beginning March 2002 whereby the counter-party will pay if the price should fall below the floor index. On May 2, 2002 the Company entered into an option arrangement for a 12-month period beginning March 2003 whereby the counter-party will pay if the price should fall below the floor index. The Company desires a measure of stability to ensure that cash flows do not fall below a certain level.
Prior to the adoption of SFAS 133 as discussed in Note 1, these collars and options were accounted for as cash flow type hedges. Accordingly, the transition adjustment resulted in recording a $778,000 liability for the fair value of the collars to accumulated other comprehensive income, of which $258,000 and $520,000 was recognized in earnings during fiscal 2002 and 2001, respectively. While this arrangement was intended to be an economic hedge, as of July 1, 2000, the Company had not documented the March 30, 2000 oil and natural gas collars as cash flow hedges and therefore reported a charge to operations of $565,000 for the increase in fair value of the liability as of September 30, 2000 in other income. As of October 1, 2000, the Company documented these collars as cash flow hedges. As of May 25, 2001, the Company had not documented the May 25, 2001 oil and natural gas options as cash flow hedges and therefore has included income of $768,000 for the increase in fair value of the asset as of June 30, 2001 in other income. As of July 1, 2001, the Company documented these options as cash flow hedges. As of May 2, 2002, the Company had documented the May 2, 2002 oil and natural gas options as cash flow hedges. The Company recorded a net decrease in derivative assets net of derivative liabilities of $543,000 and a net increase of $999,000 during fiscal 2002 and 2001, respectively.
The Company recorded in earnings an ineffectiveness expense of $85,000 and ineffectiveness income $132,000 for fiscal 2002 and 2001, respectively.
EMBEDDED DERIVATIVES. The Company is party to a volumetric production payment that meets the definition of an embedded derivative under SFAS 133. Effective July 1, 2000, the Company determined and documented that the volumetric production payment is excluded from the scope of SFAS 133 under the normal purchases/sales exclusion as set forth in SFAS 138.
For fiscal 2000, gains and amortization of premiums paid on option contracts are recognized as an adjustment to sales revenue when the related transactions being hedged are finalized. The net effect of the Company's commodity hedging activities decreased oil and natural gas revenues for the year ended June 30, 2000 by $822,270.
The following table sets forth the future volumes hedged by year and the weighted-average strike price of the option contracts at June 30, 2002 and 2001:
(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 collars are based on the Inside FERC-West Texas Waha spot price; the strike price for the natural gas put is based on the Inside FERC-El Paso Permian spot price.)
7. OTHER ACCRUED LIABILITIES
Other accrued liabilities consist of the following:
Other non-current accrued expenses consist primarily of workers compensation reserves.
8. STOCKHOLDERS' EQUITY
EQUITY OFFERINGS
On December 19, 2001, the Company closed a public offering of 5,400,000 shares of common stock, yielding approximately $43.2 million, or $8.00 per share, to the Company, (the "Equity Offering"). Net proceeds from the Equity Offering of approximately $42.6 million were used to temporarily reduce amounts outstanding under the Company's revolving line of credit. The net proceeds of the Equity Offering were ultimately used in January 2002 to redeem a portion of the Company's 14% Senior Subordinated Notes fully utilizing the Company's equity "claw-back" rights for up to 35% of the original $150 million issued.
On June 30, 2000, the Company closed a public offering of 11,000,000 shares of common stock at $9.625 per share, or approximately $106 million (the "2000 Equity Offering"). Net proceeds from the 2000 Equity Offering of approximately $101 million were used to repay a portion of the Company's term loan borrowings and revolving line of credit under its senior credit facility and retire other long-term debt.
STOCK INCENTIVE PLANS
On January 13, 1998 the Company'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 the Company's board of directors adopted the plan) were assumed and continued, without modification, under the 1997 Incentive Plan.
Under the 1997 Incentive Plan, the Company may grant the following awards to key employees, directors who are not employees ("Outside Directors") and consultants of the Company, its controlled subsidiaries, and its 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 the 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".
The Company may grant Incentive Awards covering an aggregate of the greater of (i) 3,000,000 shares of the Company's common stock and (ii) 10% of the shares of the Company's 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 the Company's 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 Company's equity offerings discussed above, as of June 30, 2002, the number of shares of the Company's common stock that may be covered by Incentive Awards has increased to approximately 11.0 million.
Any shares of the Company's 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 the Company's common stock issued under the 1997 Incentive Plan may be either newly issued or treasury shares, including shares of the Company's common stock that the Company receives 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 the Company'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 calendar year is $2,500,000. For purposes of the 1997 Incentive Plan, "Covered Employees" means a named executive officer who is one of the group covered employees as defined in Section 162(m) of the Code and the regulation 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 administrated by the Compensation Committee appointed by the Board of Directors (the "Committee") 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, the Company may issue NSOs outside the 1997 Incentive Plan.
The exercise price of options granted under the 1997 Incentive Plan and outside the 1997 Incentive Plan is at or above the fair market value per share on the date the options are granted. The exercise of NSOs results in a U. S. tax deduction to the Company equal to the income tax effect of 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 Company's plans (shares in thousands):
The following table summarizes information about the stock options outstanding at June 30, 2002 (shares in thousands):
The Company applies the intrinsic value method of APB 25 in accounting for its employee stock incentive plans. Accordingly, no compensation expense has been recognized for any stock options issued under the employee plans. Had compensation expense for stock options granted to employees been recognized based on the fair value at the grant dates, using the methodology prescribed by SFAS 123, the Company's net income (loss) and earnings (loss) per share would have been reduced to pro forma amounts indicated below:
SFAS 123 does not apply to options granted prior to January 1, 1995; therefore, the pro forma effect disclosed above may not be representative of pro forma amounts in future years.
The total fair value of stock options granted during fiscal 2002, 2001 and 2000 was approximately $7,700,000, $11,217,000 and $19,541,000, respectively. The fair value of each stock option grant was estimated on the date of grant using the Black-Sholes option-pricing model, based on the following weighted-average assumptions.
9. INCOME TAXES
Components of income tax expense (benefit) are as follows:
The Company made no income tax payments which were not offset by reimbursement for fiscal 2002, 2001 and 2000. Additionally a deferred tax benefit of $267,000 and $7,004,000 has been allocated to stockholders' equity in fiscal 2002 and 2001, respectively, for compensation expense for income tax purposes in excess of amounts recognized for financial reporting purposes.
Income tax expense (benefit) differs from amounts computed by applying the statutory federal rate as follows:
Deferred tax assets (liabilities) are comprised of the following:
A valuation allowance is provided when it is more likely than not that some portion of the deferred tax assets will not be realized. As described below, due to annual limitations on certain net operating loss carryforwards, it does not appear more likely than not that the Company will be able to utilize all available carryforwards prior to their ultimate expiration.
The Company estimates that as of June 30, 2002, the Company will have available approximately $193,021,646 of net operating loss carryforwards (which will continue to expire in fiscal 2003). Approximately $51,521,895 of the net operating loss carryforwards are subject to an annual limitation of approximately $1,012,000, under Sections 382 and 383 of the Internal Revenue Code.
10. LEASING ARRANGEMENTS
The Company leases certain property and equipment under non-cancelable operating leases that generally expire at various dates through fiscal 2007. The term of the operating leases generally run from 24 to 60 months with varying payment dates throughout each month.
As of June 30, 2002, the future minimum lease payments under non-cancelable operating leases are as follows (in thousands):
Operating lease expense was approximately $6,456,000, $6,072,000, and $6,460,000 for the fiscal years ended June 30, 2002, 2001 and 2000, respectively.
11. EMPLOYEE BENEFIT PLANS
In order to retain quality personnel, the Company maintains 401(k) plans as part of its employee benefits package. From July 1, 1998 through December 31, 1998, the Company matched 100% of employee contributions into its 401(k) plan up to a maximum of $1,000 per participant per year. From January 1, 1999 through March 31, 2000, the Company elected not to match employee contributions. Commencing April 1, 2000, the Company matches, 100% of employee contributions into its 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. The Company's matching contributions for fiscal 2002, 2001 and 2000 were approximately $2,123,000, $1,857,000 and $77,000, respectively.
12. TRANSACTIONS WITH RELATED PARTIES
Effective as of July 1, 2001, the Company entered into an amended and restated employment agreement with Francis D. John (the "Employment Agreement") pursuant to which Mr. John serves as the Chairman of the Board, President and Chief Executive Officer of the Company. The Employment Agreement provided for the payment of a one-time retention incentive payment. The purpose of this retention incentive payment was to retire all amounts owed by Mr. John under incentive-based loans previously made to him (which, because certain performance criteria had been previously met, the Company was scheduled to forgive ratably over a ten-year period as long as Mr. John continued to serve the Company in his present capacity) and in the process provide Mr. John with incentive to remain with the Company 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) approximately $7.5 million in principal and interest accrued through the date of the payment and (ii) approximately $5.6 million in a tax "gross-up" payment. The entire payment was withheld by the Company and used to satisfy Mr. John's tax obligations and his obligations under the loans. Pursuant to the Employment Agreement, Mr. John will 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 fiscal 2002, Mr. John earned approximately $1.3 million of the retention incentive payment. If Mr. John voluntarily terminates his employment with the Company or if Mr. John is terminated by the Company for Cause (as defined in the Employment Agreement), Mr. John will 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 the Company is terminated (i) by the Company 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 will be treated as earned as of the date of such event.
13. BUSINESS SEGMENT INFORMATION
The Company's reportable business segments are well servicing and contract drilling. Oil and natural gas production operations are presented in "corporate/other."
WELL SERVICING: the Company's operations provide well servicing (ongoing maintenance of existing oil and natural gas wells), workover (major repairs or modifications necessary to optimize the level of production from existing oil and natural gas wells) and production services (fluid hauling and fluid storage tank rental).
CONTRACT DRILLING: the Company provides contract drilling services for major and independent oil companies onshore the continental United States, Argentina and Ontario, Canada.
The Company's management evaluates the performance of its operating segments based on net income and operating profits (revenues less direct operating expenses). 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.
* - Net income (loss) before extraordinary gain (loss) for the contract drilling segment includes a portion of well servicing general and administrative expenses allocated on a percentage of revenue basis.
Operating revenues and operating profit for the Company's foreign operations, which includes Argentina and Canada, were $33.2 million and $6.4 million, respectively, for the year ended June 30, 2002. Operating revenues and operating profit for the Company's foreign operations, which includes Argentina and Canada, were $54.5 million and $13.4 million, respectively, for the year ended June 30, 2001. Operating revenues and operating profit for the Company's foreign operations, which includes Argentina and Canada, were $37.7 million and $7.3 million, respectively, for the year ended June 30, 2002.
The Company had $27.9 million and $84.1 million of identifiable assets as of June 30, 2002 and 2001, respectively, related to its foreign operations.
14. SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES
15. UNAUDITED SUPPLEMENTARY INFORMATION - QUARTERLY RESULTS OF OPERATIONS
Summarized quarterly financial data for fiscal 2002, and 2001 are as follows:
16. VOLUMETRIC PRODUCTION PAYMENT
In March 2000, Key sold a portion of its future oil and natural gas production from Odessa Exploration Incorporated, its wholly owned subsidiary, for gross proceeds of $20 million pursuant to an agreement under which the purchaser is entitled to receive a share of the production from certain oil and natural gas properties in amounts ranging from 3,500 to 10,000 barrels of oil and 58,800 to 122,100 Mmbtus of natural gas per month over a six year period ending February 2006. The total volume of the forward sale is approximately 486,000 barrels of oil and 6.135 million Mmbtus of natural gas.
17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
The Company's senior notes are guaranteed by all of the Company's operating subsidiaries (except for its oil and natural gas production subsidiary and its foreign subsidiaries), all of which are wholly-owned. The guarantees are joint and several, full, complete and unconditional. There are currently 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 generally accepted accounting principles.
CONDENSED CONSOLIDATING BALANCE SHEETS
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
18. ARGENTINA FOREIGN CURRENCY TRANSACTION LOSS
The local currency is the functional currency for the Company's foreign operations in Argentina and Canada. The cumulative translation gains and losses, resulting from translating each foreign subsidiary's financial statements from the functional currency to U.S. dollars are included in other comprehensive income and accumulated in stockholders' equity until a partial or complete sale or liquidation of the Company's net investment in the foreign entity.
Since 1991, the Argentine peso has been 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 will be settled at an expected fixed conversion ratio of 1.4:1 while all other transactions will 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, 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, the Company translated the assets and liabilities of its 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. At June 30, 2002, the Company used a conversion ratio of 3.9:1 to translate the assets and liabilities of its Argentine subsidiary. As a result, a foreign currency translation loss of approximately $48.3 million is included in other comprehensive income, a component of stockholders' equity, at June 30, 2002. 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 average exchange rate during the reporting period.
Additionally, the Argentine government has indicated that as part of its monetary policy changes, it will re-denominate certain consumer loans from U.S. dollar-denominated to Argentine peso- denominated. As a result, the Company recorded a foreign currency transaction loss of $1.8 million in the three months ended December 31, 2001 related to accounts receivable subject to certain U.S. dollar-denominated contracts held by its Argentine subsidiary which are subject to re-denomination. These receivables are subject to additional negotiation with the Company's customers which may result in recovery of a portion of this loss. In the six months ended June 30, 2002, the Company recovered approximately $0.4 million resulting in a net foreign currency transaction loss of approximately $1.4 million for fiscal 2002.
19. SUBSEQUENT EVENTS-ACQUISITION OF Q SERVICES, INC. [UNAUDITED]
On July 19, 2002, the Company acquired Q Services, Inc. ("QSI") pursuant to an Agreement and Plan of Merger dated May 13, 2002, as amended, by and among the Company, Key Merger Sub, Inc. and QSI. As consideration for the merger, the Company issued approximately 17.2 million shares of its common stock to QSI shareholders and assumed approximately $74 million of QSI's indebtedness, net of working capital. The aggregate value of the purchase price was approximately $221 million. Prior to the acquisition, QSI was a privately held corporation conducting field production, pressure pumping and other service operations in Louisiana, New Mexico, Oklahoma, Texas and the Gulf of Mexico.
20. SUBSEQUENT EVENTS-NEW SENIOR CREDIT FACILITY [UNAUDITED]
On July 15, 2002, the Company entered into a Third Amended and Restated Credit Agreement (the "New Senior Credit Facility"). The New Senior Credit Facility consists of a $150,000,000 revolving loan facility with a $40,000,000 sublimit for letters of credit. The loans are secured by most of the tangible and intangible assets of the Company. The revolving loan commitment will terminate on July 15, 2005 and all revolving loans must be paid on or before that date. The revolving loans bear interest based upon, at the Company's option, the prime rate plus a variable margin of 0.00% to 0.75% or a Eurodollar rate plus a variable margin of 1.25% to 2.75%.
The New Senior Credit Facility contains various financial covenants, including: (i) a maximum consolidated senior leverage ratio of 2.75 to 1.00, (ii) a minimum consolidated fixed coverage ratio of 1.50 to 1.00, and (iii) a maximum consolidated total leverage ratio of 3.50 to 1.00. The Company is also required to maintain a minimum net worth of $436,972,000 plus (i) 50% of consolidated net income and (ii) 75% of the net cash proceeds from the sale of equity.
The New Senior Credit Facility subjects the Company to other restrictions, including restrictions upon the Company's ability to incur additional debt, liens and guarantee obligations, to merge or consolidate with other persons, to make acquisitions, to sell assets, to make dividends, purchases of our stock or subordinated debt, or to make investments, loans and advances or changes to debt instruments and organizational documents. All obligations under the New Senior Credit Facility are guaranteed by most of the Company's subsidiaries and are secured by most of the Company's assets, including the Company's accounts receivable, inventory and most equipment.
At September 30, 2002 as a result of retiring certain long-term debt of QSI, there was approximately $62.0 million outstanding under the New Senior Credit Facility revolver and $28.0 million in outstanding letters of credit.
INDEPENDENT AUDITORS' REPORT
To The Board of Directors and Stockholders Key Energy Services, Inc.
We have audited the accompanying consolidated balance sheets of Key Energy Services, Inc., and subsidiaries as of June 30, 2002 and 2001, and the related consolidated statements of operations, comprehensive income, cash flows and stockholders' equity for each of the years in the three-year period ended June 30, 2002. In connection with our audits of the consolidated financial statements, we also have audited the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Key Energy Services, Inc. and subsidiaries as of June 30, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended June 30, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for goodwill and other intangible assets in 2002. As discussed in Note 6 to the consolidated financial statements, the Company changed its method of accounting for derivative instruments and hedging activities in 2001.
KPMG LLP Dallas, Texas August 16, 2002
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEMS 10-13.
Pursuant to Instruction G(3) to Form 10-K, the information required in Items 10-13 is incorporated by reference to the Company's definitive proxy statement, which will be filed with the Commission pursuant to Regulation 14A within 120 days of June 30, 2002.
ITEM 14.
ITEM 14. DISCLOSURE CONTROLS AND PROCEDURES
(b) Changes in Internal Controls
There were no significant changes in the Company's internal controls during fiscal 2002 nor did any other factors exist that could significantly affect such controls through the date of this report.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENTS AND REPORTS ON FORM 8-K.
(a) Index to Exhibits
The following documents are filed as part of this report:
(1) See Index to Financial Statements set forth in Item 8.
(2) Financial Statements Schedules:
Key Energy Services, Inc.: Consolidated Supplementary Financial Statement Schedule As of and for Each of the Three Years Ended June 30, 2002: Schedule II-Consolidated Valuation and Qualifying Accounts...S-1
The supplemental schedules other than the one listed above are omitted because of the absence of the conditions under which they are required or because the required information is included in the Consolidated Financial Statements or Notes thereto.
(3) Exhibits:
3.1 Amended and Restated Articles of Incorporation of the Company. (Incorporated by reference to the Company's Registration Statement on Form S-4, Registration No. 333-369). 3.2 Amended and Restated By-Laws of the Company. (Incorporated by reference to the Company's Registration Statement on Form S-4 dated March 8, 1996, Registration No. 333-369). 3.3 Amendment to the Amended and Restated Articles of Incorporation of the Company. (Incorporated by reference to Exhibit 3.1 of the Company's Current Report on Form 8-K dated February 2, 1998, File No. 1-8038).
3.4 Amendment to the Amended and Restated Articles of Incorporation of the Company. (Incorporated by reference to Exhibit A of the definitive proxy statement on Schedule 14A filed by the Company on November 17, 1998, File No. 1-8038). 3.5 Articles of Amendment to Amended and Restated Articles of Incorporation of the Company (Incorporated by reference to Exhibit 3.1 of the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-8038). 3.6 Unanimous Consent of the Board of Directors of the Company dated January 11, 2000, limiting the designation of the additional authorized shares to common stock (Incorporated by reference to Exhibit 3.2 of the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-8038). 4.1 Indenture dated as of September 25, 1997, among Key Energy Group, Inc. and American Stock Transfer and Trust Company. (Incorporated by reference to Exhibit 10(a) of the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1997, File No. 1-8038). 4.2 Warrant Agreement dated as of January 22, 1999 between the Company and The Bank of New York, a New York banking corporation as warrant agent. (Incorporated by reference to Exhibit 99(b) of the Company's Form 8-K filed on February 3, 1999, File No. 1-8038). 4.3 Indenture dated as of January 22, 1999 between the Company and The Bank of New York as trustee. (Incorporated by reference to Exhibit 99(c) of the Company's Form 8-K filed on February 3, 1999, File No. 1-8038). 4.4 Warrant Registration Rights Agreement dated January 22, 1999, by and among the Company and Lehman Brothers Inc., Bear, Stearns & Co. Inc., F.A.C./Equities, a division of First Albany Corporation,
and Dain Rauscher Wessels, a division of Dain Rauscher Incorporated. (Incorporated by reference to Exhibit 99(e) of the Company's Form 8-K filed on February 3, 1999, File No. 1-8038). 4.5 Indenture dated March 6, 2001 between the Company and The Chase Manhattan Bank, a New York banking corporation, as Trustee (Incorporated by reference to Exhibit 4.1 of the Company's Form 8-K filed on March 20, 2001, File No. 1-8038). 10.1 Employment Agreement between the Company and D. Kirk Edwards, dated as of July 1, 1996. (Incorporated by reference to Exhibit 10.1 of the Company's Annual Report on Form 10-K for the year ended June 30, 1997, File No. 1-8038). 10.2 $550,000,000 Second Amended and Restated Senior Credit Facility, among Key Energy Group, Inc., PNC Bank, National Association, Norwest Bank Texas, N.A., PNC Capital Markets, Inc. and the several lenders from time to time parties thereto, dated as of June 6, 1997, as amended and restated through September 14, 1998 (Incorporated by reference to Exhibit 99.7 of the Company's Current Report on Form 8-K dated September 28, 1998, File No. 1-8038). 10.3 Amended and Restated Master Guarantee and Collateral Agreement made by Key Energy Group, Inc. and certain of its subsidiaries in favor of Norwest Bank Texas, N.A., dated as of June 6, 1998, as amended and restated through September 14, 1998 (Incorporated by reference to Exhibit 99.8 of the Company's Current Report on Form 8-K dated September 28, 1998, File No. 1-8038). 10.4 Intercreditor and Collateral Agency Agreement, dated as of September 14, 1998. (Incorporated by reference to Exhibit 99.9 of the Company's Current Report on Form 8-K dated September 28, 1998, File No. 1-8038). 10.5 Consulting Agreement, dated as of October 7, 1998, by and among Key Energy Group, Inc. and Michael E. Little. (Incorporated by reference to Exhibit 10(a) of the Company's Quarterly Report on Form 10-Q for the quarter ended December 31, 1998, File No. 1-8038). 10.6 Non-Compete Agreement, dated November 13, 1998, by and between Key Energy Group, Inc. and James J. Byerlotzer. (Incorporated by reference to Exhibit 10(c) of the Company's Quarterly Report on Form 10-Q for the quarter ended December 31, 1998, File No. 1-8038). 10.7 Non-Compete Agreement, dated October 20, 1998, by and between Key Energy Group, Inc. and Joseph B. Eustace. (Incorporated by reference to Exhibit 10(e) of the Company's Quarterly Report on Form 10-Q for the quarter ended December 31, 1998, File No. 1-8038). 10.8 Consulting Agreement, dated as of November 12, 1998, by and among Key Energy Group, Inc. and C. Ron Laidley. (Incorporated by reference to Exhibit 10(f) of the Company's Quarterly Report on Form 10-Q for the quarter ended December 31, 1998, File No. 1-8038). 10.9 Key Energy Group, Inc. Performance Compensation Plan. (Incorporated by reference to Exhibit 10(g) of the Company's Quarterly Report on Form 10-Q for the quarter ended December 31, 1998, File No. 1-8038). 10.10 First Amendment, dated as of December 3, 1997, to the Second Amended and Restated Senior Credit
Facility, dated as of June 6, 1997, as amended and restated through November 6, 1997. (Incorporated by reference to Exhibit 10(h) of the Company's Quarterly Report on Form 10-Q for the quarter ended December 31, 1998, File No. 1-8038). 10.11 Second Amendment, dated as of December 29, 1998, to the Second Amended and Restated Senior Credit Facility, dated as of June 6, 1997, as amended and restated through September 14, 1998, and as amended by the First Amendment dated as of November 19, 1998. (Incorporated by reference to Exhibit 10(i) of the Company's Quarterly Report on Form 10-Q for the quarter ended December 31, 1998, File No. 1-8038). 10.12 Purchase Agreement dated January 19, 1999 by and among the Registrant, certain of its subsidiaries, Lehman Brothers, Inc., Bear, Stearns & Co. Inc., First Albany Corporation, Dain Rauscher Wessels, a division of Dain Rauscher Incorporated. (Incorporated by reference to Exhibit 99(a) of the Company's Form 8-K filed on February 3, 1999, File No. 1-8038). 10.13 Employment Agreement between the Company and Michael R. Furrow dated as of January 4, 1999. (Incorporated by reference to Exhibit 10(g) of the Company's Quarterly Report on Form 10-Q for the quarter ended December 31, 1998, File No. 1-8038). 10.14 Third Amendment, dated as of April 8, 1999, to the Second Amended and Restated Senior Credit Facility, among the Company, the several lenders from time to time parties thereto, PNC Bank, National Association, as Administrative Agent, Norwest Bank Texas, N.A., as Collateral Agent and PNC Capital Markets, Inc., as Arranger. (Incorporated by reference to Exhibit 99.5 of the Company's Current Report on Form 10-K dated April 8, 1999, File No. 1-8038). 10.15 Fourth Amendment, dated as of April 15, 1999, to the Second Amended and Restated Senior Credit Facility, among the Company, the several lenders from time to time parties thereto, PNC Bank, National Association, as Administrative Agent, Norwest Bank Texas, N.A., as Collateral Agent and PNC Capital Markets, Inc., as Arranger. (Incorporated by reference to Exhibit 99.6 of the Company's Current Report on Form 10-K dated April 8, 1999, File No. 1-8038). 10.16 Fifth Amendment, dated as of May 10, 1999, to the Second Amended and Restated Senior Credit Facility, among the Company, the several lenders from time to time parties thereto, PNC Bank, National Association, as Administrative Agent, Norwest Bank Texas, N.A., as Collateral Agent, and PNC Capital Markets, Inc., as Arranger. (Incorporated by reference to Exhibit 10.91 of the Company's Annual Report on Form 10-K dated June 30, 1999, File No. 1-8038).
10.17 Employment Agreement dated August 5, 1999, between Thomas K. Grundman and Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.2 of the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999, File No. 1-8038). 10.18 Agreement dated as of August 2, 1999, between Francis D. John and Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.5 of the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999, File No. 1-8038). 10.19 Promissory Note dated August 3, 1999, made by Thomas K. Grundman in favor of Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.6 of the Quarterly Report on Form 10-Q for the quarter ended September 30, 1999, File No. 1-8038). 10.20 Demand Note dated August 3, 1999, made by Thomas K. Grundman in favor of Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.7 of the Quarterly Report on Form 10-Q for the quarter ended September 30, 1999, File No. 1-8038). 10.21 Amendment No. 1 dated as of December 1, 1999, to Agreement dated as of August 2, 1999, between Francis D. John and Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q for the quarter ended December 31, 1999, File No. 1-8038). 10.22 Sixth Amendment, dated as of July 14, 1999, to the Second Amended and Restated Senior Credit Facility, among the Company, the several lenders from time to time parties thereto, PNC Bank, National Association, as Administrative Agent, Norwest Bank Texas, N.A., as Collateral Agent, and PNC Capital Markets, Inc., as Arranger (Incorporated by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-8038). 10.23 Seventh Amendment, dated as of March 1, 2000, to the Second Amended and Restated Senior Credit Facility, among the Company, the several lenders from time to time parties thereto, PNC Bank, National Association, as Administrative Agent, Norwest Bank Texas, N.A., as Collateral Agent, and PNC Capital Markets, Inc., as Arranger (Incorporated by reference to Exhibit 10.2 of the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-8038). 10.24 Production and Delivery Agreement dated March 31, 2000, among Odessa Exploration Incorporated and Norwest Energy Capital, Inc., (Incorporated by reference to Exhibit 10.3 of the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-8038). 10.25 Agreement dated March 31, 2000, among Odessa Exploration Incorporated, Norwest Energy Capital, Inc. and the Company (Incorporated by reference to Exhibit 10.4 of the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-8038). 10.26 Underwriting Agreement dated June 27, 2000, among the Company and Lehman Brothers Inc. for itself and as Representative of the several underwriters named in Schedule I thereto (Incorporated by reference to Exhibit 1.1 of the Company's Current Report on Form 8-K dated June 29, 2000, File No. 1-8038). 10.27 Amendment No. 2 dated as of June 16, 2000 to Agreement dated as of August 2, 1999, as amended
between Francis D. John and Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.83 of the Company's Annual Report on Form 10-K dated June 20, 2000, File No. 1-8038). 10.28 Amendment dated July 1, 2000 to Employment Agreement dated August 5, 1999 between Thomas K. Grundman and Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.1 of the Company's Quarterly report on Form 10-Q for the quarter ended September 30, 2000, File No. 1-8038). 10.29 Letter Agreement Amendment dated July 1, 2000 to the Demand Note dated August 3, 1999 made by Thomas K. Grundman in favor of Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.2of the Company's Quarterly Report of Form 10-Q for the quarter ended September 30, 2000, File No. 1-8038). 10.30 Purchase Agreement dated March 1, 2001 among the Company, certain of its subsidiaries, Lehman Brothers, Inc., and Bear Stearns & Co., Inc. (Incorporated by reference to Exhibit 1.1 of the Company's Form 8-K filed on March 20, 2001, File No. 1-8038). 10.31 Eighth Amendment to the Second Amended and Restated Senior Credit Facility, dated as of June 6, 1997, as amended and restated through September 14, 1998 and as further amended, among Key Energy Group, Inc. (now known as Key Energy Services, Inc.), the several Lenders from time to time parties thereto, PNC Bank, National association, as Administrative Agent, Norwest Bank Texas, N.A., as Collateral Agent and PNC Capital markets, Inc., as Arranger. (Incorporated by reference to Exhibit 99.3 of the Company's Form 8-K filed on March 20, 2001, File No. 1-8038). 10.32 Amendment No. 3 dated as of May 14, 2001 to Agreement dated as of August 2, 1999, as amended, between Francis D. John and Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.49 of the Company's Annual Report on Form 10-K dated June 30, 2001, File No. 1-8038). 10.33 Second Amended and Restated Employment Agreement dated October 16, 2001 between Francis D. John and Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.50 of the Company's Annual Report on Form 10-K/A dated June 30, 2001, File No. 1-8038). 10.34 Ninth Amendment to the Second Amended and Restated Credit Agreement, dated as of June 6, 1997, as amended and restated through September 14, 1998 and as further amended, among Key Energy Group, Inc. (now known as Key Energy Services, Inc.), the several Lenders from time to time parties thereto, PNC Bank, National Association, as Administrative Agent, Norwest Bank Texas, N.A., as Collateral Agent and PNC Capital Markets, Inc., as Arranger. (Incorporated by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q dated September 30, 2001, File 1-8038). 10.35 Underwriting Agreement, dated December 13, 2001, between Registrant and Lehman Brothers Inc. (Incorporated by reference to Exhibit 1.1 of the Company's Current Report on Form 8-K dated December 19, 2001, File No. 1-8038). 10.36 Tenth Amendment to the Second Amended and Restated Credit Agreement, dated as of June 6, 1997, as amended and restated through September 14, 1998 and as further amended, among Key Energy Group, Inc. (now known as Key Energy Services, Inc.), the several Lenders from time to time parties thereto, PNC Bank, National Association, as Administrative Agent, Norwest Bank Texas, N.A., as Collateral Agent and PNC Capital Markets, Inc., as Arranger. (Incorporated by reference to Exhibit 10.1 of the Company's Form 8-K filed on December 19, 2001, File 1-8038). 10.37 Employment Agreement between Key Energy Services, Inc. and Royce W. Mitchell dated December 31, 2001. (Incorporated by reference to Exhibit 10.3 of the Company's Quarterly Report on Form 10-Q dated December 31, 2001, File 1-8038). 10.38 Employment Agreement between Key Energy Services, Inc. and James Byerlotzer dated December 31, 2001. (Incorporated by reference to Exhibit 10.4 of the Company's Quarterly Report on Form 10-Q dated December 31, 2001, File 1-8038). 10.39 First Amendment to Second Amended and Restated Employment Agreement between Francis D. John and Key Energy Services, Inc. dated December 31, 2001. (Incorporated by reference to Exhibit 10.5 of the Company's Quarterly Report on Form 10-Q dated December 31, 2001, File 1-8038). 10.40 Underwriting Agreement, dated February 22, 2002, among the Registrant and Lehman Brothers Inc., Bear Stearns & Co. Inc. and First Albany Corporation. (Incorporated by reference to Exhibit 1.1 of the Company's Current Report on Form 8-K dated February 27, 2002, File No. 1-8038). 10.41 Eleventh Amendment to the Second Amended and Restated Credit Agreement, dated as of June 6, 1997, as amended and restated through September 14, 1998 and as further amended, among Key Energy Group, Inc. (now known as Key Energy Services, Inc.), the several Lenders from time to time parties thereto, PNC Bank, National Association, as Administrative Agent, Norwest Bank Texas, N.A., as Collateral Agent and PNC Capital Markets, Inc., as Arranger. (Incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K dated February 27, 2002, File 1-8038).
10.42 Twelfth Amendment to the Second Amended and Restated Credit Agreement, dated as of June 6, 1997, as amended and restated through September 14, 1998 and as further amended, among Key Energy Group, Inc. (now known as Key Energy Services, Inc.), the several Lenders from time to time parties thereto, PNC Bank, National Association, as Administrative Agent, Norwest Bank Texas, N.A., as Collateral Agent and PNC Capital Markets, Inc., as Arranger. (Incorporated by reference to Exhibit 10.2 of the Company's Current Report on Form 8-K dated February 27, 2002, File 1-8038). 10.43 Indenture dated as of February 22, 2002 among the Registrant and U.S. Bank National Association. (Incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K dated February 27, 2002, File 1-8038). 10.44 First Supplemental Indenture dated as of March 1, 2002 among the Registrant, the Guarantors (as defined therein) and U.S. Bank National Association. (Incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K dated March 1, 2002, File 1-8038). 10.45 Employment Agreement between Key Energy Services, Inc. and Thomas K. Grundman dated February 15, 2002. (Incorporated by reference to Exhibit 10.3 of the Company's Quarterly Report on Form 10-Q dated March 31, 2002, File 1-8038). *10.46 Separation and Release Agreement between Key Energy Services, Inc. and Thomas K. Grundman dated May 6, 2002. 10.47 Plan and Agreement of Merger among Key Energy Services, Inc., Key Merger Sub., Inc. and Q Services, Inc. dated as of May 13, 2002. (Incorporated by reference to Exhibit 2.1 of the Company's Current Report on Form 8-K dated May 17, 2002, File 1-8038). *21 Significant Subsidiaries of the Company. *23 Consent of KPMG LLP. 25.1 Statement of Eligibility of Trustee, U.S. Bank National Association, a national banking association, on Form T-1. (Incorporated by reference to Exhibit 25.1 of the Company's Quarterly Report on Form 8-K dated February 27, 2002, File 1-8038). *99.1 Certification of CEO and CFO Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K
The Company filed the following reports on Form 8-K during the quarter ended June 30, 2002:
(i) Current report on Form 8-K dated May 17, 2002 filed to report the signing of a definitive merger agreement with Q Services, Inc. dated as of May 13, 2002.
- -----------
* Filed herewith.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
KEY ENERGY SERVICES, INC. (Registrant)
Dated: September 30, 2002 By: /s/ FRANCIS D. JOHN ---------------------------------- Francis D. John CHAIRMAN OF THE BOARD, PRESIDENT, AND CHIEF EXECUTIVE OFFICER
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Dated: September 30, 2002 By: /s/ FRANCIS D. JOHN ---------------------------------- Francis D. John CHAIRMAN OF THE BOARD, PRESIDENT, AND CHIEF EXECUTIVE OFFICER
Dated: September 30, 2002 By: /s/ ROYCE W. MITCHELL ---------------------------------- Royce W. Mitchell CHIEF FINANCIAL OFFICER AND CHIEF ACCOUNTING OFFICER
Dated: September 30, 2002 By: /s/ MORTON WOLKOWITZ ---------------------------------- Morton Wolkowitz DIRECTOR
Dated: September 30, 2002 By: /s/ DAVID J. BREAZZANO ---------------------------------- David J. Breazzano DIRECTOR
Dated: September 30, 2002 By: /s/ KEVIN P. COLLINS ---------------------------------- Kevin P. Collins DIRECTOR
Dated: September 30, 2002 By: /s/ W. PHILLIP MARCUM ---------------------------------- W. Phillip Marcum DIRECTOR
Dated: September 30, 2002 By: /s/ WILLIAM D. FERTIG ---------------------------------- William D. Fertig DIRECTOR
Dated: September 30, 2002 By: /s/ J. ROBINSON WEST ---------------------------------- J. Robinson West DIRECTOR
I, Francis D. John, certify that:
1. I have reviewed this annual report on Form 10-K of Key Energy Services, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; and
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report.
Date: September 30, 2002
/s/ FRANCIS D. JOHN ------------------------ Francis D. John Chief Executive Officer
CERTIFICATIONS
I, Royce W. Mitchell, certify that:
1. I have reviewed this annual report on Form 10-K of Key Energy Services, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; and
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report.
Date: September 30, 2002
/s/ ROYCE W. MITCHELL ------------------------ Royce W. Mitchell Chief Financial Officer
SCHEDULE II
KEY ENERGY SERVICES, INC. CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AS OF JUNE 30,