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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549
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FORM 10-K
(MARK ONE)

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

FOR THE FISCAL YEAR ENDED JUNE 30, 2002
OR

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

FOR THE TRANSITION PERIOD FROM TO
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COMMISSION FILE NUMBER 1-8038

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KEY ENERGY SERVICES, INC.
(Exact name of registrant as specified in its charter)

MARYLAND 04-2648081
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

6 DESTA DRIVE, MIDLAND, TEXAS 79705
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (915) 620-0300

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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
Common Stock, $.10 par value New York Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
5% Convertible Subordinated Notes Due 2004

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months
(or for such shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for the past 90
days. Yes /X/: No / /

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. / /

The aggregate market value of the Common Shares held by nonaffiliates of the
Registrant as of September 27, 2002 was approximately $987,327,248.

Common Shares outstanding at September 27, 2002: 127,432,461

DOCUMENTS INCORPORATED BY REFERENCE: Portions of the Proxy Statement with
respect to the Annual Meeting of Shareholders for the fiscal year ended June
30, 2002 are incorporated by reference in Part III of this report.

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KEY ENERGY SERVICES, INC.

INDEX

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PART I.

Item 1. Business..................................................................................... 3

Item 2. Properties................................................................................... 10

Item 3. Legal Proceedings and Other Actions.......................................................... 11

Item 4. Submission of Matters to a Vote of Security Holders.......................................... 11

PART II.

Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.................... 11

Item 6. Selected Financial Data...................................................................... 12

Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition........ 13

Item 7A. Quantitative and Qualitative Disclosures About Market Risk................................... 20

Item 8. Consolidated Financial Statements and Supplementary Data..................................... 22

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure......... 59

PART III.

Item 10. Directors and Executive Officers............................................................. 59

Item 11. Executive Compensation....................................................................... 59

Item 12. Security Ownership of Certain Beneficial Owners and Management............................... 59

Item 13. Certain Relationships and Related Transactions............................................... 59

Item 14. Disclosure Controls and Procedures........................................................... 59

PART IV.

Item 15. Exhibits, Financial Statements and Reports on Form 8-K....................................... 59
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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

The statements in this document that relate to matters that are not
historical facts are "forward-looking statements" within the meaning of Section
27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. When used in this document and the documents incorporated by reference,
words such as "anticipate," "believe," "expect," "plan," "intend," "estimate,"
"project," "will," "could," "may," "predict" and similar expressions are
intended to identify forward-looking statements. Further events and actual
results may differ materially from the results set forth in or implied in the
forward-looking statements. Factors that might cause such a difference include:

- - fluctuations in world-wide prices and demand for oil and natural gas;

- - fluctuations in level of oil and natural gas exploration and
development activities;

- - fluctuations in the demand for well servicing, contract drilling and
ancillary oilfield services;

- - the existence of competitors, technological changes and developments in
the industry;

- - the existence of operating risks inherent in the well servicing,
contract drilling and ancillary oilfield services; and

- - general economic conditions, the existence of regulatory uncertainties,
and the possibility of political instability in any of the countries in
which Key does business, in addition to other matters discussed under
"Part II - Item 7 - Management's Discussion and Analysis of Results of
Operations and Financial Condition."

PART I

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

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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.

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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.

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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.

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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

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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.

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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

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,

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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. 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:

<Table>
<Caption>
WELL SERVICE AND OILFIELD DRILLING
OPERATING DIVISION WORKOVER RIGS TRUCKS RIGS
-------------------- ------------- --------------

DOMESTIC:
Permian Basin (well servicing)..................... 468 450 -
Gulf Coast......................................... 252 319 -
Mid-Continent...................................... 326 385 -
Four Corners....................................... 49 91 15
Eastern............................................ 91 253 3
Rocky Mountains.................................... 131 58 14
California......................................... 138 35 -
Key Energy Drilling (Permian Basin)................ 0 49 38
--------------------- ------------- --------------
DOMESTIC SUBTOTAL.................................... 1,455 1,640 70
--------------------- ------------- --------------

INTERNATIONAL:
Argentina.......................................... 25 75 7
Canada............................................. 4 4 2
Egypt.............................................. 2 - -
--------------------- ------------- --------------
INTERNATIONAL SUBTOTAL............................... 31 79 9
--------------------- ------------- --------------

TOTALS............................................... 1,486 1,719 79
===================== ============= ==============
</Table>

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

10
<Page>

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. LEGAL PROCEEDINGS AND OTHER ACTIONS.

See Note 3 to Consolidated Financial Statements-Commitments and
Contingencies.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

None.

PART II

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.

<Table>
<Caption>
HIGH LOW
------ -----

Fiscal Year Ending 2002:
Fourth Quarter....................................... $12.59 $9.63
Third Quarter........................................ 11.45 7.20
Second Quarter....................................... 9.70 5.99
First Quarter........................................ 11.01 5.58

Fiscal Year Ending 2001:
Fourth Quarter....................................... $15.33 $9.55
Third Quarter........................................ 13.52 8.13
Second Quarter....................................... 10.50 6.81
First Quarter........................................ 11.44 7.06
</Table>

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.

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

Equity compensation plans
approved by the security holders 6,298 $7.41 616 (1)

Equity compensation plans
not approved by the security
holders 3,710 $8.45 0 (2)

Total 10,031 $7.80 409

</Table>

(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).

11
<Page>

ITEM 6. SELECTED FINANCIAL DATA.

<Table>
<Caption>
FISCAL YEAR ENDED JUNE 30,
------------------------------------------------------------------
2002 2001 2000 1999(1) 1998
------------------------------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

OPERATING DATA:
Revenues ............................................ $ 802,564 $ 873,262 $ 637,732 $ 491,817 $ 424,543
Operating costs:
Direct costs (4) .................................. 554,773 582,154 471,169 374,308 296,328
Depreciation, depletion and amortization .......... 78,265 75,147 70,972 62,074 31,001
General and administrative (4) .................... 59,494 60,118 51,637 56,156 36,933
Interest .......................................... 43,332 56,560 71,930 67,401 21,476
Foreign currency transaction loss, Argentina ...... 1,443 - - - -
Debt issuance costs ............................... - - - 6,307 -
Restructuring charge .............................. - - - 4,504 -
Income (loss) before income taxes, minority interest,
and extraordinary items .......................... 65,257 99,283 (27,976) (78,933) 38,805
Net income (loss) ................................... 38,146 62,710 (18,959) (53,258) 24,175
INCOME (LOSS) PER COMMON SHARE:
Basic ............................................. $ 0.36 $ 0.63 $ (0.23) $ (1.94) $ 1.41
Diluted ........................................... $ 0.35 $ 0.61 $ (0.23) $ (1.94) $ 1.23
Average common shares outstanding:
Basic ............................................. 105,766 98,195 83,815 27,501 17,153
Assuming full dilution ............................ 107,462 102,271 83,815 27,501 24,024
Common shares issued at period end .................. 110,308 101,440 97,210 82,738 18,267
Market price per common share at period end ......... $ 10.50 $ 10.84 $ 9.64 $ 3.56 $ 13.12
Cash dividends paid on common shares ................ - - - - -
BALANCE SHEET DATA:
Cash ................................................ $ 54,147 $ 2,098 $ 109,873 $ 23,478 $ 25,265
Current assets ...................................... 192,073 206,150 253,589 132,543 127,557
Property and equipment .............................. 1,093,104 1,014,675 920,437 871,940 547,537
Property and equipment, net ......................... 808,900 793,716 760,561 769,562 499,152
Total assets ........................................ 1,242,995 1,228,284 1,246,265 1,148,138 698,640
Current liabilities ................................. 96,628 115,553 92,848 73,151 48,029
Long-term debt, including current portion ........... 443,610 493,907 666,600 699,978 399,779
Stockholders' equity ................................ 536,866 476,878 382,887 288,094 154,928
OTHER DATA:
Adjusted EBITDA (2) ................................. 188,465 $ 232,253 $ 116,574 $ 67,281 $ 92,108
Net cash provided by (used in):
Operating activities .............................. 178,716 143,347 34,860 (13,427) 40,925
Investing activities .............................. (108,749) (83,980) (37,766) (294,654) (306,339)
Financing activities .............................. (17,315) (167,142) 89,301 306,294 248,975
Working capital ..................................... 95,445 90,597 160,741 59,392 79,528
Book value per common share (3) ..................... $ 4.87 $ 4.70 $ 3.94 $ 3.47 $ 8.48
</Table>

(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.

12
<Page>

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

13
<Page>

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

14
<Page>

$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

15
<Page>

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.

16
<Page>

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%.

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.

17
<Page>

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.

18
<Page>

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

19
<Page>

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. 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:

<Table>
<Caption>
BALANCE AT
JUNE 30, 2002
----------------
(THOUSANDS)

8 3/8 % Senior Notes Due 2008..................................... $276,433
14% Senior Subordinated Notes Due 2009............................ 94,257
5% Convertible Subordinated Notes Due 2004........................ 49,951
Other (at approximately 8%)....................................... 140
----------------
$420,781
================
</Table>

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

<Page>

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:

<Table>
<Caption>
MONTHLY INCOME STRIKE PRICE
-------------- PER BBL/MMBTU
OIL GAS -------------
(BBLS) (MMBTU) TERM FLOOR CAP FAIR VALUE
------ ------- ---- ----- --- ----------

At June 30, 2002
Oil Put........... 5,000 - Mar 2002-Feb 2003 $22.00 - $24,000
Oil Put........... 4,000 - Mar 2003-Feb 2004 $21.00 - $118,000
Gas Put........... - 75,000 Mar 2002-Feb 2003 $3.00 - $104,000

At June 30, 2001
Oil Collar........ 5,000 - Mar 2001-Feb 2002 $19.70 $23.70 ($115,000)
Oil Put........... 5,000 - Mar 2002-Feb 2003 $22.00 - $141,000
Gas Collar........ - 40,000 Mar 2001-Feb 2002 $2.40 $2.91 ($229,000)
Gas Put........... - 75,000 Mar 2002-Feb 2003 $3.00 - $894,000
</Table>

(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.)

21
<Page>

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

<Table>
<Caption>
PAGE
----

Consolidated Balance Sheets.......................................... 23
Consolidated Statements of Operations................................ 24
Consolidated Statements of Comprehensive Income...................... 25
Consolidated Statements of Cash Flows................................ 26
Consolidated Statements of Stockholders' Equity...................... 27
Notes to Consolidated Financial Statements........................... 28
Independent Auditors' Report......................................... 58
</Table>

22
<Page>

KEY ENERGY SERVICES, INC.

CONSOLIDATED BALANCE SHEETS

<Table>
<Caption>
JUNE 30, 2002 JUNE 30, 2001
------------- -------------
(THOUSANDS, EXCEPT SHARE DATA)

ASSETS
Current assets:
Cash and cash equivalents ................................................... $ 54,147 $ 2,098
Accounts receivable, net of allowance for doubtful accounts, $3,969
and $4,082, at June 30, 2002 and June 30, 2001, respectively ............. 117,907 177,016
Inventories ................................................................. 7,776 16,547
Prepaid expenses and other current assets ................................... 12,243 10,489
----------- -----------

Total current assets .......................................................... 192,073 206,150
----------- -----------

Property and equipment:
Well servicing equipment .................................................... 776,271 723,724
Contract drilling equipment ................................................. 124,191 119,122
Motor vehicles .............................................................. 68,977 64,907
Oil and gas properties and other related equipment, successful efforts
method .................................................................... 44,439 44,245
Furniture and equipment ..................................................... 38,979 24,865
Buildings and land .......................................................... 40,247 37,812
----------- -----------

Total property and equipment .................................................. 1,093,104 1,014,675
Accumulated depreciation & depletion .......................................... (284,204) (220,959)
----------- -----------
Net property and equipment .................................................... 808,900 793,716
----------- -----------

Goodwill, net of accumulated amortization, $27,856 and $28,168, at
June 30, 2002 and June 30, 2001, respectively .............................. 201,069 189,875
Deferred costs, net ........................................................... 12,580 17,624
Notes receivable - related parties ............................................ 274 6,050
Other assets .................................................................. 28,099 14,869
----------- -----------
Total assets .................................................................. $ 1,242,995 $ 1,228,284
=========== ===========

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable ............................................................ $ 24,625 $ 42,544
Other accrued liabilities ................................................... 49,465 48,923
Accrued interest ............................................................ 14,864 16,140
Current portion of long-term debt ........................................... 7,674 7,946
----------- -----------
Total current liabilities ..................................................... 96,628 115,553
----------- -----------

Long-term debt, less current portion .......................................... 420,717 470,578
Capital lease obligations, less current portion ............................... 15,219 15,383
Deferred revenue .............................................................. 10,001 14,104
Non-current accrued expenses .................................................. 13,574 8,388
Deferred tax liability ........................................................ 149,990 127,400
Commitments and contingencies

Stockholders' equity:
Common stock, $0.10 par value; 200,000,000 shares authorized, 110,308,463 and
101,440,166 shares issued, respectively at June
30, 2002 and June 30, 2001, respectively ................................. 11,031 10,144
Additional paid-in capital .................................................. 514,752 444,768
Treasury stock, at cost; 416,666 shares at June 30, 2002 and June ........... (9,682) (9,682)
30, 2001
Accumulated other comprehensive income (loss) ............................... (48,967) 62
Retained earnings ........................................................... 69,732 31,586
----------- -----------
Total stockholders' equity .................................................... 536,866 476,878
----------- -----------
Total liabilities and stockholders' equity .................................... $ 1,242,995 $ 1,228,284
=========== ===========
</Table>

SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.

23
<Page>

KEY ENERGY SERVICES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

<Table>
<Caption>
YEAR ENDED JUNE 30,
-------------------------------------------
2002 2001 2000
--------- --------- ---------
(THOUSANDS, EXCEPT PER SHARE DATA)

REVENUES:
Well servicing ............................................... $ 706,629 $ 758,273 $ 559,492
Contract drilling ............................................ 87,077 107,639 68,428
Other ........................................................ 8,858 7,350 9,812
--------- --------- ---------
Total revenues ................................................. 802,564 873,262 637,732
--------- --------- ---------
COSTS AND EXPENSES:
Well servicing ............................................... 489,681 500,324 408,723
Contract drilling ............................................ 60,561 77,366 58,299
Depreciation, depletion and amortization ..................... 78,265 75,147 70,972
General and administrative ................................... 59,494 60,118 51,637
Interest ..................................................... 43,332 56,560 71,930
Other expenses ............................................... 4,531 4,464 4,147
Foreign currency transaction loss, Argentina ................. 1,443 - -
--------- --------- ---------
Total costs and expenses ....................................... 737,307 773,979 665,708
--------- --------- ---------
Income (loss) before income taxes .............................. 65,257 99,283 (27,976)
Income tax benefit (expense) ................................... (24,074) (37,002) 7,406
--------- --------- ---------

INCOME (LOSS) BEFORE EXTRAORDINARY GAIN (LOSS) ................. 41,183 62,281 (20,570)
Extraordinary gain (loss) on retirement of debt, less applicable
income taxes of $1,775 - 2002, $(255) - 2001 and $(580) - 2000 . (3,037) 429 1,611
--------- --------- ---------

NET INCOME (LOSS) .............................................. $ 38,146 $ 62,710 $ (18,959)
========= ========= =========

EARNINGS (LOSS) PER SHARE :
Basic - before extraordinary gain (loss) ..................... $ 0.39 $ 0.63 $ (0.25)
Extraordinary gain (loss) on retirement of debt, net of tax .. (0.03) - 0.02
--------- --------- ---------

Basic- after extraordinary gain (loss) ....................... $ 0.36 $ 0.63 $ (0.23)
========= ========= =========

Diluted- before extraordinary gain (loss) .................... $ 0.38 $ 0.61 $ (0.25)
Extraordinary gain (loss) on retirement of debt, net of tax .. (0.03) - 0.02
--------- --------- ---------

Diluted-after extraordinary gain (loss) ...................... $ 0.35 $ 0.61 $ (0.23)
========= ========= =========

WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic ........................................................ 105,766 98,195 83,815
Diluted ...................................................... 107,462 102,271 83,815
</Table>

SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.

24
<Page>

KEY ENERGY SERVICES, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

<Table>
<Caption>
YEAR ENDED JUNE 30,
2002 2001 2000
-------- -------- --------
(THOUSANDS)

NET INCOME (LOSS) .............................................. $ 38,146 $ 62,710 $(18,959)

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Derivative transition adjustment (See Note 6) ................ - (778) -
Oil and natural gas derivatives adjustment (See Note 6) ...... (279) 306 -
Amortization of oil and natural gas derivatives (See Note 6) . (367) 558 -
Currency translation gain (loss) (See Note 17) ............... (48,383) (32) (1)

-------- -------- --------
COMPREHENSIVE INCOME (LOSS), NET OF TAX ........................ $(10,883) $ 62,764 $(18,960)
======== ======== ========
</Table>

SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.

25
<Page>

KEY ENERGY SERVICES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

<Table>
<Caption>
YEAR ENDED JUNE 30,
-------------------------------------------
2002 2001 2000
--------- --------- ---------
(THOUSANDS)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ................................... $ 38,146 $ 62,710 $ (18,959)
ADJUSTMENTS TO RECONCILE INCOME FROM OPERATIONS TO
NET CASH PROVIDED BY (USED IN) OPERATIONS:
Depreciation, depletion and amortization ............ 78,265 75,147 70,972
Amortization of deferred debt issuance costs,
discount and premium................................. 3,005 4,947 5,919
Deferred income taxes ............................... 23,160 34,698 (1,818)
(Gain) loss on sale of assets ....................... (668) 173 25
Foreign currency transaction loss, Argentina ........ 1,443 - -
Extraordinary (gain) loss, net of tax ............... 3,037 (429) (1,611)
CHANGE IN ASSETS AND LIABILITIES NET OF EFFECTS
FROM THE ACQUISITIONS:
(Increase) decrease in accounts receivable ........ 48,907 (53,813) (31,205)
(Increase) decrease in other current assets ....... (4,410) (4,485) (5,483)
Increase (decrease) in accounts payable,
accrued interest and accrued expenses ........... (12,180) 29,414 18,875
Other assets and liabilities ...................... 11 (5,015) (1,855)
--------- --------- ---------
Net cash provided by (used in) operating activities . 178,716 143,347 34,860
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures - well servicing ............... (57,857) (51,064) (26,469)
Capital expenditures - contract drilling ............ (19,861) (15,884) (8,282)
Capital expenditures - other ........................ (15,979) (15,802) (3,422)
Proceeds from sale of fixed assets .................. 4,258 3,415 2,722
Notes receivable from related parties ............... - (1,500) (2,315)
Acquisitions - well servicing ....................... (17,273) (2,345) -
Acquisitions - contract drilling .................... (2,037) (800) -
--------- --------- ---------
Net cash provided by (used in) investing activities . (108,749) (83,980) (37,766)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of long-term debt ......................... (309,559) (373,998) (39,438)
Repayment of capital lease obligations .............. (10,182) (8,542) (11,639)
Proceeds from equity offerings, net of expenses ..... 42,590 - 100,571
Proceeds from long-term debt ........................ 258,500 205,210 12,000
Proceeds paid for debt issuance costs ............... (1,585) (4,958) -
Proceeds from forward sale, net of expenses ......... - - 18,236
Proceeds from exercise of warrants .................. - 847 8,473
Proceeds from exercise of stock options ............. 3,219 14,617 1,098
Other ............................................... (298) (318) -
--------- --------- ---------
Net cash provided by (used in) financing activities . (17,315) (167,142) 89,301
--------- --------- ---------
Effect of exchange rates on cash .................... (603) - -
Net increase (decrease) in cash ..................... 52,049 (107,775) 86,395
Cash and cash equivalents at beginning of period .... 2,098 109,873 23,478
--------- --------- ---------
Cash and cash equivalents at end of period .......... $ 54,147 $ 2,098 $ 109,873
========= ========= =========
</Table>

SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.

26
<Page>

KEY ENERGY SERVICES INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(THOUSANDS)

<Table>
<Caption>
COMMON STOCK ACCUMULATED
--------------------- ADDITIONAL OTHER
NUMBER OF AMOUNT AT PAID-IN TREASURY COMPREHENSIVE RETAINED
SHARES PAR CAPITAL STOCK INCOME EARNINGS TOTAL
--------- --------- --------- --------- --------- --------- ---------

BALANCE AT JUNE 30, 1999 ........ 83,155 $ 8,317 $ 301,615 $ (9,682) $ 9 $ (12,165) $ 288,094
--------- --------- --------- --------- --------- --------- ---------

Foreign currency transition
adjustment, net of tax ....... - - - - (1) - (1)
Exercise of warrants ............ 2,431 243 8,230 - - - 8,473
Exercise of options ............. 241 24 1,074 - - - 1,098
Conversion of 7% Debentures ..... 380 38 3,568 - - - 3,606
Issuance of common stock in
equity offering, net of
offering costs................ 11,000 1,100 99,471 - - - 100,571
Other ........................... 3 1 4 - - - 5
Net income (loss) ............... - - - - - (18,959) (18,959)
--------- --------- --------- --------- --------- --------- ---------
BALANCE AT JUNE 30, 2000 ........ 97,210 $ 9,723 $ 413,962 $ (9,682) $ 8 $ (31,124) $ 382,887
--------- --------- --------- --------- --------- --------- ---------
Derivative transition adjustment
(see Note 6) ................. - - - - (778) - (778)
Oil and natural gas derivatives
adjustment, net of tax (See
Note 6)....................... - - - - 306 - 306
Amortization of oil and natural
gas derivatives (see Note 6) . - - - - 558 - 558
Foreign currency translation
adjustment, net of tax ....... - - - - (32) - (32)
Exercise of warrants ............ 185 19 828 - - - 847
Exercise of options ............. 3,106 308 14,309 - - - 14,617
Conversion of 7% Debentures ..... 101 10 947 - - - 957
Issuance of common stock for
acquisitions ................. 838 84 8,036 - - - 8,120
Deferred tax benefit-
compensation expense ......... - - 7,004 - - - 7,004
Other ........................... - - (318) - - - (318)
Net income (loss) ............... - - - - - 62,710 62,710
--------- --------- --------- --------- --------- --------- ---------
BALANCE AT JUNE 30, 2001 ........ 101,440 $ 10,144 $ 444,768 $ (9,682) $ 62 $ 31,586 $ 476,878
========= ========= ========= ========= ========= ========= =========

Oil and natural gas derivatives
adjustment, net of tax (See
Note 6)....................... - - - - (279) - (279)
Amortization of oil and natural
gas derivatives (see Note 6) . - - - - (367) - (367)
Foreign currency translation
adjustment, net of tax ....... - - - - (48,383) - (48,383)
Exercise of warrants ............ 7 1 (1) - - - -
Exercise of options ............. 659 66 3,153 - - - 3,219
Issuance of common stock for
acquisitions ................. 2,801 280 24,787 - - - 25,067
Issuance of common stock in
equity offering, net of
offering costs................ 5,400 540 42,050 - - - 42,590
Other ........................... 1 - (5) - - - (5)
Net income (loss) ............... - - - - - 38,146 38,146
--------- --------- --------- --------- --------- --------- ---------
BALANCE AT JUNE 30, 2002 ........ 110,308 $ 11,031 $ 514,752 $ (9,682) $ (48,967) $ 69,732 $ 536,866
========= ========= ========= ========= ========= ========= =========
</Table>

SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.

27
<Page>

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.

28
<Page>

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:

<Table>
<Caption>
DESCRIPTION YEARS
- ------------------------------------------------------------- ------------

Well service rigs......................................... 25
Motor vehicles............................................ 5
Furniture and equipment................................... 3 - 7
Buildings and improvements................................ 10 - 40
Gas processing facilities................................. 10
Disposal wells............................................ 15 - 30
Trucks, trailers and related equipment.................... 7 - 15
</Table>

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.

29
<Page>

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

30
<Page>

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.

31
<Page>

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:

<Table>
<Caption>
---------------------------
YEAR ENDED JUNE 30,
---------------------------
2001 2000
---------- ----------
(THOUSANDS, EXCEPT PER SHARE DATA)

Reported net income (loss) before extraordinary gain (loss) $ 62,281 $ (20,570)
Add back: goodwill amortization ........................... 9,322 9,840
---------- ----------
Adjusted net income (loss) before extraordinary gain (loss) 71,603 (10,730)
Extraordinary gain, net of tax ............................. 429 1,611
---------- ----------
Adjusted net income (loss) ................................. $ 72,032 $ (9,119)
========== ==========

BASIC EARNINGS (LOSS) PER SHARE:
Reported net income (loss) before extraordinary gain (loss) $ 0.63 $ (0.25)
Add back: goodwill amortization ........................... 0.09 0.12
---------- ----------
Adjusted net income (loss) before extraordinary gain (loss) 0.72 (0.13)
Extraordinary gain, net of tax ............................. - 0.02
---------- ----------
Adjusted net income (loss) ................................. $ 0.72 $ (0.11)
========== ==========

DILUTED EARNINGS (LOSS) PER SHARE:
Reported net income (loss) before extraordinary gain (loss) $ 0.61 $ (0.25)
Add back: goodwill amortization ........................... 0.09 0.12
---------- ----------
Adjusted net income (loss)before extraordinary gain (loss) 0.70 (0.13)
Extraordinary gain, net of tax ............................. - 0.02
---------- ----------
Adjusted net income (loss) ................................. $ 0.70 $ (0.11)
========== ==========
</Table>

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

32
<Page>

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.

33
<Page>

<Table>
<Caption>
------------------------------------------
YEAR ENDED JUNE 30,
------------------------------------------
2002 2001 2000
--------- --------- ---------
(THOUSANDS, EXCEPT PER SHARE DATA)

BASIC EPS COMPUTATION:
NUMERATOR
Net income (loss) before extraordinary gain (loss) ... $ 41,183 $ 62,281 $ (20,570)
Extraordinary gain (loss), net of tax ................ (3,037) 429 1,611
--------- --------- ---------
Net income (loss) .................................... $ 38,146 $ 62,710 $ (18,959)
========= ========= =========
DENOMINATOR
Weighted average common shares outstanding ........... 105,766 98,195 83,815
--------- --------- ---------
BASIC EPS:
Before extraordinary gain (loss) ..................... $ 0.39 $ 0.63 $ (0.25)
Extraordinary gain (loss), net of tax ................ (0.03) - 0.02
--------- --------- ---------
Net income (loss) .................................... $ 0.36 $ 0.63 $ (0.23)
========= ========= =========

DILUTED EPS COMPUTATION:
NUMERATOR
Net income (loss) before extraordinary gain (loss) and
effect of dilutive securities, tax effected ....... $ 41,183 $ 62,281 $ (20,570)
Convertible securities ............................... - 5 -
--------- --------- ---------
Net income (loss) before extraordinary gain (loss) ... 41,183 62,286 (20,570)
Extraordinary gain (loss), net of tax ............... (3,037) 429 1,611
--------- --------- ---------
Net income (loss) .................................... $ 38,146 $ 62,715 $ (18,959)
========= ========= =========
DENOMINATOR
Weighted average common shares outstanding ........... 105,766 98,195 83,815
Warrants ........................................... 402 205 -
Stock options ...................................... 1,294 3,853 -
7% Convertible Debentures .......................... - 18 -
--------- --------- ---------
107,462 102,271 83,815
--------- --------- ---------

DILUTED EPS:
Before extraordinary gain (loss) ..................... $ 0.38 $ 0.61 $ (0.25)
Extraordinary gain (loss), net of tax ................ (0.03) - 0.02
--------- --------- ---------
Net income (loss) .................................... $ 0.35 $ 0.61 $ (0.23)
========= ========= =========
</Table>

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.

34
<Page>

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.

35
<Page>

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:

36
<Page>

<Table>
<Caption>
JUNE 30,
--------------------------
2002 2001
-------- --------
(THOUSANDS)

Senior Credit Facility Revolving Loans (i) ...... $ - $ 2,000
8 3/8% Senior Notes Due 2008 (ii) ............... 276,433 175,000
14% Senior Subordinated Notes Due 2009 (iii) .... 94,257 134,466
5% Convertible Subordinated Notes Due 2004 (iv).. 49,951 158,426
Capital Leases .................................. 22,829 22,964
Other notes payable ............................. 140 1,051
-------- --------
443,610 493,907
Less current portion ............................ 7,674 7,946
-------- --------
Total long-term debt ............................ $435,936 $485,961
======== ========
</Table>

(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%.

37
<Page>

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

38
<Page>

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.

(iv) 5% CONVERTIBLE SUBORDINATED NOTES

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.

39
<Page>

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:

<Table>
<Caption>
PRINCIPAL
FISCAL YEAR ENDING JUNE 30, AMOUNT
--------------
(THOUSANDS)

2003........................................................................ $ 7,674
2004........................................................................ 7,679
2005........................................................................ 57,567
2006........................................................................ -
2007........................................................................ -
Thereafter.................................................................. 372,500
-------------
$445,420
=============
</Table>

The Company's interest expense for the years ended June 30, 2002, 2001,
and 2000 consisted of the following:

<Table>
<Caption>
2002 2001 2000
----------- ------------ ----------
(THOUSANDS)

Cash payments for interest...................... $42,085 $51,524 $61,956
Commitment and agency fees paid................ 1,183 1,203 1,139
Accretion of discount and premium on notes...... 424 739 743
Amortization of debt issuance costs............. 2,581 3,578 5,176
Net change in accrued interest.................. (1,275) 146 2,916
Capitalized interest............................ (1,666) (630) -
----------- ------------ ----------
$43,332 $56,560 $71,930
=========== ============ ==========
</Table>

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.

40
<Page>

<Table>
<Caption>
2002 2001
------------------------ -------------------------
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
-------- -------- -------- --------

Financial Assets:
Cash and cash equivalents ......... $ 54,147 $ 54,147 $ 2,098 $ 2,098
Accounts receivable, net .......... 117,907 117,907 177,016 177,016
Notes receivable - related parties 274 274 6,050 6,600
Commodity option contracts ........ 246 246 1,035 1,035
Financial Liabilities:
Accounts payable .................. 24,625 24,625 42,544 42,544
Commodity option contracts ........ - - 344 344
Long-term debt:
Senior Credit Facility .......... - - 2,000 2,000
8 3/8% Senior Notes ............. 276,433 287,491 175,000 176,094
14% Senior Subordinated Notes ... 94,257 109,338 134,466 153,498
5% Convertible Subordinated Notes 49,951 46,942 158,426 141,989
Capital lease liabilities ....... 22,829 22,829 22,964 22,964
Other debt ...................... 140 140 1,051 1,051
</Table>

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.

41
<Page>

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:

42
<Page>

<Table>
<Caption>
MONTHLY INCOME STRIKE PRICE
-------------- PER BBL/MMBTU
OIL GAS -------------
(BBLS) (MMBTU) TERM FLOOR CAP FAIR VALUE
------ ------- ---- ----- --- ----------

At June 30, 2002
Oil Put............. 5,000 - Mar 2002-Feb 2003 $22.00 - $ 24,000
Oil Put............. 4,000 - Mar 2003-Feb 2004 $21.00 - $118,000
Gas Put............. - 75,000 Mar 2002-Feb 2003 $3.00 - $104,000

At June 30, 2001
Oil Collar.......... 5,000 - Mar 2001-Feb 2002 $19.70 $23.70 ($115,000)
Oil Put............. 5,000 - Mar 2002-Feb 2003 $22.00 - $141,000
Gas Collar.......... - 40,000 Mar 2001-Feb 2002 $2.40 $ 2.91 ($229,000)
Gas Put............. - 75,000 Mar 2002-Feb 2003 $3.00 - $894,000
</Table>

7. OTHER ACCRUED LIABILITIES

Other accrued liabilities consist of the following:

<Table>
<Caption>
JUNE 30,
-----------------------------------
2002 2001
---------------- ---------------
(THOUSANDS)

Accrued payroll, taxes and employee benefits............. $28,479 $31,242
State sales, use and other taxes......................... 2,344 5,825
Oil and natural gas revenue distribution................. 1,271 1,606
Other ................................................... 17,371 10,250
---------------- ---------------
Total.................................................... $49,465 $48,923
================ ===============
</Table>

Other non-current accrued expenses consist primarily of workers
compensation reserves.

8. STOCKHOLDERS' EQUITY

EQUITY OFFERINGS

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.

43
<Page>

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.)

44
<Page>

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):

<Table>
<Caption>
FISCAL YEAR ENDED JUNE 30,
--------------------------------------------------------------------------------
2002 2001 2000
---------------------- --------------------------- ---------------------------
WEIGHTED WEIGHTED- WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
---------- ---------- ----------- -------------- ------------- -----------

Outstanding:
Beginning of fiscal year........... 8,703 $7.49 9,470 $6.37 6,920 $5.55
Granted............................ 1,988 8.16 2,533 8.08 3,688 8.61
Exercised.......................... (659) 4.53 (3,107) 4.70 (241) 4.56
Forfeited.......................... (24) 4.86 (193) 4.92 (897) 9.80
----------- --------- ----------
End of fiscal year................. 10,008 7.80 8,703 7.49 9,470 6.37
=========== ========= ==========
Exercisable - end of fiscal year..... 6,273 5,820 4,370
=========== ========= ==========
</Table>

The following table summarizes information about the stock options
outstanding at June 30, 2002 (shares in thousands):

<Table>
<Caption>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------------------------- -------------------------------
WEIGHTED NUMBER OF WEIGHTED NUMBER OF WEIGHTED
AVERAGE SHARES AVERAGE SHARES AVERAGE
RANGE OF EXERCISE REMAINING OUTSTANDING AT EXERCISE OUTSTANDING AT EXERCISE
PRICES CONTRACTUAL LIFE JUNE 30, 2002 PRICE JUNE 30, 2002 PRICE
- ---------------------- ----------------- ----------------- ----------- ---------------- -----------

$3.00 - $7.13 5.65 2,052 $ 4.63 1,602 $ 4.82
7.25 - 8.13 8.75 1,997 7.86 299 7.71
8.25 - 8.31 7.71 2,080 8.25 1,857 8.26
8.35 - 8.50 7.25 2,225 8.48 1,229 8.47
8.88 - 13.25 6.65 1,677 10.12 1,286 10.39
</Table>

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:

45
<Page>

<Table>
<Caption>
FISCAL YEAR ENDED JUNE 30,
----------------------------------------
2002 2001 2000
------------ ------------ ------------
(THOUSANDS, EXCEPT PER SHARE DATA)

Net income (loss):
As reported................................... $38,146 $62,710 $(18,959)
Pro forma..................................... 26,320 52,338 (25,684)

Basic earnings per share of common stock:
As reported................................... $ 0.36 $ 0.63 $ (0.23)
Pro forma..................................... 0.25 0.53 (0.31)

Diluted earnings per share of common stock:
As reported................................... $ 0.35 $ 0.61 $ (0.23)
Pro forma..................................... 0.24 0.51 (0.31)
</Table>

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.

<Table>
<Caption>
FISCAL YEAR OF GRANT
----------------------------------------
2002 2001 2000
---------- --------- ---------

Risk-free interest rate.............................. 3.35% 4.30% 6.40%
Expected life of options............................. 5 years 5 years 5 years
Expected volatility of the Company's stock price..... 50% 59% 67%
Expected dividends................................... none none none
</Table>

9. INCOME TAXES

Components of income tax expense (benefit) are as follows:

<Table>
<Caption>
FISCAL YEAR ENDED JUNE 30,
-----------------------------------------------
2002 2001 2000
---------- ----------- -----------
(THOUSANDS)

Federal and State:
Current ............................... $ 914 $ 2,304 $(5,588)
Deferred
U.S ................................... 23,160 34,698 (1,818)
Foreign ............................... - - -
---------- ----------- -----------
$24,074 $37,002 $(7,406)
========== =========== ===========
</Table>

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:

46
<Page>

<Table>
<Caption>
FISCAL YEAR ENDED JUNE 30,
--------------------------------------------------
2002 2001 2000
-------------- ---------------- ----------------

Income tax computed at statutory rate.................. 35.0% 35.0% (35.0)%
Amortization of goodwill disallowance.................. - 2.2 7.0
State taxes............................................ 2.8 1.4 -
Change in valuation allowance and other................ (0.9) (1.4) 1.5
-------------- ---------------- ----------------
Change in valuation allowance and other................ 36.9% 37.2% (26.5)%
============== ================ ================
</Table>

Deferred tax assets (liabilities) are comprised of the following:

<Table>
<Caption>
FISCAL YEAR ENDED JUNE 30,
--------------------------------
2002 2001
-------------- ---------------
(THOUSANDS)

Net operating loss and tax credit carry forwards........... $ 50,089 $ 69,376
Property and equipment..................................... (191,834) (183,068)
Self insurance reserves.................................... 6,254 405
Allowance for bad debts.................................... 1,477 1,542
Other...................................................... (2,456) 148
-------------- ---------------
Net deferred tax liability................................. (136,470) (111,597)
Valuation allowance of deferred tax assets................. (13,520) (15,803)
-------------- ---------------
Net deferred tax liability, net of valuation allowance..... $(149,990) $(127,400)
============== ===============
</Table>

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):

47
<Page>

<Table>
<Caption>
LEASE
FISCAL YEAR ENDING JUNE 30, PAYMENTS

2003.............................................. $ 6,818
2004.............................................. 6,498
2005.............................................. 6,327
2006.............................................. 4,198
2007.............................................. 1,509
------------
$25,350
============
</Table>

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.

48
<Page>

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.

49
<Page>

<Table>
<Caption>
WELL CONTRACT CORPORATE
SERVICING DRILLING / OTHER TOTAL
--------- -------- --------- -----

TWELVE MONTHS ENDED JUNE 30, 2002
Operating revenues ................................... $706,629 $ 87,077 $ 8,858 $ 802,564
Operating profit ..................................... 216,947 26,516 4,328 247,791
Depreciation, depletion and amortization ............. 64,540 9,191 4,534 78,265
Interest expense ..................................... 1,448 - 41,884 43,332
Net income (loss) before extraordinary gain (loss)* . 76,547 7,630 (42,994) 41,183
Identifiable assets .................................. 686,425 91,374 264,127 1,041,926
Capital expenditures (excluding acquisitions) ........ 57,857 19,861 15,979 93,697

TWELVE MONTHS ENDED JUNE 30, 2001
Operating revenues ................................... $758,273 $107,639 $ 7,350 $873,262
Operating profit ..................................... 257,949 30,273 2,886 291,108
Depreciation, depletion and amortization ............. 63,578 7,947 3,622 75,147
Interest expense ..................................... 1,831 - 54,729 56,560
Net income (loss) before extraordinary gain (loss) * . 109,159 9,466 (56,344) 62,281
Identifiable assets .................................. 664,611 95,473 278,325 1,038,409
Capital expenditures (excluding acquisitions) ........ 51,064 15,884 15,802 82,750

TWELVE MONTHS ENDED JUNE 30, 2000
Operating revenues ................................... $559,492 $ 68,428 $9,812 $ 637,732
Operating profit ..................................... 150,769 10,129 5,665 166,563
Depreciation, depletion and amortization ............. 62,680 6,105 2,187 70,972
Interest expense ..................................... 2,300 - 69,630 71,930
Net income (loss) before extraordinary gain (loss)* .. 48,062 (1,664) (66,968) (20,570)
Identifiable assets .................................. 635,304 89,574 322,754 1,047,632
Capital expenditures (excluding acquisitions) ........ 26,464 8,282 3,422 38,173
</Table>

* - 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.

50
<Page>

14. SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES

<Table>
<Caption>
YEAR ENDED JUNE 30,
2002 2001 2000
---- ---- ----
(THOUSANDS)

Fair value of common stock issued in purchase transactions .......... $25,067 $8,120 $-
Fair value of common stock issued upon conversion of long-term debt . - 957 3,606
Capital lease obligations ........................................... 10,047 9,595 10,758
</Table>

15. UNAUDITED SUPPLEMENTARY INFORMATION - QUARTERLY RESULTS OF OPERATIONS

Summarized quarterly financial data for fiscal 2002, and 2001 are as
follows:

51
<Page>

<Table>
<Caption>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
--------- --------- --------- ---------
(THOUSANDS, EXCEPT PER SHARE AMOUNTS)

FISCAL 2002
Revenues ........................................... $ 249,237 $ 213,337 $ 170,241 $ 169,749
Income from operations ............................. 46,138 28,271 1,408 (10,560)
Net income (loss) before extraordinary gain (loss) . 28,996 17,368 635 (5,816)
Extraordinary gain (loss), net of tax .............. 180 2,091 (5,261) (47)
--------- --------- --------- ---------
Net income (loss) .................................. $ 29,176 $ 19,459 $ (4,626) $ (5,863)
========= ========= ========= =========
Earnings (loss) per share:
Basic - before extraordinary gain (loss) ......... $ 0.29 $ 0.17 $ 0.01 $ (0.05)
Extraordinary gain (loss), net of tax ............ - 0.02 (0.05) -
--------- --------- --------- ---------
Basic - after extraordinary gain (loss) .......... $ 0.29 $ 0.19 $ (0.04) $ (0.05)
========= ========= ========= =========

Diluted - before extraordinary gain (loss) ....... $ 0.28 $ 0.17 $ 0.01 $ (0.05)
Extraordinary gain (loss), net of tax ............ - 0.02 (0.05) -
--------- --------- --------- ---------
Diluted - after extraordinary gain (loss) ........ $ 0.28 $ 0.19 $ (0.04) $ (0.05)
========= ========= ========= =========
Weighted average shares outstanding:
Basic ............................................ 101,727 103,115 108,551 109,776
Diluted .......................................... 103,829 104,811 110,059 109,776

FISCAL 2001
Revenues ........................................... $ 191,679 $ 203,911 $ 227,370 $ 250,302
Income from operations ............................. 12,229 18,063 27,912 41,079
Net income before extraordinary gain (loss) ........ 7,510 11,094 17,587 26,090
Extraordinary gain (loss), net of tax .............. 1,197 68 (167) (669)
--------- --------- --------- ---------
Net income ......................................... $ 8,707 $ 11,162 $ 17,420 $ 25,421
========= ========= ========= =========
Earnings per share:
Basic - before extraordinary gain (loss) ......... $ 0.08 $ 0.11 $ 0.18 $ 0.26
Extraordinary gain (loss), net of tax ............ 0.01 - - (0.01)
--------- --------- --------- ---------
Basic - after extraordinary gain (loss) .......... $ 0.09 $ 0.11 $ 0.18 $ 0.25
========= ========= ========= =========

Diluted - before extraordinary gain (loss) ....... $ 0.08 $ 0.11 $ 0.17 $ 0.25
Extraordinary gain (loss), net of tax ............ 0.01 - - (0.01)
--------- --------- --------- ---------
Diluted - after extraordinary gain (loss) ........ $ 0.09 $ 0.11 $ 0.17 $ 0.24
========= ========= ========= =========
Weighted average shares outstanding:
Basic ............................................ 96,880 97,534 98,211 100,179
Diluted .......................................... 100,472 100,534 103,524 104,401
</Table>

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.

52
<Page>

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

<Table>
<Caption>
JUNE 30, 2002
------------------------------------------------------------------------
PARENT GUARANTOR NON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
---------- ------------ ------------ ------------ ------------
(IN THOUSANDS)

Assets:
Current assets $ 64,814 $ 117,140 $ 10,119 $ - $ 192,073
Net property and equipment 43,003 748,158 17,739 - 808,900
Goodwill, net 3,374 197,144 551 - 201,069
Deferred costs, net 12,580 - - - 12,580
Intercompany receivables 537,416 - - (537,416) -
Other assets 21,593 6,780 - - 28,373
---------- ---------- ---------- ---------- ----------
Total assets $ 682,780 $1,069,222 $ 28,409 $ (537,416) $1,242,995
========== ========== ========== ========== ==========
Liabilities and equity:
Current liabilities $ 48,388 $ 45,427 $ 2,813 $ - $ 96,628
Long-term debt 420,717 - - - 420,717
Capital lease obligations 1,457 13,762 - - 15,219
Intercompany payables - 516,761 20,655 (537,416) -
Deferred tax liability 149,990 - - - 149,990
Other long-term liabilities 13,474 10,101 - - 23,575
Stockholders' equity 48,754 483,171 4,941 - 536,866
---------- ---------- ---------- ---------- ----------
Total liabilities and stockholders' equity $ 682,780 $1,069,222 $ 28,409 $ (537,416) $1,242,995
========== ========== ========== ========== ==========
</Table>

53
<Page>

<Table>
<Caption>
JUNE 30, 2001
-----------------------------------------------------------------------------------------
PARENT GUARANTOR NON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
----------- ------------ ------------ ------------ ------------
(IN THOUSANDS)

Assets:
Current assets $ 10,680 $ 165,653 $ 29,817 $ - $ 206,150
Net property and equipment 21,418 717,989 54,309 - 793,716
Goodwill, net 3,374 184,379 2,122 - 189,875
Deferred costs, net 17,624 - - - 17,624
Intercompany receivables 664,592 - - (664,592) -
Other assets 15,303 5,616 - - 20,919
----------- ----------- ----------- --------- -----------
Total assets $ 732,991 $ 1,073,637 $ 86,248 $(664,592) $ 1,228,284
=========== =========== =========== ========= ===========

Liabilities and equity:
Current liabilities $ 35,671 $ 64,679 $ 15,203 $ - $ 115,553
Long-term debt 470,578 - - - 470,578
Capital lease obligations 90 15,331 (38) 15,383
Intercompany payables - 608,764 55,828 (664,592) -
Deferred tax liability 127,400 - - - 127,400
Other long-term 8,240 14,252 - - 22,492
liabilities
Stockholders' equity 91,012 370,611 15,255 - 476,878
----------- ----------- ----------- --------- -----------
Total liabilities and
stockholders' equity $ 732,991 $ 1,073,637 $ 86,248 $(664,592) $ 1,228,284
=========== =========== =========== ========= ===========
</Table>

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

<Table>
<Caption>
YEAR ENDED JUNE 30, 2002
----------------------------------------------------------------------------------------
PARENT GUARANTOR NON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
----------- ------------ ------------ ------------ ------------
(IN THOUSANDS)

Revenues $ 1,247 $ 768,106 $ 33,211 $ - $ 802,564
Costs and expenses: -
Direct expenses - 527,977 26,796 - 554,773
Depreciation, depletion and
amortization expense 1,830 73,252 3,183 - 78,265
General and administrative expense 22,715 34,481 2,298 - 59,494
Interest 41,883 857 592 - 43,332
Other - - 1,443 - 1,443
--------- --------- --------- --------- ---------
Total costs and expenses 66,428 636,567 34,312 - 737,307
--------- --------- --------- --------- ---------
Income (loss) before income taxes (65,181) 131,539 (1,101) - 65,257
Income tax (expense) benefit 24,045 (48,525) 406 - (24,074)
--------- --------- --------- --------- ---------
Net income (loss) before
extraordinary items (41,136) 83,014 (695) - 41,183
Extraordinary items, net of tax (3,037) - - - (3,037)
--------- --------- --------- --------- ---------
Net income (loss) $ (44,173) $ 83,014 $ (695) $ - $ 38,146
========= ========= ========= ========= =========
</Table>

54
<Page>

<Table>
<Caption>
YEAR ENDED JUNE 30, 2001
---------------------------------------------------------------------------
PARENT GUARANTOR NON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ ------------ ------------ ------------
(IN THOUSANDS)

Revenues $ 2,018 $ 816,724 $ 54,520 $ - $ 873,262
Costs and expenses:
Direct expenses - 540,987 41,167 - 582,154
Depreciation, depletion and
amortization expense 1,353 69,714 4,080 - 75,147
General and administrative 19,158 37,558 3,402 - 60,118
expense
Interest 54,464 1,275 821 - 56,560
Other - - - - -
--------- --------- --------- ---------- ---------
Total costs and expenses 74,975 649,534 49,470 - 773,979
--------- --------- --------- ---------- ---------
Income (loss) before income taxes (72,957) 167,190 5,050 - 99,283
Income tax (expense) benefit 27,190 (62,310) (1,882) - (37,002)
--------- --------- --------- ---------- ---------
Net income (loss) before extraordinary items (45,767) 104,880 3,168 - 62,281
Extraordinary items, net of tax 429 - - - 429
--------- --------- --------- ---------- ---------
Net income (loss) $ (45,338) $ 104,880 $ 3,168 $ - $ 62,710
========= ========= ========= ========== =========
</Table>

<Table>
<Caption>
YEAR ENDED JUNE 30, 2000
----------------------------------------------------------------------------
PARENT GUARANTOR NON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ ------------ ------------ ------------
(IN THOUSANDS)

Revenues $ 790 $ 599,225 $ 37,717 $ - $ 637,732
Costs and expenses:
Direct expenses - 440,741 30,428 - 471,169
Depreciation, depletion and
amortization expense 1,162 66,453 3,357 - 70,972
General and administrative expense 10,774 37,704 3,159 - 51,637
Interest 69,802 1,527 601 - 71,930
Other - - - - -
--------- --------- --------- ---------- ---------
Total costs and expenses 81,738 546,425 37,545 - 665,708
--------- --------- --------- ---------- ---------
Income (loss) before income taxes (80,948) 52,800 172 - (27,976)
Income tax (expense) benefit 21,429 (13,977) (46) - 7,406
--------- --------- --------- ---------- ---------
Net income (loss) before extraordinary items (59,519) 38,823 126 - (20,570)
Extraordinary items, net of tax 1,611 - - - 1,611
--------- --------- --------- ---------- ---------
Net income (loss) $ (57,908) $ 38,823 $ 126 $ - $ (18,959)
========= ========= ========= ========== =========
</Table>

55
<Page>

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

<Table>
<Caption>
FISCAL YEAR ENDED JUNE 30, 2002
--------------------------------------------------------------------------
PARENT GUARANTOR NON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ ------------ ------------ ------------
(IN THOUSANDS)

Net cash provided by (used in) operating activities $ 95,948 $ 78,577 $ 4,191 $ - $ 178,716
Net cash provided by (used in) investing activities (37,188) (67,092) (4,469) - (108,749)
Net cash provided by (used in) financing activities (7,665) (9,637) (13) - (17,315)
Effect of exchange rate changes on cash - - (603) - (603)
--------- --------- --------- --------- ---------
Net increase (decrease) in cash 51,095 1,848 (894) - 52,049
Cash and cash equivalents at beginning of period 1,647 (2,005) 2,456 - 2,098
--------- --------- --------- --------- ---------
Cash and cash equivalents at end of period $ 52,742 $ (157) $ 1,562 $ - $ 54,147
========= ========= ========= ========= =========
</Table>

<Table>
<Caption>
FISCAL YEAR ENDED JUNE 30, 2001
--------------------------------------------------------------------------
PARENT GUARANTOR NON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ ------------ ------------ ------------
(IN THOUSANDS)

Net cash provided by (used in) operating activities $ 68,932 $ 64,673 $ 9,742 $ - $ 143,347
Net cash provided by (used in) investing activities (19,824) (56,976) (7,180) - (83,980)
Net cash provided by (used in) financing activities (158,627) (8,456) (59) - (167,142)
--------- --------- --------- --------- ---------
Net increase (decrease) in cash (109,519) (759) 2,503 - (107,775)
Cash and cash equivalents at beginning of period 111,166 (1,246) (47) - 109,873
--------- --------- --------- --------- ---------
Cash and cash equivalents at end of period $ 1,647 $ (2,005) $ 2,456 $ - $ 2,098
========= ========= ========= ========= =========
</Table>

<Table>
<Caption>
FISCAL YEAR ENDED JUNE 30, 2000
--------------------------------------------------------------------------
PARENT GUARANTOR NON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ ------------ ------------ ------------
(IN THOUSANDS)

Net cash provided by (used in) operating activities $ 18,962 $ 10,434 $ 5,464 $ - $ 34,860
Net cash provided by (used in) investing activities (4,468) (26,671) (6,627) - (37,766)
Net cash provided by (used in) financing activities 80,070 9,287 (56) - 89,301
--------- --------- --------- --------- ---------
Net increase (decrease) in cash 94,564 (6,950) (1,219) - 86,395
Cash and cash equivalents at beginning of period 16,602 5,704 1,172 - 23,478
--------- --------- --------- --------- ---------
Cash and cash equivalents at end of period $ 111,166 $ (1,246) $ (47) $ - $ 109,873
========= ========= ========= ========= =========
</Table>

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

56
<Page>

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]

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.

57
<Page>

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

58
<Page>

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. 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. 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).

59
<Page>

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,

60
<Page>

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

61
<Page>

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).

62
<Page>

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

63
<Page>

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).

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<Page>

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.

<Page>

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

66
<Page>

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

67
<Page>

CERTIFICATIONS

I, Royce W. Mitchell, certify that:

1. I have reviewed this annual report on Form 10-K of Key Energy Services,
Inc.;

Date: September 30, 2002

/s/ ROYCE W. MITCHELL
------------------------
Royce W. Mitchell
Chief Financial Officer

<Page>

SCHEDULE II

KEY ENERGY SERVICES, INC.
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
AS OF JUNE 30,

<Table>
<Caption>
ADDITIONS
--------------------------------------
BALANCE AT
BEGINNING OF CHARGED TO CHARGED TO BALANCE AT
YEAR EXPENSES OTHER ACCOUNTS(a) DEDUCTIONS END OF YEAR
---- -------- ----------------- ---------- -----------
(IN THOUSANDS)

Allowance for doubtful
accounts:
2002......................... $4,082 $168 $ - $281 $3,969
2001......................... 3,189 1,263 - 370 4,082
2000......................... 6,790 1,648 - 5,249 3,189
</Table>